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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from _____________ to _____________
Commission File Number 0-9204
EXCO RESOURCES, INC.
(Exact name of Registrant as specified in its charter)
Texas 74-1492779
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5735 Pineland Drive, Suite 235
Dallas, Texas 75231
(Address of principal executive offices) (Zip Code)
(Registrant's telephone number, including area code) (214) 368-2084
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 $.02 PER SHARE
(Title of class)
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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 twelve (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 ninety (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 of this Form 10-K. [ ]
The number of shares of Common Stock, par value $.02 per share, of the
Registrant outstanding on February 29, 2000, was 6,817,696. The aggregate market
value of the voting stock held by nonaffiliates (all directors, officers and 5%
or more shareholders are presumed to be affiliates) of the Registrant on
February 29, 2000, was $16,499,000 based on the average of the closing bid and
ask prices per share of the Common Stock on such date.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the 2000 Annual
Meeting of Shareholders, filed on March 21, 2000, are incorporated by reference
into Part III.
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TABLE OF CONTENTS
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PART I ......................................................................................................... 1
Item 1. Business ............................................................................ 1
Item 2. Properties .......................................................................... 22
Item 3. Legal Proceedings ................................................................... 22
Item 4. Submission of Matters to a Vote of Security Holders ................................. 22
PART II ........................................................................................................ 23
Item 5. Market for the Registrant's Common Equity and Related Shareholder Matters ........... 23
Item 6. Selected Financial Data ............................................................. 24
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations ..................................................................... 26
Item 7A. Quantitative and Qualitative Disclosures about Market Risk .......................... 30
Item 8. Financial Statements and Supplementary Data ......................................... 32
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure .............................................................. 64
PART III ....................................................................................................... 65
Item 10. Directors and Executive Officers of the Registrant .................................. 65
Item 11. Executive Compensation .............................................................. 65
Item 12. Security Ownership of Certain Beneficial Owners and Management ...................... 65
Item 13. Certain Relationships and Related Transactions ...................................... 65
PART IV ........................................................................................................ 66
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ..................... 66
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EXCO RESOURCES, INC.
PART I
ITEM 1. BUSINESS
GENERAL
EXCO Resources, Inc. is an independent oil and natural gas company. We
have been engaged in the oil and natural gas business since 1955. We currently
conduct our primary operations in Texas and Louisiana and also operate or own
non-operated interests in wells in Kansas, Mississippi, North Dakota, Oklahoma
and Wyoming. At the end of 1997 and the beginning of 1998, new management bought
a controlling interest in EXCO and redirected its focus. We now focus on
acquiring, developing and exploiting properties which already produce oil or
natural gas (or are capable of producing oil or natural gas.)
Historically, we have financed our exploration, exploitation and
development expenditures primarily through cash flow from operations, bank
borrowings, equity capital from private sales of stock and promoted funds from
industry partners. With respect to our acquisition activities, we are focusing
on acquisitions of producing properties with additional development and
exploitation potential. We expect to use a combination of debt and equity
financing to fund these acquisitions.
We prefer to act as operator of the oil and natural gas properties and
prospects in which we own an interest. The operator of oil and natural gas
properties:
o supervises production;
o maintains production records;
o employs field personnel to oversee the general operations of the
properties;
o performs other functions required for the production of oil and
natural gas; and
o monitors performance, both operating and financial, necessary to
optimize cash flows derived from the properties.
Industry Language
The oil and natural gas industry is characterized by the use of very
precise specialized language. The following is a brief explanation of certain
industry terms which we use in this annual report. We believe this explanation
will help you understand our operations, risks and strategies. (Certain other
technical terms are defined in a "Glossary" located at page 21.)
We use five different terms to describe the status of our oil and
natural gas wells. A "development well" is a well drilled within a known oil and
natural gas reservoir with the intention of installing permanent equipment to
produce oil and natural gas. An "exploratory well" is a well drilled in an area
not known to be an oil and natural gas reservoir. A "producing well" (also
called a production well or a productive well) is a well that is currently
producing oil or natural gas or that is capable of production. A "dry hole" is
an exploratory or development well that is incapable of producing oil or natural
gas in sufficient quantities to justify completion of the well. Finally, a
"completed well" refers to a well in which permanent equipment for oil and
natural gas production has been installed, or in the case of a dry hole,
reporting the abandonment of the well to the appropriate agency.
When we count our wells, we use the terms gross wells and net wells. A
"gross well" is a well in which we own an interest that gives us the right to
drill, produce and conduct operating activities for the well and gives us the
right to a share of the oil and natural gas produced from the well. The interest
that gives us these rights is called a "working interest." Gross wells means the
total number of wells in which we own such an interest. A "net well" exists when
the sum of the fractional ownership interests in gross wells equals one. The
number of net wells we own equals the sum of the fractional working interests
owned in gross wells expressed as whole numbers.
When we describe the nature of our oil and natural gas properties, we
use the terms developed and undeveloped acreage. "Developed acreage" are those
acres assignable to producing wells. "Undeveloped acreage"
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are those acres on which wells have not been drilled or completed to a point
that permits the production of commercial quantities of oil and natural gas.
When we count the acres in which we own a working interest we use the terms
"gross acres" and "net acres." A "gross acre" is an acre in which we own a right
to drill, produce and conduct operating activities on the property and to a
share of the oil and natural gas production. A "net acre" exists when the sum of
the fractional working interests in gross acres equals one. The total net
acreage is the sum of the fractional working interests owned in gross acres
expressed in whole numbers.
When we describe our oil or natural gas reservoirs within current
developed and undeveloped acreage we use the term "reserves." We obtain
geological and engineering information which we use to estimate the amount of
reserves contained in our developed and undeveloped acreage. These estimates are
known as "proved reserves." We use two terms to describe our proved reserves.
"Proved developed" reserves are proved reserves which may be recovered from
known oil and natural gas reservoirs under existing economic and operating
conditions. "Proved undeveloped" reserves are proved reserves which may be
recovered from existing wells but would require a relatively large expense to
develop or are proved reserves in current undeveloped acreage.
DEVELOPMENTS DURING 1999
We Acquired and Subsequently Sold Oil and Natural Gas Properties
Through a Joint Venture
On December 31, 1999, EXUS Energy, LLC, a Delaware limited liability
company (EXUS), conveyed 100% of the leasehold and mineral interests it had
acquired on June 30, 1999, in Jackson Parish, Louisiana (the Jackson Parish
Properties), to its equity members in proportion to their respective membership
interests. EXUS was owned 50% by EXCO and 50% by Venus Exploration, Inc.
Subsequent to the conveyance of interests, on December 31, 1999 EXCO sold to
Anadarko Petroleum Corporation the property interests conveyed to EXCO by EXUS.
The gross consideration was approximately $18.7 million cash ($18.2 million cash
after adjustments which principally reflect production since October 1, 1999,
the effective date of the sale), and oil and natural gas leasehold interests
located in Seward and Meade Counties, Kansas, valued by the parties at $800,000.
EXCO booked a pre-tax gain from the sale of approximately $5.1 million in the
fourth quarter of 1999.
The Jackson Parish Properties which were owned by EXUS and subsequently
conveyed to Venus and EXCO included 17 gross (7.125 net to EXCO's interest)
producing wells, for which EXCO was the named operator. The Jackson Parish
Properties included approximately 6,410 gross (2,830 net to EXCO's interest)
developed acres and approximately 1,530 gross (570 net to EXCO's interest)
undeveloped acres. As of October 1, 1999, the Jackson Parish Properties were
estimated to contain net total proved reserves to our interest of 1,340 barrels
(Bbls) of oil and 32.7 billion cubic feet (Bcf) of gas. Net production to EXCO's
interest as of November 1999, was running approximately 85.7 million cubic feet
(Mmcf) per month of natural gas, and no barrels of oil or condensate. Anadarko
took over operations of the Jackson Parish Properties on January 1, 2000.
EXCO's proceeds were placed in a tax-deferred escrow account with Texas
Escrow Company, Inc. (Texas Escrow) of Dallas, Texas, under terms of a Deferred
Exchange Agreement (Exchange Agreement) between EXCO and Texas Escrow executed
on December 31, 1999. The Exchange Agreement is designed to comply with the
like-kind exchange provisions of Section 1031 of the Internal Revenue Code which
permits the deferral of gains from a sale of assets if specific like-kind
exchange reinvestment criteria are met. If we are successful in meeting the
like-kind exchange provisions, some, if not most, of the federal and state tax
payments on the gain from the sale of the Jackson Parish Properties will be
deferred to future periods. A portion of the assets purchased in Natchitoches
Parish, Louisiana, described below and meet the requirements for a like-kind
exchange. Therefore, EXCO will be permitted to defer at least some of its gain
on the sale of the Jackson Parish Properties.
We Completed An Acquisition of Oil and Gas Properties
On December 31, 1999, we purchased oil and gas assets located in
Natchitoches Parish, Louisiana from Western Gas Resources, Inc. (the
Natchitoches Parish Properties) for consideration of $7.8 million cash
(approximately $7.2 million after contractual adjustments). The assets included
Western's interest in the Black Lake Unit and the Black Lake processing and
treating facilities.
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The Natchitoches Parish Properties include 29 gross (20 net) producing
wells out of a total of 75 gross wells. We are the named operator of the
Natchitoches Parish Properties and assumed operations of all 75 wells acquired
in the transaction. The Natchitoches Parish Properties include approximately
14,250 gross (10,590 net) developed acres and approximately 10,390 gross (8,320
net) undeveloped acres. As of September 1, 1999, the Natchitoches Parish
Properties were estimated to contain net reserves of 570,000 Bbls of oil and
natural gas liquids (NGLs) and 4.5 Bcf of natural gas. Net production as of
December 1999, was running approximately 95 Mmcf per month of net residue gas,
7,100 Bbls per month of NGLs, and 5,400 Bbls of oil and condensate per month. We
took over operations on January 7, 2000.
We Dissolved an Acquisition Joint Venture
On October 9, 1998, we formed, EXCO Energy Investors, L.L.C., a $50
million joint venture with OCM Principal Opportunities Fund, L.P. to acquire oil
and natural gas related assets and securities. Under the terms of the joint
venture agreement, we were required to contribute 5% of any capital
expenditures. The joint venture had invested in various debt securities of
National Energy Group, Inc.
On November 11, 1999, the debt securities held by the joint venture
were sold for a profit. Then, later that month the proceeds were distributed on
a pro-rata basis after expenses to OCM and EXCO. On December 3, 1999, the joint
venture was dissolved. We recorded a pre-tax gain of approximately $65,000 on
our investment in the joint venture.
We Consummated an Acquisition after Acquiring a Promissory Note
On November 2, 1998, we acquired a $13 million promissory note from a
Texas bank for $6.4 million which was secured by substantially all of the assets
of Rio Grande, Inc., its subsidiaries and affiliated entities. Rio Grande, Inc.
was an oil and natural gas producer with principal operations in Texas,
Oklahoma, Louisiana, and Mississippi. At the same time we purchased the note, we
also entered into an agreement with Rio Grande, Inc. and Rio Grande, Inc.'s sole
holder of preferred stock regarding plans for the ultimate satisfaction of Rio
Grande, Inc.'s debt, including the proposed acquisition of Rio Grande, Inc. or
its assets by us through a plan of reorganization in bankruptcy court.
On November 12, 1998, Rio Grande, Inc., and its subsidiaries and
affiliated entities, announced that they filed for relief under Chapter 11 of
Title 11 of the U.S. Bankruptcy Code. As the largest secured creditor, we
negotiated a plan for financial restructuring with Rio Grande, Inc. and the
holder of its preferred stock. On March 5, 1999, the court confirmed the
proposed plan. Pursuant to the terms of the plan, Rio Grande, Inc. fully repaid
its trade creditors. The plan provided for the merger of several subsidiaries or
affiliates into Rio Grande, Inc. After the mergers, the outstanding shares of
Rio Grande, Inc.'s common and preferred stock were canceled. We issued new
shares of Rio Grande, Inc. as settlement of Rio Grande, Inc.'s $13 million
secured indebtedness owed to us. The new shares represented all of the
outstanding capital stock of Rio Grande, Inc., and we became the owners of Rio
Grande, Inc. effective on March 16, 1999. On March 30, 1999, Rio Grande, Inc.
was merged into EXCO.
INVESTMENT CONSIDERATIONS AND RISK FACTORS
Forward-Looking Statements
Before you invest in our common stock, you should be aware that there
are various risks associated with an investment, including the risks described
below and risks that we have highlighted in other sections of this annual
report. You should consider carefully these risk factors together with all of
the other information included in this annual report before you decide to
purchase shares of our common stock.
Some of the information in this annual report may contain
forward-looking statements. We use words such as "may," "will," "expect,"
"anticipate," "estimate," "believe," "continue," "intend," or other similar
words to identify forward-looking statements. You should read statements that
contain these words carefully because they: (1) discuss future expectations; (2)
contain projections of results of operations or of our financial conditions; or
(3) state other "forward-looking" information. We believe that it is important
to communicate our future expectations to our investors. However, there may be
events in the future that we are unable to accurately predict or over which we
have no control. When considering our forward-looking statements, you should
keep in mind the risk factors and other
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cautionary statements in this annual report. The risk factors noted in this
section and other factors noted throughout this annual report provide examples
of risks, uncertainties and events that may cause our actual results to differ
materially from those contained in any forward-looking statement.
Our Revenue Depends On Oil and Natural Gas Prices Which Fluctuate
Our future financial condition and results of operations depend upon
the prices we receive for our oil and natural gas. Historically, oil and natural
gas prices have been volatile and are subject to fluctuations in response to
changes in supply and demand, market uncertainty and a variety of additional
factors that are also beyond our control. Factors that affect the prices we
receive for our oil and natural gas include, without limitation:
o the level of domestic production;
o the availability of imported oil and natural gas;
o actions taken by foreign oil and natural gas producing nations;
o the availability of transportation systems with adequate capacity;
o the availability of competitive fuels;
o fluctuating and seasonal demand for natural gas;
o conservation and the extent of governmental regulation of production;
o weather;
o foreign and domestic government relations;
o the price of domestic and imported oil and natural gas; and
o the overall economic environment.
A substantial or extended decline in oil and/or natural gas prices may have a
material adverse effect on the estimated value of our natural gas and oil
reserves, and on our financial position, results of operations and access to
capital. Our ability to maintain or increase our borrowing capacity, to repay
current or future indebtedness and to obtain additional capital on attractive
terms is substantially dependent upon oil and natural gas prices.
Our Production Comes From a Small Number of Wells
Our existing proved oil and natural gas reserves and production are
highly concentrated in a small number of wells. Accordingly, to the extent that
we experience any operating difficulties with the wells, or to the extent our
actual proved reserves are less than those currently estimated to exist, we may
experience increased expenses and lower revenue.
We Have Incurred Losses in the Past
We had net losses of $205,000 and $511,000 for the years ended December
31, 1997 and 1998, respectively. We may incur net losses in the future, and
these losses may be substantial. Consequently, our liquidity may be reduced, and
we may be unable to raise capital. If our ability to raise capital is impaired
then we may be unable to implement our current business strategy.
We May Be Unable to Acquire or Develop Additional Reserves
Our future success as an oil and natural gas producer, as is generally
the case in the industry, depends upon our ability to find, develop or acquire
additional oil and natural gas reserves that are profitable. Factors which may
hinder our ability to acquire additional oil and natural gas reserves include
competition, access to capital, prevailing oil and natural gas prices and the
number of properties for sale. If we are unable to conduct successful
development activities or acquire properties containing proved reserves, our
proved reserves will generally decline as reserves are produced. We cannot
assure you that we will be able to locate additional reserves or that we will
drill economically productive wells or acquire properties containing proved
reserves.
We May Not Identify All Acquisition Risks
Generally, it is not feasible for us to review in detail every
individual property involved in an acquisition. Our business strategy includes
focused acquisitions of producing oil and natural gas properties. Any future
acquisitions will require an assessment of recoverable reserves, future oil and
natural gas prices, operating costs, potential environmental and other
liabilities and other similar factors. Ordinarily, our review efforts are
focused on
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the higher-valued properties. However, even a detailed review of these
properties and records may not reveal existing or potential problems, nor will
it permit us to become sufficiently familiar with the properties to assess fully
their deficiencies and capabilities. We do not inspect every well. Potential
problems, such as mechanical integrity of equipment and environmental conditions
that may require significant remedial expenditures, are not necessarily
observable even when we do inspect a well. Even if we identify problems, the
seller may be unwilling or unable to provide effective contractual protection
against all or part of these problems. We cannot assure you that newly acquired
oil and natural gas properties will be successfully integrated into our
operations or will achieve desired profitability.
We May Incur Significant Debt in the Future Which We May Be Unable to
Repay
Our level of indebtedness in the future may affect our operations in
the following ways:
o a substantial portion of our cash flow from operations may be
dedicated to the payment of interest and principal on our
indebtedness and would not be available for other purposes;
o the covenants contained in the credit facility which require us to
meet certain financial tests and other restrictions, will limit our
ability to borrow additional funds, to grant liens and to dispose
of assets and will affect our flexibility in planning for and
reacting to changes in our business, including possible acquisition
activities; and
o our ability to obtain additional financing in the future for
working capital, capital expenditures, acquisitions, general
corporate purposes or other purposes may be impaired.
Our ability to meet any future debt service obligations will be
dependent upon our future economic performance. Our future bank credit may not
be available in an amount sufficient to enable us to service our indebtedness or
make necessary expenditures. In that event, we would be required to obtain
financing from the sale of equity securities or other debt financing. Financing
may be unavailable on terms acceptable to us. Without sufficient capital, we may
be unable to continue to implement our business strategy.
We May Need Additional Financing for Growth Which We May Be Unable to
Obtain
The growth of our business will require substantial capital on a
continuing basis. The pledge of substantially all of our assets as collateral
for our credit facility will make it difficult in the foreseeable future for us
to obtain financing on an unsecured basis or to obtain secured financing other
than certain "purchase money" indebtedness collateralized by the acquired
assets. We may be unable to obtain additional capital on satisfactory
terms and conditions. Thus, we may lose opportunities to acquire oil and natural
gas properties and businesses. In addition, our pursuit of additional capital
may result in the incurrence of additional indebtedness or potentially dilutive
issuances of additional equity securities. We also may utilize the capital
currently expected to be available for our present operations. The amount and
timing of our future capital requirements, if any, will depend upon a number of
factors, including:
o drilling costs;
o transportation costs;
o equipment costs;
o marketing expenses;
o staffing levels and competitive conditions; and
o any purchases or dispositions of assets.
Our failure to obtain any required additional financing may have a material
adverse effect on our growth, cash flow and earnings.
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We Will Encounter Risks While Drilling
Our drilling involves numerous risks, including the risk that we will
not encounter commercially productive oil or natural gas reservoirs. We must
incur significant expenditures to identify and acquire properties and to drill
and complete wells. The cost of drilling, completing and operating wells is
often uncertain, and drilling operations may be curtailed, delayed or canceled
as a result of a variety of factors, including unexpected drilling conditions,
pressure or irregularities in formations, equipment failures or accidents,
weather conditions and shortages or delays in the delivery of equipment. In
addition, we may use 3-dimensional seismic and other advanced technology to
explore for oil and natural gas which may require greater pre-drilling
expenditures than traditional drilling strategies. We may be unsuccessful in our
future drilling activities.
Our Estimates of Oil and Natural Gas Reserves Involve Inherent
Uncertainty
Numerous uncertainties are inherent in estimating quantities of proved
oil and natural gas reserves, including many factors beyond our control. This
annual report contains an estimate of our proved oil and natural gas reserves
and the estimated future net cash flows and revenue generated by the proved oil
and natural gas reserves. These estimates are based upon reports of our
independent petroleum engineers. These reports rely upon various assumptions,
including assumptions required by the Securities and Exchange Commission, as to
constant oil and natural gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. These reports should not be
construed as the current market value of our estimated proved reserves. The
process of estimating oil and natural gas reserves is complex, requiring
significant decisions and assumptions in the evaluation of available geological,
engineering and economic data for each reservoir. As a result, these estimates
are inherently an imprecise evaluation of reserve quantities and future net
revenue. Our actual future production, revenue, taxes, development expenditures,
operating expenses and quantities of recoverable oil and natural gas reserves
may vary substantially from those we have assumed in the estimate. Any
significant variance in our assumptions could materially affect the estimated
quantity and value of reserves set forth in this annual report. In addition, our
reserves may be subject to downward or upward revision, based upon production
history, results of future exploitation and development activities, prevailing
oil and natural gas prices and other factors.
Our Properties are Geographically Concentrated
Currently, most of our properties are located in Texas, Oklahoma,
Louisiana, and Mississippi. Because of this concentration, we will be impacted
more adversely by regional events that increase our costs or level of
competition, reduce availability of equipment or supplies, and reduce demand or
limit production, than if we were geographically diversified.
We Are Exposed to Operating Hazards and Uninsured Risks
Our operations are subject to the risks inherent in the oil and natural
gas industry, including the risks of:
o fire, explosions, and blowouts;
o pipe failure;
o abnormally pressured formations; and
o environmental accidents such as oil spills, gas leaks, ruptures or
discharges of toxic gases, brine or well fluids into the environment
(including groundwater contamination).
These events may result in substantial losses to EXCO from:
o injury or loss of life;
o severe damage to or destruction of property, natural resources and
equipment;
o pollution or other environmental damage;
o clean-up responsibilities;
o regulatory investigation; and
o penalties and suspension of operations.
In accordance with customary industry practice, we maintain insurance against
some, but not all, of the risks we have described above. We cannot assure you
that our insurance will be adequate to cover these losses or liabilities.
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Further, we cannot predict the continued availability of insurance, or
availability of insurance at commercially acceptable premium levels. We do not
carry business interruption insurance. Losses and liabilities arising from
uninsured or under-insured events may have a material adverse effect on our
financial condition and operations.
From time to time, due primarily to contract terms, pipeline
interruptions or weather conditions, the producing wells in which we own an
interest have been subject to reduced or terminated production. These
curtailments may last from a few days to several months, or longer. We are not
currently experiencing any material curtailment on our production.
We May Writedown Our Asset Values
Under current accounting rules which we follow, we may be required to
writedown the value of our oil and natural gas properties if the present value
of the future cash flows from our oil and natural gas properties falls below the
net book value of these properties. This would affect our net worth which may
result in a covenant violation under our credit facility.
Our Stock Price May Be Volatile Due to Small Public Float
Because the number of shares of our common stock held by the public is
relatively small, the sale of a substantial number of shares of the common stock
in a short period of time may adversely affect the market price of the common
stock.
We Do Not Pay Dividends
We have never paid cash dividends on our common stock and do not
anticipate paying cash dividends on our common stock in the foreseeable future.
Our common stock is not a suitable investment for persons requiring current
income.
Our Articles of Incorporation or a Possible Issuance of Preferred Stock
May Prevent a Takeover Attempt
Provisions in our restated articles of incorporation effective
September 11, 1996 may delay, defer or prevent a tender offer or takeover
attempt that a shareholder might consider to be in the best interest of our
shareholders, including attempts that might result in a premium to be paid over
the market price for the stock held by our shareholders. The articles of
incorporation permit the board to issue up to 10,000,000 shares of preferred
stock and to establish by resolution one or more series of preferred stock and
to establish the powers, designations, preferences and relative, participating,
optional or other special rights of each series of preferred stock. The
preferred stock may be issued on terms that are unfavorable to the holders of
our common stock, including the grant of superior voting rights, the grant of
preferences in favor of preferred shareholders in the payment of dividends and
upon EXCO's liquidation and the designation of conversion rights that entitle
holders of preferred stock to convert their shares into common stock on terms
that are dilutive. The issuance of preferred stock may make a takeover or change
in control of EXCO more difficult. We do not intend to use the provisions of the
articles of incorporation to delay, defer or prevent a tender offer or takeover
attempt.
Our Business Depends on a Limited Number of Key Personnel
We are substantially dependent upon the skills of two key individuals
within our management, Mr. D. H. Miller and Mr. Eubank. Both individuals have
experience in restructuring oil and natural gas companies. Because we are
engaged in a new strategy, the loss of the services of either one of these
individuals may have a material adverse impact upon us.
We May Encounter Marketing Risks
Our future ability to market our oil and natural gas production will
depend upon the availability and capacity of natural gas gathering systems and
pipelines and other transportation facilities. With the exception of a few small
gathering systems, we do not currently operate our own pipelines or
transportation facilities, thus we are dependent on third parties to transport
our products.
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BUSINESS STRATEGY
We intend to become a leading independent oil and natural gas
acquisition, exploitation and production company by implementing the following
business strategies:
o Financial Growth. We plan to achieve asset, revenue and cash flow
growth as a result of the acquisition and further development of
producing oil and natural gas properties.
o Acquire and Enhance Producing Oil and Natural Gas Properties. We
plan to take advantage of opportunities that currently exist in the
United States to acquire producing oil and natural gas properties.
We continue to focus our acquisition activities onshore in Texas, New
Mexico, Oklahoma and Louisiana in order to complement our existing properties
and operations; however, we plan to review potential acquisitions in other
regions of the United States if they represent a significant concentration of
energy-related assets. We believe that numerous opportunities exist to acquire
additional energy assets and to enhance the value of these assets through
improved operating practices and by aggressively developing reserve potential.
o Emphasize Exploitation and Development Activities. We plan to
exploit existing oil and natural gas properties and to conduct
development evaluation and drilling on our existing and future oil
and natural gas properties. We intend to concentrate on enhancement
opportunities from activities such as infill drilling,
recompletions, secondary recovery projects, repairs and equipment
changes. We may participate, from time to time, in a limited number
of exploratory wells.
o Corporate Efficiencies. We plan to maximize corporate efficiencies
through the development and operation of a larger asset base with
the potential to limit increases in overhead in the future.
o Capital Management. We plan to maintain financial strength and
flexibility through effective management of debt and equity.
o Technology. We plan to increase exploitation efforts, focusing on
established geological trends where we can employ geological,
geophysical and engineering expertise. We are considering the
application of 3-D seismic and advanced drilling technologies.
In 1999, we evaluated approximately 223 acquisition opportunities with
an aggregate estimated market value of over $2.4 billion. We made offers on
properties totaling more than $970 million and successfully completed the
purchase of approximately $29.0 million. Offers varied in amounts from less than
$100,000 to $96.0 million. We intend to pursue large acquisitions that will have
a significant impact on our growth and smaller projects that have the potential
for high levels of profitability. We prefer to acquire properties with shallow
production, which offer lower geologic and mechanical risk of operations. In
evaluating prospective acquisitions, we generally focus on estimates of future
cash flows, rates of return, and net present values expected to be generated by
the acquired properties.
RECENT DEVELOPMENTS SINCE DECEMBER 31, 1999
We are Buying Our Stock from Shareholders Who Own Less Than 100 Shares
On January 15, 2000, we commenced an odd-lot stock repurchase program.
The program was originally scheduled to end on March 15, 2000, but was then
extended to May 15, 2000 by our board of directors. We are offering $8.50 per
share to any record or beneficial shareholder who owns less than 100 shares of
our common stock. The price was determined based upon a number of factors,
including trading prices for our common stock over the past 12 months and our
desire to maximize the response to this offer in order for us to achieve our
goal of reducing shareholder communication expenses. The record date to
determine eligible shareholders was December 31, 1999. As of December 31, 1999,
EXCO had approximately 1,400 odd-lot shareholders of record who owned 17,215
shares.
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We Executed a Second Amendment to Our Credit Agreement
On February 11, 2000, we entered into the second amendment to our
credit agreement. The credit facility consists of a regular revolver, which on
December 31, 1999, had a borrowing base of approximately $5.5 million. Under
terms of our credit agreement, on February 17, 2000 our borrowing base was
increased to $7.5 million. On February 29, 2000, our borrowing base was
increased to $13.0 million, and we had approximately $3.8 million available for
borrowing under the credit facility.
We Acquired Oil and Gas Natural Properties in Val Verde County, Texas
On February 25, 2000, we purchased certain oil and natural gas assets
located in Val Verde County, Texas from an undisclosed seller (the Val Verde
County Properties). The assets consist of 21 producing gas wells. Under terms of
the acquisition, we will become operator of 18 of the wells. As of September 30,
1999, total proved reserves net to our interest were estimated to include 19.8
Bcf of natural gas. Production for the month of December 1999, net to our
interest, was approximately 106 Mmcf of natural gas.
The purchase price of $12.2 million cash (approximately $11.4 million
after contractual adjustments and the waiver of certain preferential rights) was
paid from existing working capital and borrowings of $7.1 million under our
credit facility. The effective date of the acquisition was October 1, 1999.
These assets qualify as eligible replacement properties under our tax-deferred
exchange agreement. This use of tax-deferred exchange proceeds is in compliance
with the like-kind exchange provisions of Section 1031 of the Internal Revenue
Code. The price was determined through arms-length negotiation between the
parties.
We Executed a Letter of Intent to Form a Joint Venture and Acquire
Properties in Pecos County, Texas
On March 10, 2000, we entered into a letter of intent to form a joint
venture which will acquire certain natural gas assets located in Pecos County,
Texas from an undisclosed seller (the Pecos County Properties). The assets
consist of 8 producing gas wells. Under terms of the letter of intent, we will
become operator of 5 of the wells. As of January 1, 2000, under terms of the
current joint venture structure, total proved reserves net to our interest were
estimated to include 12.6 Bcf of natural gas.
The purchase price of approximately $10.3 million cash ($5.3 million
net to our interest) which is subject to contractual adjustments, will be paid
from existing working capital and anticipated borrowings of $6.8 million.
Borrowings are expected to be made under a new credit facility established for
the joint venture. The effective date of the acquisition is January 1, 2000. The
price was determined through arms-length negotiation between the parties.
Formation of the joint venture and acquisition of the Pecos County
Properties are subject to due diligence including title, environmental and
accounting reviews, as well as negotiation of a credit facility with terms
satisfactory to us.
OUR EXPLOITATION AND DEVELOPMENT ACTIVITIES
We made exploitation and development expenditures of $74,000, $257,000,
and $1.1 million during the years ended December 31, 1997, 1998, and 1999,
respectively. We made net acquisition expenditures of $2,000, $6.8 million, and
$13.6 million during the years ended December 31, 1997, 1998, and 1999,
respectively. Our ability to continue to fund our exploitation and development
activities depends upon cash flow and our ability to secure the necessary
financing for these activities.
OUR OPERATING ACTIVITIES
As of December 31, 1999, we were the operator of 117 gross (71.0 net)
wells, which represented approximately 41.2% of the gross wells and 51.5% of the
net wells in which we had an interest on that date. The remainder of the wells
in which we had an interest on December 31, 1999 are operated by third party
operators. The wells that we currently operate are located in Texas, Louisiana,
Mississippi and Kansas. On January 7, 2000, we took over operations of 29 gross
(20.0 net) producing wells of the Natchitoches Parish Properties at the Black
Lake Field in Louisiana. Although we elect to operate and manage most of our
properties and drilling activities, our wells are drilled by independent
drilling contractors.
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OUR OIL AND NATURAL GAS PROPERTIES
The following table sets forth the fields in which we have significant
oil and natural gas properties, and information as of December 31, 1999, with
respect to each of the fields.
YEAR ENDED
DECEMBER 31, 1999
WELLS PROVED RESERVES PERCENTAGE NET PRODUCTION
------------------ ------------------------ OF ------------------------
OIL(1) GAS EQUIVALENT OIL GAS
GROSS NET (BBLS) (MCF) RESERVES (BBLS) (MCF)
-------- --------- ----------- ------------ ------------ ------------ -----------
Black Lake Field................. 29 19.99 573,100 5,213,900 24.6% -- --
Ackerly Field.................... 8 4.02 454,900 312,600 8.6% 54,000 31,000
Chittim Field.................... 8 6.43 9,300 2,336,400 6.8% 1,100 143,000
Logansport Field................. 2 1.01 3,800 2,053,800 5.9% 200 29,100
Other............................ 237 106.50 2,072,600 6,631,300 54.1% 152,900 561,700
-------- --------- ----------- ------------ ------------ ------------ -----------
TOTAL.......................... 284 137.95 3,113,700 16,548,000 100.0% 208,200 764,800
======== ========= =========== ============ ============ ============ ===========
- ---------------
(1) Oil includes both oil and NGLs.
Black Lake Field
The Black Lake field is a prolific oil and natural gas field which is
located in Natchitoches Parish, Louisiana. The field produces oil, condensate,
NGLs and natural gas from the Pettit Lime formation at depths between 7,800 and
8,100 feet and is productive in over 19,000 acres. The field was discovered in
1964 and unitized prior to the start of production in 1966. Cumulative
production is over 1.1 trillion cubic feet of natural gas and 120 million Bbls
of oil. We purchased a 68.8% working interest in the field and currently serve
as the unit operator. Field production facilities include gas compression
equipment, a natural gas treating plant to remove carbon dioxide from the gas
stream and a refrigerated gas plant which recovers NGLs from the gas stream. The
field facilities also include a 60 Mmcf per day cryogenic gas plant which is
currently idle. Current reservoir pressure is low, but the field still has
significant recoverable reserves.
Ackerly Field
The Ackerly field is located in Dawson County, Texas. In 1998, we
acquired 8 gross (3.99 net) producing wells as the principal properties in the
Dawson County acquisition. These wells produce primarily oil from the Canyon
Reef and Dean formations at depths between 8,100 and 9,300 feet.
Chittim Field
The Chittim field is located in Maverick County, Texas. In 1998, we
acquired our interests in this field when we purchased the Chittim/Barclay Ranch
properties. Our wells produce natural gas from the Glen Rose Formation at depths
between 5,000 and 5,700 feet.
Logansport Field
We own working interests in two natural gas wells in the Logansport
field located in Desoto Parish, Louisiana. Our wells produce from a series of
low permeability reservoirs with long life natural gas reserves. Our reserves
are produced from the Hosston (Travis Peak) and Pettit formations from depths
between 6,000 and 7,500 feet.
Other
The other category consists of numerous unconcentrated fields located
in Kansas, Louisiana, Mississippi, North Dakota, Oklahoma, Texas and Wyoming.
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TITLE TO OUR PROPERTIES
When we acquire developed properties we conduct a title investigation,
however when we acquire undeveloped properties, as is common industry practice,
we conduct little or no investigation of title other than a preliminary review
of local mineral records. We do conduct title investigations and, in
most cases, obtain a title opinion of local counsel before we begin drilling
operations. We believe that the methods we utilize for investigating title prior
to acquiring any property are consistent with practices customary in the oil and
natural gas industry and that our practices are adequately designed to enable us
to acquire good title to properties. However, some title risks cannot be
avoided, despite the use of customary industry practices.
Our properties are generally subject to:
o customary royalty and overriding royalty interests;
o liens incident to operating agreements; and
o liens for current taxes and other burdens and minor encumbrances,
easements and restrictions.
We believe that none of these burdens either materially detract from the value
of our properties or materially interfere with their use in the operation of our
business. Substantially all of our properties are pledged as collateral under
our credit facility.
OUR OIL AND NATURAL GAS RESERVES
On December 31, 1999, our oil and natural gas reserves included direct
working interests in 280 wells in the states of Texas, Louisiana, Mississippi,
North Dakota, Kansas, Wyoming, and Oklahoma, as well as overriding royalties in
an additional 20 wells in Texas, Louisiana, Mississippi, Oklahoma and Michigan.
We also have direct working interests in 4 wells located offshore in the Gulf of
Mexico. On December 31, 1999, approximately 91.0% of the present value of the
estimated future net revenues attributable to our properties were attributable
to proved developed reserves and approximately 9.0% were attributable to proved
undeveloped reserves. In addition, approximately 53.0% of the proved reserves
were attributable to oil and NGLs and approximately 47.0% were attributable
to natural gas, on a Boe basis as discussed below.
The following table summarizes our proved reserves at December 31,
1999, and was prepared in accordance with the rules and regulations of the
Securities and Exchange Commission:
PROVED RESERVES
DECEMBER 31, 1999
(In thousands)
OIL(BBLS)(1) GAS (MCF) BOE(2)
------------ ----------- ---------
(In thousands)
Proved developed..................... 2,759 14,741 5,216
Proved undeveloped................... 355 1,807 656
------------ ----------- ---------
TOTAL................ 3,114 16,548 5,872
============ =========== =========
-----------
(1) Oil includes both oil and NGLs.
(2) Boe - Barrels of oil equivalent calculated by converting 6
Mcf of natural gas to 1 Bbl of oil. A Bbl is one stock
tank barrel, or 42 U.S. gallons liquid volume, of oil or
other liquid hydrocarbons. An Mcf is one thousand cubic
feet of natural gas.
A significant portion of the value of our proved undeveloped reserves
are in the Milroy, Palatine Hills, South Timbalier Block 76, Logansport and the
Nine Mile Draw fields. We must incur costs and undertake risks associated with
drilling and workover operations to recover these reserves.
The reserve estimates presented as of December 31, 1999 have been
prepared by Lee Keeling and Associates, Inc., independent petroleum engineers,
Tulsa, Oklahoma, and are a part of their report on our oil and natural gas
properties. Estimates of oil and natural gas reserves are, of necessity,
projections based on engineering data and, thus, are forward-looking in nature.
Moreover, because of the uncertainties inherent in the interpretation of
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this data, we cannot ensure that the reserves set forth herein will ultimately
be realized. Our actual results could differ materially. See Note 14,
Supplemental Oil and Natural Gas Reserve and Standardized Measure Information
included with our financial statements located elsewhere in this annual report
for additional information regarding our oil and natural gas reserves, including
the present value of future net revenues. Lee Keeling and Associates, Inc., also
prepared our reserve estimates as of December 31, 1996, 1997, and 1998.
WE HAVE NOT REPORTED RESERVES TO OTHER AGENCIES
As of December 31, 1999 our estimates of oil and natural gas reserves
have not been filed with or included in reports to any federal authority or
agency other than the Securities and Exchange Commission.
OUR PRODUCTION
The following table summarizes for the periods indicated, our revenues,
net production of oil (including condensate) and natural gas sold, the average
sales price per unit of oil (Bbl) and natural gas (Mcf) and costs and expenses
associated with the production of oil and natural gas:
YEAR ENDED DECEMBER 31,
---------------------------------------
1997 1998 1999
----------- ----------- -----------
Sales:
Oil:
Revenue ........................ $ 283,000 $ 634,000 $ 3,785,000
Production sold (Bbls) ......... 14,453 52,707 208,231
Average sales price per Bbl .... $ 19.56 $ 12.01 $ 18.18
Natural Gas:
Revenue ........................ $ 387,000 $ 751,000 $ 1,583,000
Production sold (Mcf) .......... 181,091 412,124 764,835
Average sales price per Mcf .... $ 2.14 $ 1.82 $ 2.07
Costs and Expenses:
Production costs per Boe ....... $ 7.21 $ 6.48 $ 7.07
Depreciation, depletion and
amortization per Boe .......... $ 1.41 $ 3.17 $ 4.31
Our total oil and natural gas revenues for the year ended December 31,
1999 increased 288% from the prior year primarily due to increases in production
volumes resulting from acquisitions we completed during 1999. Our average sales
price per barrel of oil increased $6.17 or 51%, and our average sales price per
Mcf of natural gas increased $.25, or 14%, from prices for the year ended
December 31, 1998.
Our total oil and natural gas revenues for the year ended December 31,
1998 increased 107% from the year ended December 31, 1997 due to increases in
our production volumes resulting from acquisitions we completed during 1998. The
effect of these increased volumes outweighed the decreased sales prices for both
oil and natural gas. Our average sales price per barrel of oil decreased $7.55,
or 39% and our average sales price per Mcf of natural gas decreased $.32, or
15%, from our prices for the period ended December 31, 1997.
The net production we reported in the preceding table only includes
revenue, production, production costs, and sales prices for our share of the oil
and natural gas after payment of royalties, if any. Our oil production for the
year ended December 31, 1999 was 295% higher and our natural gas production was
86% higher than for the year ended December 31, 1998. Our oil production for the
year ended December 31, 1998 was 265% higher and our natural gas production was
128% higher than the period ended December 31, 1997. On a Boe basis, our total
production for the year ended December 31, 1999 increased 177% from the year
ended December 31, 1998, and our total production for the year ended December
31, 1998 increased 172% from the period ended December 31, 1997.
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OUR INTEREST IN PRODUCTIVE WELLS
The following table sets forth our interest in productive wells
(producing wells and temporarily shut-in wells) on December 31, 1999. The number
of total gross oil and natural gas wells excludes any multiple completions. On
December 31, 1999, we did not own an interest in any well that was being
completed.
GROSS WELLS NET WELLS
------------------------------ --------------------------------
OIL GAS TOTAL OIL GAS TOTAL
-------- -------- -------- -------- -------- --------
Kansas .......... 1 2 3 1 1.08 2.08
Louisiana ....... 11 35 46 5.15 21.11 26.26
Mississippi ..... 23 -- 23 20.08 -- 20.08
North Dakota .... 2 -- 2 0.08 -- 0.08
Oklahoma ........ 37 27 64 34.52 2.31 36.83
Texas ........... 76 64 140 28.39 23.91 52.30
Wyoming ......... 6 -- 6 0.32 -- 0.32
-------- -------- -------- -------- -------- --------
TOTAL ........... 156 128 284 89.54 48.41 137.95
OUR DRILLING ACTIVITIES
We intend to continue concentrating on lower risk, development-type
properties by drilling to reservoirs from which production is, or was, being
obtained. In the past, we have drilled higher risk, exploratory-type wells. The
number and type of wells we drill will vary depending on the amount of funds we
have available for drilling, the cost of each well, the size of the fractional
working interests we acquire in each well and the estimated recoverable reserves
attributable to each well.
The following table summarizes our approximate gross and net interests
in the exploratory and development wells drilled during the periods indicated
and refers to the number of wells (holes) completed at any time during a period,
regardless of when drilling was initiated:
EXPLORATORY WELLS
------------------------------------------------------------------------
GROSS NET
---------------------------------- ----------------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
------------ ---------- ---------- ------------ ---------- ----------
Year ended December 31, 1997 ............. -- -- -- -- -- --
Year ended December 31, 1998 ............. -- -- -- -- -- --
Year ended December 31, 1999 ............. -- 1 1 -- .40 .40
DEVELOPMENT WELLS
------------------------------------------------------------------------
GROSS NET
---------------------------------- ----------------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
------------ ---------- ---------- ------------ ---------- ----------
Year ended December 31, 1997 ............. 1 -- 1 .12 -- .12
Year ended December 31, 1998 ............. 1 -- 1 .49 -- .49
Year ended December 31, 1999 ............. 2 2 4 1.25 1.41 2.66
The drilling activities referenced in the above tables were conducted
in Texas, Louisiana, Oklahoma and Mississippi. As of February 29, 2000, we were
participating in drilling one 10,600 foot development well in Val Verde County,
Texas. At this time, we have no additional commitments to drill any wells.
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OUR INTEREST IN DEVELOPED AND UNDEVELOPED ACREAGE
The following table sets forth our interest in developed and
undeveloped acreage on December 31, 1999:
DEVELOPED ACREAGE UNDEVELOPED ACREAGE
------------------------- ------------------------
GROSS NET GROSS NET
------------ ------------ ----------- ------------
Kansas ...................................... 240 93 768 178
Louisiana ................................... 26,562 12,317 10,604 8,431
Mississippi ................................. 1,562 1,340 1,586 1,265
North Dakota ................................ 472 15 320 8
Oklahoma .................................... 9,451 1,166 320 283
Texas ....................................... 24,986 8,018 12,652 6,219
Wyoming ..................................... 280 15 40 2
------------ ------------ ----------- ------------
TOTAL ..................................... 63,553 22,964 26,290 16,386
The primary terms of the oil and natural gas leases covering the
majority of our undeveloped acreage expire at various dates, generally ranging
from one to five years. We can retain our interest in undeveloped acreage by
drilling activity that establishes commercial reserves sufficient to maintain
these leases. Some of our undeveloped acreage in Texas is being "held by
production," meaning these leases are active as long as we produce oil and
natural gas from the acreage. Upon ceasing production, these leases will expire.
OUR PAST SALES OF PRODUCING PROPERTIES AND UNDEVELOPED ACREAGE
We evaluate properties on an ongoing basis to determine the economic
viability of the properties and whether these properties enhance our objectives.
During the course of normal business, we may dispose of producing properties and
undeveloped acreage if we believe that it is in our best interest.
In the year ended December 31, 1999, we sold our interest in three
major groups of producing oil and natural gas properties in Louisiana and the
Gulf of Mexico for a total of approximately $20.1 million after adjustments. In
the year ended December 31, 1998, we had no material sales of producing
properties. In the year ended December 31, 1997, we sold our interest in three
major groups of producing oil properties in Texas and Illinois for a total of
$270,000.
OUR PRODUCTS, MARKETS AND REVENUES
We produce oil and natural gas. We do not refine or process the oil
and, with the exception of the Natchitoches Parish Properties, the natural gas
that we produce. In the past, we sold the oil we produced under short-term
contracts at market prices in the areas in which the producing properties were
located, generally at F.O.B. field prices posted by the principal purchaser of
oil in these areas. In 1999, we switched a majority of our contracts to NYMEX
based pricing, which is typically calculated as the average of the daily
closing prices of quantities of oil and natural gas to be delivered one month in
the future. NYMEX is a commodities exchange where most oil and natural gas
futures contracts are traded in the U.S. This allows us to highly correlate
changes in the price we get for selling our oil and natural gas to changes in
the value of any NYMEX based hedging agreements we may enter into. A high
correlation between the product prices we receive and amounts we pay or
receive on our hedge agreements is necessary to avoid booking as expenses on
our consolidated statement of operations, unrealized hedge losses during the
term of the hedge agreements as will be required by Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities."
We sell the natural gas we produce under both short-term and long-term
contracts. We sell the natural gas to transmission and utility companies that
have pipelines in the vicinity of our producing properties or to companies that
will construct pipelines to our properties. Our sales contracts are of a type
common within the industry, and we negotiate a separate contract for each
property. Typically, we negotiate sales contracts for terms ranging from
day-to-day up to six months.
The availability of a ready market for oil and natural gas and the
prices of oil and natural gas are dependent upon a number of factors that are
beyond our control. These factors include, among other things:
o the level of domestic production and economic activity generally;
o the availability of imported oil and natural gas;
o actions taken by foreign oil producing nations;
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o the availability of natural gas pipelines with adequate capacity and
other transportation facilities;
o the availability and marketing of other competitive fuels,
fluctuating and seasonal demand for oil, natural gas and refined
products; and
o the extent of governmental regulation and taxation (under both
present and future legislation) of the production, refining,
transportation, pricing, use and allocation of oil, natural gas,
refined products and substitute fuels.
Accordingly, in view of the many uncertainties affecting the supply and demand
for oil, natural gas and refined petroleum products, we cannot predict
accurately the prices or marketability of the oil and natural gas from any
producing well in which we have or may acquire an interest.
Oil prices have been subject to significant fluctuations over the past
several decades. Levels of production maintained by the Organization of
Petroleum Exporting Countries member nations and other major oil producing
countries are expected to continue to be a major determinant of oil price
movements in the future. As a result, future oil price movements cannot be
predicted with any certainty. Similarly, during the past several years, the U.S.
market price for natural gas has been subject to significant fluctuations on a
monthly basis as well as from year to year. These frequent changes in the market
price make it impossible for us to predict natural gas price movements with any
certainty.
We cannot assure you that we will be able to market all the oil or
natural gas that we produce or, if our oil or natural gas can be marketed, that
we can negotiate favorable price and contractual terms. Changes in oil and
natural gas prices may significantly affect our revenues and cash flow and the
value of our oil and natural gas properties. Further, significant declines in
the prices of oil and natural gas may have a material adverse effect on our
business and financial condition.
We engage in oil and natural gas production activities in areas, where
from time to time the supply of oil and natural gas available for delivery
exceeds the demand. In this situation, companies purchasing oil and natural gas
in these areas reduce the amount of oil and natural gas that they may purchase
from us. If we cannot locate other buyers for our production or any of our newly
discovered oil and natural gas reserves, we may shut-in our oil and natural gas
wells for periods of time.
The following table sets forth the amount of our oil sales, natural gas
sales and the percent of these sales to total oil and natural gas revenues for
the periods indicated (in thousands):
PERCENT OF
SALES TO TOTAL OIL
AND GAS REVENUES
NATURAL TOTAL OIL ---------------------
PERIOD ENDED OIL SALES GAS SALES AND GAS SALES OIL GAS
- ----------------------------------------------------- --------- --------- ------------- ---------- ----------
Year ended December 31, 1997 ...................... $ 283 $ 387 $ 670 42% 58%
Year ended December 31, 1998 ...................... $ 634 $ 751 $ 1,385 46% 54%
Year ended December 31, 1999 ...................... $ 3,785 $ 1,583 $ 5,368 71% 29%
OUR CURRENT DELIVERY COMMITMENTS
We are not presently obligated to provide a fixed and determinable
quantity of oil or natural gas under any existing contract or agreement.
OUR PRINCIPAL CUSTOMERS
During the year ended December 31, 1999, sales of oil and
natural gas to 2 purchasers, EOTT Energy Operating Limited Partnership and
Plains All American, Inc., accounted for 27% and 36% respectively, of our total
oil and natural gas revenues. If we were to lose any one of our oil and natural
gas purchasers, then the loss could
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temporarily cease or delay production and sale of our oil and natural gas in
the purchaser's particular service area. We believe we would be able, under
current economic circumstances, to contract with other purchasers for our oil
and natural gas production if we were to lose any one of our oil and natural gas
purchasers.
During the year ended December 31, 1998, sales of oil and natural gas
to two purchasers, EOTT Energy Operating Limited Partnership and Scurlock
Permian LLC accounted for 17% and 10%, respectively, of our total revenues.
During the year ended December 31, 1997, sales of oil and natural gas to three
purchasers, Scurlock Permian Corporation, Delhi Gas Pipeline Corporation, and
Aurora Natural Gas, L.L.C., accounted for 22%, 19%, and 14%, respectively, of
our total revenues.
WE ENCOUNTER STRONG COMPETITION
The oil and natural gas industry is highly competitive. We encounter
strong competition from other independent operators and from major oil companies
in acquiring properties, contracting for drilling equipment and securing
trained personnel. Many of these competitors have financial and technical
resources and staffs substantially larger than those available to us. As a
result, our competitors may be able to pay more for desirable leases and they
may pay more to evaluate, bid for and purchase a greater number of properties or
prospects than our financial or personnel resources will permit.
We are also affected by competition for drilling rigs and the
availability of related equipment. Currently, with relatively high oil prices,
the oil and natural gas industry may experience shortages of drilling rigs,
equipment, pipe and personnel. We are unable to predict how long current market
conditions will continue, or its direct effect on our development and
exploitation program.
Competition for attractive oil and natural gas producing properties,
undeveloped leases and drilling rights is also strong, and we cannot assure you
that we will be able to compete satisfactorily in acquiring properties. Many
major oil companies have publicly indicated their decisions to concentrate on
overseas activities and have been actively marketing some of their existing
producing properties for sale to independent producers. We cannot assure you
that we will be successful in acquiring any of these properties.
WE ARE AFFECTED BY VARIOUS LAWS AND REGULATIONS
General
From time to time political developments and federal and state laws and
regulations affect our operations in varying degrees. Price control, tax and
other laws relating to the oil and natural gas industry, and changes in these
laws and regulations affect our oil and natural gas production, operations and
economics. There are currently no price controls on oil, condensate or NGLs. To
the extent price controls remain applicable after the enactment of the Natural
Gas Wellhead Decontrol Act of 1989, we are of the opinion that price controls
will not have a significant impact on the prices we receive for natural gas we
produce in the near future.
We review legislation affecting the oil and natural gas industry for
amendments. The legislative review frequently increases our regulatory burden.
Also, numerous departments and agencies, both federal and state, are authorized
by statute to issue and have issued rules and regulations binding on the oil and
natural gas industry and its individual members, compliance with which is often
difficult and costly and some of which may carry substantial penalties if we
were to fail to comply. We cannot predict how existing regulations may be
interpreted by enforcement agencies or the courts, nor whether amendments or
additional regulations will be adopted, nor what effect such interpretations and
changes may have on our business or financial condition.
Matters subject to regulation include:
o discharge permits for drilling operations;
o drilling and abandonment bonds or other financial responsibility
requirements;
o reports concerning operations;
o the spacing of wells;
o unitization and pooling of properties; and
o taxation.
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Natural Gas Regulation and the Effect on Marketing
Historically, interstate pipeline companies generally acted as
wholesale merchants by purchasing natural gas from producers and reselling the
natural gas to local distribution companies and large end users. Commencing in
late 1985, the Federal Energy Regulatory Commission 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, 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 natural gas balancing services), and to adopt a new rate
making 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 in the future, it does so pursuant to private contracts in direct
competition with all other sellers, such as the Company; however, pipeline
companies and their affiliates were not required to remain "merchants" of
natural gas, and most of the interstate pipeline companies have become
"transporters only." In subsequent orders, the FERC largely affirmed the major
features of Order 636 and denied a stay of the implementation of the new rules
pending judicial review. By the end of 1994, the FERC had concluded the Order
636 restructuring proceedings, and, in general, accepted rate filings
implementing Order 636 on every major interstate pipeline. However, even through
the implementation of Order 636 on individual interstate pipelines is
essentially complete, many of the individual pipeline restructuring proceedings,
as well as Order 636 itself and the regulations promulgated thereunder, are
subject to pending appellate review and could possibly be changed as a result of
future court orders. We cannot predict for you whether the FERC's orders will be
affirmed on appeal or what the effects will be on our business.
In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural
gas. Some of the more notable of these regulatory initiatives include:
o 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 affiliate);
o the completion of a rule making involving the regulation of
pipelines with marketing affiliates under Order No. 497;
o the FERC's ongoing efforts to promulgate standards for pipeline
electronic bulletin boards and electronic data exchange;
o a generic inquiry into the pricing of interstate pipeline
capacity;
o efforts to refine the FERC's regulations controlling operation of
the secondary market for released pipeline capacity; and
o a policy statement regarding market based rates and other
non-cost-based rates for interstate pipeline transmission and
storage capacity.
Several of these initiatives are intended to enhance competition in natural gas
markets, although some, such as "spin downs," may have the adverse effect of
increasing the cost of doing business to some in the industry as a result of the
monopolization of those facilities by their new, unregulated owners. The FERC
has attempted to address some of these concerns in its orders authorizing such
"spin downs," but it remains to be seen what effect these activities will have
on access to markets and the cost of doing business. As to all of these recent
FERC initiatives, the ongoing, or in some instances, preliminary nature of these
regulatory initiatives makes it impossible at this time for us to predict their
ultimate impact on our business.
We own, directly or indirectly, certain natural gas facilities that we
believe meet the traditional tests the FERC has used to establish a company's
status as a gatherer not subject to FERC jurisdiction under the Natural Gas Act
of 1938. Moreover, recent orders of the FERC have been more liberal in their
reliance upon or use of the traditional tests, such that in many instances, what
was once classified as "transmission" may now be classified as "gathering." We
transport our own natural gas through these facilities. We also transport a
portion of our natural
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gas through gathering facilities owned by others, including interstate
pipelines. Although these FERC orders have created the potential for
increasing our natural gas shipping costs on third party gathering facilities,
our shipping activities have not been materially affected by these orders.
Federal Taxation
The federal government may propose tax initiatives that affect us. We
are unable to determine what effect, if any, future proposals would have on
product demand or our results of operations.
State Regulation
The various states in which we conduct activities regulate our
drilling, operation and production of oil and natural gas wells, including the
method of developing new fields, spacing of wells, the prevention and clean-up
of pollution, and maximum daily production allowables based on market demand and
conservation considerations.
Environmental Regulation
Our exploration, development and production of oil and natural gas,
including our operation of saltwater injection and disposal wells, are subject
to various federal, state and local environmental laws and regulations. These
laws and regulations can increase the costs of planning, designing, installing
and operating oil and natural gas wells. Our domestic activities are subject to
a variety of environmental laws and regulations, including, but not limited to:
o the Oil Pollution Act of 1990;
o the Clean Water Act;
o the Comprehensive Environmental Response, Compensation and Liability
Act;
o the Resource Conservation and Recovery Act;
o the Clean Air Act; and
o the Safe Drinking Water Act,
as well as state regulations promulgated under comparable state statutes. These
laws and regulations:
o require the acquisition of a permit before drilling commences;
o restrict the types, quantities and concentration of various
substances that can be released into the environment in connection
with drilling and production activities;
o limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas; and
o impose substantial liabilities for pollution which might result from
our operations.
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We also are subject to regulations governing the handling, transportation,
storage and disposal of naturally occurring radioactive materials that are found
in our oil and natural gas operations. Civil and criminal fines and penalties
may be imposed for non-compliance with these environmental laws and regulations.
Additionally, these laws and regulations require the acquisition of permits or
other governmental authorizations before undertaking certain activities, limit
or prohibit other activities because of protected areas or species and impose
substantial liabilities for cleanup of pollution.
Under the Oil Pollution Act, a release of oil into water or other areas
designated by the statute could result in the Company being held responsible for
the costs of remediating a release, specified damages and natural resource
damages. The extent of that liability could be extensive, as set forth in the
statute, depending on the nature of the release. A release of oil in harmful
quantities or other materials into water or other specified areas could also
result in the Company being held responsible under the Clear Water Act for the
cost of remediation, and civil and criminal fines and penalties.
CERCLA and comparable state statutes, also known as "Superfund" laws,
can impose joint, several and retroactive liability, without regard to fault or
the legality of the original conduct, on certain classes of persons for the
release of a "hazardous substance" into the environment. In practice, cleanup
costs are usually allocated among various responsible parties. Potentially
liable parties include site owners or operators, past owners or operators under
certain conditions and entities that arrange for the disposal or treatment of,
or transport of hazardous substances found at the site. Although CERCLA, as
amended, currently exempts petroleum, including, but not limited to, crude oil,
gas and natural gas liquids from the definition of hazardous substance, our
operations may involve the use or handling of other materials that may be
classified as hazardous substances under CERCLA. Furthermore, we cannot assure
you that the exemption will be preserved in future amendments of the Act, if
any.
RCRA and comparable state and local requirements impose standards for
the management, including treatment, storage and disposal of both hazardous and
nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in
connection with our routine operations. From time to time, proposals have been
made that would reclassify certain oil and natural gas wastes, including wastes
generated during pipeline, drilling and production operations, as "hazardous
wastes" under RCRA which would make these solid wastes subject to much more
stringent handling, transportation, storage, disposal and clean-up requirements.
This development could have a significant impact on our operating costs. While
state laws vary on this issue, state initiatives to further regulate oil and
natural gas wastes may have a similar impact on our operations.
Because oil and natural gas exploration and production, and possibly
other activities, have been conducted at some of our properties by previous
owners and operators, materials from these operations remain on some of the
properties and in some instances require remediation. In addition, we have
agreed to indemnify the sellers of producing properties from whom we have
acquired reserves against certain liabilities for environmental claims
associated with the properties. While we do not believe the costs to be incurred
by us for compliance and remediating previously or currently owned or operated
properties will be material, we cannot guarantee that these potential costs will
not result in material expenditures.
Additionally, in the course of our routine oil and natural gas
operations, surface spills and leaks, including casing leaks, of oil or other
materials occur, and we may incur costs for waste handling and environmental
compliance associated with these leaks. Moreover, we are able to control
directly the operations of only those wells which we operate. Notwithstanding
our lack of control over wells owned by us but operated by others, the failure
of the operator to comply with applicable environmental regulations may be, in
certain circumstances, attributable to us.
It is not anticipated that we will be required in the near future to
expend amounts that are material in relation to our total capital expenditures
program by reason of environmental laws and regulations, but inasmuch as these
laws and regulations are frequently changed, we are unable to predict the
ultimate cost of compliance. More stringent laws and regulations protecting the
environment may be adopted and we may be required to incur material expenses in
connection with environmental laws and regulations in the future.
Other Proposed Legislation
The recent trend toward stricter standards in environmental legislation
and regulation is likely to continue. For instance, legislation has been
proposed in the U.S. Congress from time to time that would reclassify certain
crude
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oil and natural gas exploitation and production wastes as "hazardous wastes"
which would make the reclassified wastes subject to much more stringent
handling, disposal and clean-up requirements. If this legislation were to be
enacted, it may have a significant impact on our operating costs, as well as the
oil and natural gas industry in general. Initiatives to further regulate the
disposal of crude oil and natural gas wastes are also pending in various states,
and these various initiatives may have a similar impact on us. We may incur
substantial costs to comply with environmental laws and regulations. In addition
to compliance costs, government entities and other third parties may assert
substantial liabilities against owners and operators of oil and natural gas
properties for oil spills, discharge of hazardous materials, remediation and
clean-up costs and other environmental damages, including damages caused by
previous property owners. As a result, substantial liabilities to third parties
or governmental entities may be incurred, the payment of which may reduce or
eliminate the funds available for project investment or result in loss of our
properties. Although we maintain insurance coverage we consider to be customary
in the industry, we are not fully insured against all of these risks, either
because insurance is not available or because of high premium costs.
Accordingly, we may be subject to liability or may lose substantial portions of
properties due to hazards that cannot be insured against or have not been
insured against due to prohibitive premium costs or for other reasons. The
imposition of any of these liabilities on us may have a material adverse effect
on our financial condition and results of operations.
OUR EMPLOYEES
As of December 31, 1999, we employed 25 persons of which 4 were
involved in field operations and 21 were engaged in office and administrative
activities. None of our employees are represented by unions or covered by
collective bargaining agreements. To date, we have not experienced any strikes
or work stoppages due to labor problems, and we consider our relations with our
employees to be good. We also utilize the services of independent consultants on
a contract basis.
OUR EXECUTIVE OFFICERS
DOUGLAS H. MILLER, 52, was elected Chairman and Chief Executive Officer
of EXCO in December 1997. Mr. Miller was Chairman of the Board and Chief
Executive Officer of Coda Energy, Inc., an independent oil and gas company, from
October 1989 until November 1997 and served as a director of Coda from 1987
until November 1997.
T. W. EUBANK, 57, was elected President, Treasurer and a director of
EXCO in December 1997. Mr. Eubank was a consultant to various private companies
from February 1996 to December 1997. Mr. Eubank served as President of Coda from
March 1985 until February 1996. He was a director of Coda from 1981 until
February 1996.
J. DOUGLAS RAMSEY, PH.D., 39, was elected a Vice President and Chief
Financial Officer of EXCO in December 1997. Dr. Ramsey has been a director of
EXCO since March 1998. Dr. Ramsey most recently was Financial Planning Manager
of Coda and has worked in various capacities for Coda from 1992 until 1997. Dr.
Ramsey also teaches finance at Southern Methodist University.
CHARLES R. EVANS, 46, joined EXCO in February 1998 and became a Vice
President in March 1998. Mr. Evans graduated from Oklahoma University with a
B.S. degree in Petroleum Engineering in 1976. After working for Sun Oil Co., he
joined TXO Production Corp. in 1979 and was elected Vice President of
Engineering and Evaluation in 1989 and Vice President of Engineering and Project
Development for Delhi Gas Pipeline Corporation, a natural gas gathering,
processing and marketing company, in 1990. Mr. Evans most recently was
Director-Environmental Affairs and Safety for Delhi until December 1997.
JOHN D. JACOBI, 47, became a Vice President of EXCO in February 1999.
Mr. Jacobi received his B.S. degree from West Texas State University. He
co-founded Jacobi-Johnson Energy, Inc., an independent oil and natural gas
producer, in 1991 and was its President until January 1997. He then served as
its Vice President and Treasurer until May 8, 1998, when the company was sold to
EXCO.
DANIEL A. JOHNSON, 48, became a Vice President of EXCO in February
1999. Mr. Johnson graduated from Texas A&M University with a B.S. degree in
Petroleum Engineering. In 1991, he co-founded Jacobi-Johnson
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Energy, Inc., an independent oil and natural gas producer. He served as its
President from January 1997 until the company was sold to EXCO on May 8, 1998.
RICHARD E. MILLER, 46, became General Counsel and General Land Manager
and was elected Secretary of EXCO in December 1997. Mr. Miller was a senior
partner and head of the Energy Section of Gardere & Wynne, L.L.P., a Dallas
based law firm, from December 1991 to September 1994. Mr. Miller practiced law
as a sole practitioner from September 1994 to December 1997.
GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms
commonly used in the oil and natural gas industry and this annual report.
"BBL." One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.
"BCF." One billion cubic feet of natural gas.
"BOE." Barrels oil equivalent. Calculated by converting 6 Mcf of
natural gas to 1 Bbl of oil.
"INFILL DRILLING." Drilling of a well between known producing wells to
better exploit the reservoir.
"MBOE." One thousand barrels oil equivalent.
"MCF." One thousand cubic feet of natural gas.
"NGL." The combination of ethane, propane, butane and natural gasolines
that when removed from natural gas become liquid under various levels of higher
pressure and lower temperature.
"OVERRIDING ROYALTY INTEREST." An interest in an oil and/or natural gas
property entitling the owner to a share of oil and natural gas production free
of costs of production.
"PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES." The present value of
estimated future net revenues is an estimate of future net revenues from a
property at December 31, 1999, at its acquisition date, or as otherwise
indicated, after deducting production and ad valorem taxes, future capital costs
and operating expenses, but before deducting federal income taxes. The future
net revenues have been discounted at an annual rate of 10% to determine their
"present value." The present value is shown to indicate the effect of time on
the value of the net revenue stream and should not be construed as being the
fair market value of the properties. Estimates have been made using constant oil
and natural gas prices and operating costs at December 31, 1999, at its
acquisition date, or as otherwise indicated. We believe that the present value
of estimated future net revenues before income taxes, while not in accordance
with generally accepted accounting principles, is an important financial measure
used by investors and independent oil and natural gas producers for evaluating
the relative significance of oil and natural gas properties and acquisitions.
"TCF." One trillion cubic feet of natural gas.
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ITEM 2. PROPERTIES
GENERAL
We lease approximately 7,700 square feet of office space in Dallas,
Texas, for our corporate offices. The lease expires December 31, 2000 and
requires a monthly rental payment of approximately $9,200. We consider this
space adequate for our present needs. We also have an office in Tyler, Texas.
OTHER
We have described our oil and natural gas properties, oil and natural
gas reserves, acreage, wells, production and drilling activity in Item 1
beginning on page 1 of this annual report.
ITEM 3. LEGAL PROCEEDINGS
During 1999, we were not a party to any material legal proceeding.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the last three months of the year ended December 31, 1999, we
did not submit any matter to a vote by our shareholders through the solicitation
of proxies or otherwise.
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PART II
ITEM 5. MARKET FOR THE REGISTRANTS COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
MARKET INFORMATION FOR OUR COMMON STOCK
Our common stock is currently quoted on the Nasdaq National Market
System (Nasdaq NMS) under the symbol "EXCO", however there is limited trading in
our common stock. The following table sets forth the high and low bid prices
from January 1, 1997 through December 31, 1999, based upon quotations
periodically published on the Nasdaq NMS and the OTC Bulletin Board where our
stock was traded until September 16, 1998. The price quotations below have been
adjusted to estimate the effect of our one-for-two reverse stock split of the
common stock in the case of quotations for periods prior to March 31, 1998, the
effective date of the stock split. All price quotations represent prices between
dealers, without retail mark-ups, mark-downs or commissions and may not
represent actual transactions.
HIGH LOW
-------- --------
Year ended December 31, 1998
First Quarter ................... $ 7.00 $ 6.00
Second Quarter .................. 6.50 6.50
Third Quarter ................... 7.50 6.00
Fourth Quarter .................. 7.88 7.00
Year ended December 31, 1999
First Quarter ................... $ 7.50 $ 6.25
Second Quarter .................. 6.75 6.00
Third Quarter ................... 7.75 7.00
Fourth Quarter .................. 7.00 6.00
The bid price for our common stock was $6.625 on February 29, 2000.
OUR SHAREHOLDERS
According to the records of our transfer agent, there were
approximately 1,380 holders of record of our common stock on February 29, 2000
(including nominee holders such as banks and brokerage firms who hold shares for
beneficial holders).
OUR DIVIDEND POLICY
We have not paid any cash dividends on our common stock, and do not
anticipate paying cash dividends on our common stock in the foreseeable future.
In addition, our credit facility currently prohibits us from paying dividends.
We anticipate that any income generated in the foreseeable future will be
retained for the development and expansion of our business. Our future dividend
policy is subject to the discretion of the board of directors and will depend
upon a number of factors, including future earnings, debt service, capital
requirements, restrictions in our credit facility, business conditions, our
financial condition and other factors that our board of directors deems
relevant.
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ITEM 6. SELECTED FINANCIAL DATA
The following table presents our selected historical financial data.
You should read this financial data in conjunction with our consolidated
financial statements, the notes to our consolidated financial statements and the
other financial information, including pro forma information, included in this
annual report. This information does not replace the consolidated financial
statements. In our opinion, the data we have presented reflects all adjustments
we consider necessary for a fair presentation of the results for such periods.
NINE MONTH
TRANSITION
PERIOD ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31,
------------- ------------------------------------------------
1995(1) 1996(1) 1997 1998 1999
------------- --------- --------- --------- ---------
(In thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and natural gas .............................. $ 560 $ 872 $ 670 $ 1,385 $ 5,368
Other ............................................ 76 39 28 690 1,934
Gain on disposition of properties ................ -- -- -- -- 5,102
--------- --------- --------- --------- ---------
Total revenues ............. 636 911 698 2,075 12,404
Costs and expenses:
Oil and natural gas production ................... 333 429 322 786 2,375
Depreciation, depletion and
amortization .................................. 92 114 84 465 1,446
General and administrative ....................... 366 373 486 1,231 1,934
Interest expense ................................. 5 18 11 104 17
Other (2) ........................................ -- 303 -- -- --
--------- --------- --------- --------- ---------
Total expenses ............. 796 1,237 903 2,586 5,772
--------- --------- --------- --------- ---------
Income (loss) before income taxes
and minority interest .............................. (160) (326) (205) (511) 6,632
Minority interest in limited partnership .............. -- -- -- -- (7)
--------- --------- --------- --------- ---------
Income (loss) before income taxes ..................... (160) (326) (205) (511) 6,639
Income taxes .......................................... -- -- -- -- 2,139
--------- --------- --------- --------- ---------
Net income (loss) before extraordinary items .......... (160) (326) (205) (511) 4,500
Fee income from early extinguishment of debt,
net of tax ......................................... -- -- -- -- 165
--------- --------- --------- --------- ---------
Net income (loss) ..................................... $ (160) $ (326) $ (205) $ (511) $ 4,665
========= ========= ========= ========= =========
Basic and diluted earnings (loss) per share (3)(4)..... $ (.47) $ (.85) $ (.51) $ (.18) $ .69
========= ========= ========= ========= =========
Weighted average common and common
equivalent shares outstanding:
Basic ............................................ 338 383 403 2,871 6,698
========= ========= ========= ========= =========
Diluted .......................................... 338 383 403 2,874 6,714
========= ========= ========= ========= =========
DECEMBER 31,
---------------------------------------------------------
1995 1996 1997 1998 1999
--------- --------- --------- --------- ---------
BALANCE SHEET DATA: (In thousands)
Current assets ................. $ 582 $ 373 $ 727 $ 22,157 $ 31,599
Oil and gas properties, net .... 820 749 473 7,554 18,674
Total assets ................... 1,511 1,226 1,270 36,888 50,932
Current liabilities ............ 861 658 328 648 10,017
Long-term debt ................. 40 36 15 -- --
Stockholders' equity ........... 610 532 927 36,240 40,880
- ---------------
(1) The data for all prior years has been restated to reflect the change in
our method of accounting for oil and natural gas operations to the full
cost method of accounting. See Note 2 to our Consolidated Financial
Statements. As a result of the change in the accounting
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method, the net loss for the nine month period ended December 31, 1995
and the year ended December 31, 1996, has been decreased by $184,000
($0.54 per share) and $3,000 ($0.01 per share), respectively. Effective
December 31, 1995 we changed our year-end from March 31 to December 31.
(2) The $303,000 expense in 1996 represents the legal, accounting and other
expenses associated with our attempted acquisition of Taurus Energy
Corp.
(3) Per share data has been restated to reflect the one-for-five reverse
stock split effective July 19, 1996, and the one-for-two reverse stock
split effective March 31, 1998. The adoption of Financial Accounting
Standards Board No. 128, "Earnings per Share", did not have a material
impact on earnings per share amounts.
(4) We have not declared nor paid any dividends during any of the periods
presented.
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ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OUR RESULTS OF OPERATIONS
Comparison of Year Ended December 31, 1998 and December 31, 1999
Revenues. Oil and natural gas sales increased $4.0 million or 288%, to
$5.4 million in 1999 from $1.4 million in 1998. The increase was due primarily
to the Rio Grande, Inc. acquisition and other smaller acquisitions as well as
higher oil and natural gas prices during 1999.
We sold 208,231 Bbls of oil in 1999 versus 52,707 Bbls in 1998, a 295%
increase. We sold 764,835 Mcf of natural gas in 1999 versus 412,124 Mcf in 1998,
a 86% increase. The increases in oil and natural gas volumes were also
attributable to our acquisitions.
During 1999 we received an average oil price of $18.18 per Bbl versus
$12.01 per Bbl during 1998, a $6.17 per Bbl or 51% increase. During 1999 we
received an average natural gas price of $2.07 per Mcf versus $1.82 per Mcf for
1998, a $.25 per Mcf or 14% increase.
Our other income in 1999 was $1.4 million compared to $690,000 in 1998.
This income primarily includes interest income, salt water disposal income, and
well supervision fees. Other income increased primarily due to a $646,000
increase in interest income which we received from cash equivalent investments
and the Venus note.
In 1999, we also recorded a pre-tax gain of approximately $5.1 million
from the sale of various oil and natural gas assets.
Costs and Expenses. Our costs and expenses increased $3.2 million, or
123%, to $5.8 million in 1999 as compared to costs and expenses of $2.6 million
in 1998. Our costs and expenses primarily increased due to a $703,000 increase
in general and administrative costs. This increase reflects expenses associated
with our increased staffing and our focus on reserve acquisitions. Our costs and
expenses also increased due to a $1.6 million increase in oil and natural gas
production expenses and a $981,000 increase in depreciation, depletion and
amortization expenses, both increases due to our 1999 acquisitions. We also had
a decrease of $87,000 in interest expense.
Extraordinary Item. In 1999 we had extraordinary income of $165,000, or
$.02 per share, net of income taxes, from the prepayment of a promissory note we
purchased on June 30, 1999. There was no extraordinary income in 1998.
Net Income. We had net income in 1999 of $4.7 million, or $.69 per
share, compared to a loss of $511,000, or $.18 per share in 1998. We have based
our earnings per share figures on restated weighted average shares outstanding
after the retroactive effect of the one-for-two reverse stock split approved at
our shareholders' meeting held on March 31,1998.
Comparison of Year Ended December 31, 1997 and December 31, 1998
Revenues. Oil and natural gas sales increased $715,000, or 107%, to
$1.4 million in 1998 from $670,000 in 1997. The increase was due primarily to
the acquisition we made in Maverick County, the Jacobi-Johnson Energy, Inc.
acquisition, and the acquisition we made in Dawson County.
We sold 52,707 Bbls of oil during 1998 versus 14,453 Bbls in 1997, a
265% increase. We sold 412,124 Mcf of natural gas during 1998 versus 181,091 Mcf
in 1997, a 128% increase. The increases in oil and natural gas volumes were also
attributable to our acquisitions.
During 1998 we received an average oil price of $12.01 per Bbl versus
$19.56 per Bbl during 1997, a $7.55 per Bbl or 39% decrease. During 1998 we
received an average natural gas price of $1.82 per Mcf versus $2.14 per Mcf for
1997, a $.32 per Mcf or 15% decrease.
Our other income in 1998 was $690,000 as compared to $28,000 in 1997.
This income primarily includes interest income, salt water disposal income, and
well supervision fees. Other income increased due primarily to a
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$591,000 increase in interest income which we received from cash equivalent
investments and an additional $64,000 in income we received from our two salt
water disposal wells. We have reclassified amounts in the prior years'
statements of operations to reflect a change in the way we classify fees from
overhead charges billed to working interest owners, including ourselves. We
previously recorded these overhead charges as management fee revenue, and we now
record them as a reduction in general and administrative expenses.
Costs and Expenses. Our costs and expenses increased $1.7 million, or
186%, to $2.6 million in 1998 as compared to costs and expenses of $903,000 in
1997. Our costs and expenses primarily increased due to a $745,000 increase in
general and administrative costs. This increase reflects expenses associated
with our increased staffing and our new focus on reserve acquisitions. Our costs
and expenses also increased due to a $464,000 increase in oil and natural gas
production expenses and a $381,000 increase in depreciation, depletion and
amortization expenses, both increases due to our 1998 acquisitions. We also had
an increase of $93,000 in interest expense as a result of periodic borrowings
against our credit facility.
In 1997, we changed our method of accounting for oil and natural gas
properties from successful efforts to the full cost method of accounting. We
have restated prior years to reflect this change in accounting method as though
we had been using the full cost method for all periods we are comparing in this
annual report. Effective December 31, 1997, we effected a quasi-reorganization
by applying approximately $8.8 million of our additional paid-in capital account
to eliminate our accumulated deficit.
Net Loss. We had a net loss in 1998 of $511,000, or $.18 per share,
compared to a loss of $205,000, or $.51 per share in 1997. We have based our
earnings per share figures on restated weighted average shares outstanding after
the retroactive effect of the one-for-two reverse stock split approved at our
shareholders' meeting held on March 31, 1998.
1997 QUASI-REORGANIZATION
Effective December 31, 1997, we effected a quasi-reorganization by
applying approximately $8.8 million of our additional paid-in capital account to
eliminate our accumulated deficit. Our board of directors decided to effect this
quasi-reorganization given the change in management in December 1997, the
infusion of new equity capital during December 1997 and an expected increase in
acquisition, exploitation and development activities. Based on these factors and
the establishment of a strategic growth plan, our board of directors and
management believed reflecting prior losses on our balance sheet would not be
meaningful in presenting our financial position. Our accumulated deficit was
primarily related to past operations and properties that had been disposed of;
the accumulated deficit was not, in management's view, reflective of our
financial condition at that time. We did not adjust the historical carrying
values of our assets and liabilities in connection with the
quasi-reorganization.
WE CHANGED OUR METHOD OF ACCOUNTING FOR OIL AND NATURAL GAS OPERATIONS
In the fourth quarter of 1997, we changed from the successful efforts
method to the full cost method of accounting for our oil and natural gas
operations. We have restated all of the prior financial statements which we
present in this annual report to reflect the change.
During the ten years ending in December 1997, we incurred minimal
exploration and acquisition costs, liquidated substantially all our properties
and completed "out of court" debt restructurings. The "out of court" debt
restructurings were completed during 1987 and 1988. During the fourth quarter of
1997, we experienced a change in ownership control and we appointed new
management. Our management views us as a new company and believes our past
operations are insignificant and not relevant to our future plans.
Our new management changed the accounting method for oil and natural
gas properties because management believes the full cost method more
appropriately reflects our change in focus for future operations. Further, our
new management does not believe that using the successful efforts method of
accounting is appropriate for a small to medium size acquisition, development
and exploitation company.
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OUR LIQUIDITY AND CAPITAL RESOURCES
General
On December 31, 1999 we had working capital of $21.6 million compared
to $21.5 million on December 31, 1998. Our working capital at December 31, 1999
includes a receivable of approximately $18.1 million due from an escrow agent as
a result of the sale by us of certain oil and natural gas properties located in
Jackson Parish, Louisiana. This receivable was subsequently paid on January 6,
2000. The payment consisted of approximately $18.1 million cash. Our working
capital on December 31, 1998 was $21.5 million compared to $399,000 on December
31, 1997. The sale of common stock through a rights offering in August 1998 for
net proceeds of $35.2 million contributed to this $21.1 million increase in our
working capital. Our 2000 budget for capital expenditures is approximately $2.0
million.
Deferred Income Taxes
Under applicable Federal and State tax laws, we are able to
carry forward, subject to limitations, net operating losses (NOLs) incurred by
EXCO and Rio Grande, Inc. in prior years. We are able to apply a portion of
these NOLs to reduce the amount of income taxes accrued by us in subsequent
years. We account for these NOLs by establishing an off balance sheet deferred
tax asset. We believe that some of our NOLs may expire unused and, accordingly,
we must reduce the value of the deferred tax asset. We have established a
valuation allowance of $1.7 million to reflect this reduction. Additional
discussion can be found in "Item 8. Consolidated Financial Statements and
Supplementary Data, Note 4. Income Taxes".
Long-Term Debt
On December 31, 1999, we had no long-term debt.
Sale of Equity
On July 16, 1998, we commenced a rights offering to our existing
shareholders. Each shareholder received ten rights for each share of our common
stock held. Each right entitled the shareholder to purchase one share of our
common stock for $6.00 per share. The rights offering expired on August 12,
1998. We received net proceeds of approximately $35.2 million. The exercise of
the rights by some existing shareholders or their assignees has resulted in the
dilution of the shares of common stock held by those shareholders who did not
exercise their rights. To date, we have used $6.4 million to repay our
indebtedness, $6.5 million for the acquisition of Rio Grande, Inc., $341,000 for
our share of capital contributions to EXCO Energy Investors, L.L.C., $7.0
million for our share of capital contributions to EXUS Energy, LLC, a loan of
$7.0 million to Venus Exploration, Inc. to fund their capital contribution to
EXUS Energy, LLC, and $400,000 for general corporate purposes. We intend to use
the remaining proceeds of the rights offering for acquisitions, development
drilling and recompletions, the repayment of bank indebtedness, working capital
and general corporate purposes.
Credit Facility
On February 11, 1998, we entered into a credit facility with
NationsBank of Texas, N.A. The credit facility provided for borrowings up to $50
million, subject to borrowing base limitations. On September 21, 1998, we
entered into the first amendment to the credit facility with NationsBank, N.A.
(successor by merger to NationsBank of Texas, N.A.). The first amendment
provides for borrowings up to $150 million, subject to borrowing base
limitations, as determined by the lenders from time to time. On February 11,
2000, we entered into the second amendment to the credit facility with Bank of
America, N.A. (successor by merger to NationsBank, N.A.). The second amendment
provides for a new termination date, an increase in our borrowing base, subject
to certain conditions, and an increase in certain thresholds customary for a
growing company. The bank has sole discretion to determine our borrowing base
based on its valuation of our reserves valued semi-annually.
The credit facility consists of a regular revolver which on December
31, 1999, had a borrowing base of approximately $5.5 million. On February 17,
2000 our borrowing base was increased to $7.5 million. On February 29, 2000, our
borrowing base was increased to $13.0 million, of which $7.1 million has been
drawn and $3.8 million was available for borrowing. The additional $1.8 million
of borrowing will become available upon resolving outstanding title
description issues. A portion of the borrowing base is available for the
issuance of letters of credit.
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All borrowings under the credit facility are secured by tangible and intangible
assets representing at least 90% of the assessed present value of our oil and
natural gas properties.
The credit facility provides that if our aggregate outstanding
indebtedness is less than $5 million, advances will bear interest at 1.5% over
the appropriate LIBOR rate. If our aggregate outstanding indebtedness is greater
than $5 million, then our advances will bear interest at 1.0% over LIBOR if the
borrowing base usage is less than 50%, 1.25% over LIBOR if the borrowing base
usage is between 50-70%, 1.5% over LIBOR if the borrowing base usage is between
70-90%, and 1.75% over LIBOR if the borrowing base usage exceeds 90%. At March
17, 2000, the 6 month LIBOR rate was 6.41%, resulting in an interest rate of
approximately 7.66% on our outstanding indebtedness. The credit facility also
permits us to repay and reborrow amounts under the credit facility without any
penalty, thereby allowing us the flexibility to utilize any available cash to
reduce our outstanding indebtedness and thus, our costs of borrowed funds.
Under the terms of the credit facility, we must not permit our current
ratio of consolidated current assets to our consolidated current liabilities to
be less than 1.0 to 1.0 at any time. In addition, we must maintain a tangible
net worth of at least $500,000 plus (i) subsequent to December 31, 1998, 50% of
our consolidated cumulative net income and (ii) an amount equal to 75% of the
net proceeds we receive from the issuance of any equity securities after
December 31, 1998. At December 31, 1999 we were required to maintain a tangible
net worth of at least $2.8 million. On December 31, 1999, and February 29, 2000,
we were in compliance with both the consolidated tangible net worth covenant and
the current ratio covenant.
No principal amortization will be required during the term of the
credit facility as long as the aggregate principal balance does not exceed the
borrowing base then in effect. However, if a borrowing base deficiency were to
exist after giving effect to a redetermination, then we would have to do one of
the following:
o eliminate the borrowing base deficiency by making a single mandatory
prepayment of principal on the revolving loan in an amount equal to
the entire amount of the borrowing base deficiency on the first
monthly date following the date on which the borrowing base
deficiency is determined to exist;
o eliminate the deficiency by making six consecutive mandatory
prepayments of principal on the revolving loan each of which shall be
in the amount of one sixth (1/6th) of the amount of the borrowing
base deficiency commencing on the first monthly date following the
date on which the borrowing base deficiency is determined to exist
and continuing on each monthly date thereafter; or
o eliminate the borrowing base deficiency by submitting additional
mineral interests to the banks on the first monthly date following
the date on which the borrowing base deficiency is determined to
exist for evaluation as borrowing base properties which the banks, in
their sole discretion, determine have a value sufficient to increase
the borrowing base by at least the amount of the borrowing base
deficiency.
The credit facility matures on February 11, 2002. Our next borrowing
base redetermination is scheduled for no later than April 1, 2000, and
semi-annually thereafter. We may seek additional borrowing capacity at that time
for our development drilling program. However, we cannot assure you that our
current development program will result in increased collateral values or that
these values will enable us to borrow the funds we need to continue the program.
The credit facility contains a number of covenants affecting our
liquidity and capital resources, including restrictions on our ability to incur
indebtedness at any time in an amount exceeding $100,000 or to pledge assets
outside of the credit facility.
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Need to Raise Additional Capital
The growth of our business will require substantial capital on a
continuing basis. We cannot assure you that additional funds we may require will
be available on satisfactory terms and conditions, if at all. We may pursue,
from time to time, opportunities to acquire oil and natural gas properties and
businesses that may utilize the capital we currently expect to be available for
our present operations. The amount and timing of our future capital
requirements, if any, will depend upon a number of factors, including drilling
costs, transportation costs, equipment costs, marketing expenses, staffing
levels, competitive conditions, and any purchases or dispositions of assets. We
do not control many of these factors. If we fail to obtain any required
additional financing, then our growth, cash flow and earnings may be adversely
affected. In addition, we may incur additional debt or engage in potentially
dilutive issuances of equity securities in our pursuit of additional capital.
EFFECT OF INFLATION AND CHANGING PRICES ON OUR BUSINESS
It is difficult for us to assess the impact of inflation on our
business. In 1998 and through the first quarter of 1999, we experienced a
weakness in the prices we received for our oil and natural gas production. In
the latter half of 1999 we experienced increases in the prices we received for
our oil and natural gas. We cannot anticipate whether inflation will remain at
its present level. However, a sudden increase in inflation and/or an increase in
our operating costs or drilling costs coupled with a reduction in oil or natural
gas prices could have an adverse effect on our operations.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). SFAS 133 establishes accounting
and reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. SFAS
133 requires that changes in the derivative's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement. Companies
must formally document, designate, and assess the effectiveness of transactions
that receive hedge accounting.
SFAS 133 is effective for fiscal years beginning after June 15, 2000;
however, beginning June 16, 1998, companies may implement the statement as of
the beginning of any fiscal quarter. SFAS 133 cannot be applied retroactively
and must be applied to (a) derivative instruments and (b) certain derivative
instruments embedded in hybrid contracts that were issued, acquired, or
substantively modified after December 31, 1997 (and, at our election, before
January 1, 1998.) We have not yet quantified the impact of adopting SFAS 133 on
the financial statements and have not determined the timing of or method of
adoption of SFAS 133.
OUR YEAR 2000 COMPLIANCE
As of the date of this report, we have not experienced any significant
disruptions to financial or operating activities as a result of the Year 2000
issues. We experienced no internal system disruptions and we are not aware of
any failures affecting third parties that conduct operations affecting our
business. We will continue to monitor the situation for any internal or third
party disruptions, but we do not expect any disruptions. As of February 29,
2000, we have incurred approximately $7,600 in consulting costs for Year 2000
project planning. All software packages requiring an upgrade which had been
identified were upgraded.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Some of the information below contains forward-looking statements. See
Item 1. "Investment Considerations and Risk Factors - Forward-Looking
Statements" for additional factors relating to these statements.
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about our potential
exposure to market risks. The term "market risk" refers to the risk of loss
arising from adverse changes in oil and natural gas prices. The disclosure is
not meant to be a precise indicator of expected future losses, but rather an
indicator of reasonably possible losses. This forward-looking information
provides an
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indicator of how we view and manage our ongoing market risk exposures. Our
market risk sensitive instrument was entered into for hedging purposes, not for
trading purposes.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to our oil
and natural gas production. Realized pricing is primarily driven by the
prevailing worldwide price for crude oil and spot market prices for natural gas.
Pricing for oil and natural gas production is volatile.
In an effort to reduce the effects of the volatility of the price of
oil and natural gas on our operations, management has adopted a policy of
hedging oil and natural gas prices whenever such prices are in excess of the
prices anticipated in our operating budget and profit plan through the use of
commodity futures, options, and swap agreements. Hedging transactions require
the approval of the board of directors. We had no outstanding hedging agreements
at December 31, 1997 and 1998.
On September 21, 1999, we entered into an oil commodity swap, accounted
for as a derivative commodity instrument, with a counterparty to sell notional
volumes of 7,000 Bbls per month at a fixed price of $21.00 per Bbl based on
NYMEX pricing. The transaction was effective October 1, 1999, and terminates
September 30, 2000. Realized gains or losses from the settlement of the swap are
recorded separately in the financial statements as an increase or decrease in
total revenues. For a given month when the settlement price exceeds $21.00, then
a reduction in total revenues is recorded for the difference between the
settlement price and $21.00 multiplied times the notional volume of 7,000 Bbls.
Conversely, if the settlement price is less than $21.00, then an increase in
total revenues is recorded for the difference between the settlement price and
$21.00 multiplied times the notional volume of 7,000 Bbls. For example, for a
given month, if the settlement price is $22.00, then total revenues will
decrease by $7,000. Conversely, if the settlement price for a given month is
$20.00, total revenues will increase by $7,000. The fair value at December 31,
1999 of the commodity swap was a liability of approximately $106,000 and has
been estimated from a quote provided by the counterparty. This liability
represents the estimated amount that we would expect to pay to terminate the
agreement on December 31, 1999.
We report average oil prices per Bbl including the effects of oil
quality, gathering and transportation costs but excluding the net effect of the
oil hedge. The following table sets forth our oil prices, both realized before
hedge results and realized including hedge results; and the net effects of
settlements of oil price hedges to revenue:
YEAR ENDED
DECEMBER 31,
------------
1999
------------
Average price per Bbl - realized before hedge results ....... $ 18.18
Average price per Bbl - realized including hedge results .... $ 17.83
Reduction to revenue ........................................ $ 74,000
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ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EXCO RESOURCES, INC.
INDEX TO FINANCIAL STATEMENTS
CONTENTS
Audited Financial Statements
Report of Independent Accountants....................................................33
Consolidated Balance Sheets..........................................................34
Consolidated Statements of Operations................................................35
Consolidated Statements of Cash Flows................................................36
Consolidated Statements of Changes in Stockholders' Equity...........................37
Notes to Consolidated Financial Statements...........................................38
Pro Forma Combined Condensed Financial Statements (unaudited)
Pro Forma Combined Condensed Balance Sheet...........................................54
Pro Forma Combined Condensed Statement of Operations.................................55
Notes to Unaudited Pro Forma Combined Condensed Financial Statements.................56
Financial Statements of Properties Acquired - Val Verde County Properties
Reports of Independent Accountants...................................................60
Statements of Operating Revenues and Direct Operating Expenses.......................61
Notes to Statements of Operating Revenues and Direct Operating Expenses..............62
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REPORT OF INDEPENDENT ACCOUNTANTS
The Board of Directors
EXCO Resources, Inc.
We have audited the accompanying consolidated balance sheets of EXCO Resources,
Inc. as of December 31, 1998 and 1999, and the related statements of operations,
cash flows, and changes in stockholders' equity for each of the three years in
the period ended December 31, 1999. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of EXCO Resources, Inc. at
December 31, 1998 and 1999, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1999 in conformity
with accounting principles generally accepted in the United States.
/S/ ERNST & YOUNG LLP
ERNST & YOUNG LLP
Dallas, Texas
March 10, 2000
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EXCO Resources, Inc.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
-----------------------------------
1998 1999
---------- ----------
(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents .................................. $ 21,493 $ 9,972
Accounts receivables:
Oil and gas sales ..................................... 257 824
Joint interest ........................................ 206 1,914
Funds due from escrow agent ........................... -- 18,123
Interest and other .................................... 77 695
Other ...................................................... 124 71
---------- ----------
Total current assets ............................. 22,157 31,599
Oil and gas properties (full cost accounting method):
Proved developed and undeveloped oil and gas properties .... 11,765 24,177
Accumulated depreciation, depletion and amortization ....... (4,211) (5,503)
---------- ----------
Oil and gas properties, net ................................ 7,554 18,674
Office and field equipment, net ................................. 248 264
Deferred financing costs ........................................ 49 8
Investment in Rio Grande, Inc. promissory note .................. 6,539 --
Investment in EXCO Energy Investors, L.L.C ...................... 341 --
Investment in EXUS Energy, LLC .................................. -- 257
Other assets .................................................... -- 130
---------- ----------
Total assets ..................................... $ 36,888 $ 50,932
========== ==========
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable ........................................... $ 480 $ 3,870
Revenues and royalties payable ............................. 167 1,136
Accrued interest payable ................................... -- 10
Current maturities of long-term debt ....................... 1 5,001
---------- ----------
Total current liabilities ........................ 648 10,017
Long-term debt, less current maturities ......................... -- --
Other long-term liabilities ..................................... -- 227
Minority interest in limited partnership ........................ -- (192)
Stockholders' equity:
Preferred stock, $.01 par value:
Authorized shares - 10,000,000
Outstanding shares - None ............................... -- --
Common stock, $.02 par value:
Authorized shares - 25,000,000
Issued and outstanding shares - 6,687,696 and 6,805,196,
at December 31, 1998 and 1999, respectively ............. 134 136
Additional paid-in capital ................................. 46,241 46,941
Notes receivable-officers .................................. (825) (1,552)
Deficit eliminated in quasi-reorganization ................. (8,799) (8,799)
Retained earnings (deficit) since December 31, 1997 ........ (511) 4,154
---------- ----------
Total stockholders' equity ....................... 36,240 40,880
---------- ----------
Total liabilities and stockholders' equity ....... $ 36,888 $ 50,932
========== ==========
See accompanying notes.
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EXCO Resources, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
--------------------------------------
1997 1998 1999
---------- ---------- ----------
(In thousands, except per share amounts)
Revenues:
Oil and natural gas ................................................. $ 670 $ 1,385 $ 5,368
Oil hedge ........................................................... -- -- (74)
Other income ........................................................ 28 690 1,424
Equity in the earnings of EXUS Energy, LLC .......................... -- -- 584
Gain on disposition of property ..................................... -- -- 5,102
---------- ---------- ----------
Total revenues ............................................... 698 2,075 12,404
Cost and expenses:
Oil and gas production .............................................. 322 786 2,375
Depreciation, depletion and amortization ............................ 84 465 1,446
General and administrative .......................................... 486 1,231 1,934
Interest ............................................................ 11 104 17
---------- ---------- ----------
Total cost and expenses ...................................... 903 2,586 5,772
---------- ---------- ----------
Income (loss) before income taxes and minority interest ...................... (205) (511) 6,632
Minority interest in limited partnership ..................................... -- -- (7)
---------- ---------- ----------
Income (loss) before income taxes ............................................ (205) (511) 6,639
Income taxes ................................................................. -- -- 2,139
---------- ---------- ----------
Net income (loss) before extraordinary item .................................. (205) (511) 4,500
Fee income from early extinguishment of debt, net of tax ..................... -- -- 165
---------- ---------- ----------
Net income (loss) ............................................................ $ (205) $ (511) $ 4,665
========== ========== ==========
Basic and diluted earnings (loss) per share .................................. $ (.51) $ (.18) $ .69
========== ========== ==========
Weighted average number of common and common equivalent shares outstanding:
Basic ............................................................... 403 2,871 6,698
========== ========== ==========
Diluted ............................................................. 403 2,874 6,714
========== ========== ==========
See accompanying notes.
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EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
--------------------------------
1997 1998 1999
-------- -------- --------
(In thousands)
OPERATING ACTIVITIES:
Net income (loss) ..................................................................... $ (205) $ (511) $ 4,665
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion and amortization ........................................... 84 465 1,446
Loss (gain) on disposition and abandonment of property and equipment ............... 10 -- (5,102)
Deferred income taxes .............................................................. -- -- 2,139
Gain on investment in EXCO Energy Investors, L.L.C ................................. -- -- (65)
Extraordinary item, net of tax ..................................................... -- -- (165)
-------- -------- --------
Cash flow before changes in working capital ........................................... (111) (46) 2,918
Effect of changes in:
Accounts receivable .......................................................... 100 (257) (20,663)
Other current assets ......................................................... (4) (111) 123
Accounts payable and other current liabilities ............................... (166) 287 9,002
-------- -------- --------
Net cash used in operating activities ................................................. (181) (127) (8,620)
INVESTING ACTIVITIES:
Payments for oil and gas acquisitions, net of cash .................................... -- (6,146) (7,017)
Other additions to property and equipment ............................................. (100) (1,039) (23,480)
Investment in EXCO Energy Investors, L.L.C ............................................ -- (341) (3)
Proceeds from the dissolution of EXCO Energy Investors, L.L.C ......................... -- -- 409
Investment in Rio Grande, Inc. promissory note ........................................ -- (6,539) 7,451
Purchase of note from Venus Exploration, Inc. ......................................... -- -- (7,000)
Payment of note from Venus Exploration, Inc. .......................................... -- -- 7,000
Investment in EXUS Energy, LLC ........................................................ -- -- (257)
Distributions to limited partners ..................................................... -- -- (213)
Proceeds from disposition of property and equipment ................................... 304 5 20,248
-------- -------- --------
Net cash provided by (used in) investing activities ................................... 204 (14,060) (2,862)
FINANCING ACTIVITIES:
Proceeds from note payable and long-term debt ......................................... -- 6,360 3,000
Payments on long-term debt ............................................................ (23) (6,390) (3,010)
Payments on note payable .............................................................. (150) -- --
Interest income on notes receivable - officers ........................................ -- -- (76)
Interest payment on notes receivable - officers ....................................... -- -- 56
Deferred financing costs .............................................................. -- -- (9)
Proceeds from issuance of common stock ................................................ 600 35,214 --
-------- -------- --------
Net cash provided by (used in) financing activities.................................... 427 35,184 (39)
-------- -------- --------
Net increase (decrease) in cash ....................................................... 450 20,997 (11,521)
Cash at beginning of year ............................................................. 46 496 21,493
-------- -------- --------
Cash at end of year ................................................................... $ 496 $ 21,493 $ 9,972
======== ======== ========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Interest paid ......................................................................... $ 11 $ 104 $ 7
======== ======== ========
Income taxes paid ..................................................................... $ -- $ -- $ --
======== ======== ========
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EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
COMMON STOCK
-------------------
NUMBER ADDITIONAL NOTES RETAINED TOTAL
OF PAID-IN RECEIVABLE- DEFICIT EARNINGS STOCKHOLDERS'
SHARES AMOUNT CAPITAL OFFICERS ELIMINATED (DEFICIT) EQUITY
--------- --------- ----------- ------------ ---------- ---------- -------------
(In thousands)
Balance on December 31, 1996 ................ 403 $ 8 $ 9,118 $ -- $ -- $ (8,594) $ 532
Common stock issued .................... 100 2 598 -- -- -- 600
Net loss ............................... -- -- -- -- -- (205) (205)
Adjustment for quasi-reorganization
at December 31, 1997 ................. -- -- -- -- (8,799) 8,799 --
--------- --------- ----------- ------------ ---------- ---------- -------------
Balance on December 31, 1997 ................ 503 10 9,716 -- (8,799) -- 927
Purchase of oil and gas assets ......... 6 0 37 -- -- -- 37
Purchase of Jacobi-Johnson
Energy, Inc. .......................... 85 2 511 -- -- -- 513
Shares issued for rights offering ...... 5,944 119 35,080 -- -- -- 35,199
Exercise of options .................... 150 3 897 -- -- -- 900
Notes issued by officers ............... -- -- -- (825) -- -- (825)
Net loss ............................... -- -- -- -- -- (511) (511)
--------- --------- ----------- ------------ ---------- ---------- -------------
Balance on December 31, 1998 ................ 6,688 134 46,241 (825) (8,799) (511) 36,240
Interest income on notes ............... -- -- -- (77) -- -- (77)
receivable-officers
Interest payment on notes .............. -- -- -- 56 -- -- 56
receivable-officers
1998 rights offering expense ........... -- -- (4) -- -- -- (4)
Exercise of options .................... 117 2 704 -- -- -- 706
Notes issued by officers ............... -- -- -- (706) -- -- (706)
Net income ............................. -- -- -- -- -- 4,665 4,665
--------- --------- ----------- ------------ --------- ---------- -------------
BALANCE ON DECEMBER 31, 1999 ................ 6,805 $ 136 $ 46,941 $ (1,552) $ (8,799) $ 4,154 $ 40,880
========= ========= =========== ============ ========= ========== =============
See accompanying notes.
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Notes to Consolidated Financial Statements
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
EXCO Resources, Inc., (the Company), a Texas corporation, was formed in
1955. Our operations consist primarily of acquiring interests in producing oil
and natural gas properties located in the continental United States. We also act
as the operator on some of these properties and receive overhead reimbursement
fees as a result.
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the
financial statements of EXCO Resources, Inc. and its subsidiary, Rio Grande
Gulfmex, Ltd. All inter-company transactions have been eliminated.
ACCOUNTING FOR UNCONSOLIDATED INVESTMENTS
We account for our 50% interest in EXUS Energy, LLC (more fully
described in Note 11. Acquisitions) using the equity method of accounting for
investments. Equity in the pre-tax earnings of EXUS included in our 1999
consolidated statement of operations was $584,000. During 1999, EXCO's share of
the EXUS oil and gas revenues, depreciation, depletion, and amortization, direct
operating expenses and interest expense were $1.6 million, $449,000, $244,000
and $253,000, respectively.
QUASI-REORGANIZATION
Effective December 31, 1997, we effected a quasi-reorganization by
applying approximately $8.8 million of our additional paid-in capital account to
eliminate our accumulated deficit. Our board of directors decided to effect a
quasi-reorganization given the change in management, the infusion of new equity
capital and an increase in activities. Our accumulated deficit was primarily
related to past operations and properties that have been disposed of. We did not
adjust the historical carrying values of our assets and liabilities in
connection with the quasi-reorganization.
MANAGEMENT ESTIMATES
In preparing financial statements in conformity with accounting
principles generally accepted in the United States, we are required to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses during the reporting period. Actual results
may differ from management's estimates.
CASH EQUIVALENTS
We consider all highly liquid investments with maturities of three
months or less when purchased, to be cash equivalents.
CONCENTRATION OF CREDIT RISK AND ACCOUNTS RECEIVABLE
Financial instruments that potentially subject us to a concentration of
credit risk consist principally of cash and trade receivables. We place our cash
with high credit quality financial institutions. We sell oil and natural gas to
various customers. In addition, we participate with other parties in the
drilling, completion, and operation of oil and natural gas wells. Substantially
all of our accounts receivable are due from either purchasers of oil, natural
gas, or natural gas liquids or participants in oil and natural gas wells for
which we serve as the operator. Generally, operators of oil and natural gas
properties have the right to offset future revenues against unpaid charges
related to operated wells. Oil and natural gas sales are generally unsecured. We
have provided for credit losses in the financial statements and these losses
have been within management's expectations. The allowance for doubtful accounts
receivable aggregated $9,000 and $34,000 at December 31,1998 and 1999,
respectively.
As more fully described in Note 11. Acquisitions, at December 31, 1999,
approximately $18.2 million was due from Texas Escrow Company, Inc. (Texas
Escrow) of Dallas, Texas relating to the sale of certain oil and natural gas
properties located in Jackson Parish, Louisiana (the Jackson Parish Properties)
on December 31, 1999.
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
In an effort to reduce the effects of the volatility of the price of
crude oil and natural gas on our operations, management has adopted a policy of
hedging oil and natural gas prices whenever such prices are in excess of the
prices anticipated in our operating budget and profit plan through the use of
commodity futures, options, and swap agreements. Hedging transactions require
the approval of the board of directors.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The financial instruments that we account for as hedging contracts must
meet the following criteria: the underlying asset or liability must expose us to
price risk that is not offset in another asset or liability, the hedging
contract must reduce that price risk, and the instrument must be designated as a
hedge at the inception of the contract and throughout the contract period. In
order to qualify as a hedge, there must be clear correlation between changes in
the fair value of the financial instrument and the fair value of the underlying
asset or liability such that changes in the market value of the financial
instrument will be offset by the effect of price changes on the exposed items.
Amounts payable under commodity swap agreements are reflected
separately in the financial statements as a reduction of total revenues for the
applicable period. When these derivative financial instruments cease to qualify
as hedges, these instruments are classified as investments held for trading
purposes. Investments held for trading purposes are marked to market at the end
of each reporting period and the net balance change is recorded as other income
(loss) in the consolidated statement of operations for the applicable period.
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). SFAS 133 establishes accounting
and reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. SFAS
133 requires that changes in the derivative's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement. Companies
must formally document, designate, and assess the effectiveness of transactions
that receive hedge accounting.
SFAS 133 is effective for fiscal years beginning after June 15, 2000;
however, beginning June 16, 1998, companies may implement the statement as of
the beginning of any fiscal quarter. SFAS 133 cannot be applied retroactively
and must be applied to (a) derivative instruments and (b) certain derivative
instruments embedded in hybrid contracts that were issued, acquired, or
substantively modified after December 31, 1997 (and, at the Company's election,
before January 1, 1998.) We have not yet quantified the impact of adopting SFAS
133 on the financial statements and have not determined the timing of or method
of adoption of SFAS 133.
OIL AND NATURAL GAS PROPERTIES
We have recorded oil and natural gas properties at cost using the full
cost method of accounting, as prescribed by the Securities and Exchange
Commission. Under the full cost method, all costs associated with the
acquisition, exploration or development of oil and natural gas properties are
capitalized as part of the full cost pool. Capitalized costs are limited to the
aggregate of the present value of future net reserves plus the lower of cost or
fair market value of unproved properties.
Depreciation, depletion, and amortization of evaluated oil and natural
gas properties is provided using the unit-of-production method based on total
proved reserves, as determined by independent petroleum reservoir engineers.
Sales, dispositions, and other oil and natural gas property retirements
are accounted for as adjustments to the full cost pool, with no recognition of
gain or loss unless the disposition would significantly alter the amortization
rate.
OFFICE AND FIELD EQUIPMENT
Office and field equipment are capitalized at cost and depreciated on a
straight line basis over their estimated useful lives.
REVENUE RECOGNITION
We use the sales method of accounting for oil and natural gas revenues.
Under the sales method, revenues are recognized based on actual volumes of oil
and natural gas sold to purchasers.
OVERHEAD REIMBURSEMENT FEES
We have classified fees from overhead charges billed to working
interest owners, including us, of $136,000, $278,000, and $661,000 for the years
ended December 31, 1997, 1998, and 1999, respectively, as a reduction of general
and administrative expenses in the accompanying statements of operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EARNINGS PER SHARE
Statement of Financial Accounting Standards No. 128, "Earnings per
Share", requires presentation of two calculations of earnings per common share.
Basic earnings per common share equals net income divided by weighted average
common shares outstanding during the period. Diluted earnings per common share
equals net income divided by the sum of weighted average common shares
outstanding during the period plus any dilutive shares assumed to be issued.
Common stock equivalents are shares assumed to be issued if outstanding stock
options were exercised.
REVERSE STOCK SPLITS
At our 1996 annual meeting of shareholders, our shareholders approved
an amendment to our articles of incorporation, authorizing a one-for-five
reverse stock split of our common stock, which became effective July 19, 1996.
At our 1998 annual meeting of shareholders, our shareholders approved an
amendment to our articles of incorporation, authorizing a one-for-two reverse
stock split of our common stock, which became effective March 31, 1998. We have
adjusted all share and per share numbers retroactively to record the effects of
the reverse stock split.
PREFERRED STOCK
At the 1996 annual meeting, our shareholders also authorized the
issuance of up to 10,000,000 shares of preferred stock, $.01 par value per
share, that the board of directors may issue from time to time in one or more
series. With respect to each series of preferred stock, the amendment authorizes
the board to fix and determine by resolution the number of shares of each
series, the designation thereof and all rights and preferences including voting,
dividend, conversion, redemption and liquidation rights. To date no shares have
been issued. The board of directors deemed it in our best interest to provide
for corporate planning and to have shares available for future equity financings
through issuance to the general public, future acquisitions, stock dividends or
splits or for other corporate purposes for which the issuance of preferred
shares may be advisable.
RECLASSIFIED PRIOR YEAR AMOUNTS
Certain prior year amounts have been reclassified to conform to current
year presentation.
2. CHANGE IN METHOD OF ACCOUNTING FOR OIL AND NATURAL GAS OPERATIONS
In the fourth quarter of 1997, we changed from the successful efforts
method to the full cost method of accounting for our oil and natural gas
operations.
During the past ten years ending in 1997, we incurred minimal
exploration and acquisition costs which resulted in the liquidation of
substantially all of our properties. During 1987 and 1988 we completed "out of
court" debt restructurings. During the fourth quarter of 1997 we experienced a
change in control of ownership and new management was appointed. New management
views us as a new company and believes our past operations are insignificant and
not relevant to our future plans.
New management believes that the change in accounting for oil and
natural gas properties is proper because the full cost method will more
appropriately reflect our future operations which will result from our
significant management changes. Further, new management does not believe that
the use of the successful efforts method of accounting is appropriate for a
small to medium size acquisition, development and exploitation company.
We have restated the 1997 financial statements to apply the new
accounting method retroactively. The effect of the change in accounting
principle on our 1997 net loss and earnings per share data was immaterial due to
our relative inactivity in exploration and development activities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. LONG-TERM DEBT
Long-term debt is summarized as follows (in thousands):
DECEMBER 31,
---------------------
1998 1999
---------- ----------
Notes payable ................................ $ 1 $ 5,001
Less current maturities ...................... 1 5,001
---------- ----------
Long-term debt ............................... $ -- $ --
========== ==========
BANK OF AMERICA CREDIT AGREEMENT
On February 11, 1998, we entered into a credit facility with
NationsBank of Texas, N.A. The credit facility provided for borrowings up to $50
million, subject to borrowing base limitations. On September 21, 1998, we
entered into the first amendment to the credit facility with NationsBank, N.A.
(successor by merger to NationsBank of Texas, N.A.). The first amendment
provides for borrowings up to $150 million, subject to borrowing base
limitations, as determined by the lenders from time to time. On February 11,
2000, we entered into the second amendment to the credit facility with Bank of
America, N.A. (successor by merger to NationsBank, N.A.). The second amendment
provides for a new termination date, an increase in our borrowing base, subject
to certain conditions, and an in increase certain thresholds customary for a
growing company. Under the credit facility, we are required to pay a fee equal
to .25% on any accepted increase in the borrowing base in excess of the
previously determined borrowing base and a commitment fee of .30% to .425% based
on the ratio of outstanding credit to the borrowing base. The maturity date of
the credit facility is February 11, 2002.
The credit facility provides that if our outstanding credit is less
than $5 million, then our interest rate will be LIBOR plus 1.5%. If our
outstanding credit is greater than $5 million, then the credit facility provides
that our interest rate will be either Bank of America's prime rate or LIBOR plus
between 1% and 1.75% based on the ratio of outstanding credit to the borrowing
base.
There are no scheduled principal payments due on the credit facility
until maturity. However, the borrowing base will be redetermined on or around
April 1st and October 1st of each year. A borrowing base deficiency is created
in the event that the outstanding loan balances exceed the borrowing base, as
determined by the lenders in their sole discretion. Upon such event the
borrowing base deficiency must be repaid by:
(1) mandatory reductions of the deficiency over a period of not more
than 6 months;
(2) making a lump sum payment equal to the deficiency; or
(3) providing additional collateral acceptable to lenders in their sole
discretion sufficient to increase the borrowing base and eliminate
the deficiency.
Borrowings under the credit facility are secured by first and prior
liens covering 90% of the recognized value of all proved mineral interests owned
by us. The credit facility contains various restrictive covenants, including
limitations on the granting of liens, restrictions on the issuance of additional
debt, requirements to maintain a net worth of at least $500,000 plus 50% of our
consolidated cumulative net income beginning January 1, 1999, and to maintain a
current ratio of not less than 1.0 to 1.0, and currently prohibits the payment
of dividends on our capital stock.
4. INCOME TAXES
During 1999 we recorded a provision for income taxes of $2.2 million.
$2.1 million was charged to continuing operations and $85,000 was assessed
against extraordinary income. The components of the provision are as follows:
current - $0, deferred - $2.2 million.
At December 31, 1999, we had net operating loss carryforwards (NOLs)
for income tax purposes that expire beginning in 2000. Our ability to use the
NOLs is significantly restricted because of a change in our ownership, which
occurred December 19, 1997, as well as the change in ownership of Rio Grande,
Inc. which occurred on March 16, 1999, as described in Note 11. We estimate that
approximately $5.6 million of the NOLs will become available in the future at
the rate of approximately $460,000 per year. We also have available statutory
depletion carryforwards of approximately $16,000. For financial reporting
purposes, a valuation allowance has been recognized to offset the deferred tax
assets related to carryforwards prior to our quasi-reorganization. When
realized,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the tax benefit for those carryforwards will be credited to additional paid-in
capital. In addition, a valuation allowance has been recognized to offset
deferred tax assets acquired in the Rio Grande transaction. When realized, the
tax benefit for those assets will be credited to the acquired properties. $2.2
million of deferred tax assets was realized during 1999 and was credited to the
full cost pool.
Deferred income taxes reflect the net tax effects of temporary
differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for income tax purposes. Significant
components of our deferred tax liabilities and assets are as follows (in
thousands):
DECEMBER 31,
-----------------------------------
1997 1998 1999
--------- --------- ---------
DEFERRED TAX ASSETS:
Net operating loss carryforwards ............................... $ 649 $ 902 $ 1,922
Credit carryforwards ........................................... 36 29 29
Statutory depletion carryforwards .............................. 315 16 16
Other .......................................................... 6 4 4
Valuation allowance for deferred tax assets .................... (817) (494) (1,728)
--------- --------- ---------
Total deferred tax assets ................................. 189 457 243
DEFERRED TAX LIABILITIES:
Book basis of oil and gas properties in excess of tax basis .... 189 457 243
--------- --------- ---------
Total deferred tax liabilities ............................ 189 457 243
--------- --------- ---------
Net deferred tax liabilities .............................. $ -- $ -- $ --
========= ========= =========
The following is a reconciliation, stated as a percentage of pretax income
(loss) taxable at the corporate level, of the U.S. statutory federal income tax
rate to our effective tax rate:
1997 1998 1999
------ ------ ------
U.S. federal statutory rate ............... 34% 34% 34%
Adjustments to the valuation allowance .... (34%) (34%) --
------ ------ ------
Tax provision ............................. -- -- 34%
====== ====== ======
5. STOCK TRANSACTIONS
ISSUANCE OF COMMON STOCK
On March 5, 1998 we issued 6,250 shares of common stock as
consideration for the acquisition of working interests from J. Michael
Muckleroy, an outside director. On May 8, 1998 we issued 85,436 shares of common
stock as partial consideration for the Jacobi-Johnson Energy, Inc. acquisition.
On July 16, 1998 the Securities and Exchange Commission declared our
registration statement effective authorizing the commencement of a rights
offering to our existing shareholders. Each shareholder received ten rights for
each share of our common stock held. Each right entitled the shareholder to
purchase one share of our common stock for $6.00 per share. The rights offering
expired on August 12, 1998. We received net proceeds of approximately $35.2
million and issued approximately 5.9 million shares. On September 15, 1998
several of our directors and executive officers exercised stock options covering
150,000 shares of common stock at a strike price of $6.00 per share. Of the
$900,000 in aggregate proceeds, these directors and executive officers paid
$75,000 in cash with $825,000 being borrowed from us.
On November 29, 1999, several of our executive officers who are also
directors exercised stock options covering 117,500 shares of common stock,
112,500 at a strike price of $6.00 per share and 5,000 at a strike price of
$6.25 per share. Of the $706,250 in aggregate proceeds, these executive officers
who are also directors paid $0 in cash with $706,250 being borrowed from us.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes our stock option activity:
WEIGHTED
AVERAGE EXERCISE
STOCK PRICE PER
OPTIONS SHARE
--------------- ----------------
Outstanding at December 31, 1996 ................... --
Granted ....................................... 125,000 $ 5.50
Expired or canceled ........................... (125,000) $ 5.50
Exercised ..................................... --
---------------
Outstanding at December 31, 1997 ................... --
Granted ....................................... 1,072,500 $ 6.00
Expired or canceled ........................... --
Exercised ..................................... (150,000) $ 6.00
---------------
Options outstanding at December 31, 1998 ........... 922,500 $ 6.00
Granted ....................................... 268,309 $ 6.10
Expired or canceled ........................... (6,600) $ 6.16
Exercised ..................................... (117,500) $ 6.01
---------------
OPTIONS OUTSTANDING AT DECEMBER 31, 1999 ........... 1,066,709 $ 6.02
===============
OPTIONS EXERCISABLE AT DECEMBER 31, 1999 ........... 333,552 $ 6.02
===============
SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS 123)
defines a fair value based method of accounting for employee stock compensation
plans, but allows for the continuation of the intrinsic value based method of
accounting to measure compensation cost prescribed by Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25). For
companies electing not to change their accounting, SFAS 123 requires pro-forma
disclosures of earnings and earnings per share as if the change in accounting
provision of SFAS 123 has been adopted.
We have elected to continue to utilize the accounting method prescribed
by APB 25, under which no compensation cost has been recognized, and adopt the
disclosure requirements of SFAS 123. As a result, SFAS 123 has no effect on our
financial condition or our results of operations at December 31, 1997, 1998 and
1999.
Had compensation costs for these plans been determined consistent with
SFAS 123, our net income (loss) and earnings per share (EPS) would have been
adjusted to the following pro-forma amounts.
DECEMBER 31,
--------------------------------------
1997 1998 1999
---------- ---------- -----------
Net income (loss) ..... As Reported ........ $ (205,000) $ (511,000) $ 4,665,000
Pro Forma .......... $ (205,000) $ (711,000) $ 3,889,000
Basic and Diluted EPS . As Reported ........ $ (.51) $ (.18) $ .69
Pro Forma .......... $ (.51) $ (.25) $ .58
The present value of each option grant is estimated on the date of
grant using the Black-Scholes option pricing model. The following assumptions
were used: fair market values of stock at date of grant ranged from $6.00 to
$6.25; option exercise prices ranged from $6.00 to $6.25; option term of 10
years; risk-free rate of return is based on 10-year U.S. Treasury Notes; company
stock volatility is based on daily stock prices from January 1, 1998 through
December 31, 1999; company dividend yield of 0%; and calculated Black-Scholes
values ranging from $3.05 to $3.18 per option.
6. RELATED PARTY TRANSACTIONS
In the past, certain of our directors, and the companies with which
they are affiliated, participated in oil and natural gas joint ventures with us
upon the same terms and conditions as unrelated parties. In addition, we have
purchased certain oil and natural gas prospects as well as drilling services and
oil field supplies and services in the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
normal course of business from directors or from companies in which certain
directors have a financial interest. We made no significant purchases during the
year ended December 31, 1997. During the year ended December 31, 1998, we
purchased working interests from an outside director, in exchange for 6,250
shares of our common stock. During 1999, one of our directors participated under
a farmout agreement for an interest in one development well. During 1999,
approximately $42,000 in costs associated with this well were paid by the
director.
EXUS Energy, LLC
During 1999, EXCO operated the wells in which EXUS Energy, LLC (more
fully described in Note 11. Acquisitions) owned an interest. Included in 1999
joint interest receivables is $770,000 due from EXUS, representing uncollected
operating expenses billed to EXUS by EXCO through December 31, 1999. Also,
$504,000 in royalties payable were owed to EXUS on December 31, 1999. During
1999, $94,000 was classified as a reduction of general and administrative
expenses for overhead fees. The oil and gas assets of EXUS were sold and EXUS
was dissolved effective December 31, 1999.
EXCO Energy Investors, L.L.C.
On October 9, 1998, we formed a $50 million joint venture with an
institutional investor to acquire oil and natural gas related assets and
securities. Under the terms of the joint venture agreement, we were required to
contribute 5% of the joint venture's capital expenditures.
Related to an investment made by the joint venture, we presented a
restructuring plan to National Energy Group, Inc.'s bondholders' committee on
February 24, 1999. The proposal consisted of a combination of shares of our
common stock and approximately $58 million cash to satisfy all secured and
unsecured liabilities and to acquire the assets of National Energy. The plan
anticipated no consideration for the preferred or common equity of National
Energy. The plan was subject to conditions which included approval by (1) EXCO's
board of directors; (2) EXCO's shareholders; (3) EXCO's bank lenders; (4) due
diligence and (5) the U. S. Bankruptcy Court. This proposal was not accepted by
National Energy, its creditors' constituencies or the U.S. Bankruptcy Court.
On November 1, 1999, we participated in an auction of National Energy's
oil and natural gas properties. We were not the winning bidder on these assets.
The joint venture sold the debt securities of National Energy it owned on
November 11, 1999, and was subsequently dissolved on December 3, 1999. We made a
pre-tax gain of approximately $65,000 on our investment in the joint venture.
7. COMMITMENTS AND CONTINGENCIES
We lease our offices and certain equipment. Our rental expenses were
approximately $63,000, $84,000 and $134,000 for 1997, 1998 and 1999,
respectively. Our future minimum rental payments under operating leases with
remaining noncancellable lease terms at December 31, 1999 are as follows (in
thousands):
2000 .................. $ 162
2001 .................. 23
2002 .................. 5
2003 .................. 1
Thereafter ............ --
--------
$ 191
========
8. ENVIRONMENTAL REGULATION
Various federal, state and local laws and regulations covering
discharge of materials into the environment, or otherwise relating to the
protection of the environment, may affect our operations and the costs of our
oil and natural gas exploitation, development and production operations. We do
not anticipate that we will be required in the near future to expend amounts
material in relation to the financial statements taken as a whole by reason of
environmental laws and regulations. Because these laws and regulations are
constantly being changed, we are unable to predict the conditions and other
factors, over which we do not exercise control, that may give rise to
environment liabilities affecting us.
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47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. OIL AND NATURAL GAS PRODUCING ACTIVITIES
The results of operations from our oil and natural gas producing
activities are as follows (in thousands):
YEAR ENDED DECEMBER 31,
----------------------------
1997 1998 1999
-------- -------- --------
Oil and natural gas sales ........................ $ 670 $ 1,385 $ 5,368
Production costs ................................. $ (322) $ (786) $ (2,375)
Depreciation, depletion and amortization ......... $ (63) $ (385) $ (1,446)
Income tax expense, net of extraordinary item .... $ -- $ -- $ 2,139
Costs incurred in oil and natural gas producing activities are as
follows (in thousands, except per equivalent barrel amounts):
YEAR ENDED DECEMBER 31,
----------------------------
1997 1998 1999
-------- -------- --------
Property acquisition costs ....................... $ 2 $ 6,820 $ 14,803
Development costs ................................ $ 74 $ 257 $ 940
Exploration costs ................................ $ -- $ -- $ 122
Production costs ................................. $ 322 $ 786 $ 2,375
Depreciation, depletion and amortization
per equivalent barrel ........................... $ 1.41 $ 3.17 $ 4.31
Most of our oil and natural gas revenues are produced from a limited
number of wells or properties all of which are located in the United States.
Our oil and natural gas production is sold to various purchasers.
During the year ended December 31, 1999, sales of oil and natural gas to two
purchasers accounted for 27% and 36%, respectively, of our total revenues.
During the year ended December 31, 1998, sales of oil and natural gas to two
purchasers, accounted for 17% and 10%, respectively, of our total revenues.
During the year ended December 31, 1997, sales of oil and natural gas to three
purchasers accounted for 22%, 19% and 14% of gross revenues, respectively.
Management believes that the loss of these purchasers would not have a material
impact on our financial condition or results of operations.
10. HEDGING ACTIVITIES
In an effort to reduce the effects of the volatility of the price of
crude oil and natural gas on our operations, management has adopted a policy of
hedging oil and natural gas prices whenever such prices are in excess of the
prices anticipated in our operating budget and profit plan through the use of
commodity futures, options, and swap agreements. Hedging transactions require
the approval of the board of directors. We had no outstanding hedging agreements
at December 31, 1997 and 1998.
On September 21, 1999, we entered into an oil commodity swap with a
counterparty to sell notional volumes of 7,000 Bbls per month at a fixed price
of $21.00 per Bbl based on NYMEX pricing. The transaction was effective October
1, 1999, and terminates September 30, 2000. The fair value at December 31, 1999
of the commodity swap was a liability of approximately $106,000 and has been
estimated from a quote provided by the counterparty and represents the estimated
amount that we would expect to pay to terminate the agreement on December 31,
1999.
The following table sets forth our oil prices, both realized before
hedge results, and realized including hedge results; and the net effects of
settlements of oil price hedges to revenue:
YEAR ENDED
DECEMBER 31,
--------------
1999
--------------
Average price per Bbl - realized before hedge results ...... $ 18.18
Average price per Bbl - realized including hedge results ... $ 17.83
Reduction to revenue ....................................... $ 74,000
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. ACQUISITIONS
We have accounted for the following acquisitions in accordance with APB
No. 16, "Business Combinations" where applicable.
Maverick County Properties Acquisition
On February 11, 1998, we acquired from Osborne Oil Company, Gypsy
Production Company, and other working interest owners oil and natural gas
properties in Maverick County, Texas. The purchase price consisted of
approximately $760,000 cash partially paid for using funds available under the
credit facility.
Jacobi-Johnson Energy, Inc. Acquisition
On May 8, 1998, we acquired all of the outstanding common stock of
Jacobi-Johnson Energy, Inc. from its four stockholders. Jacobi-Johnson, owns oil
and natural gas working interests in Polk, Nacogdoches, Navarro, Smith and Wood
Counties of Texas. We paid approximately $1.5 million for the stock which
consisted of $703,000 cash and 85,436 shares of our common stock with a value of
$513,000. In addition, we assumed approximately $261,000 of Jacobi-Johnson
indebtedness. We obtained the cash for the purchase price under our credit
facility with NationsBank, N.A.
Dawson County Properties Acquisition
On June 30, 1998 we acquired oil and natural gas properties from J. M.
Hill, J. M. Hill, Trustee, Walter O. Hill, Steven J. Devos, Humphrey Oil
Interests, L.P. and other working interest owners, in Dawson and Brazos
Counties, Texas. The purchase price consisted of approximately $3.5 million cash
paid for using funds available under our credit facility.
Carter County Properties Acquisition
On December 21, 1998, we acquired properties from Colony Petroleum,
L.L.C. and Cumulus 2 Limited in Carter County, Oklahoma. The purchase price
consisted of approximately $706,000 cash paid from proceeds of our rights
offering.
EXCO Energy Investors, L.L.C.
On October 9, 1998, we formed a $50 million joint venture with an
institutional investor to acquire oil and natural gas related assets and
securities. Under the terms of the joint venture agreement, we were required to
contribute 5% of the joint venture's capital expenditures.
Related to an investment made by the joint venture, we presented a
restructuring plan to National Energy Group, Inc.'s bondholders' committee on
February 24, 1999. The proposal consisted of a combination of shares of our
common stock and approximately $58 million cash to satisfy all secured and
unsecured liabilities and to acquire the assets of National Energy. The plan
anticipated no consideration for the preferred or common equity of National
Energy. The plan was subject to conditions which included approval by (1) EXCO's
board of directors; (2) EXCO's shareholders; (3) EXCO's bank lenders; (4) due
diligence and (5) the U. S. Bankruptcy Court. This proposal was not accepted by
National Energy, its creditors' constituencies or the U.S. Bankruptcy Court.
On November 1, 1999, we participated in an auction of National Energy's
oil and natural gas properties. We were not the winning bidder on these assets.
The joint venture sold the debt securities of National Energy it owned on
November 11, 1999, and was subsequently dissolved on December 3, 1999. We made a
pre-tax gain of approximately $65,000 on our investment in the joint venture.
Rio Grande, Inc. Acquisition
On November 2, 1998, we acquired a promissory note from a Texas bank
for $6.4 million which was secured by substantially all of the assets of Rio
Grande, Inc., its subsidiaries and affiliated entities. Rio Grande, Inc. was an
oil and natural gas producer with principal operations in Texas, Oklahoma,
Louisiana, and Mississippi. At the same time we purchased the note, we also
entered into an agreement with Rio Grande, Inc. and Rio Grande, Inc.'s sole
holder of preferred stock, regarding plans for the ultimate satisfaction of Rio
Grande, Inc.'s debt, including the proposed acquisition of Rio Grande, Inc. or
its assets by us.
On November 12, 1998, Rio Grande, Inc. announced that it had filed for
reorganization under Chapter 11 of the Bankruptcy Code. As the largest secured
creditor, we had negotiated a plan for financial restructuring with Rio
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49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Grande, Inc. and the holder of its preferred stock. On March 5, 1999, the court
confirmed the proposed plan. Pursuant to the terms of the plan, Rio Grande, Inc.
fully repaid its trade creditors. Several of the subsidiaries or affiliates were
merged into Rio Grande, Inc. Then, the outstanding shares of Rio Grande, Inc.'s
common and preferred stock were canceled. We were issued new shares of Rio
Grande, Inc. as settlement of Rio Grande Inc.'s $13 million secured indebtedness
owed to us. The new shares represented all of the outstanding capital stock of
Rio Grande, Inc., and we became the owners of Rio Grande, Inc. effective on
March 16, 1999. On March 30, 1999, Rio Grande, Inc. was merged into EXCO. The
acquisition was recorded as a purchase.
Jackson Parish Properties Acquisition and Disposition
On June 30, 1999, we formed a joint venture with Venus Exploration,
Inc. called EXUS Energy, LLC. On June 30, 1999, EXUS Energy, LLC, a Delaware
limited liability company (EXUS), owned 50% by EXCO Resources, Inc. (EXCO) and
50% by Venus Exploration, Inc. (Venus), completed the acquisition from Apache
Corporation of the Jackson Parish Properties. Venus is a publicly-held oil and
gas exploration company based in San Antonio, Texas. The purchase price, before
closing adjustments, was approximately $28.5 million, and after adjustments (the
adjustments principally reflect production since March 1, 1999, the effective
date of the acquisition), was $27.6 million cash. EXCO and Venus initially
capitalized EXUS with $14 million of equity capital, all of which was applied to
fund the purchase of the Jackson Parish Properties. EXUS also arranged a credit
facility (discussed in greater detail below) through NationsBank, N.A. to fund
$14 million of the Jackson Parish Properties acquisition, additional development
drilling of the properties and additional acquisitions. The purchase price was
determined based upon arms-length negotiations between Apache Corporation and
Venus taking into account reserve estimates and other items customarily
considered in acquisitions of this type.
Of the initial $14 million of EXUS equity capital, $7 million was
provided by EXCO from its cash on hand, and $7 million was provided by Venus
from borrowed funds. On June 30, 1999 Venus borrowed $7 million from EXCO under
the terms of an $8 million convertible promissory note (the Note). A provision
of the Note provided for a voluntary prepayment on any or all of the Note by
Venus (subject to a prepayment penalty of 3.57% of the principal prepaid for any
prepayment occurring on or prior to July 1, 2000).
On December 31, 1999, EXUS conveyed 100% of the leasehold and mineral
interests it held in Jackson Parish, Louisiana, to its equity members in
proportion to their respective membership interests.
Then on December 31, 1999, pursuant to the terms of a Purchase, Sale
and Exchange agreement dated December 17, 1999, and subsequent amendment dated
December 31, 1999, between EXCO, as seller, and Anadarko Petroleum Corporation
(Anakarko), as buyer, EXCO sold to Anadarko the property interests conveyed to
it by EXUS. The gross consideration was approximately $18.7 million cash ($18.2
million cash after adjustments which principally reflect production since
October 1, 1999, the effective date of the sale), and oil and gas leasehold
interests located in Seward and Meade Counties, Kansas, valued by the parties at
$800,000. EXCO recorded a pre-tax gain from the sale of approximately $5.1
million. The price was determined through arms-length negotiation between the
parties.
The instruments of conveyance were executed and delivered into escrow
on and dated as of December 31, 1999. The cash consideration was paid to the
escrow agent on January 6, 2000. The conveyance documents were delivered by the
escrow agent to Anadarko on January 6, 2000. The payment of cash was delayed due
to the anticipation of the potential for a Y2K disruption to the banking system.
The Jackson Parish Properties which were sold included 17 gross (7.125
net to EXCO's interest) producing wells. EXCO was the named operator of the
Jackson Parish Properties. The Jackson Parish Properties sold included
approximately 6,410 gross (2,830 net to EXCO's interest) developed acres and
approximately 1,530 gross (570 net to EXCO's interest) undeveloped acres. As of
October 1, 1999, the Jackson Parish Properties were estimated to contain net
total proved reserves to EXCO's interest of 1,340 barrels of oil and natural gas
liquids (Bbls) and 32.7 billion cubic feet (Bcf) of gas. Net production to
EXCO's interest as of November 1999, was running approximately 85.7 million
cubic feet (Mmcf) per month of natural gas, and no barrels of oil or condensate.
Anadarko took over operations on January 1, 2000.
The proceeds received by EXCO were placed in a tax-deferred escrow
account with Texas Escrow under terms of a Deferred Exchange Agreement (Exchange
Agreement) between EXCO and Texas Escrow executed on December 31, 1999. The
Exchange Agreement is designed to comply with the like-kind exchange provisions
of Section 1031 of the Tax Code which permits the deferral of gains from a sale
of assets if specific like-kind exchange reinvestment criteria are met. If EXCO
is successful in meeting the like-kind exchange provisions, some, if not most,
of the federal and state tax payments on the gain from the sale of the Jackson
Parish Properties will be deferred to future periods. A portion of the assets
purchased in Natchitoches Parish, Louisiana, described below, meet the
requirements for a like-kind exchange. Therefore, EXCO will be permitted to
defer at least some of its gain on the sale of the Jackson Parish Properties.
-47-
50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Under terms of the Escrow Agreement For Closing Funds and Closing
Documents (the Escrow Agreement) dated December 31, 1999, by and among Anadarko,
Venus Exploration, Inc. (Venus), EXUS, EXCO, Wells Fargo Bank (Texas), N.A.
(Wells Fargo), Texas Escrow and American Escrow Company (American Escrow), the
Credit Agreement among EXUS, as borrower, and NationsBank, N.A., as
Administrative Agent, was paid in full on January 6, 2000. The payoff amount
consisted of $14.2 million of principal, and approximately $28,000 for accrued
interest and unused line fees.
Also, on December 31, 1999, pursuant to the terms of a separate
Purchase and Sale Agreement dated December 17, 1999, between Venus, as seller,
and Anadarko, as buyer, Venus sold to Anadarko the property interests conveyed
to it by EXUS. The gross consideration was approximately $18.9 million cash
($18.4 million cash after adjustments which principally reflect production since
October 1, 1999, the effective date of the sale). The proceeds received by Venus
were placed in an escrow account with American Escrow.
Then, under terms of the Escrow Agreement, Venus paid in full $7.0
million of principal, approximately $369,000 of accrued interest, and a $250,000
pre-payment penalty owed to EXCO under terms of an $8 million Convertible
Promissory Note made between Venus and EXCO dated June 30, 1999. Income from the
prepayment penalty on the Note has been reflected in the financial statements as
extraordinary income net of applicable income taxes of $85,000. Per share income
from extraordinary item was $.02 per basic and diluted share.
As a result of the sale, EXUS was dissolved effective December 31,
1999, with a nominal amount of working capital retained to wind-up the affairs
of the joint venture.
Natchitoches Parish Properties Acquisition
On December 31, 1999, under terms of a Purchase and Sale Agreement
dated November 16, 1999, which was subsequently amended on December 21, 1999,
between Western Gas Resources, Inc. (Western), as seller, and EXCO Resources,
Inc. (EXCO), as buyer, EXCO purchased certain oil and gas assets located in
Natchitoches Parish, Louisiana from Western (the Natchitoches Parish Properties)
for consideration of $7.8 million cash (approximately $7.2 million after
contractual adjustments). All risk of loss and rights associated with the
properties were transferred to EXCO on December 31, 1999. The assets include
Western's interest in the Black Lake Unit and the Black Lake processing and
treating facilities.
Of the $7.8 million purchase price, a $5.0 million non-refundable cash
deposit was paid by EXCO to Western on December 22, 1999, and a current
liability in the form of a note payable to Western in the approximate amount of
$2.2 million (reflecting contractual adjustments) was booked by EXCO on December
31, 1999. This note was subsequently paid off on January 7, 2000. The payment of
the note payable was delayed due to the anticipation of the potential for a Y2K
disruption to the banking system. Of the $7.2 million net purchase price,
approximately $1.4 million has been allocated to the plants. The plants are not
subject to the like-kind exchange treatment as the cash used for this portion of
the purchase was paid directly from EXCO. After deducting the value allocated
and paid on the plants, approximately $5.8 million was allocated to the
leasehold interests, mineral interests, and equipment. This amount was paid with
tax-deferred exchange proceeds held by Texas Escrow Company, Inc. This use of
tax-deferred exchange proceeds is in compliance with the like-kind exchange
provisions of Section 1031 of the Tax Code described in EXCO's Form 8-K filed on
January 18, 2000, dated December 31, 1999. The price was determined through
arms-length negotiation between the parties.
The Natchitoches Parish Properties include 29 gross (20.0 net)
producing wells out of a total of 75 gross wells. EXCO is the named operator of
the Natchitoches Parish Properties and assumed operations of all 75 wells
acquired in the transaction. The Natchitoches Parish Properties include
approximately 14,250 gross (10,590 net) developed acres and approximately 10,390
gross (8,320 net) undeveloped acres. As of September 1, 1999, the Natchitoches
Parish Properties were estimated to contain net reserves of 570,000 barrels of
oil and natural gas liquids (Bbls) and 4.5 billion cubic feet (Bcf) of gas. Net
production as of December 1999, was running approximately 95,000 mcf per month
of net residue gas, 7,100 barrels per month of natural gas liquids, and 5,400
barrels of oil and condensate per month. EXCO took over operations on January 7,
2000.
Pro forma results of operations.
The following table reflects the pro forma results of operations as
though the acquisition of Jacobi-Johnson, the Dawson County Properties, and Rio
Grande, Inc., the related borrowings, the common stock Rights Offering, the
disposition of the Jackson Parish Properties, the addition of the Seward/Meade
County Properties, and the acquisition of the Natchitoches Parish Properties had
been consummated on January 1, 1998.
-48-
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR ENDED DECEMBER 31,
--------------------------
1998 1999
------------- ------------
(In thousands, except per
share data)
(Unaudited
Revenues ............................................... $ 13,465 $ 11,965
Income (loss) before extraordinary item ................ $ (3,825) $ 1,349
Income (loss) per share before extraordinary item ...... $ (0.58) $ 0.20
12. SUBSEQUENT EVENTS
Odd-Lot Stock Repurchase Program
On January 15, 2000, we commenced an odd-lot stock repurchase program.
We are offering $8.50 per share to any record or beneficial shareholder who owns
less than 100 shares of common stock. The price was determined based upon a
number of factors, including trading prices for our common stock over the past
12 months and our desire to maximize the response to this offer in order for us
to achieve our goal of reducing shareholder communication expenses. The record
date to determine eligible shareholders was December 31, 1999. As of December
31, 1999, EXCO had approximately 1,400 odd-lot shareholders of record, who owned
17,215 shares.
Second Amendment to Credit Agreement
On February 11, 2000, we entered into the second amendment to our
credit agreement. For a more detailed description of the amendment see Note 3.
Long-Term Debt.
Val Verde County Properties Acquisition
On February 25, 2000, EXCO purchased certain oil and gas assets located
in Val Verde County, Texas from an undisclosed seller (the Val Verde County
Properties). The assets consist of 21 producing gas wells. Under terms of the
acquisition, EXCO will become operator of 18 of the wells. As of September 30,
1999, total proved reserves net to EXCO's interest included 19.8 Bcf of natural
gas. Production for December 1999, net to EXCO's interest was approximately 106
Mmcf of natural gas.
The purchase price of $12.2 million cash (approximately $7.9 million
after contractual adjustments and a hold-back for preferential rights) was paid
from existing working capital and borrowings of $7.1 million under EXCO's credit
facility. The effective date of the acquisition was October 1, 1999. These
assets qualify as eligible replacement properties under EXCO's tax-deferred
exchange agreement. This use of tax-deferred exchange proceeds is in compliance
with the like-kind exchange provisions of Sections 1031 of the Tax Code. The
price was determined through arms-length negotiation between the parties.
We Executed a Letter of Intent to Form a Joint Venture and Acquire
Properties in Pecos County, Texas
On March 10, 2000, we entered into a letter of intent to form a joint
venture which will acquire certain natural gas assets located in Pecos County,
Texas from an undisclosed seller (the Pecos County Properties). The assets
consist of 8 producing gas wells. Under terms of the letter of intent, we will
become operator of 5 of the wells. As of January 1, 2000, under terms of the
current joint venture structure, total proved reserves net to our interest were
estimated to include 12.6 Bcf of natural gas.
The purchase price of approximately $10.3 million cash ($5.3 million
net to our interest) which is subject to contractual adjustments, will be paid
from existing working capital and anticipated borrowings of $6.8 million.
Borrowings are expected to be made under a new credit facility established for
the joint venture. The effective date of the acquisition is January 1, 2000. The
price was determined through arms-length negotiation between the parties.
Formation of the joint venture and acquisition of the Pecos County
Properties are subject to due diligence including title, environmental and
accounting reviews, as well as negotiation of a credit facility with terms
satisfactory to us.
13. QUARTERLY FINANCIAL RESULTS (UNAUDITED)
Subsequent to September 30, 1999, we have elected to account for our
50% interest in EXUS using the equity method of accounting for investments
because control of EXUS was temporary. We previously accounted for
-49-
52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EXUS using the proportional method of consolidation. The following condensed
interim financial information has been restated from the information contained
in our Forms 10-Q for the three months ended June 30, 1999, and the three months
ended September 30, 1999, as filed with the Securities and Exchange Commission
as if the EXUS operations were accounted for using the equity method of
accounting for investments.
THREE MONTHS THREE MONTHS
ENDED ENDED
JUNE 30, SEPTEMBER 30,
------------ -------------
1999 1999
------------ -------------
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS:
Oil and gas revenue .......................... $ 1,381 $ 1,536
Equity in the earnings of EXUS Energy, LLC ... 126 286
Other ........................................ 317 339
------- -------
Total revenues ............................... 1,824 2,161
Costs and expenses ........................... 1,499 1,502
------- -------
Net income ................................... $ 325 $ 659
======= =======
Basic and diluted earnings per share ......... $ .05 $ .09
======= =======
JUNE 30, SEPTEMBER 30,
-------- -------------
1999 1999
-------- -------------
CONDENSED CONSOLIDATED BALANCE SHEET:
Current assets ............................... $10,488 $12,213
Oil and gas properties, net .................. 12,398 11,985
Investment in EXUS Energy, LLC ............... 7,340 7,626
Other assets ................................. 7,902 7,727
------- -------
Total assets ................................. $38,128 $39,551
======= =======
Current liabilities .......................... $ 1,398 $ 2,448
Other liabilities ............................ 375 226
Long-term debt ............................... -- --
Stockholders' equity ......................... 36,355 36,877
------- -------
Total liabilities and stockholders' equity $38,128 $39,551
======= =======
14. SUPPLEMENTAL OIL AND NATURAL GAS RESERVE AND STANDARDIZED MEASURE
INFORMATION (UNAUDITED)
We retain independent engineering firms to provide annual year-end
estimates of our future net recoverable oil, natural gas, and natural gas
liquids reserves. Estimated proved net recoverable reserves we have shown below
include only those quantities that you can expect to be commercially recoverable
at prices and costs in effect at the balance sheet dates under existing
regulatory practices and with conventional equipment and operating methods.
Proved developed reserves represent only those reserves that we may recover
through existing wells. Proved undeveloped reserves include those reserves that
we may recover from new wells on undrilled acreage or from existing wells on
which we must make a relatively major expenditure for recompletion or secondary
recovery operations.
-50-
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ESTIMATED QUANTITIES OF PROVED RESERVES
OIL (BBLS)(1) GAS (MCF) BOE(2)
------------- --------- -------
(In thousands)
DECEMBER 31, 1996 ................. 169 4,762 963
Purchase of reserves in place ..... -- -- --
New discoveries and extensions . -- -- --
Revisions of previous estimates. (16) (255) (59)
Production ..................... (14) (181) (44)
Sales of reserves in place ..... (81) -- (81)
------ ------- ------
DECEMBER 31, 1997 ................. 58 4,326 779
Purchase of reserves in place .. 972 4,019 1,642
New discoveries and extensions . -- -- --
Revisions of previous estimates. (14) (221) (51)
Production ..................... (53) (412) (121)
Sales of reserves in place ..... -- -- --
------ ------- ------
DECEMBER 31, 1998 ................. 963 7,712 2,249
Purchase of reserves in place .. 2,392 11,033 4,231
New discoveries and extensions . 15 -- 15
Revisions of previous estimates. 298 (942) 141
Production ..................... (208) (765) (336)
Sales of reserves in place ..... (346) (490) (428)
------ ------- ------
DECEMBER 31, 1999 ................. 3,114 16,548 5,872
====== ======= ======
ESTIMATED QUANTITIES OF PROVED DEVELOPED RESERVES
OIL (BBLS)(1) GAS (MCF) BOE(2)
------------- --------- -------
(In thousands)
December 31, 1997 ................. 57 2,341 447
December 31, 1998 ................. 830 5,775 1,792
DECEMBER 31, 1999 ................. 2,759 14,741 5,216
- --------------------
(1) Oil includes both oil and natural gas liquids.
(2) Boe - Barrels of oil equivalent calculated by converting 6 Mcf of natural
gas to 1 Bbl of oil. A Bbl is one stock tank barrel, or 42 U.S. gallons
liquid volume, of crude oil or other liquid hydrocarbons. An Mcf is one
thousand cubic feet of natural gas.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
We have summarized the standardized measure of discounted net cash
flows related to our proved oil, gas, and natural gas liquids reserves. We have
based the following summary on a valuation of proved reserves using discounted
cash flows based on year-end prices, costs, and economic conditions and a 10%
discount rate. The additions to proved reserves from new discoveries and
extensions could vary significantly from year to year; additionally, the impact
of changes to reflect current prices and costs of reserves proved in prior years
could also be significant. Accordingly, you should not view the information
presented below as an estimate of the fair value of our oil and natural gas
properties, nor should you consider the information indicative of any trends.
-51-
54
DECEMBER 31,
----------------------------
1997 1998 1999
------- ------- --------
(IN THOUSANDS)
Future cash inflows ........................................ $10,115 $23,407 $106,878
Future production and development costs .................... 3,130 9,028 46,740
Future income taxes ........................................ 296 20 12,173
------- ------- --------
Future net cash flows ...................................... 6,689 14,359 47,965
Discount of future net cash flows at 10% per annum ......... 2,824 6,406 19,370
------- ------- --------
Standardized measure of discounted future net cash flows ... $ 3,865 $ 7,953 $ 28,595
======= ======= ========
At December 31, 1999, the standardized measure of discounted future net
cash flows before income taxes was approximately $36.9 million.
During recent years, prices paid for oil in the world markets have
fluctuated significantly. This situation has had a destabilizing effect on the
posted prices of oil in the United States, including the posted prices paid by
purchasers of our oil. The weighted average prices of oil and NGLs, and natural
gas at December 31, 1997, 1998 and 1999, used in the above table, were $16.74,
$10.41 and $23.58 per Bbl, respectively, and $2.11, $1.74 and $2.00 per Mcf,
respectively.
CHANGES IN STANDARDIZED MEASURE
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
YEAR ENDED DECEMBER 31,
------------------------------
1997 1998 1999
------- ------- --------
(In thousands)
Sales and transfers of oil and natural gas produced, net of production . $ (348) $ (599) $ (2,993)
costs
Net changes in prices and production costs ............................. (3,398) (1,548) 8,411
Extensions and discoveries, net of future development and production ... -- -- 144
costs
Development costs during the period .................................... 45 -- 111
Revisions of previous quantity estimates ............................... (845) (264) 499
Sales of reserves in place ............................................. (577) -- (1,968)
Purchases of reserves in place ......................................... -- 5,944 27,804
Accretion of discount before income taxes .............................. 832 403 796
Net change in income taxes ............................................. (163) 152 (12,162)
------- ------- --------
Net change ............................................................. $(4,454) $ 4,088 $ 20,642
======= ======= ========
-52-
55
EXCO RESOURCES, INC.
PRO FORMA COMBINED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
On February 25, 2000, EXCO acquired from RVC Energy, Inc., certain oil
and gas assets located in Val Verde County, Texas (the Val Verde County
Properties). The purchase price was $12.2 million cash (approximately $11.4
million after contractual adjustments). On December 31, 1999, EXUS Energy, LLC,
a Delaware limited liability company (EXUS), owned 50% by EXCO Resources, Inc.
(EXCO) and 50% by Venus Exploration, Inc. (Venus), completed the disposition of
the Jackson Parish Properties on December 31, 1999. Additionally, effective
December 31, 1999, EXCO purchased certain oil and gas assets located in
Natchitoches Parish, Louisiana (the Natchitoches Parish Properties) from Western
Gas Resources, Inc. for $7.2 million cash, after adjustments.
The accompanying pro forma combined condensed financial statements are
based on the historical financial statements of EXCO for the year ended December
31, 1999. The pro forma combined condensed financial statements are also based,
in part, on the historical financial statements of Rio Grande, Inc. (Rio Grande
or RGI) which was acquired by EXCO effective March 16, 1999, the Seward/Meade
County, Kansas properties as partial consideration for the Jackson Parish
Properties (the Seward/Meade County Properties), the Natchitoches Parish
Properties and the Val Verde County Properties.
The Pro Forma Combined Condensed Balance Sheet as of December 31, 1999,
assumes the acquisition of the Val Verde County Properties, and the related
borrowings had been consummated on that date. Because RGI was acquired on March
16, 1999, and the disposition of the Jackson Parish Properties, the addition of
the Seward/Meade County Properties and the related repayment of borrowings, and
the acquisition of the Natchitoches Parish Properties all had been consummated
on December 31, 1999, they are already included in EXCO's December 31, 1999
balance sheet. The Pro Forma Combined Condensed Statements of Operations for the
year ended December 31, 1999, has been prepared assuming the acquisition of RGI,
the disposition of the Jackson Parish Properties, the addition of the
Seward/Meade County Properties, the acquisition of the Natchitoches Parish
Properties, and the acquisition of the Val Verde County Properties had been
consummated on January 1, 1999.
The pro forma adjustments are based upon available information and
assumptions that management of EXCO believes are reasonable. The pro forma
combined condensed financial statements do not purport to represent the
financial position or results of operations of EXCO which would have occurred
had such transactions been consummated on the dates indicated or EXCO's
financial position or results of operations for any future date or period.
-53-
56
EXCO RESOURCES, INC.
PRO FORMA COMBINED CONDENSED BALANCE SHEET
DECEMBER 31, 1999
(Unaudited)
PRO FORMA
ADJUSTMENTS
FOR THE
ACQUISITION
EXCO AND PRO FORMA
HISTORICAL DISPOSITION COMBINED
---------- ----------- ---------
(In thousands)
ASSETS:
Current assets:
Cash ............................................. $ 9,972 $ (4,333)(9) $ 5,639
Accounts receivable and other assets ............. 21,627 -- 21,627
-------- -------- --------
Total current assets ......................... 31,599 (4,333) 27,266
Net property and equipment ........................... 18,938 11,444 (9) 30,382
Investments .......................................... 257 -- 257
Other assets ......................................... 138 -- 138
-------- -------- --------
Total assets ................................. $ 50,932 $ 7,111 $ 58,043
======== ======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY:
Current liabilities:
Accounts payable and accrued liabilities ......... $ 5,016 $ -- $ 5,016
Current maturities of long-term debt ............. 5,001 -- 5,001
-------- -------- --------
Total current liabilities .................... 10,017 -- 10,017
Long-term debt, less current maturities .............. -- 7,111 (10) 7,111
Other long-term liabilities .......................... 227 -- 227
Minority interest in limited partnership ............. (192) -- (192)
Stockholders' equity:
Preferred stock .................................. -- -- --
Common stock ..................................... 136 -- 136
Additional paid-in capital ....................... 36,590 -- 36,590
Retained earnings ................................ 4,154 -- 4,154
-------- -------- --------
Total stockholders' equity ................... 40,880 -- 40,880
-------- -------- --------
Total liabilities and stockholders' equity ... $ 50,932 $ 7,111 $ 58,043
======== ======== ========
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57
EXCO RESOURCES, INC.
PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 1999
(Unaudited)
PRO FORMA
ADJUSTMENTS
SEWARD/ FOR THE
RIO MEADE NATCHITOCHES VAL VERDE ACQUISITIONS
EXCO GRANDE COUNTY PARISH COUNTY AND PRO FORMA
HISTORICAL HISTORICAL HISTORICAL HISTORICAL HISTORICAL DISPOSITION COMBINED
---------- ---------- ---------- ------------ ---------- ----------- ---------
(In thousands, except per share amounts)
REVENUES:
Oil and natural gas .................... $ 5,294 $ 176 $185 $5,357 $2,211 $ -- $ 13,223
Gain on disposition of property ........ 5,102 -- -- -- -- (5,102)(5) --
Other .................................. 2,008 23 -- -- -- (1,154)(1)(2)(8) 877
-------- ----- ---- ------ ------ ------- --------
Total revenues ................. 12,404 199 185 5,357 2,211 (6,256) 14,100
EXPENSES:
Oil and natural gas production ......... 2,375 123 45 2,688 319 -- 5,550
Depletion, depreciation and
amortization .......................... 1,446 9 -- -- -- 2,672(3)(7)(11) 4,127
General and administrative ............. 1,934 73 -- -- -- -- 2,007
Interest and other ..................... 17 0 -- -- -- 295(12) 312
-------- ----- ---- ------ ------ ------- --------
Income (loss) before income taxes and
minority interest ...................... 6,632 (6) 140 2,669 1,892 (9,223) 2,104
Minority interest in limited partnership ... (7) 1 -- -- -- -- (6)
-------- ----- ---- ------ ------ ------- --------
Income (loss) before income taxes .......... 6,639 (7) 140 2,669 1,892 (9,223) 2,110
Income tax expense (benefit) ............... 2,139 -- -- -- -- (1,750)(6) 389
-------- ----- ---- ------ ------ ------- --------
Income (loss) before extraordinary item .... 4,500 (7) 140 2,669 1,892 (7,473) 1,721
Fee income from early extinguishment
of debt, net of tax ....................... 165 -- -- -- -- (165)(4) --
-------- ----- ---- ------ ------ ------- --------
Net income (loss) .......................... $ 4,665 $ (7) $140 $2,669 $1,892 $(7,638) $ 1,721
======== ===== ==== ====== ====== ======= ========
Basic and diluted earnings per share ....... $ .69 $ -- $ -- $ -- $ -- $ -- $ .26
======== ===== ==== ====== ====== ======= ========
Weighted average number of common
and common equivalent shares
outstanding:
Basic ........................... 6,698 -- -- -- -- -- 6,698
======== ===== ==== ====== ====== ======= ========
Diluted ......................... 6,714 -- -- -- -- -- 6,714
======== ===== ==== ====== ====== ======= ========
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58
EXCO RESOURCES, INC.
NOTES TO UNAUDITED PRO FORMA
COMBINED CONDENSED FINANCIAL STATEMENTS
A. PRO FORMA ADJUSTMENTS FOR THE JACKSON PARISH PROPERTIES
The accompanying unaudited Pro Forma Combined Condensed Statement of
Operations for the year ended December 31, 1999, has been prepared as if EXCO's
share of the disposition of the Jackson Parish Properties, the addition of the
Seward/Meade County Properties, and the related repayment of debt had been
consummated on January 1, 1999 and reflect the following adjustments:
(1) To record a decrease in interest income as a result of the
repayment of the Venus convertible promissory note.
(2) To eliminate the 1999 equity in the earnings of EXUS Energy,
LLC.
(3) To adjust depreciation, depletion and amortization of the oil
and gas properties to reflect the effect of the addition of
the Seward/Meade County Properties using the full cost method
of accounting on total pro forma proved oil and natural gas
reserves.
(4) To eliminate the fee income, net of tax, on the early
extinguishment of the Venus convertible promissory note.
(5) To eliminate the gain from the sale of EXCO's share of the
Jackson Parish Properties.
(6) To adjust the provision for income taxes for the change in
financial taxable income resulting from the disposition of
EXCO's share of the Jackson Parish Properties and the
inclusion of the historical results of operations of Rio
Grande, Inc., the Seward/Meade County Properties, the
Natchitoches Parish Properties, and the Val Verde County
Properties and adjustments (1), (2), (3), (5), (7), (8),
(11), and (12).
B. PRO FORMA ADJUSTMENTS FOR THE NATCHITOCHES PARISH PROPERTIES
The accompanying unaudited Pro Forma Combined Condensed Statement of
Operations for the year ended December 31, 1999 has been prepared as if EXCO's
share of the acquisition of the Natchitoches Parish Properties had been
consummated on January 1, 1999 and reflect the following adjustments:
(7) To adjust depreciation, depletion and amortization of the oil
and gas properties to reflect the effect of the acquisition of
the Natchitoches Parish Properties using the full cost method
of accounting on total pro forma proved oil and natural gas
reserves.
(8) To record a decrease in interest income or invested cash of
$7.2 million, based on a 4% per annum interest rate.
C. PRO FORMA ADJUSTMENTS FOR THE VAL VERDE COUNTY PROPERTIES
The accompanying unaudited Pro Forma Combined Condensed Balance Sheet as of
December 31, 1999 has been prepared as if the acquisition of the Val Verde
County Properties had been consummated on that date and reflects the following
adjustment:
(9) To record the acquisition of the Val Verde County Properties
in exchange for consideration of approximately $11.4 million
in cash.
(10) To record EXCO's borrowings of approximately $7.1 million
under the NationsBank credit facility.
The accompanying unaudited Pro Forma Combined Statement of Operations for
the year ended December 31, 1999 has been prepared as if the acquisition of the
Val Verde County Properties had been consummated on January 1, 1999 and reflects
the following adjustments:
-56-
59
EXCO RESOURCES, INC.
NOTES TO UNAUDITED PRO FORMA
COMBINED CONDENSED FINANCIAL STATEMENTS
(11) To adjust depreciation, depletion and amortization of the oil
and gas properties to reflect the effect of the acquisition of
the Val Verde County Properties using the full cost method of
accounting on total pro forma proved oil and natural gas
reserves..
(12) To adjust interest expense on the borrowings of approximately
$7.1 million based on a 7.0% per annum interest rate.
D. PRO FORMA COMBINED SUPPLEMENTAL OIL AND NATURAL GAS RESERVE AND
STANDARDIZED MEASURE INFORMATION
RESERVE QUANTITY INFORMATION
The following table presents EXCO's estimate of the pro forma combined
proved oil and natural gas reserves of EXCO after giving effect to the
acquisition of the Val Verde County Properties. All reserves are located in the
United States. EXCO emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of producing
oil and natural gas properties. Accordingly, the estimates are expected to
change as future information becomes available.
Oil (Bbls)(1) Gas (Mcf) Boe(2)
------------- --------- ------
(In thousands)
Proved reserves ............. 3,114 35,284 8,995
===== ====== =====
Proved developed reserves ... 2,759 27,185 7,290
===== ====== =====
- ----------
1 Oil includes both oil and natural gas liquids.
2 Boe - Barrels of oil equivalent calculated by converting 6 Mcf of natural
gas to 1 Bbl of oil. A Bbl is one stock tank barrel, or 42 U.S. gallons
liquid volume, of crude oil or other liquid hydrocarbons. An Mcf is one
thousand cubic feet of natural gas.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND NATURAL GAS RESERVES
The Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Natural Gas Reserves (Standardized Measure) is a disclosure
requirement under Statement of Financial Accounting Standards No. 69.
The Standardized Measure does not purport to be, nor should it be
interpreted to present, the fair value of EXCO's oil and natural gas reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves not presently classified as proved, the value of unproved
properties, and consideration of expected future economic and operating
conditions.
Under the Standardized Measure, future cash flows are estimated by applying
year-end prices, adjusted for fixed and determinable escalations, to the
estimated future production of year-end proved reserves. Future cash inflows are
reduced by estimated future production costs, based on period-end costs, and
projected future development costs to determine pre-tax cash inflows. Future
income taxes are computed by applying the statutory rate (based on the current
tax law adjusted for permanent differences and tax credits) to the excess of
pre-tax net cash flows over EXCO's income tax basis of its oil and natural gas
properties. Future net cash flows are discounted using a 10% annual discount
rate to arrive at the Standardized Measure.
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EXCO RESOURCES, INC.
NOTES TO UNAUDITED PRO FORMA
COMBINED CONDENSED FINANCIAL STATEMENTS
The pro forma Standardized Measure of discounted future net cash flows
relating to EXCO's proved oil and natural gas reserves at December 31, 1999,
follows (in thousands):
Future cash inflows .................................................. $138,695
Future production costs .............................................. 53,761
Future development costs ............................................. 5,219
Future income taxes .................................................. 14,849
--------
Future net cash flows ................................................ 64,866
Discount of future net cash flows at 10% per annum ................... 28,113
--------
Pro forma Standardized Measure of discounted future net cash flows ... $ 36,753
========
The future cash flows shown above include amounts attributable to
non-producing reserves requiring approximately $5.2 million of future
development costs. If these reserves are not developed, the Standardized Measure
of discounted future net cash flows as of December 31, 1999, shown above would
be reduced significantly.
At December 31, 1999, the pro forma Standardized Measure of discounted
future net cash flows before income taxes was approximately $46.1 million.
Estimates of economically recoverable oil and natural gas reserves and of
future net reserves are based upon a number of variable factors and assumptions,
all of which are to some degree speculative and may vary considerably from
actual results. Therefore, actual production, revenues, taxes, development and
operating expenditures may not occur as estimated. The reserve data are
estimates only, are subject to many uncertainties and are based on data gained
from production histories and on assumptions as to geologic formations and other
matters. Actual quantities of oil and natural gas may differ materially from the
amounts estimated.
The weighted average prices of oil (including NGLs) and natural gas at
December 31, 1999 used in the calculation of the Standardized Measure were
$23.58 per Bbl and $1.84 per Mcf, respectively.
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REPORT OF INDEPENDENT ACCOUNTANTS
The Board of Directors
EXCO Resources, Inc.
We have audited the accompanying statements of operating revenues and direct
operating expenses of the share of the Val Verde County Properties (as defined
in Note 1 to the accompanying statements) acquired by EXCO Resources, Inc. for
the six month period ended December 31, 1998, and the year ended December 31,
1999. These statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe our audits provide a reasonable basis for our
opinion.
The accompanying statements of operating revenues and direct operating expenses
were prepared in connection with the proposed purchase of such properties and,
as described in Note 1, do not include charges for depletion, depreciation and
amortization, federal and state income taxes, interest expense or general and
administrative expenses and are not intended to be a complete presentation of
revenues and expenses of the Val Verde County Properties.
In our opinion, the statements of operating revenues and direct operating
expenses referred to above present fairly, in all material respects, the
operating revenues and direct operating expenses of the share of the Val Verde
County Properties acquired by EXCO Resources, Inc. for the six months ended
December 31, 1998, and the year ended December 31, 1999 in conformity with
accounting principles generally accepted in the United States.
/s/ ERNST & YOUNG LLP
ERNST & YOUNG LLP
Oklahoma City, Oklahoma
February 10, 2000
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
EXCO Resources, Inc.:
We have audited the accompanying statements of operating revenues and direct
operating expenses of the share of the Val Verde County Properties (as defined
in Note 1 to the accompanying statements) acquired by EXCO Resources, Inc. for
the year ended December 31, 1997, and the six month period ended June 30, 1998.
These statements are the responsibility of the Val Verde County Properties'
management. Our responsibility is to express an opinion on these statements
based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United Stated. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the statements of operating
revenues and direct operating expenses are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the statements of operating revenues and direct operating
expenses. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
The accompanying statements of operating revenues and direct operating expenses
were prepared in connection with the purchase of the Val Verde County Properties
and, as described in Note 1, exclude general and administrative expenses,
depreciation, depletion and amortization, interest and income taxes and are not
intended to be a complete presentation of revenues and expenses of the Val Verde
County Properties.
In our opinion, the statements of operating revenues and direct operating
expenses referred to above present fairly, in all material respects, the
operating revenues and direct operating expenses of the Val Verde County
Properties for the year ended December 31, 1997, and the six month period ended
June 30, 1998, in conformity with accounting principles generally accepted in
the United States.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma,
January 8, 1999
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VAL VERDE COUNTY PROPERTIES
STATEMENTS OF OPERATING REVENUES
AND DIRECT OPERATING EXPENSES
(In thousands)
SIX MONTHS SIX MONTHS
YEAR ENDED ENDED ENDED YEAR ENDED
DECEMBER 31, JUNE 30, DECEMBER 31, DECEMBER 31,
------------ ---------- ------------ ------------------
1997 1998 1998 1998 1999
------ ------ ------ ------ ------
Oil and natural gas sales ........................... $2,910 $1,335 $1,130 $2,465 $2,211
Direct operating expenses ........................... 360 150 196 346 319
------ ------ ------ ------ ------
Excess of revenues over direct operating expenses ... $2,550 $1,185 $ 934 $2,119 $1,892
====== ====== ====== ====== ======
See accompanying notes.
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VAL VERDE COUNTY PROPERTIES
NOTES TO STATEMENTS OF OPERATING REVENUES
AND DIRECT OPERATING EXPENSES
1. BASIS OF PRESENTATION
On February 25, 2000, EXCO Resources, Inc. (EXCO), as buyer, purchased
certain oil and gas assets located in Val Verde County, Texas from RVC Energy,
Inc. (RVC) (the Val Verde County Properties) for consideration of $12.2 million
cash (approximately $7.9 million after contractual adjustments and a hold-back
for preferential rights). The preferential rights were subsequently waived, and
EXCO paid on March 14, 2000, additional consideration of approximately $3.5
million cash. Total cash consideration paid for the Val Verde County Properties
was $11.4 million after contractual adjustments.
The accompanying statements present the interest acquired by EXCO in the
operating revenues and direct operating expenses of the Val Verde County
Properties. Direct operating expenses include the actual costs of maintaining
the producing properties and their production, but do not include charges for
depletion, depreciation, and amortization; federal and state income taxes;
interest; or general and administrative expenses. Presentation of complete
historical financial statements for the years ended December 31, 1997, 1998, and
1999 is not practicable because the Val Verde County Properties were not
accounted for as a separate entity by RVC; and therefore, such statements are
not available. The operating revenues and direct operating expenses for the
periods presented may not be representative of future operations.
Revenues in the accompanying Statements of Operating Revenues and Direct
Operating Expenses are recognized on the sales method. Direct operating expenses
are recognized on an accrual basis. Revenues are reflected net of gathering
changes of $.145 per Mmbtu.
2. SUPPLEMENTAL OIL AND NATURAL GAS RESERVE AND STANDARDIZED MEASURE
INFORMATION (UNAUDITED)
OIL AND NATURAL GAS OPERATIONS
During the years ended December 31, 1997, 1998 and 1999, no exploration or
incremental general and administrative costs were incurred.
RESERVE QUANTITY INFORMATION
The following table presents EXCO's estimate of its share of the proved oil
and natural gas reserves of the Val Verde County Properties, all of which are
located in the United States, as of December 31, 1999. EXCO emphasizes that
reserve estimates are inherently imprecise and that estimates of new discoveries
are more imprecise than those of producing oil and natural gas properties.
Accordingly, the estimates are expected to change as future information becomes
available.
Oil (Bbls)(1) Gas (Mcf) Boe(2)
------------- ---------- ----------
(In thousands)
Proved reserves ............. -- 19,089 3,182
========== ========== ==========
Proved developed reserves ... -- 12,798 2,133
========== ========== ==========
- ----------
(1) Oil includes both oil and natural gas liquids.
(2) Boe - Barrels of oil equivalent calculated by converting 6 Mcf of natural
gas to 1 Bbl of oil. A Bbl is one stock tank barrel, or 42 U.S. gallons
liquid volume, of crude oil or other liquid hydrocarbons. An Mcf is one
thousand cubic feet of natural gas.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves (Standardized Measure) is a disclosure requirement
under Statement of Financial Accounting Standards No. 69.
The Standardized Measure does not purport to be, nor should it be
interpreted to present, the fair value of the oil and natural gas reserves of
the Val Verde County Properties. An estimate of fair value would also take into
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VAL VERDE COUNTY PROPERTIES
NOTES TO STATEMENTS OF OPERATING REVENUES
AND DIRECT OPERATING EXPENSES
account, among other things, the recovery of reserves not presently classified
as proved, the value of unproved properties, and consideration of expected
future economic and operating conditions.
Under the Standardized Measure, future cash flows are estimated by applying
year-end prices, adjusted for fixed and determinable escalations, to the
estimated future production of year-end proved reserves. Future cash flows are
reduced by estimated future production costs, based on period-end costs, and
projected future development costs to determine net cash inflows. The Val Verde
County Properties are not a separate tax paying entity. Accordingly, the
Standardized Measure for the Val Verde County Properties is presented before
deduction of income taxes. Future net cash flows are discounted using a 10%
annual discount rate to arrive at the Standardized Measure.
The Standardized Measure of discounted future net cash flows relating to
proved oil and natural gas reserves of EXCO's share of the Val Verde County
Properties at December 31, 1999 follows (in thousands):
Future cash inflows .................................... $32,415
Future production costs ................................ 9,141
Future development costs ............................... 3,253
-------
Future net cash flows .................................. 20,021
Discount of future net cash flows at 10% per annum ..... 10,712
-------
Discounted future net cash flows before income taxes ... $ 9,309
=======
Estimates of economically recoverable oil and natural gas reserves and of
future net revenues are based upon a number of variable factors and assumptions,
all of which are to some degree speculative and may vary considerably from
actual results. Therefore, actual production, revenues, taxes, development and
operating expenditures may not occur as estimated. The reserve data are
estimates only, are subject to many uncertainties, and are based on data gained
from production histories and on assumptions as to geologic formations and other
matters. Actual quantities of natural gas and oil may differ materially from the
amounts estimated.
The weighted average price of natural gas at December 31, 1999 used in the
calculation of the Standardized Measure was $1.70 per Mcf.
-63-
66
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
-64-
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item will be set forth under the captions
"Election of Directors," "Section 16(a) Beneficial Ownership Reporting
Compliance," "Certain Relationships Between the Company and Directors, Officers
or Shareholders," and "Directors and Executive Officers" of our proxy statement
for our 2000 annual meeting of shareholders which was filed with the Securities
and Exchange Commission pursuant to Regulation 14A under the Securities Exchange
Act of 1934 and is incorporated herein by reference. The proxy statement was
filed on March 21, 2000.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth under the caption
"Executive Compensation" in Appendix C of our proxy statement which was filed
with the Securities and Exchange Commission pursuant to Regulation 14A under the
Securities Exchange Act of 1934 and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is set forth in Appendix B under the
caption "Shareholders" of our proxy statement which was filed with the
Securities and Exchange Commission pursuant to Regulation 14A under the
Securities Exchange Act of 1934 and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth under the captions
"Certain Relationships Between the Company and Directors, Officers or
Shareholders" of our proxy statement which was filed with the Securities and
Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act
of 1934 and is incorporated herein by reference.
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PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8K
1. FINANCIAL STATEMENTS
See Index to Financial Statements on page 32 to this annual report.
2. FINANCIAL STATEMENT SCHEDULES
All schedules are omitted because the information is not required under the
related instructions or is inapplicable or because the information is
included in the Financial Statements or related Notes.
3. EXHIBITS
2.1 First Amended Joint Chapter 11 Plan of Reorganization of Rio
Grande, Inc., Rio Grande Drilling Company, Rio Grande Desert Oil
Company, Rio Grande Offshore, Ltd., and Rio Grande GulfMex, Ltd.,
dated January 25, 1999 and modified March 4, 1999, previously
filed as an exhibit to Rio Grande, Inc.'s Form 8-K/A filed March
23, 1999 and incorporated by reference herein.
2.2 Confirmation Order for the Plan of Reorganization, dated March 4,
1999, previously filed as an exhibit to Rio Grande, Inc.'s Form
8-K/A filed March 23, 1999 and incorporated by reference herein.
2.3 Findings of Fact and Conclusions of Law regarding Confirmation
Order (which set forth the March 4, 1999 modifications to the
Plan), previously filed as an exhibit to Rio Grande, Inc.'s Form
8-K/A filed March 23, 1999 and incorporated by reference herein.
3.1 Restated Articles of Incorporation of EXCO filed as an Exhibit to
EXCO's Annual Report on Form 10-K for the year ended December 31,
1996 and incorporated by reference herein.
3.2 Bylaws of EXCO, as amended filed as an Exhibit to EXCO's Annual
Report on Form 10-K for the year ended December 31, 1996 and
incorporated by reference herein.
4.1 Restated Articles of Incorporation of EXCO filed as an Exhibit to
EXCO's Annual Report on Form 10-K for the year ended December 31,
1996 and incorporated by reference herein.
4.2 Restated Bylaws of EXCO, as amended, filed as an Exhibit to EXCO's
Annual Report on Form 10-K for the year ended December 31, 1996
and incorporated by reference herein.
4.3 Specimen Stock Certificate for the Common Stock of EXCO filed as
an Exhibit to EXCO's Pre-Effective Amendment No. 1 to Form S-2
filed on June 2, 1998 and incorporated by reference herein.
10.1 Standby Purchase Commitment between EXCO Resources, Inc. on the
one hand and Ares Management, L.P. on behalf of Ares Leveraged
Investment Fund, L.P. on the other hand dated July 16, 1998 filed
as an Exhibit to EXCO's Form 8-K filed August 25, 1998 and
incorporated by reference herein.
10.2 Standby Purchase Commitment between EXCO Resources, Inc. on the
one hand and Oaktree Capital Management, LLC on behalf of OCM
Principal Opportunities Fund, L.P. on the other hand, dated July
16, 1998 filed as an Exhibit to EXCO's Form 8-K filed August 25,
1998 and incorporated by reference herein.
10.3 Credit Agreement among EXCO Resources, Inc., as borrower, and
NationsBank of Texas, N.A., as agent, and financial institutions
listed on Schedule I, dated February 11, 1998 filed as an Exhibit
to EXCO's Form 8-K filed February 25, 1998 and incorporated by
reference herein.
10.4 First Amendment to Credit Agreement among EXCO Resources, Inc., as
borrower, NationsBank, N.A. (successor by merger to NationsBank of
Texas, N.A.), as agent, and financial institutions listed on
Schedule I, dated September 21, 1998, filed as an Exhibit to
EXCO's Form 8-K filed September 28, 1998 and incorporated by
reference herein.
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69
10.5 Purchase and Sale Agreement among EXCO Resources, Inc. and Osborne
Oil Company, et al., dated January 27, 1998 filed as an Exhibit to
EXCO's Form 8-K filed August 25, 1998 and incorporated by
reference herein.
10.6 EXCO Energy Investors, L.L.C. Operating Agreement, dated October
9, 1998, filed as an Exhibit to EXCO's Annual Report on Form 10-K
for the year ended December 31, 1998 and incorporated by reference
herein.
10.7 Purchase and Sale Agreement among EXCO Resources, Inc. and Osborne
Oil Company, et al., dated January 27, 1998, filed as an Exhibit
to EXCO's Form 8-K dated February 25, 1998 and incorporated by
reference herein.
10.8 Stock Purchase Agreement between EXCO Resources, Inc. and
Jacobi-Johnson Energy, Inc., dated May 1, 1998, filed as an
Exhibit to EXCO's Form 8-K filed May 15, 1998 and incorporated by
reference herein.
10.9 EXCO Resources, Inc. 1998 Stock Option Plan, filed as Appendix A
to EXCO's Proxy Statement dated March 17, 1998 and incorporated by
reference herein.
10.10 Amendment No. 1 to the EXCO Resources, Inc. 1998 Stock Option
Plan, filed as Exhibit 10.10 to EXCO's Form 10-Q dated May 17,
1999 and incorporated by reference herein.
10.11 EXCO Resources, Inc. 1998 Director Compensation Plan filed as
Appendix D to EXCO's Proxy Statement dated March 16, 1999 and
incorporated by reference herein.
10.12 Purchase and Sale Agreement dated June 24, 1998, by and between
Humphrey Oil Interests, L.P. on the one hand and EXCO Resources,
Inc. on the other, filed as an Exhibit to EXCO's Form 8-K dated
June 30, 1998 and incorporated by reference herein.
10.13 Purchase and Sale Agreement dated June 24, 1998, by and between J.
M. Hill, Individually and as Trustee, Walter O. Hill, and Steven
J. Devos on the one hand and EXCO Resources, Inc. on the other,
filed as an Exhibit to EXCO's Form 8-K dated June 30, 1998 and
incorporated by reference herein.
10.14 Purchase and Sale Agreement between Apache Corporation as seller,
and Venus Exploration, Inc., buyer, dated May 13, 1999, filed as
an Exhibit to EXCO's Form 8-K filed July 15, 1999 and incorporated
by reference herein.
10.15 Credit Agreement among EXUS Energy, LLC, as borrower, NationsBank,
N.A., as administrative agent, and financial institutions listed
on Schedule I, dated June 30, 1999, filed as an Exhibit to EXCO's
Form 8-K filed July 15, 1999 and incorporated by reference herein.
10.16 Limited Liability Company Agreement of EXUS Energy, LLC dated June
30, 1999, filed as an Exhibit to EXCO's Form 8-K filed July 15,
1999 and incorporated by reference herein.
10.17 Convertible Promissory Note made by Venus Exploration, Inc. in
favor of EXCO Resources, Inc., dated June 30, 1999, filed as an
Exhibit to EXCO's Form 8-K filed July 15, 1999 and incorporated by
reference herein.
10.18 Pledge Agreement made by Venus Exploration, Inc. for the benefit
of EXCO Resources, Inc., dated June 30, 1999, filed as an Exhibit
to EXCO's Form 8-K filed July 15, 1999 and incorporated by
reference herein.
10.19 Registration Rights Agreement between EXCO Resources, Inc. and
Venus Exploration, Inc., dated June 30, 1999, filed as an Exhibit
to EXCO's Form 8-K filed July 15, 1999 and incorporated by
reference herein.
10.20 Agreement Among Members between EXCO Resources, Inc. and Venus
Exploration, Inc., dated June 30, 1999, filed as an Exhibit to
EXCO's Form 8-K filed July 15, 1999 and incorporated by reference
herein.
10.21 Second Amendment to Credit Agreement among EXCO Resources, Inc.,
as borrower, Bank of America, N.A. (successor by merger to
NationsBank, N.A., successor by merger to NationsBank of Texas,
N.A.), as agent, and Bank of America , N.A. (successor by merger
to NationsBank, N.A., successor by merger to NationsBank of Texas,
N.A.), as the sole bank, dated February 11, 2000 (filed herewith).
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70
10.22 Purchase, Sale and Exchange Agreement between EXCO Resources,
Inc., as seller, and Anadarko Petroleum Corporation, as buyer,
dated December 17, 1999, filed as an Exhibit to EXCO's Form 8-K
filed January 18, 2000 and incorporated by reference herein.
10.23 Amendment to Purchase, Sale and Exchange Agreement dated as of
December 17, 1999, between EXCO Resources, Inc., as seller, and
Anadarko Petroleum Corporation, as buyer, dated December 31, 1999,
filed as an Exhibit to EXCO's Form 8-K filed January 18, 2000 and
incorporated by reference herein.
10.24 Purchase and Sale Agreement between Western Gas Resources, Inc.,
as seller, and EXCO Resources, Inc., as buyer, dated November 16,
1999, filed as an Exhibit to EXCO's Form 8-K filed January 18,
2000 and incorporated by reference herein.
10.25 Amendment No. 1 to Purchase and Sale Agreement between Western Gas
Resources, Inc., as seller, and EXCO Resources, Inc., as buyer,
dated December 21, 1999, filed as an Exhibit to this Form 8-K
filed January 18, 2000 and incorporated by reference herein.
16.1 Letter from Belew Averitt LLP regarding change in certifying
accountant dated January 20, 1998 filed as an Exhibit to EXCO's
Form 8-K filed January 21, 1998 and incorporated by reference
herein.
18.1 Letter from Ernst & Young LLP regarding change in accounting
principles dated February 11, 1998 filed as an Exhibit to EXCO's
Annual Report on Form 10-K for the year ended December 31, 1997
and incorporated by reference herein.
23.1 Consent of Independent Accountants, Ernst & Young LLP (filed
herewith).
23.2 Consent of Independent Public Accountants, Arthur Andersen LLP
(filed herewith).
23.3 Consent of Independent Petroleum Engineers, Lee Keeling and
Associates, Inc. (filed herewith).
27.1 Financial Data Schedule (filed herewith).
99.1 Voting Agreement dated October 30, 1998 between Rio Grande, Inc.,
Rio Grande Drilling Company, Rio Grande Offshore, Ltd., Rio Grande
Desert Oil Company and Rio Grande GulfMex, Ltd. and EXCO
Resources, Inc. filed as an Exhibit to Rio Grande, Inc.'s Form 8-K
dated November 12, 1998 and incorporated by reference herein.
- ----------
4. REPORTS ON FORM 8-K
Current Report on Form 8-K dated December 31, 1999 filed January 18,
2000 pursuant to Item 2 reporting the acquisition of the Natchitoches
Parish Properties.
Current Report on Form 8-K/A (Amendment No. 1) dated December 31, 1999
filed March 6, 2000 pursuant to Item 7 and containing the Natchitoches
Parish Properties Financial Statements.
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SIGNATURE PAGE
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, there unto duly authorized in the City of Dallas,
Texas on the 22nd of March, 2000.
EXCO RESOURCES, INC.
By: /s/ DOUGLAS H. MILLER
--------------------------------
Douglas H. Miller
Chairman of the Board of Directors
And Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
March 22, 2000 /s/ DOUGLAS H. MILLER
----------------------------------
Douglas H. Miller
Chairman of the Board of Directors
And Chief Executive Officer
March 22, 2000 /s/ T. W. EUBANK
----------------------------------
T. W. Eubank
Director, President and Treasurer
March 22, 2000 /s/ J. DOUGLAS RAMSEY
----------------------------------
J. Douglas Ramsey, Ph.D.
Director, Vice President and
Chief Financial Officer
(Principal Financial and Accounting
Officer)
March 22, 2000 /s/ JEFFREY D. BENJAMIN
----------------------------------
Jeffrey D. Benjamin
Director
March 22, 2000 /s/ EARL E. ELLIS
----------------------------------
Earl E. Ellis
Director
March 22, 2000 /s/ J. MICHAEL MUCKLEROY
----------------------------------
J. Michael Muckleroy
Director
March 22, 2000 /s/ BOONE PICKENS
----------------------------------
Boone Pickens
Director
March 22, 2000 /s/ STEPHEN F. SMITH
----------------------------------
Stephen F. Smith
Director
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EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.1 First Amended Joint Chapter 11 Plan of Reorganization of Rio
Grande, Inc., Rio Grande Drilling Company, Rio Grande Desert Oil
Company, Rio Grande Offshore, Ltd., and Rio Grande GulfMex, Ltd.,
dated January 25, 1999 and modified March 4, 1999, previously
filed as an exhibit to Rio Grande, Inc.'s Form 8-K/A filed March
23, 1999 and incorporated by reference herein.
2.2 Confirmation Order for the Plan of Reorganization, dated March 4,
1999, previously filed as an exhibit to Rio Grande, Inc.'s Form
8-K/A filed March 23, 1999 and incorporated by reference herein.
2.3 Findings of Fact and Conclusions of Law regarding Confirmation
Order (which set forth the March 4, 1999 modifications to the
Plan), previously filed as an exhibit to Rio Grande, Inc.'s Form
8-K/A filed March 23, 1999 and incorporated by reference herein.
3.1 Restated Articles of Incorporation of EXCO filed as an Exhibit to
EXCO's Annual Report on Form 10-K for the year ended December 31,
1996 and incorporated by reference herein.
3.2 Bylaws of EXCO, as amended filed as an Exhibit to EXCO's Annual
Report on Form 10-K for the year ended December 31, 1996 and
incorporated by reference herein.
4.1 Restated Articles of Incorporation of EXCO filed as an Exhibit to
EXCO's Annual Report on Form 10-K for the year ended December 31,
1996 and incorporated by reference herein.
4.2 Restated Bylaws of EXCO, as amended, filed as an Exhibit to EXCO's
Annual Report on Form 10-K for the year ended December 31, 1996
and incorporated by reference herein.
4.3 Specimen Stock Certificate for the Common Stock of EXCO filed as
an Exhibit to EXCO's Pre-Effective Amendment No. 1 to Form S-2
filed on June 2, 1998 and incorporated by reference herein.
10.1 Standby Purchase Commitment between EXCO Resources, Inc. on the
one hand and Ares Management, L.P. on behalf of Ares Leveraged
Investment Fund, L.P. on the other hand dated July 16, 1998 filed
as an Exhibit to EXCO's Form 8-K filed August 25, 1998 and
incorporated by reference herein.
10.2 Standby Purchase Commitment between EXCO Resources, Inc. on the
one hand and Oaktree Capital Management, LLC on behalf of OCM
Principal Opportunities Fund, L.P. on the other hand, dated July
16, 1998 filed as an Exhibit to EXCO's Form 8-K filed August 25,
1998 and incorporated by reference herein.
10.3 Credit Agreement among EXCO Resources, Inc., as borrower, and
NationsBank of Texas, N.A., as agent, and financial institutions
listed on Schedule I, dated February 11, 1998 filed as an Exhibit
to EXCO's Form 8-K filed February 25, 1998 and incorporated by
reference herein.
10.4 First Amendment to Credit Agreement among EXCO Resources, Inc., as
borrower, NationsBank, N.A. (successor by merger to NationsBank of
Texas, N.A.), as agent, and financial institutions listed on
Schedule I, dated September 21, 1998, filed as an Exhibit to
EXCO's Form 8-K filed September 28, 1998 and incorporated by
reference herein.
73
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.5 Purchase and Sale Agreement among EXCO Resources, Inc. and Osborne
Oil Company, et al., dated January 27, 1998 filed as an Exhibit to
EXCO's Form 8-K filed August 25, 1998 and incorporated by
reference herein.
10.6 EXCO Energy Investors, L.L.C. Operating Agreement, dated October
9, 1998, filed as an Exhibit to EXCO's Annual Report on Form 10-K
for the year ended December 31, 1998 and incorporated by reference
herein.
10.7 Purchase and Sale Agreement among EXCO Resources, Inc. and Osborne
Oil Company, et al., dated January 27, 1998, filed as an Exhibit
to EXCO's Form 8-K dated February 25, 1998 and incorporated by
reference herein.
10.8 Stock Purchase Agreement between EXCO Resources, Inc. and
Jacobi-Johnson Energy, Inc., dated May 1, 1998, filed as an
Exhibit to EXCO's Form 8-K filed May 15, 1998 and incorporated by
reference herein.
10.9 EXCO Resources, Inc. 1998 Stock Option Plan, filed as Appendix A
to EXCO's Proxy Statement dated March 17, 1998 and incorporated by
reference herein.
10.10 Amendment No. 1 to the EXCO Resources, Inc. 1998 Stock Option
Plan, filed as Exhibit 10.10 to EXCO's Form 10-Q dated May 17,
1999 and incorporated by reference herein.
10.11 EXCO Resources, Inc. 1998 Director Compensation Plan filed as
Appendix D to EXCO's Proxy Statement dated March 16, 1999 and
incorporated by reference herein.
10.12 Purchase and Sale Agreement dated June 24, 1998, by and between
Humphrey Oil Interests, L.P. on the one hand and EXCO Resources,
Inc. on the other, filed as an Exhibit to EXCO's Form 8-K dated
June 30, 1998 and incorporated by reference herein.
10.13 Purchase and Sale Agreement dated June 24, 1998, by and between J.
M. Hill, Individually and as Trustee, Walter O. Hill, and Steven
J. Devos on the one hand and EXCO Resources, Inc. on the other,
filed as an Exhibit to EXCO's Form 8-K dated June 30, 1998 and
incorporated by reference herein.
10.14 Purchase and Sale Agreement between Apache Corporation as seller,
and Venus Exploration, Inc., buyer, dated May 13, 1999, filed as
an Exhibit to EXCO's Form 8-K filed July 15, 1999 and incorporated
by reference herein.
10.15 Credit Agreement among EXUS Energy, LLC, as borrower, NationsBank,
N.A., as administrative agent, and financial institutions listed
on Schedule I, dated June 30, 1999, filed as an Exhibit to EXCO's
Form 8-K filed July 15, 1999 and incorporated by reference herein.
10.16 Limited Liability Company Agreement of EXUS Energy, LLC dated June
30, 1999, filed as an Exhibit to EXCO's Form 8-K filed July 15,
1999 and incorporated by reference herein.
10.17 Convertible Promissory Note made by Venus Exploration, Inc. in
favor of EXCO Resources, Inc., dated June 30, 1999, filed as an
Exhibit to EXCO's Form 8-K filed July 15, 1999 and incorporated by
reference herein.
10.18 Pledge Agreement made by Venus Exploration, Inc. for the benefit
of EXCO Resources, Inc., dated June 30, 1999, filed as an Exhibit
to EXCO's Form 8-K filed July 15, 1999 and incorporated by
reference herein.
10.19 Registration Rights Agreement between EXCO Resources, Inc. and
Venus Exploration, Inc., dated June 30, 1999, filed as an Exhibit
to EXCO's Form 8-K filed July 15, 1999 and incorporated by
reference herein.
10.20 Agreement Among Members between EXCO Resources, Inc. and Venus
Exploration, Inc., dated June 30, 1999, filed as an Exhibit to
EXCO's Form 8-K filed July 15, 1999 and incorporated by reference
herein.
10.21 Second Amendment to Credit Agreement among EXCO Resources, Inc.,
as borrower, Bank of America, N.A. (successor by merger to
NationsBank, N.A., successor by merger to NationsBank of Texas,
N.A.), as agent, and Bank of America , N.A. (successor by merger
to NationsBank, N.A., successor by merger to NationsBank of Texas,
N.A.), as the sole bank, dated February 11, 2000 (filed herewith)
74
EXHIBIT
NUMBER DESCRIPTION
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10.22 Purchase, Sale and Exchange Agreement between EXCO Resources,
Inc., as seller, and Anadarko Petroleum Corporation, as buyer,
dated December 17, 1999, filed as an Exhibit to EXCO's Form 8-K
filed January 18, 2000 and incorporated by reference herein.
10.23 Amendment to Purchase, Sale and Exchange Agreement dated as of
December 17, 1999, between EXCO Resources, Inc., as seller, and
Anadarko Petroleum Corporation, as buyer, dated December 31, 1999,
filed as an Exhibit to EXCO's Form 8-K filed January 18, 2000 and
incorporated by reference herein.
10.24 Purchase and Sale Agreement between Western Gas Resources, Inc.,
as seller, and EXCO Resources, Inc., as buyer, dated November 16,
1999, filed as an Exhibit to EXCO's Form 8-K filed January 18,
2000 and incorporated by reference herein.
10.25 Amendment No. 1 to Purchase and Sale Agreement between Western Gas
Resources, Inc., as seller, and EXCO Resources, Inc., as buyer,
dated December 21, 1999, filed as an Exhibit to this Form 8-K
filed January 18, 2000 and incorporated by reference herein.
16.1 Letter from Belew Averitt LLP regarding change in certifying
accountant dated January 20, 1998 filed as an Exhibit to EXCO's
Form 8-K filed January 21, 1998 and incorporated by reference
herein.
18.1 Letter from Ernst & Young LLP regarding change in accounting
principles dated February 11, 1998 filed as an Exhibit to EXCO's
Annual Report on Form 10-K for the year ended December 31, 1997
and incorporated by reference herein.
23.1 Consent of Independent Accountants, Ernst & Young LLP (filed
herewith).
23.2 Consent of Independent Public Accountants, Arthur Andersen LLP
(filed herewith).
23.3 Consent of Independent Petroleum Engineers, Lee Keeling and
Associates, Inc. (filed herewith).
27.1 Financial Data Schedule (filed herewith).
99.1 Voting Agreement dated October 30, 1998 between Rio Grande, Inc.,
Rio Grande Drilling Company, Rio Grande Offshore, Ltd., Rio Grande
Desert Oil Company and Rio Grande GulfMex, Ltd. and EXCO
Resources, Inc. filed as an Exhibit to Rio Grande, Inc.'s Form 8-K
dated November 12, 1998 and incorporated by reference herein.