UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
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(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 0-21663
OFFSHORE ENERGY DEVELOPMENT CORPORATION
(Exact name of registrant as specified in its charter)
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DELAWARE 76-0509791
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1400 WOODLOCH FOREST DRIVE, SUITE 200 77380
THE WOODLANDS, TEXAS (Zip Code)
(Address of principal executive offices)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(281) 364-0033
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SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF
THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
COMMON STOCK, PAR VALUE $.01 PER SHARE
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [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 of March 25, 1997, the number of outstanding shares of Common Stock
was 8,701,885. As of such date, the aggregate market value of the shares of
Common Stock held by non-affiliates was approximately $44.2 million.
DOCUMENTS INCORPORATED BY REFERENCE:
(1) Portions of the Company's Proxy Statement for the 1997 Annual Meeting
of Stockholders (Part III, Items 10-13).
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TABLE OF CONTENTS
PART I
ITEM 1. Business...................................................... 1
ITEM 2. Properties.................................................... 19
ITEM 3. Legal Proceedings............................................. 19
ITEM 4. Submission of Matters to a Vote of Security Holders........... 19
PART II
ITEM 5. Market for Registrant's Common Equity and Related
Shareholder Matters......................................... 20
ITEM 6. Selected Financial Data....................................... 20
ITEM 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................... 22
ITEM 8. Financial Statements and Supplementary Data................... 29
ITEM 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure........................ 29
PART III
ITEM 10. Directors and Executive Officers of the
Registrant.................................................... 29
ITEM 11. Executive Compensation........................................ 29
ITEM 12. Security Ownership of Certain Beneficial
Owners and Management......................................... 29
ITEM 13. Certain Relationships and Related
Transactions.................................................. 29
PART IV
ITEM 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K....................................... 30
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PART I
ITEM 1. BUSINESS
Offshore Energy Development Corporation (the "Company" or "OEDC") is an
independent energy company that focuses on the acquisition, exploration,
development and production of natural gas and on natural gas gathering,
processing and marketing activities. The Company's integrated operations are
conducted in the Gulf of Mexico, where the Company has interests in 20 lease
blocks, all of which are operated by the Company. See "-- Exploration and
Development -- Oil and Gas Properties."
The Company operates the Dauphin Island Gathering System (the "DIGS")
and the Main Pass Gas Gathering System ("MPGGS"), which are pipeline systems
offshore Alabama and Louisiana. Combined, the systems comprise approximately 150
miles of gas gathering line with a capacity of 650 MMcf/d. The Company owns a 1%
general partner interest in the partnership that owns the DIGS and the MPGGS,
Dauphin Island Gathering Partners ("DIGP"), and the Company's interest will
increase to 11.15% when its partners in DIGP receive a return of their
investment plus a 10% rate of return. See "-- Natural Gas Gathering."
In November 1996, the Company formed a partnership with subsidiaries of
MCN Corporation ("MCN") and PanEnergy Corp. ("PanEnergy") for the construction
and development of one or more natural gas liquids ("NGL") plants onshore in
Alabama. The initial plant is expected to begin operations in the second quarter
of 1998 with a capacity of 600 MMcf/d. The Company's interest in this
partnership, called Mobile Bay Processing Partners ("MBPP"), is currently 1%,
and the Company has acquired from its partners an option to purchase an
additional 321/3% interest (currently subject to dilution to 24.3%) in MBPP
during the first three years of operation of the initial plant. See "-- Natural
Gas Processing."
EXPLORATION AND DEVELOPMENT
GENERAL
In its natural gas and oil exploration and development activities, the
Company emphasizes several operating strategies. By controlling operations on
its properties, the Company attempts to reduce development costs and the time
between development expenditures and initial production. By focusing its
exploration and development efforts geographically and geologically and
employing appropriate technology, the Company attempts to reduce exploration
risk. By building strategic alliances, the Company aims to complement the
strengths of the major Gulf of Mexico producers with its creativity, focus,
flexibility and lower overhead costs. An important component of the Company's
development strategy is the development of several proximate blocks in clusters
to avoid duplication of expense in production infrastructure. The principal
areas in which the Company conducts development activities are the Central Gulf
of Mexico offshore Louisiana, including the South Timbalier area, offshore
Alabama and Mississippi, including the Mobile and Viosca Knoll areas, and
offshore Texas, including the North Padre Island area.
Certain of the Company's exploration and development activities are
conducted through a partnership, South Dauphin II Limited Partnership ("SDPII"),
with an affiliate of Enron Capital & Trade Resources Corp. (the "ECT
Affiliate"). The Company and the ECT Affiliate formed SDPII to fund a drilling
and development program on certain of the Company's properties. Under the terms
of the SDPII partnership agreement, the ECT Affiliate receives 85% of the net
cash flow from the wells included in the program (provided a minimum payment
schedule is met) until it has been repaid all of its original investment plus a
15% pre-tax rate of return ("Payout"). Once Payout has occurred, the ECT
Affiliate's interest will decrease to 25%, and the Company's interest will
increase to 75%. SDPII has the option to accelerate the ownership change by
prepaying the amount necessary to cause Payout to occur plus 10% of the ECT
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Affiliate's net investment (funds advanced less distributions received) and five
percent of its unfunded commitment. The Company expects to cause SDPII to effect
such a prepayment, using proceeds from the Company's initial public offering
contributed by the Company to SDPII, once production commences on the wells
included in the program.
OIL AND GAS PROPERTIES
MOBILE AND VIOSCA KNOLL, OFFSHORE ALABAMA AND MISSISSIPPI
GENERAL. In 1990, the Company began examining the potential for
exploration activity in the Mobile and Viosca Knoll ("VK") areas offshore
Alabama and Mississippi. Potential gas reservoirs in this area can be defined
geophysically with bright spots and are characterized by productive sands which
generally are highly porous and permeable, allowing the potential for high
deliverabilities. The total cost of drilling and development in these areas is
low in comparison to other offshore developments because of the shallow water
and reservoir depths. In addition, the expected finding costs per Mcf are low in
these areas compared to other onshore and offshore developments because of the
ratio of total drilling and development costs to the expected recoverable
reserves. Finally, gas production from these areas historically has been sold at
a premium as compared to gas produced from other Gulf Coast and Mid-Continent
areas because of the proximity of the Mobile and VK areas to Northeast and
Florida gas markets.
During the 1980s, substantial shallow gas reserves had been drilled in
the Mobile and VK areas but none of the reserves had been placed on production
because there was no public-access pipeline system to gather the gas to onshore
markets. Moreover, fragmented ownership of the reservoirs among multiple
producers discouraged development. In light of these factors, the Company
decided to acquire significant acreage in the areas and to create a gas
gathering system to solve the marketability problem. See " -- Natural Gas
Gathering."
MOBILE 822 CLUSTER. From 1990 through 1993, the Company acquired
leaseholds covering about 21,000 acres (five blocks) in state and federal waters
offshore Alabama. In 1993 and early 1994, the Company drilled eight wells with
13 completions on these blocks and constructed a four-pile platform in 45 feet
of water at Mobile 822 with production and compression facilities to handle up
to 50 MMcf/d of gas. Initial production commenced within four months of spudding
the first 822 well. The Mobile 822 cluster cost approximately $35 million to
develop and produced about $9 million in income before it was sold in 1994 for
$50 million. Favorable gas prices and the need for capital to pursue new
projects made the sale attractive to the Company. The Company recorded
approximately $13.65 million in pre-tax profits from the sale transaction after
repaying development financing and dividing the sale proceeds with minority
interest owners.
MOBILE 959/960 CLUSTER. In late 1994, the Company acquired an undivided
50% interest in Mobile 959/960 just east of the Mobile Bay entrance and south of
Fort Morgan peninsula. Drilling for production from these blocks was problematic
because the seismic data was poor due to unfavorable sea floor conditions and
because much of the reserve potential was in the shipping fairways where
drilling was prohibited. The Company drilled six highly deviated or horizontal
wells to target sands at around 2,000 feet subsea. Four of the wells had bottom
hole locations with lateral displacements over three times the vertical depth.
The Company constructed a manned, four-pile platform at Mobile 959 in 60 feet of
water with 30 MMcf/d in production and compression capacity. The Company
constructed a three-pile platform at Mobile 960 and a flowline from the platform
to the production platform in Mobile 959. The Company now owns a 100% working
interest in the property and is currently producing about six MMcf/d from four
wellbores. The Company plans one additional recompletion to access additional
proved reserves behind pipe when production from the current producing zone on
that well is depleted.
The Company has acquired ownership percentages (ranging from 15% to
100%) in five blocks offshore Alabama east of Mobile 959/960 and is the operator
of all five blocks. The Company believes that all five blocks may
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be developed utilizing the Mobile 959/960 platforms making use of excessplatform
capacity and avoiding an expensive duplication of infrastructure. Four of the
blocks (Mobile 830, Pensacola 881, Destin Dome 1 and Destin Dome 2) have proved
undeveloped reserves attributable to four wellbores drilled by a former operator
of these leases. The Company has commenced the regulatory filings necessary for
these activities. The Company has identified a seismic anomaly on the fifth
block, VK 38, through use of a regional seismic grid. It has shot its own
proprietary seismic survey on this block and is currently evaluating its
drilling potential.
VIOSCA KNOLL. SDPII has interests in four VK leases, on which four
wells were drilled during 1996. The Company expects to install a central
production facility on these VK leases to commence production during the second
quarter of 1997.
The Company has interests in seven additional lease blocks in the VK
area. During 1996, the Company drilled and abandoned a well located at VK 80
which the Company deemed uneconomic. The Company owns one well at VK 117 which
was drilled by a prior operator. The Company installed a caisson over the well
during the fourth quarter of 1996 and expects to install a flowline and commence
production on the well during the second quarter of 1997. The Company also
drilled a successful well on VK 35 in early 1997. Production is expected to
commence from that well during the second quarter of 1997.
Once the wells described above have established a stabilized production
history, the Company will be better able to assess the shallow potential of the
Company's other VK lease blocks.
The Company acquired VK 24 in 1993 as a producing property. By the
summer of 1996, production on this development, located due south of Pascagoula,
Mississippi, had declined to less than one MMcf/d with produced water. However,
in 1996 the Company evaluated a proprietary high resolution seismic grid over
the property and identified an updip proved undeveloped drilling location.
During the fourth quarter of 1996, the Company drilled this well from an
existing braced caisson, and the well is currently producing at a rate of about
3.5 MMcf/d. In addition, the Company recently signed a farm out agreement to
explore a deep objective on VK 24, retaining a 36% interest in the project.
SOUTH TIMBALIER, OFFSHORE LOUISIANA
In 1988, the Company led several partners in an acquisition from a
subsidiary of Shell Oil Company of a producing property, South Timbalier 162
("STIM 162"). The property is located about 45 miles offshore due south of New
Orleans in approximately 125 feet of water. The Company sold its interest in the
platform and the then producing portion of the property in 1990 but retained the
right to explore and develop the approximately 4,000 undeveloped acres in the
block.
In 1990, the Company identified and drilled a bright spot on the
retained acreage to a total depth of approximately 7,000 feet, encountering two
potentially productive horizons. The well, known as the B-6 well, was dually
completed as a gas well. The Company constructed and installed an unmanned
platform and production facility known as the B Platform and laid a two mile
flowline to the nearby interstate pipeline. The original B-6 well ceased
production in 1993 due to mechanical problems. In 1996, the Company attempted to
repair problems in the lower completion of this well to restore production.
These efforts proved unsuccessful, however, and a sidetrack drilled from this
wellbore during the first quarter of 1997 was not productive.
In response to a proposal from the Company, a subsidiary of Amoco Corp.
("Amoco") agreed to make its seismic data available to OEDC in exchange for an
option for up to a 25% non-operated participation in any prospects generated by
OEDC from that 3-D survey. The Company, using Amoco proprietary 3-D seismic, has
identified drilling prospects and drilled and completed two wells on STIM 162 in
1995 and 1996. The first well, known as the B-7 well,
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was a directional well drilled from the B Platform to a bottom-hole location
west of the B-6 well having a total vertical depth of 7,500 feet. The B-7 well
commenced production immediately following completion of the well at an initial
rate of 10 MMcf/d. The second well, known as the B-8 well, which was contributed
by the Company to SDPII, was a directional well drilled from the B Platform to a
bottom-hole location east of the B-6 well having a total vertical depth of 7,000
feet. Production from the B-8 well commenced in September 1996 but ceased in
February 1997 as a result of excessive water production.
NORTH PADRE ISLAND, OFFSHORE TEXAS
In October 1996, the Company acquired a 60.6% working interest in North
Padre Island Block A-59, offshore Texas in federal waters for $414,000 plus the
assumption of abandonment liability. The block is approximately 50 miles
southeast of Corpus Christi, 35 miles offshore. The water depth on the block is
approximately 222 feet. Taylor Energy, Inc., the prior operator, and its
co-interest owner drilled three wells on the block and constructed a four-pile
six slot manned platform and a flowline from the platform to an interstate
pipeline at North Padre Island Block A-44 offshore Texas. The wells were drilled
through eight potentially productive Miocene sands between 3,500 and 4,500 feet
and three deeper Miocene sands at approximately 8,000 feet. The wells produced
from the deeper sands, but two of the wells have been shut in because of water
encroachment and one produces only negligible volumes. During the second quarter
of 1997, the Company intends to drill two new wells in the shallow Miocene
sands. The drilling and completion of these wells is subject to all of the risks
associated with oil and gas operations, and no assurance may be given that
drilling operations will be completed or that the wells will be a commercial
success.
VERMILION
In March 1997, the Company was high bidder on three tracts in the
Vermilion area of the Gulf of Mexico in a federal offshore lease sale. The
Company's apparent winning bids were $224,000 for a 50% working interest in
Vermilion 236, $2,753,000 for a 100% working interest in Vermilion 253 and
$822,000 for a 100% working interest in Vermilion 356. The Company, which would
be the operator of all of these tracts, expects to evaluate prospects and drill
on these tracts during 1997 and 1998.
OTHER DRILLING PROSPECTS
Other potential drilling prospects have been identified on the
Company's acreage, including prospects at deeper depths than those at which the
Company has historically operated. A detailed analysis of these prospects has
not been undertaken, and evaluation of these prospects is in the preliminary
stage. The Company will use the results of its planned drilling and development
program to assist in the evaluation of these additional prospects. No assurance
may be given that the Company ultimately will attempt to drill any of these
prospects or, if it does so, that such drilling would be successful.
AMOCO JOINT VENTURE
The Company and Amoco have had a joint development arrangement in the
Gulf of Mexico since late 1995, and the two companies have recently expanded
that relationship. In October 1996, the Company and a subsidiary of Amoco
entered into an agreement for the purpose of generating drilling prospects in
South Timbalier. Pursuant to the agreement, the Company will be given exclusive
access for a one-year term to a proprietary 3-D seismic data base covering
approximately 59,000 acres for the purpose of identifying and prioritizing
exploitation potential in the area. The Company will, in turn, provide Amoco
access to 5,000 acres of 3-D seismic data, subject to restrictions in the
Company's license. Costs of drilling and development on existing leases will be
shared 75% by the owner of the lease being drilled and 25% by the other party;
such costs will be shared equally on newly acquired leases. The Company
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will generate prospects from the seismic data base and Amoco will either elect
or decline to participate in each prospect. If Amoco elects not to participate
on acreage that Amoco currently owns, it retains a one-twelfth overriding
royalty interest with an option after payout to either increase the overriding
royalty interest to one-tenth or convert such interest to a 25% working
interest. On all other acreage, an election by Amoco not to participate will
result in Amoco having no interest in the prospect. The Company will be the
operator of any prospects drilled under this agreement. The agreement would
provide the Company with the opportunity to participate in the development of
properties that would otherwise be unavailable to it on a cost effective basis.
The Company is currently drilling a prospect on acreage owned by Amoco in South
Timbalier Block 161. Amoco elected not to participate in the development of this
prospect, and the Company therefore currently has a 100% working interest in the
prospect. The Company expects production to begin from this prospect during the
second quarter of 1997.
NATURAL GAS RESERVES
The following table sets forth estimates of the Company's (i) proved
natural gas reserves at December 31, 1996, which were prepared by Ryder Scott
Company ("Ryder Scott"), independent petroleum engineers, in accordance with
regulations promulgated by the Securities and Exchange Commission and (ii)
present value of proved reserves of natural gas at December 31, 1996. The price
used in the table below was based on the price of natural gas at December 31,
1996, with consideration of price changes only to the extent provided by
contractual arrangements in effect as of such date. As of December 31, 1996, the
average price of natural gas was $3.55 per Mcfe. Additional information
concerning the Company's natural gas reserves is included in the Supplemental
Financial Information accompanying the Notes to Consolidated Financial
Statements included elsewhere in this report.
NATURAL GAS RESERVE INFORMATION
AS OF
DECEMBER 31, 1996
-----------------
(DOLLARS IN THOUSANDS)
Net Proved Reserves (MMcfe):
Developed producing............................. 8,900
Developed nonproducing.......................... 12,544
Undeveloped..................................... 11,755
------
Total proved............................. 33,199
======
Present Value of Estimated Future Net Revenue:
Developed producing............................. $23,692
Developed nonproducing.......................... 25,828
Undeveloped..................................... 17,371
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Total proved............................. $66,891
=======
Based on information contained in Ryder Scott's report, the Company estimates
that if effect is given to the increase in the Company's interest in SDPII, the
Company's total proved reserves as of December 31, 1996 would have been 35,901
MMcfe. See "-- Exploration and Development -- General."
PRODUCTION PRICE AND COST HISTORY
The following table sets forth the Company's natural gas production,
the average sales price, the production (lifting) costs and depletion
attributable to the Company's properties during each of the three years ended
December 31, 1996.
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NATURAL GAS PRICES,
AVERAGE SALES PRICE AND PRODUCTION COSTS
YEAR ENDED DECEMBER 31,
-----------------------
1994 1995 1996
------ ------ -----
Net natural gas production (MMcfe)(1)............. 3,686 3,668 4,756
Average sales price (per Mcfe)(2)................. $1.50 $1.68 $2.07
Production (lifting) costs (per Mcfe)............. $0.38 $0.51 $0.41
DD&A (per Mcfe)................................... $0.57 $1.50 $1.03
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(1) The Company had immaterial amounts of condensate (oil) production
during such years.
(2) Prices include the effects of hedging transactions. See Item 7 --
"Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Hedging Activities."
Prices for natural gas have historically been subject to substantial
seasonal fluctuation as demand for natural gas is generally highest during
winter months. Recently, however, demand has been less subject to seasonal
fluctuation as a result of the unbundling and open access of transportation and
storage.
DEVELOPMENT, PRODUCTION AND PRODUCTIVE WELLS
The following table shows the Company's net productive and dry
exploratory and development wells drilled during each of the years in the
three-year period ended December 31, 1996:
DRILLING ACTIVITY
YEAR ENDED DECEMBER 31,
-----------------------
1994 1995 1996
------ ------ -----
Exploratory:
Net productive wells............. 4.46 3.59 1.72*
Net dry holes.................... 0.80 -- 1.00
Development:
Net productive wells............. -- -- --
Net dry holes.................... -- -- --
---- ---- ---
5.26 3.59 2.72
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* If effect is given to the increase in the Company's interest in SDPII, the
number of net productive exploration wells drilled by the Company during
1996 would have been 4.59. See "-- Exploration and Development -- General."
The following table sets forth the Company's ownership interest in
leaseholds as of December 31, 1996. The leases in which the Company has an
interest are for varying primary terms and many require the payment of delay
rentals to continue the primary terms. The leases may be surrendered by the
Company at any time by notice to the lessors, by the cessation of production or
by failure to make timely payment of delay rentals.
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LEASEHOLD INTERESTS
DEVELOPED NONPRODUCING/
DEVELOPED PRODUCING UNDEVELOPED
--------------------- ------------------------
GROSS ACRES NET ACRES GROSS ACRES NET ACRES
----------- --------- ----------- ---------
Offshore Alabama...... 11,520 11,520 83,549 47,035*
Offshore Louisiana.... 3,984 2,370 -- --
Offshore Mississippi.. 5,760 5,760 -- --
Offshore Texas........ 5,760 3,485 -- --
Total.......... 27,024 23,135 83,549 47,035*
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* If effect is given to the increase in the Company's interest in SDPII, the
Company would have had 60,859 net developed nonproducing or undeveloped
acres offshore Alabama at December 31, 1996. See "-- Exploration and
Development -- General."
As of December 31, 1996, the Company owned interests in 16 gross (8.23
net) productive gas wells (including producing wells and wells capable of
production). One of these wells has multiple completions. If effect is given to
the increase in the Company's interest in SDPII, as of December 31, 1996, the
Company would have owned interests in 11.1 net productive gas wells.
OPERATING PROCEDURES AND RISKS
The Company generally seeks to be named as operator for wells in which
it has acquired a significant interest and currently operates 100% of its
material holdings. As operator, the Company is able to exercise substantial
influence over development and enhancement of a well, and supervises operation
and maintenance activities on a day-to-day basis. The Company does not conduct
the actual drilling of wells on properties for which it acts as operator.
Drilling operations are conducted by independent contractors engaged and
supervised by the Company. The Company employs supervisory personnel, but
contracts with appropriate outside specialists (such as petroleum geologists,
geophysicists, engineers and petrophysicists) who attempt to improve production
rates, increase reserves, and/or lower the cost of operating its oil and gas
properties. The Company thus hopes to have specialized resources applied to the
solution of each nonroutine operation it faces without incurring overhead
charges for such services when they are not needed.
The Company's reliance upon others for drilling, exploration and other
services requires that it schedule such activities when these services are
available. When drilling activity in the Gulf of Mexico is high, competition for
available equipment and personnel increases and may make it more difficult to
complete projects in a timely manner. Recently, exploration and development
activity has increased in the Gulf of Mexico and has increased the demand for
drilling vessels, supply boats and personnel experienced in offshore operations.
As a result, the Company has experienced difficulty in obtaining certain
services from vendors that are necessary to implement its growth strategy. The
inability to obtain required services could adversely affect the Company's
ability to complete its scheduled projects in a timely manner.
The Company's operations are subject to all of the risks normally
incident to the exploration for and the production of oil and gas, including
blowouts, craterings, explosions, pipe failure, casing collapse, oil spills and
fires, each of which could result in severe damage to or destruction of oil and
gas wells, production facilities or other property, and personal injuries. In
addition, the Company's oil and gas operations are located in an area that is
subject to tropical weather disturbances, some of which can be severe enough to
cause substantial damage to facilities and possible
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interruptions in production. The oil and gas exploration business is also
subject to environmental hazards, such as oil spills, gas leaks and ruptures and
discharges of toxic substances or gases that could expose the Company to
substantial liability due to pollution or other environmental damage. The
Company maintains comprehensive insurance coverage, including general liability
in an amount not less than $35 million, general partner's liability, operator's
extra expenses, physical damage on certain assets, employer's liability,
automobile, workers' compensation and loss of production income insurance. The
Company believes that its insurance is adequate and customary for companies of a
similar size engaged in comparable operations, but losses could occur for
uninsurable or uninsured risks or in amounts in excess of existing insurance
coverage. Moreover, no assurance can be given that the Company will be able to
maintain adequate insurance in the future at rates considered reasonable.
Additionally, as general partner of limited partnerships, and as managing
general partner of its general partnerships, the Company is solely responsible
for the day-to-day conduct of the partnerships' affairs and accordingly has
liability for expenses and liabilities of such partnerships.
ABANDONMENT COSTS
The Company establishes reserves, exclusive of salvage value, to
provide for the eventual abandonment of its offshore wells and platforms.
Historically, the actual cost to the Company of physically abandoning its wells
has been largely offset by the proceeds from the sale of the salvaged equipment.
There can be no assurance that an active secondary market in used equipment will
continue to exist at the time that properties are abandoned, or that the
regulatory and other costs of abandoning offshore properties will not increase.
See Note 1 of Notes to Consolidated Financial Statements.
The Company carries a $3 million area-wide abandonment bond with the
Minerals Management Service (the "MMS"), which is secured by restricted cash
balances on deposit at a commercial bank. The sum on deposit was $1.4 million at
December 31, 1996 and will increase over time to $3 million. Bond premiums
decline as the amount of the security deposit increases, and the Company
receives all interest earned on the security deposit. The MMS is empowered to
require supplemental abandonment bonds under appropriate circumstances. Although
the cost to the Company of these supplemental bonds to date has not been
material, no assurance may be given that the amounts thereof will not increase,
or that the availability thereof will not be restricted.
MARKETING
The Company's natural gas is transported through gas pipelines that are
not owned by the Company. Capacity on such pipelines is occasionally limited and
at times unavailable due to repairs or improvements being made to such
facilities or due to such capacity being utilized by other gas shippers with
priority agreements. Although the Company has not experienced any inability to
market its natural gas, if pipeline capacity is restricted or is unavailable,
the Company's cash flow from the affected properties could be adversely
affected.
Substantially all of the Company's natural gas is sold at current
market prices, under short term contracts (one year or less) providing for
variable or market sensitive prices. Sales to Enron Capital & Trade Resources
Corp. ("ECT") accounted for approximately 54% of revenue in 1996. However, due
to the availability of other markets, the Company does not believe that the loss
of ECT or any other single customer would adversely affect the Company's results
of operations. The Company utilizes forward sales contracts and commodity swaps
to achieve more predictable cash flow and to reduce its exposure to fluctuations
in gas prices. See Item 7 -- "Management's Discussion of Financial Condition and
Results of Operations -- Hedging Activities." The Company accounts for its
commodity swaps as hedging activities and, accordingly, the effects thereof are
included in oil and gas revenue for the period production was hedged.
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The income generated by the Company's operations is highly dependent
upon the prices of, and demand for, oil and natural gas. The price received by
the Company for its oil and natural gas production depends on numerous factors
beyond the Company's control.
The Company sells its gas from the Mobile and Viosca Knoll areas
pursuant to a long term sales contract with ECT coterminous with the life of the
reserves, subject to earlier termination by the Company in certain events. The
price of gas sold pursuant to this contract is market sensitive and is
considered favorable by the Company. The Mobile outlet for the Company's gas is
downstream of the Louisiana pipeline bottlenecks and is close to locations where
gas is sold for delivery to major East Coast gas consumers. Although the
net-back price historically received by the Company for its gas production has
been less than the Henry Hub price due to gathering and transportation charges,
such price historically has been higher than prices received by other Gulf Coast
and Mid-Continent producers. As the market for natural gas changes, no assurance
may be given that this premium will continue to be available.
COMPETITION
The oil and gas industry is highly competitive in all its phases. The
Company encounters strong competition from many other oil and gas producers in
the acquisition of economically desirable producing properties and exploratory
drilling prospects, and in obtaining equipment and labor to operate and maintain
its properties. Many of the Company's competitors are large well-established
companies with substantially larger operating staffs and greater capital
resources than the Company. Such competitors may be able to pay more for
productive oil and natural gas properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of properties and
prospects than the Company's financial or human resources permit. The Company's
ability to acquire additional properties and to discover reserves in the future
will depend upon its ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment.
TITLE TO PROPERTIES
The Company has obtained title opinions on substantially all of its
producing properties and believes it has satisfactory title to all of its
producing properties in accordance with standards generally accepted in the oil
and gas industry. The Company's properties are subject to customary royalty
interests, liens incident to operating agreements, liens for current taxes and
other burdens which the Company believes do not materially interfere with the
use of or affect the value of such properties. Substantially all of the
Company's producing properties are subject to a lien in favor of Union Bank. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources." The title investigation
performed by the Company prior to acquiring undeveloped properties is thorough
but less rigorous than that conducted prior to drilling, consistent with
industry standards. The MMS must approve all transfers of record title or
operating rights on its respective leases. The MMS approval process can in some
cases delay the requested transfer for a significant period of time.
NATURAL GAS GATHERING
OVERVIEW
In 1990, the Company recognized the potential for development of an
independent gas gathering system to serve the rapidly developing offshore
Alabama area in which significant reserves of natural gas had been discovered in
the shallow Miocene and deep Norphlet formations. The Company believed that
these reserves would become available for commitment to a gathering system, but
Federal Energy Regulatory Commission ("FERC") regulatory issues, perceived
environmental problems and high capital costs had discouraged others from the
development of a system through Mobile Bay. Obtaining the commitment of a volume
of reserves sufficient to support the cost of
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constructing and operating the gathering system was key to its development, and
the Company believed that the commitment could be obtained sequentially to
support the incremental construction of the gathering system. The Company
identified gas reserves located near the central and western end of Dauphin
Island, the barrier island south of Mobile, Alabama, which would support this
incremental development. Because these reserves were located both north and
south of the island, gathering the gas south of the island required a horizontal
boring under the island 4,000 feet long. In 1991, the Company executed a
construction agreement with a subsidiary of British Petroleum to connect its
field south of the Company's Mobile 90 field with a gathering line owned by
Atlantic Richfield Company north of Dauphin Island. To accommodate future
development, the Company installed three 12" lines under the island (one to
service initial needs and two for system expansion). Despite the perceived
engineering uncertainty associated with a water-to-water boring of the required
length, the first stage of the DIGS was completed before the end of 1991.
In 1993, the Company and a non-regulated Enron subsidiary formed DIGP
to construct and operate a 20" pipeline to directly connect the DIGS to the
interstate pipeline transportation network and enable the full utilization of
the three 12" pipes under the island. This segment was completed in May 1993,
creating direct outlets to the Transcontinental Gas Pipe Line Corporation
("Transco") and Koch Gateway Pipeline Company interstate pipeline systems. In
1994, Florida Gas Transmission Company sponsored an expansion of the Mobile
segment of the Transco pipeline in exchange for capacity ownership therein,
establishing a direct interconnect with the Florida Gas system. DIGP added
Tenneco Gas Inc. as a partner in 1994 and expanded the system to connect
numerous newly developing supply sources in the Mobile and Viosca Knoll offshore
areas. This construction activity brought the DIGS to its current 95 mile,
"inverted Y" configuration, consisting of 20", 12" and 8" pipe. In early 1996, a
nonregulated subsidiary of MCN purchased a 99% interest in DIGP, buying out the
interests of Tenneco and Enron and all but a one percent general partnership
interest held by the Company. In mid-1996, MCN sold a 40% interest in the
partnership to a nonregulated subsidiary of PanEnergy.
On December 31, 1996, DIGP merged with Main Pass Gas Gathering Company
("MPGGC"), which owned the MPGGS. DIGP was the surviving entity of the merger,
and the former partners of MPGGC, subsidiaries of PanEnergy, Coastal Corp. and
CNG Energy Services Corporation, were admitted as partners in DIGP. The MPGGS is
located in the Main Pass Area East, offshore Louisiana, and the southern Viosca
Knoll Area, offshore Alabama, and consists of approximately 57 miles of pipeline
designed to gather approximately 300 MMcf/d.
CURRENT OPERATIONS
The partners in DIGP have retained the Company to manage and operate
the DIGS and the MPGGS. The Company is responsible for all commercial
activities, as well as all supervisory, administrative, technical, maintenance,
and gas control services necessary to the operation of the DIGS and the MPGGS
with the exception of certain financial functions, which are performed by MCN.
For performing these services, the Company is paid a monthly management fee of
$62,500, which represents an increase of $7,500 which became effective upon
consummation of the merger with MPGGC. The Company's partnership interest will
increase from 1% to 11.15% when the Company's DIGP partners receive the return
of their investment plus a 10% rate of return ("DIGP Payout"), subject to
reduction, however, if the Company does not exercise the option to increase its
interest in MBPP. See "-- Natural Gas Processing." The increase in the Company's
interest in DIGP, which in the absence of a refinancing transaction the Company
does not expect to occur prior to 2001, would result in a commensurate increase
in the Company's share of the results of operations of DIGP. No assurance may be
given, however, that DIGP Payout will occur. The DIGP partnership agreement
provides that the Company may be removed as manager of the DIGS at any time for
gross negligence or willful misconduct that results in material economic loss to
DIGP, at any time after February 28, 2001 for failure to operate the DIGS in
accordance with sound and prudent practices in the pipeline industry, or without
cause following the earlier to occur of DIGP Payout or February 28, 2003.
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The DIGS and the MPGGS have a current estimated combined throughput
capacity of up to 650 MMcf/d, depending on where gas enters the systems, which
could be expanded with looping and onshore compression. At December 31, 1996,
the DIGS and the MPGGS were gathering between 300 and 350 MMcf/d. Although no
assurances may be given, the Company believes that additional volumes expected
to be contributed to the system, when combined with new production from the
proposed southern extension of the DIGS, will have the system operating at a
level approaching its current capacity by early 1998.
Customers on the DIGS and MPGGS currently include Chevron U.S.A. Inc.,
Union Oil Company of California, Shell Offshore, Inc., Bechtel Energy Partners,
Ltd., SCANA Hydrocarbons, Inc., Chieftain International (U.S.) Inc., Santa Fe
Energy Resources, Inc., Legacy Resources Company, Excel Resources, Inc., EOG,
Coastal Oil & Gas Corporation, CNG Producing Company, Elf Acquitane Oil Program,
Inc., Oryx Gas Marketing Limited Partnership, Piquant, Inc. and the Company.
Most commitments of gas are reserve life commitments with minimum monthly
production requirements. Several of the contracts are term contracts with
guaranteed payments on throughput volumes. Since the contracts permit producers
to shut in production due to market conditions in only very limited
circumstances, the Company expects the cash flow of the system to be consistent
and relatively predictable.
Field operations are handled from a DIGP field office in Coden,
Alabama. DIGP employees at that location monitor the system, calibrate offshore
sales meters monthly and perform light maintenance and repair tasks. The sales
meters are linked by satellite communications to DIGP's home office in The
Woodlands, Texas, where they are continuously monitored as part of the gas
control function.
The Company is responsible for the design and implementation of all new
construction on the DIGS and MPGGS. Design activity and field supervision has
historically been performed by independent engineering and consulting firms,
subject to supervision by Company personnel. The Company will be paid a
construction supervision fee of one-half of one percent of all new construction
costs.
EXTENSIONS AND EXPANSIONS
The partners in DIGP have approved expansion plans to construct
approximately 78 miles of 24-inch diameter gas gathering line, which will
provide an additional 500 MMcf/d of capacity for a total combined capacity of
the DIGS and the MPGGS of approximately 1,150 MMcf/d. The expansion also will
provide a separate system for delivering wet gas (I.E., including gas liquids)
onshore to the NGL processing plant initially planned to be constructed by MBPP.
The expansion will be installed in two phases. The initial phase of the
expansion is expected to enable the utilization of approximately 200 MMcf/d of
unused capacity by the end of the third quarter of 1997. The second phase, which
will add approximately 500 MMcf/d of capacity, is expected to be completed
during the winter of 1997-98.
On November 22, 1996, DIGP filed a petition with the FERC for a
Declaratory Order Disclaiming Jurisdiction (PDO) over the expansion (Docket No.
CP97-119-000). The PDO has not yet been set on the FERC agenda for hearing.
Accordingly, in order to expedite construction of the first phase of the
expansion in the time-frame of producer commitments to the expansion, on March
17, 1997, DIGP filed (without prejudice to the pending PDO) a Conditional
Application with the FERC for a Certificate of Public Convenience and Necessity,
Blanket Transportation and Construction Certificates, Temporary Authority to
Transport Gas Through an Existing Gathering Line, Authorization to Charge
Negotiated Rates and Expedited Treatment (Docket No. CP97-___-000). DIGP
anticipates commencing construction of the expansion in July, 1997 and
completion thereof by October 1, 1997. DIGP has received subscriptions for firm
capacity service in the expansion in excess of 110,000 MMbtu/d. An Open-Season
for excess capacity will be conducted within the next two months for prospective
shippers to obtain firm capacity on a first-come, first-served basis.
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DIGP has the right of first refusal to gather one company's gas
production from its discoveries in the offshore Destin area. These volumes are
tentatively scheduled to come to market in the year 2000. Public data would
indicate that there is the potential for substantial natural gas production from
this area. DIGP will be evaluating the feasibility of an eastward expansion to
collect this gas over the next two to three years. No assurance may be given
that this project will be undertaken or successfully completed.
COMPETITION
The gas gathering industry is highly competitive in all its phases. The
Company encounters strong competition from many other gas pipelines, both
regulated and nonregulated, in acquiring gathering commitments. Many of these
competitors possess substantial financial resources and may be able to offer
gathering services for productive oil and natural gas properties at prices DIGP
would consider noncommercial. Because the volumes controlled by individual
producers may be substantial, they have the ability to stimulate the competitive
process by attempting to induce pipeline companies to build systems in direct
competition to the DIGS and the MPGGS. This is particularly true in the Main
Pass area, which has significant uncommitted reserves and is in reasonable reach
of expansion for several large pipeline companies.
The Company believes, however, that the location of the DIGS outlet to
the interstate grid downstream of existing pipeline bottlenecks in Louisiana
gives the Company a competitive advantage. The Mobile Bay delivery point is
geographically the closest of any major Gulf Coast gas producing area to
locations where gas is sold for delivery to major East Coast markets, resulting
in higher net back prices. During peak demand times in the past, Mobile prices
have been at a significant premium to those in other domestic producing regions.
No assurance may be given that such positive differentials will continue in the
future. In addition, Mobile area gas has not been curtailed during periods when
the upstream infrastructure in Texas and Louisiana experiences capacity
constraints due to excessive demand. Several of DIGP's competitors route their
offshore gas to the Mississippi River delta area of Louisiana, where market
prices and reliability are less favorable.
NATURAL GAS PROCESSING
In November 1996, the Company and subsidiaries of MCN and PanEnergy
formed MBPP for the purpose of constructing, owning and operating, or providing
financing for one or more natural gas processing facilities onshore in Mobile
County, Alabama. Such a facility would extract condensate and natural gas
liquids from natural gas prior to delivery of natural gas to the interstate
pipeline system. Much of the natural gas produced in the Mobile, Viosca Knoll
and Main Pass areas of the Gulf of Mexico has a high gas liquids content.
Because no gas processing facility is currently available in southern Alabama to
process the Mobile, Viosca Knoll and Main Pass gas, producers effectively lose
the potential additional value associated with the liquefiable hydrocarbons in
their natural gas production. Construction of a plant in this area would enable
producers to achieve a higher total price for the sale of their gas and would
make attachment to the DIGS more desirable because the DIGS would be the only
gathering system that delivers gas in proximity to a processing plant in this
area. PanEnergy is the managing partner of MBPP and will manage the construction
and operation of MBPP's projects.
Currently, MBPP plans to construct in stages a plant that will have an
initial capacity of 600 MMcf/d, with capacity being increased in increments of
300 MMcf/d as warranted by demand. Preliminary estimates by the Company are that
this will be a $60 million construction project. The Company expects the plant
to be operational in the second quarter of 1998, and the Company and its
partners continue to evaluate design, construction and market information for
the plant. No assurance may be given, however, that the plant will be
constructed or that, if constructed, it will be completed within the estimated
cost or on the anticipated schedule.
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MBPP is now owned 49.5% by each of MCN and PanEnergy and 1% by the
Company. The Company has acquired for $200,000 an option to buy an additional
321/3% (currently subject to dilution to 24.3%) of the interest in MBPP,
exercisable until the third anniversary of the commencement of commercial
operations at MBPP's initial processing facility. The exercise price for the
Company's option is calculated by multiplying (a) the product of (i) the
"Processing Facilities Value" and (ii) 322/3% of the interests of MCN and
PanEnergy (and in certain cases their assignees) in MBPP by (b) the "Payment
Factor," and then subtracting $200,000 from such total amount. "Processing
Facilities Value" means (1) with respect to any processing facility completed as
of the closing of the exercise of the option, the depreciated book value as of
such date, as determined in accordance with generally accepted accounting
principles and using 25-year straight line depreciation, of such facility and
(2) with respect to any facility not completed as of such date, the allowance
for funds used during construction for such facility as of such date, as
determined in accordance with generally accepted accounting principles. The
"Payment Factor" is initially 100% and increases by 3% upon the commencement of
commercial operations at MBPP's initial processing facility and thereafter by 3%
after each three-month period during the term of the option. The interest in
MBPP that the Company's option entitles it to buy would be diluted if MBPP
admitted an additional partner that was either an assignee of a proportionate
interest from all of the partners or whose admittance otherwise resulted in a
proportionate decrease in each partner's interest.
The Company most likely will need to obtain financing in order to
exercise the option to increase its interest, and, although the Company
anticipates that such financing will be available, no assurance may be given in
this regard. If the Company does not exercise the option to acquire the
additional partnership interest, the Company will be required to assign to each
of MCN and PanEnergy a .726% interest in DIGP out of the increased interest in
DIGP that the Company may earn pursuant to the DIGP partnership agreement upon
DIGP Payout.
The partnership agreement for MBPP provides that any partner who
desires to participate in the construction, ownership, operation or financing of
a gas processing plant in Mobile County must offer the other partners a right of
first refusal to participate in the project. In addition, the Company, MCN and
PanEnergy have entered into an Area of Mutual Interest Agreement pursuant to
which any party that desires to construct, own and operate or provide financing
for (a) any gas processing plant in Jackson or Harrison Counties, Mississippi,
Baldwin County, Alabama or Escambia County, Florida or (b) a power plant located
in Mobile County, Alabama for the generation of power to the initial processing
plant constructed by MBPP must offer the other parties a right of first refusal
to participate in the project. The Company's right to participate would be 20%
in any such power plant and 331/3% (currently subject to dilution to 24.3%) in
any such processing plant, except that the Company's right to participate in a
processing plant at any time after the exercise or termination of the Company's
option described above will be equal to the Company's interest in MBPP.
OTHER FACILITIES
The Company currently leases approximately 8,433 square feet of office
space in The Woodlands, Texas, where its administrative offices are located.
DIGP owns a field office in Coden, Alabama.
EMPLOYEES
As of December 31, 1996, the Company had 18 employees, none of whom
were represented by any labor union. The Company also utilizes the services of
independent contractors to perform various field and other services.
The Company considers its relations with its personnel to be satisfactory.
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GOVERNMENT REGULATION
GENERAL
Domestic development, production and sale of oil and gas are
extensively regulated at both the federal and state levels. Legislation
affecting the oil and gas industry is under constant review for amendment or
expansion, frequently increasing the regulatory burden. Numerous departments and
agencies, both federal and state, have issued rules and regulations applicable
to 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 regulatory burden on the natural gas and oil industry
increases the Company's cost of doing business and, consequently, affects its
profitability. Inasmuch as such laws and regulations are frequently expanded,
amended or reinterpreted, the Company is unable to predict the future cost or
impact of complying with such regulations.
REGULATION OF NATURAL GAS AND OIL EXPLORATION AND PRODUCTION
Exploration and production operations of the Company are subject to
various types of regulation at the federal, state and local levels. Such
regulation includes requiring permits for the drilling of wells, maintaining
bonding requirements in order to drill or operate wells, and regulating the
location of wells, the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled and the plugging and
abandonment of wells. Exploration and development operations are also subject to
various conservation laws and regulations that regulate the size of drilling and
spacing units or proration units and the density of wells which may be drilled
and unitization or pooling of oil and gas properties. In this regard, some
states allow the forced pooling or integration of tracts to facilitate
exploration while other states rely on voluntary pooling of lands and leases. In
addition, state conservation laws establish maximum rates of production from
natural gas and oil wells, generally prohibit the venting or flaring of natural
gas and impose certain requirements regarding the ratability of production. The
effect of these regulations is to limit the amounts of natural gas and oil that
may be produced and to limit the number of wells or the locations at which
drilling operations may be conducted.
NATURAL GAS MARKETING, GATHERING AND TRANSPORTATION
Federal legislation and regulatory controls in the United States have
historically affected the price of the natural gas produced by the Company and
the manner in which such production is marketed. The transportation and sale for
resale of natural gas in interstate commerce are regulated by the FERC pursuant
to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of
1978 (the "NGPA"). The maximum selling prices of natural gas were formerly
established pursuant to regulation. However, on July 26, 1989, the Natural Gas
Wellhead Decontrol Act of 1989 ("Decontrol Act") was enacted, which terminated
wellhead price controls on all domestic natural gas on January 1, 1993 and
amended the NGPA to remove completely by January 1, 1993 price and nonprice
controls for all "first sales" of natural gas, which will include all sales by
the Company of its own production. Consequently, sales of the Company's natural
gas currently may be made at market prices, subject to applicable contract
provisions. The FERC's jurisdiction over natural gas transportation was
unaffected by the Decontrol Act.
The FERC also regulates interstate natural gas transportation rates and
service conditions, which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of such
natural gas. Since the latter part of 1985, the FERC has endeavored to make
interstate natural gas transportation more accessible to gas buyers and sellers
on an open and nondiscriminatory basis. The FERC's efforts have significantly
altered the marketing and pricing of natural gas. Commencing in April 1992, the
FERC issued Order Nos. 636, 636-A and 636-B (collectively, "Order No. 636"),
which, among other things, require interstate pipelines to "restructure" their
services to provide transportation separate or "unbundled" from the pipelines'
sales of gas. Also, Order No. 636 requires
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interstate pipelines to provide open-access transportation on a basis that is
equal for all gas supplies. Order No. 636 has been implemented through decisions
and negotiated settlements in individual pipeline services restructuring
proceedings. In many instances, the result of Order No. 636 and related
initiatives have been to substantially reduce or eliminate the interstate
pipelines' traditional role as wholesalers of natural gas in favor of providing
only storage and transportation services. The FERC has issued final orders in
virtually all pipeline restructuring proceedings, and has now commenced a series
of one year reviews to determine whether refinements are required regarding the
implementation by individual pipelines of Order No. 636. In July 1996, the
United States Court of Appeals for the District of Columbia Circuit largely
upheld Order No. 636.
The DIGS and the MPGGS have been operated as gas gatherers exempt from
the FERC's jurisdiction under the NGA. In February 1996, the FERC issued a
Statement of Policy concerning gas gathering on the Outer Continental Shelf (the
"OCS"). The FERC reaffirmed its so-called "modified primary function" test as
appropriate to determine whether a gas pipeline operating on the OCS is subject
to its jurisdiction as an interstate transporter or exempt from its jurisdiction
as a gatherer. The modified primary function test examines several criteria,
including (1) the length and diameter of the pipeline; (2) the location of wells
along all or part of the pipeline system; (3) the location of compressors and
processing plants on the system; (4) the extension of the pipeline beyond the
central point in the field, (5) the pipeline's geographic configuration; and (6)
the operating pressure of the line. Other factors (e.g., the business of the
pipeline's owners) may also be examined. In its Statement of Policy, FERC stated
for the first time it would presume that pipeline operations in OCS water depths
of 200 meters or greater were exempt gathering facilities, up to the point of
potential connection with an interstate pipeline.
The DIGS and the MPGGS are subject to regulation of their gathering
operations under the Outer Continental Shelf Lands Act (the "OCSLA"). This
statute requires the DIGS and the MPGGS, among other things, to provide OCS gas
producers with open and non-discriminatory access to its gathering system and to
charge non-discriminatory rates. The Company believes that the DIGS and the
MPGGS, as they currently exist and after giving effect to the planned extension
and expansion of the DIGS, meet the criteria of the modified primary function
test and are exempt from FERC jurisdiction under the NGA. In November 1996, DIGP
sought a formal declaration from the FERC confirming its status as an exempt
gatherer. However, the FERC has not acted on DIGP's request, and no assurance
may be given that the FERC will concur with the Company's view. A determination
that the DIGS and the MPGGS are subject to FERC jurisdiction would require that
the systems comply with FERC regulation. In addition, in order to facilitate
completion of the initial phase of the planned expansion of the DIGS during
1997, in March 1997 DIGP filed with the FERC an application for authorization to
construct the proposed expansion. The Company does not believe a determination
that the DIGS, the MPGGS or the proposed expansion of the DIGS is subject to
FERC jurisdiction would have a material adverse effect on the Company's
operations. See "-- Natural Gas Gathering -- Extensions and Expansions."
Although Order No. 636 does not regulate natural gas production
operations, and the Company believes Order No. 636 is not applicable to DIGP's
gathering operations, the FERC has stated that Order No. 636 is intended to
foster increased competition within all phases of the natural gas industry. It
is unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company and its natural gas
marketing efforts. Although Order No. 636 could provide the Company with
additional market access and more fairly applied transportation services rates,
terms and conditions, it could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violation of those
tolerances. The Company does not believe, however, that it will be affected by
any action taken with respect to Order No. 636 materially differently than other
natural gas producers and marketers with which it competes.
The FERC has recently announced its intention to reexamine certain of
its transportation-related policies, including the appropriate manner for
setting rates for new interstate pipeline construction, the manner in which
interstate pipeline shippers may release interstate pipeline capacity under
Order No. 636 for resale in the secondary market, and
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the use of negotiated and market-based rates and terms and conditions for
interstate gas transmission. While any resulting FERC action would affect the
Company only indirectly, the FERC's stated intention is to further enhance
competition in natural gas markets.
Much of the Company's gas production is gathered by DIGP. To the extent
FERC regulation results in a gathering rate reduction on the DIGS and the MPGGS,
the Company could benefit from a reduction of the gathering rates for its
production. The benefits to the Company of any such reduction could mitigate any
loss suffered by the Company as a result of FERC jurisdiction of the DIGS and
the MPGGS.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any such
proposals might become effective, or their effect, if any, on the operations of
the Company or DIGP. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.
OFFSHORE LEASING
The Company conducts certain operations on federal oil and gas leases,
which the MMS administers. The MMS issues such leases through competitive
bidding. These leases contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to the OCSLA, which
are subject to change by the MMS. For offshore operations, lessees must obtain
MMS approval for exploration, development and production plans prior to the
commencement of such operations. In addition to permits required from other
agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS has promulgated regulations
requiring offshore production facilities located on the OCS to meet stringent
engineering and construction specifications, and has recently proposed
additional safety-related regulations concerning the design and operating
procedures for OCS production platforms and pipelines. The MMS also has issued
regulations restricting the flaring or venting of natural gas, and has recently
proposed to amend such regulations to prohibit the flaring of liquid
hydrocarbons and oil without prior authorization. Similarly, the MMS has
promulgated other regulations governing the plugging and abandonment of wells
located offshore and the removal of all production facilities. To cover the
various obligations of lessees on the OCS, the MMS generally requires that
lessees post substantial bonds or other acceptable assurances that such
obligations will be met. The cost of such bonds or other surety can be
substantial and there is no assurance that the Company will be able to obtain
bonds or other surety in all cases. See "-- Environmental Matters."
OIL SALES AND TRANSPORTATION RATES
Sales of crude oil, condensate and gas liquids by the Company are not
regulated and are made at market prices. The price the Company receives from the
sale of these products is affected by the cost of transporting the products to
market. Effective as of January 1, 1995, the FERC implemented regulations
establishing an indexing system for transportation rates for oil pipelines,
which would generally index such rates to inflation, subject to certain
conditions and limitations. These regulations could increase the cost of
transporting crude oil, liquids and condensate by pipeline. These regulations
are subject to pending petitions for judicial review. The Company is not able to
predict with certainty what effect, if any, these regulations will have on it,
but other factors being equal, the regulations may tend to increase
transportation costs or reduce wellhead prices for such commodities.
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SAFETY REGULATION
The Company's gathering operations are subject to safety and
operational regulations relating to the design, installation, testing,
construction, operation, replacement, and management of facilities. Pipeline
safety issues have recently been the subject of increasing focus in various
political and administrative arenas at both the state and federal levels. In
addition, the major federal pipeline safety law is subject to change this year
as it is considered for reauthorization by Congress. For example, federal
legislation addressing pipeline safety issues has been introduced, which, if
enacted, would establish a federal "one call" notification system. Additional
pending legislation would, among other things, increase the frequency with which
certain pipelines must be inspected, as well as increase potential civil and
criminal penalties for violations of pipeline safety requirements. The Company
believes its operations, to the extent they may be subject to current gas
pipeline safety requirements, comply in all material respects with such
requirements. The Company cannot predict what effect, if any, the adoption of
this or other additional pipeline safety legislation might have on its
operations, but the industry could be required to incur additional capital
expenditures and increased costs depending upon future legislative and
regulatory changes.
ENVIRONMENTAL MATTERS
The Company's oil and natural gas exploration, development, production
and pipeline gathering operations are subject to stringent federal, state and
local laws governing the discharge of materials into the environment or
otherwise relating to environmental protection. Numerous governmental
departments, such as the Environmental Protection Agency ("EPA"), issue
regulations to implement and enforce such laws, which are often difficult and
costly to comply with and which carry substantial civil and criminal penalties
for failure to comply. These laws and regulations may require the acquisition of
a permit before drilling commences, restrict the types, quantities and
concentrations of various substances that can be released into the environment
in connection with drilling, production and pipeline gathering activities, limit
or prohibit drilling activities on certain lands lying within wilderness,
wetlands, frontier and other protected areas, require some form of remedial
action to prevent pollution from former operations, such as plugging abandoned
wells, and impose substantial liabilities for pollution resulting from the
Company's operations. In addition, these laws, rules and regulations may
restrict the rate of oil and natural gas production below the rate that would
otherwise exist. The regulatory burden on the oil and gas industry increases the
cost of doing business and consequently affects its profitability. Changes in
environmental laws and regulations occur frequently, and any changes that result
in more stringent and costly waste handling, disposal or clean-up requirements
could adversely affect OEDC's operations and financial position, as well as the
oil and gas industry in general. While management believes that OEDC is in
substantial compliance with current applicable environmental laws and
regulations and the Company has not experienced any material adverse effect from
compliance with these environmental requirements, there is no assurance that
this will continue in the future.
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons who are considered to be responsible for the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances at the site
where the release occurred. Under CERCLA, such persons may be subject to joint
and several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and
for the costs of certain health studies and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the release of hazardous substances or other
pollutants into the environment. Furthermore, although petroleum, including
crude oil and natural gas, is exempt from CERCLA, at least two courts have ruled
that certain wastes associated with the production of crude oil may be
classified as "hazardous substances" under CERCLA and thus such wastes may
become subject to liability and regulation under CERCLA. State initiatives to
further regulate
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<PAGE>
the disposal of oil and natural gas wastes are also pending in certain states,
and these various initiatives could have a similar impact on the Company.
The Oil Pollution Act ("OPA") currently requires persons responsible
for "offshore facilities" to establish $150 million in financial responsibility
to cover environmental cleanup and restoration costs likely to be incurred in
connection with an oil spill in the waters of the United States. On September
10, 1996 Congress passed legislation that would lower the financial
responsibility requirement under OPA to $35 million, subject to increase to $150
million if a formal risk assessment indicates the increase is warranted. The
Company cannot predict whether the President will sign this legislation. The
impact of any legislation is not expected to be any more burdensome to the
Company than it will be to other similarly situated companies involved in oil
and gas exploration and production.
OPA imposes a variety of additional requirements on "responsible
parties" for vessels or oil and gas facilities related to the prevention of oil
spills and liability for damages resulting from such spills in waters of the
United States. The "responsible parties" include the owner or operator of an
onshore facility, pipeline, or vessel or the lessee or permittee of the area in
which an offshore facility is located. OPA assigns liability to each responsible
party for oil spill removal costs and a variety of public and private damages
from oil spills. While liability limits apply in some circumstances, a party
cannot take advantage of liability limits if the spill is caused by gross
negligence or willful misconduct or resulted from violation of a federal safety,
construction or operating regulation. If a party fails to report a spill or to
cooperate fully in the cleanup, liability limits likewise do not apply. OPA
establishes a liability limit for offshore facilities (including pipelines) of
all removal costs plus $75 million. Few defenses exist to the liability for oil
spills imposed by OPA. OPA also imposes other requirements on facility
operators, such as the preparation of an oil spill contingency plan. Failure to
comply with ongoing requirements or inadequate cooperation in a spill event may
subject a responsible party to civil or criminal enforcement actions.
In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating in the
OCS. Specific design and operational standards may apply to OCS vessels, rigs,
platforms, pipelines, vehicles and structures. Violations of lease conditions or
regulations issued pursuant to OCSLA can result in substantial civil and
criminal penalties, as well as potential court injunctions curtailing operations
and the cancellation of leases. Such enforcement liabilities can result from
either governmental or private prosecution.
The Federal Water Pollution Control Act ("FWPCA") imposes restrictions
and strict controls regarding the discharge of produced waters and other oil and
gas wastes into navigable waters. Permits must be obtained to discharge
pollutants into state and federal waters. The FWPCA and analogous state laws
provide for civil, criminal and administrative penalties for any unauthorized
discharges of oil and other hazardous substances in reportable quantities and,
along with the OPA, may impose substantial potential liability for the costs of
removal, remediation and damages. State water discharge regulations and the
federal (NPDES) permits prohibit or are expected to prohibit within the next
year the discharge of produced water and sand, and some other substances related
to the oil and gas industry, into coastal waters. Although the costs to comply
with zero discharge mandates under federal or state law may be significant, the
entire industry will experience similar costs and the Company believes that
these costs will not have a material adverse impact on the Company's financial
conditions and operations. Some oil and gas exploration and production
facilities are required to obtain permits for their storm water discharges.
Costs may be incurred in connection with treatment of wastewater or developing
storm water pollution prevention plans.
The Resource Conservation and Recovery Act ("RCRA"), as amended,
generally does not regulate most wastes generated by the exploration and
production of oil and gas. RCRA specifically excludes from the definition of
hazardous waste "drilling fluids, produced waters, and other wastes associated
with the exploration, development, or production of crude oil, natural gas or
geothermal energy." However, these wastes may be regulated by EPA or state
agencies as solid waste. Moreover, ordinary industrial wastes, such as paint
wastes, waste solvents, laboratory wastes, and waste
18
<PAGE>
compressor oils, may be regulated as hazardous waste. Pipelines used to transfer
oil and gas may also generate some hazardous wastes. Although the costs of
managing solid and hazardous waste may be significant, the Company does not
expect to experience more burdensome costs than similarly situated companies
involved in oil and gas exploration and production.
The Clean Air Act Amendments of 1990 required the EPA to promulgate
regulations for the control of air pollution from certain OCS sources. Those
regulations impose requirements on operators of affected OCS facilities,
including the possible need to obtain operating permits. Monitoring, reporting,
notification, inspections, compliance requirements, and other provisions may
also apply to OCS facilities. Failure to comply with these regulations will
subject a facility to civil or criminal enforcement actions.
ITEM 2. PROPERTIES
Certain of the information included in Item 1 -- "Business" is
incorporated in response to this item.
ITEM 3. LEGAL PROCEEDINGS
The Company is a defendant in a suit styled H.E. (GENE) HOLDER, JR. AND
DAN H. MONTGOMERY V. OFFSHORE ENERGY DEVELOPMENT CORPORATION, which was filed in
1995 alleging that the idea, design, and location of the DIGS as an intrastate
gas gatherer regulated by the Federal Energy Regulatory Commission under Section
311 of the Natural Gas Policy Act of 1978 was a confidential trade secret owned
by the plaintiffs which had been revealed to the Company during confidential
discussions in furtherance of a proposed joint venture. The plaintiffs further
alleged that the Company made misrepresentations regarding its intention to form
a joint venture with the plaintiffs in order to obtain the confidential
information and to induce the plaintiffs into executing a confidentiality
agreement which thereafter prevented the plaintiffs from further pursuing the
project independently. The plaintiffs also alleged that the Company orally
agreed to form a joint venture and that the Company breached its fiduciary
duties to the plaintiffs. As a consequence, the plaintiffs alleged "millions of
dollars in profits" as actual damages and also sought the award of unspecified
punitive damages, attorneys' fees, pre- and post-judgment interest and costs of
suit.
On March 10, 1997, OEDC filed a motion for summary judgment as to all
of the plaintiffs' claims. Subsequently, the plaintiffs amended their petition,
dropping their claims of misrepresentation and conversion of trade secrets and
adding a claim of alleged fraudulent inducement to execute a covenant not to
compete. Further, the plaintiffs specified that they seek $6.5 million in actual
damages and punitive damages of five times the amount of actual damages. OEDC
denies the plaintiffs' claims. Oral argument on OEDC's motion for summary
judgment will be heard in May 1997, and trial is set for September 29, 1997.
Although a decision adverse to the Company in this litigation could have a
material adverse effect on the Company's financial condition and results of
operation, the Company does not believe that the final resolution of this case
will result in a material liability to the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the
fourth quarter of 1996.
19
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
Since November 1, 1996, the Company's Common Stock has been listed on
the Nasdaq National Market (the "Nasdaq") under the symbol "OEDC." From November
1, 1996 through December 31, 1996, the high and low sale prices for the Common
Stock on the Nasdaq were $165/8 and $13, respectively. There were approximately
75 record holders of Common Stock as of March 25, 1997.
The Company has not paid any cash dividends on the Common Stock in the
past and anticipates that, for the future, it will use its capital for the
operation and expansion of its business rather than the payment of dividends.
The loan agreement relating to the Company's revolving credit facility with
Union Bank of California, N.A. contains a covenant prohibiting the payment of
dividends on the Common Stock without the bank's prior consent. See Item 7 --
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Credit Facility."
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated historical
financial data for the Company as of and for each of the periods indicated. The
financial data are derived from the audited financial statements of the Company.
Prior to August 31, 1992, the financial data reflect the operations of Offshore
Energy Development Corporation, a Texas corporation, a predecessor of the
Company. From August 31, 1992 through November 6, 1996, the financial data
reflects the consolidated operations of OEDC Partners, L.P. and OEDC, Inc.,
predecessors of the Company. The following data should be read in conjunction
with Item 7 -- "Management's Discussion and Analysis of Financial Condition and
Results of Operations," which includes a discussion of the acquisition or sales
of oil and gas producing properties and investments in partnerships and other
factors materially affecting the comparability of the information presented, and
the Company's consolidated financial statements and notes thereto included
elsewhere herein.
20
<PAGE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
Statement of Operations Data:
Income:
Exploration and production............. $ 2,116 $ 1,744 $ 5,513 $ 6,169 $ 9,835
Pipeline operating and marketing....... 886 358 358 166 1,014
Equity in earnings (loss) of
equity investments.................. - (255) (3) 497 53
Gain on sales of oil and gas
properties or partnership
investments, net.................... - - 13,655 - 10,661
------- ------- ------ ------ ------
Total income................... 3,002 1,847 19,523 6,832 21,563
------- ------- ------ ------ ------
Expense:
Operations and maintenance............. 745 570 1,410 2,210 1,972
Exploration charges.................... 36 32 2,231 405 2,297
Depreciation, depletion and
amortization........................ 1,941 355 2,112 5,501 4,898
Abandonment expense.................... - 59 2,735 84 1,301
General and administrative............. 785 1,725 2,359 2,192 2,325
------- ------- ------ ------ ------
Total expense.................. 3,507 2,741 10,847 10,392 12,793
------- ------- ------ ------ ------
Earning (loss) before interest and taxes.... (505) (894) 8,676 (3,560) 8,770
Interest income (expense) and other:
Interest expense....................... (975) (228) (590) (1,651) (783)
Preferential payments by subsidiaries.. - - (1,431) - -
Interest income and other.............. (63) (226) 317 123 (94)
------- ------- ------ ------ ------
Total interest income
(expense) and other.......... (1,038) (454) (1,704) (1,528) (877)
------- ------- ------ ------ ------
Income (loss) before income taxes........... (1,543) (1,348) 6,972 (5,088) 7,893
Income tax benefit (expense)................ - - (27) 21 (1,443)
------- ------- ------ ------ ------
Net income (loss)........................... (1,543) (1,348) 6,945 (5,067) 6,450
Preference unit payments and accretion
of discount............................ - (731) (585) (1,142) (2,617)
------- ------- ------ ------ ------
Income (loss) available to common
unitholders and stockholders........... $ (1,543) $(2,079) $6,360 $(6,209) $3,833
======== ======= ====== ======= ======
Net income (loss) per common share ......... $ (0.31)(a) $ (0.41)(a) $ 1.26(a) $ (1.23)(a) $ 0.68
</TABLE>
- ------------
(a) OEDC became a publicly held entity in November 1996. See "Notes to
Consolidated Financial Statements -- Note 1 -- General Information and
Summary of Significant Accounting Policies."
21
<PAGE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------------------------------------
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C> <C>
Balance Sheet Data:
Property, plant and equipment, net..... $ 14,146 $ 23,626 $ 9,599 $ 20,108 $ 25,703
Total assets........................... 16,828 30,952 20,035 25,170 50,941
Total long term debt (less
current portion).................... - 20,238 5,969 - -
Capital lease payable-noncurrent....... - 474 309 832 462
Redeemable preference units,
net of discount..................... 6,500 6,500 6,500 10,294 -
Stockholders' equity (deficit)......... 971 (1,091) 2,192 (2,117) 41,571
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion should be read in conjunction with the
Company's consolidated financial statements and the notes thereto included
elsewhere herein.
OVERVIEW
The financial statements presented for periods prior to November 7,
1996 represent the consolidated financial statements of OEDC, Inc. and OEDC
Partners, L.P, the Company's predecessors. The Company was formed for the
purpose of becoming the holding company for OEDC, Inc. and OEDC Partners, L.P.
pursuant to the terms of an Agreement and Plan of Reorganization dated August
30, 1996 (the "Combination"). Under the terms of the Combination, which was
consummated on November 6, 1996, the Company (i) acquired all of the outstanding
capital stock of OEDC, Inc. which was previously owned by certain members of
Company management (including their families) and by Natural Gas Partners, L.P.
("NGP"), (ii) acquired by merger 50% of the common limited partnership units of
OEDC Partners, L.P. from the Texas corporation having the same name as the
Company, and (iii) acquired 50% of the common units of OEDC Partners, L.P. held
by NGP and certain of its employees. As a result of the change in the form of
the business resulting from the Combination, the Company incurred a charge of
approximately $2,038,000 during the fourth quarter of 1996 to record a deferred
tax liability reflecting the excess of the pre-Combination tax deductions for
intangible drilling costs over the amount of their recognition for financial
statement purposes. Unless the context requires otherwise, references herein to
the Company are to the Company and its predecessors on a consolidated basis.
Contemporaneously with the consummation of the Combination, the Company
completed an initial public offering (the "Offering") of 3,650,000 shares of its
Common Stock, par value $0.01 per share.
The Company commenced operations in 1988 drilling one well per year
through 1992. From 1993 to 1995 the Company drilled four to six gross wells per
year, initiating and managing over $125 million in capital projects in gas
exploration, production and gathering and retaining net interests ranging from
25% to 80% in these projects. The Company subsequently sold most of such
interests as described below. Project funding came initially from private
placements and later from NGP, mezzanine financing sources and partnerships and
other arrangements with industry participants. The Company's growth was
constrained by its lack of financial resources, requiring the Company to develop
projects utilizing short-term vendor financing and other borrowings and to sell
its interests in the projects it initiated at a profit rather than retain them.
This resulted in the Company sustaining losses in years when it incurred the
project expenses and gains in the
22
<PAGE>
years when the interests in the projects were sold. During 1995, the Company
sustained losses resulting from the expenses associated with development
expenditures on the Company's Mobile 959/960 cluster, while net income was
recorded in 1996 as the result of gains on the sale of all but one percent of
the Company's interest in DIGP, the partnership that owns the DIGS.
This report contains certain forward-looking statements regarding the
Company's future financial condition, liquidity, results of operations and
prospects. The words "expect," "estimate," "anticipate," "predict" and similar
expressions are intended to identify forward-looking statements. These
statements are subject to risks and uncertainties that could cause actual
results to differ materially from those set forth in a forward-looking
statement. Such risks and uncertainties include, but are not limited to, those
relating to: (i) the speculative nature of the assumptions underlying
forward-looking statements, (ii) the volatility of natural gas and oil prices,
(iii) the Company's ability to replace its reserves, (iv) the costs and
uncertainties relating to oil and gas exploration and development, (v) the
substantial capital requirements associated with the Company's business
strategy, and (vi) the other risks and uncertainties described herein and under
the caption "Risk Factors" in the Company's Registration Statement on Form S-1
(No. 333-11269) filed with the Securities and Exchange Commission.
RESULTS OF OPERATIONS
1996 COMPARED TO 1995
INCOME. Total income increased $14,732,000 (216%) from $6,832,000 in
1995 to $21,564,000 in 1996. Exploration and production revenue increased
$3,666,000 (59%) from $6,169,000 in 1995 to $9,835,000 in 1996, primarily as a
result of increased production and increases in the price received by the
Company on the sale of its natural gas production. The production increase was
primarily attributable to full year production from the Company's South
Timbalier 162 B-7 well. The average natural gas price received (inclusive of
hedging) in 1995 was $1.68 per Mcf compared to $2.07 per Mcf in 1996 (a 23%
increase).
The Company's pipeline operating and marketing income increased
$848,000 (511%) from $166,000 in 1995 to $1,014,000 in 1996. The increase was
partially attributable to increased monthly management fees received by the
Company for operating the DIGS. Monthly management fees were increased from
$5,800 to $44,700 per month in January, 1996 and subsequently increased to
$55,000 per month in July, 1996. Total DIGS operator fees received by the
Company increased $472,000 (338%) in 1996 compared to 1995. The Company
increased gas marketing revenue by $376,000 (1,399%) from $27,000 in 1995 to
$403,000 in 1996. The increase was primarily attributable to full year
production in 1996 from a well in the South Timbalier area where the Company
markets third-party gas.
The Company's equity in earnings of equity investments relating to the
Company's interest in DIGP decreased $444,000 (89%) from $497,000 in 1995 to
$53,000 in 1996. The decrease is the result of a reduction in the Company's
ownership in DIGP from 25% to 1% in early 1996.
The Company's sale of all but a 1% general partnership interest in DIGP
resulted in a gain of $10,827,000. The gain on sale was offset by a $166,000
loss on sale the Company realized on the disposition of non-strategic and
non-producing acreage.
EXPENSE. Total expenses increased $2,401,000 (23%) from $10,392,000 in
1995 to $12,793,000 in 1996. Operations and maintenance expense decreased by
$238,000 (11%) from $2,210,000 in 1995 to $1,972,000 in 1996. The decrease was
primarily due to a $268,000 (80%) reduction in gas transportation charges from
$334,000 in 1995 to $66,000 in 1996, as the result of a negotiated gas marketing
agreement. In general, a significant portion of operations expense does not
fluctuate from period to period as changes occur in production volume and prices
received for those volumes, provided
23
<PAGE>
that new production facilities are not brought on-line, as was the case in 1996.
Therefore, such expenses do not always change proportionately with changes in
exploration and production income.
The Company's natural gas production volume increased 1.09 Bcf (30%)
from 3.67 Bcf in 1995 compared to 4.76 Bcf in 1996. However, the Company's
depreciation, depletion and amortization ("DD&A") decreased by $603,000 (11%)
from $5,501,000 in 1995 to $4,898,000 in 1996. The Company's average DD&A rate
per Mcf was $1.50 per Mcf in 1995 compared to $1.03 per Mcf in 1996. The decline
in DD&A rate per Mcf was due to increased production in 1996 from the Company's
South Timbalier 162 B-7 well, which had a lower finding cost per Mcf as compared
to the Company's Mobile 959 cluster.
Exploration charges increased $1,892,000 (467%) from $405,000 in 1995
to $2,297,000 in 1996. In 1996, the Company drilled a non-commercial well
located at Viosca Knoll Block 80 at a cost of $1,336,000 and incurred costs of
$89,000 relating to an unsuccessful additional completion attempt made by the
Company in a producing South Timbalier well. The Company increased expenditures
on geological and seismic data by $511,000 (587%) from $87,000 in 1995 to
$598,000 in 1996. The geological expenditures in 1996 were primarily related to
the Company's activities in the South Timbalier and Viosca Knoll areas.
Abandonment expenses increased $1,217,000 (1,449%) from $84,000 in 1995
to $1,301,000 in 1996. The Company had a Viosca Knoll lease that management
deemed uneconomic which expired in late 1996. This lease had a cost basis of
$581,000, which was expensed when the lease reached expiration. The Company also
incurred an impairment charge of $422,000 in 1996 related to its interest in a
South Timbalier well. An impairment charge is an amount by which the actual
development cost of a well exceeds the expected future revenues from that well.
An abandonment charge of $148,000 was incurred in 1996 as a result of final
resolution of a vendor dispute relating to a 1995 platform abandonment.
INTEREST EXPENSE. Interest expense decreased by $868,000 (53%) from
$1,651,000 in 1995 to $783,000 in 1996. During 1995 and 1996, the Company paid
interest to an affiliate of Enron Corp. ("Enron") relating to a combination term
and revolving credit facility. The term portion of the credit facility bore
interest at 15% per annum and the revolving portion bore interest at a floating
rate equal to 2.5% above the applicable prime rate. During early 1996, the
Company repaid all amounts outstanding under the term portion and one-half of
the amount outstanding under the revolving portion. The Company also paid
$116,000 of interest charges to an Enron affiliate relating to a delayed swap
settlement in early 1996. Total interest paid to Enron decreased by $987,000
(63%) from $1,576,000 in 1995 to $589,000 in 1996.
The Company replaced the Enron revolving credit facility in August 1996
with a revolving credit facility from Union Bank of California N.A. ("Union
Bank") with an interest rate of LIBOR plus 2.5%. During 1996, $61,000 in
interest was paid on the Union Bank credit facility. Following the Company's
initial public offering in November 1996, the Company repaid all amounts
outstanding under the credit facility. Other interest paid in 1996 of $133,000
primarily consisted of interest on leased equipment and short-term vendor
financings.
NET INCOME (LOSS), INCOME (LOSS) AVAILABLE TO COMMON UNIT HOLDERS AND
STOCKHOLDERS AND PREFERENCE UNIT PAYMENTS. The Company incurred a net loss of
$5,067,000 in 1995 compared to net income of $6,450,000 in 1996. The net income
in 1996 was primarily attributable to the gain realized on the previously
discussed sale of the Company's interest in DIGP.
Income (loss) available to common unit holders and stockholders, which
gives effect to preference unit payments and accretion of discount, was a loss
of $6,209,000 in 1995 and net income of $3,833,000 in 1996. In November 1996,
the Company redeemed all of the outstanding preference units of OEDC Partners,
L.P. with proceeds of the Offering.
Therefore, in future periods all income will be available to common
stockholders.
24
<PAGE>
During 1995 the Company made preference payments to NGP totaling
$848,000 compared to $911,000 in 1996 (a 7% increase). The Company began
accreting the $2 million discount on preference units following the purchase of
additional preference units by NGP in 1995. The accretion of discount was
$294,000 in 1995 compared to $1,706,000 in 1996.
1995 COMPARED TO 1994
INCOME. Total income decreased $12,691,000 (65%) from $19,523,000 in
1994 to $6,832,000 in 1995. Exploration and production revenue increased
$656,000 (12%), primarily as a result of increased natural gas prices, while
production volumes in 1995 decreased slightly from 3.69 Bcfe in 1994 to 3.67
Bcfe produced in 1995. Production declines associated with the disposition of
the Mobile 822 cluster during the second quarter of 1994 were largely offset by
the addition of Mobile 959/960 in the second quarter of 1995 and the addition of
the South Timbalier 162 B-7 well in October 1995. The average natural gas price
received (inclusive of hedging) in 1994 was $1.50 per Mcf compared to $1.68 per
Mcf in 1995, representing a 12% increase.
The Company's pipeline operating and marketing income decreased
$192,000 from 1994 to 1995 as a result of decreased pipeline construction
activity.
Equity earnings in DIGP increased from a loss of $3,000 in 1994 to
positive earnings of $497,000 in 1995 as a result of increased throughput in the
DIGS.
The Company sold its interest in the Mobile 822 cluster during second
quarter 1994 at a gain of $13,655,000, which was the primary reason the Company
reported net income in 1994 as compared to its net loss in 1995.
EXPENSES. Total expenses decreased $456,000 (4%) from $10,848,000 in
1994 to $10,392,000 in 1995. Operations and maintenance charges increased by
$800,000 (57%) from $1,410,000 in 1994 to $2,210,000 in 1995. In 1995 two new
properties, the Mobile 959/960 cluster and the South Timbalier B-7, were brought
on production, while in 1994 no new properties were brought on production. The
start-up of these wells resulted in additional expense for personnel,
transportation and supplies. Also, the Company incurred marketing charges in
1995 due to unused firm transportation charges in the Mobile area.
Exploration charges decreased by $1,826,000 (82%) from $2,231,000 in
1994 to $405,000 in 1995, due principally to the Company recording a dry hole
charge of $1,586,000 relating to the Viosca Knoll 79 well in 1994 and the
absence of a similar charge in 1995. Expense relating to seismic data
acquisition and processing declined by $559,000 from $645,000 in 1994 to $87,000
in 1995. In 1994, seismic work was being done on the Mobile 959/960 cluster,
while in 1995 no new projects were being developed that involved new seismic
expenditure. During 1995, the Company paid $318,000 in lease rentals on acreage
acquired in 1994.
The Company's DD&A expense increased $3,389,000 (160%) from $2,112,000
in 1994 to $5,501,000 in 1995 as a result of the commencement of production of
the Mobile 959/960 cluster, which had a higher finding cost per Mcfe than the
Company's reserves producing in 1994. The DD&A charge in 1994 was $.57 per Mcfe
compared to $1.50 Mcfe in 1995.
Abandonment expense declined $2,651,000 (97%) from $2,735,000 in 1994
to $84,000 in 1995 as the result of a charge of $2,264,743 relating to the
abandonment of the Company's Eugene Island 163 platform in 1994. This platform
was not able to resume production because of water encroachment in the wellbore
during a routine shut-in due to a hurricane. Other abandonment charges and
accruals were approximately $471,000 in 1994.
25
<PAGE>
INTEREST EXPENSE AND PREFERENTIAL PAYMENTS. In 1994, the Company made
preferential payments of $1,431,000 to affiliates of Enron to meet non-recurring
partnership obligations. Of this amount, $1,300,000 was a non-cash capital
account adjustment compensating Enron for the cost of capital advanced to DIGP.
Interest expense increased $1,061,000 (180%) from $590,000 in 1994 to
$1,651,000 in 1995. In 1994, the Company paid the ECT Affiliate $350,000 in
interest under a term and revolving credit facility, as compared to $744,000 and
$802,000 under the term and revolver portions of the credit facility,
respectively, in 1995. The term portion of the credit facility was used to
partially fund the Company's development in the Mobile 959/960 cluster and bore
interest at a rate of 15% per annum. The revolver was used for general corporate
purposes and bore interest at a rate equal to the applicable prime rate plus
2.5%. In 1994, NGP provided the Company a short-term working capital bridge
facility. Borrowings under the NGP facility bore interest at 15% per annum and
$175,000 was paid to NGP during 1994 under this facility. This loan was repaid
in 1994. In 1995, the Company incurred $75,000 in miscellaneous interest
charges.
NET INCOME (LOSS), INCOME (LOSS) AVAILABLE TO COMMON UNIT HOLDERS AND
STOCKHOLDERS AND PREFERENCE UNIT PAYMENTS. The Company recorded 1994 net income
of $6,945,000 compared to a net loss of $5,067,000 in 1995 as a result of the
1994 sale of its interest in the Mobile 822 cluster. Income (loss) available to
common unit holders and stockholders, which gives effect to preference unit
payments and accretion of discount, was income of $6,360,000 for 1994 compared
to a loss of $6,209,000 in 1995. In 1994, the Company paid $585,000 in
preference unit payments to NGP, which represents a nine percent coupon on NGP's
preference units. This increased to $1,142,000 in 1995, due to NGP's purchase of
additional preference units in August 1995 and due to the five months of
accretion of the $2 million discount associated with the preference units
purchased.
LIQUIDITY AND CAPITAL RESOURCES
SUMMARY
The Company's main source of liquidity historically has been
short-term, project-specific debt and equity and vendor financings. The large
early debt service demands of these financings have created periodic liquidity
strains on the Company. The Company increased its cash position in 1996 by
$14,352,000 due to financing activities, primarily as a result of the Offering
which raised $40,734,000 net to the Company, which was offset by the Company
redeeming all outstanding preference units at a cost of $12,000,000 and, the
repayment of the term credit facility to Enron in the amount of $12,261,000. The
Company also utilized $911,000 to meet preference payment obligations and
$880,000 in connection with Offering expenses. In the future the Company intends
to finance its capital expenditures out of funds generated from operations, the
proceeds from the Offering and bank borrowings.
The second largest source of liquidity historically has been the
profitable sale of assets which the Company has developed. The Company received
net cash of $1,334,000 from investing activities in 1996 as compared to
utilizing $16,626,000 in investing activities during 1995. The 1996 cash inflow
was the result of selling all but one percent of the Company's general
partnership interest in the DIGS and selling a non-strategic lease block and
generating $11,340,000 from these transactions. This was partially offset by
investments of $9,997,000 in oil and gas properties primarily located in the
Viosca Knoll and South Timbalier areas. The 1995 investment outflows consisted
primarily of development activities on the Mobile 959/960 cluster. The Company
has no present plans to sell any of its properties and does not anticipate that
sales of properties will be a significant source of liquidity to the Company in
the foreseeable future.
In the event the cash flows from the Company's operating activities,
credit available under its credit facility with Union Bank and the proceeds from
the Offering are not sufficient to fund development costs, or results from
drilling are not as successful as anticipated, the Company will either curtail
its drilling or seek additional financing to assist in its drilling activities.
No assurance may be given that the Company will be able to obtain such
additional financing. If the
26
<PAGE>
Company is required to curtail its drilling activities, its ability to develop
and expand its prospect inventory, as well as its earnings and cash flow from
exploration and production activities, will be adversely affected.
The Company intends to continue its efforts to acquire additional
acreage if and when these opportunities become available. Any such acquisition
or related drilling on such acquisition could require additional borrowings
under the credit facility with Union Bank, or additional debt or equity
financing. No assurance may be given that the Company will be able to obtain
such additional funds.
WORKING CAPITAL
The Company had working capital of $15,654,000 as of December 31, 1996
as compared to a working capital deficit of $12,834,000 at December 31, 1995.
The 1996 working capital surplus is primarily the result of the Offering. The
Company periodically has experienced substantial working capital deficits. The
Company has incurred substantial expenditures for the acquisition and
development of capital assets either on vendor open accounts payable or under
short-term financings. The Company has been able to refinance the accounts
payable balances by including them in longer-term project financings. The
operation of the Company's properties, when combined with property-based credit
facilities, has usually generated sufficient cash within 12 months to repay the
investments therein. Thus, capital investments in properties have converted to
cash or generated borrowing capacity rapidly enough to finance the Company's
working capital deficits.
CASH FLOW FROM OPERATIONS
During 1996, the Company generated net cash flow from operations of
$2,011,000 as compared to a cash deficit from operations of $383,000 during
1995. The improvement in 1996 was due primarily to new production from the
Company's South Timbalier 162 block. While improved gas prices also contributed
to the increase in net cash flow from operations, the impact was diminished by a
decrease in exploration and production revenue attributable to hedging
activities in 1996. This is consistent with the Company's hedging program to
moderate fluctuations in cash flows and thereby enable the Company to cover its
fixed obligations despite fluctuations in commodity process.
Net cash flow from operations during 1996 was also increased by the
Company's receipt of management fees the Company began to earn as the operator
of DIGP, which contributed $611,000 of operating cash flow in that period. Prior
to January 1, 1996, the Company performed similar functions for minimal
remuneration as a 25% partner in DIGP. The terms of the sale by the Company of
all but a one percent general partnership interest in DIGP provided for
compensation to the Company for its services as operator.
FINANCING ACTIVITIES
The Company's total capital expenditure budget for 1997 is estimated at
$38.6 million. The Company believes that the proceeds from the Offering,
borrowings under the credit facility described below and cash flows generated
from operations will be sufficient to fund these budgeted expenditures. However,
no assurance may be given as to the adequacy of these sources.
CREDIT FACILITY. The Company has a two-year line of credit with Union
Bank. Borrowing under the line of credit may not exceed at any time the lesser
of $10 million or a borrowing base (computed with reference to the Company's oil
and gas reserves) as determined by the bank in its sole discretion. The
borrowing base will be determined at least semiannually. On December 31, 1996,
the borrowing base was $5,000,000 and there were no outstanding amounts under
this facility. The borrowing base will be reduced by $312,500 per month through
August 31, 1997, by $250,000 per month for the succeeding six months and by
$166,667 per month for the final six months of the agreement, unless changed by
the bank at the time of a borrowing base redetermination. Borrowings under this
facility bear interest at a rate equal to, at the
27
<PAGE>
Company's option, either the bank's reference rate plus 1% or LIBOR plus 2.5%,
with an effective rate of interest on December 31, 1996 of 8.0%.
The credit facility contains restrictive covenants imposing limitations
of the incurrence of indebtedness, the sale of properties, payment of dividends,
mergers or consolidations, capital expenditures, transactions with affiliates,
making loans, and investments outside the ordinary course of business. The
facility requires that the Company maintain at the subsidiary level certain
minimum financial ratios, including a current ratio of at least 1:1 and interest
coverage ratio on 2.5:1. In addition, the weighted average maturity of
indebtedness incurred on ordinary terms to vendors, suppliers and others
supplying goods and services to the Company in the ordinary course of business
may not exceed 60 days. The loan agreement, in addition to customary default
provisions, provides that it is an event of default if either (i) a person or
group (other than Messrs. Strassner, Kiesewetter, Anderson and Bradshaw and
their respective family members, and NGP), owns beneficially more than 50% of
the Company's voting capital stock outstanding, or (ii) any two of Messrs.
Strassner, Kiesewetter, Anderson and Bradshaw cease to be actively involved in
the management and operation of the Company for any reason other than death or
disability. The credit facility requires the Company to maintain a certain
volume of hedging contracts in effect during the term of the credit facility.
Indebtedness under the credit facility is secured by a first lien upon
substantially all of the properties owned by OEDC Exploration & Production, L.P.
and by the pledge of the Company's limited partnership interests in SDP and
SDPII and its general partnership interest in DIGP. All assets not subject to a
lien in favor of the lender are subject to a negative pledge, with certain
exceptions.
SOUTH DAUPHIN II LIMITED PARTNERSHIP. The Company and the ECT Affiliate
formed SDPII to fund drilling and development, with the Company generally
responsible for costs in excess of budgeted amounts. The financing of SDPII is
nonrecourse to the Company's other assets. Pursuant to the terms of the
partnership agreement, the ECT Affiliate receives 85% of the net cash flows from
the subject wells (provided a minimum payment schedule is met) until it has been
repaid all of its original investment plus a 15% pre-tax rate of return
("Payout"). Once Payout has occurred, the ECT Affiliate's interest will decrease
to 25% and the Company's interest will increase to 75%. SDPII has the option to
prepay the ECT Affiliate's investment and accelerate the ownership change. If
such prepayment is from financing activities instead of cash flow from
operations, the Company is required to make an additional payment to the ECT
Affiliate equal to 10% of the ECT Affiliate's net investment (funds advanced
less distributions received) and five percent of the unfunded portion of the ECT
Affiliate's commitment. The Company expects to cause SDPII to use up to $14
million contributed from the proceeds of the Offering to repay such obligations
once the wells in the SDPII program commence production and, accordingly, will
incur the additional charges. The amount to be repaid to the ECT Affiliate will
be determined by the amount of funds contributed by the ECT Affiliate to SDPII.
As of December 31, 1996, the ECT Affiliate had made contributions to SDPII of
$4,195,000 and the Company had contributed $3,063,000.
The SDPII partnership agreement also provides that the failure of any
two of Messrs. Strassner, Kiesewetter and Anderson to be actively involved in
the management and operations of SDPII constitutes a change of control of such
partnership. In such event, the agreement gives the ECT Affiliate the right to
fix a price at which the Company would be required to elect to either purchase
the ECT Affiliate's interest in the partnership or sell all of the Company's
interest in the partnership to the ECT Affiliate.
HEDGING ACTIVITIES
The Company continues to utilize financial futures to hedge its natural
gas production. In 1995, total natural gas revenue was increased by $622,000
compared to a decrease of $1,276,000 in 1996 as a result of its hedging
position. As of December 31, 1996 the Company had 3.35 Bcf hedged from January,
1997 through December, 1997 at an average price of $2.19 per Mcf. The Company
estimates that as of December 31, 1996, the cost to unwind its hedged position
is
28
<PAGE>
approximately $824,000. Although hedging reduces the Company's susceptibility to
declines in the sales prices of its natural gas production, it also prevents the
Company from receiving the full benefit of any increases in the sales prices of
such production. Further, significant reductions in production at times when the
Company's production is hedged could require the Company to make payments under
the hedge agreements in the absence of offsetting income.
EFFECTS OF INFLATION
The Company's results of operations and cash flow are affected by
changing oil and gas prices. Increases in oil and gas prices often result in
increased drilling activity, which in turn increases the demand for and cost of
exploration and development. Thus, increased prices may generate increased
revenue without necessarily increasing profitability. These industry market
conditions have been far more significant determinants of Company earnings than
have macroeconomic factors such as inflation, which has had only minimal impact
on Company activities in recent years. While it is impossible to predict the
precise effect of changing prices and inflation on future Company operations,
the short-lived nature of the Company's gas reserves makes it more possible to
match development costs with predictable revenue streams than would long-lived
reserves. No assurance can be given as to the Company's future success at
reducing the impact of price changes on the Company's operating results.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Independent Auditors' Report ......................................... 35
Consolidated Balance Sheets, December 31, 1996 (Company)
and 1995(Predecessors) ............................................. 36
Consolidated Statements of Operations, for the periods
November 7, 1996 through December 31, 1996 (Company),
and January 1, 1996 through November 6, 1996 and for
the years ended December 31, 1995 and 1994
(Predecessors) ..................................................... 37
Consolidated Statements of Stockholders' and
Predecessors' Equity (Deficit), for the periods
November 7, 1996 through December 31, 1996 (Company),
and January 1, 1996 through November 6, 1996 and for
the years ended December 31, 1995 and 1994
(Predecessors) ..................................................... 38
Consolidated Statements of Cash Flows, for the periods
November 7, 1996 through December 31, 1996 (Company),
and January 1, 1996 through November 6, 1996 and for
the years ended December 31, 1995 and 1994
(Predecessors) ..................................................... 39
Notes to Consolidated Financial Statements .......................... 40
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
The information under the captions "Election of Directors -- Nominees
for Election," "Election of Directors -- Continuing Directors and Executive
Officers" and "Section 16(a) Beneficial Ownership Reporting Compliance" in the
Company's Proxy Statement for the Company's 1997 Annual Meeting of Stockholders
(the "1997 Proxy Statement") is incorporated herein by reference in response to
this item.
ITEM 11. EXECUTIVE COMPENSATION
The information under the caption "Executive Compensation and Other
Matters" in the 1997 Proxy Statement is incorporated herein by reference in
response to this item.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information under the caption "Common Stock Ownership of Certain
Beneficial Owners and Management" in the 1997 Proxy Statement is incorporated
herein by reference in response to this item.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information under the caption "Certain Transactions" in the 1997
Proxy Statement is incorporated herein by reference in response to this item.
29
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Financial Statements, Financial Statement Schedules, and Exhibits
1. Financial Statements of the Company
Reference is made to the consolidated financial statements,
the report thereon and the notes thereto beginning at page 35
of this report. Set forth below is a list of such items:
Consolidated Financial Statements of the Company
Independent Auditors' Report
Consolidated Balance Sheets, December 31, 1996
(Company) and 1995 (Predecessors)
Consolidated Statements of Operations, for
the periods November 7, 1996 through
December 31, 1996 (Company), and January 1, 1996
through November 6, 1996 and for the years ended
December 31, 1995 and 1994 (Predecessors)
Consolidated Statements of Stockholders' and
Predecessors' Equity (Deficit), for the
periods November 7, 1996 through
December 31, 1996 (Company), and January 1, 1996
through November 6, 1996 and for the years
ended December 31, 1995 and 1994 (Predecessors)
Consolidated Statements of Cash Flows for the
periods November 7, 1996 through
December 31, 1996 (Company), and January 1, 1996
through November 6, 1996 and for the
years ended December 31, 1995 and 1994
(Predecessors)
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
All schedules for which provision is made in Regulation S-X of
the Securities and Exchange Commission are not required under
the related instructions or are inapplicable and, therefore,
have been omitted.
3. Exhibits
The following documents are filed as exhibits to this Annual
Report on Form 10-K.
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------- ----------------------
2 -- Agreement and Plan of Reorganization dated August 30, 1996 by and
among the Company, Offshore Energy Development Corporation, a Texas
corporation, OEDC, Inc., Natural Gas Partners, L.P., NGP-OEDC
Holdings, L.P., David B. Strassner, Douglas H. Kiesewetter, R. Keith
Anderson, Matthew T. Bradshaw, Taft and Nancy Bradshaw, R. Gamble
Baldwin, David R. Albin, Donald Shore, Trustee of the Albin Income
Trust, John S. Foster, Kenneth A. Hersh, Bruce B. Selkirk, III, John
C. Goff, and Agnes Denise Darraugh (incorporated herein by reference
to Exhibit 2 to the Company's Registration Statement on Form S-1
(Registration No. 33-11269) (the "Registration Statement")).
3.1 -- Certificate of Incorporation of the Company (incorporated herein by
reference to Exhibit 3.1 to the Registration Statement).
3.2 -- Bylaws of the Company (incorporated herein by reference to Exhibit
3.2 to the Registration Statement).
4 -- Form of Certificate representing shares of Common Stock
(incorporated herein by reference to Exhibit 4 to the Registration
Statement).
30
<PAGE>
10.1 -- Fifth Amended and Restated General Partnership Agreement for
Dauphin Island Gathering Partners dated as of December 31, 1996 among
MCNIC Mobile Bay Gathering Company, PanEnergy Dauphin Island Company,
Dauphin Island Gathering Company, L.P., Centana Gathering Company, CNG
Main Pass Gathering Corporation and Coastal Dauphin Island Company,
L.L.C. (incorporated herein by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K dated December 31, 1996).
10.2 -- Partnership Contribution Agreement dated December 13, 1996 by and
among Dauphin Island Gathering Partners, Dauphin Island Gathering
Company, L.P., MCNIC Mobile Bay Gathering Company, PanEnergy Dauphin
Island Company, CNG Main Pass Gathering Corporation, Centana Gathering
Company, Coastal Dauphin Island Company, L.L.C. and Main Pass Gas
Gathering Company (incorporated herein by reference to Exhibit 99.1 to
the Company's Current Report on Form 8-K dated December 31, 1996).
10.3 -- Agreement for Purchase and Sale dated January 31, 1996 by and
between Dauphin Island Gathering Company, L.P. and Pipeline &
Processing Group, Inc. (incorporated herein by reference to Exhibit
10.9 to the Registration Statement).
10.4 -- Performance Guaranty dated February 28, 1996 by OEDC Partners, L.P.
in favor of MCNIC Mobile Bay Gathering Company (incorporated herein by
reference to Exhibit 10.10 to the Registration Statement).
10.5 -- Agreement of Limited Partnership of South Dauphin II Limited
Partnership dated July 25, 1996 by and between OEDC Exploration and
Production, L.P. and Joint Energy Development Investments Limited
Partnership (incorporated herein by reference to Exhibit 10.11 to the
Registration Statement).
10.6 -- Purchase Agreement dated July 31, 1995 by and among Offshore Energy
Development Corporation, a Texas corporation, OEDC, Inc., OEDC
Partners, L.P., Beacon Gas Storage Co., L.P., Dauphin Island Gathering
Company, L.P., Beacon Natural Gas Company, L.P., OEDC Exploration &
Production, L.P. and NGP-OEDC Holdings, L.P. (incorporated herein by
reference to Exhibit 10.13 to the Registration Statement).
10.7 -- Credit Agreement dated August 28, 1996 between OEDC Exploration and
Production, L.P., OEDC, Inc., OEDC Partners, L.P., the Company,
Dauphin Island Gathering Company, L.P. and Union Bank of California,
N.A. (incorporated herein by reference to Exhibit 10.14 to the
Registration Statement).
10.8 -- Guaranty dated August 28, 1996 by Dauphin Island Gathering Company,
L.P. in favor of Union Bank of California, N.A. (incorporated herein
by reference to Exhibit 10.15 to the Registration Statement).
10.9 -- Guaranty dated August 28, 1996 by OEDC, Inc. in favor of Union Bank
of California, N.A. (incorporated herein by reference to Exhibit 10.16
to the Registration Statement).
10.10 -- Guaranty dated August 28, 1996 by Offshore Energy Development
Corporation in favor of Union Bank of California, N.A. (incorporated
herein by reference to Exhibit 10.17 to the Registration Statement).
10.11 -- Guaranty dated August 28, 1996 by OEDC Partners, L.P. in favor of
Union Bank of California, N.A. (incorporated herein by reference to
Exhibit 10.18 to the Registration Statement).
10.12 -- Amended and Restated Excess Gas Purchase Contract dated June 7,
1995 by and among OEDC Exploration and Production, L.P., South Dauphin
Partners, Ltd. and Enron Capital & Trade Resources Corp. (incorporated
herein by reference to Exhibit 10.19 to the Registration Statement).
10.13 -- Amended and Restated Guaranty Agreement dated March 30, 1994 by
OEDC Partners, L.P. in favor of Enron Finance Corp., Enron Reserve
Acquisition Corp., Enron Gas Marketing, Inc. and
31
<PAGE>
Cactus Hydrocarbon III Limited Partnership (incorporated herein by
reference to Exhibit 10.20 to the Registration Statement).
10.14 -- Area of Interest Agreement dated May 18, 1993 between OEDC
Exploration and Production, L.P. and Enron Finance Corp. (incorporated
herein by reference to Exhibit 10.21 to the Registration Statement).
10.15 -- Offshore Energy Development Corporation 1996 Stock Awards Plan
(incorporated herein by reference to Exhibit 10.22 to the Registration
Statement).
10.16 -- Form of Incentive Stock Option Agreement (incorporated herein by
reference to Exhibit 10.23 to the Registration Statement).
10.17 -- Form of Nonqualified Stock Option Agreement (new option)
(incorporated herein by reference to Exhibit 10.24 to the Registration
Statement).
10.18 -- Form of Nonqualified Stock Option Agreement (replacement option)
(incorporated herein by reference to Exhibit 10.25 to the Registration
Statement).
10.19 -- Registration Rights Agreement by and between the Company, Natural
Gas Partners, L.P., David B. Strassner, Douglas H. Kiesewetter and R.
Keith Anderson (incorporated herein by reference to Exhibit 10.26 to
the Registration Statement).
10.20 -- Stockholders Agreement by and between the Company, Natural Gas
Partners, L.P., David B. Strassner, Douglas H. Kiesewetter and R.
Keith Anderson (incorporated herein by reference to Exhibit 10.27 to
the Registration Statement).
10.21 -- Form of Affiliates Agreement by and between OEDC Partners, L.P.,
OEDC, Inc., Natural Gas Partners, L.P., David B. Strassner, Douglas H.
Kiesewetter, R. Keith Anderson and Gaylen J. Byker (incorporated
herein by reference to Exhibit 10.28 to the Registration Statement).
10.22 -- Form of Amendment to Affiliates Agreement by and between the
Company, OEDC Partners, L.P., OEDC, Inc., Natural Gas Partners, L.P.,
David B. Strassner, Douglas H. Kiesewetter, R. Keith Anderson and
Gaylen J. Byker (incorporated herein by reference to Exhibit 10.29 to
the Registration Statement).
10.23 -- Form of Indemnity Agreement by and between the Company and each of
its directors and executive officers (incorporated herein by reference
to Exhibit 10.30 to the Registration Statement).
10.24 -- Financial Advisory Services Agreement dated as of April 1, 1996
between OEDC Partners, L.P. and Natural Gas Partners, L.P.
(incorporated herein by reference to Exhibit 10.31 to the Registration
Statement).
10.25 -- Amendment dated August 30, 1996 to Financial Advisory Services
Agreement between OEDC Partners, L.P. and Natural Gas Partners, L.P.
(incorporated herein by reference to Exhibit 10.32 to the Registration
Statement).
10.26 -- Agreement of Management Stockholders dated August 30, 1996 by and
among the Company and David B. Strassner, Douglas H. Kiesewetter and
R. Keith Anderson (incorporated herein by reference to Exhibit 10.33
to the Registration Statement).
10.27 -- Joint Exploration and Participation Agreement dated as of October
3, 1996 by and between OEDC Exploration and Production, L.P. and Amoco
Production Company (incorporated herein by reference to Exhibit 10.34
to the Registration Statement).
10.28 -- General Partnership Agreement for Mobile Bay Processing Partners
dated as of November 6, 1996 by and among MCNIC Mobile Bay Processing,
L.P., OEDC Processing, L.P. and PanEnergy Mobile Bay Processing
Company (incorporated herein by reference to Exhibit 10.25 to the
Company's Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1996 (the "September 30, 1996 Form 10-Q").
32
<PAGE>
10.29 -- Option Agreement dated November 6, 1996 among Dauphin Island
Gathering Company, L.P., OEDC Processing, L.P. and PanEnergy Mobile
Bay Processing Company (incorporated herein by reference to Exhibit
10.26 to the September 30, 1996 Form 10-Q).
10.30 -- Area of Mutual Interest Agreement dated as of November 6, 1996
between Pipeline & Processing Group, Inc., OEDC Partners, L.P. and
PanEnergy Field Services, Inc. (incorporated herein by reference to
Exhibit 10.27 to the September 30, 1996 Form 10-Q).
*21 -- Subsidiaries of the Company.
*27 -- Financial Data Schedule.
- --------------------
* Filed herewith.
(b) Reports on Form 8-K
The Company did not file any Current Reports on Form 8-K during the
fourth quarter of 1996.
33
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
OFFSHORE ENERGY DEVELOPMENT CORPORATION
By: /s/ DAVID B. STRASSNER
David B. Strassner
President
Date: March 31, 1997
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.
<TABLE>
<CAPTION>
NAME POSITION DATE
---- -------- ----
<S> <C> <C>
/s/ DAVID B. STRASSNER President and Director March 31, 1997
David B. Strassner (principal executive officer)
/s/ DOUGLAS H. KIESEWETTER Executive Vice President, March 31, 1997
Douglas H. Kiesewetter Chief Operating Officer and
Director (principal financial
and accounting officer)
/s/ R. KEITH ANDERSON Vice President and Director March 31, 1997
R. Keith Anderson
/s/ DAVID R. ALBIN Director March 31, 1997
David R. Albin
Director
R. Gamble Baldwin
Director
G. Alan Rafte
</TABLE>
34
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Offshore Energy Development Corporation:
We have audited the accompanying consolidated balance sheet of Offshore Energy
Development Corporation as of December 31, 1996 and the related consolidated
statements of operations, stockholders' equity and cash flows for the period
November 7, 1996 through December 31, 1996 and the consolidated balance sheet of
the Company's Predecessors as of December 31, 1995 and the related Predecessors'
consolidated statements of operations, predecessors' equity (deficit) and cash
flows for the period January 1, 1996 through November 6, 1996 and for the years
ended December 31, 1995 and 1994. These consolidated financial statements are
the responsibility of the Company's and the Predecessors' management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Offshore Energy
Development Corporation and its Predecessors as of December 31, 1996 and 1995,
respectively, and the results of its operations and its cash flows and those of
its Predecessors for the period November 7, 1996 through December 31, 1996 and
the period January 1, 1996 through November 6, 1996 and for the years ended
December 31, 1995 and 1994, respectively, in conformity with generally accepted
accounting principles.
KPMG PEAT MARWICK LLP
Houston, Texas
March 17, 1997
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31, December 31,
1995 1996
(Predecessors) (Company)
---------------------------------
<S> <C> <C>
Assets
Current Assets:
Cash and cash equivalents ........................................................ $ 710,306 $ 18,407,768
Accounts receivable - trade, net ................................................. 1,660,193 2,308,439
Accounts receivables - affiliate ................................................. 653,068 87,979
Accounts receivable - other ...................................................... 38,930 1,788,284
Prepaids and other assets ........................................................ 27,484 45,491
----------- ------------
Total current assets ......................................... 3,089,981 22,637,961
Oil and gas properties - at cost (successful efforts method ........................... 26,153,845 36,769,166
Other property and equipment .......................................................... 329,923 372,946
Accumulated depreciation, depletion and amortization ....................................... (6,376,095) (11,439,301)
----------- ------------
20,107,673 25,702,811
Investments in affiliates and others .................................................. 245,783 729,784
Investments in certificates of deposits, restricted .................................. 1,378,601 1,445,442
Deferred and other assets ............................................................. 348,347 424,855
----------- ------------
Total Assets ................................................. $ 25,170,385 $ 50,940,853
=========== ============
Liabilities and Stockholders' Equity (Deficit)
Current Liabilities:
Accounts payable ................................................................. $ 3,136,223 $ 6,392,031
Payable to affiliate ............................................................. 1,124 --
Capital lease payable - current .................................................. 168,168 187,444
Accrued liabilities .............................................................. 357,766 404,138
Current portion of long-term debt ................................................ 12,260,962 --
----------- ------------
Total current liabilities .................................... 15,924,243 6,983,613
Deferred tax liability ................................................................ -- 1,442,844
Capital lease payable - noncurrent .................................................... 831,692 462,380
Reserve for abandonment ............................................................... 236,608 480,906
----------- ------------
Total Liabilities ............................................ 16,992,543 9,369,743
Redeemable preference units, net ..................................................... 10,294,365 --
Stockholders' Equity (Deficit):
Predecessor deficit ......................................................... (2,116,523) --
Preferred stock, $.01 par value, authorized
1,000,000 shares, none issued or outstanding .......................... -- --
Common stock - Offshore Energy Development
Corporation $.01 par value; authorized 10,000,000 shares; ............. -- 87,019
issued and outstanding 8,701,885 at December 31, 1996
Additional paid-in capital .................................................. -- 42,645,778
Accumulated deficit ......................................................... -- (1,161,687)
----------- ------------
Total stockholders' equity (deficit) ......................... (2,116,523) 41,571,110
Commitments and contingencies
----------- ------------
Total Liabilities and Stockholders' Equity (Deficit) .................................. $ 25,170,385 $ 50,940,853
=========== ============
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
January 1 November 7
Year Ended Year Ended through through
December 31, December 31, November 6, December 31,
1994 1995 1996 1996
(Predecessors) (Predecessors) (Predecessors) (Company)
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Income:
Exploration and production ................................. $ 5,512,496 $ 6,168,591 $ 8,018,667 $ 1,816,403
Pipeline operating and marketing ........................... 358,150 166,419 808,081 206,124
Equity in earnings (loss) of equity investments ............ (2,779) 496,979 37,753 15,125
Gain on sales of oil and gas properties
or partnership investments, net ...................... 13,655,225 -- 10,661,433 --
------------ ------------ ------------ -----------
Total Income ...................................... 19,523,092 6,831,989 19,525,934 2,037,652
------------ ------------ ------------ -----------
Expenses:
Operations and maintenance ................................. 1,410,231 2,210,070 1,746,710 225,687
Exploration charges ........................................ 2,231,349 404,836 961,798 1,335,338
Depreciation, depletion and amortization .................. 2,112,350 5,501,072 4,273,109 624,535
Abandonment expense ........................................ 2,735,253 84,219 216,215 1,084,695
General and administrative ................................. 2,358,668 2,191,877 1,824,963 500,258
------------ ------------ ------------ -----------
Total Expenses ..................................... 10,847,851 10,392,074 9,022,795 3,770,513
------------ ------------ ------------ -----------
Earnings (loss) before interest and taxes ....................... 8,675,241 (3,560,085) 10,503,139 (1,732,861)
Interest Income (Expense) and Other:
Interest expense ........................................... (589,948) (1,651,063) (782,708) --
Preferential payments by subsidiaries ...................... (1,430,722) -- -- --
Interest income and other, net ............................ 316,668 122,974 (70,083) (24,468)
------------ ------------ ------------ -----------
Total Interest Income (Expense) and Other .......... (1,704,002) (1,528,089) (852,791) (24,468)
------------ ------------ ------------ -----------
Income (Loss) Before Income Taxes ............................... 6,971,239 (5,088,174) 9,650,348 (1,757,329)
Income Tax Benefit (Expense) .................................... (26,723) 21,375 (2,038,486) 595,642
------------ ------------ ------------ -----------
Net Income (Loss) ............................................... 6,944,516 (5,066,799) 7,611,862 (1,161,687)
------------ ------------ ------------ -----------
Preference unit payments and accretion of discount ......... (585,000) (1,141,865) (2,616,722) --
Income (loss) available to common unit holders and
stockholders ............................................... $ 6,359,516 $ (6,208,664) $ 4,995,140 $(1,161,687)
============ ============ ============ ===========
Income (loss) available to common unit holders and
stockholders per common share .............................. $ 1.26 $ (1.23) $ 0.99 $ (0.13)
============ ============ ============ ===========
ccWeighted average number of common shares and
common share equivalents outstanding ....................... 5,051,882 5,051,882 5,051,882 8,701,885
============ ============ ============ ===========
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' AND PREDECESSORS' EQUITY (DEFICIT)
<TABLE>
<CAPTION>
Total
Additional Stockholders'
Predecessors' Paid-In Accumulated and Predecessors'
Equity (Deficit) Shares Amount Capital (Deficit) Equity (Deficit)
----------- --------- ------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
January 1, 1994 (Predecessors) ................ $(1,090,748) -- $ -- $ -- $ -- $ (1,090,748)
Capital Distributions ......................... (3,076,681) -- -- -- -- (3,076,681)
Net income .................................... 6,944,516 -- -- -- -- 6,944,516
Preference units payments ..................... (585,000) -- -- -- -- (585,000)
----------- --------- ------- ----------- ----------- ------------
December 31, 1994 (Predecessors) .............. 2,192,087 -- -- -- -- 2,192,087
Capital distributions ......................... (100,000) -- -- -- -- (100,000)
Issuance of common units, 99,000 units ........ 2,000,000 -- -- -- -- 2,000,000
Issuance of common stock, 5,400 shares ........ 54 -- -- -- -- 54
Net loss ...................................... (5,066,799) -- -- -- -- (5,066,799)
Preference unit payments ...................... (847,500) -- -- -- -- (847,500)
Accretion of discount on preference units ..... (294,365) -- -- -- -- (294,365)
----------- --------- ------- ----------- ----------- ------------
December 31, 1995 (Predecessors) .............. (2,116,523) -- -- -- -- (2,116,523)
Net income .................................... 7,611,862 -- -- -- -- 7,611,862
Preference unit payments ...................... (911,087) -- -- -- -- (911,087)
Issuance of common stock (Company) ............ -- 3 -- 30 -- 30
Accretion of discount on preference units ..... (1,705,635) -- -- -- -- (1,705,635)
----------- --------- ------- ----------- ----------- ------------
November 6, 1996 (Predecessors and Company).... 2,878,617 3 -- 30 -- 2,878,647
Transfer of predecessor equity
and issuance of common stock pursuant
to the Combination .......................... (2,878,617) 5,051,882 50,519 2,828,098 -- --
Issuance of common stock, net ................. -- 3,650,000 36,500 39,817,650 -- 39,854,150
Net loss ...................................... -- -- -- -- (1,161,687) (1,161,687)
----------- --------- ------- ----------- ----------- ------------
December 31, 1996 (Company) ................... $ -- 8,701,885 $87,019 $42,645,778 $(1,161,687) $ 41,571,110
=========== ========= ======= =========== =========== ============
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
January 1 November 7
Year Ended Year Ended through through
December 31, 1994 December 31, 1995 November 6, 1996 December 31, 1996
(Predecessors) (Predecessors) (Predecessors) (Company)
-------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating Activities
Net income (loss) ................................... $ 6,944,516 $ (5,066,799) $ 7,611,862 $ (1,161,687)
Adjustments to reconcile net income (loss)
to cash provided by (used in) operations
Depreciation, depletion and amortization ...... 2,234,000 5,652,841 4,409,690 637,755
Abandonment expense ............................ 2,735,253 84,219 68,644 1,084,695
Gain on sales, net.............................. (13,655,225) -- (10,661,433) --
Dry hole expense ............................... 1,585,872 -- 301,750 1,123,601
Transfer of partnership equity interest ........ 1,300,000 41,126 -- --
Equity in (earnings) loss of equity investments 2,779 (496,979) (37,753) (15,125)
Change in interest of oil and gas partnerships . 25,864 344,590 845,995 (2,101,538)
Deferred taxes ................................. 23,018 (23,018) 2,038,486 (595,642)
Changes in assets and liabilities:
Accounts receivable ....................... 1,211,677 (1,561,151) 639,167 (999,717)
Deferred and other assets ................. (72,381) 134,016 (853,006) (874,129)
Accounts payable .......................... 443,173 719,648 2,748,657 (2,245,598)
Accrued liabilities ....................... 54,839 (211,565) 358,381 (312,009)
---------- --------- ---------- ------------
Total adjustments .................... (4,111,131) 4,683,727 (141,422) (4,297,707)
---------- --------- ---------- ------------
Net cash provided by (used in) operating
activities ................................ 2,833,385 (383,072) 7,470,440 (5,459,394)
Investing Activities
Investment in equity interests ...................... (192,474) (263,534) (245,748) (208,930)
Advances to equity investees ........................ (714,918) (836,137) -- --
Repayments from equity investees .................... 40,624 997,791 512,640 --
Short term investments .............................. 50,000 -- -- --
Cash paid under net profits interest ................ (32,440) -- -- --
Proceeds from the sales of properties and other
investments ......................................... 40,289,309 -- 11,340,093 --
Note receivable ..................................... 246,030 -- -- --
Restricted investments in certificates of deposit ... (134,682) (558,431) (55,224) (11,617)
Capital expenditures for property and equipment ..... (18,418,340) (15,965,301) (7,955,984) (2,041,103)
---------- --------- ---------- ------------
Net cash provided by (used in) investing
activities .......................................... 21,133,109 (16,625,612) 3,595,777 (2,261,650)
Financing Activities
Capital distributions ............................... (3,076,681) (100,000) -- --
Proceeds from issuance of redeemable preference
units and common units ......................... -- 5,500,000 -- --
Redemption of preference units ...................... -- -- -- (12,000,000)
Preference unit payments ............................ (585,000) (847,500) (802,500) (108,587)
Payments of note payable to partner ................. (2,000,000) -- -- --
Proceeds from borrowings ............................ 7,400,000 8,291,492 3,133,606 --
Principal payments on borrowings .................... -- (3,430,530) (12,260,962) (3,133,606)
Fees paid to acquire financing ...................... (560,003) -- (121,004) (39,884)
Settlement of production payment .................... (20,237,945) -- -- --
Proceeds from stock issuance ........................ -- -- -- 40,734,030
Payment of initial public offering expenses ......... -- -- -- (879,850)
Principal payments on capital lease ................. (490,513) (108,254) (139,378) (29,576)
---------- --------- ---------- ------------
Net cash provided by (used in) financing
activities .......................................... (19,550,142) 9,305,208 (10,190,238) 24,542,527
Increase (decrease) in cash and cash
equivalents ......................................... 4,416,352 (7,703,476) 875,979 16,821,483
Cash and cash equivalents balance, beginning of
period .............................................. 3,997,430 8,413,782 710,306 1,586,285
---------- --------- ---------- ------------
Cash and cash equivalents balance, end of period ... $ 8,413,782 $ 710,306 $ 1,586,285 $ 18,407,768
========== ========= ========== ============
Supplemental disclosures of cash flow information:
Cash paid during the period for interest ....... $ 353,809 $ 1,760,571 $ 744,045 $ 58,407
========== ========= ========== ============
Cash paid during the period for income taxes ... -- $ -- $ -- $ --
========== ========= ========== ============
Supplemental disclosure of non-cash activity:
Capital lease acquisition ...................... $ 256,553 $ 762,349 $ -- $-
Issuance of stock .............................. -- 54 -- --
Accretion of discount on preference units ...... -- 294,365 1,705,635 --
Interests in OEDC Partners, L.P. and OEDC Inc.
contributed for common stock .............. -- -- 50,519 --
Predecessors' partners capital and retained
earnings reclassified to additional
paid-in capital .......................... -- -- 2,828,098 --
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996 AND 1995
1. GENERAL INFORMATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION AND BUSINESS PURPOSE
Offshore Energy Development Corporation ("OEDC" or the "Company")
is a Delaware corporation formed on July 24, 1996 for the purpose of acquiring
the common stock of OEDC, Inc. and the partners' interest in OEDC Partners, L.P.
(the "Combination"). At formation, OEDC issued a share of stock to three of its
officers.
The Combination was consummated on November 6, 1996 and OEDC
issued 5,051,882 shares of common stock to the stockholders of OEDC, Inc.
("Inc.") and the partners of OEDC Partners, L.P. ("Partners"), collectively (the
"Predecessors). The Combination was accounted for by assigning the Predecessors'
carryover basis to the acquired assets. In conjunction with the Combination, the
Company completed a public issuance of 3,650,000 shares of common stock.
The Predecessors were formed on August 31, 1992 for the purpose of investing in
certain partnerships involved in drilling, producing, marketing, gathering and
storing oil and gas. Upon completion of the Combination, all of Partners' assets
and liabilities were transferred to OEDC, the partners of Partners were issued
common stock in exchange for their interests and Partners was dissolved. The
shareholders of Inc. exchanged their Inc. common stock for OEDC common stock and
Inc. became a wholly-owned subsidiary of OEDC.
PRINCIPLES OF CONSOLIDATION
The Company's investments in associated oil and gas partnerships
are accounted for using the proportionate consolidation method, whereby the
Company's proportionate share of each oil and gas partnerships' assets,
liabilities, revenues, and expenses is included in the appropriate
classifications in the Company's financial statements. Investments in non-oil
and gas partnerships where the Company has ownership interest of less than 50%
are accounted for on the equity method, all investments with an ownership
interest of less than 20% are accounted for on the cost method. All of the
Company's material intercompany accounts and transactions have been eliminated
in the consolidation.
The consolidated financial statements include the consolidated
accounts of Inc. and Partners prior to the Combination. The consolidated
financial statements are presented due to Inc.'s sole general partner interest
and control over Partners. The stockholders' equity of Inc. and partners' equity
of Partners are presented together due to the commonality of the stockholders
and partners of Inc. and Partners.
<PAGE>
CASH AND CASH EQUIVALENTS
Short-term investments with an original maturity of three months
or less are considered cash equivalents and are classified as such in the
accompanying statements of cash flows. Cash and cash equivalents consist of cash
on hand and investments in short-term government securities at cost, which
approximates market.
OIL AND GAS PROPERTIES
Oil and gas properties are accounted for on the successful
efforts method whereby costs, including lease acquisition and intangible
drilling costs associated with exploration efforts which result in the discovery
of proved reserves and costs associated with development wells, whether or not
productive, are capitalized. Gain or loss is recognized when a property is sold
or ceases to produce and is abandoned. Capitalized costs of producing oil and
gas properties are amortized using the unit-of-production method based on units
of proved developed reserves for each property whereas leasehold costs are
depleted based on total proved reserves.
The costs of unproved leaseholds are capitalized pending the
results of exploration efforts. Significant unproved leaseholds are assessed
periodically, on a property-by-property basis, and a loss is recognized to the
extent, if any, that the costs of the property has been impaired. Exploratory
dry holes, geological and geophysical charges and delay rentals are expensed as
incurred. Costs to operate and maintain wells and equipment and to lift oil and
gas to the surface are expensed as incurred.
Estimated future expenditures for site remediation, abandonment
and dismantlement costs are charged to operations using the unit-of-production
method based upon estimates of proved oil and gas reserves for each property.
Effective January 1, 1996, the Company adopted Statement of
Financial Accounting Standards No. 121, ACCOUNTING FOR THE IMPAIRMENT OF
LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF, ("SFAS No. 121").
Consequently, the Company reviews its long-lived assets to be held and used,
including oil and gas properties accounted for under the successful efforts
method of accounting, whenever events or circumstances indicate the carrying
value of those assets may not be recoverable. SFAS No. 121 requires that an
impairment loss be recognized whenever the carrying amount of an asset exceeds
the sum of the estimated future net cash flows (undiscounted) of the asset.
Under SFAS No. 121, the Company performs its impairment review of proved oil and
gas properties on a depletable unit basis. For any depletable unit determined to
be impaired, an impairment loss equal to the difference between the carrying
value and the fair value of the depletable unit will be immediately recognized.
Fair value, on a depletable unit basis, is estimated to be the present value of
expected
<PAGE>
future cash flows computed by applying estimated future oil and gas prices, as
determined by management, to estimated future production of oil and gas reserves
over the economic lives of the reserves. No such impairment was recognized as a
result of the adoption of SFAS No. 121.
Prior to January 1, 1996, the Company determined the impairment
of proved oil and gas properties on an aggregate basis. Using the aggregate
basis, if the net capitalized costs exceeded the estimated future undiscounted
after-tax net cash flows from proved oil and gas reserves using period-ending
pricing, such excess would be charged to expense. No such charge was required at
December 31, 1995 or 1994.
INCOME TAXES
The Company provides for income taxes using the asset and
liability method. Under the asset and liability method, deferred tax assets and
liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets
and liabilities and their respective tax bases and operating loss and tax credit
carryforwards. Deferred tax assets and liabilities are measured using enacted
tax rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. The effect on
deferred tax assets and liabilities of a change in tax rates is recognized in
income in the period that includes the enactment date.
Prior to the Combination, Partners was a limited partnership. As
such, it was not subject to federal income taxes; the taxable income or loss was
passed through to the partners.
STOCK-BASED COMPENSATION
Effective January 1, 1996, the Company adopted Statement of
Financial Accounting Standards No. 123, ACCOUNTING FOR STOCK-BASED COMPENSATION
("SFAS No. 123"). SFAS No. 123 allows a company to adopt a fair value based
method of accounting for a stock-based employee compensation plan or to continue
to use the intrinsic value based method of accounting prescribed by Accounting
Principles Board Opinion No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES ("APB
No. 25"). The Company has chosen to continue to account for stock-based
compensation under APB No. 25 using the intrinsic value method. Under this
method, the Company has not recorded any compensation expense related to stock
options granted. The disclosures required by SFAS No. 123, however, have been
included in Note 6.
<PAGE>
REVENUE RECOGNITION
The Company uses the sales method of accounting for natural gas
imbalances. Under the sales method, the Company recognizes revenues based on the
amount of gas sold to purchasers, which may differ from the amounts to which the
Company is entitled based on its interest in the properties. Gas imbalance
obligations as of December 31, 1996, 1995, and 1994, were not significant.
The Company recognizes marketing revenue net of the cost of gas
and third-party delivery fees as service is provided.
The Company recognizes pipeline operating revenue as service is
provided.
NATURAL GAS HEDGING ACTIVITIES
The Company periodically enters into natural gas price swaps with
third parties to hedge against potential adverse effects of fluctuations in
future prices for the Company's anticipated production volumes based on current
engineering estimates. The natural gas price swaps qualify as hedges and
correlate to natural gas production; therefore any gains or losses will be
recorded when the related natural gas production has been delivered. In order to
qualify as a hedge, the price movements in the underlying commmodity derivatives
must be sufficiently correlated with the hedged commodity.
Gains and losses on closed natural gas swap agreements will be deferred and
amortized over the original term of the agreement. Should the natural gas price
swaps cease to be recognized as a hedge, subsequent changes in value will be
recorded in the Statements of Operations. While the swaps are intended to reduce
the Company's exposure to declines in the market price of natural gas, they may
limit the Company's gain from increases in the market price. The swap agreements
also expose the Company to credit risk to the extent the counterparty is unable
to perform under the agreement.
OTHER PROPERTY AND EQUIPMENT
Other property and equipment consists of furniture, office
equipment and automobiles which are depreciated on a straight-line basis over
the estimated useful life of the assets ranging from five to seven years.
DEFERRED AND OTHER ASSETS
The December 31, 1996 and 1995 balances primarily consist of
financing fees, incurred in securing a long-term note payable, and partnership
organization costs. The financing fees are being amortized over the life of the
loan and the partnership organization costs are being amortized over 60 months.
<PAGE>
NET INCOME PER SHARE
Net income per common share is computed using the weighted
average number of common shares outstanding and common stock equivalents during
each of the years presented. Outstanding stock options are common stock
equivalents and are considered when the effect is dilutive.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value of cash and cash equivalents, accounts
receivable, other current assets, accounts payable and accrued expenses
approximates fair value because of the short-term maturity of these instruments.
The carrying value of the outstanding debt at December 31, 1995
approximated fair value as this debt bears interest at rates which approximate
current market rates and there has been no change in the Company's credit
profile.
USE OF ESTIMATES
The preparation of financial statements in conformity with
generally accepted accounting principles requires management of the Company to
make estimates and assumptions that affect certain reported amounts of assets
and liabilities and disclosure of contingent liabilities at the date of the
financial statements. Certain amounts of reported revenues and expenses are also
affected by these estimates and assumptions. Actual results could differ from
those estimates.
2. INVESTMENTS
AFFILIATES
Through Dauphin Island Gathering Company, L.P. ("DIGCO"), a
partnership wholly-owned by OEDC, the Company has a one percent investment in
Dauphin Island Gathering Partners ("DIGP") that is accounted for using the
equity method. This investment includes undistributed earnings (losses) of
approximately $53,000, $497,000 and $(3,000) in 1996, 1995, and 1994,
respectively.
On January 14, 1993, the Company entered into a Texas general
partnership with Enron Gas Gathering, Inc. ("EGGI"), a wholly-owned subsidiary
of Enron Corp., to form DIGP to which the Company contributed the Dauphin Island
Gathering System ("DIGS") together with certain permits, contracts, accrued
income and liabilities with a net book value of $13,692. The Company serves as
operator of DIGP's pipeline facilities. Under the DIGP partnership agreement,
income is to be allocated on the basis of 80% to EGGI and 20% to the Company
until such time as EGGI has recouped its investment together
<PAGE>
with a specified rate of return, as defined. After such time, both income and
losses will be allocated equally to EGGI and to the Company.
On March 25, 1994, DIGP entered into a contribution agreement
with Tenneco Gas, Inc. ("Tenneco"), whereby Tenneco contributed $19 million in
cash, contracts and materials to DIGP in exchange for a 50% interest in DIGP.
The remaining 50% interest was split evenly between the Company and EGGI.
Also in 1994, the Company transferred $1,300,000 of its partners'
capital in DIGP to EGGI. The Company and EGGI agreed that the transfer resulted
in EGGI realizing the recoupment of its investment as of September 30, 1994.
Beginning October 1, 1994, income and losses were allocated 50% to Tenneco, 25%
to EGGI and 25% to the Company.
In 1995, DIGP recorded an $82,252 transfer of partners' capital
from the Company and EGGI to Tenneco to reflect the proper allocation of state
sales and use tax relating to materials purchased prior to March 25, 1994 by
DIGP to construct DIGS. The transfer was split evenly between the Company and
EGGI. As a result, the Company transferred $41,126 of its partners' capital in
DIGP to Tenneco.
In 1996, the Company sold approximately 96% if its remaining
interest in DIGP to a subsidiary of MCN Investment Corporation ("MCN") thereby
reducing its interest in DIGP to 1%.
Effective December 31, 1996, DIGP merged with Main Pass Gas
Gathering Company, which owned the Main Pass Gas Gathering System, with DIGP
being the surviving entity of the merger. In connection with the merger, the
Company agreed to purchase from one of its partners in DIGP for approximately
$619,000 additional interest in DIGP in order to maintain the Company's interest
in DIGP at 1%.
The Company continues to operate DIGS and, pursuant to an
incentive management arrangement, its one percent interest in DIGP will increase
up to a maximum of 11.15% when its DIGP partners receive the return of their
investment plus a 10% rate of return, subject to certain other conditions.
Accordingly, the investment continued to be carried on the equity method.
<PAGE>
Summarized financial data of DIGP as of December 31, 1995 and 1994 and for the
years then ended follows:
<TABLE>
<CAPTION>
1994 1995
------------------ ------------------
<S> <C> <C>
Current assets..................................... $ 3,496,164 $ 1,963,998
Long-term assets................................... 51,714,521 58,172,859
================== ==================
Total assets................................. $ 55,210,685 $ 60,136,857
================== ==================
Current liabilities................................ $ 6,702,506 $ 9,689,455
Long-term liabilities.............................. 18,461,633 18,375,242
Partners' capital.................................. 30,046,546 32,072,160
================== ==================
Total liabilities and partners' capital...... $ 55,210,685 $ 60,136,857
================== ==================
Revenues........................................... $ 4,482,987 $ 9,526,215
Operating expenses................................. (4,299,971) (7,500,601)
================== ==================
Net income................................... $ 183,016 $ 2,025,614
================== ==================
The Company's share of net income.......... $ 29,661 $ 506,403
================== ==================
</TABLE>
Summarized financial data for the year ended and as of December
31, 1996 is not presented since the Company's ownership interest in DIGP is not
material to its current operations.
In 1996, the Company and subsidiaries of MCN and PanEnergy Corp
formed a partnership (the "Processing Partnership") for the purpose of
constructing, owning and operating, or providing financing for one or more
natural gas processing facilities onshore in Mobile County, Alabama. The Company
has approximately $200,000 invested in the Processing Partnership, representing
a 1% general partnership interest. The Company has an option to buy an
additional 32 1/3% interest in the Processing Partnership, exercisable until the
third anniversary of the commencement of commercial operations at the Processing
Partnership's initial processing facility. The costs of the additional
partnership interest will be equal to the historical book value of the plant
reduced for depreciation on the date the option is exercised and increased by
12% per year.
OTHER
The Company has approximately $250,000 invested in Asia-Pacific
Refinery Investment, L.P. ("APRI"), representing a 13% limited partnership
interest, which is carried at cost. APRI is involved in the construction and
operation of a refinery unit and is currently in the final stages of compiling a
financing group to generate the additional funds necessary to begin construction
of the refinery. The Company has no responsibility to provide additional funds
to APRI. The refinery will be constructed in Houston, Texas and transported to
Papua New Guinea. APRI has already purchased the necessary refinery site in
Papua New Guinea. The construction of the refinery is expected to begin in 1997.
The Company also has a $4,109 investment in the Salach Partnership
<PAGE>
("Salach"). Salach was formed to participate in the acquisition of on-shore
undeveloped leases. Salach's operations have been, and are expected to be,
insignificant to the Company,
3. LONG-TERM DEBT
In 1994, the Company obtained a credit facility from Joint Energy
Development Investments Limited Partnership totaling $16,000,000. The
$16,000,000 includes a revolving credit loan for $7,500,000 and a term loan for
$8,500,000 made available to the Company upon request. The outstanding principal
balance of each revolving credit loan accrues interest at a varying rate per
annum that is 2.5% per annum above the prime lending rate. The outstanding
principal amount of each term loan bears interest from the date made until the
due date at a rate of 15% per annum. Under the debt agreement, principal
repayments for the term loan are to begin on or before March 20, 1995. Amounts
outstanding under the revolving loan are due in full in August 1996. The current
portion of the term loan is determined based on the terms set forth in the
agreements. At December 31, 1995, the Company had borrowed $5 million against
the revolving loan and $7,260,962 against the term loan. All amounts borrowed
were repaid in 1996 and the credit facility was terminated.
In 1996, the Company entered into a two-year $10,000,000 line of
credit with Union Bank of California, N.A. At December 31, 1996, the borrowing
base was $5,000,000 with no amounts outstanding under this facility. The
borrowing base is reduced by $312,500 per month through August 31, 1997, by
$250,000 per month for the succeeding six months and by $166,667 per month for
the final six months of the agreement, unless changed by the bank at the time of
a borrowing base redetermination. The borrowing base is to be redetermined every
six months. Borrowings under this facility bear interest at a rate equal to, at
the Company's option, either the bank's reference rate plus 1% or LIBOR plus
2.5%.
The Union Bank credit facility is collateralized by the Company's
investments in oil and gas properties. The credit facility contains restrictive
covenants imposing limitations on the incurrence of indebtedness, the sale of
properties, payment of dividends, mergers or consolidations, capital
expenditures, transactions with affiliates, making loans and investments outside
the ordinary course of business. The credit facility also contains certain
restrictions of working capital and interest coverage and requires the Company
to maintain a certain volume of hedging contracts in effect during the term of
the facility.
The Company is in compliance with all debt covenants for all
periods presented.
<PAGE>
4. REDEEMABLE PREFERENCE UNITS
In August of 1992, the Predecessors issued 100,000 common units
to one of its partners. In July of 1995, an additional 20,000 preference units
were issued and the redemption price of all 120,000 preference units was
increased to $100 from $65 per unit, resulting in a redemption value of $12
million. Of the total cash contribution made by the Predecessors' partners, $10
million was allocated to the preference units. The difference between the
redemption value and recorded value of the preference units, $2,000,000, is
being accreted over the redemption period for the preference units. The
Predecessors paid a 9% coupon on the preference units outstanding.
The preference units were redeemed for $12 million in November of
1996 at which time, the unaccreted discount was recognized in the Statements of
Operation and all obligations under the agreement were terminated.
5. STOCKHOLDERS' EQUITY
In November of 1996, the Company completed an initial public
offering, issuing 3,650,000 shares of stock.
The Board of Directors of the Company is empowered, without
approval of stockholders, to cause shares of preferred stock to be issued in one
or more series. The Board of Directors is authorized to fix and determine
variations in designations, preferences and relative, participating, optional or
other special rights and the limitations or restrictions of such rights and
voting powers, No preferred stock has been issued at December 31, 1996.
Holders of common stock are entitled to one vote per share in the
election of directors and on all other matters submitted to a vote of common
stockholders. The common stock does not have cumulative voting rights. Holders
of common stock are entitled to received dividends, if any, as may be declared
by the Board of Directors out of funds legally available therefore, subject to
any preferential dividend rights of holders of outstanding preferred stock.
6. KEY EMPLOYEE STOCK PLAN
The Company has established a stock awards plan (the "1996 Stock
Awards Plan") pursuant to which options to purchase up to 835,000 shares of
common stock will be available for grants. The 1996 Stock Awards Plan provides
for the granting of incentive options, non-qualified stock options, restricted
stock awards, stock appreciation rights, performance awards and phantom stock
awards, or any combination thereof.
<PAGE>
Non-qualified stock options to purchase 727,580 shares of common
stock were granted in 1996 and are outstanding and subject to vesting
requirements. Twenty percent of the granted options vest each year. Of such,
options to purchase 187,580 shares of common stock (of which 99,268 are
currently exercisable) were exchanged for options issued by Offshore Energy
Development Corporation (a Texas Corporation) prior to 1995 at a fair value
exercise price of $3.61. The quantity and price of the options have been
adjusted for the effect of the Combination and the exercise price was adjusted
to the initial public offering price per share. The exercise price of the
balance of options to purchase 727,580 shares of common stock is $12. No option
may be exercised earlier than six months from the date of grant.
At December 31, 1996, the Company has reserved a total of
approximately 727,580 shares of common stock for issuance under the 1996 Stock
Award Plan. The outstanding stock options granted to key employees, officers and
directors for the purchase of shares of the Company's common stock are as
follows:
Price per share
------------------------------
Shares From To
--------- -------- ----------
Balance, December 31, 1995 - - -
Granted 727,580 $3.61 $12.00
Exercised - - -
Expired - - -
--------- -------- ----------
Balance, December 31, 1996 727,580 $3.61 $12.00
========= ======== ==========
As of December 31, 1996, 99,268 options are immediately
exercisable and have a remaining term of approximately seven years. No grants
were made in 1994 or 1995. The expected life of the options granted is 8-10
years. The weighted average fair value of options granted during 1996 is $5.48.
The fair value of each option grant is estimated on the date of grant, using the
Black-Scholes options-pricing model. The model assumed expected volatility of
30% and risk-free interest rates of 5.58%, 6.69%, and 6.31% for grants in 1996.
As the Company has not declared dividends since it became a public entity, no
dividend yield was used. Actual value realized, if any, is dependent on the
future performance of the Company's common stock and over all stock market
conditions. There is no assurance the value realized by an optionee will be at
or near the value estimated by the Black-Scholes model.
Outstanding options at December 31, 1996 expire between January
2004 and November 2006.
As discussed in Note 1, no compensation expense has been recorded
in 1996 for the Company's non-qualified stock options under the intrinsic value
method. Had compensation cost for the Company's stock option plans been
determined based on the fair value at the grant dates for awards made after
December 31, 1994 under those plans,
<PAGE>
the Company's net income (loss) and earnings (loss) per share would have been
reduced to the pro forma amounts indicated below:
YEAR ENDED DECEMBER 31,
-----------------------
1996
----
Net income (loss) As reported $ 3,833,453
Pro forma $(152,716)
Earnings (loss) per share As reported $ 0.68
Pro forma $(0.03)
Under the provisions of SFAS No. 123, the pro forma disclosures above indicate
only the effects of stock options granted by the Company subsequent to December
31, 1994. During this initial phase-in period, the pro forma disclosures as
required by SFAS No. 123 are not representative of the effects on reported net
income for future years as options vest over several years and additional awards
are generally made each year.
7. ABANDONMENT OF OIL AND GAS OF PROPERTIES
After evaluating the potential results from a workover of the
well, the Company allowed its lease on the Eugene Island Block 163 to expire in
1994. All property costs and accumulated depletion and depreciation were written
off in 1994, resulting in an abandonment charge of $2,108,743. As of December
31, 1994, $292,425 had been accrued for final abandonment costs which were
incurred in 1995. During 1996, the Company incurred $147,572 in abandonment
expense for the settlement of disputed invoices related to the Eugene Island
Block 163 abandonment and accrued an additional $150,538 for future abandonment
costs.
In 1996, the Company allowed its lease on the Viosca Knoll Block
118 to expire. All property costs were written off in 1996, resulting in a lease
expiration charge of $581,020. Also in 1996, due to poor results from the South
Timbalier Block 162 B-8 well, the well costs and accumulated depletion and
depreciation were written off, resulting in an abandonment charge of $421,780.
In 1996, the Company drilled two exploratory dry holes resulting
in exploration charges of $1.4 million.
The Company has an estimated future abandonment liability related
to its producing properties of approximately $830,000 at December 31, 1996,
which will be amortized to expense over the properties' reserve life.
<PAGE>
8. NATURAL GAS HEDGING
During 1996, the Company entered into natural gas price swap
agreements with Enron Capital & Trade Resources. The Company's exploration and
production revenues were decreased by approximately $1,276,000 in 1996 as a
result of the swap agreements.
At December 31, 1996, the Company had the following commitments under swap
agreements:
MONTHLY
VOLUME FIXED PRICE
TIME PERIOD (MMBTU) ($/MMBTU)
----------- ------- ------------
January 1997 to February 1997.............. 350,000 $2.009-2.880
March 1997................................. 370,000 2.009-2.375
April 1997................................. 400,000 2.009-2.165
May 1997................................... 410,000 2.009-2.065
June 1997 to August 1997................... 420,000 2.009-2.045
September 1997............................. 60,000 2.009
October 1997 to December 1997.............. 50,000 2.009
At December 31, 1996, the Company estimates the cost of unwinding
these positions to be approximately $824,000.
During 1995 and 1994, the Company entered into natural gas swap
agreements with Enron Capital & Trade Resources and Enron Risk Management
Services Corporation, respectively. During 1995 and 1994, the Company's
exploration and production revenues were increased by approximately $622,000 and
$482,000, respectively, as a result of the swap agreements.
9. SALE OF INVESTMENT IN PARTNERSHIP AND OIL AND GAS PROPERTIES
During 1996, the Company sold approximately 96% of its interest
in DIGP to MCN. The Company received net proceeds of approximately $10,800,000
from MCN resulting in a gain of approximately $10,800,000. The Company will
continue to operate DIGP and retain a 1% ownership interest (see Note 2).
Also, during 1996 the Company sold its interest in a
non-producing oil and gas property for approximately $500,000 resulting in a
loss of approximately $166,000.
The Company sold a group of properties effective June 1, 1994, to
Scana Petroleum Resources Inc., for net proceeds of approximately $40,000,000,
resulting in a gain of approximately $13,700,000.
<PAGE>
10. CAPITAL LEASE
During 1994, the Company entered into a capital lease agreement
for a compressor unit. The compressor, with a net book value at December 31,
1996 of approximately $632,000, is the security for the lease. The agreement
calls for monthly payments of $22,614 including interest at a basic annual rate
of 11%. Total future minimum lease obligations at December 31, 1996 are as
follows:
YEAR ENDED DECEMBER 31,
----------------------
1997 $271,368
1998 271,368
1999 271,368
2000 22,614
-----------
Total future minimum lease payments...................... 836,718
Less amounts representing interest ...................... 186,894
-----------
Present value of future minimum lease
payments................................................. 649,824
Less current installments of obligation under capital
lease.................................................... 187,444
-----------
Obligations under capital lease, excluding current
installments............................................. $462,380
===========
11. RELATED PARTY TRANSACTIONS
OPERATOR FEES
The Company, as operator of the DIGS, is entitled to charge
certain fees to DIGP attributable to the pipeline operations. For the year ended
December 31, 1996, the Company charged $611,337 in operator fees to DIGP. In
1995, the Company charged $139,544 in operator fees and construction overhead
fees to DIGP, of which $65,569 is a receivable at December 31, 1995. In 1994,
the Company charged $338,221 in operator fees and construction overhead fees to
DIGP.
RECEIVABLE FROM AFFILIATES
At December 31, 1996, the Company had affiliated receivables from
DIGP of $87,979 for expenses paid by the Company on behalf of DIGP. Also at
December 31, 1996, the Company had a receivable from Enron Capital & Trade
Resources ("ECT") for $1,787,084 for development costs paid by the Company on
behalf of ECT. This receivable is included in the accounts receivable from
others balance at December 31, 1996.
<PAGE>
At December 31, 1995, the Company had affiliated receivables from
DIGP of $585,732, representing expenses paid by the Company on behalf of DIGP
and accrued interest charged to DIGP for its outstanding payable balance due to
the Company at a rate commensurate with DIGP's long-term borrowing rate. The
interest charged is in accordance with the DIGP Partnership Agreement. Also at
December 31, 1995, the Company had a receivable from NGP in the amount of $54
for the purchase of the Predecessor's common stock and $1,713 from the Company's
officers for expenses paid by the Company on behalf of the officers.
PREFERENCE UNIT PAYMENTS
Preference units payments totaling $911,087, $847,500 and
$585,000 were paid to NGP for preference units outstanding during the years
ended December 31, 1996, 1995 and 1994, respectively. The preference units were
redeemed for $12,000,000 by the Company in November 1996 at which time the
unaccreted discount was recognized in the Statements of Operations.
OTHER
During 1994, the Company made a $130,722 non-cash preferential
payment, in the form of a transfer of partners capital to Enron Finance
Corporation ("EFC") to complete EFC's recoupment of its investment in an oil and
gas partnership participated in by both EFC and the Company. Upon EFC's
recoupment of its initial investment in the partnership, the income (loss)
sharing ratio between EFC and the Company was restructured.
One of the employees, who is also an officer and a director of
the Company, is a majority shareholder of CSA Financial Services ("CSA"). CSA
provides, on a contractual basis, all Company operating personnel. The Company
reimburses CSA for actual payroll costs plus burden. The Company made payments
to CSA totaling approximately $1,304,000, $1,197,000 and $1,065,000 for the
years ended December 31, 1996, 1995 and 1994, respectively. No amounts were
outstanding or payable under this arrangement at the end of any of the years
presented.
Two of the Company's directors are majority shareholders of
Natural Gas Partners L.P. (NGP). The Company and NGP are parties to a Financial
Advisory Services Agreement pursuant to which the Company has engaged NGP to
serve as financial advisor. In consideration of its services, NGP receives an
annual fee of $15,000 for each representative of NGP that serves on the board of
directors of the Company and an annual fee of $30,000 commencing November 6,
1996 and continuing for a two-year period. In 1996, the Company paid $30,000
under this agreement, of which $7,500 is accrued for at year-end.
<PAGE>
12. INCOME TAXES
As discussed in Note 1, the Company accounts for income taxes
under the asset and liability method. Prior to the Combination, Partners,
representing the majority ownership of the Predecessors, did not incur federal
income taxes; the taxable income or loss was passed through to the partners. As
a result of the Combination in November 1996, the Predecessors became a taxable
entity and recorded a one-time charge of $2,038,486, primarily representing the
difference between the financial statement and income tax basis of oil and gas
properties. Income tax benefit for the period November 7, 1996 through December
31, 1996 was $595,642, which represents a deferred federal income tax benefit.
Income tax expense (benefit) relating to the Company's and Inc.'s
pre-tax operating results for the years ended December 31, 1996, 1995 and 1994
consists of:
<TABLE>
<CAPTION>
Predecessors Company
----------- -----------
January 1 November 7
Predecessors Predecessors through through
---------- ---------- November 6, December 31,
1994 1995 1996 1996
---- ---- ----------- ---------
<S> <C> <C> <C> <C>
Current federal expense $ 3,705 $ 1,643 $ - $ -
Deferred federal expense (benefit) 23,018 (23,018) 2,038,486 (595,642)
------ -------- ---------- ---------
$26,723 $(21,375) $2,038,486 $(595,642)
======= ======== ========== =========
</TABLE>
The Company's effective tax rate applicable for the period
November 7, 1996 to December 31, 1996 approximates the statutory federal tax
rate of 34%.
Tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and deferred tax liabilities at
December 31, 1996 and 1995 are presented below:
INC. COMPANY
---- ----
1995 1996
---- ----
Net operating loss carry forwards $54,706 $ 987,406
Accrued contracts payable -- 136,000
Accrued abandonment costs -- 163,508
---------- -----------
Total gross deferred tax assets 54,706 1,286,914
Valuation allowance (22,864) -
---------- -----------
Net deferred tax assets 31,842 1,286,914
========== ===========
Basis differences in property and equipment -- 2,654,366
Investments in partnerships 31,842 75,392
------------ -----------
Total gross deferred tax liabilities 31,842 2,729,758
---------- -----------
Net deferred tax liability $ -- $1,442,844
============ ===========
There was an increase in the valuation allowance for deferred tax assets of
$22,864 during 1995. The change in the total valuation allowance for the year
ended December 31, 1996 was a decrease of $22,864.
In assessing the realizability of deferred tax assets, management considers
whether it is more likely than not that some portion or all of the deferred tax
assets will not be realized. Accordingly, a valuation allowance was established
at December 31, 1995. No such valuation allowance was established at December
31, 1996. The net deferred tax assets primarily relates to net operating loss
carryforwards which will begin to expire in 2010 if not previously utilized.
13. RESTRICTED INVESTMENTS
The Company carries a $3 million Gulf of Mexico area-wide
abandonment bond with the Minerals Management Service, which is secured by cash
balances currently invested in certificates of deposit at a commercial bank. The
sum on deposit related to this area-wide abandonment bond is approximately $1.4
million at December 31, 1996 and 1995.
14. COMMITMENTS AND CONTINGENCIES
OPERATING LEASES
The Company has a non-cancelable operating lease for its office
space which will expire on September 30, 1998. The Company will be required to
make future payments in connection with the lease agreement as follows for the
years ending:
DECEMBER 31,
1997................ $116,976
1998................ 87,732
-----------
$204,708
===========
Rent expense under operating leases was $130,413, $115,698 and $82,583 in 1996,
1995 and 1994, respectively.
OTHER
The Company is a defendant in a suit filed in 1995 alleging that
the idea, design and location of DIGS was a confidential trade secret owned by
the plaintiffs which had been revealed to the Company during confidential
discussions in furtherance of a proposed joint venture. The plaintiffs allege
"millions of dollars in profits" as actual damages and also seek unspecified
punitive damages, attorneys' fees, pre- and post- judgment interest and costs of
the suit.
<PAGE>
On March 10, 1997, the Company filed a motion for summary
judgment as to all of the plaintiffs' claims. Subsequently, the plaintiffs
amended their petition, dropping their claims of misrepresentation and
conversion of trade secrets and adding a claim of alleged fraudulent inducement
to execute a covenant not to compete. Further, the plaintiffs specified that
they seek $6.5 million in actual damages and punitive damages of five times the
amount of actual damages. The Company denies the plaintiffs' allegations and is
vigorously defending this matter. Oral argument on the Company's motion for
summary judgment will be heard in May 1997 and the trial is set for September
29, 1997. While a decision adverse to the Company in this litigation could have
a material adverse effect on the Company's financial condition and results of
operations, the Company does not believe that the final resolution of this case
will result in a material liability to the Company.
The Company is involved in other various claims and legal actions
arising in the ordinary course of business. In the opinion of management, the
ultimate disposition of these matters will not have a material adverse effect on
the Company's financial position, results of operations or liquidity.
In connection with sales and marketing of natural gas, the
Company entered into a commitment in 1995 to secure firm transportation capacity
on an interstate pipeline. The Company has recorded, in operations and
maintenance expense, estimated amounts related to the cost of not utilizing firm
transportation capacity. Subsequent to December 31, 1996, the Company has
settled all obligations related to the commitment for $400,000, of which the
entire amount is accrued for at December 31, 1996.
During 1996, approximately 100% of the Company's natural gas
sales were to two customers. During 1995, and 1994 approximately 80% of the
Company's natural gas sales were to a single customer. However, due to the
availability of other markets, the Company does not believe that the loss of
this single customer would adversely affect the Company's results of operations.
15. SUPPLEMENTAL OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
RESERVE QUANTITY INFORMATION
Total proved and proved developed oil and gas reserves of the
Company's properties at December 31, 1996 and 1995 have been estimated by an
independent petroleum engineer in accordance with guidelines established by the
Securities and Exchange Commission ("SEC"). Total proved and proved developed
oil and gas reserves at December 31, 1994 have been estimated by the Company in
accordance with guidelines established by the SEC. All reserves are based on
economic and operating conditions existing at the respective year end. The
future net cash flows from the
<PAGE>
production of these proved reserve quantities were computed by applying current
prices of oil and gas, at each period end, (with consideration of price changes
only to the extent provided by contractual and derivative arrangements) to
estimated future production of proved oil and gas reserves less the estimated
future expenditures (based on current costs) to be incurred in developing and
producing the proved reserves. Year-end 1996 caluclations were made using prices
of $3.55 per Mcfe. The Company had immaterial amounts of condensate (oil)
production during the years presented. All of the Company's properties are
located offshore in the Gulf of Mexico in federal and state waters.
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
December 31, December 31,
1995 1996
-----------------------------------
Proved properties $22,234,125 $35,595,670
Unproved properties 3,919,720 1,173,496
-----------------------------------
26,153,845 36,769,166
Accumulated depreciation,
depletion and amortization (6,210,210) (11,233,986)
-----------------------------------
$19,943,635 $25,535,180
===================================
COSTS INCURRED IN OIL AND GAS PROPERTY, ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES
Years Ended December 31,
---------------------------------------
1994 1995 1996
---- ---- ----
Acquisition of properties:
Proved $ 2,173,901 $ 1,850,000 $ 420,831
Unproved 2,422,080 - -
Exploration costs 2,231,349 404,836 2,297,136
Development costs 14,070,818 13,876,703 9,333,052
-------------- --------------- ----------------
$20,898,148 $16,131,539 $12,051,019
============== =============== ================
RESULTS OF OPERATIONS FOR GAS AND OIL PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
1994 1995 1996
---- ---- ----
<S> <C> <C> <C>
Revenues $ 5,512,496 $ 6,168,591 $ 9,835,070
Lifting costs:
Lease operating expense 1,410,231 1,876,186 1,906,281
------------- ------------- -------------
4,102,265 4,292,405 7,928,789
General operating expense (388,097) (423,742) (181,429)
Exploration charges (2,231,349) (404,836) (2,297,136)
Depreciation, depletion and amortization (2,112,350) (5,501,072) (4,897,644)
Abandonment of oil and gas properties (2,735,253) (84,219) (1,300,910)
------------- ------------- -------------
Results of operations from producing activities $(3,364,784) $(2,121,464) $ (748,330)
============= ============= =============
</TABLE>
<PAGE>
RESERVE QUANTITY INFORMATION
Gas
(Mcfe)
Year Ended December 31, 1994:
Proved Developed and Undeveloped Reserves:
Beginning of year 23,932,644
Sales of reserves in place (19,849,128)
Revisions of previous estimates 4,325,581
Production (3,685,681)
-------------
End of year 4,723,416
=============
Year Ended December 31, 1995:
Proved Developed and Undeveloped Reserves:
Beginning of year 4,723,416
Purchases of reserve in place 5,299,000
Revisions of previous estimates 8,734,305
Extensions and discoveries 5,223,000
Production (3,668,721)
-------------
End of year 20,311,000
=============
Year Ended December 31, 1996:
Proved Developed and Undeveloped Reserves:
Beginning of year 20,311,000
Purchases of reserve in place 6,207,000
Revisions of previous estimates 2,084,659
Extensions and discoveries 9,352,000
Production (4,755,914)
-------------
End of year 33,198,745
=============
Proved Developed Reserves:
December 31, 1994 4,723,416
December 31, 1995 14,987,000
December 31, 1996 21,444,174
=============
The reserve volumes presented are estimates only and should not
be construed as being exact quantities. These reserves may or may not be
recovered and may increase or decrease as a result of future operations of the
Company and changes in economic conditions.
<PAGE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
<TABLE>
<CAPTION>
December 31,
--------------------------------------
1994 1995 1996
---- ---- ----
<S> <C> <C> <C>
Future cash inflows $ 6,719,617 $46,478,461 $121,154,647
Future development costs (138,771) (7,173,990) (22,384,474)
Future production costs (1,935,929) (7,589,878) (15,418,769)
--------------- --------------- ----------------
Future net cash inflows
before income taxes 4,644,917 31,714,593 83,351,404
Future income taxes - - (21,321,525)
--------------- --------------- ----------------
Future net cash inflows 4,644,917 31,794,593 62,029,879
10% annual discount (694,423) (5,270,803) (10,864,103)
--------------- --------------- ----------------
Standardized measure of
discounted future net cash inflows $ 3,950,494 $26,443,790 $ 51,165,776
=============== =============== ================
</TABLE>
PRINCIPAL SOURCES OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1994 1995 1996
---- ---- ----
<S> <C> <C> <C>
Standardized measure of discounted future net cash flows
Beginning of year $35,323,954 $ 3,950,494 $26,443,790
Purchases of reserves in place - 3,318,239 7,332,943
Sales of reserves in place (36,329,095) - -
Revisions of previous quantity estimates
less related costs 6,034,804 17,051,312 5,686,006
Extensions and discoveries less related costs - 6,678,479 19,985,027
Net change in income taxes - - (15,724,866)
Net changes in prices and production costs (3,500,358) 3,655,966 17,204,691
Acquisition/development costs incurred during period
and changes in estimated future development costs 5,530,947 (1,329,510) (3,657,026)
Sales of oil and gas produced during period,
net of lifting costs (4,102,265) (4,292,405) (7,928,789)
Accretion of discount 3,532,395 395,049 2,644,379
Other (2,539,888) (2,983,834) (820,379)
-------------- -------------- -------------
Standardized measure of discounted future net cash flows,
end of year $ 3,950,494 $26,443,790 $51,165,776
============== ============== =============
</TABLE>
<PAGE>
16. SUBSEQUENT EVENT
Subsequent to December 31, 1996, OEDC entered into an agreement
to purchase the remaining interest in one of its associated oil and gas
partnerships for approximately $218,000. The oil and gas partnership will now be
wholly owned by the Company.
SUBSIDIARIES OF OFFSHORE ENERGY DEVELOPMENT CORPORATION
OEDC, Inc., a Texas corporation
OEDC Partners, L.P., a Texas limited partnership
OEDC Exploration & Production, L.P., a Texas limited partnership
Beacon Natural Gas Company, L.P., a Texas limited partnership
Dauphin Island Gathering Company, L.P., a Texas limited partnership
OEDC Processing, L.P., a Texas limited partnership
All subsidiaries are wholly owned, directly or indirectly, by Offshore Energy
Development Corporation.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE FINANCIAL DATA SCHEDULE CONTAINS SUMMARY INFORMATION EXTRACTED FROM THE
REGISTRANTS' FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1996, WHICH INCLUDES THE
CONSOLIDATED FINANCIAL STATEMENTS OF THE REGISTRANT, AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 18,407,768
<SECURITIES> 0
<RECEIVABLES> 4,184,702
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 22,637,961
<PP&E> 37,142,112
<DEPRECIATION> 11,439,301
<TOTAL-ASSETS> 50,940,853
<CURRENT-LIABILITIES> 6,983,613
<BONDS> 0
0
0
<COMMON> 87,019
<OTHER-SE> 41,484,091
<TOTAL-LIABILITY-AND-EQUITY> 50,940,853
<SALES> 10,849,275
<TOTAL-REVENUES> 21,563,586
<CGS> 1,972,397
<TOTAL-COSTS> 12,793,308
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 782,708
<INCOME-PRETAX> 7,893,019
<INCOME-TAX> 1,442,844
<INCOME-CONTINUING> 6,450,175
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 3,833,453
<EPS-PRIMARY> .68
<EPS-DILUTED> 0
</TABLE>
