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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 1996
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 NO. 0-21411
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COSTILLA ENERGY, INC.
(Exact name of registrant as specified in its charter)
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DELAWARE 75-2658940
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 WEST ILLINOIS, SUITE 1000 MIDLAND, TEXAS 79701
(Address of principal executive offices) (Zip code)
(915) 683-3092
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, $0.10 PAR VALUE 10 1/4% SENIOR NOTES DUE 2006
(Title of Class) (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 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
YES NO X*
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*The Registrant's Form 8-A was declared effective with the Securities
and Exchange Commission on October 2, 1996.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the Common Stock held by non-affiliates, based
upon the last sale price as quoted on the Nasdaq Stock Market's National
Market of $13.00 per share on March 21, 1997, was $79,887,340.
Number of shares of Common Stock outstanding as of March 21, 1997 ... 10,476,500
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Form 10-K will be included in
the registrant's definitive Proxy Statement, which will be filed with the
Commission not later than April 30, 1997 and which is incorporated herein by
reference.
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COSTILLA ENERGY, INC.
TABLE OF CONTENTS
PAGE
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PART I.
Item 1. Business. 3
Item 2. Properties. 10
Item 3. Legal Proceedings. 18
Item 4. Submission of Matters to a Vote of Security Holders. 18
PART II.
Item 5. Market for the Registrant's Common Equity and
Related Stockholder Matters. 19
Item 6. Selected Financial Data. 20
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations. 21
Item 8. Financial Statements and Supplementary Data. 26
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure. 26
PART III.
Item 10. Directors and Executive Officers of the Registrant. 27
Item 11. Executive Compensation. 27
Item 12. Security Ownership of Certain Beneficial Owners
and Management. 27
Item 13. Certain Relationships and Related Transactions. 27
PART IV.
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K. 28
SIGNATURES 30
2
PART I
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Form 10-K under "Item 1. Business," "Item 3. Legal
Proceedings," "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations," and elsewhere in this Form 10-K
constitute "forward-looking statements" within the meaning of the Private
Securities Litigation Reform Act of 1995 (the "Reform Act"). Such
forward-looking statements involve known and unknown risks, uncertainties,
and other factors which may cause the actual results, performance, or
achievements of Costilla Energy, Inc. ("Costilla" or the "Company") to be
materially different from any future results, performance, or achievements
expressed or implied by such forward-looking statements. Such factors
include, among others, the following: the volatility of oil and gas prices,
the Company's drilling results and ability to replace oil and gas reserves,
the availability of capital resources, the reliance upon estimates of proved
reserves, operating hazards and uninsured risks, competition, government
regulation, and the ability of the Company to implement its business
strategy, and other factors referenced in the Company's recent prospectus for
its initial public offering of common stock.
ITEM 1. BUSINESS.
Special Note: Certain statements set forth below under this caption
constitute "forward-looking statements" within the meaning of the Reform Act.
See "Special Note Regarding Forward-Looking Statements" for additional
factors relating to such statements.
GENERAL
Costilla Energy, Inc. ("Costilla" or the "Company") is an independent energy
company that is engaged in the exploration, exploitation, development, and
acquisition of oil and gas properties. The Company's primary operations are
in the Permian Basin area of Texas and New Mexico, the Gulf Coast (onshore)
and the Rocky Mountain regions. In 1996 the Company acquired an interest in
an entity which has a concession for the development of mineral interests in
the Republic of Moldova, in Eastern Europe.
The Company's predecessor began operating in 1988 with the strategy of
acquiring and exploiting undervalued oil and gas properties, and at December
31, 1992 had net proved reserves of 4.7 MMBOE. Since January 1, 1993, the
Company has successfully closed seven transactions for an aggregate purchase
price of approximately $101 million. As of January 1, 1997, the Company had
total estimated net proved reserves of 17.0 Mmbbls of oil and 120.3 Bcf of
gas, aggregating 37.0 MMBOE, with a PV-10 Value of approximately $311.8
million, all of which has been calculated pursuant to the requirements of the
Securities and Exchange Commission. The Company also has a substantial
undeveloped acreage position consisting of 242,541 gross (147,742 net) acres
at December 31, 1996. The Company has identified in excess of 200 drilling
locations of which 88 are included in its proved reserves.
Costilla has in-house exploration expertise which uses 3-D seismic technology
as a primary tool to identify drilling opportunities and has experienced high
rates of success in each of its first two major 3-D seismic drilling programs.
Since 1994, the Company has drilled 41wells based on these 3-D surveys, 36 of
which have been productive. The Company has completed two additional 3-D
surveys in 1996 on one of these acreage blocks. The Company currently plans
to drill approximately 48 wells in 1997 based on its 3-D surveys.
Since 1993, Costilla has generated significant growth in reserves and
production. The Company increased its estimated proved reserves from 6.0
MMBOE at January 1, 1994 to 37.0 MMBOE at January 1, 1997 representing a
compound annual growth rate of 83%. This reserve growth has been achieved at
an average All-In Finding Cost of $3.68 per BOE over such period, a level
which the Company believes is lower than industry averages. Concurrently,
the Company increased its average net daily production from 827 BOE for the
year ended December 31, 1993 to 8,907 BOE for the year ended December 31,
1996, representing a compound annual growth rate of 121%. The Company's
production rate at December 31, 1996 was approximately 12,400 BOEPD.
Oil and gas terms used herein are defined under "-Definition of Certain Oil
and Gas Terms".
3
CORPORATE REORGANIZATION
Costilla was incorporated in Delaware in June 1996 primarily to consolidate
and continue the activities previously conducted by Costilla Energy, L.L.C.,
a Texas limited liability company (the "LLC"). Costilla was formed for the
purpose of conducting a $60 million initial public offering of common stock
and a $100 million senior notes offering (the "Offerings"), which Offerings
were completed in early October 1996.
The following is a description of sources and uses of proceeds from the
Offerings (in millions):
SOURCES:
Notes Offering . . . . . . . . . . . . . . . . . . . . . . $ 100.0
Common Stock Offering. . . . . . . . . . . . . . . . . . . 65.9 (a)
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$ 165.9
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USES:
Refinance Existing Debt. . . . . . . . . . . . . . . . . . $ 125.8
Redeem membership interests in the L.L.C. . . . . . . . . 15.5
Distributions to individual members to pay estimated
income tax liability of such members in the L.L.C. . . . 3.4
Pro rata distribution to remaining member in the L.L.C.. . 0.8
Purchase of stock and assets of affiliated companies . . . 0.7
Working capital. . . . . . . . . . . . . . . . . . . . . . 10.7
Estimated fees, commissions, underwriting discounts and
expenses related to the Offerings . . . . . . . . . . . . 9.0
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$ 165.9
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(a) Includes 475,000 shares of the underwriter's over-allotment exercised
subsequent to the closing of the common stock offering.
The Company's executive offices are located at 400 West Illinois, Suite 1000,
Midland, Texas, 79701 (mailing address P.O. Box 10369, Midland, Texas 79702)
and its telephone number is (915) 683-3092.
BUSINESS STRATEGY
The Company's strategy is to increase its oil and gas reserves, production
and cash flow from operations through a two-pronged approach which combines
an active exploration program using 3-D seismic and other technological
advances with the acquisition and exploitation of producing properties. The
Company seeks to reduce its operating and commodity risks by holding a
geographically diverse portfolio of properties, the reserves attributable to
which are approximately balanced between oil and gas. The Company also seeks
to manage the elements of its business strategy through the operation of a
significant portion of its properties, the use of a rate of return analysis
and the direct marketing and hedging of its oil and gas production. The
elements of the Company's strategy may be further described as follows:
- EXPLORATION EFFORTS. The Company uses extensive geological
and geophysical analysis to carefully focus its 3-D seismic surveys.
This focus allows the Company to successfully direct the size and
scope of its exploration program in order to improve the likelihood
of success while managing overall exploration costs. The Company's
exploration efforts are concentrated currently in known producing
regions. The Company's 1997 capital budget for exploration activities
is $7.2 million, which includes the drilling of 26 exploratory wells.
In addition, Costilla has $5.2 million budgeted for the acquisition
of undeveloped acreage and seismic projects.
4
- EXPLOITATION ACTIVITIES. The Company is actively pursuing
numerous exploitation opportunities within its existing properties,
including areas where no proved reserves are currently assigned.
Exploitation activities currently in progress include the drilling
of development wells, recompletions, workovers, infill and horizontal
drilling, a secondary recovery project and a carbon dioxide flood.
The Company's 1997 capital budget for such activities is $13.6 million,
which includes the drilling of 36 development wells.
- PROPERTY ACQUISITIONS. The Company seeks to acquire producing
properties where it has identified opportunities to increase
production and reserves through both exploitation and exploration
activities. The Company has increased the value of its acquisitions
by aggressively managing the operations of existing proved properties
and by successfully identifying and developing previously unproved
reserves on acquired acreage. The Company seeks to acquire reserves
which will fit its existing portfolio, are generally not being actively
marketed and where a negotiated sale would be the method of purchase.
The Company does not rely on major oil company divestitures or property
auctions.
- PROPERTY DIVERSIFICATION. The Company holds a portfolio of oil and
gas properties located in the Permian Basin, the Gulf Coast and the
Rocky Mountain regions. The Company believes that by conducting its
activities in distinct regions it is able to reduce commodity price
and other operational risks. The Company's Moldovan interest is an
extension of this strategy and can be characterized by low initial
costs, additional reserve potential and the availability of technical
data that may be further developed by the Company.
- CONTROL OF OPERATIONS. The Company prefers to operate and own
the majority working interest in its properties. This allows the
Company greater control over future development, drilling, completing
and operating costs and marketing of production. At January 1, 1997,
the Company operated wells constituting approximately 74% of its
total PV-10 Value.
SIGNIFICANT ACQUISITIONS
1995 ACQUISITION. In a $46.6 million acquisition completed in June 1995, the
Company acquired a group of oil and gas properties located in the Permian
Basin, Gulf Coast and Rocky Mountain regions. At the date of acquisition,
the net proved reserves included 7.1 Mmbbls of oil and 44.1 Bcf of gas,
aggregating 14.4 MMBOE. From the date of acquisition until December 31,
1996, the Company produced 2.8 MMBOE from the acquired properties and sold a
portion of the acquired properties for approximately $3.6 million. At
January 1, 1997, the net proved reserves of the remaining properties were
13.9 MMBOE. The acquired properties also included 103,010 gross (93,787 net)
undeveloped acres.
1996 ACQUISITION. In June 1996, the Company acquired a group of oil and gas
properties located primarily in the Permian Basin and Gulf Coast regions for
an adjusted purchase price of approximately $38.7 million. This acquisition
included properties with net proved reserves at April 1, 1996 of 5.0 Mmbbls
of oil and 33.5 Bcf of gas, aggregating 10.6 MMBOE. The acquired properties
also included 42,855 gross (16,646 net) undeveloped acres and a pipeline
located in Pennsylvania, which was sold on December 31, 1996 for $3.3 million.
RECENT DEVELOPMENTS
On December 31, 1996, the Company closed the sale of all of the capital stock
of a wholly owned subsidiary, which owned a 120 mile gas transportation
pipeline in southwestern Pennsylvania, for net proceeds of $3.3 million. The
pipeline was acquired through the 1996 Acquisition, was regarded as a
non-strategic asset to the Company's business and had been held for resale.
On December 31, 1996 the Company also closed the sale of substantially all of
the assets of another wholly owned subsidiary, for net proceeds of
approximately $3.0 million. The remaining assets of the subsidiary are held
by the Company.
5
In 1996, the Company purchased a 40.5% membership interest in Republic Gas
Partners, L.L.C., a Delaware limited liability company ("Republic"), for
approximately $1,020,000. Republic owns and operates gas pipelines and
associated facilities in Louisiana.In March 1997, the Company sold its
investment in Republic for an amount equal to its original cost, plus
interest from the date of purchase.
COMPETITION AND MARKETS
Competition in all areas of the Company's operations is intense. Major and
independent oil and gas companies and oil and gas syndicates actively bid for
desirable oil and gas properties, as well as for the equipment and labor
required to operate and develop such properties. A number of the Company's
competitors have financial resources and acquisition, exploration and
development budgets that are substantially greater than those of the Company,
which may adversely affect the Company's ability to compete with these
companies. Many of the Company's competitors have been engaged in the energy
business for a much longer time than the Company. Such companies may be able
to pay more for productive oil and gas properties and exploratory prospects
and to define, evaluate, bid for and purchase a greater number of properties
and prospects than the Company's financial or human resources permit. The
Company's ability to acquire additional properties and to discover reserves
in the future will be dependent on its ability to evaluate and select
suitable properties and to consummate transactions in a highly competitive
environment.
The market for oil, gas and natural gas liquids produced by the Company
depends on factors beyond its control, including domestic and foreign
political conditions, the overall level of supply of and demand for oil, gas
and natural gas liquids, the price of imports of oil and gas, weather
conditions, the price and availability of alternative fuels, the proximity
and capacity of gas pipelines and other transportation facilities and overall
economic conditions. The oil and gas industry as a whole also competes with
other industries in supplying the energy and fuel requirements of industrial,
commercial and individual consumers.
REGULATION
The Company's oil and gas exploration, production and related operations are
subject to extensive rules and regulations promulgated by federal, state and
local agencies. Failure to comply with such rules and regulations can result
in substantial penalties. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and affects its
profitability. Because such rules and regulations are frequently amended or
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such laws.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from oil and gas wells and
the regulation of spacing, plugging and abandonment of such wells. The
statutes and regulations of certain states limit the rate at which oil and
gas can be produced from the Company's properties.
The Federal Energy Regulatory Commission ("FERC") regulates interstate
natural gas transportation rates and service conditions. Such regulation
affects the marketing of gas produced by the Company and the revenues
received by the Company for sales of such production. Since the mid-1980s,
FERC Orders have fundamentally restructured interstate pipeline sales and
transportation services, including the unbundling by interstate pipelines of
the sales, transportation, storage and other components of the city-gate
sales services such pipelines previously performed. These regulatory measures
may ultimately enhance the Company's ability to market and transport its gas,
although it may also subject the Company to greater competition, more
restrictive pipeline imbalance tolerances and greater penalties if those
tolerances are violated.
The FERC has recently announced several important transportation-related
policy statements and proposed rule changes, including policy statements on
how interstate natural gas pipelines can recover the cost of new pipeline
facilities and policy statements on alternatives to its traditional
cost-of-service ratemaking methodology (including criteria to be used in
evaluating proposals to charge market-based rates for the transportation of
natural gas). In addition, the FERC is reconsidering its regulations regarding
releases of firm interstate natural gas pipeline capacity. While the Company
cannot predict exactly how FERC actions might impact the Company's natural
gas sales, it
6
does not believe it will be treated materially differently than other natural
gas producers and marketers with which it completes.
ENVIRONMENTAL MATTERS
Operations of the Company are subject to numerous and constantly changing
federal, state and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition of certain
permits, restrict or prohibit the types, quantities and concentration of
substances that can be released into the environment in connection with
drilling and production, restrict or prohibit drilling activities that could
impact wetlands, endangered or threatened species or other protected natural
resources and impose substantial liabilities for pollution resulting form the
Company's operations. Such laws and regulations may substantially increase the
cost of exploring for, developing or producingoil and gas and may prevent or
delay the commencement or continuation of a given project. In the opinion of
the Company's management, the Company is in substantial compliance with
current applicable environmental laws and regulations, and the cost of
compliance with such laws and regulations has not been material and is not
expected to be material during the next fiscal year. Nevertheless, changes in
existing environmental laws and regulations or in interpretations thereof
could have a significant impact on the operating costs of the Company, as
well as the oil and gas industry in general. For instance, legislation has
been proposed in congress from time to time that would reclassify certain oil
and gas production wastes as "hazardous wastes," which reclassification would
make exploration and production wastes subject to much more stringent
handling, disposal and clean-up requirements. State initiatives to further
regulate the disposal of oil and gas wastes and naturally occurring
radioactive materials are also pending in certain states, including Texas,
and these various initiatives could have a similar impact on the Company.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also know as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes
of persons that are considered to have contributed to the release of a
"hazardous substance" into the environment. These persons include the owner or
operator of the disposal site or the site where the release occurred and
companies that disposed or arranged for the disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances found at the site and persons who are or were
responsible for releases of hazardous substances under CERCLA may be subject
to joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment and for damages to
natural resources, and it is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the
environment. The Company is able to control directly the operation of only
those wells with respect to which its acts as operator. Notwithstanding the
Company's lack of control over wells operated by others, the failure of the
operator to comply with applicable environmental regulations may, in certain
circumstances, be attributed to the Company. The Company has no material
commitments for capital expenditures to comply with existing environmental
requirements.
EMPLOYEES
At December 31, 1996, the Company had 114 full time employees. None of the
Company's employees is subject to a collective bargaining agreement. The
Company considers its relations with its employees to be good.
7
DEFINITION OF CERTAIN OIL AND GAS TERMS
The terms defined in this section are used throughout this Form 10-K.
ALL-IN FINDING COSTS. The amount of total capital expenditures, including
acquisition costs, and exploration and abandonment costs for oil and gas
activities, divided by the amount of proved reserves (expressed in BOE) added
during the specified period (including the effect on proved reserves of
reserve revisions).
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.
BOE. Equivalent barrels of oil. In reference to natural gas, natural gas
equivalents are determined using the ratio of six MCF of natural gas to one
Bbl of crude oil, condensate or natural gas liquids.
BTU. One British thermal unit. The quantity of heat required to raise the
temperature of one pound of water one degree Fahrenheit.
DEVELOPED ACREAGE. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon know to be productive.
DRY WELL. A well found to be incapable of producing either oil or gas in
sufficient quantifies to justify completion of an oil or gas well.
EXPLORATORY WELL. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be, in
which a working interest is owned.
MBBL. One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
MMBOE. One million barrels of oil equivalent.
MMBBLS. One million barrels of crude oil or other liquid hydrocarbons.
MMBTU. One million Btu's.
MCF. One thousand cubic feet.
MMCF. One million cubic feet.
NET ACRES OR NET WELLS. The sum of the fractional working interests owned in
gross acres or gross wells.
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES OR PV-10 VALUE. The present
value of estimated future net revenues is an estimate of future net revenues
from a property at its acquisition date, at a specified date, 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
revenue stream and
8
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 the specified date.
PRODUCTIVE WELL. A well that is producing oil or gas that is capable of
production.
PROVED DEVELOPED RESERVES. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED UNDEVELOPED RESERVES. Reserves that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.
ROYALTY INTEREST. An interest in an oil and gas property entitling the owner
to a share of oil and gas production free of costs of production.
3-D SEISMIC. Advanced technology method of detecting accumulations of
hydrocarbons identified by the collection and measurement of the intensity
and timing of sound waves transmitted into the earth as they reflect back to
the surface.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of oil and gas regardless of whether such acreage contains proved
reserves.
WORKING INTEREST. The cost bearing operating interest which gives the owner
the right to drill, produce and conduct operating activities on the property
and a share of production.
9
ITEM 2. PROPERTIES.
PRINCIPAL PROPERTIES
The following table sets forth certain information, as of January 1, 1997,
which relates to the principal oil and gas properties owned by the Company.
PROVED RESERVES
---------------------------------------------------
TOTAL OIL PERCENT OF
GROSS OIL GAS EQUIVALENT TOTAL OIL
WELLS (MBBLS) (MMCF) (MBOE) EQUIVALENT
----- ------ ------- ---------- ----------
REGION
- ------
Permian Basin. . . . . . . 2,001 9,889 59,512 19,808 53.5%
Gulf Coast . . . . . . . . 932 2,189 37,149 8,381 22.6
Rocky Mountain . . . . . . 249 4,124 5,742 5,081 13.7
Other. . . . . . . . . . . 433 798 17,869 3,776 10.2
----- ------ ------- ------ ------
Total. . . . . . . . . . . 3,615 17,000 120,272 37,045 100.00%
----- ------ ------- ------ ------
----- ------ ------- ------ ------
PERMIAN BASIN. At January 1, 1997, 53.5% of the Company's proved reserves
were concentrated in the Permian Basin, an approximately 70-county region in
West Texas and Southeast New Mexico. The Company's production comes from
well known formations such as the Spraberry, Canyon, Ellenberger and
Devonian. The majority of the Company's producing intervals in the Permian
Basin range from 4,500 feet to 9,500 feet in depth.
The Company has several exploratory projects in the Permian Basin based
primarily on 3-D seismic surveys. The most significant include:
EDWARDS/MCELROY RANCH PROSPECT, ECTOR AND CRANE COUNTIES, TEXAS. Costilla has
identified 81 drilling locations on the Company's 14,623 gross (7,165 net)
acres in this prospect based on an approximate 80-square mile 3-D seismic
project. Through December 31, 1996, the Company drilled 15 wells on this
prospect, of which 14 were successful resulting in three separate field
discoveries. In addition, these wells have confirmed the Strawn and Wolfcamp
trends which were identified by the seismic project undertaken jointly with
Texaco Exploration and Production Inc. ("Texaco"). The Company plans to
drill 20 wells in this trend in 1997, two of which were in progress at
December 31, 1996. The Company's working interest in this prospect is
approximately 49%.
Costilla and Texaco are also evaluating the development of a Queen Sand field
identified from the Edwards/McElroy Ranch seismic program. The six producing
wells at December 31, 1996 were producing an aggregate of approximately 50
Bbls of oil per day. A pilot waterflood has been commenced and is being
evaluated for additional development. The drilling of one additional Queen
Sand well is anticipated in 1997.
MACGYVER-GREEN ACRES PROSPECT, HOWARD COUNTY, TEXAS. The Company has
identified 53 locations in this prospect based on information derived from
approximately 30 square miles of 3-D seismic data that the Company acquired
on the area in 1994. The Talbot Fuller well was the first well drilled by
the Company on this prospect and was completed in the Canyon Lime formation
at 8,600 feet in August 1994. From completion to December 31, 1996, the well
produced 72 MBbls of oil and 287 Mmcf of gas, and averaged 54 Bbls of oil per
day and 625 Mcf of gas per day during December 1996. Of the 24 wells which
have been drilled on this prospect, 20 are productive. The
10
Company intends to drill 20 additional wells during 1997 on its 10,041 gross
(7,229 net) acres. The Company's working interest in this prospect averages
approximately 72%.
The following two 3-D programs currently being undertaken by the Company in
the Permian Basin are expected to provide additional drilling locations:
WILSON RANCH 3-D PROJECT, PECOS COUNTY, TEXAS. The Wilson Ranch is located
in northeastern Pecos County, approximately 10 miles west of the Yates field.
In 1996 the Company completed an approximate 17-square mile seismic survey
on the project. The project presents several potential exploration targets,
including the Queen, San Andres, Wolfcamp, Devonian and Ellenberger
formations, found at depths ranging from 1,600 to 8,000 feet. The Company
has purchased a lease covering 3,750 gross acres on this 50,000 acre ranch.
After acquiring the lease, the Company sold a portion of its interest in the
lease to a major oil company, which left the Company with an approximately
53% working interest. The Company believes that there is significant
potential in this area.
DAVAN UNIT 3-D PROJECT, STONEWALL COUNTY, TEXAS. The Company has completed
another 3-D seismic project to further develop the Company-operated Davan
Unit. The project involves a 3-D seismic evaluation of approximately 4,380
gross acres adjacent to a Company-operated waterflood which has produced in
excess of three Mmbbls of oil. The Company plans to drill four wells on this
project during 1997. The Company's working interest in this project is 100%.
An example of the Company's current exploitation efforts in the Permian Basin
is:
WORLD FIELD, CROCKETT COUNTY, TEXAS. This field was acquired in the 1996
Acquisition. It produces from the Grayburg formation at an average depth of
2550 feet. Discovered in 1926, it is one of the oldest and most prolific
shallow fields in the Permian Basin. Costilla owns a 100% working interest in
4,380 acres containing 87 existing wells. At the time of acquisition, the
field was producing approximately 480 Bbls of oil per day and 53,400 Bbls of
water per day. In December, 1996 the Company initiated a polymer treatment
program to reduce water production and increase oil cut. Thirteen treatments
have been completed as of February 1997 resulting in oil production improving
to approximately 650 Bbls of oil per day and water production dropping to
approximately 43,500 Bbls of water per day. Additionally, some submersible
pumps have been replaced by progressing cavity pumps which are expected to be
significantly less costly to operate. A fieldwide study is underway to
identify additional workover candidates as well as additional locations for
development drilling.
GULF COAST. At January 1, 1997, 22.6% of the Company's proved reserves were
concentrated in the Gulf Coast region, on shore. The Company's production in
this region primarily comes from known formations such as Frio, Yegua, Austin
Chalk and Wilcox.
The Company plans to use its expertise in aggressively developing 3-D
opportunities on the extensive acreage position it holds in the region.
Examples of such exploration projects in progress include:
SEALY PROSPECT, AUSTIN COUNTY, TEXAS. The Sealy Field was acquired in the
1995 Acquisition and currently consists of 10,982 gross and net acres. The
Wilcox formation in this field has produced over 66 Bcf of gas and there are
subsurface indications of the presence of several fault blocks that lie
untested. The Company's working interest in this prospect is 100%. The
Company has acquired additional acreage in this prospect and plans to
initiate a 3-D survey in 1997.
SOUTHWEST SPEAKS, LAVACA COUNTY, TEXAS. This project was also acquired in
the 1995 Acquisition and currently consists of 9,062 gross and net acres.
Multiple producing horizons from shallow depths to below 14,000 feet have
produced over 122 Bcf of gas from this highly faulted field. A well has been
completed in the Rainbow Wilcox sand on acreage adjoining Costilla's lease.
A well, in which Costilla holds a 10% interest as a result of a farmout, is
11
being completed on Costilla's lease. The Company has commenced a 3-D survey
in the Speaks area in the first quarter of 1997. The Company's working
interest in this prospect is 100%.
BORCHERS FIELD, LAVACA COUNTY, TEXAS. This field was acquired by the Company
in the 1996 Acquisition. The property is on trend with the Speaks project
and is also a highly faulted field providing opportunity for further
development. The Company's lease in the Borchers field area has produced
over 21 Bcf of gas from two Wilcox sands. Costilla has a 100% working
interest in this field consisting of 1,322 gross and net acres.
Examples of exploitation activities in this region include:
PERSONVILLE, LIMESTONE COUNTY, TEXAS. When this lease was acquired in the
1995 Acquisition, it was producing 70 Mcf per day from one well. In the last
half of 1996, the Company completed two 11,000 foot Cotton Valley wells which
were collectively producing approximately 4.5 Mmcf per day in December 1996.
A third well was completed in January 1997. The Company plans 14 additional
wells in this area. The Company is the operator and owns approximately 29%
working interest in this 1,026 gross acre (298 net acre) lease.
AUSTIN CHALK, BRAZOS, BURLESON, FAYETTE AND LEE COUNTIES, TEXAS. Costilla
acquired the majority of the working interest in nine gross Austin Chalk
wells in the 1995 Acquisition and an additional 80 gross Austin Chalk wells
were included in the 1996 Acquisition. By mid-December 1996 the Company had
worked over six wells via refracing and/or opening additional pay zones.
Production has improved from 137 BOE per day to 325 BOE per day on those
wells. Additional increases in production are expected as frac loads are
recovered. Completion of the first two of seven planned horizontal wells in
the Austin Chalk are the Patterson "G" 1-H, producing 326 barrels of oil and
727,000 cubic feet of gas per day, and Mais-Kachtik 1-H, producing 364
barrels of oil and 952,000 cubic feet of gas per day. Costilla has 30,414
gross (20,985 net) acres in the Austin Chalk area, and its working interest
in this area averages approximately 69%.
ROCKY MOUNTAIN. At January 1, 1997, 13.7% of the Company's proved reserves
were concentrated in the Rocky Mountain region, which includes Montana, North
Dakota, Wyoming, Colorado and Utah.
The Company has a number of opportunities in the Rocky Mountain region
involving 3-D seismic surveys, exploratory drilling and exploitation
activities. Examples of each of these opportunities are:
OUTLOOK FIELD, SHERIDAN COUNTY, MONTANA. The Company undertook its first
Rocky Mountain 3-D seismic survey in the Outlook area to further develop the
field. Three drilling locations were identified from the data of which the
first well has been drilled and completed as a producer. Additional
development is anticipated. Costilla has 5,169 gross (1,292 net) acres in
the Outlook prospect, and its working interest is approximately 25%.
WATTENBERG FIELD, WELD COUNTY, COLORADO. The Company operates 70 wells in
the Wattenberg Field of the DJ Basin in northeast Colorado. During January,
1997 the Company initiated an 11 well development program of which 7 wells
have been completed at March 20, 1997, with initial producing rates averaging
55 BOEPD per well. An estimated 20 additional locations are drillable. The
Company owns an approximate 72% average working interest in 6,255 gross
(4,479 net) acres.
MARKETING ARRANGEMENTS
The Company utilizes an active marketing program for a portion of its crude
oil production in order to enhance the net price it receives. The Company
sells its crude oil production from operated properties in North Dakota,
Montana and Wyoming, at the lease level to an oil transportation company for
the posted price, plus an agreed upon bonus, with a corresponding agreement
to repurchase this production at its delivery point (typically, Cushing,
Oklahoma) for a price equal to the then posted price for West Texas
Intermediate crude oil less an agreed upon deduction for transportation and
quality differentials, if any between the repurchased crude oil and West
Texas
12
Intermediate crude oil. The Company then employs a broker to resell its
crude oil to end users (such as refineries) on a month-to-month basis. The
lease level sales and repurchase contracts are typically of six months
durations. With respect to its other operated oil production (primarily
located in Texas), the Company employs a similar price enhancement strategy,
although the repurchase feature is absent. Instead, the lease level purchaser
resells the crude oil to end users at the delivery point for the account of
the Company. While these arrangements have the effect of increasing the net
price the Company receives for its crude oil, such arrangements do not have
the effect of limiting the Company's exposure to movements in crude oil
prices. The Company markets its gas production at the lease level pursuant to
month-to-month contracts. For the year ended December 31, 1996, one oil
purchaser accounted for 11.2% of the Company's 1996 consolidated revenue.
The Company does not anticipate any difficulty if it should have to replace
any of the purchasers of its crude oil and natural gas.
RISK MANAGEMENT
The Company typically employs a strategy of purchasing put options on a
portion of its anticipated oil and gas production. This strategy is designed
to protect the Company from significant downward movements in commodity
prices while preserving the benefit of rising prices. The Company does not
establish hedges in excess of its anticipated production. The Company's
current position with regard to its 1997 commodity hedges is as follows:
OIL SALES. As of December 31, 1996, the Company had purchased put options on
6,536 barrels of oil per day for the calendar months June 1997 through
October 1997 providing a floor price of $17.00 per barrel. Additionally, the
Company had purchased put options on 2,500 Bbls of oil per day for 1997 which
provide a floor price of $16.00 per barrel and sold call options on 2,500
barrels of oil per day for 1997 at $20.65 per barrel. These put options
provide downside protection on approximately 70% of the Company's estimated
1997 oil production.
GAS SALES. As of December 31, 1996, the Company had put options which
provide a floor price of $1.65 per Mmbtu (approximately $1.82 per Mcf) for
150,000 Mmbtu's per month of its gas production through October 1997. In
February 1997, the Company purchased put options which establish a floor
price of $1.85 per Mmbtu (approximately $2.04 per Mcf) for 300,000 Mmbtu's
per month of its gas production for the period April 1997 through October
1997. The put options currently in place represent approximately 25% of the
Company's estimated gas production for 1997.
13
OIL AND GAS RESERVES
The Company's estimated total proved and proved developed reserves of oil and
gas as of January 1, 1997 were as follows:
JANUARY 1, 1997
--------------------------
OIL GAS
(MBBLS) (MMCF) MBOE
------- ------- ------
Proved developed producing . . . . 13,894 82,861 27,704
Proved developed non-
producing. . . . . . . . . . . . 124 7,162 1,318
Proved undeveloped . . . . . . . . 2,982 30,249 8,023
------ ------- ------
Total proved . . . . . . . . . . 17,000 120,272 37,045
------ ------- ------
------ ------- ------
The future net cash flows from the Company's estimated proved reserves as of
January 1, 1997 were as follows:
JANUARY 1, 1997
---------------
(in thousands)
Future net cash flows before
income taxes . . . . . . . . . . . . . . . . . . $538,343
Future net cash flows before
income taxes, discounted
at 10% . . . . . . . . . . . . . . . . . . . . . $311,803
The reserve estimates at January 1, 1997 were prepared by Williamson
Petroleum Consultants, Inc.
The reserve data set forth herein present estimates only. In general,
estimates of economically recoverable oil and gas reserves and of the future
net revenues therefrom are based upon an number of variable factors and
assumptions, such as historical production from the subject properties, the
assumed effects of regulation by governmental agencies and assumptions
concerning future oil and gas prices and future operating costs, all of which
may vary considerably from actual results. All such estimates are to some
degree speculative, and classifications of reserves are only attempts to
define the degree of speculation involved. For these reasons, estimates of
the economically recoverable oil and gas reserves attributable to any
particular group of properties, classifications of such reserves based on
risk of recovery and estimates of the future net revenues expected therefrom,
prepared by different engineers or by the same engineers at different times
may vary substantially. The Company therefore emphasizes that the actual
production, revenues, severance and excise taxes, development and operating
expenditures with respect to its reserves will likely vary from such
estimates, and such variances could be material.
Estimates with respect to proved reserves that may be developed and produced
in the future are often based upon volumetric calculations and upon analogy
to similar types of reserves rather than actual production history.
Estimates based on these methods are generally less reliable than those based
on actual production history. Subsequent evaluation of the same reserves
based upon production history will result in variations, which may be
substantial, in the estimated reserves.
In accordance with applicable requirements of the Securities and Exchange
Commission (the "Commission"), the estimated discounted future net revenues
from estimated proved reserves are based on prices and costs as of the date
of the estimate unless such prices or costs are contractually determined at
such date. Actual future prices and costs may be materially higher or lower.
Actual future net revenues also will be affected by factors such as actual
production, supply and demand for oil and natural gas, curtailments or
increases in consumption by natural gas purchasers, changes in governmental
regulations or taxation and the impact of inflation on costs.
14
PRODUCTION VOLUMES, PRICES AND COSTS
The following table sets forth certain information regarding the Company's
production volumes, average sales price and costs for the periods presented:
YEAR ENDED DECEMBER 31,
--------------------------
1996 1995 1994
------ ------ ------
Production:
Oil (MBbls). . . . . . . . . . . . . 1,726 950 330
Gas (Mmcf) . . . . . . . . . . . . . 9,205 4,806 1,600
MBOE . . . . . . . . . . . . . . . . 3,260 1,751 597
Average Sales Price:
Oil (per Bbl). . . . . . . . . . . . $19.87 $15.53 $15.25
Gas (per Mcf). . . . . . . . . . . . 2.13 1.45 1.63
Costs Per BOE:
Production costs, including
severance taxes (1). . . . . . . . $ 6.68 $ 5.91 $ 3.94
Depreciation, depletion and
amortization . . . . . . . . . . . 3.81 3.40 3.09
- ---------------------
(1) Production costs per BOE in 1996 and 1995 were unusually high as a result
of relatively high workover expenses with respect to properties acquired
in the 1995 Acquisition and the 1996 Acquisition which did not produce
related production improvements until subsequent periods. Additionally,
the Company's 1995 production costs were adversely affected by expenses
incurred in connection with plugging wells to comply with applicable
regulatory requirements.
EXPLORATION AND DEVELOPMENT ACTIVITIES
The Company drilled, or participated in the drilling of, the following number
of wells during the periods indicated. At December 31, 1996, the Company was
in the process of drilling 7 gross (4.33 net) wells and was in the process of
completing 8 gross (4.04 net) wells as producers which are not reflected in
the following table.
1996 1995 1994
------------- ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- ----
Exploratory:
Productive. . . . . 13 8.88 10 4.58 9 2.27
Dry . . . . . . . . 2 2.00 6 2.57 10 3.73
----- ----- ----- ----- ----- ----
Total . . . . . . 15 10.88 16 7.15 19 6.00
----- ----- ----- ----- ----- ----
----- ----- ----- ----- ----- ----
Development:
Productive. . . . . 16 9.93 1 0.44 - -
Dry . . . . . . . . 5 3.20 - - - -
----- ----- ----- ----- ----- ----
Total . . . . . . 21 13.13 1 0.44 - -
----- ----- ----- ----- ----- ----
----- ----- ----- ----- ----- ----
Total:
Productive. . . . . 29 18.81 11 5.02 9 2.27
Dry . . . . . . . . 7 5.20 6 2.57 10 3.73
----- ----- ----- ----- ----- ----
Total . . . . . . 36 24.01 17 7.59 19 6.00
----- ----- ----- ----- ----- ----
----- ----- ----- ----- ----- ----
15
The Company does not own any drilling rigs and all of its drilling activities
are conducted by independent contractors under standard drilling contracts.
PRODUCTIVE WELL SUMMARY
The following table sets forth the Company's gross and net interests in
productive oil and gas wells as of December 31, 1996. Productive wells are
producing wells and wells capable of production.
ACTUAL (1)
-------------
GROSS NET
----- ---
Oil Wells . . . . . . . . . . . . . . . . . . . . . 2,323 708
Gas Wells . . . . . . . . . . . . . . . . . . . . . 1,292 238
----- ---
Total . . . . . . . . . . . . . . . . . . . . . . 3,615 946
----- ---
----- ---
- ----------------
(1) One well with multiple completions is counted as a single well.
ACREAGE
The following table sets forth certain information regarding the Company's
developed and undeveloped leasehold acreage as of December 31, 1996. Acreage
in which the Company's interest is limited to royalty, overriding royalty,
mineral and similar interests is excluded.
DEVELOPED UNDEVELOPED TOTAL
----------------- ----------------- -----------------
REGION GROSS NET GROSS NET GROSS NET
------ ------- ------- ------- ------- ------- -------
Permian Basin. . . . . . 220,859 48,038 124,781 72,373 345,640 120,411
Gulf Coast . . . . . . . 138,569 57,595 41,123 34,962 179,692 92,557
Rocky Mountain . . . . . 19,652 6,603 30,091 14,209 49,743 20,812
Other. . . . . . . . . . 57,079 14,585 46,546 26,198 103,625 40,783
------- ------- ------- ------- ------- -------
Total. . . . . . . . . . 436,159 126,821 242,541 147,742 678,700 274,563
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------
OTHER ACTIVITIES
MOLDOVA CONCESSION AGREEMENT. In July 1995, the Republic of Moldova (located
in Eastern Europe between Romania and the Ukraine) granted a Concession
Agreement to Resource Development Company Limited, L.L.C. ("Redeco"), an
entity not affiliated with the Company. The Company has paid Redeco $90,000
and agreed to bear the first $2.0 million of Concession expenses in return
for a 50% interest in Redeco. After the initial $2.0 million expenditure,
which was incurred in August 1996, the Company and the other member of Redeco
are responsible for bearing 50.0% each of future expenses. To date, three
wells, drilled by the government in the 1960s, have been reentered and two
new wells have been completed by the Company in Moldova. The Company
continues to evaluate the Concession for further development.
TITLE TO PROPERTIES
The Company has obtained title opinions on substantially all of its producing
properties and believes that it has satisfactory title to such properties in
accordance with standards generally accepted in the oil and gas industry. As
is
16
customary in the oil and gas industry, the Company performs a minimal title
investigation before acquiring undeveloped properties. A title opinion is
obtained prior to the commencement of drilling operations on such properties.
The Company's properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and other burdens
which the Company believes do not materially interfere with the use of or
affect the value of such properties.
OPERATIONAL HAZARDS AND INSURANCE
The Company's operations are subject to the hazards and risks inherent in
drilling and production and transportation of oil and gas, including fires,
natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, cratering, pipeline ruptures, and spills, any of which
can result in loss of hydrocarbons, environmental pollution, personal injury
or loss of life, severe damage to and destruction of properties of the
Company and others, and suspension of operations.
The Company maintains insurance of various types to cover its operations,
including liability coverage and operator's extra expense coverage which
provides for care, custody and control of all material wells drilled by the
Company as operator. The Company believes that its insurance is adequate and
customary for companies of a similar size engaged in operations similar to
those of the Company, but losses could occur for uninsurable or uninsured
risks or in amounts in excess of existing insurance coverage. The Company's
general policy is to only engage drilling contractors who provide substantial
insurance coverage and name the Company as an additional named insured. The
occurrence of a significant adverse event, the risks of which are not fully
covered by insurance, could have a material adverse effect on the Company's
financial condition and results of operations. Moreover, no assurances can be
given that the Company will be able to maintain adequate insurance in the
future at rates it considers reasonable.
17
ITEM 3. LEGAL PROCEEDINGS.
Special Note: Certain statements set forth below under this caption
constitute "forward-looking statements" within the meaning of the Reform Act.
See "Special Note Regarding Forward-Looking Statements" for additional
factors relating to such statements.
The Company is a defendant or codefendant in minor lawsuits that have arisen
in the ordinary course of business. While the outcome of these lawsuits
cannot be predicted with certainty, management does not expect any of these
to have a material adverse effect on the Company's consolidated financial
condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to a vote of the Company's stockholders during the
fourth quarter of the year ended December 31, 1996.
18
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Company completed its initial public offering of Common Stock on October
2, 1996. On October 3, 1996 the Common Stock commenced trading on the Nasdaq
Stock Market's National Market (the "Nasdaq National Market") under the
trading symbol "COSE". The following table sets forth the high and low
closing price for the period presented:
1996 HIGH LOW
------ ------
Fourth Quarter (October 3 inception of trading)........ $13.63 $11.75
The Company had approximately 1300 record and beneficial holders of its Common
Stock at December 31, 1996.
The Company has never declared or paid any cash dividends on its Common Stock.
The Company's Board of Directors does not anticipate paying any cash
dividends in the foreseeable future, as it intends to retain cash to finance
the growth of the Company's business. In addition, the payment of any
dividends is prohibited by the terms of the Company's Credit Facility with its
secured lenders. The payment of any cash dividends on the Common Stock in the
future will depend on such factors as the earnings, anticipated capital
requirements, and operating and financial condition of the Company and any
other factors deemed relevant by the Board of Directors.
19
ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth selected financial data of Costilla Energy,
Inc. and Predecessor. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations." The historical information should be
read in conjunction with the Consolidated Financial Statements and the Notes
thereto included elsewhere herein. Costilla Energy, Inc. and Predecessor
acquired significant producing oil and gas properties in certain of the
periods presented which affect the comparability of the historical financial
and operating information. The historical results are not necessarily
indicative of the Company's future operations or financial results.
YEAR ENDED DECEMBER 31,
---------------------------------------------------
1996 1995 1994 1993 1992
-------- -------- -------- ------- -------
STATEMENT OF OPERATIONS DATA:
Operating revenues............................. $ 53,919 $ 21,693 $ 7,637 $ 4,231 $ 2,362
Total revenues................................. 55,026 21,816 7,836 4,397 2,887
Expenses:
Oil and gas production....................... 21,774 10,355 2,351 1,688 1,340
General and administrative................... 5,238 3,571 1,184 952 388
Compensation related to option settlement.... - 656 - - -
Exploration and abandonments................. 2,550 1,650 793 218 4
Depreciation, depletion and amortization..... 12,430 5,958 1,847 884 404
Interest..................................... 11,281 4,591 1,458 605 365
Other........................................ - 2 - - -
-------- -------- -------- ------- -------
Income (loss) before income taxes and
extraordinary item........................... 1,753 (4,967) 203 50 386
Net income (loss).............................. (4,440) (4,970) 163 73 368
STATEMENT OF CASH FLOWS DATA:
Net cash provided by (used in):
Operating activities......................... $ 12,350 $ 6,366 $ 1,527 $ 322 $ 140
Investing activities......................... (64,129) (62,467) (12,146) (6,731) (1,432)
Financing activities......................... 61,531 58,830 10,618 6,315 1,450
OTHER FINANCIAL DATA:
Capital expenditures........................... $ 70,017 $ 62,220 $ 11,868 $ 6,862 $ 3,720
Adjusted EBITDA (1)............................ 27,108 7,232 4,301 1,757 1,159
Adjusted EBITDA/interest expense (1)........... 2.4x 1.6x 2.9x 2.9x 3.2x
BALANCE SHEET DATA (AS OF PERIOD END):
Working capital................................ $ 10,320 $ 2,496 $ 1,081 $ 1,612 $ 185
Total assets................................... 162,790 87,367 24,904 13,290 6,675
Total debt..................................... 100,262 71,494 23,613 12,034 5,352
Redeemable predecessor capital................. - 11,576 - - -
Predecessor capital............................ - (7,445) (747) 51 434
Stockholders' Equity........................... 40,569 - - - -
_____________
(1) Adjusted EBITDA and the ratio of Adjusted EBITDA to interest expense are
presented because of their wide acceptance as financial indicators of a
company's ability to service or incur debt. Adjusted EBITDA (as used
herein) is calculated by adding interest, income taxes, depreciation,
depletion and amortization, exploration and abandonment costs and
extraordinary loss resulting from early extinguishment of debt, net of a
deferred tax benefit, to net income (loss), and excluding a nonrecurring
gain on the sale of substantially all of the assets of a subsidiary in
1996. The ratio of Adjusted EBITDA to interest expense is calculated by
dividing Adjusted EBITDA by interest. Adjusted EBITDA and the ratio of
Adjusted EBITDA to interest expense should not be considered as
alternatives to earnings (loss), or operating earnings (loss), as defined
by generally accepted accounting principles, as indicators of the
Company's financial performance or to cash flow as a measure of liquidity.
20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.
Special Note: Certain statements set forth below under this caption
constitute "forward-looking statements" within the meaning of the Reform Act.
See "Special Note Regarding Forward-Looking Statements" for additional factors
relating to such statements.
GENERAL
Costilla is an independent energy company engaged in the exploration,
acquisition and development of oil and gas properties. The Company's
predecessor began operating in 1988 and through mid-1995 had grown primarily
through a series of small acquisitions of oil and gas properties and the
exploitation of those properties. In June 1995, Costilla consummated the 1995
Acquisition for a purchase price of approximately $46.6 million, and in June
1996, the 1996 Acquisition was consummated for a purchase price of
approximately $38.7 million.
To date, the Company has achieved its high rate of growth primarily through
acquisitions. This has impacted its reported financial results in a number of
ways. Properties sold by others frequently have not received focused
attention prior to sale. After acquisition, certain of these properties are
in need of maintenance, workovers, recompletions and other remedial activity
not constituting capital expenditures, which substantially increase lease
operating expenses. The increased production and revenue resulting from these
expenditures is predominately realized in periods subsequent to the period of
expense. In addition, the rapid growth of the Company has required it to
develop operating, accounting and administrative personnel compatible with its
increased size. The Company believes it has now achieved a sufficient size to
expand its reserve base without a corresponding increase in its general and
administrative expense. The Company also believes it now has a sufficient
inventory of prospects and the professional staff necessary to follow a more
balanced program of exploration and exploitation activities to complement its
acquisition efforts.
Costilla's strategy is to increase its oil and gas reserves, production and
cash flow from operations through a two-pronged approach which combines an
active exploration program with the acquisition and exploitation of proved
reserves. In addition, Costilla continues to evaluate the acquisition of
undeveloped acreage for its exploration efforts. Costilla has in-house
exploration expertise using 3-D seismic technology to identify new drilling
opportunities as well as for the exploitation of acquired properties.
Costilla has shown a significant increase in its oil and gas reserves and
production, especially due to the 1995 Acquisition and the 1996 Acquisition.
The following table sets forth certain operating data of Costilla for the
periods presented:
YEAR ENDED DECEMBER 31,
------------------------
1996 1995 1994
---- ---- ----
OIL AND GAS PRODUCTION:
Oil (MBbls)................................. 1,726 950 330
Gas (Mmcf).................................. 9,205 4,806 1,600
MBOE........................................ 3,260 1,751 597
AVERAGE SALES PRICES (1):
Oil (per Bbl)............................... $19.87 $15.53 $15.25
Gas (per Mcf)............................... 2.13 1.45 1.63
PRODUCTION COST (2):
Per BOE (3)................................. $ 6.68 $ 5.91 $ 3.94
Per dollar of sales......................... 0.40 0.48 0.31
DEPRECIATION, DEPLETION AND AMORTIZATION:
Per BOE...................................... $ 3.81 $ 3.40 $ 3.09
Per dollar of sales.......................... 0.23 0.27 0.24
21
_____________
(1) Before deduction of production taxes and net of any hedging results.
(2) Production cost includes lease operating expenses and production and ad
valorem taxes, if applicable, and excludes depreciation, depletion and
amortization.
(3) Production costs per BOE in 1995 and 1996 were unusually high as a result
of relatively high workover expenses with respect to properties acquired
in the 1995 Acquisition and the 1996 Acquisition which did not produce
related production improvement until subsequent periods. Additionally,
the Company's 1995 production costs were adversely affected by expenses
incurred in connection with plugging wells to comply with applicable
regulatory requirements.
Costilla uses the successful efforts method of accounting for its oil and gas
activities. Costs to acquire mineral interests in oil and gas properties, to
drill and equip exploratory wells that result in proved reserves, and to drill
and equip development wells are capitalized. Costs to drill exploratory wells
that do not result in proved reserves, geological, geophysical and seismic
costs, and costs of carrying and retaining unproved properties are expensed.
Capitalized costs of producing oil and gas properties, after considering
estimated dismantlement and abandonment costs and estimated salvage values,
are depreciated and depleted using the unit-of-production method. Unproved
oil and gas properties that are individually significant are periodically
reviewed for impairment of value, and a loss is recognized at the time of
impairment by providing an impairment allowance. Other unproved properties
are amortized based on the Company's experience of successful drilling and
average holding period.
The Company utilizes option contracts to hedge the effect of price changes on
a portion of its future oil and gas production. Premiums paid and amounts
receivable under the option contracts are amortized and accrued to oil and gas
sales, respectively. If market prices of oil and gas exceed the strike price
of put options, the options will expire unexercised, therefore, reducing the
effective price received for oil and gas sales by the cost of the related
option. Conversely, if market prices of oil and gas decline below the strike
price of put options, the options will be exercised, therefore, increasing the
effective price received for oil and gas sales by the proceeds received from
the related option. The net effect of the Company's commodity hedging
activities reduced oil and gas revenues by $1,705,000, $80,000 and $9,000 for
the years ended December 31, 1996, 1995, and 1994, respectively.
The Company utilizes interest rate swap agreements to reduce the potential
impact of increases in interest rates on floating-rate, long term debt. If
market rates of interest experienced during the applicable swap term are below
the rate of interest effectively fixed by the swap agreement, the rate of
interest incurred by the Company will exceed the rate that would have been
experienced under the Credit Agreement. The net effect of the Company's
interest rate hedging activities increased interest expense in 1996 by
$442,000 prior to repayment of the Company's floating rate debt and $8,000 for
the year ended December 31, 1995. Concurrent with the payment of all of the
Company's floating rate debt from proceeds of the Offerings in the fourth
quarter of 1996, the interest rate swap agreements ceased to qualify as
hedges. These interest rate swap agreements were marked-to-market and the
related liability recorded. The liability for the two interest rate swap
agreements was $1,712,000 at December 31, 1996. The Company must mark the
agreements to market at the end of each reporting period and the net change
during the reporting period will be treated as investment gain or loss. At
March 11, 1997 the value of the agreements was an approximate $1.5 million
liability.
The Company's predecessor was classified as a partnership for federal income
tax purposes. Therefore, no income taxes were paid or provided for by the
Company prior to the Offerings. Future tax amounts, if any, will be dependent
upon several factors, including but not limited to the Company's results of
operations.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
The Company's total oil and gas revenues for the year ended December 31, 1996
were $53,919,000, representing an increase of $32,226,000 (149%) over revenues
of $21,693,000 in 1995. This increase was primarily due to the 1996
Acquisition and 1995 Acquisition, which accounted for approximately
$12,754,000 and $14,059,000 of the revenue increase, respectively. The
remainder of the increase was due to a combination of increased product
prices, successful drilling activities and the enhancement of existing
production. The average oil price per barrel received in 1996 was $19.87
compared to $15.53 in 1995, a 28% increase, and the average gas price received
in 1996 was $2.13 compared to $1.45 in 1995, a 47% increase.
22
Oil and gas production was 3,260 MBOE in 1996 compared to 1,751 MBOE in 1995,
an increase of 86%. Of the 1,509 MBOE increase, approximately 723 MBOE was
due to the properties acquired in the 1996 Acquisition and 562 MBOE was due
to the properties acquired in the 1995 Acquisition. The remainder of the
increase was due to a combination of successful drilling activities and the
enhancement of existing production.
Interest and other revenues were $40,000 for the year ended December 31, 1996
compared to $123,000 in 1995, representing a decrease of $83,000, which was
primarily comprised of $195,000 in losses on investments held for trading
purposes and an increase in interest income of $67,000 in 1996 due to
increased funds earning interest. Also in 1996, the Company realized gains of
$ 1,067,000 on various transactions for which no comparable sales were
recorded in 1995.
Oil and gas production costs in 1996 were $21,774,000 ($6.68 per BOE),
compared to $10,355,000 in 1995 ($5.91 per BOE), representing an increase of
$11,419,000 (110%), due principally to the 1996 Acquisition and to a lesser
extent the 1995 Acquisition. On a per BOE basis, production costs increased
$0.77 due primarily to higher production costs per BOE for the properties
acquired in the 1996 Acquisition.
General and administrative expenses for the year ended December 31, 1996 were
$5,238,000, representing an increase of $1,667,000 (47%) from 1995 of
$3,571,000. The increase is primarily due to an increase in personnel and
related costs necessary to accommodate the increased activities of the
Company due to the 1995 and 1996 Acquisitions. However, as noted above,
production volumes increased 86% and, therefore, general and administrative
expenses per BOE decreased to $1.61 per BOE for the year ended December 31,
1996 from the $2.04 per BOE in 1995.
Results of operations for the year ended December 31, 1995 include non-cash
compensation expense of $656,000 deemed to have been accrued to a minority
interest owner of the Company who was deemed to have benefited from the
cancellation of an option to purchase an additional interest held by the
other minority interest owner.
Exploration and abandonment expense increased to $2,550,000 in 1996 compared
to $1,650,000 in 1995. The Company incurred $913,000 of seismic costs for
the year ended December 31, 1996, compared to $790,000 which were incurred in
1995. Dry hole and abandonment costs increased to $1,524,000 in 1996 from
$860,000 in 1995.
Depreciation, depletion and amortization expense for 1996 was $12,430,000
compared to $5,958,000 for 1995, representing an increase of $6,472,000
(109%). During 1996, depreciation, depletion and amortization on oil and gas
production was provided at an average rate of $3.81 per BOE compared to $3.40
per BOE for 1995. The increases were due primarily to the 1996 and 1995
Acquisitions.
Interest expense was $11,281,000 in 1996, compared to $4,591,000 in 1995.
The $6,690,000 (146%) increase was attributable primarily to increased levels
of debt which the Company used to finance the 1996 Acquisition. The average
amounts of applicable interest-bearing debt in 1996 and 1995 were $95,671,000
and $49,972,000, respectively. The effective annualized interest rate in
1996 was 11.8%, as compared to 9.2% in 1995.
Results of operations for the year ended December 31, 1996 include an
extraordinary charge of $4,975,000, net of the related deferred tax benefit
of $1,042,000, related to the early extinguishment of the Company's prior
bank credit facilities ( the "1995 Credit Facility and the Bridge Facility").
The 1995 Credit Facility was replaced by the Bridge Facility in June 1996
and the Bridge Facility was paid off with proceeds from the Offerings in
October 1996.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994
The Company's total oil and gas revenues for 1995 were $21,693,000,
representing an increase of $14,056,000 (184%) over revenues of $7,637,000 in
1994. This increase was primarily due to the 1995 Acquisition which
accounted for approximately $13,373,000 of the revenue increase.
Oil and gas production was 1,751 MBOE in 1995 and 597 MBOE in 1994. Of the
1,154 MBOE increase, 1,099 MBOE was due to the properties acquired in the
1995 Acquisition.
23
Interest and other revenues were $123,000 in 1995 compared to $87,000 in
1994, representing an increase of $36,000 (41%), which was comprised of an
increase in interest income of $59,000 in 1995 due to an increased amount of
funds earning interest, partially offset by a decrease of other income of
$23,000. In 1994, the Company realized a gain of $112,000 on the sale of
various properties for which there were no comparable gains in 1995.
Oil and gas production costs in 1995 were $10,355,000 ($5.91 per BOE),
compared to $2,351,000 in 1994 ($3.94 per BOE), representing an increase of
$8,004,000 (340%). The major portion of the increase was due to increased
production associated with the 1995 Acquisition. In addition, certain
acquired properties required remedial workovers and other activity
immediately following acquisition resulting in unusual operating costs of
approximately $600,000 during 1995. In addition, $1,605,000 of operating
costs were incurred in connection with properties acquired in late 1994.
General and administrative expense for 1995 was $3,571,000, representing an
increase of $2,387,000 (202%) from 1994 expense of $1,184,000. The increase
is primarily due to an increase in personnel and related costs necessary to
accommodate the increased activities of the Company due to the 1995
Acquisition.
Results of operations for the year ended December 31, 1995 include non-cash
compensation expense of $656,000 deemed to have been accrued to a minority
interest owner of the Company in connection with the cancellation of an
option to purchase an additional interest in the Company held by the other
minority interest owner.
Exploration and abandonment expense increased to $1,650,000 in 1995 compared
to $793,000 in 1994. The increase of $857,000 (108%) was comprised
principally of $790,000 of seismic costs.
Depreciation, depletion and amortization expense for 1995 was $5,958,000
compared to $1,847,000 for 1994, representing an increase of $4,111,000
(223%). During 1995 depreciation, depletion and amortization on oil and gas
production was provided at an average rate of $3.40 per BOE compared to $3.09
per BOE for 1994. The increase was due primarily to the 1995 Acquisition.
Interest expense was $4,591,000 in 1995 compared to $1,458,000 in 1994. The
$3,133,000 (215%) increase was attributable to increased levels of debt which
the Company used to finance the 1995 Acquisition. The average amounts of
applicable interest-bearing debt in 1995 and 1994 were $49,972,000 and
$17,632,000, respectively.
LIQUIDITY AND CAPITAL RESOURCES
NET CASH USED IN OPERATING ACTIVITIES
For the year ended December 31, 1996, net cash provided by operating
activities increased to $12.4 million from $6.4 million for 1995. Cash
provided by operations, before changes in operating assets and liabilities,
increased to $14.7 million from $1.7 million for 1995 due primarily to the
1996 Acquisition and the increase in results of operations therefrom.
NET CASH USED IN INVESTING ACTIVITIES
Net cash used in investing activities for the year ended December 31, 1996
was $64.1 million. Approximately $38.7 million was used for the 1996
Acquisition, $28.7 million was used for other oil and gas expenditures and
$3.0 million was used for other property and equipment. During the year
ended December 31, 1996, approximately $6.3 million net cash was provided by
sales of oil and gas properties. For the year ended December 31, 1995, net
cash used in investing activities was $62.5 million. Approximately $46.6
million was used for the 1995 Acquisition, $14.9 million for additional
acquisition of producing oil and gas properties and exploration and
development activities and $1.0 million primarily for other property and
equipment.
NET CASH PROVIDED BY FINANCING ACTIVITIES
The Company entered into a $125.0 million senior credit agreement in June
1996, which was fully funded prior to the Company's initial public offering
of Common Stock in October 1996. Approximately $74.5 million was for the
24
extension and refinancing of prior debt, $42.5 million was used for the 1996
Acquisition and approximately $8.0 million was used for general corporate
purposes.
CAPITAL RESOURCES
Funding for the Company's business activities has historically been provided
by bank financings, cash flow from operations, private equity sales, property
divestitures and joint ventures with industry participants. The Company
completed a $10 million private equity placement in February 1995.
Subsequently, the 1995 Acquisition and the 1996 Acquisition were
substantially funded by bank financings. The Company plans to finance its
continuing operations and execute its business strategy with cash flow from
operations and borrowings under the Credit Facility.
While the Company regularly engages in discussions relating to potential
acquisitions, the Company has no present agreement, commitment or
understanding with respect to any such acquisition, other than the
acquisition of undeveloped acreage and various mineral interests in its
normal course of business. Any future acquisition may require additional
financing and will be dependent upon financing arrangements available at the
time.
The Company believes that cash flow from operations will be sufficient for
its budgeted 1997 capital expenditures. However, because the Company's
ultimate 1997 capital expenditures, future cash flows and the availability of
financing are subject to a number of variables, there can be no assurance
that the Company's capital resources will be sufficient to maintain its
capital expenditures. In addition, if the Company is unable to generate
sufficient cash flow from operations to service its debt, it may be required
to refinance all or a portion of its debt, including the Notes, or to obtain
additional financing. There can be no assurance that any such refinancing
would be possible or that any additional financing could be obtained.
The Company has the Credit Facility with NationsBank of Texas, N.A. (the
"Bank"). The Credit Facility provides for a revolving line of credit with
the availability of funds and letters of credit being subject to a borrowing
base determination at least semi-annually. The borrowing base provides for a
maximum availability of $50.0 million (which amount was also the initial
borrowing base), $100,000 of which was borrowed at December 31, 1996.
Availability under the borrowing base is initially limited to $20.0 million
for working capital and $30.0 million for acquisitions of oil and gas
properties meeting certain criteria established by the Bank. Borrowings
under the Credit Facility bear interest at the Company's option at a floating
rate which is at or above the NationsBank, N.A. prime rate or the LIBOR rate,
depending on the percentage of committed funds which have been borrowed.
Interest is payable quarterly and principal is amortized in twelve equal
installments commencing, October 1998. Under the Credit Facility, the
Company is obligated to pay certain fees to the Bank, including a commitment
fee based on the unused portion of the commitment. The Credit Facility
contains customary restrictive covenants (including restrictions on the
payment of dividends and the incurrence of additional indebtedness) and
requires the Company to maintain a current ratio of not less than 1.0 to 1.0,
a ratio of Adjusted EBITDA to interest expense of not less than 2.0 to 1 and
a minimum tangible net worth. At December 31, 1996, the Company's current
ratio was 2.0 to 1.0, the ratio of Adjusted EBITDA to interest expense was
3.9 to 1 and the Company exceeded the tangible net worth test.
Borrowings under the Credit Facility are secured by substantially
all of the assets of the Company.
Although certain of the Company's costs and expenses may be affected by
inflation, inflationary costs have not had a significant effect on the
Company's results of operations.
CAPITAL EXPENDITURES
The Company requires capital primarily for the exploration, development and
acquisition of oil and gas properties, the repayment of indebtedness and
general working capital needs. The Company's capital budget for 1997 is
$26.0 million of which approximately $7.2 will be expended for exploratory
drilling, approximately $13.6 million for exploitation activities,
approximately $2.5 million for the purchase of undeveloped acreage and
approximately $2.7 million for new seismic projects.
25
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
For the financial statements and supplementary data required by this Item 8,
see the Index to Consolidated Financial Statements on page F-1 in this Form
10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
26
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by this Item is incorporated herein by reference to
the Company's definitive proxy statement which will be filed with the
Commission within 120 days after December 31, 1996.
ITEM 11. EXECUTIVE COMPENSATION.
The information required by this Item is incorporated herein by reference to
the Company's definitive proxy statement which will be filed with the
Commission within 120 days after December 31, 1996.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this Item is incorporated herein by reference to
the Company's definitive proxy statement which will be filed with the
Commission within 120 days after December 31, 1996.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by this Item is incorporated herein by reference to
the Company's definitive proxy statement which will be filed with the
Commission within 120 days after December 31, 1996.
27
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
FINANCIAL STATEMENTS
For a list of the consolidated financial statements filed as part of this
Form 10-K, see the Index to Consolidated Financial Statements on page F-1.
REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the quarter ended December 31, 1996.
EXHIBITS
Exhibit
Number Description of Exhibit
- ------- ----------------------
*3.1 Certificate of Incorporation of the Company
*3.2 Bylaws of the Company
*4.1 Form of Notes or Global Certificate (included as Exhibit A to the
Indenture)
*4.2 Indenture dated as of October 1, 1996 by and between State Street
Bank and Trust Company, as Trustee, and the Company, as Issuer
**4.3 Form of Stock Certificate
***10.1 Credit Agreement dated October 10, 1996 between NationsBank of
Texas, N.A., as agent, the Lenders named therein and the Company
*10.2 Lease Agreement dated January 12, 1996 between Independence
Plaza, Ltd. and Costilla Energy, L.L.C.
*10.3 Concession Agreement dated July 6, 1995 between the Government of
the Republic of Moldova and Resource Development Company Ltd.,
L.L.C. (DE)
*10.4 Consolidation Agreement dated October 8, 1996
*10.5 1996 Stock Option Plan
*10.6 Outside Directors Stock Option Plan
*10.7 Employment Agreement between the Company and Bobby W. Page
effective June 30, 1996
*10.8 Employment Agreement between the Company and Cadell S. Liedtke
effective October 8, 1996
*10.9 Employment Agreement between the Company and Michael J. Grella
effective October 8, 1996
*10.10 Employment Agreement between the Company and Henry G. Musselman
effective October 8, 1996
*10.11 Purchase and Sale Agreement dated April 3, 1995 by and between
Parker & Parsley Development L.P., Parker & Parsley Producing
L.P. and Parker & Parsley Gas Processing Co., as Seller, and
Costilla Petroleum Corporation and Costilla Energy, L.L.C., as
Purchaser
*10.12 Purchase and Sale Agreement dated March 8, 1996 by and between
Parker & Parsley Development L.P., Parker & Parsley Producing
L.P. and Parker & Parsley Gas Processing Co., as Seller, and
Costilla Petroleum Corporation and Costilla Energy, L.L.C., as
Purchaser
*10.13 Bonus Incentive Plan
28
***10.14 Letter Agreement dated December 18, 1996 by and between Statewide
Minerals, Inc., as Seller, Boldrick Partners, as Buyer
***10.15 Stock Purchase Agreement dated December 31, 1996 by and between ERI
Investments, Inc. and the Company
***12.1 Computation of Ratio of Adjusted EBITDA to Interest Expense
**16.1 Letter Regarding Change of Accountants
***21.1 Subsidiaries of the Registrant
***23.1 Consent of KPMG Peat Marwick LLP
***23.2 Consent of Williamson Petroleum Consultants, Inc.
***23.3 Consent of Elms, Faris & Co., P.C.
***24.1 Power of Attorney
***24.2 Certified copy of resolution of Board of Directors of Costilla
Energy, Inc. authorizing signature by Power of Attorney
***27.1 Financial Data Schedule
* Incorporated by reference to Registration Statement on Form S-1, File
No. 333-08909
** Incorporated by reference to Registration Statement on Form S-1, File
No. 333-08913.
*** Filed herewith
FINANCIAL STATEMENT SCHEDULES
No Financial Statement Schedules are required with this report. For a list
of the consolidated financial statements filed as a part of this report,
see the Index to Consolidated Financial Statements on page F-1.
REPORTS ON FORM 8-K
The Company did not file a report on Form 8-K during the last quarter of
the period covered by this report.
29
S I G N A T U R E S
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
COSTILLA ENERGY, INC.
Date: March 26, 1997 By: */s/ CADELL S. LIEDTKE
--------------------------------
Cadell S. Liedtke
Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed by the following persons on behalf of the registrant
and in the capacities and on the dates indicated.
Date: March 26, 1997 */s/ CADELL S. LIEDTKE
--------------------------------
Cadell S. Liedtke
Chairman of the Board
and Chief Executive Officer
Date: March 26, 1997 */s/ MICHAEL J. GRELLA
--------------------------------
Michael J. Grella
President and Chief Operating Officer
and Director
Date: March 26, 1997 */s/ HENRY G. MUSSELMAN
--------------------------------
Henry G. Musselman
Executive Vice President
and Director
Date: March 26, 1997 */s/ W. D. KENNEDY
--------------------------------
W. D. Kennedy
Director
Date: March 26, 1997 */s/ JERRY J. LANGDON
--------------------------------
Jerry J. Langdon
Director
Date: March 26, 1997 /s/ BOBBY W. PAGE
--------------------------------
Bobby W. Page
Senior Vice President and Chief Financial
Officer (principal accounting officer)
Date: March 26, 1997 *By: /s/ BOBBY W. PAGE
--------------------------------
Bobby W. Page
Agent and Attorney in fact
30
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Financial Statements of Costilla Energy, Inc.:
Independent Auditors' Reports . . . . . . . . . . . . . . . . . . . . . . . . F - 2
Consolidated Balance Sheets as of December 31, 1996 and 1995. . . . . . . . . F - 4
Consolidated Statements of Operations for the years ended December31, 1996,
1995 and 1994. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F - 5
Consolidated Statements of Stockholders' Equity for the years
ended December 31, 1996, 1995 and 1994. . . . . . . . . . . . . . . . . . . . F - 6
Consolidated Statements of Cash Flows for the years ended December 31, 1996,
1995 and 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F - 7
Notes to Consolidated Financial Statements. . . . . . . . . . . . . . . . . . F - 8
F-1
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Costilla Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Costilla
Energy, Inc. and subsidiaries as of December 31, 1996 and 1995, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for the years then ended. These consolidated financial statements are
the responsibility of the Company's management. Our responsibility is to
express an opinion on these consolidated financial statements based on our
audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Costilla
Energy, Inc. and subsidiaries as of December 31, 1996 and 1995, and the
results of their operations and their cash flows for the years then ended, in
conformity with generally accepted accounting principles.
/s/ KPMG PEAT MARWICK LLP
---------------------------------
KPMG PEAT MARWICK LLP
Midland, Texas
March 10, 1997
F-2
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Costilla Energy, Inc.:
We have audited the accompanying consolidated statement of operations,
stockholders' equity, and cash flows of the predecessor entities of Costilla
Energy, Inc. and subsidiaries, as detailed in Note 1 to the consolidated
financial statements, for the year ended December 31, 1994. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the results of operations and the
cash flows of Costilla Energy, Inc. and subsidiaries for the year ended
December 31, 1994, in conformity with generally accepted accounting
principles.
/s/ ELMS, FARIS & CO., P. C.
------------------------------------
ELMS, FARIS & CO., P. C.
Midland, Texas
March 31, 1995
F-3
COSTILLA ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
ASSETS
DECEMBER 31,
---------------------
1996 1995
--------- --------
CURRENT ASSETS:
Cash and cash equivalents $ 12,618 $ 2,866
Accounts receivable:
Trade, net 6,675 3,154
Affiliates 332 507
Oil and gas sales 9,031 3,915
Prepaid and other current assets 1,753 439
--------- --------
Total current assets 30,409 10,881
--------- --------
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas properties, using the successful efforts
method of accounting:
Proved properties 140,477 79,897
Unproved properties 4,482 2,903
Accumulated depletion, depreciation and amortization (20,435) (9,413)
--------- --------
124,524 73,387
Other property and equipment, net 2,420 679
--------- --------
Total property, plant and equipment 126,944 74,066
--------- --------
OTHER ASSETS:
Deferred charges (Note 2) 4,503 1,736
Note receivable - other 250 -
Note receivable - affiliate 684 684
--------- --------
Total other assets 5,437 2,420
--------- --------
$ 162,790 $ 87,367
--------- --------
--------- --------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt $ 98 $ -
Trade accounts payable 12,718 5,467
Undistributed revenue 3,517 1,227
Other current liabilities 3,756 1,533
--------- --------
Total current liabilities 20,089 8,227
--------- --------
LONG-TERM DEBT, LESS CURRENT MATURITIES (NOTE 7) 100,262 71,494
--------- --------
DEFERRED REVENUE - 3,319
--------- --------
OTHER NONCURRENT LIABILITIES 1,870 196
--------- --------
REDEEMABLE PREDECESSOR CAPITAL - 11,576
--------- --------
STOCKHOLDERS' EQUITY (DEFICIT):
Predecessor capital - (7,445)
Preferred stock, $.10 par value (3,000,000 shares authorized;
no shares outstanding - -
Common stock, $.10 par value (20,000,000 shares authorized;
10,475,000 shares outstanding at December 31, 1996) 1,047 -
Additional paid-in capital 41,081 -
Retained earnings (deficit) (1,559)
--------- --------
Total stockholders' equity (deficit) 40,569 (7,445)
--------- --------
COMMITMENTS AND CONTINGENCIES (NOTE 9) - -
--------- --------
$ 162,790 $ 87,367
--------- --------
--------- --------
See accompanying notes to consolidated financial statements.
F-4
COSTILLA ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
YEARS ENDED DECEMBER 31,
---------------------------------
1996 1995 1994
-------- -------- --------
REVENUES:
Oil and gas sales $ 53,919 $ 21,693 $ 7,637
Interest and other 40 123 87
Gain on sale of assets 1,067 - 112
-------- -------- --------
55,026 21,816 7,836
-------- -------- --------
EXPENSES:
Oil and gas production 21,325 10,024 2,349
Oil and gas production - affiliates 449 331 2
General and administrative 4,682 2,910 634
General and administrative - affiliates 556 661 550
Compensation related to option settlement - 656 -
Exploration and abandonments 2,550 1,652 793
Depreciation, depletion and amortization 12,430 5,958 1,847
Interest 11,281 4,591 1,458
-------- -------- --------
53,273 26,783 7,633
-------- -------- --------
Income (loss) before federal income taxes and
extraordinary item 1,753 (4,967) 203
PROVISION FOR FEDERAL INCOME TAXES
Current 176 3 8
Deferred 1,042 - 32
-------- -------- --------
Income (loss) before extraordinary item 535 (4,970) 163
Extraordinary loss resulting from early
extinguishment of debt, net of the related
deferred tax benefit of $1,042 (Notes 5 and 7) (4,975) - -
-------- -------- --------
NET INCOME (LOSS) $ (4,440) $ (4,970) $ 163
-------- -------- --------
-------- -------- --------
NET INCOME (LOSS) APPLICABLE TO PREDECESSOR CAPITAL $ (5,337) $ (7,812) $ 163
-------- -------- --------
-------- -------- --------
INCOME (LOSS) PER SHARE:
Income (loss) before extraordinary item $ 0.08 $ (0.96) $ 0.03
Extraordinary loss resulting from
early extinguishment of debt, net of
deferred tax benefit (0.77) - -
-------- -------- --------
Net income (loss) $ (0.69) $ (0.96) $ 0.03
-------- -------- --------
-------- -------- --------
Net income (loss) applicable to predecessor capital $ (0.82) $ (1.50) $ 0.03
-------- -------- --------
-------- -------- --------
WEIGHTED AVERAGE SHARES OUTSTANDING 6,473 5,200 5,200
-------- -------- --------
-------- -------- --------
See accompanying notes to consolidated financial statements.
F-5
COSTILLA ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(IN THOUSANDS)
TOTAL
STOCKHOLDERS'
ADDITIONAL RETAINED EQUITY AND
PREDECESSOR COMMON PAID-IN EARNINGS PREDECESSOR
CAPITAL STOCK CAPITAL (DEFICIT) CAPITAL
----------- ------ ---------- -------- -------------
BALANCE AT DECEMBER 31, 1993 (PREDECESSOR) $ 51 $ - $ - $ - $ 51
Net income 163 - - - 163
Withdrawals (961) - - - (961)
------- ------ -------- ------- -------
BALANCE AT DECEMBER 31, 1994 (PREDECESSOR) (747) - - - (747)
Issuance of predecessor interest 1,266 - - - 1,266
Issuance costs (753) - - - (753)
Net loss (4,970) - - - (4,970)
Withdrawals (55) - - - (55)
Imputed capital contribution on
settlement of option 656 - - - 656
Preferred return and accretion of
redeemable predecessor capital (2,842) - - - (2,842)
------- ------ -------- ------- -------
BALANCE AT DECEMBER 31, 1995 (PREDECESSOR) (7,445) - - - (7,445)
Net loss (2,881) - - (1,559) (4,440)
Preferred return and accretion of
redeemable predecessor capital (2,456) - - - (2,456)
Common stock issued, net - 527 60,052 - 60,579
Distributions to members (4,218) 4,218 - -
Transfer of predecessor capital and
issuance of common stock pursuant
to the Offerings 17,000 520 (23,189) - (5,669)
------- ------ -------- ------- -------
BALANCE AT DECEMBER 31, 1996 $ - $1,047 $ 41,081 $(1,559) $40,569
------- ------ -------- ------- -------
------- ------ -------- ------- -------
See accompanying notes to consolidated financial statements.
F-6
COSTILLA ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEARS ENDED DECEMBER 31,
---------------------------------
1996 1995 1994
--------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS) $ (4,440) $ (4,970) $ 163
ADJUSTMENTS TO RECONCILE NET INCOME
(LOSS) TO NET CASH PROVIDED BY
OPERATING ACTIVITIES:
Depreciation, depletion and amortization 12,430 5,958 1,847
Exploration and abandonments 491 - -
Amortization of deferred charges 1,131 137 -
Other noncash 103 (75) 35
Compensation related to option settlement - 656 -
Gain on sale of oil and gas properties (1,067) - (112)
Extraordinary loss resulting from early
extinguishment of debt 6,017 - -
--------- -------- --------
14,665 1,706 1,933
Changes in operating assets and liabilities:
Increase in accounts receivable (8,462) (4,818) (1,535)
Decrease (increase) in other assets (1,076) (216) 301
Increase in accounts payable 6,067 3,745 723
Increase in other liabilities 4,475 2,655 102
Increase (decrease) in deferred revenue (3,319) 3,294 3
--------- -------- --------
Net cash provided by operating activities 12,350 6,366 1,527
--------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties (67,010) (61,500) (11,819)
Proceeds from sale of oil and gas properties 6,388 - 112
Additions to other property and equipment (3,007) (720) (49)
Advances on notes receivable - other (500) - -
Advances on affiliate notes receivable - (247) (390)
--------- -------- --------
Net cash used in investing activities (64,129) (62,467) (12,146)
--------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under long-term debt 228,707 62,704 11,579
Payments of long-term debt (199,840) (11,232) -
Proceeds from issuance of common stock, net 60,579 - -
Proceeds from redeemable predecessor capital - 10,000 -
Deferred loan and financing costs (8,191) (2,587) -
Redemption of member's interest (15,506) - -
Distributions to members and withdrawals (4,218) (55) (961)
--------- -------- --------
Net cash provided by financing activities 61,531 58,830 10,618
--------- -------- --------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 9,752 2,729 (1)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 2,866 137 138
--------- -------- --------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 12,618 $ 2,866 $ 137
--------- -------- --------
--------- -------- --------
See accompanying notes to consolidated financial statements.
F-7
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF OPERATIONS
Costilla was incorporated in Delaware in June 1996 to consolidate and
continue the activities previously conducted by Costilla Energy, L.L.C., a
Texas limited liability company (the "LLC"), and its wholly owned
subsidiaries, to acquire the assets of CSL Management Corporation ("CSL")
(which owns certain office equipment used by the Company), and to acquire the
stock of Valley Gathering Company ("Valley"). Costilla was formed for the
purpose of conducting a $60 million initial public offering of common stock
and a $100 million senior notes offering (the "Offerings"), which Offerings
were completed in early October 1996.
At December 31, 1994, the financial statements of the LLC and its
affiliates were combined. The combining companies were owned by three
individuals prior to the formation of the LLC. Such individuals owned
exactly the same proportionate interest in each of the combining companies
prior to their combination into the LLC on February 14, 1995. Each
individual held exactly the same proportionate interest in the combining
companies as was their proportionate interest in the LLC after its formation.
Management believes, based on the exact same proportionate interests being
held in the combining companies and the LLC before and after the date of its
formation, that the combination lacks substance and is not the purchase of a
minority interest.
The LLC was formed on February 14, 1995 as the successor to CSL
Partners, a Texas general partnership, which was organized on January 11,
1989. Subsequent to the formation of the LLC, NationsBank Capital
Corporation ("NBCC") acquired a 30% interest in the LLC as described in Note
12. Contemporaneously with the closings of the Offerings: (1) the redeemable
membership interests of NBCC in the LLC were redeemed for $15.5 million; (2)
the LLC was merged into Costilla (the "Merger") and an aggregate of 5,200,000
shares of Common Stock were issued to the members of the LLC; (3) Costilla
acquired all of the issued and outstanding stock of Valley and the assets of
CSL for $0.7 million; and (4) $4.2 million in distributions were made to the
members of the LLC, $3.4 million of which was provided to former members for
certain income tax effects of the Merger. The LLC was an unincorporated
association of several individuals and a corporation and ceased to exist on
the date of the Offerings.
The Company is an oil and gas exploration and production concern with
properties located principally in West Texas, South Texas, and the Rocky
Mountain regions of the United States.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
As of December 31, 1996, the consolidated financial statements include
the accounts of the Company and its wholly-owned subsidiaries. The Company
proportionately consolidates less than 100%-owned oil and gas partnerships
and joint ventures in accordance with industry practice. All significant
accounts and transactions between the Company and its subsidiaries have been
eliminated.
At December 31, 1996 Costilla had three wholly owned subsidiaries: (i)
Costilla Petroleum Corporation, a Texas corporation ("CPC"), which operated
properties owned by Costilla and owned minor interests in the same
properties, (ii) Statewide Minerals, Inc., a Texas corporation
("Statewide"), which had engaged in the purchase of small royalty and mineral
interests; and (iii) Valley, which owns several small gas gathering systems,
a small gas processing plant, certain salt water disposal systems and gas
compressors. Costilla and CPC were the sole members of two Texas limited
liability companies through which the Company's Moldovan operations are
conducted.
F-8
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
USE OF ESTIMATES
Preparation of the accompanying consolidated financial statements in
conformity with generally accepted accounting principles requires management
to make estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
CASH AND CASH EQUIVALENTS
For purposes of the statements of cash flows, cash and cash equivalents
include cash on hand and depository accounts held by banks.
CONCENTRATIONS OF CREDIT RISK
Financial instruments that potentially expose the Company to
concentrations of credit risk consist primarily of unsecured accounts
receivable from unaffiliated working interest owners and crude oil and
natural gas purchasers. During the year ended December 31, 1996, the Company
had sales to one customer which accounted for 11.2% of total revenues.
During the year ended December 31, 1995, the Company had sales to one
customer which accounted for 17.7% of total revenues.
TRADE RECEIVABLES
Trade receivables generally consist of amounts due from outside working
interest owners for their proportionate share of drilling and operating costs
incurred by the Company, as operator of the related properties.
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
The financial instruments that the Company accounts for as hedging
contracts must meet the following criteria: the underlying asset or
liability must expose the Company to price or interest rate risk that is not
offset in another asset or liability, the hedging contract must reduce that
price or interest rate 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 or interest rate
changes on the exposed items.
Premiums paid for commodity option contracts and interest rate swap
agreements which qualify as hedges are amortized to oil and gas sales and
interest expense, respectively, over the terms of the agreements.
Unamortized premiums are included in other assets in the consolidated balance
sheet. Amounts receivable under the commodity option contracts and interest
rate swap agreements are accrued as an increase in oil and gas sales and a
reduction of interest expense, respectively, for the applicable periods.
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 in
the consolidated statement of operations for the applicable period.
OIL AND GAS PROPERTIES
The Company uses the successful efforts method of accounting for oil and
gas producing activities. Costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that find proved reserves,
and to drill and equip development wells are capitalized. Costs to drill
exploratory wells that do not find proved reserves, geological and
geophysical costs, and costs of carrying and retaining unproved properties
are expensed.
F-9
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unproved oil and gas properties that are individually significant are
periodically assessed for impairment of value, and a loss is recognized at
the time of impairment by providing an impairment allowance. Other unproved
properties are amortized based on the Company's experience of successful
drilling and average holding period. Capitalized costs of producing oil and
gas properties, after considering estimated dismantlement and abandonment
costs and estimated salvage values, are depreciated and depleted by the
unit-of-production method. Support equipment and other property and
equipment are depreciated over their estimated useful lives of the assets,
which range from 5 to 7 years.
Prior to the adoption of FAS 121 on January 1, 1995, the Company's
aggregate oil and gas properties were carried at cost, not in excess of total
estimated undiscounted future net revenues, on a worldwide basis.
On sale or retirement of a complete unit of a proved property, the cost
and related accumulated depreciation, depletion, and amortization are
eliminated from the property accounts, and the resultant gain or loss is
recognized. On retirement or sale of a partial unit of proved property, the
cost is charged to accumulated depreciation, depletion, and amortization with
a resulting gain or loss recognized in income.
On sale of an entire interest in an unproved property for cash or cash
equivalent, gain or loss on the sale is recognized, taking into consideration
the amount of any recorded impairment if the property had been assessed
individually. If a partial interest in an unproved property is sold, the
amount received is treated as a reduction of the cost of the interest
retained.
IMPAIRMENT OF LONG-LIVED ASSETS
As of January 1, 1995, the Company adopted the provisions of Statement
of Financial Accounting Standards No. 121 - ACCOUNTING FOR THE IMPAIRMENT OF
LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF ("FAS 121").
Consequently, the Company reviews its long-lived assets to be held and used,
including oil and gas properties accounted for under the successful efforts
method of accounting, whenever events or circumstances indicate that the
carrying value of those assets may not be recoverable. An impairment loss is
indicated if the sum of the expected future cash flows, on a depletable unit
basis, is less than the carrying amount of such assets. In this
circumstance, the Company recognizes an impairment loss for the amount by
which the carrying amount of the asset exceeds the fair value of the asset.
DEFERRED CHARGES
The Company capitalized certain costs incurred in connection with the
issuance of $100 million of senior notes and with obtaining the 1996 Credit
Facility (see Note 7 for definitions and descriptions of each). These costs
are being amortized over the lives of the related instruments.
DEFERRED REVENUE
In November 1995, the Company entered into gas sales agreements whereby
it committed to delivery of a total of 2,379,000 MMbtu, from December 1, 1995
through December 31, 1996, for a total fixed price of $3,429,610. Income
from such agreements is generally recognized in the period of delivery.
REVENUE RECOGNITION
The Company uses the sales method of accounting for crude oil revenues.
Under this method, revenues are recognized based on actual volumes of oil
sold to purchasers.
The Company uses the entitlements method of accounting for natural gas
revenues. Under this method, revenues are recognized based on actual
production of natural gas. Natural gas revenues would not have been
significantly altered in any period had the sales method of recognizing
natural gas revenues been utilized.
F-10
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
STOCK-BASED COMPENSATION
The Company accounts for employee stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" ("APB 25"). Accordingly, the
Company has only adopted the disclosure provisions of Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation"
("SFAS 123"). See Note 12 for the pro forma disclosures of compensation
expense determined under the fair-value provisions of SFAS 123.
INCOME TAXES
The Company accounts for income taxes in accordance with the provisions
of Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes" ("SFAS 109"). Under the asset and liability method of SFAS
109, deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax
rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. Under SFAS
109, the effect on deferred tax assets and liabilities of a change in tax
rate is recognized in income in the period that includes the enactment date.
EARNING PER SHARE
Primary net income (loss) per share is computed based on the weighted
average number of shares of common stock and common stock equivalents
outstanding during the period. Common stock equivalent shares arising from
stock options are computed using the treasury stock method. There were no
potentially dilutive securities, other than common stock equivalents.
Consequently, primary and fully diluted earnings per share do not differ.
For the periods prior to the Offerings, the weighted average shares
outstanding attributable to predecessor capital are the 5,200,000 shares
issued to the predecessor members upon conversion of the LLC.
ENVIRONMENTAL
The Company is subject to extensive Federal, state and local
environmental laws and regulations. These laws, which are constantly
changing, regulate the discharge of materials into the environment and may
require the Company to remove or mitigate the environmental effects of the
disposal or release of petroleum or chemical substances at various sites.
Environmental expenditures are expensed or capitalized depending on their
future economic benefit. Expenditures that relate to an existing condition
caused by past operations and that have no future economic benefits are
expensed. Liabilities for expenditures of a noncapital nature are recorded
when environmental assessment and/or remediation is probable, and the costs
can be reasonably estimated.
RECLASSIFICATIONS
Certain reclassifications have been made to the 1995 and 1994 financial
statements to conform to the 1996 presentation.
(3) ACQUISITION OF OIL AND GAS PROPERTIES
On June 14, 1996, the Company consummated the purchase from Parker and
Parsley Petroleum Company of certain oil and gas properties for an estimated
adjusted purchase price of approximately $38.7 million (the "1996
Acquisition"). The properties are located primarily in south and west Texas.
The transaction was accounted for using the purchase method. The results of
operations of the acquired properties are included in the Consolidated
Statements of Operations as of the acquisition closing date, June 14, 1996.
The Company sold for approximately $3.3 million its wholly-owned subsidiary,
Costilla Pipeline Corporation, which owned the Three Rivers Pipeline
F-11
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
purchased in the 1996 Acquisition. Certain other acquired properties, which
were located outside the Company's areas of strategic focus, were sold in
1996. No gain or loss was recorded on these sales.
In June 1995 the Company acquired a group of oil and gas properties from
Parker and Parsley Petroleum Company for approximately $46.6 million (the
"1995 Acquisition"). The properties are located in the Permian Basin, Gulf
Coast and Rocky Mountain regions. The transaction was accounted for using
the purchase method. The results of operations of the acquired properties
are included in the Consolidated Statements of Operations as of the
acquisition date of June 12, 1995. Certain other acquired properties, which
were located outside the Company's areas of strategic focus, were sold in
1995. No gain or loss was recorded on these sales.
PRO FORMA RESULTS OF OPERATIONS (UNAUDITED)
The following table reflects the pro forma results of operations as
though the 1995 Acquisition and 1996 Acquisition, net of the related
properties sold, had occurred on January 1, 1995. The pro forma amounts are
not necessarily indicative of the results that may be reported in the future.
YEARS ENDED
DECEMBER 31,
1996 1995
------- --------
(IN THOUSANDS)
Revenues. . . . . . . . . . . . . . . . . . . . . . $64,251 $ 51,896
Net loss before extraordinary item. . . . . . . . . (689) (11,385)
Net loss per share before extraordinary item. . . . (0.11) (2.19)
(4) IMPAIRMENT OF LONG-LIVED ASSETS
The Company adopted FAS 121 effective as of January 1, 1995. FAS 121
requires that long-lived assets held and used by an entity, including oil and
gas properties accounted for under the successful efforts method of
accounting, be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. Long-lived assets to be disposed of are to be accounted for at
the lower of carrying amount or fair value less cost to sell when management
has committed to a plan to dispose of the assets. All companies, including
successful efforts oil and gas companies, are required to adopt FAS 121 for
fiscal years beginning after December 15, 1995.
In order to determine whether an impairment had occurred, the Company
estimated the expected future cash flows of its oil and gas properties on a
depletable unit basis and compared such future cash flows to the carrying
amount of the related oil and gas properties to determine if the carrying
amount was recoverable. Based on this process, no writedown in the carrying
amount of the Company's proved properties was necessary at December 31, 1996
or 1995.
(5) DERIVATIVE FINANCIAL INSTRUMENTS
The Company utilizes derivative financial instruments to manage
well-defined interest rate and commodity price risks. The Company is exposed
to credit losses in the event of nonperformance by the counterparties to its
interest rate swap agreements and its commodity hedges. The Company
anticipates, however, that such counterparties will be able to fully satisfy
their obligations under the contracts. The Company does not obtain
collateral or other security to support financial instruments subject to
credit risk but monitors the credit standing of the counterparties.
F-12
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COMMODITY HEDGES. The Company utilizes option contracts to hedge the
effect of price changes on future oil and gas production. If market prices
of oil and gas exceed the strike price of put options, the options will
expire unexercised, therefore reducing the effective price received for oil
and gas sales by the cost of the related option.
The following table sets forth the future volumes hedged by year and the
weighted-average strike price of the option contracts at December 31, 1996:
OIL GAS
VOLUME VOLUME STRIKE PRICE
(BBLS) (MMBTU) PER BBL/MMBTU
--------- --------- ------------------
Oil:
1997 . . . . . . . . . . . . . . . . .1,912,500 - $16.52 - $20.65(a)
Gas:
1997 . . . . . . . . . . . . . . . . . - 1,500,000 $1.65(b)
- -----------------------
(a) Represents the weighted-average price of a purchased put option contract
and of a collar established with the purchase of a put option contract and
the sale of a call option contract.
(b) Represents the strike price on a purchased put option contract.
INTEREST RATE SWAP AGREEMENTS. Prior to the Offerings, the Company
utilized two interest rate swap agreements to reduce the potential impact of
increases in interest rates on floating-rate long-term debt. Concurrent with
the issuance of the $100 million of 10.25% fixed-rate senior notes in early
October 1996, the two interest rate swap agreements ceased to be hedges.
These interest rate swap agreements were marked-to-market and the related
liability recorded. The liability for the two interest rate swap agreements
was $1,712,000 at December 31, 1996. The average balance of this liability
during the quarter ended December 31, 1996 was approximately $1,700,000.
During the quarter ended December 31, 1996, the Company recorded investment
losses of $207,300 on the interest rate swap agreements. The following table
sets forth the terms, fixed rates, and notional amounts of the interest rate
swap agreements in place as of December 31, 1996:
NOTIONAL
PRINCIPAL FIXED
TERM AMOUNT INTEREST RATE
- -------------------------------- ----------- -------------
Jan. 25, 1996 to Jan. 25, 1999 $24 million 7.50%
May 24, 1995 to May 27, 1997 (a) $60 million 5.99%
- -----------------------
(a) Subject to extension until May 24, 1999 at the option of the
counterparty.
(6) FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair
values of the Company's financial instruments at December 31, 1996 and 1995.
FASB Statement No. 107, DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL
INSTRUMENTS, defines the fair value of a financial instrument as the amount
at which the instrument could be exchanged in a current transaction between
willing parties.
F-13
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1996 1995
------------------- ----------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- -------- ------- -----
Financial Assets: (IN THOUSANDS)
Cash, cash equivalents and restricted cash. . .$ 12,618 $ 12,618 $ 2,866 $ 2,866
Receivables (trade) . . . . . . . . . . . . . . 6,675 6,675 3,154 3,154
Receivables (oil and gas sales) . . . . . . . . 9,031 9,031 3,915 3,915
Commodity option contracts. . . . . . . . . . . 592 (2,172) 165 555
Notes receivable -- affiliate . . . . . . . . . 684 542 684 684
Notes receivable -- other . . . . . . . . . . . 500 500 0 0
Financial liablilites:
Payables (trade). . . . . . . . . . . . . . . . 12,718 12,718 5,467 5,467
Deferred revenue. . . . . . . . . . . . . . . . - - 3,319 2,950
Long-term debt. . . . . . . . . . . . . . . . . 100,262 105,512 71,494 71,494
Interest rate swap and option agreements. . . . 1,712 1,712 146 (2,970)
The carrying amounts shown in the table are included in the statement of
financial position under the indicated captions.
The following methods and assumptions were used to estimate the fair
value of each class of financial instruments:
CASH, TRADE RECEIVABLES, NOTES RECEIVABLE-OTHER AND TRADE PAYABLES: The
carrying amounts approximate fair value because of the short maturity of
those instruments.
COMMODITY OPTION CONTRACTS: The carrying amount comprises the unamortized
premiums paid for the option contracts. The fair value is estimated using
option pricing models and essentially values the potential for the option
contracts to become in-the-money through changes in commodity prices during
the remaining terms.
NOTES RECEIVABLE-AFFILIATE: The amounts reported relate to notes
receivable from an affiliated company. The carrying amount reflects an
estimate of net present value using an assumed annual interest rate of 9%
based upon the anticipated note payment schedule.
DEFERRED REVENUE: The amounts reported relate to the gas purchase
agreements described in Note 2. The carrying amount represents the payments
received under the agreements for which subsequent delivery is required. The
fair value is estimated based upon the commodity price at December 31, 1995
for a similar agreement.
LONG-TERM DEBT: The fair value of the Corporation's long-term debt is
based upon the quoted market price for this issue at December 31, 1996.
INTEREST RATE SWAP AGREEMENTS: At December 31, 1996, the Company had two
interest rate swap agreements outstanding with an aggregate notional amount
of $84 million. These agreements are more fully described in Note 5. The
carrying amount is equal to the sum of the unamortized premiums paid for the
agreements and the fair value. The fair values of each of the open interest
rate swap agreements were obtained from bank quotes and represent the
estimated amount the Company would pay upon termination of the agreements at
December 31, 1996, taking into consideration interest rates at that date.
F-14
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(7) LONG-TERM DEBT
Long-term debt consists of the following (thousands):
DECEMBER 31,
-------------------
1996 1995
-------- -------
10 1/4% Senior Notes due 2006 . . . . .$100,000 $ -
Revolver Note . . . . . . . . . . . . . 100 59,824
Term notes. . . . . . . . . . . . . . . - 11,670
Other notes payable . . . . . . . . . . 260 -
-------- --------
100,360 71,494
Less current maturities. . . . . 98 -
-------- --------
$100,262 $ 71,494
-------- --------
-------- --------
In October 1996, the Company issued $100 million aggregate principal
amount of 10.25% Senior Notes due October 1, 2006 (the "Notes"). The notes
were sold at par and interest is payable April 1 and October 1, commencing
April 1, 1997. The Notes may not be redeemed prior to October 1, 2001, and
thereafter at a premium reducing to par, plus interest, by maturity. There
is no mandatory redemption of the Notes required prior to maturity. The notes
are general unsecured senior obligations of the Company and rank equally in
right of payment with all other senior indebtedness of the Company and senior
in right of payment of all existing future subordinated indebtedness of the
Company. The Notes are subject to an Indenture between the Company and a
trustee. The Indenture restricts, among other things, the Company's ability
to incur additional indebtedness, pay dividends or make certain other
restricted payments, incur liens, engage in any sale and leaseback
transaction, sell stock of subsidiaries, apply net proceeds from certain
assets sales, merge or consolidate with any other person, sell, assign,
transfer, lease, convey or otherwise dispose of substantially all of the
assets of the company, or enter into certain transactions with affiliates.
Net proceeds from the sale of the Notes of approximately $96.1 million were
used to repay existing indebtedness.
In October 1996, the Company entered into a credit agreement (the "1996
Credit Facility") with NationsBank of Texas, N.A. (the "Bank"). The 1996
Credit Facility provides a revolving line of credit with the availability of
funds and letters of credit being subject to a borrowing base determination
at least semiannually. The borrowing base provides a maximum availability of
$50.0 million (which amount is also the initial borrowing base), $100,000 of
which was outstanding at December 31, 1996. Availability under the borrowing
base is initially limited to $20.0 million for working capital and $30.0
million for acquisitions of oil and gas properties meeting certain criteria
established by the Bank. Borrowings under the 1996 Credit Facility bear
interest, at the Company's option, at a floating rate which is at or above
the NationsBank, N.A. prime rate or the LIBOR rate, depending on the
percentage of committed funds which have been borrowed. Interest is payable
quarterly and principal will be amortized in twelve equal installments
commencing two years from the date of the credit agreement. Under the 1996
Credit Facility, the Company is obligated to pay certain fees to the Bank,
including a commitment fee which ranges from 0.30% to 0.40% based on
the unused portion of the commitment. The 1996 Credit Facility contains
customary restrictive covenants (including restrictions on the payment of
dividends and the incurrence of additional indebtedness) and requires the
Company to maintain a current ratio of not less than 1.0 to 1.0, a ratio of
Adjusted EBITDA to interest expense of not less than 2.0 to 1.0 and a minimum
tangible net worth. Borrowings under the 1996 Credit Facility are secured by
substantially all of the assets of the Company and any subsidiary of the
Company that guarantees the Company's obligations under the 1996 Credit
Facility. Initially, none of the Company's subsidiaries have guaranteed the
Company's obligations under the 1996 Credit Facility.
In June, 1996, the Company entered into a loan agreement with
NationsBridge, L.L.C. to provide financing of up to $125 million ("Bridge
Loan"). The proceeds of this Bridge Loan were used to finance the 1996
Acquisition, to refinance the 1995 Credit Facility and for other general
corporate purposes. The Company
F-15
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
capitalized certain costs incurred in obtaining the Bridge Loan and amortized
these costs over the estimated life of the Bridge Loan. Concurrent with the
Offerings, the $2,665,000 remaining unamortized balance of these deferred
charges were expensed as an extraordinary item.
In June, 1995, the Company entered into a Credit Agreement ("1995 Credit
Facility") with a syndicate of banks to provide financing for an aggregate
$185 million senior secured revolving line of credit ("Revolver Notes") and
an aggregate $15 million in senior secured term notes ("Term Notes"). In
June 1996, these notes in a total amount of $71,494,000 were paid off with a
portion of the proceeds of the Bridge Loan. The Company capitalized certain
costs incurred in obtaining the 1995 Credit Facility and amortized these
costs over the lives of the notes. Concurrent with the Bridge Loan, the
$1,640,000 remaining unamortized balance of these deferred charges were
expensed as an extraordinary item.
Maturities of long-term debt at December 31, 1996 are as follows
(thousands):
1997 . . . . . . . . . . . . . . . . . . $ 98
1998 . . . . . . . . . . . . . . . . . . 62
1999 . . . . . . . . . . . . . . . . . . 101
2000 . . . . . . . . . . . . . . . . . . -
2001 . . . . . . . . . . . . . . . . . . 100
Thereafter . . . . . . . . . . . . . . . 100,000
The Company paid interest on long-term debt of $8,838,971, $4,453,684 and
$1,356,604 in 1996, 1995 and 1994, respectively.
(8) INCOME TAXES
Concurrent with the Offerings and upon consummation of the Corporate
Reorganization, the Company became a tax paying entity for U.S. Federal
income tax purposes. At that date, the tax basis of the Company's assets and
liabilities exceeded the book basis by approximately $3,500,000, resulting in
a deferred tax asset of approximately $1,200,000. A valuation allowance was
provided for 100% of this deferred tax asset.
Income tax provision (benefit), generated from $2,978,000 of net income
before extraordinary item from the date of the Corporate Reorganization
through December 31, 1996, and amounts separately allocated were
as follows (thousands):
Income (loss) before extraordinary item $ 1,218
Extraordinary loss resulting from early
extinguishment of debt (1,042)
--------
$ 176
--------
--------
The Company's effective tax rate does not differ materially from the U.S.
Federal statutory rate.
F-16
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The tax effects of temporary differences that give rise to significant
portions of deferred tax assets and deferred tax liabilities were as follows
at December 31, 1996:
Deferred tax assets:
Net operating loss carryforwards $ 2,805
Interest rate swap agreements held
for trading purposes 599
-------
Total gross deferred tax asset 3,404
-------
Deferred tax liabilities:
Oil and gas properties, principally due
to differences in depletion and the
deduction of intangible drilling costs
for tax purposes 1,692
-------
Net deferred tax asset 1,712
Valuation allowance of net deferred tax asset (1,712)
-------
Net deferred tax asset, net of valuation allowance $ -
-------
-------
A valuation is provided for when it is more likely than not that some
portion of the deferred tax assets will not be realized. Due to uncertainties
arising from a lack of earnings history and based on management's intentions
to continue an aggressive drilling program (generating intangible drilling
costs which are projected to create future losses for tax purposes), it does
not appear more likely than not that the Company will be able to utilize all
the available carryforwards prior to their ultimate expiration.
At December 31, 1996, the Company had net operating loss carryforwards of
approximately $8 million, which are available to offset future regular taxable
income, if any. The carryforwards expire December 31, 2011.
(9) COMMITMENTS AND CONTINGENCIES
LEASES
The Company leases equipment and office facilities under operating leases
on which rental expense for the years ended December 31, 1996, 1995 and 1994
was $416,442, $311,221, and $197,533, respectively. Future minimum lease
commitments under noncancellable operating leases at December 31, 1996 are as
follows (thousands):
1997................................... $ 275,695
1998................................... 273,943
1999................................... 260,324
2000................................... 233,880
2001................................... 286,850
Thereafter............................. 1,395,886
EMPLOYMENT AGREEMENTS
During the period from June through October, 1996, the Company entered
into employment agreements with four of its executive officers. The
employment agreements are each for three years and each will automatically
renew for successive one-year periods thereafter unless the employee is
notified to the contrary. These employment agreements provide for base annual
salary levels totaling $990,000 for 1997.
F-17
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Each employee would receive his salary for the remaining term of the
applicable employment agreement if the Company were to terminate such person's
employment other than for cause. If such person were to voluntarily leave his
employment with the Company prior to the second anniversary of the employment
agreement no further payments would be required. With the exception of one of
the Company's executive officers, if a voluntary termination were to occur
after the second anniversary of the employee agreement, such person would be
entitled to one year's salary from the date of termination. With the exception
of one of the Company's executive officers, the employee agreements provide
that the covered employee will not compete with the Company for a one year
period following his voluntary cessation of employment or termination of
employment for cause, in either case if such event occurs within the initial
three-year term of the employee agreement.
EXPLORATION AND DEVELOPMENT
In July 1995, the Republic of Moldova (located in Eastern Europe between
Romania and the Ukraine) granted a Concession Agreement to Resource
Development Company Limited, L.L.C. ("Redeco"), an entity not affiliated with
the Company. The Company paid Redeco $90,000 and agreed to bear the first
$2.0 million of Concession expenses in return for a 50.0% interest in Redeco.
Upon reaching the $2.0 million in 1996, Redeco elected, according to the
agreement, to pay the Company for half of all amounts expended in excess of
$750,000 plus interest. The Concession Agreement covers the entire country
with respect to oil and gas and other minerals and continues for various time
periods depending on the nature of the activity conducted. The Company has no
material fixed financial commitments with respect to the Concession. As of
December 31, 1996, the Company's share of costs expended was $1,909,349.
LETTERS OF CREDIT
As a result of certain bonding and trade creditor requirements, the
Company has caused irrevocable letters of credit to be issued by a bank
totaling $96,000. As of December 31, 1996, no amounts had been drawn on these
letters of credit.
(10) 401(k) PLAN
The Company has established a qualified cash or deferred arrangement
under IRS code section 401(k) covering substantially all employees. Under the
plan, the employees have an option to make elective contributions of a portion
of their eligible compensation, not to exceed specified annual limitations, to
the plan and the Company has an option to match a percentage of the employee's
contribution. The Company has made matching contributions to the plan
totaling $58,713, $22,531, and $8,921 in 1996, 1995 and 1994, respectively.
(11) REDEEMABLE PREDECESSOR CAPITAL AND PREDECESSOR CAPITAL
During 1995, NationsBanc Capital Corporation ("NBCC") contributed $10
million in exchange for a 30% ownership interest in the Company including the
preferential return described below. Of this amount $1,266,000 was attributed
to the non-redeemable portion of predecessor capital and $8,734,000 was
attributed to redeemable predecessor capital. Preferred return and accretion
of predecessor capital included in the consolidated statements of operations
and the consolidated statements of stockholders' equity includes accretion of
the amount attributable to redeemable predecessor capital to $10,000,000 over
a two year period beginning February 17, 1995. As described below, the
redemption amount was ultimately to be equal to $10,000,000 plus a preferred
return and an additional redemption amount related to NBCC's redeemable
interest not subject to preferential return.
Concurrent with the Offerings, NBCC's membership interest was redeemed
for a total of $15,506,614 and 936,000 common shares were issued to NBCC.
After accounting for the Underwriter's exercise of its over-
F-18
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
allotment option in November 1996, NBCC owns 8.94% of the 10,475,000 common
shares outstanding at December 31, 1996. The following table details the
redemption price paid to NBCC:
NBCC Preferred Capital Contribution................. $10,000,000
Preferred Return.................................... 2,732,376
-----------
Adjusted NBCC Preferred Capital Contribution........ 12,732,376
PLUS: 10% Redemption Premium........................ 1,273,238
PLUS: Aggregate Redemption Price of NBCC's
Redeemable Unrestricted Common Units.......... 1,500,000
-----------
Total Redemption Price Paid NBCC.................... $15,505,614
-----------
-----------
Redeemable predecessor capital was subject to a preferential return of
15% per annum and was redeemable at any time at the Company's option, subject
to a redemption premium as described below, or at NBCC's option on February
17, 2003 or at an earlier date upon occurrence of certain events including a
change in control, certain changes in management, a change in the Company's
status as a limited liability company for tax purposes, or violation of any of
various other restrictive provisions contained in the Regulations of Costilla
Energy, Inc. (the "Regulations"). The 15% preferred return was treated as a
reduction of predecessor capital. The redemption price to be paid by the
Company was equal to the initial amount received for the preferred units plus
a premium, determined in the year the units are purchased, as follows:
Year after Premium
February 17, 1995 Percentage
----------------- ----------
1 10%
2 10%
3 8%
4 6%
5 4%
6 2%
7 0%
8 0%
In addition, a portion of NBCC's interest not subject to preferential
return was classified as redeemable predecessor capital as the Company could
have been be required to repurchase such interest upon the occurrence of
certain events similar to those events requiring redemption of the redeemable
predecessor capital described above and, in any event, on or after February
17, 2000. Such interest could have, at the Company's option, been repurchased
to the extent the Company has exercised its right to redeem all or a portion
of the redeemable members' interest subject to the preferential return. The
redemption price the Company would have paid in either instance would be
determined by the year in which the predecessor capital was repurchased as
follows:
Before Aggregate
February 17 Redemption Price
----------- ----------------
1996 $ 1
1997 1,500,000
1998 3,000,000
1999 4,500,000
2000 5,500,000
F-19
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Prior to the Offerings in October 1996, the ultimate redemption price of
$5,500,000 was being accrued ratably over the period from February 17, 1995
through February 17, 2000 and was treated as a reduction of predecessor
capital.
(12) STOCK-BASED COMPENSATION
OUTSIDE DIRECTORS STOCK OPTION PLAN
The Outside Directors Stock Option Plan provides for the issuance of
stock options to the outside directors of the Company. A total of 50,000
shares has been authorized and reserved for issuance under the plan, subject
to adjustments to reflect changes in the Company's capitalization resulting
from stock splits, stock dividends and similar events. Only outside directors
are eligible to participate in the plan. Outside directors are those
directors of the Company who are not executive officers or regular salaried
employees of the Company as of the date the Option is granted. Under the
plan, an option for 1,000 shares of Common Stock will be granted to each
person who qualifies as an outside director each year that such person is
elected as a director of the Company. The exercise price of each option
granted under the plan will be the fair market value (as reported on the
Nasdaq National Market) of the Common Stock at the time the option is granted
and may be paid either in cash, shares of Common Stock or a broker-assisted
cashless transaction. Each option will be exercisable immediately, and will
expire ten years from the date of grant. As of December 31, 1996, no options
had been granted under this plan.
BONUS INCENTIVE PLAN
The Company has adopted the Bonus Incentive Plan, concurrent with the
Offerings. The plan provides that the Board of Directors each year may award
bonuses in cash, Common Stock, or some combination thereof, to those officers,
directors, employees and advisors of the Company or a subsidiary of the
Company, who the Board of Directors determines have contributed to the success
of the Company. A total of 150,000 shares of Common Stock has been authorized
and reserved for issuance under the plan, subject to adjustments to reflect
changes in the Company's capitalization resulting from stock splits, stock
dividends and similar events. All officers, directors, employees and advisors
of the Company or a subsidiary of the Company who have completed a minimum of
180 days of service and are employed or retained by the Company or such
subsidiary on the last day of the plan year, other than such persons who own
ten percent or more of the outstanding shares of the Common Stock during that
year, are eligible to participate in the plan. Bonus awards will be
determined based upon a number of factors, including performance and salary
level of the participant and the financial performance of the Company and its
subsidiaries. Bonuses will be awarded after review and upon approval of the
Board of Directors, subject to the terms and conditions of the plan. As of
December 31, 1996, no shares of Common Stock have been issued pursuant to this
plan.
1996 STOCK OPTION PLAN
The 1996 Stock Option Plan provides for the grant of both incentive stock
options and non-qualifying stock options, as well as limited stock
appreciation rights and supplemental bonuses, to the employees of the Company
and its subsidiaries, including officers and directors who are salaried
employees. A total of 850,000 shares of Common Stock has been authorized and
reserved for issuance under the plan, subject to adjustments to reflect
changes in the Company's capitalization resulting from stock splits, stock
dividends and similar events. The plan is administered by the Board of
Directors. The Board of Directors has the sole authority to interpret the
plan, to determine the persons to whom the options will be granted, to
determine the basis upon which the options will be granted, and to determine
the exercise price, duration and other terms of the options to be granted
under the plan; provided that (a) the exercise price of each option granted
under the plan may not be less than the fair market value of the Common Stock
on the date the option is granted (and for incentive stock options, 110% of
fair market value if the employee is the beneficial owner of 10% or more the
Company's voting securities), (b) the exercise price must be paid in cash, by
surrendering previously owned shares of Common Stock upon the exercise of the
option or by a
F-20
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
promissory note or broker-assisted cashless exercise approved by the Board of
Directors, (c) the term of the option may not exceed ten years, and (d) no
option is transferable other than by will, the laws of descent and
distribution or pursuant to a qualified domestic relations order. Limited
stock appreciation rights may be granted under the plan with respect to
specified options, allowing the option holder to receive, in cash, the
difference between the exercise price and the market value in the event of a
change in control of the Company. The Board of Directors may also grant
supplemental bonuses under the plan which are cash bonuses not to exceed the
amount of income tax liability incurred by a plan participant upon the
exercise of a non-qualifying stock option or a limited stock appreciation
right with respect to which the bonus was granted. The Board of Directors may
amend without stockholder approval, in any respect other than any amendment
that requires stockholder approval by law, and may modify any outstanding
option, including the repricing of non-qualifying options, with the consent of
the option holder. There are currently approximately 100 employees who are
eligible to participate in the plan.
During 1996, the Company granted 711,750 stock options pursuant to the
1996 Stock Option Plan, leaving 138,250 options available for future grant
under the plan as of December 31, 1996. The options granted during the year
have a term of ten (10) years and an exercise price of $12.50 per share, a
price equal to the market price on the date of the grant. The fair value, as
calculated under the provision of SFAS 123, of the options granted in 1996 was
$6.73 per share.
The Company applies APB 25 and related Interpretations in accounting for
its stock option awards. Accordingly, no compensation expense has been
recognized for its stock option awards. If compensation expense for the stock
option awards had been determined consistent with SFAS 123, the Company's net
loss and net loss per share, for the year ended December 31, 1996 would have
been adjusted to the following pro forma amounts:
Net loss $(6,285,276)
Net loss per share $ (0.97)
The pro forma net loss and pro forma net loss per share amounts noted
above are not likely to be representative of the pro forma amounts to be
reported in future years. Pro forma adjustments in future years will include
compensation expense associated with the options granted in 1996 plus
compensation expense associated with any options awarded in future years. As
a result, such pro forma compensation expense is likely to be higher than the
levels reflected for 1996 if any options are awarded in future years.
Under SFAS 123, the fair value of each stock option grant is estimated on
the date of grant using the Black-Scholes option pricing model with the
following weighted average assumptions used for grants in 1996:
Risk-free interest rate 6.25%
Expected life 5 years
Expected volatility 54%
Expected dividend yield 0%
(13) RELATED PARTY TRANSACTIONS
Certain members and officers of the Company own interests in and hold
positions with A&P Meter Service and Supply, Inc. ("A&P"), CSL, 511 Tex L.C.
("511 Tex"), and Valley.
Advances from the Company to A&P have been consolidated into two
promissory notes. The first note, which was originally executed December 31,
1994, totals $390,000, including accrued interest of $20,000 at December 31,
1996. The note bears interest at a floating rate equal to the "prime rate"
plus 1.0%. No principal or interest payments are due until the maturity of
the note at December 31, 2004. The note is secured by a second lien on A&P's
accounts receivable, inventory and equipment. The second note is in the
amount of $294,000,
F-21
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
including accrued interest of $47,000, and is dated May 22, 1996. The note
bears interest at 6.0% per annum, is unsecured and is payable upon demand.
During 1996, the Company paid $520,519 to A&P for goods and services
provided. During 1995, the Company paid $612,139 to A&P for goods and
services provided.
During 1996, 1995 and 1994, the Company paid $517,352, $592,920 and
$549,620, respectively, to CSL for management fees and lease payments on
equipment.
During 1996, the Company paid $50,742 to 511 Tex for office rent. During
1995, the Company paid $67,896 to 511 Tex for office rent.
During 1996, 1995 and 1994 the Company paid $484,000, $440,884 and
$2,458, respectively, to Valley for gas compression and salt water disposal
charges. During 1996, Valley paid the Company $383,139 for operating costs
of its salt water disposal wells and gas compressors. During 1995, Valley
paid the Company $109,399 for operating costs of its salt water disposal
wells and gas compressors.
On December 31, 1996, certain officers and related party entities owed
the Company $321,310 plus accrued interest of $1,431. During March
1997, the Company has received full payment for these amounts.
During 1996 and 1995 the LLC paid $75,000 each year to NationsBank
Capital Corp. for management fees. No management fees are due to NationsBank
Capital Corp. for any period subsequent to the Offerings.
(14) SUBSEQUENT EVENTS
On January 1, 1997 Costilla Petroleum Corporation was merged into its
parent, Costilla Energy, Inc. and Costilla Energy, Inc. assumed the business,
assets and liabilities of Costilla Petroleum Corporation. The merger was
effected for administrative purposes and to further reflect the Corporate
Reorganization whereby business will be conducted through the Company rather
than its predecessor, Costilla Energy, L.L.C.
On March 1, 1997 Valley Gathering Company was merged into its parent,
Costilla Energy, Inc. and Costilla Energy, Inc. assumed the business, assets
and liabilities of Valley Gathering Company. The merger was effected for
administrative purposes and to further reflect the Corporate Reorganization
whereby business will be conducted through the Company rather than its
predecessor, Costilla Energy, L.L.C.
On March 5, 1997 Statewide was dissolved. This dissolution was effected
for administrative purposes subsequent to the sale on December 31, 1996 of
substantially all of the assets of Statewide for net proceeds of
approximately $3.0 million. The remaining unsold producing oil and gas
property was transferred to its parent, Costilla Energy, Inc., on December
31, 1996.
On March 6, 1997, the Company sold its 40.5% interest in a Delaware
limited liability company which owns and operates a gas pipeline and
associated facilities in Louisiana. This membership interest had been held
for resale. The Company sold its interest to another member of the limited
liability company for $1,071,150. This amount represented the Company's
actual investment of $1,019,771 plus interest of $51,379 since the date of
the Company's original investment in April, 1996. The effective date of the
sale was the date of the Company's original investment in April, 1996. The
Company received a cash payment of $918,184 on March 6, 1997. In addition,
the Company received a $152,966 note due in full on July 1, 1997 plus
interest at 5.62%.
F-22
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(15) OIL AND GAS EXPENDITURES
The following table reflects costs incurred in oil and gas property
acquisition, exploration and development activities:
YEARS ENDED DECEMBER 31,
------------------------------
1996 1995 1994
------- ------- -------
(THOUSANDS)
Property acquisition costs:
Proved $39,505 $52,470 $ 9,649
Unproved 721 1,742 1,232
Exploration 6,760 5,627 2,167
Development 17,723 158 -
------- ------- -------
$64,709 $59,997 $13,048
------- ------- -------
------- ------- -------
(16) SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The estimates of proved oil and gas reserves, which are located
principally in the United States, were prepared by the Company as of December
31, 1995 and 1994 and by Williamson Petroleum Consultants as of December 31,
1996. Reserves were estimated in accordance with guidelines established by
the SEC and FASB which require that reserve estimates be prepared under
existing economic and operating conditions with no provision for price and
cost escalations except by contractual arrangements. The Company has
presented the reserve estimates utilizing an oil price of $24.17 per Bbl and
a gas price of $3.96 per Mcf as of December 31, 1996 and an oil price of
$17.79 per Bbl and a gas price of $2.03 per Mcf as of December 31, 1995.
OIL AND GAS PRODUCING ACTIVITIES
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and
in the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either
upward or downward revision of previous estimates. Further, the volumes
considered to be commercially recoverable fluctuate with changes in prices
and operating costs. The Company emphasizes that reserve estimates are
inherently imprecise and that estimates of new discoveries are more imprecise
than those of currently producing oil and gas properties. Accordingly, these
estimates are expected to change as additional information becomes available
in the future.
F-23
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND NATURAL
CONDENSATE (MBBLS) GAS (MMCF)
------------------ ----------
Total Proved Reserves:
Balance, January 1, 1993 . . . . . . . . . . . . 1,985 16,418
Revisions of previous estimates . . . . . . . 57 1,160
Extensions and discoveries . . . . . . . . . . 380 591
Production . . . . . . . . . . . . . . . . . . (158) (865)
Purchases of minerals-in-place . . . . . . . . 101 4,315
------ -------
Balance, December 31, 1993 . . . . . . . . . . . 2,365 21,619
Revisions of previous estimates . . . . . . . (460) (5,424)
Extensions and discoveries . . . . . . . . . . 761 1,520
Production . . . . . . . . . . . . . . . . . . (330) (1,600)
Purchases of minerals-in-place . . . . . . . . 1,673 11,397
------ -------
Balance, December 31, 1994 . . . . . . . . . . . 4,009 27,512
Revisions of previous estimates . . . . . . . (570) 425
Extensions and discoveries . . . . . . . . . . 605 8,922
Production . . . . . . . . . . . . . . . . . . (950) (4,806)
Purchases of minerals-in-place . . . . . . . . 7,694 46,099
------ -------
Balance, December 31, 1995 . . . . . . . . . . . 10,788 78,152
Revisions of previous estimates . . . . . . . 1,782 5,440
Extensions and discoveries . . . . . . . . . . 1,169 13,581
Production . . . . . . . . . . . . . . . . . . (1,726) (9,205)
Sales of minerals-in-place . . . . . . . . . . (119) (482)
Purchases of minerals-in-place . . . . . . . . 5,106 32,786
------ -------
Balance, December 31, 1996 . . . . . . . . . . 17,000 120,272
------ -------
------ -------
Proved Developed Reserves:
January 1, 1993. . . . . . . . . . . . . . . . 1,488 10,055
December 31, 1993. . . . . . . . . . . . . . . 1,785 13,268
December 31, 1994. . . . . . . . . . . . . . . 2,632 16,340
December 31, 1995. . . . . . . . . . . . . . . 8,566 57,393
December 31, 1996. . . . . . . . . . . . . . . 14,018 90,023
F-24
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING
TO PROVED OIL AND GAS RESERVES
The standardized measure of discounted future net cash flows is computed
by applying year-end prices of oil and gas (with consideration of price
changes only to the extent provided by contractual arrangements) to the
estimated future production of proved oil and gas reserves less estimated
future expenditures (based on year-end costs) to be incurred in developing
and producing the proved reserves, less estimated future income tax expenses
(based on year-end statutory tax rates, with consideration of future tax
rates already legislated) to be incurred on pretax net cash flows less tax
basis of the properties and available credits, and assuming continuation of
existing economic conditions. The estimated future net cash flows are then
discounted using a rate of 10% per year to reflect the estimated timing of
the future cash flows.
Discounted future cash flow estimates like those shows below are not
intended to represent estimates of the fair value of oil and gas properties.
Estimates of fair value should also consider probable reserves, anticipated
future oil and gas prices, interest rates, changes in development and
production costs and risks associated with future production. Because of
these and other considerations, any estimate of fair value is necessarily
subjective and imprecise.
YEARS ENDED DECEMBER 31,
-----------------------------------
1996 1995 1994
--------- --------- --------
(THOUSANDS)
Future cash flows . . . . . . . . . . . . . . . . . . . $ 887,100 $ 350,653 $122,098
Future costs:
Production. . . . . . . . . . . . . . . . . . . . . . (323,288) (145,510) (46,345)
Development . . . . . . . . . . . . . . . . . . . . . (25,469) (16,806) (7,157)
--------- --------- --------
Future net cash flows before income taxes . . . . . . . 538,343 188,337 68,596
Future income taxes . . . . . . . . . . . . . . . . . . 144,836 - -
--------- --------- --------
Future net cash flows . . . . . . . . . . . . . . . . . 393,507 188,337 68,596
10% annual discount for estimated timing of
cash flows . . . . . . . . . . . . . . . . . . . . . . (165,273) (75,041) (31,817)
--------- --------- --------
Standardized measure of discounted net cash
flows. . . . . . . . . . . . . . . . . . . . . . . . . $ 228,234 $ 113,296 $ 36,779
--------- --------- --------
--------- --------- --------
F-25
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM
PROVED RESERVES (IN THOUSANDS)
YEARS ENDED DECEMBER 31,
-----------------------------
1996 1995 1994
-------- -------- -------
(THOUSANDS)
Increase (decrease):
Purchase of minerals-in place . . . . . . . . . . . . $ 49,966 $ 77,343 $15,231
Extensions and discoveries and improved
recovery, net of future production and
development costs. . . . . . . . . . . . . . . . . . 25,910 9,799 4,072
Accretion of discount . . . . . . . . . . . . . . . . 11,330 3,678 2,638
Net change in sales prices net of production
costs. . . . . . . . . . . . . . . . . . . . . . . . 108,160 (3,422) 503
Changes in estimated future
development costs. . . . . . . . . . . . . . . . . . 4,187 (2,419) 940
Revisions of quantity estimates . . . . . . . . . . . 29,485 (2,855) (7,248)
Net change in income taxes. . . . . . . . . . . . . . (83,570) - -
Sales, net of production costs. . . . . . . . . . . . (32,146) (11,338) (5,286)
Sales of minerals in place. . . . . . . . . . . . . . (1,330) - -
Changes of production rates (timing) and
other. . . . . . . . . . . . . . . . . . . . . . . . 2,946 5,731 (448)
-------- -------- -------
Net increase. . . . . . . . . . . . . . . . . . . . 114,938 76,517 10,402
Standardized measure of discounted future
net cash flows:
Beginning of period. . . . . . . . . . . . . . . . 113,296 36,779 26,377
-------- -------- -------
End of period. . . . . . . . . . . . . . . . . . . $228,234 $113,296 $36,779
-------- -------- -------
-------- -------- -------
The 1996 future cash flows shown above include amounts attributable to
proved undeveloped reserves requiring approximately $24.6 million of future
development costs. If these reserves are not developed, the standardized
measure of discounted future net cash flows for 1996 shown above would be
reduced by approximately $44.4 million.
F-26
EXHIBIT INDEX
Exhibit
Number Description of Exhibit
- ------- ----------------------
*3.1 Certificate of Incorporation of the Company
*3.2 Bylaws of the Company
*4.1 Form of Notes or Global Certificate (included as Exhibit A to the
Indenture)
*4.2 Indenture dated as of October 1, 1996 by and between State Street
Bank and Trust Company, as Trustee, and the Company, as Issuer
**4.3 Form of Stock Certificate
***10.1 Credit Agreement dated October 10, 1996 between NationsBank of
Texas, N.A., as agent, the Lenders named therein and the Company
*10.2 Lease Agreement dated January 12, 1996 between Independence
Plaza, Ltd. and Costilla Energy, L.L.C.
*10.3 Concession Agreement dated July 6, 1995 between the Government of
the Republic of Moldova and Resource Development Company Ltd.,
L.L.C. (DE)
*10.4 Consolidation Agreement dated October 8, 1996
*10.5 1996 Stock Option Plan
*10.6 Outside Directors Stock Option Plan
*10.7 Employment Agreement between the Company and Bobby W. Page
effective June 30, 1996
*10.8 Employment Agreement between the Company and Cadell S. Liedtke
effective October 8, 1996
*10.9 Employment Agreement between the Company and Michael J. Grella
effective October 8, 1996
*10.10 Employment Agreement between the Company and Henry G. Musselman
effective October 8, 1996
*10.11 Purchase and Sale Agreement dated April 3, 1995 by and between
Parker & Parsley Development L.P., Parker & Parsley Producing
L.P. and Parker & Parsley Gas Processing Co., as Seller, and
Costilla Petroleum Corporation and Costilla Energy, L.L.C., as
Purchaser
*10.12 Purchase and Sale Agreement dated March 8, 1996 by and between
Parker & Parsley Development L.P., Parker & Parsley Producing
L.P. and Parker & Parsley Gas Processing Co., as Seller, and
Costilla Petroleum Corporation and Costilla Energy, L.L.C., as
Purchaser
*10.13 Bonus Incentive Plan
***10.14 Letter Agreement dated December 18, 1996 by and between Statewide
Minerals, Inc., as Seller, Boldrick Partners, as Buyer
Exhibit
Number Description of Exhibit
- ------- ----------------------
***10.15 Stock Purchase Agreement dated December 31, 1996 by and between ERI
Investments, Inc. and the Company
***12.1 Computation of Ratio of Adjusted EBITDA to Interest Expense
**16.1 Letter Regarding Change of Accountants
***21.1 Subsidiaries of the Registrant
***23.1 Consent of KPMG Peat Marwick LLP
***23.2 Consent of Williamson Petroleum Consultants, Inc.
***23.3 Consent of Elms, Faris & Co., P.C.
***24.1 Power of Attorney
***24.2 Certified copy of resolution of Board of Directors of Costilla
Energy, Inc. authorizing signature by Power of Attorney
***27.1 Financial Data Schedule
- -------------------
* Incorporated by reference to Registration Statement on Form S-1, File
No. 333-08909
** Incorporated by reference to Registration Statement on Form S-1, File
No. 333-08913.
*** Filed herewith