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Form 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[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
Commission File No. 0-10955
CODA ENERGY, INC.
(Name of Registrant)
State of Delaware 75-1842480
(State of Incorporation) (IRS Employer Identification Number)
5735 PINELAND DRIVE
SUITE 300
DALLAS, TEXAS 75231
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (214) 692-1800
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. ____
As the Company's Common Stock is not traded on a public market, the market
value held by non-affiliates is undeterminable.
As of March 1, 1997, the Registrant had outstanding 913,611 shares of
Common Stock.
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TABLE OF CONTENTS
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Item Page
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PART I
ITEM 1. BUSINESS
General..................................................... 1
Recent Acquisition Activities............................... 2
Oil and Gas Operations...................................... 3
Gas Plants and Gathering System Operations.................. 8
ITEM 2. PROPERTIES
Oil and Gas Reserves........................................ 10
Oil and Gas Operations Data................................. 13
Drilling Activities......................................... 15
Gas Plants and Gathering Systems............................ 16
Other Properties............................................ 17
ITEM 3. LEGAL PROCEEDINGS............................................. 17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS....................................................... 17
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS............................... 18
ITEM 6. SELECTED FINANCIAL DATA....................................... 18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
General..................................................... 19
Results of Operations....................................... 20
Changes in Prices & Hedging Activities...................... 24
Liquidity and Capital Resources............................. 26
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA.......................................................... 31
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE.................................................... 31
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT............ 31
ITEM 11. EXECUTIVE COMPENSATION........................................ 31
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.................................................... 31
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................ 31
The information required by Part III of this report
was filed March 31, 1997 under Form 10K/A No. 1.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
AND REPORTS ON FORM 8-K....................................... 32
SIGNATURES.................................................... 39
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PART I
Item 1. BUSINESS
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GENERAL
Coda Energy, Inc., an independent energy company, is principally engaged in
the acquisition and exploitation of oil and natural gas properties. The Company
also owns and operates natural gas processing and liquids extraction facilities
and natural gas gathering systems. Unless the context otherwise requires, the
term "Registrant" or "Coda" refers to Coda Energy, Inc. only and "Company"
refers to Coda and its subsidiaries. The Company seeks to acquire oil and
natural gas properties whose predominant economic value is attributable to
proved producing reserves and to enhance that value through control of
operations, reduction of costs and development of the properties. The Company's
producing properties are concentrated in the mid-continent region of the United
States. At December 31, 1996, the Company had proved reserves of 43.0 Mmbbls of
oil and 39.0 Bcf of natural gas, aggregating 49.5 Mmboe. Company operated
properties accounted for approximately 93% of its 1996 production of 3.5 Mmboe.
The Company's strategy is to increase oil and natural gas reserves, production
and cash flow by selectively acquiring and exploiting producing oil and natural
gas properties, especially those properties with enhanced recovery and other
lower-risk development potential. The Company's exploitation efforts include,
where appropriate, the drilling of lower-risk development wells, the initiation
of secondary recovery projects, the renegotiation of marketing agreements and
the reduction of drilling, completion and lifting costs. Cost savings may be
principally achieved through reductions in field staff and the more effective
utilization of field facilities and equipment by virtue of geographic
concentration.
As a result of its acquisition and exploitation activities, the Company has
shown significant growth in reserves, production and EBITDA (earnings before
interest, income taxes and depletion, depreciation and amortization and in 1996
before non-cash stock option compensation expense) the last three years. Since
January 1, 1994, the Company has purchased properties for an aggregate cost of
$70.0 million. Proved reserves have increased from 36.1 Mmboe at January 1,
1994 to 49.5 Mmboe at December 31, 1996. The present value of estimated future
net revenues of the Company's proved reserves discounted at 10% has increased
from $217.5 million at December 31, 1994, to $447.9 million at December 31,
1996, while the Company received $107.5 million in oil and gas revenues, net of
operating expenses during that period. Average net daily production has
increased from 9,534 BOE in 1994 to 10,997 BOE for 1996. EBITDA increased at a
37% compound annual growth rate from $27.6 million in 1994 to $52.0 in 1996.
The Company operated 2,009 of the 2,713 gross producing and water injection
wells in which it owned an interest as of December 31, 1996.
On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as of
October 30, 1995 (as amended, the "Merger Agreement"), by and among Coda, Joint
Energy Development Investments Limited Partnership ("JEDI"), which is an
affiliate of Enron Capital & Trade Resources
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Corp. ("ECT"), and Coda Acquisition, Inc. ("CAI"), which was a subsidiary of
JEDI, JEDI acquired Coda through a merger (the "Merger") at a price of $7.75 per
share in cash (for an aggregate purchase price of approximately $176.2 million).
Concurrently with the execution of the Merger Agreement, JEDI and CAI entered
into certain agreements with members of management (the "Management Group"),
providing for a continuing role of management in the Company after the Merger.
Following consummation of the Merger, the Management Group owns approximately 5%
of Coda's common stock on a fully-diluted basis. JEDI owns the remaining 95%.
The Merger has been accounted for using the purchase method of accounting. As
such, JEDI's cost has been allocated to the assets and liabilities acquired
based on estimated fair values. As a result, the financial position and
operating results subsequent to the date of the Merger reflect a new basis of
accounting and are not comparable to prior periods.
The Company was incorporated in 1981 as a Delaware corporation. The Company's
executive offices are located at 5735 Pineland Drive, Suite 300, Dallas, Texas
75231 (telephone: (214) 692-1800). As of December 31, 1996, the Company had
159 full time employees.
FORWARD-LOOKING STATEMENTS
All statements in this document concerning the Company other than purely
historical information (collectively "Forward-Looking Statements") reflect the
current expectation of management and are based on the Company's historical
operating trends, estimates of proved reserves and other information currently
available to management. These statements assume, among other things, (i) that
no significant changes will occur in the operating environment for the Company's
oil and gas properties, gas plants and gathering systems and (ii) that there
will be no material acquisitions or divestitures. The Company cautions that the
Forward-Looking Statements are subject to all the risks and uncertainties
incident to the acquisition, development and marketing of, and exploration for,
oil and gas reserves. These risks include, but are not limited to, commodity
price risk, environmental risk, drilling risk, reserve, operations and
production risks, regulatory risks and counterparty risk. Many of these risks
are described elsewhere herein. The Company may make material acquisitions or
dispositions, enter into new or terminate existing oil and gas sales or hedging
contracts, or enter into financing transactions. None of these can be predicted
with any certainty and, accordingly, are not taken into consideration in the
Forward-Looking Statements made herein. For all of the foregoing reasons,
actual results may vary materially from the Forward-Looking Statements and there
is no assurance that the assumptions used are necessarily the most likely.
RECENT ACQUISITION ACTIVITIES
In February 1997, the Company purchased 123 producing oil and gas properties
from J. M. Huber Corporation for an aggregate purchase price of approximately
$13.1 million, of which $6.5 million was financed under the Company's credit
agreement. The properties are predominately located in Texas, Oklahoma and
Arkansas. The Company estimates the properties have proved reserves of
approximately 1.5 million barrels of oil and 13.0 Bcf of gas.
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OIL AND GAS OPERATIONS
DEVELOPMENT AND EXPLORATION
GENERAL
The Company concentrates on exploiting proved producing properties, including
those with development potential, through workovers, recompletions in other
productive zones, secondary recovery operations, the drilling of development
wells or infill wells and other exploitation techniques. The Company has
conducted or intends to conduct significant secondary recovery/infill drilling
programs on many of its properties.
Secondary recovery projects have represented the Company's primary development
focus over the past four years. Generally, "secondary recovery" refers to
methods of oil extraction in which fluid or gas (usually water, natural gas or
CO\\2\\) is injected into a formation through input (injector) wells, and oil is
removed from surrounding wells. "Waterflooding" is one proven method of
secondary recovery in which water is injected into an oil reservoir for the
purpose of forcing the oil out of the reservoir rock and into the bore of a
producing well. Waterflood projects are engineered to suit the type of
reservoir, depth and condition of the field. The Company has considerable
experience with and actively employs waterflood techniques in many of its fields
in order to stimulate production.
The Company also seeks to exploit its properties through cost reduction
measures, including the reduction of labor, electrical and materials costs. It
seeks to take advantage of volume discounts in the purchase of equipment and
supplies and more effectively utilize field facilities and equipment by virtue
of its geographical concentration. The Company attempts to negotiate more
favorable marketing agreements upon completion of an acquisition, particularly
for oil production. Certain oil purchasers have paid in the past and are
currently paying a premium over posted prices and have eliminated certain
quality and marketing deductions for a portion of the Company's oil production
due to the Company's control over a significant volume of oil production in its
core geographic areas.
The Company has budgeted capital spending of between $15 million and $20
million in 1997. The Company makes only limited investments in exploratory
drilling. Several of the Company's more significant projects are discussed
below.
DEVELOPMENT PROJECTS
CROOKED CREEK PROSPECT - The Company's study of the Cleveland reservoir in the
Crooked Creek prospect began in early 1995. The Company acquired its first
interest in the field in September 1995. Unitization efforts are currently
underway. The leases the Company either owns or has commitments on will give
the Company 74% working interest in the proposed unit.
The proposed Crooked Creek Cleveland Unit ("CCCU") is located in Kingfisher
County, Oklahoma, and contains 4,580 acres. The Company expects the CCCU to be
effective May 1, 1997. Gross development capital expenditures will be
approximately $5.3 million. CCCU will initially have
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six injection wells and 21 producing wells. Additional wells will be converted
to injection as project performance dictates. The Company expects to drill two
wells, convert two wells and install injection facilities during 1997 at a cost
to the Company of approximately $2.4 million.
OAKDALE REDFORK UNIT - In 1989 in its search for attractive secondary recovery
candidates, the Company recognized the waterflood potential of the Red Fork sand
in the Oakdale Field. The Company acquired its first interest in the field in
May 1990 and continued to actively acquire additional interest through the April
1991 unitization and initial development stages of the project. The May 1995
acquisition of a 29.4% interest was the last acquisition of significant interest
in the field. The Company currently has 88.9% working interest in the project.
The 3,560 acre Oakdale Red Fork Unit ("Oakdale") is located in southeastern
Woods County, Oklahoma. The Unit currently has 19 injection wells and 22
producing wells. During December 1996 the average daily production was 1,756
barrels of oil with 766 barrels of water.
The Company's plans for future development include the drilling of eleven
wells over the next three years. Capital expenditures in 1997 are budgeted at
approximately $1.5 million and anticipate the drilling of four wells, converting
five wells and facilities improvements.
ANDREWS UNIT - On January 1, 1993, the Company took over the operations of
three leases in the Andrews Wolfcamp and Penn Fields. The Company recognized
the waterflood potential of these fields and began acquiring offset leases. In
July 1994, the Company purchased a 100% working interest in three adjacent
properties with five active wells. In December 1994, the Company purchased a
100% working interest in two additional leases and a 93.8% working interest in a
third lease. The Company acquired several additional minor leases in 1995. The
last lease was purchased in July of 1996, during unitization of the field.
The Andrews Unit located in Andrews County, Texas contains 3,280 acres.
During the unitization process, the Company obtained approval to consolidate the
two fields into the Wolfcamp/Penn field in August 1995. The Company has a
working interest in 98.58% in Phase I and 97.96% in Phase II.
The Company initiated a waterflood in this field in September 1996. The
capital costs were dramatically reduced by modifying and expanding the existing
injection facilities in the Shafter Lake San Andres Unit. The Andrews Unit
produced 514 barrels of oil and 790 Mcf of gas per day from 25 wells on this
Unit in December 1996. The Company plans to drill one well and convert six
wells in 1997 at a cost to the Company of approximately $1.0 million.
CALUMET COTTAGE GROVE UNIT - In its search for attractive waterflood
candidates, the Company identified the potential of a Cottage Grove waterflood
in the Calumet Field in 1990. The Company acquired its first interest in the
field in May 1991 and continued to actively acquire additional interest through
the unitization and initial development stages of the project. The Company
currently has a 44.1% working interest in the project. Unitization was
accomplished in May 1992.
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The Calumet Cottage Grove Unit ("Calumet") is located in Canadian County,
Oklahoma, and contains 11,400 acres. First injection was in August 1992.
Initial response to injection occurred in December 1992 and peak production of
approximately 3,500 barrels of oil occurred in January 1995. A fracture
stimulation program has maintained Calumet production at approximately 2,900
barrels of oil per day for 1996. Calumet currently has 28 injection wells and
74 producing wells. December 1996 average daily production was 2,744 barrels of
oil with 3,881 barrels of water.
The Company's plans for future development include the drilling of nineteen
wells and the conversion to injection of ten wells over the next four years.
The Company expects to drill four wells, convert nine wells and improve
facilities during 1997 at a cost to the Company of approximately $1.4 million.
SHAFTER LAKE SAN ANDRES UNIT - On January 1, 1993, the Company became the
operator of the Shafter Lake San Andres Unit ("SLSAU") in Andrews County, Texas
by acquiring a 49% working interest in the Unit from the prior operator. This
property was part of a large acquisition made from a major oil company. The
Company has since increased its working interest to over 62% in eleven separate
transactions. The SLSAU was unitized in 1967 and water injection began in 1968
on this 12,720 acre Unit.
When the Company became the operator in January 1993, the SLSAU produced 728
barrels of oil and 150 Mcf of gas per day. In 1993, the Company expanded and
east-west drive waterflood pattern by converting eight wells to water injection.
The Company continued expanding this pattern in 1994, 1995 and 1996 by drilling
27 additional producing wells and converting 26 wells to water injection. In
December 1996, average daily production was 881 barrels of oil and 280 Mcf of
gas from 117 producing wells and 40 injection wells.
The Company has identified 43 additional proven drilling locations as well as
continued secondary response. During 1997, the Company plans to drill six wells
and convert four wells at a cost to the Company of approximately $1.1 million.
MARKETS, COMPETITION AND MARKETING
The oil and natural gas industry is highly competitive. Competitors include
major oil companies, other independent oil and natural gas concerns, and
individual producers and operators, many of which have financial resources,
staffs and facilities substantially greater than those of the Company. In
addition, the Company encounters substantial competition in acquiring oil and
natural gas properties, marketing oil and natural gas and securing trained
personnel. When possible, the Company tries to avoid open competitive bidding
for acquisition opportunities. The principal means of competition with respect
to the sale of oil and natural gas production are product availability and
price. While it is not possible for the Company to state accurately its
position in the oil and natural gas industry, the Company believes that it
represents a minor competitive factor.
Enron Corp. ("Enron") is the parent of ECT and accordingly may be deemed to
control indirectly both JEDI and the Company. Enron and certain of its
subsidiaries and other affiliates collectively
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participate in nearly all phases of the oil and natural gas industry and are,
therefore, competitors of the Company. Because of these various conflicting
interests, ECT, the Company, JEDI and the Management Group have entered into the
Business Opportunity Agreement which is intended to make it clear that Enron and
its affiliates have no duty to make business opportunities available to the
Company in most circumstances. The Business Opportunity Agreement also provides
that ECT and its affiliates may pursue certain business opportunities to the
exclusion of the Company. The Business Opportunity Agreement may limit the
business opportunities available to the Company. In addition, pursuant to the
Business Opportunity Agreement there may be circumstances in which the Company
will offer business opportunities to certain affiliates of Enron. If an Enron
affiliate is offered such an opportunity and decides to pursue it, the Company
may be unable to pursue it.
The market for oil, natural 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, natural
gas and natural gas liquids, the price of imports of oil and natural gas,
weather conditions, the price and availability of alternative fuels, the
proximity and capacity of natural gas pipelines and other transportation
facilities and overall economic conditions. The oil and natural gas industry as
a whole also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual consumers.
With the exception of the operations of Taurus Energy Corp. ("Taurus") (see
"--Gas Plants and Gathering Systems Operations" below), the Company does not
refine or process any of the oil and natural gas it produces. The Company's oil
and natural gas production is sold to various purchasers typically in the areas
where the oil or natural gas is produced. The Company is currently able to
sell, under contract or in the spot market, all of the oil and natural gas it is
capable of producing at current market prices. Substantially all of the
Company's oil and natural gas is sold under short term contracts or contracts
providing for periodic price adjustments or in the spot market; therefore, its
revenue streams are highly sensitive to changes in current market prices.
Certain of the Company's oil purchasers have paid in the past and are currently
paying a premium over posted prices and have eliminated certain quality and
marketing deductions for a portion of the Company's oil production due to the
Company's control over a significant volume of oil production in its core
geographic areas. The Company's principal markets for natural gas are natural
gas processing and marketing companies as opposed to end users.
Oil prices have been subject to significant fluctuations over the past decade.
Levels of production maintained by the Organization of Petroleum Exporting
Countries member nations and other major oil producing countries are expected to
continue to be a major determinant of crude oil price movements in the near
term. The market price for natural gas has fluctuated significantly from month
to month and year to year for the past several years. The Company cannot
predict oil or gas price movements with any certainty.
In an effort to reduce the effects of the volatility of the price of crude oil
and natural gas on the Company's operations, management has adopted a policy of
hedging oil and gas prices, on a portion of the Company's production, whenever
market prices are in excess of the prices anticipated in the Company's operating
budget and profit plan through the use of commodity futures, options and swap
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agreements. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Changes in Prices and Hedging Activities" and Note 11
of Notes to the Company's Consolidated Financial Statements.
During the year ended December 31, 1994, sales of oil and natural gas to Amoco
Production Company and EOTT Energy Operating Limited Partnership ("EOTT"), a
subsidiary of Enron, accounted for 13% and 22%, respectively, of the Company's
consolidated revenues. During the year ended December 31, 1995, sales of oil
and natural gas to Amoco Production Company and EOTT accounted for 10% and 18%,
respectively, of the Company's consolidated revenues. During the 319 day period
ended December 31, 1996, sales of oil and gas to EOTT accounted for 20% of the
Company's consolidated revenues. EOTT is a subsidiary of Enron and an affiliate
of the Company, ECT and ECT Securities, Inc. See "Certain Transactions."
Management believes that in the event this purchaser were to discontinue its
purchases, the Company could quickly locate other buyers and, therefore, the
loss of this purchaser would not have a material impact on the Company's
financial condition or results of operations. However, short term disruptions
could occur while the Company sought alternative buyers.
REGULATION
The Company's operations are affected from time to time in varying degrees by
political develop ments and federal and state laws and regulations. In
particular, oil and gas production operations and economics are or have been
affected by price control, tax and other laws relating to the oil and gas
industry, by changes in such laws and by changing administrative regulations.
Legislation affecting the oil and gas industry is under constant review for
amendment or expansion, frequently increasing the regulatory burden. Also,
numerous departments and agencies, both federal and state, are authorized by
statute to issue and have issued rules and regulations binding on the oil and
gas industry and its individual members, compliance with which is often
difficult and costly and some of which carry substantial penalties for the
failure to comply. The Company cannot predict how existing regulations may be
interpreted by enforcement agencies or court rulings, nor whether amendments or
additional regulations will be adopted, nor what effect such changes may have on
its business or financial condition.
Federal Taxation -- The Federal government is continually proposing tax
initiatives that may affect the oil and gas industry, including the Company.
Due to the preliminary nature of these proposals, the Company is unable to
determine what effect, if any, the proposals would have on product demand or the
Company's results of operations.
Environmental Laws -- The Company's management believes that its present
operations substantially comply with applicable federal and state pollution
control, toxic waste, and environmental protection laws and regulations. The
Company also believes that such laws have had no material effect on the
Company's operations to date, and that the cost of such compliance has not been
material. The discharge of oil, gas or other pollutants into the air, soil or
water may give rise to liabilities to the government and third parties and may
require the Company to incur costs to
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remedy the discharge. The Company does not believe that its environmental risks
are materially different from those of comparable companies in the oil and gas
industry. Nevertheless, no assurance can be given that environmental laws will
not, in the future, adversely affect the Company's operations and financial
condition. Pollution and similar environmental risks generally are not fully
insurable.
State Regulation -- The various states in which the Company conducts
activities regulate the drilling, operation and production of oil and gas wells,
such as the method of developing new fields, spacing of wells, the prevention
and clean-up of pollution, and maximum daily production allowables based on
market demand and conservation considerations.
CERTAIN RISK FACTORS RELATING TO THE OIL AND GAS INDUSTRY
During the last few years, the oil and gas industry has been affected by
variations in supplies of crude oil and natural gas, which has tended to result
in significant fluctuations in oil and natural gas prices and created difficulty
in estimating future prices for such products. The Company is unable to predict
the future stability or direction of either oil or natural gas prices.
The Company's oil and gas business is subject to all of the operating risks
normally associated with the exploration for and production of oil and gas,
including blowouts, cratering, pollution and fires, each of which could result
in damage to or destruction of oil and gas wells, formations, production
facilities or properties, or in personal injury. In accordance with customary
industry practices, the Company maintains insurance coverage limiting financial
loss resulting from certain of these operating hazards. Losses and liabilities
arising from uninsured or underinsured events could reduce revenues and increase
costs to the Company.
GAS PLANTS AND GATHERING SYSTEM OPERATIONS
On April 29, 1994, the Company acquired by merger all of the issued and
outstanding common stock of Taurus, in exchange for 1,500,000 shares of Coda's
common stock, valued at approximately $7.3 million, and $3.25 million cash.
Coda assumed existing Taurus indebtedness of approximately $9.75 million.
Taurus operates three natural gas processing facilities and owns interests in
approximately 700 miles of natural gas gathering systems primarily located in
west central Texas.
In July 1994, Taurus acquired ownership of the Shackelford gas processing
plant and gathering system ("Shackelford"). Taurus had previously been
operating the system and plant under operating leases. The plant is a 30,000
MCF per day capacity refrigerated lean oil absorption plant located near Putnam,
Texas. In related transactions, Taurus entered into an agreement to sell 10,000
MMBTU per day to the former owner of Shackelford for a period of 48 months.
Simultaneously, Taurus entered into a gas purchase agreement with an unrelated
third party for similar quantities over the same term. Pricing under both the
gas sales agreement and the gas purchase agreement is structured to allow Taurus
to earn a margin on all volumes sold. These contracts will not be renewed when
they expire in July 1998. For the year ended December 31, 1996, Taurus received
net proceeds under these contracts of approximately $1 million.
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In January 1995, Taurus acquired the remaining 42% interest in the Hamlin gas
gathering system and gas processing plant ("Hamlin"). The Hamlin gathering
system consists of about 450 miles of low pressure gathering lines and twelve
compressor stations in Fisher, Cottle, Taylor, Stonewall, Jones, Haskell, King
and Knox Counties, Texas. The Hamlin plant utilizes a cryogenic process and has
a processing capacity of 20,000 Mcf per day. Gas supply to the system consists
almost entirely of high BTU casinghead gas. The Hamlin plant produces a
demethanized stream which is delivered into a products pipeline.
The following table shows certain financial data related to Taurus' gas
gathering and processing operations, by source, for the periods indicated.
<TABLE>
<CAPTION>
==============================================================================================
TAURUS ENERGY CORP.
REVENUES
(in thousands)
==============================================================================================
| Pro forma
47 days | 319 days year
ended | ended ended
Year ended December 31, February 16, | December 31, December 31,
----------------------- ------------ | ------------- ------------
(Unaudited) | (Unaudited)
1994 1995 1996 | 1996 1996
----------- ---------- ------------ | ------------ -------------
<S> <C> <C> <C> | <C> <C>
Gas Sales $12,261 $21,038 $3,487 | $25,243 $28,730
|
Natural Gas |
Liquids Sales 7,771 14,597 1,862 | 14,283 16,145
|
Operating |
Margin 2,724 5,161 755 | 6,728 7,483
- ----------------------------------------------------------------------------------------------
</TABLE>
Sales and markets -- Taurus' two largest plants and gathering systems,
Shackelford and Hamlin (See Item 2. Properties - GAS PLANTS AND GATHERING
SYSTEMS), account for the majority of Taurus' revenue.
Taurus sells its residue gas from Shackelford to a variety of large gas
purchasers under short-term contracts at market sensitive prices. Residue gas
from Shackelford can be delivered into either one of two major pipeline systems.
These connections provide significant marketing flexibility by giving access to
major marketing hubs in East Texas, West Texas and the Gulf Coast. Major gas
consuming markets in California, the Midwest, the Northeast as well as along the
Texas Gulf Coast can be accessed through these market hubs. Generally residue
gas is sold under short-term contracts either at the tailgate of the Shackelford
plant or out of the intrastate pipeline.
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The Shackelford plant produces a demethanized stream which is delivered
into a products pipeline. Ethane and natural gasoline components of the product
stream are generally sold as they enter the pipeline. The remaining components
of the product stream are then sold under short-term agreements to various
customers at a central marketing point in Mont Belvieu, Texas. A transportation
and fractionation fee is paid on all gallons not sold to the pipeline owner.
Residue gas from Hamlin can be delivered into either Palo Duro Pipeline or
Lone Star Gas Pipeline. These connections afford the Company the opportunity to
offer residue gas from both Hamlin and Shackelford as a package which increases
the marketing flexibility and leverage of both plants. Since assuming operation
of Hamlin, all residue gas has been sold under short-term contracts at market
sensitive prices to a variety of large purchasers.
The Hamlin plant produces a demethanized stream which is delivered into a
products pipeline. All of Hamlin's liquids production is being sold under
agreements that provide for market index prices less a transportation and
fractionation fee.
Purchases -- Taurus purchases gas for Shackelford from approximately 250
wells in Shackelford, Callahan, Stephens and Throckmorton Counties. The majority
of the production connected to the gathering system is low volume casinghead
gas. The system is operated at low pressure with lateral line pressures ranging
from 15 to 150 psi. The mainline pressure averages about 300 psi.
Taurus utilizes two base forms of gas purchase agreements: percentage of
proceeds and fixed price. Percentage contracts provide that the seller is
allocated its proportionate share of residue gas sales and natural gas liquids
production. Fixed price contracts, which generally provide for acreage
dedications, are for primary terms of up to twenty years with annual renewals
thereafter. The purchase price to be paid is stated in the contract and is
subject to annual price redetermination if certain specific conditions are met.
The gas connected to Shackelford is purchased primarily under percentage of
proceeds contracts with some fixed price contracts. The majority of the gas
connected to Hamlin is being purchased utilizing percent of proceeds contracts.
There are about 200 gas purchase agreements covering over 450 wells connected to
Hamlin.
Item 2. PROPERTIES
----------
OIL AND GAS RESERVES
For certain information concerning the Company's oil and gas reserves and
estimates of future net revenues attributable thereto, see Note 14 of the Notes
to Consolidated Financial Statements which comprise a part of this Annual Report
on Form 10-K.
10
<PAGE>
GENERAL
The following tables summarize certain information regarding the estimated
proved oil and gas reserves as of December 31, 1994, 1995, and 1996. Such
estimated reserves and future net revenues, as set forth herein and in Note 14
of Notes to Consolidated Financial Statements which accompany this report, are
based upon reports prepared by Lee Keeling and Associates, Inc., independent
consulting petroleum engineers. All such reserves are located in the United
States. All reserves are evaluated at contract temperature and pressure which
can affect the measurement of natural gas reserves.
Reserve estimates are imprecise and may be expected to change as additional
information becomes available. Furthermore, estimates of oil and gas reserves,
of necessity, are projections based on engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
way, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Accordingly, there can be no assurance that the reserves set forth herein will
ultimately be produced nor can there be assurance that the proved undeveloped
reserves will be developed within the periods anticipated. The Company
emphasizes with respect to the estimates prepared by independent petroleum
engineers that the discounted future net cash inflows should not be construed as
representative of the fair market value of the proved oil and gas properties
belonging to the Company, since discounted future net cash inflows are based
upon projected cash inflows which do not provide for changes in oil and gas
prices nor for escalation of expenses and capital costs. The meaningfulness of
such estimates is highly dependent upon the accuracy of the assumptions upon
which they were based. For further information, see Note 14 of Notes to
Consolidated Financial Statements.
11
<PAGE>
PROVED OIL AND GAS RESERVES
The following table sets forth proved reserves considered to be
economically recoverable under normal operating methods and existing conditions,
at prices and operating costs prevailing at the date thereof.
<TABLE>
<CAPTION>
==========================================================================
PROVED OIL AND GAS RESERVES
(000's omitted)
==========================================================================
December 31,
---------------------------------------------------
1994 1995 1996
--------------- --------------- ---------------
Oil Gas Oil Gas Oil Gas
(Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf)
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Proved Developed
Reserves........... 20,151 32,890 25,877 31,496 33,895 33,255
Proved Undeveloped
Reserves........... 19,056 6,918 16,713 5,634 9,142 5,790
------ ------ ------ ------ ------ ------
Total Proved
Reserves........... 39,207 39,808 42,590 37,130 43,037 39,045
====== ====== ====== ====== ====== ======
- --------------------------------------------------------------------------
</TABLE>
Definition of Reserves -- The reserve categories are summarized as follows:
Proved developed reserves are those quantities of crude oil, natural gas
and natural gas liquids which, upon analysis of geological and engineering data,
are expected with reasonable certainty to be recoverable in the future from
known oil and gas reservoirs under existing economic and operating conditions.
This classification includes: (a) proved developed producing reserves which are
those expected to be recovered from currently producing zones under continuation
of present operating methods; and (b) proved developed non-producing reserves
which consist of (i) reserves from wells which have been completed and tested
but are not yet producing due to lack of market or minor completion problems
which are expected to be corrected, and (ii) reserves currently behind the pipe
in existing wells which are expected to be productive due to both the well log
characteristics and analogous production in the immediate vicinity of the well.
Proved undeveloped reserves are those reserves which may be expected
either from existing wells that will require a major expenditure to develop or
from undrilled acreage adjacent to productive units which are reasonably certain
of production when drilled.
No major discovery or other favorable or adverse event is believed to have
caused a significant change in these estimates of the Company's proved reserves
since January 1, 1997.
12
<PAGE>
Except for Form EIA 23, "Annual Survey of Domestic Oil and Gas Reserves",
filed with the United States Department of Energy, no other estimates of total
proven net oil and gas reserves have been filed by the Company with, or included
in any report to, any United States authority or agency pertaining to the
Company's individual reserves since the beginning of the Company's last fiscal
year. Reserves reports in Form EIA 23 are comparable to the reserves reported by
the Company herein.
OIL AND GAS OPERATIONS DATA
The following table sets forth the total gross and net productive wells in
which the Company owned an interest as of December 31, 1996. The oil well
category includes 506 gross and 382 net active water injection and utility wells
which are necessary for the operation of the Company's waterflood projects.
<TABLE>
<CAPTION>
============================================
PRODUCTIVE WELLS
============================================
Gross/1/ Net/1/
------------ ------------
Oil Gas Oil Gas
----- --- ----- ---
<S> <C> <C> <C> <C>
Texas 2,376 17 1,802 9
Oklahoma 254 17 155 6
Kansas 67 6 62 4
Other 5 -- 1 --
----- --- ----- ---
2,673 40 2,020 19
===== === ===== ===
--------------------------------------------
</TABLE>
/1/ The number of gross wells is the total number of wells in which a
fractional working interest is owned. The number of net wells is the sum
of the fractional working interests owned by the Company in gross wells.
Includes wells with multiple completions.
The following table shows the net production attributable to the Company's
oil and gas interests, the average sales price per barrel of oil and Mcf of
natural gas and the average production and depletion, depreciation and
amortization expenses attributable to the Company's oil and gas production for
the periods indicated.
13
<PAGE>
<TABLE>
<CAPTION>
================================================================================================
PRODUCTION ECONOMICS
================================================================================================
| Pro forma
47 days | 319 days year
Year ended December 31, ended | ended ended
----------------------- February 16, | December 31, December 31,
1994 1995 1996 | 1996 1996/1/
----------- ---------- ------------ | ------------ -------------
<S> <C> <C> <C> | <C> <C>
Oil and Gas Production |
- ---------------------- |
Oil (MBbls) 2,650 3,165 405 | 2,974 3,379
Natural Gas (MMcf) 4,982 4,416 500 | 3,310 3,810
|
Average Sales Prices/2/ |
- ----------------------- |
Oil (Per Bbl) $15.86 $17.08 $17.57 | $20.58 $20.22
Natural Gas (Per Mcf) 1.74 1.57 1.82 | 2.28 2.22
|
Average Production Cost/3/ |
- -------------------------- |
Per BOE/4/ $6.22 $6.95 $7.34 | $8.11 $8.01
Per dollar of sales .43 .44 .44 | .42 .42
|
Depletion, Depreciation |
- ----------------------- |
and Amortization |
---------------- |
Per BOE/4/ $4.27 $4.33 $4.40 | $5.89 $5.90
Per dollar of sales .29 .28 .27 | .30 .31
- ------------------------------------------------------------------------------------------------
</TABLE>
1 See Notes 1 and 2 of Notes to Consolidated Financial Statements
2 Before deduction of production taxes and net of hedging results for the
periods shown.
3 Excludes depletion, depreciation and amortization. Production cost
includes lease operating expenses and production and ad valorem taxes, if
applicable.
4 Gas production is converted to equivalent barrels of oil at the rate of
six Mcf of natural gas per barrel, representing the estimated relative energy
content of natural gas and oil.
14
<PAGE>
DRILLING ACTIVITIES
The following tables set forth the results of the Company's drilling
activities (wells completed or abandoned as of fiscal period end) for the
periods covered. In January and February 1997, the Company drilled one well.
There were no wells drilled during the 47-day period ended February 16, 1996.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------
DRILLING ACTIVITIES
- --------------------------------------------------------------------
319 days
Year ended December 31, ended
---------------------------------- December 31,
1994 1995 1996
---------------- ---------------- ----------------
Gross/1/ Net/1/ Gross/1/ Net/1/ Gross/1/ Net/1/
-------- ------ -------- ------ -------- ------
<S> <C> <C> <C> <C> <C> <C>
Exploratory:
Oil -- -- -- -- -- --
Gas 1 0.38 2 0.75 -- --
Dry -- -- -- -- -- --
-- ----- --- ----- -- --
Total 1 0.38 2 0.75 -- --
== ===== === ===== == ==
Development:
Oil 26 12.07 109 98.88 17 15
Gas -- -- -- -- 4 2
Dry -- -- -- -- -- --
-- ----- --- ----- -- --
Total 26 12.07 109 98.88 21 17
== ===== === ===== == ==
Total:
Oil 26 12.07 109 98.88 17 15
Gas 1 0.38 2 0.75 4 2
Dry -- -- -- -- -- --
-- ----- --- ----- -- --
Total 27 12.45 111 99.63 21 17
== ===== === ===== == ==
- --------------------------------------------------------------------
</TABLE>
1 The number of gross wells is the total number of wells in which a fractional
working interest is owned. The number of net wells is the sum of the
fractional working interests owned in gross wells expressed in whole numbers
and decimal fractions thereof.
For purposes of the table above an "exploratory well" is a well drilled to
find and produce oil or gas in an unproved area, to find a reservoir in a field
previously found to be productive of oil or gas in
15
<PAGE>
another reservoir or to extend a known reservoir. A "development well" is a
well drilled within the proven boundaries of an oil or gas reservoir with the
intention of completing the stratigraphic horizon known to be productive. A
"dry well" is an exploratory or development well found to be incapable of
producing either oil or gas in sufficient quantities to justify completion as an
oil or gas well.
DEVELOPED AND UNDEVELOPED ACREAGE
The following table sets forth the approximate gross and net acres of
productive properties in which the Company owned a leasehold interest as of
December 31, 1996. "Gross" acres refers to the total acres in which the Company
has a working interest, and "net" acres refers to the fractional working
interests owned by or attributable to the Company multiplied by the gross acres
in which the Company has a working interest. Developed acreage is that acreage
spaced or assignable to productive wells. Undeveloped acreage is considered to
be that 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 or not such acreage contains proved reserves. At December
31, 1996, the Company had no significant amount of undeveloped acreage.
<TABLE>
<CAPTION>
===========================
LEASEHOLD ACREAGE
===========================
Developed
---------------
Gross Net
------- ------
<S> <C> <C>
Texas 48,273 24,940
Oklahoma 95,315 54,492
Kansas 16,359 13,872
Other 5,317 1,817
------- ------
Total 165,264 95,121
======= ======
---------------------------
</TABLE>
Essentially all of the Company's oil and gas interests are leasehold working
interests or overriding royalty interests under standard on-shore oil and gas
leases, rather than mineral or fee interests.
GAS PLANTS AND GATHERING SYSTEMS
Taurus owns and operates three natural gas processing facilities and owns
approximately 700 miles of natural gas gathering systems primarily located in
west central Texas. One of the plants was acquired in 1991 and is not
significant in size. The other two plants are discussed below.
In July 1994, Taurus acquired ownership of Shackelford, which previously had
been operated by Taurus under operating leases for approximately five years.
Shackelford consists of approximately
16
<PAGE>
250 miles of pipeline located in Shackelford, Callahan, Stephens and
Throckmorton Counties, Texas. The plant is a 30,000 MCF per day capacity
refrigerated lean oil absorption plant located near Putnam, Texas. The
Shackelford plant produces a demethanized stream which is delivered into a
products pipeline. The steel gathering lines range in size from 3 inches to 10
inches in diameter. There are over 100 purchase, check and sales meters. The
system utilizes 20 compressors with over 4,500 total horse power.
In January 1995, Taurus acquired the remaining 42% interest in the Hamlin.
The Hamlin gathering system consists of about 450 miles of low pressure
gathering lines and twelve compressor stations in Fisher, Stonewall, Jones,
Haskell, King and Knox Counties, Texas. The Hamlin plant utilizes a cryogenic
process and has a processing capacity of 20,000 MCF per day. Gas supply to the
system consists almost entirely of high BTU casinghead gas. The Hamlin plant
produces a demethanized stream which is delivered into a products pipeline.
OTHER PROPERTIES
The Company owns or has interests in numerous oil and gas production
facilities relating to its oil and gas production operations. In addition, the
Company owns or leases office space and other properties for its operations.
In December 1992, the Company purchased a building in Dallas, Texas,
containing approximately 65,000 square feet to serve as its corporate
headquarters. The Company currently occupies approximately two-thirds of the
office space and has made the balance available for lease.
Item 3. LEGAL PROCEEDINGS
-----------------
The Company is a defendant or codefendant in minor lawsuits that have arisen
in the ordinary course of business. The Company does not expect any of these to
have a material adverse effect on the Company's consolidated financial position.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
---------------------------------------------------
Not Applicable.
17
<PAGE>
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
---------------------------------------------------------------------
Not Applicable
Item 6. SELECTED FINANCIAL DATA
-----------------------
The following table sets forth for the period indicated selected historical
and pro forma financial data of the Company. The selected historical financial
data as of and for the five periods ended December 31, 1996 have been derived
from the historical financial statements of the Company, which were audited by
Ernst & Young LLP, independent auditors. The selected financial data as of
and for the period ended February 16, 1996 has been derived from the unaudited
consolidated financial statements of the Company. The pro forma selected
financial data is derived from the pro forma information contained in the
Company's Consolidated Financial Statements (Notes 1 and 2) included elsewhere
herein.
The Selected Financial Data reflects revenues and earnings since the of
acquisition of various assets that materially affect comparability with prior
years. See Note 4 of Notes to Consolidated Financial Statements.
As a result of the Merger Agreement, JEDI acquired Coda effective February 1,
1996. The Merger has been accounted for using the purchase method of
accounting. As such, JEDI's cost of acquiring Coda has been allocated to the
assets and liabilities acquired based on estimated fair values. As a result,
the Company's financial position and operating results subsequent to the date of
the Merger reflect a new basis of accounting and are not comparable to prior
periods.
On September 30, 1994, the Company acquired by merger all of the issued and
outstanding stock of Diamond Energy Operating Company and Diamond A Inc.
(collectively, "Diamond"). The merger with Diamond has been accounted for as a
pooling of interests. Accordingly, the merger of the equity interests has been
given retroactive effect in the accompanying data for periods prior to the
merger to represent the combined activities of the previously separate entities.
18
<PAGE>
The information below should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements and the notes thereto, included elsewhere
in this report.
<TABLE>
<CAPTION>
===========================================================================================================================
SELECTED FINANCIAL DATA (IN THOUSANDS)
===========================================================================================================================
Predecessor | Successor
----------------------------------------------------------------------------------------
Year Year Year Year 47 days | 319 days Pro forma
ended ended ended ended ended | ended year ended
12/31/92 12/31/93 12/31/94 12/31/95 2/16/96 | 12/31/96 12/31/96/(1)/
--------- --------- --------- --------- -------- | --------------- -------------
<S> <C> <C> <C> <C> <C> | <C> <C>
Revenues $ 23,637 $ 40,050 $ 71,586 $ 97,838 $ 13,569 | $ 110,382 $ 123,951
Income (loss) available for |
common stockholders (734) 2,334 3,329 5,755 (1,298) | (51,027)/(2)/ 1,278
Total assets at end of period 82,226 132,754 203,102 229,064 226,266 | 295,570 295,570
Long-term debt at end of period 56,563 59,651 105,063 123,907 122,290 | 174,966 174,996
15% cumulative preferred stock --- --- --- --- --- | 20,000 20,000
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
/(1)/ Reflects the pro forma effect of the Merger, the sale of the Notes
and the application of the proceeds thereof to retire $100 million
of debt to JEDI and pay down a portion of the outstanding borrowings
under the Company's credit facility. See Notes 1 and 2 of Notes to
Consolidated Financial Statements. The pro forma results of
operations exclude a charge of approximately $53.3 million (net of
related deferred taxes of $30.0 million) representing the adjustment
of the carrying value of proved oil and gas properties pursuant to
the full cost method of accounting.
/(2)/ Includes a charge of $53.3 million (net of related deferred taxes of
$30.0 million) for the writedown of oil and gas properties.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
-----------------------------------------------------------------------
OF OPERATIONS
-------------
The Company is an independent energy company principally engaged in the
acquisition and exploitation of producing oil and natural gas properties. The
Company also owns and operates natural gas processing and liquids extraction
facilities and natural gas gathering systems. Coda seeks to acquire properties
whose predominant economic value is attributable to proved producing reserves
and to enhance that value through control of operations, reduction of costs and
development of properties.
19
<PAGE>
The Company's principal strategy is to increase oil and natural gas reserves
and cash flow by selectively acquiring and exploiting producing oil and natural
gas properties, especially those properties with enhanced recovery and other
lower risk development potential. Coda's exploitation efforts include, where
appropriate, the drilling of lower risk development wells, the initiation of
secondary recovery projects, the renegotiation of marketing agreements and the
reduction of drilling, completion and lifting costs. Cost savings may be
principally achieved through reductions in field staff and the more effective
utilization of field facilities and equipment by virtue of geographic
concentration.
The Company expects to continue its efforts to acquire additional oil and
natural gas properties. Future acquisitions, if any, would necessitate, in most
cases, borrowing additional funds under the Company's credit facility. The
ability to borrow such funds is dependent upon the Company's borrowing base from
time to time and the effect upon the borrowing base under the Credit Agreement.
On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as of
October 30, 1995 (as amended, the "Merger Agreement"), by and among Coda, Joint
Energy Development Investments Limited Partnership ("JEDI"), which is an
affiliate of Enron Capital & Trade Resources Corp. ("ECT"), and Coda
Acquisition, Inc. ("CAI"), which was a subsidiary of JEDI, JEDI acquired Coda
through a merger (the "Merger") at a price of $7.75 per share in cash (for an
aggregate purchase price of approximately $176.2 million). The Merger has been
accounted for using the purchase method of accounting. As such, JEDI's cost of
acquiring Coda has been allocated to the assets and liabilities acquired based
on estimated fair values. As a result, the Company's financial position and
operating results subsequent to the date of the Merger reflect a new basis of
accounting and are not comparable to prior periods.
RESULTS OF OPERATIONS
The following table sets forth certain operating data regarding the production
and sales volumes, average sales prices, and costs associated with the Company's
oil and gas operations and gas gathering and processing operations for the
periods indicated.
20
<PAGE>
<TABLE>
<CAPTION>
Pre-Merger | Post Merger
---------------------------------------------------------
Year Ended 47 Days | 319 Days Pro Forma
-------------------------- Ended | Ended Year Ended
December 31, December 31, February 16, | December 31, December 31,
1994 1995 1996 | 1996 1996
------------ ------------ ------------ | ------------ ------------
<S> <C> <C> <C> | <C> <C>
OIL AND GAS OPERATING DATA: |
Net production: |
Oil (MBbls) 2,650 3,165 405 | 2,974 3,379
Gas (MMcf) 4,982 4,416 500 | 3,310 3,810
|
Average sales price: |
Oil (per Bbl) $15.86 $17.08 $17.57 | $20.58 $20.22
Gas (per Mcf) $1.74 $1.57 $1.82 | $2.28 $2.22
|
Average production cost |
per BOE $6.22 $6.95 $7.34 | $8.11 $8.01
|
GAS GATHERING AND PROCESSING OPERATING DATA: |
Sales: |
Gas sales (MMBTU) 6,725 13,356 1,555 | 10,768 12,323
Gas sales average price $1.82 $1.58 $2.24 | $2.34 $2.33
Natural gas liquids sales |
(Mgallons) 26,193 53,284 5,868 | 37,957 43,825
Natural gas liquids |
average price $.2967 $.2739 $.3127 | $.3763 $.3684
|
Costs and expenses (in thousands): |
Gas purchases $15,121 $26,547 $4,060 | $29,177 $33,237
Plant operating $2,203 $3,926 $507 | $3,648 $4,155
</TABLE>
COMPARISON OF THE YEARS ENDED DECEMBER 31, 1995 (HISTORICAL) AND 1996 (PRO
FORMA)
The unaudited pro forma combined information was prepared as if the
Merger and the issuance of $110.0 million of 10 1/2% Senior Subordinated Notes
(the "Notes") had occurred on January 1, 1996. The unaudited pro forma
information was prepared by combining the two 1996 periods and giving effect to
adjustments affecting (i) depletion, depreciation and amortization, (ii)
interest expense, (iii) income taxes and (iv) certain other costs resulting from
the Merger as more fully outlined in Notes 1 and 2 of the Notes to Consolidated
Financial Statements. The comparisons below compare the unaudited pro forma
combined information to historical information for 1995.
Oil and gas sales for the year ended December 31, 1996, increased 26%
to approximately $76.8 million from approximately $61.0 million in the
comparable period in 1995 primarily due to a 7% increase in oil production and
an increase of $3.14 per barrel and $.65 per Mcf in the average sales price of
oil and gas, respectively. The increase in production is a result of the
acquisition of producing oil and gas properties in the fourth quarter of 1995,
the Company's development drilling program and
21
<PAGE>
favorable responses from certain of the Company's waterflood units. This
increase was partially offset by a 14% decrease in gas production due primarily
to sales of properties and natural production declines. During the year ended
December 31, 1996, 89% of oil and gas sales was attributable to oil production.
Oil and gas prices remain unpredictable. See "- Changes in Prices and Hedging
Activities" below.
Gas gathering and processing revenues for the year ended December 31,
1996 increased 26% to approximately $44.9 million from approximately $35.6
million in the comparable period in 1995 primarily due to a 47% and a 35%
increase in the average sales price for natural gas and natural gas liquids,
respectively. This increase was partially offset by an 18% decrease in natural
gas liquids volumes due to reduced plant throughput volumes as a result of the
termination of a gas purchase contract in January 1996 and production declines.
Other income for the year ended December 31, 1996 increased 91% to
approximately $2.3 million from approximately $1.2 million for the same period
in 1995 primarily due to an increase in interest income of $382,000 from the
investment of higher available cash balances and gains on sales of marketable
securities of $701,000.
Oil and gas production expenses (including production taxes) for the
year ended December 31, 1996 increased 19% to approximately $32.2 million from
approximately $27.1 million for the same period in 1995, reflecting the effects
of the increased production from the properties acquired in 1995 and from new
wells drilled. Oil and gas production expenses for the year ended December 31,
1996 were $8.01 per BOE and are expected to remain near this level for 1997.
Gas gathering and processing expenses for the year ended December 31,
1996 increased 23% to approximately $37.4 million from approximately $30.5
million in the comparable period in 1995 due primarily to an increase in the
purchase price paid to producers. Gas gathering and processing purchases
usually fluctuate in ratio with gas gathering and processing revenues.
Pro forma depletion, depreciation and amortization expense for the
year ended December 31, 1996, increased 39% to approximately $27.4 million from
approximately $19.7 million for the historical period in 1995 reflecting the
increase in the carrying value of the Company's assets as a result of the
Merger, the increase in oil production from acquisitions in 1995 and property
development. Oil and gas depletion, depreciation and amortization expense
increased from $4.33 per BOE for the year ended December 31, 1995, to $5.90 per
BOE on a pro forma basis for the year ended December 31, 1996. The Company
anticipates that the depletion, depreciation and amortization rate per BOE will
be approximately $5.75 for 1997 absent significant additional acquisitions or
significant reserve revisions.
General and administrative expenses for the year ended December 31,
1996 decreased 17% to approximately $2.4 million from approximately $2.9 million
in the comparable period in 1995. This is primarily due to increased overhead
charges billed to working interest owners on the properties acquired in 1995,
being partially offset by additional employees needed as a result of
acquisitions of
22
<PAGE>
oil and gas properties. The Company expects base general and administrative
expenses, net of overhead recoveries, to remain near this level, absent
significant additional acquisitions.
Pro forma interest expense for the year ended December 31, 1996
increased 96% to approximately $17.0 million from approximately $8.7 million for
the historical period in 1995, primarily due to increases in outstanding debt
levels as a result of the Merger which reduced the Company's bank debt by
approximately $37.0 million, but added $110.0 million of senior subordinated
debt bearing interest at 10 1/2%. Also contributing to the increase were
amounts borrowed during 1995 to fund development drilling and property
acquisitions which would have been outstanding for a full year in 1996.
The historical results of operations for the period ended February 16,
1996, include approximately $3.2 million of stock option compensation expense as
a result of the replacement of certain outstanding options and warrants with new
options subject to a lower exercise price. The historical results for the
period ended December 31, 1996 include a writedown of oil and gas properties of
approximately $83.3 million to the full cost pool ceiling based on product
prices at the date of the Merger.
Pro forma net income for the year ended December 31, 1996, was
approximately $4.5 million compared to approximately $5.8 million for the
historical period in 1995. This decrease resulted primarily from increases in
depletion, depreciation and amortization and interest expense as a result of the
Merger partially offset by an increase in oil production and higher oil and
natural gas prices.
COMPARISON OF THE YEARS ENDED DECEMBER 31, 1994 AND 1995
Oil and natural gas sales for the year ended December 31, 1995
increased 20% to approximately $61.0 million from approximately $50.7 million in
1994 primarily due to a 19% increase in oil production and an increase of $1.22
per barrel in the average sales price for oil. The increase in production was a
result of the acquisition of producing oil and natural gas properties during the
fourth quarters of 1994 and 1995, the Company's development drilling program and
favorable responses from certain of the Company's waterflood units. This
increase was partially offset by an 11% decrease in natural gas production (due
primarily to sales of properties) and a decrease in the average sales price for
natural gas of $0.17 per Mcf. During the year ended December 31, 1995, 89% of
oil and natural gas sales was attributed to oil production. Oil and natural gas
prices remain unpredictable. See "--Changes in Prices and Hedging Activities."
As a result of the acquisition of Taurus on April 29, 1994, gas
gathering and processing revenues, expenses and gross profit increased
significantly for the year ended December 31, 1995, compared to 1994. The year
ended December 31, 1994 only included eight months of Taurus' operations.
Contributing to the increases in revenues and expenses was the acquisition in
January 1995 of the remaining ownership interest in one of Taurus' gas plants
and associated facilities for $6.5 million, The levels of revenues and expenses
attributed to Taurus' operations are largely dependent on natural gas and
natural gas liquids prices and plant throughput volumes and, therefore, may
fluctuate significantly.
23
<PAGE>
Oil and natural gas production expenses (including production taxes)
for the year ended December 31, 1995 increased 25% to approximately $27.1
million from approximately $21.6 million for 1994, reflecting the effects of the
increased production from the properties acquired in 1994 and from new wells
drilled. Oil and natural gas production expenses for the year ended December
31, 1995 were $6.95 per BOE.
Depletion, depreciation and amortization expense for the year ended
December 31, 1995 increased 20% to approximately $19.7 million from
approximately $16.4 million for 1994, reflecting the increase in oil production
from acquisitions in 1994, property development and the acquisition of Taurus in
April 1994. The increase attributable to Taurus was approximately $1.2 million.
Oil and natural gas depletion, depreciation and amortization expense increased
to $4.33 per BOE for the year ended December 31, 1995 from $4.27 per BOE for
1994. The increase reflects the relatively higher purchase price of the
reserves related to the properties acquired during 1994.
General and administrative expenses for the year ended December 31,
1995 decreased to approximately $2.9 million from approximately $3.1 million for
1994. This decrease was primarily due to increased overhead charges billed to
working interest owners on the properties acquired during the fourth quarter of
1994 and 1995, being partially offset by additional employees needed as a result
of acquisitions of oil and natural gas properties and the acquisition of Taurus.
Interest expense for the year ended December 31, 1995 increased 64% to
approximately $8.7 million from approximately $5.3 million for 1994, primarily
due to increases in outstanding debt levels used to fund development drilling,
oil and natural gas property acquisitions and the acquisition of Taurus and
related assets, and higher market interest rates in 1995.
Business combination expenses of $1.8 million in 1994 were related to
the acquisition of Diamond pursuant to a merger. The merger with Diamond was
accounted for as a pooling of interests and accordingly the transaction costs
were expensed when incurred.
Net income for the year ended December 31, 1995 increased to
approximately $5.8 million from approximately $3.3 million for 1994, primarily
due to (i) an increase in oil production from the Company's waterflood units,
the Company's development drilling program and the oil and natural gas property
acquisitions during the fourth quarters of 1994 and 1995, (ii) an increase in
the average sales price of oil by $1.22 per barrel and (iii) the lack of
business combination expenses in 1995.
CHANGES IN PRICES AND HEDGING ACTIVITIES
Annual average oil and natural gas prices have fluctuated
significantly over the past three years. The Company's weighted average oil
price per Bbl during 1996 and at December 31, 1996, was $20.22 and $24.88,
respectively. For the year ended December 31, 1996, the Company averaged $1.80
per barrel less (including an oil hedging price decrease of $.92 per barrel) and
$.29 per Mcf less for its oil and natural gas sales, respectively, than the
average NYMEX prices for the same period.
24
<PAGE>
On March 17, 1997, the NYMEX closing price for the near month for oil and
natural gas was $20.92 per barrel and $1.91 per Mcf, respectively.
Pursuant to the loan agreements with Diamond's former primary lender,
Diamond entered into an agreement with a refining and marketing company to sell
a fixed number of barrels attributable to its share of production of liquid
hydrocarbons from certain formerly secured properties at a price of $15.25 per
barrel. The effect of this contract was to lower the Company's 1995 and 1996
oil revenues by approximately $1.0 million ($.32 per barrel) and $123,000 ($.04
per barrel), respectively. The commitment under this agreement was fulfilled
during February 1996.
In an effort to reduce the effects of the volatility of the price of oil
and natural gas on the Company's operations, management has adopted a policy of
hedging oil and natural gas prices, on a portion of the Company's production,
through the use of commodity futures, options, and swap agreements whenever
market prices are in excess of the prices anticipated in the Company's operating
budget and profit plan. While the use of these hedging arrangements limits the
downside risk of adverse price movements, it may also limit future gains from
favorable movements. All hedging is accomplished pursuant to exchange-traded
contract or master swap agreements based upon standard forms. The Company
addresses market risk by selecting instruments whose value fluctuations
correlate strongly with the underlying commodity being hedged. Credit risk
related to hedging activities, which is minimal, is managed by requiring minimum
credit standards for courterparties, periodic settlements and mark-to-market
valuations. The Company has not historically been required to provide any
significant amount of collateral in connection with its hedging activities. The
Company has hedged 735,000 barrels at a weighted average NYMEX price of $19.13
for the year ending December 31, 1997 under various swap agreements entered into
as of December 31, 1996.
As of December 31, 1996, the Company had open positions for sold call
options covering 25,000 Bbls of oil per month at an option price of $20.00 per
Bbl for the period from January to August 1997. Under the standard form swap and
option agreements, in use by the Company, the Company's revenues will be limited
when the NYMEX prices exceeds the strike price. The total potential reduction
in revenues is equal to the difference between the swap prices and the NYMEX
price for the production month hedged multiplied by the number of barrels
swapped. To the extent this amount exceeds the credit limit established by the
counterparty, the Company may be required to utilize cash to fund a margin
account. The Company has not historically had to fund a margin account.
During the year ended December 31, 1995 the Company's oil revenues were
increased by $298,000 as a result of hedging transactions. During the periods
ended February 16, 1996 and December 31, 1996 the Company's oil revenues were
decreased by $14,000 and $3.1 million, respectively, as a result of hedging
transactions.
In connection with two swaps beginning January 1, 1997 covering 10,000
barrels per month and 15,000 barrels per month at a strike price of $19.41 and
$19.00, respectively, which expire June 30, 1997 and December 31, 1997,
respectively, the Company granted the counterparty a one day option at the
expiration of the swap to extend the swap under the same terms for an additional
twelve months.
25
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 1996, the Company had cash and cash equivalents aggregating
approximately $8.0 million and working capital of approximately $6.9 million.
Cash provided by operating activities for the year ended December 31, 1996
increased to approximately $38.3 million compared to $24.3 million for the
comparable period in 1995 due primarily to an increase in oil production and an
oil price increase partially offset by an increase in interest expense. An
increase in accrued interest accounts for $3.0 million of the increase in cash
provided by operating activities. Excluding the impact of the Merger, cash
flows used in investing activities decreased from $43.0 million for the year
ended December 31, 1995 to $14.1 million for the comparable period in 1996, as a
result of a higher level of additions to property and equipment in 1995.
Investing activities in 1996 also include the impact of the purchase of Coda by
JEDI. Cash flows provided by financing activities increased to $159.3 million
for the year ended December 31, 1996 from $16.9 million for the comparable
period in 1995, primarily due to financing transactions related to the Merger.
See " --The Merger" below.
The Company has two principal operating sources of cash: (i) net oil and
gas sales from its oil and gas properties and (ii) net margins earned from gas
gathering and processing operations. The Company expects to continue its
efforts to acquire additional oil and gas properties. Future acquisitions, if
any, would necessitate, in most cases, borrowing additional funds under the
Company's credit facility. The ability to borrow such funds is dependent upon
the Company's borrowing base from time to time and the effect upon the borrowing
base of the properties to be acquired.
The Company from time to time solicits bids for selected portions of its
existing oil and natural gas properties which it believes are no longer suitable
for its business strategy. Sales of properties in the past three years have not
been material and no substantial sales of oil and gas properties are currently
under negotiation. Coda is continuing to study alternatives for maximizing the
value of its investment in Taurus.
The Company has development drilling programs designed for all its major
operating areas. The Company has a revised capital spending budget of between
$15 million and $20 million in 1997, excluding property acquisitions, but is not
contractually committed to expend these funds. In addition, the Company is
continuing to evaluate oil and natural gas properties for future acquisitions.
Historically, the Company has used the public equity market (i) to raise cash to
fund acquisitions or repay indebtedness incurred for acquisitions and (ii) as a
medium of exchange for other companies' capital stock or assets in connection
with acquisitions. As a result of being 95% owned by JEDI (on a fully diluted
basis), the Company does not expect to utilize the public equity market to
finance acquisitions in the near term. Accordingly, any material expenditures
in connection with acquisitions would require borrowing under the Company's
credit facility or from other sources. There can be no assurance that such
funds will be available to the Company. Furthermore, the Company's ability to
borrow in the future is subject to restrictions imposed by the Company's credit
facility and the indenture governing the Notes (the "Indenture") as more fully
described below.
26
<PAGE>
The Merger
On February 16, 1996, the Company completed the Merger. The Merger has
been accounted for using the purchase method of accounting. As such, JEDI's
cost of acquiring Coda was allocated to the assets and liabilities acquired
using estimated fair values. As a result, the Company's financial position and
operating results subsequent to the date of the Merger reflect a new basis of
accounting and are not comparable to prior periods. Concurrently with the
execution of the Merger Agreement, JEDI and CAI entered into certain agreements
with the Management Group providing for a continuing role of management in the
Company after the Merger. The sources and uses of funds related to financing
the Merger were as follows:
<TABLE>
<CAPTION>
SOURCES OF FUNDS
(in millions)
<S> <C>
Credit Agreement $ 95.0
JEDI Debt(l) 100.0
15% Cumulative Preferred Stock issued to JEDI 20.0
Common Stock issued to JEDI 90.0
------
Total $305.0
======
</TABLE>
<TABLE>
<CAPTION>
USES OF FUNDS
(in millions)
<S> <C>
Payments to Coda stockholders, warrantholders and optionholders $176.2
Repayment of former credit facility and other indebtedness 122.7
Merger costs and other expenses 6.1
------
Total $305.0
======
</TABLE>
(1) Represents indebtedness incurred by CAI and assumed by Coda to fund a
portion of the consideration paid in the Merger.
The Company incurred substantial indebtedness in connection with the Merger
and is highly leveraged. As of December 31, 1996, the Company had total
indebtedness of approximately $175.1 million and common stockholders' equity of
approximately $41.7 million. Based upon the Company's current level of
operations and anticipated growth, management of the Company believes that
available cash, together with available borrowings under the Company's credit
facility will be adequate to meet the Company's anticipated future requirements
for capital expenditures and scheduled payments of principal of, and interest
on, its indebtedness, including the Notes. There can be no assurance that such
anticipated growth will be realized, that the Company's business will generate
sufficient cash flow from operations or that future borrowings will be available
in an amount sufficient to enable the Company to service its indebtedness,
including the Notes, or make necessary capital expenditures. In addition, the
Company anticipates that it is likely to find it necessary to
27
<PAGE>
refinance a portion of the principal amount of the Notes at or prior to their
maturity. However, there can be no assurance that the Company will be able to
obtain financing to complete a refinancing of the Notes.
Credit Agreement
Effective February 16, 1996, the Company entered into a credit agreement with
NationsBank of Texas, N.A. ("NationsBank"), as lender and as agent, and
additional lenders named therein (the "Credit Agreement"). The Credit Agreement
is guaranteed by all of Coda's subsidiaries and provides for a revolving credit
facility in an amount up to $250.0 million. The borrowing base is subject to
redetermination: (i) semiannually, (ii) upon the sale of Taurus and (iii) upon
issuance of public subordinated debt in an amount greater than $100.0 million.
The lenders under the Credit Agreement waived their right to redetermine the
borrowing base with respect to the issuance of the Notes. The borrowing base
was redetermined effective July 1, 1996 and remained at $115.0 million. The
next scheduled redetermination is April 1, 1997. At December 31, 1996, $64.5
million was outstanding under the Credit Agreement and $50.5 million was
available for borrowing thereunder.
The Credit Agreement is unsecured. The Company has provided the lenders with
first lien deeds of trust on its oil and natural gas assets which will not
become effective, and the lenders have agreed not to file, unless (i) 80% of any
outstanding borrowings in excess of the borrowing base is not repaid within a 90
day period, (ii) cash collateral securing a hedge transaction exceeds 20% of the
borrowing base or (iii) an event of default or a material adverse event, as
defined in the Credit Agreement, occurs.
So long as no default (as defined in the Credit Agreement) is continuing, the
Company has the option of having all or any portion of the amount borrowed under
the Credit Agreement be the subject of one of the following interest rates: (i)
NationsBank's prime rate, (ii) the CD Rate plus 1 1/4% to 1 5/8% based upon the
ratio of outstanding debt to the available borrowing base and (iii) LIBOR plus 1
1/4% to 1 5/8% based upon the ratio of outstanding debt to the available
borrowing base. The Company must also pay a commitment fee of between 0.375% to
0.425% on the unused portion of the credit facility. The Credit Agreement
contains various restrictive covenants, including limitations on the granting of
liens, restrictions on the issuance of additional debt, restrictions on
investments, a requirement to maintain positive working capital, and
restrictions on dividends and stock repurchases. The Credit Agreement also
contains requirements that JEDI or certain affiliates of JEDI must continue to
own a majority of the outstanding equity of Coda and must have the ability to
elect the majority of the Board of Directors and that certain members of
management maintain specified levels of equity ownership in Coda and continue
their employment with the Company. The Credit Agreement matures on February 16,
2001.
On August 1, 1996, the Company entered into the First Amendment to Credit
Agreement (the "First Amendment") which in general reduced the Company's
interest rate. The first amendment provides the Company the option of having
all or any portion of the amount borrowed under the Credit Agreement be the
subject of one of the following interest rates: (i) NationsBank's prime rate,
28
<PAGE>
(ii) the CD Rate plus 1% to 1 1/2% based upon the ratio of outstanding debt to
the available borrowing base and (iii) LIBOR plus 1% to 1 1/2% based upon the
ratio of outstanding debt to the available borrowing base. The Company must
also pay a commitment fee of between 0.30% to 0.425% on the unused portion of
the credit facility.
10 1/2% Senior Subordinated Notes
On March 18, 1996, the Company completed the sale of $110 million principal
amount of the Notes. The proceeds of the Notes were used to fully repay the
JEDI debt assumed in the Merger and to partially repay bank debt. The Notes
bear interest at an annual rate of 10 1/2% payable semiannually in arrears on
April 1 and October 1 of each year. The Notes are general, unsecured
obligations of the Company, are subordinated in right of payment to all Senior
Debt (as defined in the Indenture) of Coda, and are senior in right of payment
to all future subordinated debt of the Company. The claims of the holders of
the Notes are subordinated to Senior Debt, which, as of December 31, 1996, was
$65.1 million.
Coda's payment obligations under the Notes are fully, unconditionally and
jointly and severally guaranteed on a senior subordinated basis by all of Coda's
current subsidiaries (the "Guarantors") and future Restricted Subsidiaries (as
defined in the Indenture). Such guarantees are subordinated to the guarantees
of Senior Debt issued by the Guarantors under the Credit Agreement and to other
guarantees of Senior Debt issued in the future. All of Coda's current
subsidiaries are wholly owned. There are currently no contractual restrictions
on distributions from the Guarantors to Coda.
The Notes were issued pursuant to an Indenture, which contains certain
covenants that, among other things, limit the ability of Coda and its Restricted
Subsidiaries to incur additional indebtedness and issue Disqualified Stock (as
defined in the Indenture), pay dividends, make distributions, make investments,
make certain other restricted payments, enter into certain transactions with
affiliates, dispose of certain assets, incur liens securing pari passu or
subordinated indebtedness of Coda and engage in mergers and consolidations.
The Notes are not redeemable at Coda's option prior to April 1, 2001. After
April 1, 2001, the Notes will be subject to redemption at the option of Coda, in
whole or in part, at the redemption prices set forth in the Indenture, plus
accrued and unpaid interest thereon to the applicable redemption date. In
addition, until March 12, 1999, up to $27.5 million in aggregate principal
amount of Notes are redeemable, at the option of Coda on any one or more
occasions from the net proceeds of an offering of common equity of Coda, at a
price of 110.5% of the aggregate principal amount of the Notes, together with
accrued and unpaid interest thereon to the date of the redemption; provided,
however, that at least $82.5 million in aggregate principal amount of Notes must
remain outstanding immediately after the occurrence of such redemption;
provided, further, that any such redemption shall occur within 75 days of the
date of the closing of such offering of common equity.
In the event of a Change of Control (as defined in the Indenture), holders of
the Notes will have the right to require Coda to repurchase their Notes, in
whole or in part, at a price in cash equal to
29
<PAGE>
101% of the aggregate principal amount thereof, plus accrued and unpaid interest
thereon to the date of repurchase. The Indenture requires that, prior to such a
repurchase but in any event within 90 days of such Change of Control, Coda must
either repay all Senior Debt or obtain any required consent to such repurchase.
15% Cumulative Preferred Stock
Coda's Restated Certificate of Incorporation authorizes the issuance of up to
40,000 shares of Preferred Stock. In conjunction with the Merger, Coda issued
20,000 shares of Preferred Stock to JEDI for $20.0 million in cash. Shares of
Preferred Stock in excess of such 20,000 shares shall be issuable only for the
purpose of paying dividends on the Preferred Stock. The holders of each share
of Preferred Stock are entitled to receive, when and as declared by the Board of
Directors, cumulative preferential dividends, at the rate of $150.00 per share
per annum. The payment of Preferred Stock dividends in cash is restricted by
the Credit Agreement and the Indenture. As of December 31, 1996, the Preferred
Stock had accumulated approximately $2.7 million in preferred dividends which
had not been declared by the Board of Directors.
As long as any shares of Preferred Stock are outstanding, no dividends
whatsoever, whether paid in cash, stock or otherwise (except for dividends paid
in shares of common stock, either in the form of a stock split or stock
dividend), may be paid or declared, nor may any distribution be made, on any
common stock of Coda to the holders of such stock, unless certain conditions are
met.
Coda's Restated Certificate of Incorporation requires that Coda redeem all the
issued and outstanding shares of Preferred Stock at a redemption price of $1,000
per share, plus all accrued and unpaid dividends (including undeclared
dividends) to the date of redemption, if Coda has sufficient funds legally
available for such redemption and if such redemption would not violate or
conflict with any loan agreement, credit agreement, note agreement, indenture or
other agreement relating to indebtedness to which Coda is a party, on or before
the fifth business day after the earliest to occur of the following: (i) the
closing of the sale by Coda of Taurus and (ii) a Trigger Event, as such term is
defined in the Stockholders Agreement (see Certain Transactions--Stockholders
Agreement). The Preferred Stock may be redeemed by Coda at its option, as a
whole or in part, to the extent Coda shall have funds legally available for such
redemption, at any time or from time to time at a redemption price of $1,000 per
share, plus all accrued and unpaid dividends (including undeclared dividends) to
the date of redemption. Such redemption, whether required or optional, is
restricted by the Credit Agreement and the Indenture.
Enron
Enron is the parent of ECT and accordingly may be deemed to control indirectly
both JEDI and the Company. Enron and certain of its subsidiaries and other
affiliates collectively participate in nearly all phases of the oil and natural
gas industry and are, therefore, competitors of the Company. In addition, ECT
and JEDI have provided, and may in the future provide, and ECT Securities Corp.
has assisted, and may in the future assist, in arranging financing to non-
affiliated participants in the
30
<PAGE>
oil and natural gas industry who are or may become competitors of the Company.
Because of these various conflicting interests, ECT, the Company, JEDI and the
Management Group have entered into the Business Opportunity Agreement which is
intended to make it clear that Enron and its affiliates have no duty to make
business opportunities available to the Company in most circumstances. The
Business Opportunity Agreement also provides that ECT and its affiliates may
pursue certain business opportunities to the exclusion of the Company. The
Business Opportunity Agreement may limit the business opportunities available to
the Company. In addition, pursuant to the Business Opportunity Agreement there
may be circumstances in which the Company will offer business opportunities to
certain affiliates of Enron. If an Enron affiliate is offered such an
opportunity and decides to pursue it, the Company may be unable to pursue it.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
-------------------------------------------
The financial statements required by this Item are included as part of Item 14
hereof.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
---------------------------------------------------------------
FINANCIAL DISCLOSURE
--------------------
None
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
--------------------------------------------------
Item 11. EXECUTIVE COMPENSATION
----------------------
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
--------------------------------------------------------------
Item 13. CERTAIN TRANSACTIONS
--------------------
The information required by Part III of this report was filed March 31, 1997
under Form 10K/A No. 1.
31
<PAGE>
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
----------------------------------------------------------------
(a) The following are filed as a part of this Annual Report on Form 10-K:
1. Financial Statements Page
-------------------- ----
Report of independent auditors F-1
Consolidated balance sheets at December 31, 1995, and
December 31, 1996 F-2
Consolidated statements of operations for the years ended
December 31, 1994 and 1995, 47 days ended February 16,
1996 and 319 days ended December 31, 1996 F-3
Consolidated statements of cash flows for the years ended
December 31, 1994 and 1995, 47 days ended February 16,
1996 and 319 days ended December 31, 1996 F-4
Consolidated statements of stockholders' equity of the
years ended December 31, 1994 and 1995, 47 days ended
February 16, 1996 and 319 days ended December 31, 1996 F-5
Notes to consolidated financial statements F-6 - F-31
2. Financial Statement Schedules - None
All schedules have been omitted because the required information
is either inapplicable, insignificant or included in the
consolidated financial statements and notes thereto.
3. Exhibits
--------
2.1 Agreement and Plan of Merger, by and among Coda, Joint Energy
Development Investments Limited Partnership and Coda Acquisition,
Inc. dated as of October 30, 1995 filed as Exhibit 2.1 to Coda's
Current Report on Form 8-K dated October 30, 1995, and incorporated
by reference herein.
2.2 Agreement of Coda to provide schedules to the Agreement and Plan of
Merger (Exhibit 2.1) omitted pursuant to Item 6.01 (b)(2) of
Regulation S-K filed as Exhibit 2.2 to Coda's Quarterly Report on
Form 10-Q for the quarterly period ended September 30, 1995, and
incorporated by reference herein.
32
<PAGE>
2.3 Amendment to Agreement and Plan of Merger dated as of December
22, 1995 filed as Exhibit 2.1 to Coda's Current Report on Form
8-K dated December 22, 1995, and incorporated by reference herein.
2.4 Second Amendment to Agreement and Plan of Merger dated as of
January 10, 1996 filed as Exhibit 2.1 to Coda's Current Report on
Form 8-K dated January 10, 1996, and incorporated by reference
herein.
2.5 Agreement of Coda to provide schedules and exhibits to Second
Amendment to Agreement and Plan of Merger (Exhibit 2.4) and to
provide schedules to Amendment No. 1 to Subscription Agreement
(Exhibit 10.13) and Amendment No. 1 to Stockholders Agreement
(Exhibit 10.14) filed as Exhibit 99.4 to Coda's Current Report on
Form 8-K dated January 10, 1996, and incorporated by reference
herein.
3.1 Restated Certificate of Incorporation of Coda filed as Exhibit 3.1
to the Company's Registration Statement on Form S-4 filed April 9,
1996 (Registration No 333-2375, the "1996 Form S-4") and
incorporated by reference herein.
3.2 Amended and Restated Bylaws of Coda filed as Exhibit 3.2 to the
1996 Form S-4 and incorporated by reference herein.
3.3 Certificate of Incorporation of Diamond Energy Operating Company,
as amended, filed as Exhibit 3.3 to the 1996 Form S-4 and
incorporated by reference herein.
3.4 Bylaws of Diamond Energy Operating Company, as amended, filed as
Exhibit 3.4 to the 1996 Form S-4 and incorporated by reference
herein.
3.5 Articles of Incorporation of Taurus Energy Corp., as amended, filed
as Exhibit 3.5 to the 1996 Form S-4 and incorporated by reference
herein.
3.6 Bylaws of Taurus Energy Corp., as amended, filed as Exhibit 3.6 to
the 1996 Form S-4 and incorporated by reference herein.
3.7 Articles of Incorporation of Electra Resources, Inc. filed as
Exhibit 3.7 to the 1996 Form S-4 and incorporated by reference
herein.
3.8 Bylaws of Electra Resources, Inc. filed as Exhibit 3.8 to the 1996
Form S-4 and incorporated by reference herein.
4.1 Indenture, dated as of March 18, 1996, among Coda, the Guarantors
and Texas Commerce Bank National Association, as trustee, relating
to $110,000,000 aggregate principal amount of 10 1/2% Series A and
Series B Senior Subordinated Notes due 2006 filed as Exhibit 4.1 to
the 1996 Form S-4 and incorporated by reference herein.
33
<PAGE>
4.2 Registration Rights Agreement, dated as of March 18, 1996, among
Coda, the Guarantors and the Initial Purchasers filed as Exhibit
4.2 to the 1996 Form S-4 and incorporated by reference herein.
4.3 Purchase Agreement, dated as of March 12, 1996, among Coda, the
Guarantors and the Initial Purchasers filed as Exhibit 4.3 to the
1996 Form S-4 and incorporated by reference herein.
4.4 Credit Agreement, dated February 14, 1996, among the Company,
NationsBank of Texas, N.A., individually and as agent
("NationsBank"), and additional lenders named therein, filed as
Exhibit 4.5 to the 1996 Form S-4 and incorporated by reference
herein.
4.5 Promissory Note dated February 14, 1996, in the original principal
amount of $87,500,000.00, executed by Coda, payable to NationsBank
of Texas, N.A. filed as Exhibit 4.6 to the 1996 Form S-4 and
incorporated by reference herein.
4.6 Promissory Note dated February 14, 1996, in the original principal
amount of $37,500,000.00, executed by Coda, payable to Bank One,
Texas, N.A. filed as Exhibit 4.7 to the 1996 Form S-4 and
incorporated by reference herein.
4.7 Promissory Note dated February 14, 1996, in the original principal
amount of $75,000,000.00, executed by Coda, payable to Texas
Commerce Bank National Association filed as Exhibit 4.8 to the 1996
Form S-4 and incorporated by reference herein.
4.8 Promissory Note dated February 14, 1996, in the original principal
amount of $50,000,000.00, executed by Coda, payable to the First
National Bank of Boston filed as Exhibit 4.9 to the 1996 Form S-4
and incorporated by reference herein.
4.9 Specimen Certificate of Series A 10 1/2% Senior Subordinated Notes
due 2006 (the "Private Notes") (included in Exhibit 4.1 hereto),
filed as Exhibit 4.10 to the 1996 Form S-4 and incorporated by
reference herein.
4.10 Specimen Certificate of Series B 10 1/2% Senior Subordinated Notes
due 2006 (the "Exchange Notes") (included in Exhibit 4.1 hereto),
filed as Exhibit 4.11 to the 1996 Form S-4 and incorporated by
reference herein.
4.11 First Supplement to Indenture dated as of April 25, 1996 filed as
Exhibit 4.12 the Company's Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 1996 (the "June 1996 10-Q") and
incorporated by reference herein amending the Indenture filed as
Exhibit 4.1 above.
34
<PAGE>
4.12 First Amendment to Credit Agreement, dated August 1, 1996, among the
Company, NationsBank and additional lenders named therein, filed as
exhibit 4.13 to the Company's quarterly report on Form 10-Q for the
quarterly period ended September 30, 1996 (the "September 1996 10-Q")
and incorporated by reference herein amending the Credit Agreement
filed as Exhibit 4.5 above.
10.1/(2)/ Form of Indemnification Agreement entered into between Coda and each
of its directors and officers filed as Exhibit 10.1 to Coda's Annual
Report on Form 10-K for the fiscal year ended December 31, 1994 (the
"1994 10-K"), and incorporated by reference herein.
10.2/(2)/ List of directors and officers that have entered into Indemnification
Agreements with Coda filed as Exhibit 10.1 to the Company's Quarterly
Report on Form 10-Q for the quarterly period ended September 30, 1995,
and incorporated by reference herein.
10.3/(2)/ Stockholders Agreement dated October 30, 1995 filed as Exhibit 99.2 to
Coda's Current Report on Form 8-K dated October 30, 1995, and
incorporated by reference herein.
10.4/(2)/ Subscription Agreement among Coda Acquisition, Inc. and The Management
Investors dated October 30, 1995 filed as Exhibit 99.3 to Coda's
Current Report on Form S-K dated October 30, 1995, and incorporated by
reference herein.
10.5 Agreement of Coda to provide schedules to Stockholders Agreement
(Exhibit 10.7) and to Subscription Agreement (Exhibit 10.8) filed as
Exhibit 99.11 to Coda's Current Report on Form 8-K dated October 30,
1995, and incorporated by reference herein.
10.6/(2)/ Business Opportunity Agreement dated as of October 30, 1995 filed as
Exhibit 99.4 to Coda's Current Report on Form 8-K dated October 30,
1995, and incorporated by reference herein.
10.7/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and
Randell A. Bodenhamer filed as Exhibit 99.5 to Coda's Current Report
on Form 8-K dated October 30, 1995, and incorporated by reference
herein.
10.8/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and J.
William Freeman filed as Exhibit 99.6 to Coda's Current Report on Form
8-K dated October 30, 1995, and incorporated by reference herein.
10.9/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and
Grant W. Henderson filed as Exhibit 99.7 to Coda's Current Report on
Form 8-K dated October 30, 1995 and incorporated by reference herein.
35
<PAGE>
10.10/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and
Jarl P. Johnson filed as Exhibit 99.8 to Coda's Current Report on
Form 8-K dated October 30, 1995, and incorporated by reference
herein.
10.11/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and
Douglas H. Miller filed as Exhibit 99.9 to Coda's Current Report on
Form S-K dated October 30, 1995, and incorporated by reference
herein.
10.12/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and
J.W. Spencer, III filed as Exhibit 99.10 to Coda's Current Report on
Form 8-K dated October 30, 1995, and incorporated by reference
herein.
10.13/(2)/ Amendment No. 1 to Subscription Agreement dated as of January 10,
1996 filed as Exhibit 99.2 to Coda's Current Report on Form S-K dated
January 10, 1996, and incorporated by reference herein.
10.14/(2)/ Amendment No. 1 to Stockholders Agreement dated as of January 10,
1996 filed as Exhibit 99.3 to Coda's Current Report on Form 8-K dated
January 10, 1996, and incorporated by reference herein.
10.15 Credit Agreement, dated February 14, 1996, among the Company,
NationsBank of Texas, N.A., individually and as agent, and additional
lenders named therein filed as Exhibit 4.4 above.
10.16 Promissory Note dated February 14, 1996, in the original principal
amount of $87,500,000.00, executed by Coda, payable to NationsBank of
Texas, N.A. filed as Exhibit 4.5 above.
10.17 Promissory Note dated February 14, 1996, in the original principal
amount of $37,500,000.00, executed by Coda, payable to Bank One,
Texas, N.A. filed as Exhibit 4.6 above.
10.18 Promissory Note dated February 14, 1996, in the original principal
amount of $75,000,000.00, executed by Coda, payable to Texas Commerce
Bank National Association filed as Exhibit 4.7 above.
10.19 Promissory Note dated February 14, 1996, in the original principal
amount of $50,000,000.00, executed by Coda, payable to the First
National Bank of Boston filed as Exhibit 4.8 above.
10.20/(2)/ Form of Nonstatutory Stock Option Agreement attached and filed as
Exhibit A to Exhibit 99.3 to Coda's Current Report on Form 8-K dated
October 30, 1995, and incorporated by reference herein.
36
<PAGE>
10.21/(2)/ Form of Limited Recourse Promissory Note attached and filed as
Exhibit B to Exhibit 99.3 to Coda's Current Report on Form 8-K dated
October 30, 1995, and incorporated by reference herein.
10.22/(2)/ Form of Security Agreement attached and filed as Exhibit C to Exhibit
99.3 to Coda's Current Report on Form 8-K dated October 30, 1995, and
incorporated by reference herein.
10.23/(2)/ List of Management Investors who are parties to Nonstatutory Stock
Option Agreement (Exhibit 10.20), Limited Recourse Promissory Note
(Exhibit 10.21) or Security Agreement (Exhibit 10.22) filed as
Exhibit 10.27 to the 1996 Form S-4 and incorporated by reference
herein.
10.24 First Amendment to Credit Agreement, dated August 1, 1996, among the
Company, NationsBank and additional lenders named therein filed as
Exhibit 4.12 above.
10.25/(2)/ Limited Recourse Promissory Note dated July 31, 1996, in the original
principal amount of $1,187,500.00 executed by Douglas H. Miller,
payable to the Company. Filed as Exhibit 10.30 to the September 1996
10-Q and incorporated by reference herein.
10.26/(2)/ Amendment to Nonstatutory Stock Option Agreement dated July 31, 1996
between the Company and Douglas H. Miller filed as Exhibit 10.31 to
the September 1996 10-Q and incorporated by reference herein amending
the Nonstatutory Stock Option Agreement filed as Exhibit 10.20 above.
21/(1)/ Subsidiaries of the Company.
24.1/(1)/ The power of attorney of officers and directors of Coda is set
forth on the signature page hereof.
27/(1)/ Financial data schedule
- --------------------------------
/(1)/ Filed herewith.
/(2)/ Identifies management contract or compensation plan.
(b) Reports on Form 8-K: None
(c) The exhibits referenced in Item 14 (a)(3) are filed herewith or
incorporated by reference herein.
(d) Not applicable.
37
<PAGE>
THE COMPANY WILL PROVIDE A COPY OF ITS FORM 10-K FOR THE FISCAL YEAR ENDED
DECEMBER 31, 1996, FREE OF CHARGE TO ANY STOCKHOLDER UPON RECEIPT OF A WRITTEN
REQUEST CONTAINING THE NAME AND ADDRESS OF THE PERSON SO REQUESTING. A COPY OF
THE EXHIBITS TO SUCH FORM 10-K WILL BE PROVIDED UPON PAYMENT OF $.20 PER PAGE TO
COVER THE COST OF POSTAGE AND HANDLING.
38
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 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.
CODA ENERGY, INC.
(Registrant)
By: /s/ Douglas H. Miller
--------------------------------------
Douglas H. Miller
Chief Executive Officer
DATE: March 27, 1997
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and
directors of Coda Energy, Inc. (the "Company") hereby constitutes and appoints
Grant W. Henderson and Douglas H. Miller or either of them (with full power to
each of them to act alone), his true and lawful attorney-in-fact and agent, with
full power of substitution, for him and on his behalf and in his name, place and
stead, in any and all capacities, to sign, execute, and file any and all
documents relating to the Company's Form 10-K for the fiscal year ended December
31, 1996, including any and all amendments and supplements thereto, with any
regulatory authority, granting unto said attorneys, and each of them, full power
and authority to do and perform each and every act and thing requisite and
necessary to be done in and about the premises in order to effectuate the same
as fully to all intents and purposes as he himself might or could do if
personally present, hereby ratifying and confirming all that said attorneys-in-
fact and agents, or any of them, or their or his substitute or substitutes, may
lawfully do or cause to be done.
39
<PAGE>
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Name Capacities Date
---- ---------- -------
/s/ Douglas H. Miller Chairman of the Board and Chief 3/27/97
- -------------------------------- Executive Officer -------
Douglas H. Miller
/s/ Grant W. Henderson President, Chief Financial Officer 3/27/97
- -------------------------------- (Principal Financial and Accounting -------
Grant W. Henderson Officer) and Director
/s/ Jarl P. Johnson Vice Chairman of the Board and 3/25/97
- -------------------------------- Chief Operating Officer -------
Jarl P. Johnson
/s/ Richard B. Buy Director 3/27/97
- -------------------------------- -------
Richard B. Buy
/s/ Timothy J. Detmering Director 3/27/97
- -------------------------------- -------
Timothy J. Detmering
/s/ James V. Derrick, Jr. Director 3/26/97
- -------------------------------- -------
James V. Derrick, Jr.
/s/ C. John Thompson Director 3/25/97
- -------------------------------- -------
C. John Thompson
40
<PAGE>
REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS
The Board of Directors and Stockholders
Coda Energy, Inc.
We have audited the accompanying consolidated balance sheet of Coda Energy,
Inc., and subsidiaries (the "Successor") as of December 31, 1996, and the
related consolidated statements of operations, cash flows, and stockholders'
equity for the 319-day period from February 17, 1996 to December 31, 1996 and
the predecessor's consolidated balance sheet as of December 31, 1995 and its
related consolidated statements of operations, cash flows, and stockholders'
equity as described in Note 1 for each of the two years in the period ended
December 31, 1995. These financial statements are the responsibility of the
Successor's and the predecessor'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 of the Successor referred
to above present fairly, in all material respects, the consolidated financial
position of Coda Energy, Inc., and subsidiaries at December 31, 1996, and the
consolidated results of their operations and their cash flows for the 319-day
period from February 17, 1996 to December 31, 1996, in conformity with generally
accepted accounting principles.
In our opinion, the consolidated financial statements of the predecessor
referred to above present fairly, in all material respects, the consolidated
financial position of the predecessor at December 31, 1995, and the consolidated
results of its operations and its cash flows for each of the two years in the
period ended December 31, 1995 in conformity with generally accepted accounting
principles.
ERNST & YOUNG LLP
Dallas, Texas
February 19, 1997
F-1
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 1995 and 1996
(dollars in thousands)
<TABLE>
<CAPTION>
December 31,
------------------------
1995 1996
------------ ----------
Predecessor Successor
------------ ----------
ASSETS
------
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 4,604 $ 7,994
Accounts receivable - revenue 10,598 14,432
Accounts receivable - joint interest and other 2,463 1,673
Other current assets 2,206 1,046
-------- --------
19,871 25,145
Oil and gas properties (full cost accounting method):
Proved oil and gas properties 226,650 249,693
Unproved oil and gas properties - 1,000
Less accumulated depletion, depreciation, and amortization (56,042) (20,757)
-------- --------
Oil and gas properties, net 170,608 229,936
Gas plants and gathering systems, at cost 38,068 34,258
Less accumulated depreciation (4,082) (2,305)
-------- --------
Gas plants and gathering systems, net 33,986 31,953
Other properties and assets, net 4,599 8,536
-------- --------
$229,064 $295,570
======== ========
LIABILITIES AND STOCKHOLDERS EQUITY
------------------------------------
Current liabilities:
Current maturities of long-term debt $ 453 $ 120
Accounts payable - trade 7,252 8,934
Accounts payable - revenue and other 3,394 5,210
Accrued interest 342 3,366
Income taxes payable 128 579
-------- --------
11,569 18,209
Long-term debt, less current maturities 123,907 64,966
10 1/2% senior subordinated notes - 110,000
Deferred income taxes 14,400 37,061
Commitments and contingencies
15% cumulative preferred stock, 40,000 shares of
$.01 par value authorized; 20,000 shares issued and outstanding
at December 31, 1996; liquidation preference of $22,738 at
December 31, 1996, including dividends in arrears - 20,000
Common stockholders' equity of management, subject to put
and call rights; 13,611 shares of $.01 par value common
stock issued and outstanding - 4,560
Less related notes receivable - (937)
-------- --------
- 3,623
-------- --------
Other common stockholders' equity:
Common stock, 40 million, $.02 par value, 1 million, $.01 par value,
shares authorized at December 31, 1995 and 1996, respectively
22,088,903 and 900,000 shares issued and outstanding at December 31,
1995 and 1996, respectively 442 9
Additional paid-in capital 68,671 89,991
Retained earnings (deficit) 10,075 (48,289)
-------- --------
Total other common stockholders' equity 79,188 41,711
-------- --------
$229,064 $295,570
======== ========
</TABLE>
See notes to consolidated financial statements.
F-2
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years ended December 31, 1994 and 1995, 47 days ended February 16, 1996,
and 319 days ended December 31, 1996
(in thousands)
<TABLE>
<CAPTION>
Predecessor Successor
-------------------------------- --------------------------
Year ended 47 days 319 days Pro forma
December 31, ended ended year ended
----------------- February 16, December 31, December 31,
1994 1995 1996 1996 1996
-------- ------- ------------- ------------- -------------
(unaudited) (unaudited)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales $50,683 $60,997 $ 8,079 $ 68,690 $ 76,769
Gas gathering and processing 20,081 35,634 5,322 39,553 44,875
Other income 822 1,207 168 2,139 2,307
------- ------- ------- -------- --------
71,586 97,838 13,569 110,382 123,951
Costs and expenses:
Oil and gas production 21,646 27,119 3,607 28,560 32,167
Gas gathering and processing 17,357 30,473 4,567 32,825 37,392
Depletion, depreciation, and amortization 16,419 19,715 2,583 24,031 27,412
General and administrative 3,144 2,898 320 2,078 2,398
Business combination 1,829 - - - -
Interest 5,281 8,676 1,102 14,555 16,985
Stock option compensation - - 3,199 - -
Writedown of oil and gas properties - - - 83,305 -
------- ------- ------- -------- --------
65,676 88,881 15,378 185,354 116,354
------- ------- ------- -------- --------
Income (loss) before income taxes 5,910 8,957 (1,809) (74,972) 7,597
Income tax expense (benefit) 2,581 3,202 (511) (26,683) 3,146
------- ------- ------- -------- --------
Net income (loss) 3,329 5,755 (1,298) (48,289) 4,451
Preferred stock dividend requirements - - - 2,738 3,173
------- ------- ------- -------- --------
Net income (loss) available for common
stockholders $ 3,329 $ 5,755 $(1,298) $(51,027) $ 1,278
======= ======= ======= ======== ========
</TABLE>
See notes to consolidated financial statements.
F-3
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 1994 and 1995, 47 days ended February 16, 1996,
and 319 days ended December 31, 1996
(in thousands)
<TABLE>
<CAPTION>
Predecessor Successor
---------------------------------- -------------
Year ended 47 days 319 days
December 31, ended ended
----------------------- February 16, December 31,
1994 1995 1996 1996
----------- ---------- ------------ -------------
(unaudited)
<S> <C> <C> <C> <C>
Cash flows from operating activities:
Net income (loss) $ 3,329 $ 5,755 $ (1,298) $ (48,289)
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation, and amortization 16,973 20,256 2,583 24,031
Deferred income tax expense (benefit) 1,567 3,187 (511) (27,254)
Stock option compensation - - 3,199 -
Writedown of oil and gas properties - - - 83,305
Gain on sale of other assets - - - (701)
Other 123 55 6 (14)
Effect of changes in:
Accounts receivable 589 (3,849) 3,386 (6,430)
Other current assets 60 (558) (63) 398
Accounts payable and other
current liabilities 346 (545) (4,166) 10,104
-------- -------- ------ ---------
Net cash provided by operating activities 22,987 24,301 3,136 35,150
Cash flows from investing activities:
Additions to oil and gas properties (49,732) (41,079) (1,717) (13,433)
Additions to gas plant and gathering systems
and other property (4,130) (8,500) (114) (823)
Business combinations, net of $5,740 cash
acquired in 1996 (3,250) - - (174,373)
Investment in common equity securities - (573) - (2,649)
Payments received on amounts due from stockholders - 1,294 130 124
Proceeds from sale of assets 2,515 5,722 110 4,938
Prepaid long-term gas purchases (1,759) - - -
Loan to stockholder - - - (738)
Other, net (423) 106 - 75
-------- -------- ------ ---------
Net cash used in investing activities (56,779) (43,030) (1,591) (186,879)
Cash flows from financing activities:
Proceeds from sale of common and preferred stock - - - 110,000
Proceeds from subordinated notes - - - 210,000
Repayment of debt and subordinated notes (41,542) (11,551) (19) (256,920)
Proceeds from bank borrowings 76,350 30,400 - 97,500
Proceeds from exercise of stock options and warrants 2,370 772 - -
Repurchases of common stock (812) (2,125) - -
Other, net (140) (637) (390) (857)
-------- -------- ------ ---------
Net cash provided by (used in) financing
activities 36,226 16,859 (409) 159,723
-------- -------- ------ ---------
Net increase (decrease) in cash and cash equivalents 2,434 (1,870) 1,136 7,994
Cash and cash equivalents at beginning of period 4,040 6,474 4,604 -
-------- -------- ------- ---------
Cash and cash equivalents at end of period $ 6,474 $ 4,604 $ 5,740 $ 7,994
======== ======== ======= =========
Supplemental cash flow information:
Interest paid $ 3,788 $ 9,584 $ 1,548 $ 11,152
======== ======== ======= =========
Income taxes paid $ 300 $ 618 $ - $ 120
======== ======== ======= =========
</TABLE>
See notes to consolidated financial statements.
F-4
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years ended December 31, 1994 and 1995, 47 days ended February 16, 1996,
and 319 days ended December 31, 1996
(in thousands)
<TABLE>
<CAPTION>
Common Stockholders'
15% Cumulative Equity of Management,
Preferred Stock Subject to Put and Call Rights Other Common Stockholders' Equity
------------------- -------------------------------- -------------------------------------
Additional Retained
Notes paid-in earnings
Shares Amount Shares Amount receivable Shares Amount capital (deficit)
--------- -------- ---------- -------- ---------- ------ ------ ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Predecessor:
Balances December 31, 1993 - $ - - S - $ - 19,455 $389 $56,851 $ 991
Shares issued as director
compensation - - - - - 7 - 44 -
Shares issued upon
exercise of stock
options and warrants - - - - - 788 16 2,355 -
Common stock issued to
purchase Taurus
Energy Corp. - - - - - 1,500 30 7,265 -
Repurchase and
cancellation of
common stock - - - - - (157) (3) (809) -
Common stock issued to
acquire reversionary
interests in oil and gas
properties - -- - - - - 635 13 4,270 -
Net income - - - - - - - - 3,329
--- ------- --- ------ ------ ------ ---- ------- -------
Balances December 31, 1994 - - - - - 22,228 445 69,976 4,320
Shares issued as director
compensation - - - - - 7 - 45 -
Shares issued upon
exercise of stock
options and warrants - - - - - 225 5 767 -
Repurchase and
cancellation of common
stock - - - - - (371) (8) (2,117) -
Net income - - - - - - - - 5,755
--- ------- --- ------ ------ ------ ---- ------- -------
Balances December 31, 1995 - - - - - 22,089 442 68,671 10,075
Stock option compensation
(unaudited) - - - - - - - 3,199 -
Net loss for the period
from January 1, 1996
to February 16, 1996
(unaudited) - - - - - - - - (1,298)
--- ------- --- ------ ------ ------ ---- ------- -------
Balances at February 16,
1996 (unaudited) - $ - - $ - $ - 22,089 $442 $71,870 $ 8,777
=== ======= === ====== ====== ====== ==== ======= =======
Successor:
Transactions related to
the merger:
Common stock issued to
management investors
in exchange for
common stock, options,
warrants, notes
receivable and cash - $ - 14 $4,560 $ (937) - $ - $ - $ -
Common stock issued to
JEDI for cash - - - - - 900 9 89,991 -
Preferred stock issued to
JEDI for cash 20 20,000 - - - - - - -
Net loss for the period
from February 17, 1996
through December 31, 1996 - - - - - - - - (48,289)
--- ------- --- ------ ------ ------ ---- ------- --------
Balances December 31, 1996 0 $20,000 14 $4,560 $ (937) 900 $ 9 $89,991 $(48,289)
=== ======= === ====== ====== ====== ==== ======= ========
</TABLE>
F-5
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. The Merger
----------
On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as
of October 30, 1995 (as amended, the "Merger Agreement"), by and among Coda
Energy, Inc. ("Coda"), Joint Energy Development Investments Limited
Partnership ("JEDI"), which is an affiliate of Enron Capital & Trade
Resources Corp. ("ECT"), and Coda Acquisition, Inc. ("CAI"), which was a
subsidiary of JEDI, JEDI acquired Coda through a merger (the "Merger") at a
price of $7.75 per share in cash (for an aggregate purchase price of
approximately $176.2 million). Coda together with its subsidiaries prior to
and including February 16, 1996 is referred to herein as the Predecessor and
after such date as CEI or Successor and collectively, for both periods the
Company. Concurrently with the execution of the Merger Agreement, JEDI and
CAI entered into certain agreements with--members of management (the
"Management Group"), providing for a continuing role of management in the
Company after the Merger. Following consummation of the Merger, the
Management Group owns approximately 5% of Coda's common stock on a fully-
diluted basis. JEDI owns the remaining 95%.
The sources and uses of funds related to financing the Merger were as
follows:
Sources of Funds
(in millions)
<TABLE>
<CAPTION>
<S> <C>
Credit Agreement (See Note 5) $ 95.0
JEDI debt/(1)/ 100.0
15% cumulative preferred stock issued to JEDI 20.0
Common stock issued to JEDI 90.0
------
Total $305.0
======
</TABLE>
Uses of Funds
(in millions)
<TABLE>
<CAPTION>
<S> <C>
Payments to Coda stockholders,
warrantholder and optionholders $176.2
Repayment of former credit facility
and other indebtedness 122.7
Merger costs and other expenses 6.1
------
Total $305.0
======
</TABLE>
(1) Represents indebtedness incurred by CAI and assumed by Coda to
fund a portion of the consideration paid in the Merger.
The Merger has been accounted for using the purchase method of accounting.
As such, JEDI's acquisition cost has been allocated to the assets and
liabilities acquired based on estimated fair values. As a result, the
financial position and operating results subsequent to the date of the
Merger reflect a new basis of accounting and are not comparable to prior
periods.
F-6
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The allocation of JEDI's purchase price to the assets and liabilities
acquired resulted in a significant increase in the carrying value of the oil
and gas properties. Based upon the allocation of JEDI's purchase price and
estimated proved reserves and product prices in effect at the date of the
Merger, the purchase price allocated to oil and gas properties was in
excess of the cost center ceiling (see Note 2 - oil and gas properties) by
approximately $83.3 million ($53.3 million net of related deferred taxes).
The resulting writedown was a non-cash charge and has been included in the
results of operations for the 319 days ended December 31, 1996.
2. Summary of significant accounting and reporting policies
--------------------------------------------------------
Principles of consolidation and basis of financial statement presentation -
-------------------------------------------------------------------------
The consolidated financial statements include the accounts of Coda and its
majority owned subsidiaries. All significant intercompany balances and
transactions have been eliminated in consolidation. Certain
reclassifications have been made to amounts reported in prior years to
conform with the current presentation. All information contained herein
concerning the 47-day period ended February 16, 1996 is unaudited.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
Cash and cash equivalents - Cash and cash equivalents include commercial
-------------------------
paper or eurodollar investments with major financial institutions with
maturities of three months or less when purchased.
Accounts receivable - Substantially all accounts receivable arise from sales
-------------------
of oil, natural gas, or natural gas liquids or from participants in operated
oil and gas wells. Generally, operators of oil and gas properties have the
right to offset future revenues against unpaid charges related to operated
wells. Oil and gas sales are generally unsecured. Most of the receivables
are from a broad and diverse group of oil and gas companies and,
accordingly, do not generally represent a significant credit risk. Credit
losses, which have been insignificant, are provided for in the financial
statements and have been within management's expectations.
Oil and gas properties - Oil and gas properties are recorded at cost using
----------------------
the full cost method of accounting, as prescribed by the Securities and
Exchange Commission (the "SEC"). Under the full cost method, all costs
associated with the acquisition, exploration, or development of oil and gas
properties are capitalized as part of the full cost pool. Sales,
dispositions, and other oil and gas property retirements are accounted for
as adjustments to the full cost pool, with no recognition of gain or loss
unless such disposition would significantly alter the amortization rate.
Under rules of the SEC for the full-cost method of accounting, the net
carrying value of oil and gas properties is
F-7
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
limited to the sum of the present value (10% discount rate) of estimated
future net cash flows from proved reserves, based on period-end prices and
costs, plus the lower of cost or estimated fair value of unproved properties
(the "cost center ceiling").
Depletion, depreciation, and amortization of evaluated oil and gas
properties are provided using the unit-of-production method based on total
proved reserves, as determined by independent petroleum reservoir engineers.
Gas plants and gathering systems - Gas plants and gathering systems are
--------------------------------
recorded at cost and depreciated on a straight-line basis over the shorter
of their estimated useful lives or 15 years.
Other properties and assets, net - Other assets include deferred financing
--------------------------------
costs, deferred gas contract costs and a receivable from a related party
(see Note 13). Such costs are amortized over the life of the related loan
agreements and contracts. Amortization of these costs for the 47-day period
ended February 16, 1996 and the 319-day period ended December 31, 1996
amounted to $68,000 and $660,000, respectively, which is included in
depletion, depreciation, and amortization expense in the accompanying
statements of operations.
Overhead reimbursement fees - Fees from overhead charges billed to working
---------------------------
interest owners, including the Company, of $3,372,000, $5,571,000, $848,000,
and $6,011,000 for the years ended December 31, 1994, 1995, and the 47 days
ended February 16, 1996 and 319 days ended December 31, 1996, respectively,
have been classified as a reduction of general and administrative expenses
in the accompanying consolidated statements of operations.
Financial instruments - The Company enters into swap agreements to reduce
---------------------
the effects of the volatility of the price of crude oil and natural gas on
the Company's operations. These agreements involve the receipt of fixed
price amounts in exchange for variable payments based on NYMEX prices and
specific volumes. The differential to be paid or received is accrued in the
month of the related production and recognized as a component of oil and gas
revenues.
The Company also sells call options on crude oil. The strike price of these
agreements exceeds current market prices at the time they are entered into.
If the applicable market price exceeds the strike price and option premium,
the differential is accrued and recognized as a reduction of oil revenues in
the month of the related production. Any remaining deferred option premiums
are recognized at the end of the option period.
The fair values of the swap agreements and sold call options are not
included in the accompanying consolidated balance sheet. See Note 11 for the
estimated fair value of these financial instruments. Due to the short
maturity, market sensitive interest rates and/or minimal changes in forward
interest rates since the date of issuance, the carrying value of the
Company's other financial instruments approximates fair value.
F-8
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
New accounting pronouncements - In the first quarter of 1996, the Company
-----------------------------
adopted the Financial Accounting Standards Board ("FASB") Statement No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of" ("FAS 121"). Adoption of this statement did not
have a material effect on the Company's financial statements.
The FASB has issued its statement No. 123, "Accounting for Stock Based
Compensation" ("FAS 123") which establishes an alternative method of
accounting for stock based compensation to the method set forth in
Accounting Principles Board Opinion No. 25 ("APB 25"). FAS 123 encourages,
but does not require, adoption of a fair value based method of accounting
for stock options and similar equity instruments granted to employees. The
Company has elected to account for such grants under the provisions of APB
No. 25.
Pro forma information (unaudited) - The pro forma statement of operations
---------------------------------
information was prepared as if the Merger and the sale of the Notes (see
Note 6) had occurred on January 1, of each 1995 and 1996. The pro forma
information does not purport to represent the results of operations which
would have occurred had such transactions been consummated on January 1,
1995 and 1996 or for any future period. The pro forma information was
prepared by adjusting the historical periods: (i) to adjust depletion,
depreciation, and amortization to reflect JEDI's purchase price allocated to
property and equipment, (ii) to adjust interest expense to give effect to
the net reduction of approximately $37.0 million under the Company's credit
facility, repayment of a note payable to an officer of the Company, and an
increase in the interest rate on borrowings under the new credit facility of
.25%, (iii) to record interest on the Notes at an interest rate of 10 1/2%,
(iv) to record amortization of the issuance cost of the Notes over the term
such debt is expected to be outstanding (10 years), (v) to adjust the
writedown of oil and gas properties and stock option compensation in 1996 to
eliminate these non-recurring charges related to the Merger, (vi) to adjust
the provision for income taxes for the change in financial taxable income
resulting from the above adjustments, (vii) to record the cumulative
dividend requirements of the 15% cumulative preferred stock issued to JEDI.
<TABLE>
<CAPTION>
Pro forma (unaudited, in thousands)
Year ended December 31,
------------------------------------
1995 1996
----------------- -----------------
<S> <C> <C>
Revenues $97,838 $123,951
------- --------
Net income (loss) available
for common stockholders $(7,593) $ 1,278
------- --------
</TABLE>
3. Predecessor merger with Diamond
-------------------------------
On September 30, 1994, pursuant to an Agreement and Plan of Merger, the
Predecessor acquired all of the issued and outstanding stock of Diamond
Energy Operating Company and Diamond A Inc. (collectively, "Diamond"). The
Predecessor issued an aggregate of 3,647,715 shares of
F-9
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
common stock to the Diamond stockholders. Contemporaneously with the merger,
Diamond acquired the overriding royalty and reversionary interests owned by
Diamond's primary lender in certain of Diamond's oil and gas properties for
$9.0 million cash. Coda provided the funds necessary to complete such
acquisition and repay $18.5 million of existing Diamond indebtedness. If the
price of oil received from the Diamond properties averages more than $17.65
per barrel for the 48-month period ending September 30, 1998, Diamond's
former lender will be paid an additional $1.0 million. In addition, other
reversionary interests in oil and gas properties in which Diamond owns an
interest were purchased from certain employees, former employees,
consultants and a financial advisor to Diamond for 634,519 shares of common
stock and approximately $39,000 in cash.
The merger with Diamond was accounted for as a pooling of interests.
Accordingly, the merger of the equity interests was given retroactive effect
in these financial statements for periods prior to the merger to represent
the combined financial statements of the previously separate entities. The
acquisitions of the reversionary interests were accounted for as purchases
effective September 30, 1994.
Separate and combined results of the Predecessor and Diamond for periods
prior to the merger were as follows (in thousands):
<TABLE>
<CAPTION>
Predecessor Diamond Combined
----------- ------- --------
<S> <C> <C> <C>
Nine months ended September 30, 1994
(unaudited):
Revenues $37,048 $13,314 $50,362
Net income 194 1,831 2,025
</TABLE>
In connection with the merger, the Predecessor incurred approximately $1.8
million of legal, accounting, printing, and other costs related to the
combination of the previously separate entities. Under pooling of interests
accounting, these costs were expensed in September 1994.
4. Other Predecessor Acquisitions
------------------------------
The Company is continually acquiring oil and gas properties. The significant
transactions that have occurred since January 1, 1994, are discussed below.
On April 29, 1994, Coda acquired 100% of the issued and outstanding common
stock of Taurus Energy Corporation ("Taurus"), a privately held Texas
corporation, in exchange for 1,500,000 shares of the Predecessor's common
stock, valued at approximately $7.3 million, and $3.25 million cash. The
Predecessor assumed existing Taurus indebtedness of approximately $9.75
million. Taurus operates three natural gas processing facilities and owns
interests in approximately 700 miles of natural gas gathering systems
located primarily in west central Texas.
F-10
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In July 1994, Taurus acquired ownership of the Shackelford gas gathering
system and processing plant. Taurus had previously been operating the system
and plant under operating leases. Taurus paid $3.8 million for the system
and plant, which was funded under the existing credit agreement. In related
transactions, Taurus entered into an agreement to sell 10,000 MMBTU per day
to the former owner of Shackelford for a period of 48 months.
Simultaneously, Taurus entered into a gas purchase agreement with an
unrelated third party for similar quantities over the same term. Pricing
under both the gas sales agreement and the gas purchase agreement is
structured to allow Taurus to earn a margin on all volumes sold during the
term of the agreements. In January 1995, Taurus acquired the remaining
ownership interest in one of Taurus' gas plants and related facilities for
$6.5 million.
In December 1994, in two separate transactions, the Predecessor acquired
interests in 31 producing oil and gas properties in West Texas from two
major oil companies. The acquisition prices were $13.3Emillion and
$10.0Emillion, respectively. The acquisitions were accounted for as
purchases.
In October 1995, the Predecessor acquired from Snyder Oil Company interests
in 63 producing oil and gas properties located in West Texas (the "Snyder
Properties"). The aggregate purchase price was $17.1 million in cash, of
which $16.0 million was financed by borrowings under the existing credit
facility. The acquisition was accounted for as a purchase.
The following unaudited pro forma data present the consolidated results of
operations of the Predecessor for the year ended December 31, 1995, as if
the acquisition of the Snyder Properties had occurred on January 1, 1995.
The pro forma results of operations are presented for comparative purposes
only and are not necessarily indicative of the results that would have been
obtained had such acquisitions been consummated as presented. The following
data reflect pro forma adjustments for depletion, depreciation, and
amortization related to the acquired oil and gas properties; adjustments to
interest expense on borrowed funds; and resulting adjustments to income tax
expense (in thousands).
Pro forma
Year ended December 31,
1995
----------
(unaudited)
Revenues $102,997
========
Net income $6,107
======
F-11
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. Long-term debt
--------------
Long-term debt is summarized as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
----------------------
1995 1996
----------- ---------
Predecessor Successor
----------- ---------
<S> <C> <C>
NationsBank credit agreements $122,000 $64,500
Note payable to NationsBank 606 486
Senior subordinated debentures 988 -
Other 766 100
-------- -------
124,360 65,086
Less current maturities 453 120
-------- -------
Long-term debt $123,907 $64,966
======== =======
</TABLE>
NationsBank credit agreements - Effective February 16, 1996, CEI entered
-----------------------------
into a credit agreement with NationsBank of Texas, N.A. ("NationsBank"), as
lender and as agent, and additional lenders named therein (the "Credit
Agreement"). The Credit Agreement is guaranteed by all of Coda's
subsidiaries and provides for a revolving credit facility in an amount up to
$250.0 million. The borrowing base is subject to redetermination: (i)
semiannually, (ii) upon the sale of Taurus and (iii) upon issuance of public
subordinated debt in an amount greater than $100.0 million. The lenders
under the Credit Agreement agreed to waive their right to redetermine the
borrowing base with respect to the issuance of the Notes (see Note 6). The
borrowing base was redetermined effective July 1, 1996 and remained at
$115.0 million. At December 31, 1996, $64.5 million was outstanding under
the Credit Agreement and $50.5 million was available for borrowing
thereunder. The next redetermination of the borrowing base is scheduled for
April 1, 1997.
The Credit Agreement is unsecured. CEI has provided the lenders with first
lien deeds of trust on its oil and natural gas assets which will not become
effective, and the lenders have agreed not to file, unless (i) 80% of any
outstanding borrowings in excess of the borrowing base is not repaid within
a 90-day period, (ii) cash collateral securing a hedge transaction exceeds
20% of the borrowing base or (iii) an event of default or a material adverse
event, as defined in the Credit Agreement, occurs. There are no scheduled
principal payments due on the Credit Agreement until maturity.
So long as no default (as defined in the Credit Agreement) is continuing,
CEI has the option of having all or any portion of the amount borrowed under
the Credit Agreement be the subject of one of the following interest rates:
(i) NationsBank's prime rate, (ii) the CD Rate plus 1 1/4% to 1 5/8% based
upon the ratio of outstanding debt to the available borrowing base and (iii)
LIBOR plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to the
available borrowing base. CEI must also pay a commitment fee of between
0.375% to 0.425% on the unused portion of the credit facility. The Credit
Agreement contains various restrictive covenants, including limitations
F-12
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
on the granting of liens, restrictions on the issuance of additional debt,
restrictions on investments, a requirement to maintain positive working
capital, and restrictions on dividends and stock repurchases. The Credit
Agreement also contains requirements that JEDI or certain affiliates of JEDI
must continue to own a majority of the outstanding equity of Coda and must
have the ability to elect the majority of the Board of Directors and that
certain members of management maintain specified levels of equity ownership
in Coda and continue their employment with the Company. The Credit Agreement
matures on February 16, 2001.
On August 1, 1996, CEI entered into the First Amendment to Credit Agreement
(the "First Amendment") which in general reduced the interest rate. The
First Amendment provides CEI the option of having all or any portion of the
amount borrowed under the Credit Agreement be the subject of one of the
following interest rates: (i) NationsBank's prime rate, (ii) the CD Rate
plus 1% to 1 1/2% based upon the ratio of outstanding debt to the available
borrowing base and (iii) LIBOR plus 1% to 1 1/2% based upon the ratio of
outstanding debt to the available borrowing base. CEI must also pay a
commitment fee of between 0.30% to 0.425% on the unused portion of the
credit facility.
The Predecessor's credit agreement provided that interest rates on
borrowings ranged from NationsBank's prime rate to LIBOR plus between 1% and
1 3/8% based on the ratio of outstanding debt to the available borrowing
base. The weighted average interest rate on borrowings outstanding under the
Credit Agreement was 7.43% and 6.91% for the year ended December 31, 1995
and for the 319-day period ended December 31, 1996, respectively.
Note payable to NationsBank - The promissory note requires monthly
---------------------------
principal and interest payments to January 2, 1998, with interest at
NationsBank's prime rate.
Senior subordinated debentures - The 12% Senior Subordinated Debentures
------------------------------
(the "Debentures") are presented net of unamortized issuance discount of
$165,000 at December 31, 1995. The effective interest rate on the Debentures
is 16.61%. On May 1, 1996, CEI deposited with the trustee of the Debentures
funds sufficient to redeem the Debentures at a redemption price of 100.0% of
the principal amount of the Debentures plus accrued and unpaid interest
thereon, and thereafter interest on the Debentures ceased to accrue.
Scheduled maturities of long-term debt (including the Notes discussed in
Note 6 below) as of December 31, 1996, are as follows (in thousands):
<TABLE>
<CAPTION>
<S> <C>
1997 $ 120
1998 366
1999 100
2000 -
2001 64,500
Thereafter 110,000
--------
$175,086
========
</TABLE>
F-13
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As a result of the long-term debt bearing interest at floating market rates
and the minimal change in forward market interest rates from the time CEI
completed the sale of the Notes (see Note 6), the carrying value of these
financial instruments approximates fair value.
6. 10 1/2% Senior subordinated notes
---------------------------------
On March 18, 1996, CEI completed the sale of $110 million principal amount
of 10 1/2% Senior Subordinated Notes due 2006 (the "Notes"). The proceeds of
the Notes were used to fully repay the JEDI debt assumed in the Merger and
to partially repay bank debt. The Notes bear interest at an annual rate of
10 1/2% payable semiannually in arrears on April 1 and October 1 of each
year. The Notes are general, unsecured obligations of CEI, are subordinated
in right of payment to all Senior Debt (as defined in the Indenture
governing the Notes) of Coda, and are senior in right of payment to all
future subordinated debt of CEI. The claims of the holders of the Notes are
subordinated to Senior Debt, which, as of December 31, 1996, was $65.1
million.
The Notes were issued pursuant to an Indenture, which contains certain
covenants that, among other things, limit the ability of Coda and its
Restricted Subsidiaries (as defined in the Indenture) to incur additional
indebtedness and issue Disqualified Stock (as defined in the Indenture), pay
dividends, make distributions, make investments, make certain other
restricted payments, enter into certain transactions with affiliates,
dispose of certain assets, incur liens securing pari passu or subordinated
indebtedness of Coda and engage in mergers and consolidations.
The Notes are not redeemable by Coda's prior to April 1, 2001. After April
1, 2001, the Notes will be subject to redemption at the option of Coda, in
whole or in part, at the redemption prices set forth in the Indenture, plus
accrued and unpaid interest thereon to the applicable redemption date. In
addition, until March 12, 1999, up to $27.5 million in aggregate principal
amount of Notes are redeemable, at the option of Coda on any one or more
occasions from the net proceeds of an offering of common equity of Coda, at
a price of 110.5% of the aggregate principal amount of the Notes, together
with accrued and unpaid interest thereon to the date of the redemption;
provided, however, that at least $82.5 million in aggregate principal amount
of Notes must remain outstanding immediately after the occurrence of such
redemption; provided, further, that any such redemption shall occur within
75 days of the date of the closing of such offering of common equity.
In the event of a Change of Control (as defined in the Indenture), holders
of the Notes will have the right to require Coda to repurchase their Notes,
in whole or in part, at a price in cash equal to 101% of the aggregate
principal amount thereof, plus accrued and unpaid interest thereon to the
date of repurchase. The Indenture requires that, prior to such a repurchase
but in any event within 90 days of such Change of Control, Coda must either
repay all Senior Debt or obtain any required consent to such repurchase.
F-14
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Coda's payment obligations under the Notes are fully, unconditionally and
jointly and severally guaranteed on a senior subordinated basis by all of
Coda's current subsidiaries and future Restricted Subsidiaries. Such
guarantees are subordinated to the guarantees of Senior Debt issued by the
Guarantors (as defined in the Indenture) under the Credit Agreement and to
other guarantees of Senior Debt issued in the future. All of Coda's current
subsidiaries are wholly owned. There are currently no contractual
restrictions on distributions from the Guarantors to Coda.
Separate financial statements and other disclosures concerning the
Guarantors are not presented because management has determined they are not
material to investors. The combined condensed financial information of
Coda's current subsidiaries, the Guarantors, is as follows:
<TABLE>
<CAPTION>
December 31,
----------------------
1995 1996
----------- ---------
Predecessor Successor
----------- ---------
<S> <C> <C>
Current assets $ 5,394 $ 7,745
Oil and gas properties, net 36,469 50,176
Gas plants and gathering systems, net 33,650 31,617
Other properties, net, and other assets 1,713 1,113
------- -------
Total assets $77,226 $90,651
======= =======
Current liabilities $ 5,629 $ 8,321
Intercompany payables 50,172 33,551
Deferred income taxes 7,828 16,191
Stockholder's equity 13,597 32,588
------- -------
Total liabilities and stockholder's equity $77,226 $90,651
======= =======
</TABLE>
F-15
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Predecessor Successor
---------------------------------- -------------
Year ended 47 days 319 days
December 31, ended ended
-------------------- February 16, December 31,
1994 1995 1996 1996
------- -------- ----------- ------------
(unaudited)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales $17,660 $18,826 $2,529 $25,115
Gas gathering and processing 20,031 35,634 5,322 39,553
Other income 251 244 2 215
------- ------- ------ -------
37,942 54,704 7,853 64,883
Costs and expenses:
Oil and gas production 4,706 7,023 843 6,718
Gas gathering and processing 17,324 30,473 4,567 32,825
Depletion, depreciation and
amortization 6,719 7,776 1,039 9,537
General and administrative 1,158 3,936 435 2,993
Interest 2,628 3,538 460 2,443
Business combination 1,184 - - -
Writedown of oil and gas
properties - - - 19,159
------- ------- ------ -------
33,719 52,746 7,344 73,675
------- ------- ------ -------
Income (loss) before income
taxes 4,223 1,958 509 (8,792)
Income tax expense (benefit) 1,813 822 277 (2,898)
------- ------- ------ -------
Net income (loss) $ 2,410 $ 1,136 $ 232 $(5,894)
======= ======= ====== =======
</TABLE>
7. Preferred Stock
---------------
Under Coda's Restated Certificate of Incorporation, the Board of Directors
is authorized to issue up to 40,000 shares of preferred stock, par value
$0.01 per share. All 40,000 shares of preferred stock are designated as "15%
Cumulative Preferred Stock," (the "Preferred Stock"). The holders of each
share of Preferred Stock are entitled to receive, when and as declared by
the Board of Directors, cumulative preferential dividends, at the rate of
$150.00 per share per annum. There are currently 20,000 shares of Preferred
Stock issued and outstanding. Shares of Preferred Stock in excess of such
20,000 shares shall be issuable only for the purpose of paying dividends on
the Preferred Stock. As of December 31, 1996, the Preferred Stock had
accumulated approximately $2.7 million in preferred dividends which had not
been declared by the Board of Directors.
F-16
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As long as any shares of Preferred Stock are outstanding, no dividends
whatsoever, whether paid in cash, stock or otherwise (except for dividends
paid in shares of common stock, either in the form of a stock split or stock
dividend), may be paid or declared, nor may any distribution be made, on any
common stock to the holders of such stock, unless certain conditions are
met.
Coda's Restated Certificate of Incorporation requires that Coda redeem all
the issued and outstanding shares of Preferred Stock at a redemption of
$1,000 per share, plus all accrued and unpaid dividends (including
undeclared dividends) to the date of redemption, if Coda has sufficient
funds legally available for such redemption and if such redemption would not
violate or conflict with any loan agreement, credit agreement, note
agreement, indenture or other agreement relating to indebtedness to which
Coda is a party, on or before the fifth business day after the earliest to
occur of the following: (i) the closing of the sale by Coda of Taurus and
(ii) a Trigger Event, as such term is defined in the Stockholders Agreement
(see Note 13). The Preferred Stock may be redeemed by Coda at its option, as
a whole or in part, to the extent Coda shall have funds legally available
for such redemption, at any time or from time to time at a redemption price
of $1,000 per share, plus all accrued and unpaid dividends (including
undeclared dividends) to the date of redemption. Such redemption, whether
required or optional, is restricted by the Credit Agreement and the
Indenture.
Upon the complete liquidation, dissolution, or winding up of Coda, whether
voluntarily or involuntarily, the holders of Preferred Stock shall be
entitled, after payment or provision for payment of the debts and other
liabilities of Coda but before any distribution is made to the holders of
any common stock, to be paid $1,000 per share plus all accrued and unpaid
dividends (including undeclared dividends), and shall not be entitled to any
further payment.
Except as otherwise provided herein or required by law, the holders of
shares of Preferred Stock are not entitled to vote on any matters to be
voted on by the stockholders of Coda; provided, however, that so long as any
shares of the Preferred Stock are outstanding, Coda shall not, without the
written consent or the affirmative vote of holders of at least a majority of
the total number of sharers of Preferred Stock then outstanding and voting
as a class, (i) amend its Restated Certificate of Incorporation or Bylaws or
(ii) authorize the merger (whether or not Coda is a surviving corporation in
such merger) of Coda, in each case, if such amendment or merger would alter,
change or abolish the powers, preference or rights of the Preferred Stock so
as to affect the holders of the Preferred Stock adversely.
8. Common equity
-------------
Common stock - At December 31, 1995, the Predecessor had 40.0 million
------------
shares of $0.02 par value common stock authorized with 22.1 million shares
issued and outstanding. At December 31, 1996, CEI had 1.0 million shares of
$0.01 par value common stock authorized with 13,611 shares
F-17
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
issued to management subject to put and call rights (see Note 13. Related
Party Transactions - Stockholders Agreement) and 900,000 issued to JEDI for
a total of 913,611 common shares issued and outstanding.
Stock options and warrants - The Company has stock option plans providing
--------------------------
for the granting of stock options to officers and key employees.
Compensation expense has not been recognized at the time options are granted
because the option price per share represents the market value of the share
at the date of grant.
The 1986 Non-Qualified Stock Option Plan provided that options may be
granted, from time to time, to key employees and directors to purchase a
maximum of 180,000 shares of common stock. This plan expired under its own
terms during 1996. The 1989 Incentive Stock Option Plan provides that
options may be granted, from time to time, to key employees to purchase a
maximum of 750,000 shares of common stock. The 1993 Incentive Stock Option
Plan permits the granting of options to purchase up to 1,500,000 shares of
common stock.
Option transactions are summarized below:
<TABLE>
<CAPTION>
Number Option
of shares price range
--------- -------------
<S> <C> <C>
Outstanding at December 31, 1993 899,084 $2.25 - $6.00
Granted 525,785 5.00 - 6.50
Exercised (108,629) 2.25 - 5.75
Forfeited (56,708) 3.50 - 5.75
---------
Outstanding at December 31, 1994 1,259,532 2.25 - 6.50
Granted --
Exercised (100,213) 2.25 - 5.75
Forfeited (42,687) 3.50 - 5.75
---------
Outstanding at December 31, 1995 1,116,632 2.25 - 6.50
Granted --
Exercised --
Canceled and exchanged for CEI option (164,375) 2.25 - 6.00
Forfeited (1,917) 5.63
---------
Outstanding at February 16, 1996
(subsequently terminated - see
following discussion) 950,340 2.25 - 6.50
=========
</TABLE>
F-18
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes warrants outstanding at February 16, 1996
exclusive of warrants covering 700,000 shares exchanged for a CEI option:
<TABLE>
<CAPTION>
Exercise
Number of price
shares under warrants Expiration date per share
------------------------- --------------- ---------
<S> <C> <C>
450,000 December 2000 3.13
50,000 April 2002 3.00
100,000 April 2004 4.88
-------
600,000
-------
</TABLE>
As a result of the Merger, all outstanding options and warrants were fully
vested and the holders thereof were entitled to receive the difference
between $7.75 per share and the exercise price for each share represented by
the options and warrants, an aggregate of approximately $5.4 million.
Additionally, certain members of the management of the Company exchanged
their right to receive payment as it relates to options covering 164,375
shares and warrants covering 700,000 shares with an aggregate value of
approximately $3.2 million for an equity participation in CEI (the
Replacement Options, Note 13). Such amount was recognized as stock option
compensation expense in the 47-day period ended February 16, 1996. This
equity participation took the form of options covering 31,989 CEI common
shares with an exercise price of $.01, a 10-year term and immediately
exercisable.
The stock options outstanding at December 31, 1996, were not issued pursuant
to any of the stock option plans. A certain number of shares could be
reserved for issuance under the stock option plans in future periods;
however, management does not presently expect any options to be granted
pursuant thereto. See Note 13.
The Company has elected to follow APB 25 in accounting for its employee
stock options because, as discussed below, the alternative fair value
accounting provided for under FAS 123 requires use of option valuation
models that were not developed for use in valuing employee stock options.
Generally, under APB 25, because the exercise price of the employee stock
options equals the market price of the underlying stock on the date of
grant, no compensation expense is recognized. The compensation expense
recognized under APB 25 is due to changing the exercise price of the options
in connection with the Merger.
FAS 123 requires the use of the "minimum value" method for determining the
value of employee stock options for nonpublic companies. This method
estimates the value of the employee stock option as the excess of the fair
value of the stock at the date of grant over the present value of both the
exercise price and the expected dividend payments, each discounted at the
risk-free rate, over the expected life of the option. FAS 123 generally
requires the presentation of pro forma information as if employee stock
options had been accounted for under FAS 123. However, due to the
recognition of compensation expense under APB 25, at the date of the Merger
and the absence of options grants subsequent thereto, the pro forma
information would not be materially different from the historical results of
operations.
F-19
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. Employee benefit plan
---------------------
The Company sponsors a 401(k) defined contribution plan. The 401(k) plan is
available to all employees who have at least six months of service. The
Company matches between 50% and 100% (based on years of service) of an
employee's contribution up to 6% of an employee's compensation. For the
years ended December 31, 1994 and 1995, the 47 days ended February 16, 1996
and the 319 days ended December 31, 1996, the Company 401(k) expense was
$123,000, $252,000, $37,000 and $282,000, respectively, and is included in
general and administrative expenses in the accompanying statements of
operations.
10. Income taxes
------------
At December 31, 1996, Coda has net operating loss carryforwards ("NOLs") for
income tax purposes that expire beginning in 1998. Utilization of the NOLs
is severely restricted because of a change in ownership, as defined by the
Tax Reform Act of 1986, of Coda, which occurred in March 1990. At December
31, 1996, Coda estimates that approximately $18.0 million of the NOLs is
available to offset future taxable income without limitation, while the
remainder will become available in the future at the rate of approximately
$921,000 per year through 2004. Coda also has available statutory depletion
carryforwards of approximately $1,000,000.
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for income tax purposes. Significant
components of deferred tax liabilities and assets are as follows (in
thousands):
<TABLE>
<CAPTION>
December 31,
-----------------------
1995 1996
------------ ---------
Predecessor Successor
------------ ---------
<S> <C> <C>
Deferred tax liabilities:
Book basis of oil and gas properties
in excess of tax basis $11,441 $37,611
Book basis of gas plants and gathering
systems in excess of tax basis 6,447 7,633
Other 1,074 1,315
------- -------
Total deferred tax liabilities 18,962 46,559
Deferred tax assets:
Net operating loss carryforwards 8,468 9,323
Other 136 175
Valuation allowance for deferred tax assets (4,042) -
------- -------
Net deferred tax assets 4,562 9,498
------- -------
Net deferred tax liabilities $14,400 $37,061
======= =======
</TABLE>
F-20
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Significant components of income tax expense attributable to continuing
operations are as follows (in thousands):
<TABLE>
<CAPTION>
Predecessor Successor
------------------------------------ ------------
Year ended 47 days 319 days
December 31, ended ended
-------------------- February 16, December 31,
1994 1995 1996 1996
-------- ---------- ------------- ------------
(unaudited)
<S> <C> <C> <C> <C>
Current $ 733 $ 15 $ - $ 571
Deferred federal 1,848 3,187 (511) (27,254)
------ ------ ------ --------
$2,581 $3,202 $ (511) $(26,683)
====== ====== ====== ========
</TABLE>
The following is a reconciliation, stated as a percentage of pretax income
(loss) taxable at the corporate level, of the U.S. statutory federal income
tax rate to the Company's effective tax rate:
<TABLE>
<CAPTION>
Predecessor Successor
------------------------------------------- -----------
Year ended 47 days 319 days
December 31, ended ended
---------------------------- February 16, December 31,
1994 1995 1996 1996
------------- ------------- ------------- -----------
<S> <C> <C> <C> <C>
(unaudited)
U.S. federal statutory rate 34% 34% 34% 34%
State taxes 5 2 (1) 2
Non-deductible business
combination expenses 5 - - -
---- ---- ---- ----
44% 36% 33% 36%
==== ==== ==== ====
</TABLE>
1. Operations
----------
Nature of Operations
The Company is an independent energy company principally engaged in the
acquisition and exploitation of producing oil and natural gas properties.
The Company seeks to acquire properties whose predominant economic value is
attributable to proved producing reserves and to enhance that value through
control of operations, reduction of costs, and property development. The
Company's producing properties are concentrated in the mid-continent region
of the United
F-21
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
States. Through a subsidiary, Taurus, the Company also operates natural gas
processing and liquid extraction facilities and natural gas gathering
systems.
Oil and Gas Producing Activities
The results of operations from the Company's oil and gas producing
activities are as follows (in thousands):
<TABLE>
<CAPTION>
Predecessor Successor
---------------------------------------- -------------
Year ended 47 days 319 days
December 31, ended ended
------------------------- February 16, December 31,
1994 1995 1996 1996
----------- ------------ ------------- -------------
<S> <C> <C> <C> <C>
(unaudited)
Oil and gas sales $ 50,683 $ 60,997 $ 8,079 $ 68,690
Production costs (21,646) (27,119) (3,607) (28,560)
Depletion, depreciation, and amortization (14,853) (16,889) (2,161) (20,757)
Writedown of oil and gas properties - - - (83,305)
Income tax (expense) benefit at 34% (4,823) (5,776) (786) 22,570
-------- -------- ------- --------
$ 9,361 $ 11,213 $ 1,525 $(41,362)
======== ======== ======= ========
</TABLE>
Costs incurred in oil and gas producing activities are as follows (in
thousands, except per equivalent barrel amounts):
<TABLE>
<CAPTION>
Predecessor Successor
---------------------------------------- -------------
Year ended 47 days 319 days
December 31, ended ended
------------------------- February 16, December 31,
1994 1995 1996 1996
----------- ------------ ------------- -------------
<S> <C> <C> <C> <C>
(unaudited)
Property acquisition costs $40,109 $25,363 $ 305 $324,732/(1)/
Development costs 12,450 14,464 1,286 8,608
Exploration costs 206 511 - -
Depletion, depreciation, and amortization
rate per equivalent barrel 4.25 4.33 4.40 5.89
</TABLE>
/(1)/ Includes approximately $320.5 million related to the Merger
discussed in Note 1.
F-22
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All of the Company's oil and gas revenues are from proved developed
properties located in the United States.
The Company has capitalized internal costs of $712,000, $748,000, $105,000,
and $567,000 for the years ended December 31, 1994, and 1995, the 47 days
ended February 16, 1996, and the 319 days ended December 31, 1996,
respectively. Such capitalized costs include salaries and related benefits
of individuals directly involved in the Company's acquisition, exploration,
and development activities based on the percentage of their time devoted to
such activities.
During the year ended December 31, 1994, sales of oil and gas to two
purchasers accounted for 13% and 22% of consolidated gross revenue. During
the year ended December 31, 1995, sales of oil and gas to two purchasers
accounted for 10% and 18%, respectively, of consolidated gross revenue.
During the 47 days ended February 16, 1996, sales of oil and gas to one
purchaser accounted for 17% of consolidated gross revenue. During the 319
days ended December 31, 1996, sales of oil and gas to one purchaser
accounted for 20% of consolidated gross revenue (an affiliate of Enron - see
Note 13). Management believes that the loss of these purchasers would not
have a material impact on the Company's consolidated financial condition or
results of operations.
Oil and Gas Hedging Activities and Commitments
In an effort to reduce the effects of the volatility of the price of crude
oil and natural gas on the Company's operations, management has adopted a
policy of hedging oil and gas prices whenever such prices are in excess of
the prices anticipated in the Company's operating budget and profit plan
through the use of commodity futures, options, and swap agreements. The
Company does not hold or issue financial instruments for trading purposes.
While the use of these hedging arrangements limits the downside risk of
adverse price movements, it may also limit future gains from favorable
movements. All hedging is accomplished pursuant to exchange-traded contracts
or master swap agreements based upon standard forms. The Company addresses
market risk by selecting instruments whose value fluctuations correlate
strongly with the underlying commodity being hedged. Credit risk related to
hedging activities, which is minimal, is managed by requiring minimum credit
standards for counterparties, periodic settlements, and market to market
valuations. The Company has not historically been required to provide any
significant amount of collateral relating to its hedging activities.
At December 31, 1996, the Company had entered into various swap agreements
to fix selling prices for crude oil at a weighted average NYMEX price of
$19.13 per barrel for 735,000 barrels during 1997, certain of which are with
affiliates of JEDI (see Note 13). The Company has also sold call options,
which serve to limit the Company's oil price, covering 25,000 barrels of oil
per month at an option price of $20.00 per barrel for the period January
1997 to August 1997. In connection with two swaps beginning January 1, 1997
covering 10,000 barrels per month and
F-23
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15,000 barrels per month at a strike price of $19.41 and $19.00,
respectively, which expire June 30, 1997 and December 31, 1997,
respectively, the Company granted the counterparty a one day option at the
expiration of the swap to extend the swap for an additional twelve months.
While these contracts have no carrying value in the accompanying balance
sheet, their fair value (the estimated amount that would have been paid by
the Company to terminate of the swaps) at December 31, 1996 was
approximately $4.4 million. A one dollar change in the average NYMEX oil
price (which was $25.92 at December 31, 1996) would change the fair value by
approximately $1.2 million.
During the years ended December 31, 1994 and 1995, the 47 days ended
February 16, 1996 and the 319 days ended December 31, 1996, oil and gas
sales were reduced by $5,000, increased by $298,000, reduced by $14,000, and
reduced by $3.1 million, respectively, as a result of hedging transactions.
12. Commitments and contingencies
-----------------------------
CEI does not believe that future costs related to site restoration,
dismantlement, and abandonment costs, net of estimated salvage values, will
have a significant effect on its results of operations or financial position
because the salvage value of equipment and related facilities should
approximate or exceed any future expenditures for restoration,
dismantlement, or abandonment. The Company has not incurred any net
expenditures for costs of this nature during the last three years.
The Company is a defendant or co-defendant in minor lawsuits that have
arisen in the ordinary course of business. In the lawsuits, management
believes, based in part on advice from legal counsel, that the Company has
meritorious defense against the claims asserted. Management believes that
the ultimate resolution of the lawsuits and claims will not have a material
adverse effect on results of operations or financial position.
13. Related party transactions
--------------------------
Subscription Agreement
CAI entered into a Subscription Agreement dated as of October 30, 1995, as
amended by Amendment No. 1 to Subscription Agreement dated as of January 10,
1996, with members of the Management Group (as amended, the "Subscription
Agreement") which provided for the acquisition by such persons of CAI common
stock and the grant to them of nonqualified stock options to purchase shares
of successor common stock (the "Replacement Options") of Coda. Under the
Subscription Agreement, each member of the Management Group who acquired CAI
common stock paid $100 per share for shares thereof, which is the same price
per share paid by JEDI for the remaining shares of CAI common stock. Under
the Subscription Agreement, the Management Group acquired CAI common stock
immediately prior to the effective time of the
F-24
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Merger in exchange for varying combinations of (i) proceeds from limited
recourse promissory notes payable to CAI in the aggregate principal amount
of $937,300 (the "Promissory Notes"), (ii) Coda common stock, which was
valued for this purpose at $7.75 per share, and (iii) cash. The CAI common
stock so acquired was not registered under any federal or state securities
laws and did not have the benefit of any registration rights, but was
subject to the Stockholders Agreement described below. By virtue of the
Merger, each share of CAI common stock was converted into one share of Coda
common stock.
The Promissory Notes are due on February 16, 2001, bear interest at 5.61%
per annum, are secured by the common stock purchased with the proceeds
thereof and certain rights of the maker under the Stockholders Agreement,
and provide that in no event will an individual maker's liability thereunder
for any deficiency on his respective Promissory Note (after the sale and
disposition of all collateral securing same) exceed 35% of the original
principal balance of the Promissory Note.
The Subscription Agreement provided that the Specified Options (representing
certain options to purchase common stock held by certain members of the
Management Group) and Specified Warrants (representing certain warrants to
purchase common stock held by certain members of the Management Group) would
not be exercised prior to the effective time of the Merger and would, as of
the effective time, be canceled without exercise and without payment of
consideration. Concurrently, the Management Group entered into Nonstatutory
Stock Option Agreements governing the Replacement Options that provided for
the right for a period of 10 years from and after the effective time of the
Merger to purchase shares of CEI common stock for $0.01 per share. However,
the Replacement Options may only be exercised while the holder remains an
employee and for a limited period of time thereafter. The number of shares
of Coda common stock underlying the Replacement Options each member of the
Management Group received is based on the amount of cash the holder would
have received if his Specified Options or Specified Warrants had been
converted into cash in the Merger on the same basis as other outstanding
options and warrants to purchase common stock were converted, divided by the
$100 per share purchase price paid by JEDI and the other Management Group
members for their shares of CAI common stock. Thus, if the Replacement
Options are exercised, the holders will have effectively paid the same
purchase price per share as JEDI and the Management Group paid for their
shares of common stock of Coda.
In connection with the issuance of the Replacement Options, the Company
recognized stock option compensation expense of approximately $3.2 million
in the 47 days ended February 16, 1996 representing the total amount of cash
the holders of the Specified Options and Specified Warrants would have
received if such options and warrants had been converted to cash in the
Merger.
F-25
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stockholders Agreement
CAI, JEDI and the Management Group entered into a Stockholders Agreement
dated as of October 30, 1995, as amended by Amendment No. 1 to Stockholders
Agreement dated as of January 10, 1996 (as amended, the "Stockholders
Agreement"), which provides generally that all parties, including JEDI and
the Management Group, (i) have rights of first refusal to acquire additional
shares of common stock of Coda that may be issued by Coda and (ii) are
restricted from transferring their Coda common stock. Coda has a right to
match any third party offer to purchase shares of Coda common stock from any
stockholder, and, in the event that Coda does not purchase those shares, the
other stockholders may have a right to include a pro rata portion of their
Coda common stock in the transaction. The Stockholders Agreement provides
that, if the employment of a member of the Management Group terminates for
any reason (including death or disability) other than his voluntary
termination (except upon retirement at age 65 or older or the expiration of
the term of any employment agreement he has with Coda) or his termination by
Coda for cause, then Coda shall have a right to purchase such member's
shares of Coda common stock (an aggregate of 13,611 shares at December 31,
1996) at a purchase price to be determined from time to time by Coda
pursuant to a formula that values the shares on the basis of a comparison of
the discretionary cash flow and EBITDA (as defined therein) of the Company
and a group of peer companies. The Stockholders Agreement also provides
that, if the employment of a member of the Management Group terminates for
any reason other than voluntary termination or termination of such member
for cause, then such member shall have the right to require Coda to purchase
such member's shares of Coda common stock based on the previously described
formula. The purchase price under the formula will vary depending on the
financial performance of CEI and the group of peer companies.
The Stockholders Agreement provides that each member of the Management Group
shall have the right (the "Special Management Rights") to receive from JEDI,
upon the occurrence of certain events (generally an initial public offering,
a business combination with another person or the liquidation of Coda)
(each, a "Trigger Event"), an amount, which is payable in cash or additional
shares of Coda common stock depending upon the cause of the Trigger Event,
designed to result in the Management Group receiving in connection with the
Trigger Event one-third of the proceeds, attributable to the shares of Coda
common stock purchased by JEDI, above the amount of proceeds necessary for
JEDI to achieve an internal annual rate of return on that investment of 15%.
The individual member's interest in such Special Management Rights is
proportional to such member's ownership of the fully diluted common stock of
Coda. The Stockholders Agreement also provides that if the employment of a
member of the Management Group terminates, his Special Management Rights
shall terminate and, if the termination is other than a voluntary
termination or a termination for cause, he may be entitled to receive an
amount based on the discretionary cash flow and EBITDA formula discussed
above. The Stockholders Agreement further provides that, after the effective
time of the Merger, Coda will establish an employee benefit plan for the
benefit of its employees who are not members of the Management Group and
will contribute to the plan 1,900 shares of Coda common stock. Furthermore,
pursuant to the Stockholders Agreement, 4% of the Special Management Rights
will be allocated thereto.
F-26
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At September 30, 1996, the discretionary cash flow and EBITDA formula
determines a theoretical value for Coda's common stock which indicates JEDI
would have earned more than a 15% rate of return on its investments. The
information to calculate the discretionary cash flow and EBITDA formula as
of December 31, 1996, is not yet available. As determined by the
discretionary cash flow and EBITDA formula, the value of the Special
Management Rights to the Management Group in the aggregate was approximately
$38 million at September 30, 1996. When a Trigger Event becomes probable,
the Company will record compensation expense equal to the estimated value of
the Special Management Rights at the time of such trigger event, which may
be significantly different than the amount as of September 30, 1996. Since
the Special Management Rights are an obligation of JEDI, the offsetting
credit would be additional paid-in capital.
The Stockholders Agreement will terminate and no party thereto will have any
further obligations or rights thereunder upon the earliest to occur of (i)
the termination of the Merger Agreement in accordance with its terms, (ii)
October 30, 2005, (iii) the date on which an initial public offering of Coda
common stock or any business transaction involving Coda whereby Coda common
stock becomes a publicly traded security is consummated, (iv) the date of
the dissolution, liquidation or winding-up of Coda and (v) the date of the
delivery to Coda of a written termination notice executed by certain parties
to the Stockholders Agreement.
Enron
Enron Corp. ("Enron") is the parent of ECT and accordingly may be deemed to
control indirectly both JEDI and CEI. Enron and certain of its subsidiaries
and other affiliates collectively participate in nearly all phases of the
oil and natural gas industry and are, therefore, competitors of CEI. In
addition, ECT and JEDI have provided, and may in the future provide, and ECT
Securities Corp. has assisted, and may in the future assist, in arranging,
financing to non-affiliated participants in the oil and natural gas industry
who are or may become competitors of CEI. Because of these various
conflicting interests, ECT, CEI, JEDI and the Management Group have entered
into the Business Opportunity Agreement which is intended to make it clear
that Enron and its affiliates have no duty to make business opportunities
available to CEI in most circumstances. The Business Opportunity Agreement
also provides that ECT and its affiliates may pursue certain business
opportunities to the exclusion of CEI. The Business Opportunity Agreement
may limit the business opportunities available to CEI. In addition, pursuant
to the Business Opportunity Agreement there may be circumstances in which
CEI will offer business opportunities to certain affiliates of Enron. If an
Enron affiliate is offered such an opportunity and decides to pursue it, CEI
may be unable to pursue it.
Certain of Enron's affiliates purchase oil and gas from the Company.
Management of the Company had determined that the contracts for sale of oil
and gas to Enron affiliates have been entered into on terms no less
favorable than those available from third parties after receiving
competitive bids from third parties. Enron affiliates paid CEI approximately
$24.1 million under
F-27
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
such contracts for the 319 days ended December 31, 1996. Such amount is
included in oil and gas revenue in the accompanying statement of operations.
The Company has entered into two fixed price oil swaps with ECT. One swap
covers the period from January 1, 1995 through June 30, 1997 at a strike
price of $19.05 covering 15,000 barrels per month. The other covers the
period from January 1, 1997 through December 31, 1997 at a strike price of
$19.55 covering 10,000 barrels per month. Management of the Company had
determined that both swaps were entered into on terms no less favorable than
those available from third parties after receiving competitive bids from
third parties. CEI paid ECT approximately $539,000 under such contracts for
the 319 days ended December 31, 1996.
During August 1996, Douglas H. Miller ("Miller"), the Company's Chief
Executive Officer and Chairman of the Board of Directors, received $738,000
pursuant to a Limited Recourse Promissory Note in the original principal
amount of $1,188,000 (the "Miller Note"). The Miller Note bears interest at
6.74% per annum with final maturity on February 16, 2001, and provides that
in no event will Miller's liability thereunder (after the sale and
disposition of all collateral securing same) exceed 35% of the original
principal balance of the Miller Note. In connection with the execution of
the Miller Note, CEI and Miller entered into an amendment of the agreement
governing Miller's Replacement Option which prohibits the exercise of the
option until all amounts due under the Miller Note have been paid in full.
14. Supplemental oil and gas reserve and standardized measure information
---------------------------------------------------------------------
(unaudited)
-----------
The Company retains independent engineering firms to provide annual year-end
estimates of the Company's future net recoverable oil, gas, and natural gas
liquids reserves. Estimated proved net recoverable reserves as shown below
include only those quantities that can be expected to be commercially
recoverable at prices and costs in effect at the balance sheet dates under
existing regulatory practices and with conventional equipment and operating
methods. Proved developed reserves represent only those reserves expected to
be recovered through existing wells. Proved undeveloped reserves include
those reserves expected to be recovered from new wells on undrilled acreage
or from existing wells on which a relatively major expenditure is required
for recompletion.
Reserve estimates are imprecise and may be expected to change as additional
information becomes available. Furthermore, estimates of oil and gas
reserves, of necessity, are projections based on engineering data, and there
are uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
way, and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and
judgment. Accordingly, there can be no assurance that the reserves set forth
herein will ultimately be produced nor can there be assurance that the
proved undeveloped reserves will be developed within the periods
anticipated. The Company emphasizes with respect to the estimates prepared
F-28
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
by independent petroleum engineers that the discounted future net cash
inflows should not be construed as representative of the fair market value
of the proved oil and gas properties belonging to the Company, since
discounted future net cash inflows are based upon projected cash inflows
which do not provide for changes in oil and gas prices nor for escalation of
expenses and capital costs. The meaningfulness of such estimates is highly
dependent upon the accuracy of the assumptions upon which they were based.
Estimated Quantities of Proved Reserves
(in thousands)
<TABLE>
<CAPTION>
Oil (Bbl) Gas (Mcf)
--------- ---------
<S> <C> <C>
December 31, 1993 30,084 36,196
Purchase of reserves in place 11,038 5,482
Extensions 271 912
Revisions of previous estimates 749 4,107
Production (2,650) (4,982)
Sales of reserves in place (285) (1,907)
------ -------
December 31, 1994 39,207 39,808
Purchase of reserves in place 7,324 7,298
Extensions 783 3,173
Revisions of previous estimates (1,011) 1,459
Production (3,165) (4,416)
Sales of reserves in place (548) (10,192)
------ -------
December 31, 1995 42,590 37,130
Purchase of reserves in place 64 10
Production (405) (500)
Sales of reserves in place (14) (4)
------ -------
February 16, 1996 42,235 36,636
====== =======
Purchase of reserves in place 43,431 36,862
Extensions 121 4,982
Revisions of previous estimates 2,579 604
Production (2,974) (3,310)
Sales of reserves in place (120) (93)
------ -------
December 31, 1996 43,037 39,045
====== =======
</TABLE>
F-29
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Estimated Quantities of Proved Developed Reserves
(in thousands)
Oil (Bbl) Gas (Mcf)
--------- ---------
<S> <C> <C>
December 31, 1993 16,230 30,573
December 31, 1994 20,151 32,890
December 31, 1995 25,877 31,496
February 16, 1996 25,522 31,002
December 31, 1996 33,895 33,255
</TABLE>
The following is a summary of a standardized measure of discounted net cash
flows related to the Company's proved oil, gas, and natural gas liquids
reserves. The information presented is based on a valuation of proved
reserves using discounted cash flows based on year-end prices, costs, and
economic conditions and a 10% discount rate exclusive of the effect of the
oil hedging commitments. The additions to proved reserves from new
discoveries and extensions could vary significantly from year to year;
additionally, the impact of changes to reflect current prices and costs of
reserves proved in prior years could also be significant. Accordingly, the
information presented below should not be viewed as an estimate of the fair
value of the Company's oil and gas properties, nor should it be considered
indicative of any trends.
Standardized Measure of Discounted Future Net Cash Flows
(in thousands)
<TABLE>
<CAPTION>
Predecessor Successor
-------------------------- ------------
December 31, February 16, December 31,
1995 1996 1996
------------ ------------ ------------
<S> <C> <C> <C>
Future cash inflows $860,180 $827,883 $1,208,793
Future production and
development costs 366,421 360,511 431,250
Future income taxes 113,775 106,672 206,720
-------- -------- ----------
Future net cash flows 379,984 360,700 570,823
Discount of future net cash
flows at 10% per annum 159,242 152,437 242,964
-------- -------- ----------
Discounted future net cash
flows after income taxes $220,742 $208,263 $ 327,859
======== ======== ==========
</TABLE>
During recent years, there have been significant fluctuations in the prices
paid for crude oil in the world markets. This situation has had a
destabilizing effect on crude oil's posted prices in the United States,
including the posted prices paid by purchasers of the Company's crude oil.
The weighted average prices of oil and gas at December 31, 1995, February
16, 1996 and December 31, 1996 used in the above table, were $18.31, $17.92
and $24.88 per Bbl, respectively, and $2.19, $2.01 and $3.53 per Mcf,
respectively.
F-30
<PAGE>
The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands):
<TABLE>
<CAPTION>
Predecessor Successor
--------------------------------------- -------------
Year ended 47 Days 319 Days
December 31, ended ended
------------------------ February 16, December 31,
1994 1995 1996 1996
------------ ---------- ------------- -------------
<S> <C> <C> <C> <C>
Sales and transfers of oil and gas produced,
net of production costs $(29,037) $(33,878) $ (4,472) $ (40,130)
Net changes in prices and production costs 18,674 37,290 (21,595) 152,369
Extensions and discoveries, net of future
development and production costs 3,673 15,932 - 12,338
Development costs during the period 12,656 14,464 1,286 8,608
Revisions of previous quantity estimates 3,579 (19,084) - 48,120
Sales of reserves in place (1,755) (6,323) (70) (365)
Purchases of reserves in place 54,672 35,680 389 215,529
Accretion of discount before income taxes 14,098 21,754 4,880 31,438
Net change in income taxes (23,967) (13,709) 7,103 (100,048)
-------- -------- -------- ---------
Net change $ 52,593 $ 52,126 $(12,479) $ 327,859
======== ======== ======== =========
</TABLE>
F-31
<PAGE>
Exhibit 21
Coda Energy, Inc.
Subsidiaries
Name State of Incorporation Ownership %
- ---- ---------------------- -----------
Diamond Energy Operating Company Oklahoma 100%
Taurus Energy Corp. Texas 100%
Electra Resources Inc. Texas 100%
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
FINANCIAL STATEMENTS OF CODA ENERGY, INC. FOR THE 319 DAYS ENDED DECEMBER 31,
1996, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> OTHER
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> FEB-17-1996
<PERIOD-END> DEC-31-1996
<CASH> 7,994
<SECURITIES> 0
<RECEIVABLES> 16,105
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 25,145
<PP&E> 295,792
<DEPRECIATION> 23,062
<TOTAL-ASSETS> 295,570
<CURRENT-LIABILITIES> 18,209
<BONDS> 174,966
0
20,000
<COMMON> 9
<OTHER-SE> 45,334
<TOTAL-LIABILITY-AND-EQUITY> 295,570
<SALES> 108,243
<TOTAL-REVENUES> 110,382
<CGS> 61,385
<TOTAL-COSTS> 61,385
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 14,555
<INCOME-PRETAX> (74,972)
<INCOME-TAX> (26,683)
<INCOME-CONTINUING> (48,289)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (48,289)
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
