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FORM 10-K\A NO.2
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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PART I
Item 1. BUSINESS
--------
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 2,265 of the 2,983 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
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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). 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 a 74% working interest in the proposed unit.
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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 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 an 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
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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.
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 SLSAU 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 the
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.
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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 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
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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 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
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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 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
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in July 1998. For the year ended December 31, 1996, Taurus received net proceeds
under these contracts of approximately $1 million.
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
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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.
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
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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.
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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. Re serve 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.
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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 599 gross and 439 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 2,396 17 1,829 9
Oklahoma 468 24 280 9
Kansas 67 6 62 4
Other 5 -- 1 --
----- --- ----- ---
2,936 47 2,172 22
===== === ===== ===
----------------------------------------
</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 fraction al 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
======================================================================================
47 days 319 days Pro forma
Year ended ended ended year ended
December 31, 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 21 17
Gas -- -- -- -- 4 2
Dry -- -- -- -- -- --
-- ----- --- ----- -- --
Total 26 12.07 109 98.88 25 19
== ===== === ===== == ==
Total:
Oil 26 12.07 109 98.88 21 17
Gas 1 0.38 2 0.75 4 2
Dry -- -- -- -- -- --
-- ----- --- ----- -- --
Total 27 12.45 111 99.63 25 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 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.
17
<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/ Grant W. Henderson
----------------------------------
Grant W. Henderson
Chief Financial Officer
DATE: April 4, 1997
18
<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 indicated.
Name Capacities
- ------------------------------ -----------------------
Chairman of the Board and Chief
/s/ Douglas H. Miller* Executive Officer
- ------------------------------
Douglas H. Miller
President, Chief Financial Officer
(Principal Financial and Accounting
/s/ Grant W. Henderson Officer) and Director
- ------------------------------
Grant W. Henderson
Vice Chairman of the Board and Chief
/s/ Jarl P. Johnson* Operating Officer
- ------------------------------
Jarl P. Johnson*
/s/ Richard B. Buy* Director
- ------------------------------
Richard B. Buy
/s/ Timothy J. Detmering* Director
- ------------------------------
Timothy J. Detmering
/s/ James V. Derrick, Jr.* Director
- ------------------------------
James V. Derrick, Jr.
/s/ C. John Thompson* Director
- ------------------------------
C. John Thompson
* Executed on behalf of the indicated person by Douglas H. Miller, duly
appointed attorney-in-fact.
By: /s/ Grant W. Henderson
---------------------------
Granr W. Henderson
Attorney-in-fact
19
