Filed pursuant to Rule 424(b)(1)
Registration No. 333-11269
3,682,000 SHARES
[LOGO]
OFFSHORE ENERGY
DEVELOPMENT CORPORATION
Common Stock
Of the 3,682,000 shares of Common Stock, par value $.01 per share ("Common
Stock"), offered hereby (the "Offering"), 3,500,000 shares are being sold by
Offshore Energy Development Corporation, a Delaware corporation (the "Company"
or "OEDC"), and 182,000 shares are being sold by certain of the selling
stockholders named herein (the "Selling Stockholders"). Prior to this
Offering, there has been no public market for the Common Stock. See
"Underwriting" for information relating to the factors to be considered in
determining the initial public offering price. The Company will not receive any
of the proceeds from the shares to be sold by the Selling Stockholders. See
"Principal and Selling Stockholders."
The Common Stock has been approved for listing on the NASDAQ National
Market under the symbol "OEDC."
SEE "RISK FACTORS" BEGINNING ON PAGE 9 FOR A DISCUSSION OF CERTAIN
FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN THE COMMON
STOCK OFFERED HEREBY.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS
PROSPECTUS. ANY REPRESENTATION TO THE
CONTRARY IS A CRIMINAL OFFENSE.
<TABLE>
<CAPTION>
==================================================================================================================
PROCEEDS
PRICE TO UNDERWRITING PROCEEDS TO TO SELLING
PUBLIC DISCOUNT(1) COMPANY(2) STOCKHOLDERS
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Per Share........................... $12.00 $.84 $11.16 $11.16
- ------------------------------------------------------------------------------------------------------------------
Total(3)............................ $44,184,000 $3,092,880 $39,060,000 $2,031,120
==================================================================================================================
</TABLE>
(1) The Company and the Selling Stockholders have agreed to indemnify the
several Underwriters against certain liabilities, including liabilities
under the Securities Act of 1933, as amended. See "Underwriting."
(2) Before deducting expenses payable by the Company estimated at $593,000.
(3) The Company and certain of the Selling Stockholders have granted to the
several Underwriters an option for 30 days to purchase up to an additional
552,300 shares of Common Stock at the Price to Public, less Underwriting
Discount, solely to cover overallotments, if any. If such option is
exercised in full, the Price to Public, Underwriting Discount, Proceeds to
Company and Proceeds to Selling Stockholders will be $50,811,600,
$3,556,812, $40,734,000, and $6,520,788, respectively. See "Underwriting"
and "Principal and Selling Stockholders."
------------------------
The shares of Common Stock are offered by the several Underwriters, subject
to prior sale, when, as and if issued to and accepted by them, and subject to
certain other conditions. The Underwriters reserve the right to withdraw, cancel
or modify such offer and to reject orders in whole or in part. It is expected
that delivery of the shares of Common Stock will be made on or about November 6,
1996.
------------------------
MORGAN KEEGAN & COMPANY, INC. PRINCIPAL FINANCIAL SECURITIES, INC.
The date of this Prospectus is November 1, 1996
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
Map of the DIGS.
Map of Gulf of Mexico properties, including the following table:
PROJECT INVENTORY
WELL
RECOMPLETIONS/ SCHEDULED
AREA CONNECTIONS DRILL SITES
- ------------------------------------- --------------- ------------
Mobile............................... 2 0
Pensacola............................ 1 0
Destin Dome.......................... 2 0
Viosca Knoll......................... 5 5
South Timbalier...................... 2* 0
N. Padre Island...................... 0 2
-- --
12 7
- ------------
* One commenced production 9/96.
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK OF
THE COMPANY AT LEVELS ABOVE THOSE WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH TRANSACTIONS MAY BE EFFECTED IN THE NASDAQ NATIONAL MARKET, IN THE
OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE
DISCONTINUED AT ANY TIME.
<PAGE>
PROSPECTUS SUMMARY
THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO THE MORE
DETAILED INFORMATION AND FINANCIAL STATEMENTS (INCLUDING THE NOTES THERETO)
APPEARING ELSEWHERE IN THIS PROSPECTUS. UNLESS OTHERWISE INDICATED HEREIN, THE
INFORMATION CONTAINED IN THIS PROSPECTUS (I) GIVES EFFECT TO THE COMBINATION
(THE "COMBINATION") OF CERTAIN OPERATIONS DESCRIBED UNDER "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -- OVERVIEW" AND (II) ASSUMES THAT THE UNDERWRITERS' OVER-ALLOTMENT
OPTION IS NOT EXERCISED. UNLESS THE CONTEXT OTHERWISE REQUIRES, REFERENCES
HEREIN TO THE "COMPANY" OR "OEDC" SHALL MEAN OFFSHORE ENERGY DEVELOPMENT
CORPORATION AND THE CORPORATIONS AND PARTNERSHIPS CONSOLIDATED THEREIN, AND
THEIR RESPECTIVE PREDECESSORS, ON A CONSOLIDATED BASIS. CERTAIN TERMS USED
HEREIN RELATING TO THE OIL AND GAS INDUSTRY ARE DEFINED IN THE "GLOSSARY OF
CERTAIN OIL AND GAS TERMS" INCLUDED ELSEWHERE IN THIS PROSPECTUS.
THE COMPANY
Offshore Energy Development Corporation is an independent energy company
that focuses on the acquisition, exploration, development and production of
natural gas and on natural gas gathering and marketing activities. The Company's
integrated operations are conducted in the Gulf of Mexico, primarily offshore
Alabama and Louisiana. The Company has established strategic alliances with
several major energy companies to conduct exploration and development activities
and to construct and operate a natural gas gathering system and a natural gas
processing plant. Management believes these relationships and its experience in
its core area of operations provide the Company with unique growth
opportunities.
EXPLORATION AND DEVELOPMENT
The Company has interests in 21 lease blocks, all of which are operated by
the Company. On 14 of these blocks, the Company plans to connect eight existing
wells to production platforms and to drill five exploratory prospects and three
proved undeveloped locations by the end of 1997. The Company's estimated capital
expenditure budget for these activities from November 1, 1996 through December
31, 1997 is $34 million. The Company plans to finance a majority of these
expenditures from the proceeds of this Offering, with the balance to be financed
from cash flow from operations and, to the extent necessary, borrowings under
the Company's existing line of credit. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Capital
Expenditures and Future Outlook."
From January 1 through October 7, 1996, the Company drilled and completed
four exploratory wells offshore Alabama and offshore Louisiana. The Company has
drilled a fifth exploratory well offshore Alabama that was logged in October.
The one well drilled offshore Louisiana is currently producing and the Company
anticipates that construction of necessary production facilities offshore
Alabama and connection of the Alabama wells to such facilities will be completed
by the end of the first quarter of 1997.
In October 1996, the Company acquired a majority interest in North Padre
Island Block A-59 in federal waters offshore Texas. As part of the acquisition,
the Company acquired a platform with two wells, a satellite well and a flowline
to an interstate pipeline. Prior to the end of 1996, the Company intends to
drill two new platform wells with dual completions in shallow Miocene sands
under this property. See "Business and Properties -- Exploration and
Development."
As of January 1, 1996, the Company had net proved natural gas reserves, as
estimated by Ryder Scott Company ("Ryder Scott"), of 20.3 Bcfe attributable to
11 gross (7.30 net) wells offshore Alabama and Louisiana. From January 1 through
October 7, 1996, the Company drilled and completed four exploratory wells,
completed the purchase of an interest in North Padre Island Block A-59 and shot
a proprietary seismic survey over its one block offshore Mississippi. Based on a
reserve report prepared by Ryder Scott dated October 7, 1996, these activities
have added 14.87 Bcf of estimated net proved reserves attributable to the
Company's interests after giving effect to the increase in the Company's
interest in the four wells that will occur through the application of the net
proceeds of this Offering. See "Use of Proceeds." Although no assurance may be
given, the Company's experience under similar circumstances has been that
additional reserves will be attributed to its interests in all such properties
once production history has been established.
3
<PAGE>
In October 1996, the Company entered into a joint venture agreement with a
subsidiary of Amoco Corporation ("Amoco") pursuant to which the Company will
evaluate proprietary 3-D seismic data to identify prospects for joint
exploration and development by the parties on approximately 59,000 contiguous
acres covering portions of 23 lease blocks in the Gulf of Mexico. Of this total,
approximately 14,000 acres are currently leased by the Company or Amoco. Costs
of drilling and development on existing leases would 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 will be the operator of any
prospects drilled under this agreement. Unless renewed by mutual consent, the
agreement terminates on October 1, 1997. See "Business and
Properties -- Exploration and Development."
NATURAL GAS GATHERING
The Company operates the Dauphin Island Gathering System ("DIGS") as a
95-mile non-jurisdictional pipeline system offshore Alabama with a current
capacity of 400 MMcf/d. The DIGS, which the Company began developing in 1990, is
the primary open-access gas gathering system in federal waters serving the
Mobile, Viosca Knoll and Destin Dome areas of the Gulf of Mexico. In early 1996,
the Company sold its 24% limited partnership interest in Dauphin Island
Gathering Partners ("DIGP"), the partnership that owns the DIGS, for $19.1
million, and retained a one percent general partnership interest. The Company
realized a pre-tax profit of $10.8 million on the sale. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
The current partners in DIGP are the Company and subsidiaries of MCN
Corporation ("MCN") and PanEnergy Corp ("PanEnergy"). The Company's one
percent interest in DIGP will increase to 15% (subject to reduction in certain
circumstances) when each of MCN and PanEnergy receives the return of its
investment plus a 10% rate of return, subject to certain other conditions
(collectively, "DIGP Payout"). See "Business and Properties -- Natural Gas
Gathering -- Current Operations." The Company and its DIGS partners recently
announced a planned 65-mile extension of the DIGS to gather new production that
currently lacks adequate transportation outlets. An additional planned 1997
expansion of the DIGS would create separate dry gas and wet gas gathering
systems with a combined capacity of approximately 900 MMcf/d. In September 1996,
DIGP signed a nonbinding letter of intent with Main Pass Gathering Company
("MPGC") to combine MPGC's Main Pass Gathering System ("MPGS") with the
DIGS. See "Business and Properties -- Natural Gas Gathering," "Business and
Properties -- Natural Gas Processing" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Capital
Expenditures and Future Outlook."
NATURAL GAS PROCESSING
In August 1996, the Company entered into an agreement to form a partnership
with MCN and PanEnergy for the construction and development of a natural gas
liquids ("NGL") plant onshore Alabama. This plant will be constructed in
stages and when completed is expected to have a capacity of 900 MMcf/d. The
plant would be the first NGL plant in Alabama available for processing existing
Mobile area production and would be available to process additional volumes from
the Main Pass and Viosca Knoll areas of the Gulf of Mexico. The total cost of
this plant is estimated by the Company to be $90 million. The Company will
initially have a one percent cost and revenue interest in the partnership. In
addition, the Company will acquire from MCN and PanEnergy for $200,000 an option
to purchase up to an additional 32 1/3% interest in the partnership during the
first three years of plant operations for 32 1/3% of the depreciated book value
of the plant, increased by 12% each year. See "Business and
Properties -- Natural Gas Processing."
4
<PAGE>
BUSINESS STRATEGY
The Company's objective is to enhance stockholder value through sustained
growth in revenue, earnings and operating cash flow from increases in natural
gas and oil reserves and production and development of related downstream
projects. The Company intends to achieve its objective by pursuing the following
key strategies:
o CAPITALIZE ON INTEGRATED NATURAL GAS OPERATIONS. OEDC has operations in
all phases of the production, gathering, and marketing of natural gas. OEDC
believes this integrated approach has provided the Company access to
information not otherwise widely available regarding regional reserve
development; flexibility in achieving favorable volumes and prices on gas
sales; the opportunity to initiate downstream projects on terms attractive
to the Company; and diversification of revenue streams.
o DEVELOP AND EXPAND PROSPECT INVENTORY. The Company believes that its
reserve growth will come primarily from drilling activity rather than
through acquisitions of producing reserves. The Company has accumulated
approximately 21,000 gross (19,000 net) producing acres with additional
exploitation potential. Additionally, the Company has approximately 92,000
gross undeveloped acres which, after giving effect to the increase in the
Company's interest in four wells that will occur through the application of
the net proceeds of this Offering, will represent approximately 66,000 net
undeveloped acres. See "Use of Proceeds." Joint ventures, other strategic
alliances and acquisitions of acreage with development potential are being
pursued in order to generate additional post-1997 drilling inventory.
o DEVELOP STRATEGIC ALLIANCES. The Company intends to continue to form
strategic alliances with substantial energy companies, which have
historically given the Company access to the financial strength, property
inventories, marketing presence and other resources of such companies. The
Company has traditionally managed projects with strategic partners from
conceptualization through planning, implementation and operation. The
Company has successfully managed joint developments with affiliates of
major energy companies, such as Amoco, British Petroleum, Enron Corp.,
Tenneco, Inc., MCN, Mobil Corporation and PanEnergy.
o ACTIVELY MANAGE DRILLING RISK. The Company primarily targets geophysically
defined natural gas prospects with associated hydrocarbon indicators. The
Company uses computer aided exploration analysis and proprietary 3-D and
high resolution 2-D seismic data to better determine the likelihood of
encountering hydrocarbons and more closely estimate the extent of
reservoirs. During the drilling of wells, the Company interactively
correlates geophysical data on seismic workstations with real-time
well-logging techniques, such as measurement-while-drilling and magnetic
resonance imaging, to improve its accuracy in defining and evaluating oil
and gas reservoirs. As a result of this approach, the Company has completed
24 of the 25 wells it has drilled since 1988.
o PURSUE OPERATING EFFICIENCIES. The Company generally initiates and manages
projects and prefers to maintain majority ownership in order to improve
project returns. The Company has reduced the time between capital
expenditure and revenue generation by the use of refurbished platforms and
equipment, and off-the-shelf designs and components and by simultaneously
conducting exploration and construction. The Company has also reduced
development costs by the cluster development of neighboring properties and
the use of slim hole and splitter technology. The Company is committed to
maintaining low operating overhead by outsourcing many technical and field
functions, rather than developing in-house capabilities.
o MAINTAIN GEOGRAPHIC FOCUS. The Company has focused its exploration and
development efforts in relatively concentrated areas of the Gulf of Mexico.
This geographic focus has enabled the Company to build and utilize a base
of geological, geophysical, engineering and production experience in its
focus areas. The Company believes this discipline enhances its ability to
identify, evaluate and prioritize drilling prospects and other ancillary
business opportunities in its areas of operation.
5
<PAGE>
RISK FACTORS
An investment in the Company involves a high degree of risk. In particular,
prospective investors should be aware of the effect on the Company of the risks
presented by (i) the volatility of natural gas and oil prices, (ii) the
Company's ability to replace its reserves, (iii) the costs and uncertainties
relating to oil and gas exploration and development, (iv) the Company's
historical operating losses and the absence of assurance of future
profitability, (v) the Company's historical working capital deficits and the
lack of assurance that such deficits will not recur or that, if they do recur,
the Company will be able to fund such deficits, (vi) the substantial capital
requirements associated with the Company's business strategy and the possibility
that the Company will not be able to finance such requirements, and (vii) the
Company's dependence on its key personnel. See "Risk Factors."
THE OFFERING
Common Stock to be sold:
By the Company.................. 3,500,000 shares(1)
By certain Selling
Stockholders.................. 182,000 shares(2)
Common Stock to be outstanding after
the Offering....................... 8,551,885 shares(1)(3)
Use of Proceeds...................... Of the net proceeds to the Company from
this Offering, $14 million will be used
to finance a five-well drilling and
development program; $12 million will be
used to redeem preference units in a
subsidiary; and the balance will be used
for working capital and other general
corporate purposes. See "Use of
Proceeds."
NASDAQ National Market Symbol........ OEDC
- ------------
(1) Does not include up to 150,000 shares that may be sold by the Company
pursuant to the Underwriters' overallotment option.
(2) Does not include up to 402,300 shares that may be sold by certain of the
Selling Stockholders pursuant to the Underwriters' overallotment option.
(3) Does not include 727,580 shares subject to employee stock options, of which
99,268 are presently exercisable.
------------------------
The principal executive offices of the Company are located at 1400 Woodloch
Forest Drive, Suite 200, The Woodlands, Texas 77380, and its telephone number is
(713) 364-0033.
6
<PAGE>
SUMMARY CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS)
The following table sets forth certain consolidated historical financial
data for the Company as of and for each of the periods indicated. The financial
data for each year in the three-year period ended December 31, 1995, and the
financial data for the six months ended June 30, 1996, are derived from the
audited financial statements of the Company. The financial data for the six
months ended June 30, 1995 are derived from the Company's unaudited financial
statements. The following data should be read in conjunction with "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
financial statements included elsewhere in this Prospectus. The results for the
six months ended June 30, 1996 are not necessarily indicative of results for the
full year.
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE
YEAR ENDED DECEMBER 31, 30,
------------------------------- -----------------------
1993 1994 1995 1995 1996
--------- --------- --------- ----------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Income:
Exploration and production......... $ 1,744 $ 5,513 $ 6,169 $ 1,859 $ 5,549
Pipeline operating and marketing... 358 358 167 93 494
Equity in earnings (loss) of equity
in investments................... (255) (3) 497 315 23
Gain on sales of oil and gas
properties or partnership
investments, net................. -- 13,655 -- -- 10,661
--------- --------- --------- ----------- ---------
Total income................ 1,847 19,523 6,833 2,267 16,727
--------- --------- --------- ----------- ---------
Expense:
Operations and maintenance......... 570 1,410 2,210 1,064 1,025
Exploration charges................ 32 2,231 405 153 421
Depreciation, depletion and
amortization..................... 355 2,112 5,501 1,598 2,876
Abandonment expense................ 59 2,735 84 13 216
General and administrative......... 1,725 2,359 2,192 1,155 1,155
--------- --------- --------- ----------- ---------
Total expense............... 2,741 10,847 10,392 3,983 5,693
--------- --------- --------- ----------- ---------
Earnings (loss) before interest and
taxes.............................. (894) 8,676 (3,559) (1,716) 11,034
========= ========= ========= =========== =========
Net Income (Loss).................... (1,348) 6,944 (5,066) (2,174) 10,334
========= ========= ========= =========== =========
Income (loss) available to common
unitholders and stockholders....... $ (2,079) $ 6,359 $ (6,209) $ (2,466) $ 9,440
========= ========= ========= =========== =========
Pro forma net income (loss)(2)(3).... $ (4,334) $ 5,617
========= =========
Pro forma net income (loss) per
common share(2)(3)................. $ (0.86) $ 1.11
========= =========
EBITDA(1)............................ $ (539) $ 10,788 $ 1,942 $ (118) $ 13,910
</TABLE>
<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
-----------------------------------------------------
HISTORICAL PRO FORMA PRO FORMA
BALANCE SHEET DATA: CONSOLIDATED FOR COMBINATION(2) AS ADJUSTED(4)
------------ ------------------ ---------------
<S> <C> <C> <C>
Working capital (deficit)............ $ (1,012) $ (1,012) $11,455
Total assets......................... $ 24,551 $ 24,551 $51,018
Long-term debt, excluding current
maturities......................... $ -- $-- $--
Redeemable preference units.......... $ 10,648 $ 10,648 $--
Combined equity...................... $ 7,323 $ 5,386(3) $42,501
</TABLE>
- ------------
(1) EBITDA is defined as income before income taxes, interest, preference unit
payments, depreciation, depletion, and amortization. EBITDA is a financial
measure commonly used for the Company's industry and should not be
considered in isolation or as a substitute for net income, cash flow
provided by operating activities or other income or cash flow data prepared
in accordance with generally accepted accounting principles or as a measure
of a company's profitability or liquidity. Because EBITDA excludes some, but
not all, items that affect net income and may vary among companies, the
EBITDA presented above may not be comparable to similarly titled measures of
other companies.
(2) Gives effect to the Combination as if it had occurred on June 30, 1996. See
Note 1 of Notes to Consolidated Financial Statements.
(3) Prior to the Combination, the Company's operating partnerships were exempt
from United States federal income taxes. The pro forma data reflects a net
deferred tax liability of $1,937,000 for the federal income tax expense that
would have been recorded in prior years had such entities not been exempt
from paying such income taxes.
(4) Sets forth the pro forma for Combination balance sheet data of the Company,
as adjusted to give effect to the sale of 3,500,000 shares of Common Stock
in the Offering and the application of the net proceeds therefrom as
described in "Use of Proceeds."
7
<PAGE>
SUMMARY CONSOLIDATED OPERATING DATA
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
----------------------------------- ------------------------
1993 1994 1995 1995 1996
--------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
PRODUCTION DATA (NET):
Natural gas equivalent (Mcfe)(1)... 672,838 3,685,681 3,667,701 1,021,641 2,528,002
AVERAGE SALES PRICE:
Natural gas (per Mcfe)(2).......... $2.59 $1.50 $1.68 $1.82 $2.20
EXPENSE (PER MCFE):
Lease operating.................... $0.85 $0.38 $0.51 $0.90 $0.35
Depreciation, depletion and
amortization.................... $0.53 $0.57 $1.50 $1.56 $1.14
General and administrative,
net(3).......................... $1.77 $0.49 $0.45 $0.87 $0.35
</TABLE>
- ------------
(1) The Company had immaterial amounts of condensate (oil) production during
such years.
(2) Prices include the effects of hedging transactions. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Hedging Activities."
(3) Excludes general and administrative expenses attributed by the Company to
its pipeline operations.
SUMMARY CONSOLIDATED RESERVE DATA
The following table summarizes the estimates of the Company's net proved
natural gas reserves as of December 31, 1995 and the present value attributable
to those reserves at such date. Such information has been derived from a reserve
report prepared by Ryder Scott. All calculations of estimated reserves have been
made in accordance with the rules and regulations of the Securities and Exchange
Commission, and, except as otherwise indicated, give no effect to federal or
state income taxes otherwise attributable to estimated future cash flow from the
sale of oil and gas. The present value of estimated future net revenue has been
calculated using a discount factor of 10%. See "Risk Factors -- Uncertainty of
Estimates of Reserves and Future Net Revenue" and "Business and
Properties -- Exploration and Development -- Natural Gas Reserves" and
"Experts."
AS OF DECEMBER 31, 1995
-----------------------
(DOLLARS IN THOUSANDS)
Natural gas (MMcfe).................. 20,311
Estimated Future Net Revenue
(Before Income Taxes).............. $31,715
Present Value of Estimated Future Net
Revenue
(Before Income Taxes; Discounted at
10%)............................... $26,444
From January 1 through October 7, the Company drilled and completed four
exploratory wells, completed the purchase of a majority interest in North Padre
Island Block A-59 and shot a proprietary seismic survey over its one block
offshore Mississippi. Based on a reserve report prepared by Ryder Scott dated
October 7, 1996, these activities have added 14.87 Bcf of estimated net proved
reserves attributable to the Company's interests after giving effect to the
increase in the Company's interest in the four wells that will occur through the
application of the net proceeds of this Offering. See "Use of Proceeds."
Although no assurance may be given, the Company's experience under similar
circumstances has been that additional reserves will be attributed to its
interests in all such properties once production history has been established.
8
<PAGE>
RISK FACTORS
AN INVESTMENT IN THE COMPANY INVOLVES A HIGH DEGREE OF RISK. PROSPECTIVE
PURCHASERS SHOULD GIVE CAREFUL CONSIDERATION TO THE SPECIFIC FACTORS SET FORTH
BELOW, AS WELL AS THE OTHER INFORMATION SET FORTH IN THIS PROSPECTUS, BEFORE
PURCHASING THE COMMON STOCK OFFERED HEREBY.
VOLATILITY OF NATURAL GAS AND OIL PRICES
Income generated from the Company's operations is highly dependent upon the
price of, and demand for, natural gas and oil. The markets for natural gas and
oil historically have been volatile and are likely to continue to be volatile in
the future. Prices for natural gas and oil are subject to wide fluctuation in
response to relatively minor changes in the supply of and demand for natural gas
and oil, market uncertainty and a variety of additional factors that are beyond
the control of the Company. These factors include the level of consumer product
demand, weather conditions, domestic and foreign governmental regulations, the
price and availability of alternative fuels, political conditions in the Middle
East, the foreign supply of natural gas and oil, the price of foreign imports
and overall economic conditions. In addition, sales of and demand for natural
gas and oil have historically been seasonal in nature, which may lead to
substantial differences in cash flow at various times throughout the year. It is
impossible to predict future natural gas and oil price movements with any
certainty. Declines in natural gas and oil prices may materially adversely
affect the Company's financial condition, liquidity and results of operations.
Lower natural gas and oil prices also may reduce the amount of the Company's
natural gas and oil that can be produced economically. In order to reduce its
exposure to price risks in the sale of its natural gas and oil, the Company
enters into hedging arrangements from time to time. The Company's hedging
arrangements apply to only a portion of its production and provide only limited
price protection against fluctuations in the natural gas and oil markets. See
" -- Effects of Price Risk Hedging" and "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Hedging Activities."
REPLACEMENT OF RESERVES
The Company's future success depends upon its ability to find, develop or
acquire additional reserves of natural gas and oil that are economically
recoverable. The estimated proved reserves of the Company generally will decline
as reserves are depleted, except to the extent that the Company conducts
successful exploration or development activities or acquires properties
containing proved reserves, or both. The rate of decline depends on reservoir
characteristics. The Gulf of Mexico, where the Company currently has all of its
proved reserves, is characterized by relatively steep decline rates. The Company
may in the future drill wells in other offshore or onshore locations with
similar production decline characteristics. In order to increase reserves and
production, the Company must continue drilling programs or undertake other
replacement activities. The Company's current strategy includes increasing its
reserve base through the exploitation of its existing properties; exploration
and development of its undeveloped acreage position in the Gulf of Mexico;
acquisition and development of other undeveloped acreage in the Gulf of Mexico;
and identification of new drilling prospects through joint ventures with larger
producers. There can be no assurance, however, that the Company's strategy will
result in significant additional reserves or that the Company will have
continuing success drilling productive wells at its historical finding and
development costs. See "Business and Properties -- Exploration and
Development -- Natural Gas Reserves."
UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUE
There are numerous uncertainties inherent in estimating natural gas and oil
reserves and their values, including many factors beyond the control of the
Company. The reserve and future net revenue data set forth in this Prospectus
represent only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact manner. Estimates of economically recoverable gas and oil
reserves and of future net revenue necessarily depend upon a number of variable
factors and assumptions, such as historical production from the area compared
with production from other producing areas, and assumptions concerning the
effects of regulation by governmental agencies, future oil and gas prices,
future operating costs, severance and excise taxes, development costs and
9
<PAGE>
workover and remedial costs, all of which may vary considerably from actual
results. For these reasons, estimates of the economically recoverable quantities
of natural gas and oil attributable to any particular group of properties,
classifications of such reserves based on risk of recovery, and estimates of the
future net revenue expected therefrom prepared by different engineers or by the
same engineers at different times may vary substantially, and such reserve
estimates may be subject to downward or upward adjustment based upon such
factors. Actual production, revenue and expenditures with respect to the
Company's reserves will likely vary from estimates, and such variances may be
material. See "Business and Properties -- Exploration and
Development -- Natural Gas Reserves."
Approximately 26% of the Company's estimated proved reserves at January 1,
1996 were undeveloped, which are by their nature less certain. Recovery of such
reserves will require significant capital expenditures. The reserve data
included in this Prospectus assumes that substantial capital expenditures by the
Company will be required to develop such reserves. No assurance may be given
that the estimated costs are accurate, that development will occur as scheduled,
that the Company will have the capital resources necessary to make the
expenditures assumed, or that the results will be as estimated. See "Business
and Properties -- Exploration and Development -- Natural Gas Reserves."
The present value of estimated future net revenue referred to in this
Prospectus should not be construed as the current market value of the estimated
natural gas and oil reserves attributable to the Company's properties. In
accordance with applicable requirements of the Securities and Exchange
Commission ("Commission"), the estimated discounted future net revenue from
proved reserves is generally based on prices and costs as of the date of the
estimate, whereas actual future prices and costs may be materially higher or
lower. Actual future net revenue also will be affected by factors such as the
amount and timing of actual production, supply of and demand for natural gas and
oil, curtailments or increases in consumption by gas purchasers and changes in
governmental regulations or taxation. The timing of actual future net revenue
from proved reserves, and the actual present value thereof, will be affected by
the timing of both the production and the incurrence of expenses in connection
with development and production of natural gas and oil properties. In addition,
the calculation of the estimated present value of the future net revenue using a
10% discount rate as required by the Commission is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company's reserves or the natural gas and oil
industry in general.
EXPLORATION AND DEVELOPMENT RISKS
Exploration and development of natural gas and oil involve a high degree of
risk that no commercial production will be obtained or that the production will
be insufficient to recover drilling and completion costs. The cost of drilling,
completing and operating wells is often uncertain, and cost overruns in offshore
operations can adversely affect the economics of a project. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, including title problems, weather conditions, compliance with
governmental requirements and shortages or delays in the delivery of equipment.
Furthermore, completion of a well does not ensure a profit on the investment or
a recovery of drilling, completion and operating costs.
HISTORICAL OPERATING LOSSES
The Company has sustained losses in two of the past three years as a result
of its decision to finance its operations in part through the sale of
properties. Due to limited capital resources, the Company historically has grown
by acting as a developer of projects that it subsequently sold at a profit. This
resulted in significant variances in year to year income, with the Company
sustaining losses during years in which it incurred the expenses of project
development and achieving net income during years when the projects were sold.
No assurance may be given that the Company will be profitable in the future. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Company's consolidated financial statements and the related
notes thereto included elsewhere herein.
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WORKING CAPITAL DEFICITS
The Company had working capital deficits of $1,011,953 and $12,834,262 at
June 30, 1996 and December 31, 1995, respectively. These deficits are the result
of the Company's decision to finance its acquisitions of capital assets and
property development in part through short-term, project-specific borrowings and
vendor financings. The Company may incur working capital deficits in the future,
and no assurance may be given that the Company will be able to obtain the
financing necessary to fund any such deficits. See " -- Substantial Capital
Requirements" and "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Liquidity and Capital Resources."
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company makes, and will continue to make, substantial capital
expenditures for the acquisition, exploration, development, and production of
oil and natural gas reserves and related downstream projects. Historically, the
Company has financed these expenditures through vendor financings, short term
borrowings from commercial banks and other industry lenders and project
financing in separate partnerships with equity investors, as well as cash
generated from operations, including the sale of projects. The Company believes
that the net proceeds of this Offering, bank borrowings and funds generated from
operations will be sufficient to fund its growth strategy through 1997. If the
Company experiences operating difficulties or if oil and gas prices decline and
reduce income, however, the Company may be required to obtain additional
financing to fund its operations. No assurance may be given that such financing
will be available, and if it is not available, the Company may be required to
curtail its drilling and other projects.
The Company has entered into an agreement to form a partnership to
construct, own and operate an onshore NGL plant. The Company will have the
option to increase its interest in the partnership. The exercise of its option
to increase its interest in such partnership will require substantial capital in
addition to the amounts being raised in this Offering. No assurance may be given
that the financing necessary to exercise the Company's option will be available
or, if available, will be on terms that are acceptable to the Company. See
"Business and Properties -- Natural Gas Processing."
DEPENDENCE UPON KEY PERSONNEL
The success of the Company has been and will continue to be highly
dependent on David B. Strassner, Douglas H. Kiesewetter, R. Keith Anderson and
certain other senior management personnel. The partnership agreements relating
to the DIGS and to the Company's drilling programs with affiliates of Enron
Corp. ("Enron") contain change of control provisions that would be triggered
by the failure of any two of Messrs. Strassner, Anderson or Kiesewetter to be
actively involved in the management and operations of such entities. In the case
of DIGP, the occurrence of such an event prior to the earlier of DIGP Payout or
February 28, 2001 would prevent the Company's interest in the partnership from
increasing above its current one percent level. See "Business and
Properties -- Natural Gas Gathering -- Current Operations." In the case of the
Enron partnerships, the occurrence of such an event would give Enron the right
to fix a price at which the Company would be required to either purchase all of
Enron's interest in the partnerships or sell all the Company's interest in the
partnerships to Enron. In addition, the Company's loan agreement with Union Bank
of California, N.A. ("Union Bank") provides that it is an event of default
under such loan agreement if any two of Messrs. Strassner, Anderson, Kiesewetter
or Matthew T. Bradshaw cease to be actively involved in the management and
operation of the Company for any reason other than his death or disability.
Accordingly, loss of the services of any of the foregoing individuals could have
a material adverse effect on the Company's operations. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Financing Activities." Each of
Messrs. Strassner, Kiesewetter and Anderson has agreed with the Company that,
prior to the earlier of DIGP Payout or February 28, 2001, he will not
voluntarily (i) cease to be actively involved as the management of and in the
operation of DIGP to substantially the same degree as he was involved in such
management and operation on July 1, 1996, or (ii) reduce his respective
ownership interest in the Company following the Company's initial public
offering by 75% or more. Each of Messrs. Strassner, Anderson and Kiesewetter is
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also subject to an agreement limiting his ability to compete with the Company
for a one year period after they cease to be employed by the Company. See
"Management -- Certain Transactions."
AVAILABILITY OF EQUIPMENT AND PERSONNEL
The recent increase in drilling activity in the Gulf of Mexico has
increased the demand for drilling vessels, supply boats and personnel
experienced in offshore operations. The Company has recently experienced
difficulty in obtaining certain services from vendors. No assurance may be given
that such services, equipment and personnel will be available in a timely
manner, or that the cost thereof will not increase. See "Business and
Properties -- Exploration and Development -- Operating Procedures and Risks."
FERC REGULATION RISKS
The transportation and sale for resale of natural gas in interstate
commerce are regulated by the Federal Energy Regulatory Commission ("FERC")
pursuant to the Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act
of 1978 ("NGPA"). 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 net revenue received by it
for sales of natural gas. The DIGS is subject to regulation of its gathering
operations under the Outer Continental Shelf Lands Act ("OCSLA"), which
requires the DIGS to provide gas producers on the Outer Continental Shelf
("OCS") with open and non-discriminatory access to its gathering system and to
charge non-discriminatory rates.
The Company, as the managing partner in DIGP, operates the DIGS as a gas
gatherer exempt from FERC's jurisdiction under the NGA. In February 1996, FERC
issued a Statement of Policy concerning gas gathering on the OCS in which FERC
reaffirmed that its "modified primary function" test was the appropriate test
to use in determining whether a gas pipeline operating on the OCS is subject to
its NGA jurisdiction as an interstate transporter or exempt from such
jurisdiction as a gatherer. The Company believes that the DIGS, as it currently
exists and after giving effect to its planned extension and expansion, and the
potential combination with MPGC discussed under "Business and
Properties -- Natural Gas Gathering -- Proposed Combination with Main Pass
Gathering Company," meets the criteria of the modified primary function test
and is exempt from FERC jurisdiction under the NGA. However, DIGP has not sought
a formal declaration from FERC confirming its status as an exempt gatherer. The
Company expects DIGP to seek such an order in the near future. However, no
assurance may be given that the FERC will concur with the Company's view.
A determination that the DIGS is subject to FERC's NGA jurisdiction would
require that DIGP comply with the FERC's regulations applicable to interstate
transporters of natural gas, including rate regulation, accounting and reporting
requirements. Moreover, in the event jurisdictional status was determined,
future facilities expansions or significant facilities alterations would require
prior FERC approval, which may be denied or granted subject to condition. While
market-based rates are possible under the FERC regulations, FERC frequently
imposes cost-of-service rates. The imposition of cost-of-service rates by FERC
would be likely to reduce DIGP revenue. In addition, FERC's regulations would
impose administrative costs on DIGP. These costs, however, would be recoverable
in rates and thus should not materially adversely affect the profitability of
DIGP. See "Business and Properties -- Government Regulation -- Natural Gas
Marketing, Gathering and Transportation."
As a one percent owner of DIGP, the impact of FERC cost of service rate
regulation under the NGA would not be material to the Company. Such regulation,
however, could delay the Company's receipt of the additional interest in DIGP
which it will earn if and when DIGP Payout occurs. Furthermore, any revenue
reduction would diminish the value of the Company's interest in DIGP.
LITIGATION RISKS
The Company is a defendant in a suit filed in 1995 alleging that the idea,
design and location of the DIGS as an intrastate gas gatherer regulated by the
FERC under Section 311 of the NGPA was a confidential trade secret owned by the
plaintiffs, which had been revealed to the Company during
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confidential discussions in furtherance of a proposed joint venture. The
plaintiffs also allege, among other things, misrepresentations by the Company
regarding its intention to form a joint venture, breach of an oral agreement to
form a joint venture and breach of fiduciary duties. The plaintiffs are seeking
"millions of dollars in profits" as actual damages and are also seeking the
award of an unspecified amount of punitive damages. The Company has denied the
plaintiffs' allegations, raised various affirmative defenses, and is vigorously
defending this litigation. Discovery is currently ongoing and a trial date has
not been set. An adverse decision in this litigation could have a material
adverse effect on the Company. See "Business and Properties -- Litigation."
OPERATING HAZARDS AND UNINSURED RISKS
The Company's operations are subject to risks inherent in the oil and gas
industry and the gas pipeline industry, such as blowouts, cratering, explosions,
uncontrollable flows of crude oil, natural gas or well fluids, fires, pollution
and other environmental risks. These risks could result in substantial losses to
the Company due to injury and loss of life, severe damage to and destruction of
property and equipment, pollution and other environmental damage and suspension
of operations. Moreover, offshore operations are subject to a variety of
operating risks peculiar to the marine environment, such as hurricanes and other
adverse weather conditions, to more extensive governmental regulation, including
regulations that may, in certain circumstances, impose strict liability for
pollution damage, and to interruption or termination of operations by
governmental authorities based on environmental or other considerations. See
"Business and Properties -- Governmental Regulation." The Company utilizes
general and limited partnerships with others in conducting its oil and gas and
pipeline operations. As the general partner of these entities, the Company is
responsible for all of the liabilities of such entities, even though it owns
less than all of the equity interests therein.
The Company maintains insurance of various types to cover its operations,
including general liability insurance, general partner liability insurance, and
operator's extra expense insurance, among others. No assurance may be given that
the Company will be able to maintain adequate insurance in the future at rates
the Company considers reasonable. The occurrence of a significant event not
fully insured or indemnified against could materially and adversely affect the
Company's financial condition and results of operations. Pollution and
environmental risks generally are not fully insurable. See " -- Environmental,
Health and Safety Regulation and Risks" and "Business and
Properties -- Exploration and Development -- Operating Procedures and Risks."
ENVIRONMENTAL, HEALTH AND SAFETY REGULATION AND RISKS
The Company's operations are subject to extensive and developing federal,
state and local laws and regulations relating to environmental, health and
safety matters. Permits, registrations and other authorizations are required for
the operation of the DIGS and certain of the Company's facilities and for its
oil and gas exploration, production, gathering and marketing activities. These
permits, registrations and authorizations are subject to revocation,
modification and renewal. Governmental authorities have the power to enforce
compliance with these regulatory requirements, the provisions of required
permits, registrations or other authorizations, and lease conditions, and
violations are subject to civil and criminal penalties, including fines,
injunctions, technical requirements or any combination thereof. Failure to
obtain or maintain a required permit may also result in the imposition of civil
and criminal penalties. Third parties may have the right to sue to enforce
compliance or to participate in the revocation, modification, amendment or
renewal of required permits. Further, the imposition of stricter requirements of
environmental or health and safety laws and regulations affecting the Company's
business or more stringent interpretation of, or enforcement policies with
respect to, such laws and regulations, could adversely affect the Company.
The discharge of oil, gas or other pollutants into the air, soil or water
may give rise to liabilities to governments and third parties and may require
the Company to incur costs to remedy any such discharges. Oil, gas and other
pollutants may be discharged in many ways, including from a well or drilling
equipment at a drill site, leakage from pipelines or other gathering or
transportation facilities, leakage from storage
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tanks and sudden discharges resulting from damage to or explosions at oil or gas
wells or other facilities. Discharged hydrocarbons and other pollutants may
migrate through soil to water supplies or adjoining properties, giving rise to
additional liabilities. A variety of federal and state laws and regulations
govern the environmental aspects of oil and gas exploration, production,
gathering and transportation and may, in addition to other laws and regulations,
impose liability in the event of discharges (whether or not accidental), failure
to notify the proper authorities of a discharge and other failures to comply
with those laws and regulations. Environmental laws may also affect the costs of
the Company's acquisitions of oil and gas properties. The Company does not
believe that its environmental, health and safety risks are materially different
from those of comparable companies engaged in similar businesses. Nevertheless,
no assurance can be given that requirements of environmental, health and safety
laws and regulations will not, in the future, result in a curtailment of
production or a material increase in the costs of production, development,
exploration or gathering or otherwise adversely affect the Company's operations
and financial condition. Pollution and similar environmental risks generally are
not fully insurable. See "Business and Properties -- Governmental
Regulation -- Environmental Matters."
The operations of the DIGS are subject to regulation by the United States
Department of Transportation ("DOT") under the Natural Gas Pipeline Safety Act
of 1969, as amended ("NGPSA"). Under this statute DOT regulates the design,
installation, testing, construction, operation and management of the DIGS and
the MPGS. The NGPSA requires any entity that owns or operates pipeline
facilities to comply with applicable safety standards, to establish and maintain
inspection and maintenance plans and to comply with such plans.
Proposed legislation is pending before the U.S. Congress that would amend
NGPSA. Among other things, the proposed legislation, if enacted, would establish
a national "one-call" notification system regarding pipeline violations,
increase the frequency of pipeline inspections, and increase civil and criminal
penalties for violations of pipeline safety requirements. Although the Company
cannot predict whether such legislative proposals will be enacted or the effect,
if any, such legislation might have on DIGP's operations, depending on the
provisions of any new legislation ultimately enacted the Company could be
required to incur increased costs associated with the operation of the DIGS and
the MPGS. The Company believes the operations of the DIGS comply in all material
respects with the requirements of the NGPSA.
COMPETITION
The oil and gas industry and the natural gas gathering industry are highly
competitive. The Company encounters competition from other oil and gas companies
in all areas of its oil and gas operations, including the acquisition of leases
and producing properties. The DIGS encounters strong competition from regulated
and unregulated gas pipelines in the acquisition of gathering commitments. The
Company's competitors include major integrated oil and natural gas companies,
natural gas pipeline companies and numerous independent oil and natural gas
companies, individuals and drilling and income programs. Many of its competitors
are large, well-established companies with substantially larger operating staffs
and greater capital resources than the Company's and which, in many instances,
have been engaged in the energy business for a much longer time than the
Company. Such companies may be able to offer more attractive rates for natural
gas gathering commitments and 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, discover reserves and acquire additional natural gas gathering
commitments in the future will be dependent upon its ability to evaluate and
select suitable properties and to consummate transactions in a highly
competitive environment. See "Business and Properties -- Exploration and
Development -- Competition" and "Business and Properties -- Natural Gas
Gathering -- Competition."
MARKETABILITY OF PRODUCTION
The marketability of the Company's production depends in part upon the
availability, proximity and capacity of natural gas gathering systems, pipelines
and processing facilities. While much of the Company's natural gas is gathered
by the DIGS, it is delivered through gas pipelines that are not owned by the
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Company. Federal and state regulation of oil and natural gas production and
transportation, tax and energy policies, changes in supply and demand and
general economic conditions all could adversely affect the Company's ability to
produce and market its natural gas and oil. If market factors were to change
dramatically, the financial impact on the Company could be substantial. The
availability of markets and the volatility of product prices are beyond the
control of the Company and represent a significant risk. See "Business and
Properties -- Exploration and Development -- Marketing."
EFFECTS OF PRICE RISK HEDGING
Part of the Company's business strategy is to reduce its exposure to the
volatility of natural gas prices by hedging a portion of its production.
Approximately 79% of the estimate by Ryder Scott as of January 1, 1996 of the
Company's expected production from proved producing wells for the fourth quarter
of 1996 is hedged. For calendar 1997, approximately 31% of the estimate by Ryder
Scott as of January 1, 1996 of the Company's expected production from proved
producing wells is hedged. The Company's credit facility with Union Bank
requires the Company to maintain its hedging contracts in effect as of August
28, 1996 and to enter, prior to December 1, 1996, into contracts covering an
additional 0.7 Bcf of natural gas. No assurance may be given as to the financial
effect on the Company of these requirements. By replacing the right to receive
the market price for its production with a right to receive the difference in
the market price and the fixed hedge price, hedging will prevent the Company
from receiving the full advantage of increases in natural gas or crude oil
prices above the fixed amount specified in the hedge. In addition, significant
reductions in production at times when the market price exceeds the price fixed
in the hedge transaction could require the Company to make payments under the
hedge agreements even though such payments are not offset by sales of
production. The occurrence of such an event could have a material adverse effect
on the Company's financial conditions and results of operation. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Hedging Activities."
RISKS OF PURCHASING INTERESTS IN PRODUCING PROPERTIES
Although the Company currently emphasizes reserve growth through drilling
on its existing properties, it expects to make acquisitions of producing
properties and properties with proved undeveloped reserves from time to time. It
generally will not be feasible for the Company to review all records of every
property it purchases. However, even an in-depth review of all records may not
necessarily reveal existing or potential problems, nor will it permit a buyer to
become familiar enough with the properties to assess fully their deficiencies
and capabilities. Evaluation of future recoverable reserves of natural gas and
oil, which is an integral part of the property selection process, depends upon
evaluation of existing geological, engineering and production data, some or all
of which may prove to be unreliable or not indicative of future performance. See
" -- Uncertainty of Estimates of Reserves and Future Net Revenue." To the
extent the seller does not operate the properties, obtaining access to
properties and records may be more difficult. Even when problems are identified,
the seller may not be willing or financially able to give contractual protection
against such problems, and the Company may decide to assume environmental and
other liabilities in connection with acquired properties. See "Business and
Properties -- Exploration and Development -- Title to Properties."
CONTROL BY PRINCIPAL STOCKHOLDERS
After the Offering, Natural Gas Partners, L.P. ("NGP") and Messrs.
Strassner, Kiesewetter and Anderson will beneficially own in the aggregate
approximately 49% of the outstanding Common Stock. If such stockholders should
agree to act together with respect to the voting of their Common Stock, they
would be able to exercise substantial influence in the election of the board of
directors and the outcome of other matters requiring stockholder action. See
" -- Certain Anti-takeover Provisions" and "Principal and Selling
Stockholders."
CONFLICTS OF INTEREST
The Offering will result in certain benefits to affiliates of the Company.
Certain of the directors and executive officers of the Company and NGP own
shares of Common Stock and would therefore benefit
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from any increase in the value and liquidity of the Common Stock resulting from
the creation of a public trading market for the Common Stock following the
Offering. In addition, certain of such persons will benefit from the Offering
because they are selling, or may sell if the Underwriters' overallotment option
is exercised, shares of Common Stock in the Offering. See "Principal and
Selling Stockholders." Furthermore, an entity owned by NGP and certain of its
affiliates and employees, including David R. Albin and R. Gamble Baldwin, who
are directors of the Company, will receive $12 million of the net proceeds to
the Company of the Offering. See "Use of Proceeds."
RESTRICTION ON PAYMENT OF DIVIDENDS
The Company's credit facility with Union Bank prohibits the Company from
paying dividends on the Common Stock without the bank's prior consent. See
"Dividend Policy" and "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources --
Financing Activities -- Credit Facility."
DILUTION
Purchasers of shares of Common Stock in this Offering will experience
immediate and substantial dilution. See "Dilution."
NO PRIOR PUBLIC MARKET
Prior to this Offering, there has been no public market for shares of the
Common Stock. Although the Common Stock has been approved for listing on the
NASDAQ National Market, there can be no assurance that an active trading market
for such shares will develop or be sustained. The initial public offering price
for the Common Stock has been determined by negotiations among the Company and
the Underwriters and may not be indicative of the market price of the Common
Stock after this Offering. See "Underwriting."
CERTAIN ANTI-TAKEOVER PROVISIONS
The Company's Certificate of Incorporation and Bylaws contain provisions
that may have the effect of delaying, deferring or preventing a change in
control of the Company. These provisions, among other things, provide for a
classified Board of Directors with staggered three-year terms, impose certain
procedural requirements on stockholders of the Company who wish to make
nominations for elections of directors or propose other actions at stockholders'
meetings and authorize the Board of Directors to fix the rights and preferences
of the shares of a series of preferred stock without stockholder approval. Any
series of preferred stock is likely to be senior to the Common Stock with
respect to dividends, liquidation rights and, possibly, voting. The ability to
issue preferred stock could have the effect of discouraging unsolicited
acquisition proposals. See "Description of Capital Stock -- Certain Provisions
of the Company's Charter and Bylaws and Delaware Law." The Company's employee
stock option plan contains provisions that allow for, among other things, the
acceleration of vesting or payment awards granted under such plan in the event
of a "change of control," as defined in such plan. See "Management -- 1996
Stock Awards Plan." Certain of the Company's partnership agreements and its
credit facility with Union Bank contain provisions that impose adverse
consequences on the Company if its key officers are removed or sell 75% or more
of their respective ownership interests in the Company following this Offering.
See " -- Dependence on Key Personnel."
SHARES ELIGIBLE FOR FUTURE SALE
The Company, each of its directors and executive officers and NGP each have
agreed not to dispose of any shares of Common Stock for a period of 180 days
from the date of this Prospectus without the consent of Morgan Keegan & Company,
Inc. Following such period, a total of 4,869,885 shares of Common Stock will be
eligible for resale after the satisfaction of the two-year holding period and
the volume and other requirements of Rule 144 under the Securities Act of 1933,
as amended ("Securities Act"). In addition, options to purchase a total of
727,580 shares of Common Stock will have been granted as of the completion of
this Offering to members of the Company's management, 99,268 shares of which
will be presently exercisable, and all of which would be issued pursuant to a
registration statement on Form S-8 and become
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freely tradeable, subject in certain cases to the provisions of Rule 144 other
than the holding period. The Company has entered into a Registration Rights
Agreement (the "Registration Rights Agreement") with NGP (including certain
affiliates) and Messrs. Strassner, Kiesewetter and Anderson. Under the
Registration Rights Agreement, after one year following the completion of this
Offering, the holders of at least 35% of the shares held by NGP (including
certain affiliates) and Messrs. Strassner, Kiesewetter and Anderson may require
the Company to register shares held by such persons under applicable securities
laws. In addition, the Registration Rights Agreement entitles NGP (including
certain affiliates) and Messrs. Strassner, Kiesewetter and Anderson and, for two
years after the effective date of the Company's initial registration statement
under the securities laws, certain other stockholders, to include shares held by
them in certain registrations under applicable securities laws initiated by the
Company. See "Management -- Certain Transactions."
No prediction may be made as to the effect, if any, that future sales of
shares of Common Stock or the availability of shares for sale could have on the
market price of the Common Stock prevailing from time to time. Sales of
substantial amounts of Common Stock in the public market, or the perception of
the availability of shares for sale, could adversely affect the prevailing
market price of the Common Stock and could impair the Company's ability to raise
capital through the future sale of its equity securities. See "Shares Eligible
for Future Sale."
USE OF PROCEEDS
The net proceeds to the Company from this Offering are estimated to be
approximately $38.5 million. Of such net proceeds, (i) $14 million will be
contributed to South Dauphin II Limited Partnership ("SDPII"), a partnership
managed by the Company, to fund a five-well drilling and development program
(the "SDPII Program"), (ii) $12 million will be used to redeem from an
affiliate of NGP at the face value thereof all of the outstanding mandatorily
redeemable partnership preference units of OEDC Partners, L.P., a subsidiary of
the Company, and (iii) the balance will be used for working capital and other
general corporate purposes, including funding a portion of the Company's 1996
and 1997 capital expenditure budget. The Company will not receive any of the
proceeds paid to the Selling Stockholders.
All or a portion of the proceeds contributed to SDPII will be used to repay
amounts contributed to SDPII by an affiliate (the "ECT Affiliate") of Enron
Capital & Trade Resources, Inc. ("ECT"). The Company and the ECT Affiliate
formed SDPII in July 1996 to finance the SDPII Program. The ECT Affiliate has
agreed to contribute 85% of the partnership capital contributions in exchange
for an 85% interest in SDPII's net cash flow (100% until a minimum payment
schedule has been satisfied) until it has received the return of its investment
plus a 15% rate of return, at which time its interest reduces to 25%. The
financing is nonrecourse to the Company's other assets. The Company's interest
in SDPII will increase from 15% to 75% contemporaneously with the decrease in
the ECT Affiliate's interest. SDPII has the right to prepay the amounts
contributed by the ECT Affiliate at any time prior to completion of the SDPII
Program. Under the terms of the SDPII partnership agreement, the repayment of
the ECT Affiliate through funds obtained from this Offering rather than
operations will require the payment to the ECT Affiliate of an additional sum
equal to ten percent (10%) of the amount outstanding plus five percent (5%) of
the unused portion of the ECT Affiliate's commitments.
Subject to the limitation set forth above, the actual amount paid to the
ECT Affiliate from the proceeeds of this Offering will be determined by the
amount of funds contributed by the ECT Affiliate to SDPII at the time of such
repayment. Because the amount due to the ECT Affiliate will change as additional
funds are contributed by it to fund the SDPII Program, the amount to be paid to
the ECT Affiliate from the proceeds of this Offering will increase as amounts
are contributed. The Company currently estimates that funds contributed by the
ECT Affiliate will be approximately $4.2 million in mid-November 1996 and that
prepayment of that sum at that time would result in a total payment to the ECT
Affiliate of approximately $5.3 million (including the applicable premium). The
Company intends to cause SDPII to prepay the amounts due to the ECT Affiliate
during the first quarter of 1997.
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<PAGE>
OEDC Partners, L.P., a limited partnership that will be a subsidiary of the
Company after completion of the Combination, is required to redeem one-half of
its preference units issued to an affiliate of NGP no later than December 31,
1997 and the balance no later than December 31, 1998. The aggregate redemption
price of all of the preference units is $12 million. The Company will utilize
$12 million of the net proceeds of the Offering to redeem at the face value
thereof all of the outstanding preference units. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources -- Financing Activities -- OEDC Partners, L.P. Preference
Units."
DIVIDEND POLICY
The Company currently intends to retain its capital for the operation and
expansion of its business and does not anticipate paying any dividends in the
foreseeable future. The Company's loan agreement with Union Bank contains a
covenant that prohibits the payment of dividends on the Common Stock by the
Company without the bank's prior consent. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources -- Financing Activities -- Credit Facility."
DILUTION
As of June 30, 1996, the pro forma consolidated net tangible book value
(total tangible assets less total liabilities) of the Company, was approximately
$5.1 million, or $1.01 per share of Common Stock, assuming completion on that
date of the Combination described elsewhere herein. After giving effect to the
receipt of approximately $38.5 million of estimated net proceeds from this
Offering (net of estimated underwriting discounts and commissions and offering
expenses), the pro forma net tangible book value of the Common Stock outstanding
at June 30, 1996 would have been $5.09 per share, representing an immediate
increase in net tangible book value of $4.08 per share to the existing
stockholders and an immediate dilution of $6.91 per share (the difference
between the assumed initial public offering price and the consolidated net
tangible book value per share after this Offering) to persons purchasing Common
Stock at the initial public offering price. The following table illustrates such
per share dilution:
Initial public offering price per
share.............................. $ 12.00
---------
Pro forma consolidated net
tangible book value per share
before this Offering........... $ 1.01
---------
Increase in consolidated net
tangible book value per share
attributable to the sale of
Common Stock in this
Offering....................... 4.08
---------
Pro forma consolidated net tangible
book value per share after giving
effect to this Offering............ 5.09
---------
Dilution in pro forma consolidated
net tangible book value to the
purchasers of Common Stock offered
hereby............................. $ 6.91
=========
The foregoing computations do not include 727,580 shares of Common Stock
issuable upon exercise of outstanding management stock options at an average
exercise price of $9.84 per share. See "Management -- 1996 Stock Awards
Plan -- Grants." Assuming the exercise of all such options, the pro forma
consolidated net tangible book value per share before this Offering would be
$2.12, the pro forma consolidated net tangible book value per share after this
Offering would be $5.47 and the dilution per share to new investors would be
$6.53.
18
<PAGE>
CAPITALIZATION
The following table sets forth (i) the historical consolidated
capitalization of the Company as of June 30, 1996, (ii) the pro forma
capitalization of the Company as of June 30, 1996 after giving effect to the
issuance of 5,051,882 shares of Common Stock in the Combination, and a one time
non-cash charge of $1,937,000 to establish a net deferred tax liability upon
consummation of the Combination, and (iii) the pro forma capitalization of the
Company as of June 30, 1996, as adjusted to give effect to the sale by the
Company of 3,500,000 shares of Common Stock in the Offering and the application
of the net proceeds therefrom as described in "Use of Proceeds." This table
should be read in conjunction with the Company's financial statements and notes
thereto and "Management's Discussion and Analysis of Financial Condition and
Results of Operations" included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
----------------------------------------------------
PRO FORMA PRO FORMA
HISTORICAL FOR AS
CONSOLIDATED COMBINATION ADJUSTED
------------- --------------- ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Long-term debt (excluding current
maturities)........................ $-- $-- $ --
Capital lease payable-noncurrent..... 741 741 741
Redeemable preference units.......... 10,648 10,648 --
Stockholders' equity:
Preferred Stock, $.01 par value
per share; 1,000,000 shares
authorized; none
outstanding................... -- -- --
Common Stock, $.01 par value per
share; 10,000,000 shares
authorized; 8,551,885 issued
and outstanding pro forma as
adjusted...................... -- 50 86
Additional paid-in capital........... -- 5,135 42,214
Retained earnings.................... 201 201 201
Combined equity...................... 7,122 -- --
------------- --------------- ------------
Total stockholders'
equity.................. $ 7,323 $ 5,386 $ 42,501
------------- --------------- ------------
Total capitalization....... $18,712 $16,775 $ 43,242
============= =============== ============
</TABLE>
19
<PAGE>
SELECTED CONSOLIDATED 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 for each year in the four-year period ended December 31, 1995, and the
financial data for the six months ended June 30, 1996, are derived from the
audited financial statements of the Company. The financial data for the year
ended December 31, 1991 and for the six months ended June 30, 1995 are derived
from the Company's unaudited financial statements. Prior to August 31, 1992, the
financial data reflects the operations of Offshore Energy Development
Corporation, a Texas corporation, a predecessor of the Company. The following
data should be read in conjunction with "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 financial statements included elsewhere
in this Prospectus. The results for the six months ended June 30, 1996 are not
necessarily indicative of results for the full year.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
--------------------------------------------------------- ------------------------
1991 1992 1993 1994 1995 1995 1996
------------ --------- --------- --------- --------- ------------ ---------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Income:
Exploration and production....... $ 5,298 $ 2,116 $ 1,744 $ 5,513 $ 6,169 $ 1,859 $ 5,549
Pipeline operating and
marketing...................... -- 886 358 358 167 93 494
Equity in earnings (loss) of
equity investments............. -- -- (255) (3) 497 315 23
Gain on sales of oil and gas
properties or partnership
investments, net............... -- -- -- 13,655 -- -- 10,661
------------ --------- --------- --------- --------- ------------ ---------
Total income................ 5,298 3,002 1,847 19,523 6,833 2,267 16,727
------------ --------- --------- --------- --------- ------------ ---------
Expense:
Operations and maintenance....... 919 745 570 1,410 2,210 1,064 1,025
Exploration charges.............. -- 36 32 2,231 405 153 421
Depreciation, depletion and
amortization................... 1,915 1,941 355 2,112 5,501 1,598 2,876
Abandonment expense.............. -- -- 59 2,735 84 13 216
General and administrative....... 561 785 1,725 2,359 2,192 1,155 1,155
------------ --------- --------- --------- --------- ------------ ---------
Total expense............... 3,395 3,507 2,741 10,847 10,392 3,983 5,693
------------ --------- --------- --------- --------- ------------ ---------
Earnings (loss) before interest and
taxes.............................. 1,903 (505) (894) 8,676 (3,559) (1,716) 11,034
Interest income (expense) and other:
Interest expense................. (805) (975) (228) (590) (1,651) (697) (622)
Preferential payments by
subsidiaries................... -- -- -- (1,431) -- -- --
Interest income and other........ 35 (63) (226) 316 123 229 (65)
------------ --------- --------- --------- --------- ------------ ---------
Total interest income
(expense) and other....... (770) (1,038) (454) (1,705) (1,528) (468) (687)
------------ --------- --------- --------- --------- ------------ ---------
Income (loss) before income taxes.... 1,133 (1,543) (1,348) 6,971 (5,087) (2,184) 10,347
Income tax benefit (expense)......... -- -- -- (27) 21 10 (13)
------------ --------- --------- --------- --------- ------------ ---------
Net income (loss).................... 1,133 (1,543) (1,348) 6,944 (5,066) (2,174) 10,334
Preference unit payments and
accretion of discount.............. -- -- (731) (585) (1,143) (292) (894)
------------ --------- --------- --------- --------- ------------ ---------
Income (loss) available to common
unitholders and stockholders(1).... $ 1,133 $ (1,543) $ (2,079) $ 6,359 $ (6,209) $ (2,466) $ 9,440
============ ========= ========= ========= ========= ============ =========
Pro forma net income (loss)(2)....... $ (4,334) $ 5,617
========= =========
Pro forma net income (loss) per
common share(2).................... $ (0.86) $ 1.11
========= =========
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF JUNE 30,
--------------------------------------------------------- ------------------------
1991 1992 1993 1994 1995 1995 1996
------------ --------- --------- --------- --------- ------------ ---------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Property, plant and equipment,
net............................ $ 5,517 $ 14,146 $ 23,626 $ 9,599 $ 20,108 $ 18,989 $ 17,301
Total assets..................... $ 6,236 $ 16,828 $ 30,952 $ 20,035 $ 25,170 $ 24,858 $ 24,551
Total long term debt (less
current portion)............... $ 30 $ -- $ 20,238 $ 5,969 $ -- $ 10,922 $ --
Capital lease
payable -- noncurrent.......... $ -- $ -- $ 474 $ 309 $ 832 $ 918 $ 741
Redeemable preference units...... $ -- $ 6,500 $ 6,500 $ 6,500 $ 10,294 $ 6,500 $ 10,648
Combined equity (deficit)........ $ 1,952 $ 971 $ (1,091) $ 2,192 $ (2,117) $ (263) $ 7,323
</TABLE>
- ------------
(1) The Company's loan agreement with Union Bank contains a covenant that
prohibits the payment of dividends on the Common Stock by the Company
without the bank's prior consent. OEDC, Inc. has never paid dividends. OEDC
Partners, L.P. made capital distributions to its partners totaling
$3,076,681 and $100,000 in 1994 and 1995, respectively. No such capital
distributions were made during 1991, 1992 or 1993 or the six month period
ended June 30, 1996.
(2) Gives effect to the Combination as if it had occurred on June 30, 1996.
Prior to the Combination, the Company's operating partnerships were exempt
from United States federal income taxes. The pro forma data reflects a net
deferred tax liability of $1,937,000 for the federal income tax expense that
would have been recorded in prior years had such entities not been exempt
from paying such income taxes. See Note 1 of Notes to Consolidated Financial
Statements.
20
<PAGE>
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 notes thereto and other financial
information included elsewhere in this Prospectus.
OVERVIEW
The Company was formed in 1996 for the purpose of becoming the holding
company for OEDC Partners, L.P. and OEDC, Inc. pursuant to the terms of an
Agreement and Plan of Reorganization dated August 30, 1996 (the
"Combination"). Under the terms of the Combination, the Company will (i)
acquire all of the outstanding capital stock of OEDC, Inc. previously owned by
Messrs. Strassner, Kiesewetter, Anderson and Bradshaw (including certain of his
family members) and by NGP, (ii) acquire 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) acquire 50% of the common units of OEDC
Partners, L.P. held by NGP and certain of its employees. The Company will be the
surviving corporation in the merger. As a result of the change in the form of
the business resulting from the Combination, the Company will incur a charge of
$1,937,000 to record a deferred tax liability reflecting the excess of the
pre-Combination tax deductions for intangible drilling costs over the amount of
their depreciation for financial statement purposes. The Combination will be
consummated contemporaneously with the closing of this Offering.
The Company's predecessor commenced operations in 1988 and drilled one well
per year through 1992. From 1993 through 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 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 years when the interests in the projects were
sold. During 1993 and 1995, the Company sustained losses resulting from the
expense incurred in forming a property development partnership with a subsidiary
of Enron and the expense associated with development expenditures on its Mobile
959/960 cluster, respectively, while net income was recorded in 1994 and the
first half of 1996 as the result of gains on the sale of properties from the
Enron partnership and all but one percent of the Company's interest in DIGP,
respectively.
RESULTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 1996 COMPARED TO SIX MONTHS ENDED JUNE 30, 1995
INCOME. Total income for the Company increased $14,460,038 (639%) from
$2,267,145 in the six months ended June 30, 1995 to $16,727,183 in the six
months ended June 30, 1996. Natural gas revenue increased $3,689,736 (198%) from
$1,859,093 in the six months ended June 30, 1995 to $5,548,829 in the six months
ended June 30, 1996, primarily as a result of an increase in production volumes
from 1.02 Bcfe during the 1995 period to 2.53 Bcfe during the 1996 period. The
increase in production volumes was attributable to completion of the Company's
South Timbalier 162 B-7 well, which occurred in October 1995. New production
from the South Timbalier 162 B-7 well was partially offset by normal production
declines experienced at the Mobile 959/960 cluster. Average natural gas prices
(inclusive of hedging) were $1.82 per Mcfe compared to $2.20 per Mcfe in the six
months ended June 30, 1995 and 1996, respectively.
In the six months ended June 30, 1996, the Company's pipeline and marketing
income increased $400,236 (428%) compared to the six months ended June 30, 1995
due to the increase in January 1996 of the monthly management fee that the
Company earns for operating the DIGS from $5,800 to $44,650 per month. See
" -- Liquidity and Capital Resources -- Cash Flow from Operations." The
Company also earned $212,413 in marketing revenue from the South Timbalier B-7
well in the first half of 1996.
21
<PAGE>
Equity earnings in DIGP decreased by $291,367 (92%) for the six months
ended June 30, 1996 as compared to the same period in 1995 due to the decrease
in the Company's ownership of DIGP from 25% to one percent.
During the first six months of 1996, the Company consummated the sale of
all but a one percent general partnership interest in DIGP, resulting in a gain
of $10,826,938 net to the Company. The gain on this sale was partially offset by
a $165,505 loss the Company realized on the sale of a non-producing lease block
that was no longer consistent with the Company's development plans.
EXPENSE. Total expense increased $1,800,030 (46%) from $3,893,943 in the
first half of 1995 to $5,693,973 in the first half of 1996.
Operations, maintenance and insurance expense was essentially flat between
the two periods. In general, a significant portion of operating expenses does
not fluctuate from period to period as changes occur in production volumes and
prices received for those volumes. Therefore, such expenses do not change
proportionately with changes in exploration and production income. The Company
experienced marketing charges during the first half of 1996 and 1995 as a result
of unused firm transportation charges in the Mobile area. The Company's
depreciation, depletion and amortization expenses ("DD&A") increased
approximately 80% from $1,597,913 in the six months ended June 30, 1995 to
$2,876,566 in the six months ended June 30, 1996. The DD&A charge for the first
six months of 1995 was $1.56 per Mcfe compared to $1.14 per Mcfe for the same
period in 1996. The larger DD&A charge per Mcfe for the first half of 1995 was
the result of higher reserve finding costs in the Mobile 959/960 cluster. In
addition, the South Timbalier 162 B-7 well commenced production in the fourth
quarter of 1995 and had relatively low finding costs, which reduced the average
DD&A charge per Mcfe.
The Company's abandonment expense increased by $202,962 from $13,159 during
the six months ended June 30, 1995 to $216,121 for the same period in 1996. The
expense for 1996 consisted of a $68,944 accrual associated primarily with the
South Timbalier 162 property and actual abandonment expense of $147,177 recorded
during the period relating to the settlement of a dispute regarding the
previously abandoned Eugene Island 163 property.
INTEREST EXPENSE. Interest expense decreased $74,556 (11%) from $696,688
in the first half of 1995 to $622,132 in the first half of 1996.
In the six months ended June 30, 1995, interest of $623,688 was paid to the
ECT Affiliate under a combined term and revolving credit facility. Borrowings
under the term facility bore interest at a fixed rate of 15% per annum, and
borrowings under the revolving credit facility bore interests at a floating rate
per annum equal to 2.5% above the applicable prime rate. During the first
quarter of 1996, such term facility was repaid and amounts outstanding under the
revolving credit facility were reduced by 50%. This reduced interest charges
during the first six months of 1996 by $219,271 (35%). The reduction in interest
expense from such credit facility was partially offset by $142,715 in additional
first quarter interest charges, most of which related to the delayed settlement
of hedging agreements.
NET INCOME (LOSS), INCOME (LOSS) AVAILABLE TO COMMON UNIT HOLDERS AND
STOCKHOLDERS AND PREFERENCE UNIT PAYMENTS. The Company incurred a net loss of
$2,173,829 in the first half of 1995 compared to net income of $10,333,125 in
the first half of 1996. The net income for the first six months of 1996 was
primarily attributable to the gain realized by the Company on the sale of all
but a one percent general partner interest in DIGP and the absence of any
comparable transaction in the prior period.
Income (loss) available to common unit holders and stockholders, which
gives effect to preference unit payments and accretion of discount, was a loss
of $2,466,329 in the first half of 1995 compared to income of $9,439,887 in the
first half of 1996.
In the first half of 1995, preference unit payments to NGP totaled
$292,500, representing a nine percent coupon on all preference units
outstanding. In the first half of 1996, preference unit payments to NGP were
$540,000, reflecting additional preference units purchased by NGP in August 1995
and $353,238 for accretion of the discount on the preference units.
22
<PAGE>
1995 COMPARED TO 1994
INCOME. Total income decreased $12,691,103 (65%) from $19,523,092 in 1994
to $6,831,989 in 1995. Natural gas revenue increased $656,095 (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. Production from Mobile 959/960 stabilized during
the third quarter of 1995 and, when combined with revenues from the South
Timbalier 162 B-7 well, resulted in a majority of 1995 exploration and
production revenues being recognized in the last six months of 1995. The average
natural gas price received (inclusive of hedging) in 1994 was $1.50 per Mcfe
compared to $1.68 in 1995, representing a 12% increase.
The Company's pipeline and marketing income decreased $191,731 from 1994 to
1995 as a result of decreased pipeline construction activity.
Equity earnings in DIGP increased from a loss of $2,779 in 1994 to positive
earnings of $496,979 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 $13,655,225, which was the primary reason the Company
reported net income in 1994 as compared to its net loss in 1995.
EXPENSE. Total expense decreased $455,777 (4%) from $10,847,851 in 1994 to
$10,392,074 in 1995. Operations and maintenance charges increased by $799,839
(57%) from $1,410,231 in 1994 to $2,210,070 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 $1,826,513 (82%) from $2,231,349 in 1994
to $404,836 in 1995, due principally to the Company recording a dry hole charge
of $1,585,872 relating to the Viosca Knoll 79 well and the absence of a similar
charge in 1995. Expense relating to seismic data acquisition and processing
declined by $558,641 from $645,477 in 1994 to $86,836 in 1995. During 1995, the
Company paid $318,000 in lease rentals on acreage acquired in 1994. 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.
The Company's DD&A expense increased $3,388,722 (160%) from $2,112,350 in
1994 to $5,501,072 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 $2,651,034 (97%) from $2,735,253 in 1994 to
$84,219 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 $470,510 in 1994.
INTEREST EXPENSE AND PREFERENTIAL PAYMENTS. In 1994, the Company made
preferential payments of $1,430,722 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 $1,061,115 (180%) from $589,948 in 1994 to
$1,651,063 in 1995. In 1994, the Company paid the ETC Affiliate $349,673 in
interest under a term and revolving credit facility, as compared to $774,445 and
$801,618 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
23
<PAGE>
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 $6,944,516 compared to a net loss of $5,066,799 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 $6,359,516 for 1994 compared
to a loss of $6,208,664 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 $1,141,865 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.
1994 COMPARED TO 1993
INCOME. Income increased $17,676,361 (957%) from $1,846,731 in 1993 to
$19,523,092 in 1994. Natural gas revenue increased $3,768,030 (216%) from
$1,744,466 during 1993 to $5,512,496 in 1994, due primarily to increased
production, which was partially offset by lower average natural gas prices.
Natural gas production increased by 3.01 Bcfe (449%) from 0.67 Bcfe in 1993 to
3.68 Bcfe in 1994 as a result of an increase in the Company's interest in the
partnership owning the Mobile 822 cluster from 20% to 80%, and as a result of
having three more months of production from that cluster in 1994. In addition,
the Company added production in 1994 from two new wells drilled during that
year. The price the Company received for natural gas sales (inclusive of
hedging) decreased 42% from $2.59 per Mcfe in 1993 to $1.50 per Mcfe in 1994.
The equity loss in DIGP decreased from $255,493 in 1993 to a loss of $2,779
in 1994 as a result of increased throughput in the DIGS.
The Company sold its interest in the Mobile 822 cluster during second
quarter of 1994 at a gain of $13,655,225, which resulted in the Company
recording net income of $6,359,516 in 1994 compared to a net loss of $2,079,166
in 1993.
EXPENSE. Total expense increased $8,107,155 (296%) from $2,740,696 in 1993
to $10,847,851 in 1994. Operations, maintenance and insurance cost increased by
$840,064 (147%) from $570,167 in 1993 to $1,410,231 in 1994. Cost directly
relating to lease operating expense increased $577,000 (109%) from $526,802 in
1993 to $1,103,557 in 1994, due to the increased scope of production operations
primarily at the Mobile 822 cluster. Insurance costs increased from $19,738 in
1993 to $232,927 in 1994 and operations consulting costs increased from $23,627
in 1993 to $73,747 in 1994 as a result of the above noted expanded scope of
operations during 1994.
Exploration charges increased $2,199,000 from $32,349 in 1993 to $2,231,349
in 1994. The relatively low costs in 1993 represented seismic related costs of
$19,526 and delay rentals of $12,823. Seismic expense increased significantly in
1994 to $645,477 due to seismic acquisition and analysis expenses incurred in
connection with the Company's participation in Minerals Management Service
("MMS") lease auctions during 1994 and expense associated with defining
drilling prospects. In addition, the Company incurred dry hole expense in 1994
of $1,585,872 relating to the Viosca Knoll 79 well.
DD&A increased by $1,757,733 (496%) from $354,617 in 1993 to $2,112,350 in
1994. The increase in DD&A in 1994 was primarily the result of increased
ownership in the partnership owning the Mobile 822 cluster coupled with
increased production from three additional wells drilled and connected to such
cluster. The DD&A charge in 1993 was $0.53 per Mcfe compared to $0.57 per Mcfe
in 1994.
Abandonment expense increased $2,676,133 from $59,120 in 1993 to $2,735,253
in 1994, primarily as a result of write down and abandonment charge of
$2,264,743 incurred in 1994 relating to the abandonment of the Company's Eugene
Island 163 platform. This platform was not able to resume production because of
24
<PAGE>
water encroachment in the wellbore during a routine shut-in due to a hurricane.
Other abandonment charges and accruals were $470,510 in 1994.
General and administrative expense increased $634,225 (37%) from $1,724,443
in 1993 to $2,358,668 in 1994. The increase during 1994 was primarily
attributable to additional payroll and consulting expenses associated with the
increase in the Company's scope of operations during 1994 relative to 1993.
INTEREST EXPENSE AND PREFERENTIAL PAYMENTS. In 1994, the Company made
preferential payments of $1,430,722 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.
In 1993, NGP provided the Company a short-term credit facility that bore
interest at 15% per annum. Interest expense under this facility was $180,748 in
1993, and the loan (including interest of $175,000) was repaid in 1994. In 1993,
the Company also incurred interest expense of $47,637 relating to the initial
development of the DIGS. In addition, during 1994 the Company entered into a
lease/purchase transaction involving a natural gas compressor with an imputed
interest rate of 11% per annum, which resulted in interest charges of $65,275.
In 1994, the Company paid the ECT Affiliate $349,673 in interest under a term
and revolving credit facility. 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 fixed rate of 15% per annum. The revolving credit facility
was used for general corporate purposes and bore interest at a floating rate per
annum equal to 2.5% above the applicable prime rate.
The Company's other expense was $225,566 in 1993, consisting of a write off
of capitalized costs associated with a gas storage project.
Interest income in 1993 was $73,198 compared to $218,295 in 1994 as a
result of larger cash balances following the sale of the Mobile 822 cluster in
1994.
NET INCOME (LOSS), INCOME (LOSS) AVAILABLE TO COMMON UNIT HOLDERS AND
STOCKHOLDERS AND PREFERENCE UNIT PAYMENTS. The Company incurred a net loss of
$1,347,916 in 1993 compared to net income of $6,944,516 in 1994. The loss in
1993 was the result of the Company incurring cost during the development phase
of the Mobile 822 cluster prior to the receipt of revenue from that cluster.
Income (loss) available to common unit holders and stockholders, which
gives effect to preference unit payments, was a loss of $2,079,166 in 1993
compared to income of $6,359,516 in 1994.
In 1993, preference unit payments to NGP totaled $731,250, representing
coupon payments on preference units outstanding during 1993. Preference unit
payment expense to NGP in 1994 was $585,000.
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 reduced its cash position by $10,382,767 due to
financing activities during the first half of 1996, which consisted primarily of
repayment of the ECT Affiliate term facility for the development of Mobile
959/960 cluster and the repayment of $2,500,000 of the ECT Affiliate revolving
credit facility. During the first half of 1995, the Company realized net
proceeds of $4,640,319 from financing activities, which represented borrowings
under such term credit facility for the development of Mobile 959/960 cluster.
In the future the Company intends to finance its capital expenditures out of
funds generated from operations, the proceeds of this Offering and bank
borrowings.
The second largest source of liquidity has been the profitable sale of
assets which the Company has developed. The Company received net cash of
$10,281,414 from investing activities in the first half of 1996 as compared to
utilizing $11,973,724 in investing activities during the first half of 1995. The
1996 cash inflow was the result of selling all but one percent of the Company's
interest in DIGP and selling a non-strategic lease block. This was partially
offset by investments in properties and a contribution to DIGP to repay its
nonrecourse liabilities. 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
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does not anticipate that sales of properties will be a significant source of
liquidity subsequent to this Offering.
WORKING CAPITAL
The Company had a working capital deficit of $1,011,953 as of June 30, 1996
as compared to a working capital deficit of $2,221,211 at June 30, 1995. 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 the six months ended June 30, 1996, the Company generated net cash
flow from operations of $968,502 as compared to net cash flow from operations of
$470,012 during the same period in 1995. The improvement in 1996 was due
primarily to new production from the South Timbalier 162 B-7 well. 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 and by an increase
in exploration and production revenue attributable to hedging activities in
1995. 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 prices.
Net cash flow from operations during the first six months of 1996 was also
increased by the Company's receipt of management fees the Company began to earn
as the operator of DIGP, which contributed almost $268,000 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. This
fee has been increased to $330,000 for the second half of 1996.
FINANCING ACTIVITIES
The Company's estimated total capital expenditure budget for the period
from November 1, 1996 through December 31, 1997 is approximately $36 million.
The Company believes that the proceeds of this 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. See "-- Capital Expenditures and
Future Outlook" and "Risk Factors -- Substantial Capital Requirements."
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 September 30, 1996,
the borrowing base was $5,912,500 and $2,633,606 was outstanding 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 Company's option, either the
bank's reference rate plus 1% or LIBOR plus 2.5%, with an effective rate of
interest on September 30, 1996 of 7.94%.
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
facility requires that the Company maintain at the subsidiary level certain
minimum financial ratios, including a current ratio of at least 1:1 and an
interest coverage ratio of 2.5:1. In addition, the weighted average maturity of
indebtedness incurred on ordinary terms to vendors, suppliers and others
supplying
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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 its hedging
contracts in effect as of August 28, 1996 and to enter into, prior to December
1, 1996, hedging contracts covering an additional 0.7 Bcf of natural gas.
Indebtedness under the credit facility is secured by a first lien upon
substantially all of the properties owned by OEDC Exploration and 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 will contribute $14
million of the proceeds of the Offering to SDPII. See "Use of Proceeds." The
Company and the ECT Affiliate formed SDPII to fund the SDPII Program. The ECT
Affiliate and the Company fund 85% and 15%, respectively, of an agreed drilling
and development budget, 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 will receive 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 repayment 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 intends to cause SDPII to use all or a portion of the $14 million
contributed from the proceeds of this Offering to repay such obligations 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 ECT to
SDPII. As of September 30, 1996, the ECT Affiliate had made contributions to
SDPII of $2.3 million. The five wells have been drilled and the Company expects
that, by mid-November 1996, total contributions by the ECT Affiliate will
approximate $4.2 million. Assuming the prepayment of the $4.2 million
contemporaneously with the closing of this Offering, the Company would incur
additional charges of approximately $1.1 million. The Company intends to cause
SDPII to prepay the amounts due to the ECT Affiliate during the first quarter of
1997.
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. See "Risk
Factors -- Dependence Upon Key Personnel."
OEDC PARTNERS, L.P. PREFERENCE UNITS. NGP currently owns 120,000
preference units in OEDC Partners, L.P. having a stated value of $100 per unit.
The Company is required to pay a nine percent per annum preference payment on
all such units outstanding. A discount of $2,000,000, due to NGP's purchase of
additional preference units in August 1995, is being accreted over the
redemption period. Preference payments are made on a quarterly basis. Income
(loss) available to common unit holders and stockholders gives effect to
preference unit payments and, as applicable, accretion of discount of $731,250,
$585,000 and $1,141,862 in 1993, 1994 and 1995, respectively and $292,500 and
$893,238 in the six-month periods ended June 30, 1995 and 1996, respectively.
The preference units carry a mandatory redemption of 60,000 units on December
31, 1997, and the remaining 60,000 units are mandatorily redeemable on December
31, 1998. The preference units are a general obligation of the Company and are
subordinated to all senior debt. If preference payments are not made as
scheduled on a quarterly basis, the coupon rate increases from nine
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percent to 15 percent per annum. The Company will redeem all of the outstanding
preference units with a portion of the proceeds from this Offering. See "Use of
Proceeds."
HEDGING ACTIVITIES
The Company uses financial futures to hedge its natural gas production.
These activities increased revenue by $622,295 in 1995 and $481,545 in 1994.
During the first six months of 1996, however, Company revenue was reduced by
$822,475 as a result of its hedging position. The hedging program in place for
the first half of 1996 was structured to ensure a minimum level of cash flow
from production to service fixed obligations such as debt service and general
and administrative expenses. See Note 5 of Notes to Consolidated Financial
Statements.
In a typical hedge transaction, the Company will have the right to receive
from the counterparty to the hedge the excess of the fixed price specified in
the hedge over a floating price based on a market index, multiplied by the
quantity hedged. If the floating price exceeds the fixed price, the Company is
required to pay the counterparty this difference multiplied by the quantity
hedged. The Company is required to pay the difference between the floating price
and the fixed price (when the floating price exceeds the fixed price) regardless
of whether the Company has sufficient production to cover the quantities
specified in the hedge.
The Company hedges through use of financial contracts, the settlement value
of which is determined by the average closing price of the last three trading
days of the NYMEX contract ("NYMEX Price") as compared to the Company's fixed
price. If the fixed price is higher than the NYMEX Price, then the Company is
paid the difference in price multiplied by the volumes hedged; and if the fixed
price is lower than the NYMEX Price, then the Company pays the difference in
price multiplied by the hedged volume.
Approximately 79% of Ryder Scott's estimate as of January 1, 1996 of the
Company's expected production from proved producing wells for the fourth quarter
of 1996 is hedged at a weighted average price of $2.503. For calendar 1997,
approximately 31% of Ryder Scott's estimate as of January 1, 1996 of the
Company's expected production from proved producing wells is hedged at a
weighted average price of $2.233. The counter-party to all of the Company's
hedge positions is ECT. 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. See "Risk
Factors -- Effects of Price Risk Hedging." The Company's credit facility with
Union Bank requires the Company to maintain certain hedging positions. See
" -- Liquidity and Capital Resources -- Credit Facility."
CAPITAL EXPENDITURES AND FUTURE OUTLOOK
From November 1996 through the end of 1997, the Company anticipates
spending approximately $34 million to drill five exploratory prospects and three
proved undeveloped locations and connect eight existing wells to production
platforms. The Company's potential dry hole cost included in this capital
expenditure program is approximately $6 million. The Company plans to continue
its strategy of cluster development pursuant to which new wells will utilize
common infrastructure to reduce overall development cost. In addition, other
capital expenditures anticipated to be made by the Company prior to the end of
1997 are an estimated $900,000 to cover the Company's one percent share of the
construction costs for the proposed NGL plant, $200,000 to purchase the
Company's option to increase its interest in the NGL plant, an estimated
$750,000 to fund the Company's one percent interest in the proposed extension
and expansion of the DIGS, and, if the combination of the DIGS with the MPGS is
consummated, approximately $500,000 to purchase additional interest in DIGP from
MCN in order to maintain the Company's interest at one percent.
The Company plans to finance a majority of these expenditures from the
proceeds of this Offering, with the balance to be financed from cash flow from
operations and, to the extent necessary, borrowings under the Company's existing
line of credit. The relative portion of the funds actually provided by each of
these sources to the Company's development operations may vary, however,
depending on the results of the Company's operations and other factors beyond
the control of the Company, including the price of natural
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gas and oil. The Company estimates that these sources will be sufficient to meet
its financial obligations to fund its planned drilling and development
activities through the end of 1997, provided, that (i) there are no significant
decreases in gas prices beyond current levels or anticipated seasonal lows, (ii)
there are no significant decreases in gas production from existing properties
other than declines in production currently anticipated based on engineering
estimates of the decline curves associated with such properties and (iii)
drilling costs do not significantly increase from drilling costs recently
experienced by the Company. See "Risk Factors -- Volatility of Natural Gas and
Oil Prices," "-- Exploration and Development Risks" and " -- Availability of
Equipment and Personnel."
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 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. See "Risk Factors -- Substantial Capital Requirements."
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
capital. See "Risk Factors -- Substantial Capital Requirements."
EFFECTS OF INFLATION AND CHANGING PRICES
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.
ACCOUNTING MATTERS
The Company uses the successful efforts method of accounting for its oil
and gas properties. This results in the capitalization of certain exploration
charges and expensing of dry hole costs. The Company uses the units of
production method to depreciate its producing properties.
In January 1996, the Company adopted the provisions of SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of." SFAS 121 requires the Company to review its oil and gas
properties whenever events or changes in circumstances indicate that the
carrying amount of such assets may not be recoverable, and recognize a loss if
such recoverable amounts are less than the carrying amount. There have been no
impairment losses recognized as of June 30, 1996, but any future losses would be
included in depletion, depreciation, amortization and impairment in future
accounting periods.
On October 23, 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation," which establishes a fair value method for accounting
for stock-based compensation plans either through recognition or disclosure. The
Company adopted this standard in 1996 and will disclose the pro forma net income
(loss) and earnings (loss) per share amounts assuming the fair value method was
adopted on January 1, 1995 in its financial statements as of and for the year
ended December 31, 1996. The adoption of this standard will not impact the
Company's consolidated results of operations or financial position.
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BUSINESS AND PROPERTIES
THE COMPANY
OEDC is an independent energy company that focuses on the acquisition,
exploration, development and production of natural gas and on natural gas
gathering and marketing activities. The Company's integrated operations are
conducted in the Gulf of Mexico, primarily offshore Alabama and Louisiana. The
Company has established strategic alliances with several major energy companies
to conduct exploration and development activities and to construct and operate a
natural gas gathering system and a natural gas processing plant. Management
believes these relationships and its experiences in its core area of operations
provide the Company with unique growth opportunities.
The Company has interests in 21 lease blocks, all of which are operated by
the Company. On 14 of these blocks, the Company plans to connect eight existing
wells to production platforms and to drill five exploratory prospects and three
proved undeveloped locations by the end of 1997. The Company's estimated capital
expenditure budget for these activities from November 1, 1996 through December
31, 1997 is $34 million. See "-- Exploration and Development."
From January 1 through October 7, 1996, the Company drilled and completed
four exploratory wells offshore Alabama and offshore Louisiana. The Company has
drilled a fifth exploratory well offshore Alabama that was logged in October.
The one well drilled offshore Louisiana is currently producing and the Company
anticipates that construction of necessary production facilities offshore
Alabama and connection of the Alabama wells to such facilities will be completed
by the end of the first quarter of 1997.
In October 1996, the Company acquired a majority interest in North Padre
Island Block A-59 in federal waters offshore Texas. As part of the acquisition,
the Company acquired a platform with two wells, a satellite well and a flowline
to an interstate pipeline. Prior to the end of 1996, the Company intends to
drill two new platform wells with dual completions in shallow Miocene sands
under this property. See "-- Exploration and Development."
As of January 1, 1996, the Company had net proved natural gas reserves, as
estimated by Ryder Scott, of 20.3 Bcfe attributable to 11 gross (7.30 net) wells
offshore Alabama and Lousiana. From January 1 through October 7, 1996, the
Company drilled and completed four exploratory wells, completed the purchase of
an interest in North Padre Island Block A-59 and shot a proprietary seismic
survey over its one block offshore Mississippi. Based on a reserve report
prepared by Ryder Scott, these activities have added 14.87 Bcf of estimated net
proved reserves attributable to the Company's interests after giving effect to
the increase in the Company's interest in the four wells that will occur through
the application of the net proceeds of this Offering. See "Use of Proceeds."
Although no assurance may be given, the Company's experience under similar
circumstances has been that additional reserves will be attributed to its
interests in all such properties once production history has been established.
In October 1996, the Company entered into a joint venture agreement with a
subsidiary of Amoco pursuant to which the Company will evaluate proprietary 3-D
seismic data to identify prospects for joint exploration and development by the
parties on approximately 59,000 contiguous acres covering portions of 23 lease
blocks in the Gulf of Mexico. Of this total, approximately 14,000 acres are
currently leased by the Company or Amoco. Costs of drilling and development on
existing leases would 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 will be the operator of any prospects drilled under this
agreement. Unless renewed by mutual consent, the agreement terminates on October
1, 1997. See "-- Exploration and Development."
The Company operates the DIGS as a 95-mile non-jurisdictional pipeline
system offshore Alabama with a current capacity of 400 MMcf/d. The DIGS, which
the Company began developing in 1990, is the primary open-access gas gathering
system in federal waters serving the Mobile, Viosca Knoll and Destin Dome areas
of the Gulf of Mexico. In early 1996, the Company sold its 24% limited
partnership interest in DIGP, the partnership that owns the DIGS, for $19.1
million, and retained a one percent general partnership
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interest. The Company realized a pre-tax profit of $10.8 million on the sale.
See "-- Natural Gas Gathering."
The current partners in DIGP are the Company and subsidiaries of MCN and
PanEnergy. The Company's one percent interest in DIGP will increase to 15%
(subject to reduction in certain circumstances) when DIGP Payout occurs. The
Company and its DIGS partners recently announced a planned 65-mile extension of
the DIGS to gather new production that currently lacks adequate transportation
outlets. An additional planned 1997 expansion would create a dry gas gathering
system and a wet gas gathering system with a combined capacity of approximately
900 MMcf/d. See "-- Natural Gas Gathering."
In September 1996, DIGP entered into a letter of intent with MPGC to
combine the MPGS with the DIGS. The MPGS is a gathering system operated as a
nonjurisdictional facility in deeper waters south of the DIGS with a nominal
capacity of 300 MMcf/d. If consummated, the contribution of the assets and
liabilities of MPGC to DIGP would provide to DIGP a broader base of committed
supply and would create an additional outlet for the gas committed to the MPGS,
but would reduce the interest of the Company in DIGP to approximately .65%. The
Company intends to acquire from MCN, immediately prior to the closing of the
contribution by the MPGC partners, an interest in DIGP sufficient to cause the
Company to have a one percent interest in DIGP after the contribution of the
MPGS. In addition, as a result of the contribution of the MPGS to DIGP, the
interest in DIGP to be held by the Company after the occurrence of DIGP Payout
would be reduced to approximately 11.9%. Consummation of this transaction is
subject to numerous conditions, including the execution of definitive
agreements. See "-- Natural Gas Gathering."
In August 1996, the Company entered into an agreement to form a partnership
with MCN and PanEnergy for the construction and development of an NGL plant
onshore Alabama. This plant will be constructed in stages and when completed is
expected to have a capacity of 900 MMcf/d. The plant would be the first NGL
plant in Alabama available for processing existing Mobile area production and
would be available to process additional volumes from the Main Pass and Viosca
Knoll areas of the Gulf of Mexico. The total cost of this plant is estimated to
be $90 million. The Company will initially have a one percent cost and revenue
interest in the partnership. In addition, the Company will acquire from MCN and
PanEnergy for $200,000 an option to purchase up to an additional 32 1/3%
interest in the partnership during the first three years of plant operations for
32 1/3% of the depreciated book value of the plant, increased by 12% each year.
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.
OIL AND GAS PROPERTIES
SOUTH TIMBALIER, OFFSHORE LOUISIANA
In 1988, the Company led several partners in an acquisition from Shell 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
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undeveloped acres in the block. The Company currently has an 80% working
interest in the 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 with a capacity of 25 MMcf/d, known as the B
Platform, and laid a two mile flowline to the nearby interstate pipeline. The
adequacy of the Company's engineering and construction capabilities was
confirmed when the B Platform sustained only minimal damage from Hurricane
Andrew in 1992. The original B-6 well ceased production in 1993 due to
mechanical problems. The Company intends to attempt to repair problems in the
lower completion of this well to restore production and is evaluating the
potential use of artificial formation fracturing technology to improve the
productive capability of the well. The Company has identified three side track
locations which can be drilled from this wellbore when production from the lower
completion is depleted.
In response to a proposal from the Company, Amoco agreed to make its
seismic data available to OEDC in exchange for an option for 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 the past twelve months. The
first well, known as the B-7 well, 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, 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.
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 of 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 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 1980's, 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
two to nine miles south of central Dauphin Island, the barrier island due south
of Mobile, Alabama. These blocks formerly had 15 owners and four different
operators. This aggregation of properties became the basis for the Company's
first cluster development. Prior to drilling, the Company shot a proprietary,
high resolution, high density seismic survey over its prospects. By controlling
the acquisition and processing parameters of this data instead of following the
historical practice of relying on regional data shot for much deeper horizons,
the Company was able to focus on the specific zones of interest and correlate
data effectively among blocks.
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
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<PAGE>
facilities to handle up to 50 MMcf/d of gas. Initial production commenced within
four months of spudding the first 822 well. The Company set caissons at four
remote locations and laid flowlines from those wells to the central platform.
Three of these cluster wells were drilled in the state waters of Alabama under
rigorous environmental scrutiny, including zero discharge regulations. One
reservoir was beneath a shipping fairway necessitating the Company's first
horizontal 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 $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.
Several of these wells were drilled as high deliverability wells with large
tubing programs and long horizontal completions in the potentially productive
sands. 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 seven MMcf/d from four
wellbores with one additional recompletion scheduled in 1997 to access
additional proved reserves behind pipe.
The Company has acquired ownership percentages (ranging from 15% to 80%) in
five blocks in offshore Alabama east of Mobile 959/960 and is the operator of
all five blocks. The Company believes that all five blocks may be developed from
the Mobile 959/960 platforms making use of excess platform 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 reserves
attributable to four wellbores drilled by a former operator of these leases.
These wells are in 45 to 100 feet of water and are temporarily abandoned
awaiting the installation of caissons, connection of the wells to the surface
and construction of flowlines to the platform at Mobile 960. 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.
PROPOSED VK CLUSTERS. The Company owns 10 additional lease blocks in VK,
encompassing over 54,720 gross (47,808 net) acres, on which it has identified
five geophysically defined Miocene exploratory prospects and one proved
undeveloped location that it is scheduled to drill and develop by the end of
1997. In addition, the Company has four wells on these blocks, which were
drilled since June 30, 1996, that the Company is scheduled to connect to
platforms by the end of 1997. The Company estimates that the combined cost for
these projects will be approximately $25 million. A portion of the proceeds of
this Offering will be used for the drilling and development of these prospects
and the connection of these wells to the production platforms. See "-- The
Company" and "Use of Proceeds." These 10 lease blocks are located in VK, 30
to 50 miles south of coastal Alabama. The Company intends to develop these
prospects and complete the connection of these wells to production platforms in
four additional production clusters. These prospects are geologically on trend
with other producing reservoirs in the area. The Company is the operator of all
the blocks and holds a working interest on these blocks ranging from 75% to
100%. Net acres and working interests set forth in this paragraph give effect to
the increase in the Company's interest in SDPII that will occur upon application
of the proceeds of this Offering. See "Use of Proceeds."
Phase one of this development involves the connection of five wells with
proved reserves and the drilling of five exploratory wells in 100-120 foot water
depths to test target sands at depths ranging from
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<PAGE>
1,000-2,500 feet. The Company expects drilling to be completed by the end of
1997. Caissons will be set on all commercial wells, except one location that
will be the site of an unmanned platform with appropriate production and
compression facilities. Operating personnel would be shared with the Mobile 959
platform, where production would be monitored remotely through an electronic
communication system. The Company believes that this plan will help to avoid
expensive duplication of lease operating costs and infrastructure on these
blocks. Flowlines would connect all wells to production platforms where they
will interconnect to the DIGS.
In drilling the five exploratory wells on these clusters, the Company
intends to utilize vertical holes drilled by slim hole techniques in order to
reduce costs. As a result, the wells will be physically constrained to a maximum
production rate of five MMcf/d. Although these wells, if successful, will be
capable of lower production rates than are possible in conventional wells, the
Company's anticipated cost to drill and complete these wells is less than the
cost of conventional wells.
The Company drilled one exploratory well on the eastern cluster in August
1996. The well was drilled to a total vertical depth of 2,165 feet. Three of the
five exploratory wells that the Company intends to drill are targeted for
drilling on the eastern cluster. The Company has an agreement to share a nearby
Enron Oil and Gas Company ("EOG") platform with EOG acting as contract
operator for the Company with respect to processing and compressing gas. The
Company will pay EOG for the use of its facilities and personnel. The Company
would have about 15 MMcf/d of production capacity on the EOG platform and the
same remote well monitoring capability as on other properties.
The western cluster has one well that was drilled and temporarily abandoned
by a prior operator. This well has been completed in a 2,400 foot sand and
awaits the installation of a caisson structure and a flowline to a platform for
processing and compression. The Company is evaluating the prospect and will
decide whether to drill an additional well before year end 1996. Discussions are
in progress with neighboring operators about use of their platforms and
facilities to handle any gas that may be produced from the existing well and any
wells drilled on the prospect. The Company expects to finalize a suitable
development plan before year end 1996. The two leases that comprise the western
cluster will expire by the end of 1996 if the MMS is not given satisfactory
evidence of progress toward commercial production.
At the southern cluster, the Company is discussing a combined development
with EOG involving EOG's two proved undeveloped wells on nearby blocks. Two of
the five exploratory wells are targeted for drilling on this cluster. The
Company and EOG have preliminarily scheduled concurrent development of the
blocks in the first half of 1997. The Company anticipates that production from
the blocks would be flowed to the EOG platform near the eastern cluster for
gathering.
Three wells were drilled by the Company during August, September and
October 1996 on the center cluster. These wells encountered potentially
productive sands at total vertical depths of 1,290, 1,190 and 1,380 feet,
respectively. The Company anticipates installing an unmanned platform on this
cluster by the end of the first quarter of 1997.
The drilling, development and completion of wells and the installation of
facilities on the proposed VK clusters is subject to all the risks associated
with oil and gas operations. No assurance may be given that the drilling of
these wells will be completed or that delays and increased costs will not reduce
the attractiveness of these wells. Further, if the wells are completed, no
assurance may be given that the wells will be a commercial success. See "Risk
Factors -- Exploration and Development Risks."
VK 24 DEVELOPMENT. The Company acquired VK 24 in 1993 as a producing
property. The development is located due south of Pascagoula, Mississippi and
production has declined to less than one MMcf/d with produced water. The Company
has recently evaluated a proprietary high resolution seismic grid over the
property and has identified an updip proved undeveloped drilling location. The
Company commenced drilling on this location in October, 1996. The Company is
drilling this well from an existing braced caisson which, if the well is
successful, will allow production to commence immediately upon completion. The
Company has budgeted approximately $1.0 million for expenditure on this well
prior to the end of 1996. The drilling and development of VK 24 is subject to
all of the risks associated with oil and gas operations,
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<PAGE>
and no assurance may be given that drilling operations will be completed or that
the well will be a commercial success. See "Risk Factors -- Exploration and
Development Risks."
NORTH PADRE ISLAND, OFFSHORE TEXAS
In October 1996, the Company acquired a 60.6% working (44% net revenue)
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. Prior to the end of 1996 the Company intends to drill two new wells
with dual completions in the shallow Miocene sands. Based on a reserve report
prepared by Ryder Scott dated October 7, 1996, approximately 6.16 Bcf of
estimated net proved natural gas reserves are attributable to the Company's
interest in shallow Miocene sands under this property. The Company has estimated
that the cost to the Company to drill and complete these wells is approximately
$2.1 million. A portion of the proceeds of this Offering will be used for the
drilling of these wells. See "Use of Proceeds." 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. See "Risk
Factors -- Exploration and Development Risks."
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 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.
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<PAGE>
NATURAL GAS RESERVES
The following table sets forth estimates of the Company's (i) proved
natural gas reserves at January 1, 1996, which were prepared by Ryder Scott,
independent petroleum engineers, in accordance with regulations promulgated by
the Commission and (ii) present value of proved reserves of natural gas at
January 1, 1996. The price used in the table below was based on the price of
natural gas at December 31, 1995, with consideration of price changes only to
the extent provided by contractual arrangements in effect as of such date. As of
December 31, 1995, the average price of natural gas was $2.01 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 Prospectus. See "Risk
Factors -- Uncertainty of Estimates of Reserves and Future Net Revenue."
NATURAL GAS RESERVE INFORMATION
AS OF
DECEMBER 31, 1995
--------------------
(DOLLARS IN
THOUSANDS)
Net Proved Reserves (MMcfe):
Developed producing............. 11,074
Developed nonproducing.......... 2,536
Undeveloped..................... 6,701
--------------------
Total proved............... 20,311
====================
Present Value of Estimated Future Net
Revenue:
Developed producing............. $ 16,963
Developed nonproducing.......... 2,691
Undeveloped..................... 6,790
--------------------
Total proved............... $ 26,444
====================
From January 1 through October 7, the Company drilled and completed four
exploratory wells, completed the purchase of a majority interest in North Padre
Island Block A-59 and shot a proprietary seismic survey over its one block
offshore Mississippi. Based on a reserve report prepared by Ryder Scott dated
October 7, 1996, these activities have added 14.87 Bcf of estimated net proved
reserves attributable to the Company's interests after giving effect to the
increase in the Company's interest in the four wells that will occur through the
application of the net proceeds of this Offering. See "Use of Proceeds."
Although no assurance may be given, the Company's experience under similar
circumstances has been that additional reserves will be attributed to its
interests in all such properties once production history has been established.
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 amortization
attributable to the Company's properties during each of the three years ended
December 31, 1995 and during the six months ended June 30, 1996.
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<PAGE>
NATURAL GAS PRODUCTION,
AVERAGE SALES PRICE AND PRODUCTION COSTS
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED
------------------------------- JUNE 30,
1993 1994 1995 1996
--------- --------- --------- ----------
<S> <C> <C> <C> <C>
Net natural gas production
(MMcfe)(1)......................... 673 3,686 3,668 2,528
Average sales price (per Mcfe)(2).... $ 2.59 $ 1.50 $ 1.68 $ 2.20
Production (lifting) costs (per
Mcfe).............................. $ 0.85 $ 0.38 $ 0.51 $ 0.35
DD&A (per Mcfe)...................... $ 0.53 $ 0.57 $ 1.50 $ 1.14
</TABLE>
- ------------
(1) The Company had immaterial amounts of condensate (oil) production during
such years.
(2) Prices include the effects of hedging transactions. See "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 three years ended December 31,
1995 and during the six months ended June 30, 1996.
DRILLING ACTIVITY
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS
DECEMBER 31, ENDED
------------------------------- JUNE 30,
1993 1994 1995 1996
--------- --------- --------- ----------
<S> <C> <C> <C> <C>
Exploratory
Net productive wells............ 4.66 4.46 3.59 --
Net dry holes................... -- 0.8 -- --
Development
Net productive wells............ -- -- -- --
Net dry holes................... -- -- -- --
--------- --------- --------- ----------
4.66 5.26 3.59 --
========= ========= ========= ==========
</TABLE>
Subsequent to June 30, 1996 the Company has drilled five gross exploratory
wells, no exploratory dry holes, and no development wells. All of the wells
drilled subsequent to June 30, 1996 were drilled pursuant to the SDPII Program.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Financing Activities -- South
Dauphin II Limited Partnership."
The following table sets forth the Company's ownership interest in
leaseholds as of October 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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<PAGE>
LEASEHOLD INTERESTS
<TABLE>
<CAPTION>
DEVELOPED(1) UNDEVELOPED
--------------------------- ---------------------------
GROSS ACRES NET ACRES GROSS ACRES NET ACRES(2)
----------- ------------ ----------- ------------
<S> <C> <C> <C> <C>
Offshore Alabama..................... 11,520 11,520 86,429 62,587
Offshore Louisiana................... 3,984 3,134 -- --
Offshore Mississippi................. 5,760 4,608 -- --
Offshore Texas....................... -- -- 5,760 3,485
----------- ------------ ----------- ------------
Total........................... 21,264 19,262 92,189 66,072
=========== ============ =========== ============
</TABLE>
- ------------
(1) Acres spaced or assignable to productive wells.
(2) Gives effect to the increase in the Company's interest in SDPII that will
occur through the application of the net proceeds of this Offering. See
"Use of Proceeds."
As of October 31, 1996, and after giving effect to the increase in the
Company's interests in five wells that will occur through the application of the
net proceeds of this Offering, the Company owned interests in 16 gross (10.90
net) productive gas wells (including producing wells and wells capable of
production). One of these wells has multiple completions.
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. See "Risk
Factors -- Availability of Equipment and Personnel."
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 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 liability, operator's extra expenses, physical damage on certain
assets, employer's liability, automobile, workers' compensation and
38
<PAGE>
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 MMS,
which is secured by restricted cash balances on deposit at a commercial bank.
The sum on deposit is currently $1.4 million 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. While 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. While 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 ECT accounted for approximately 80% of revenue
in 1994 and 1995 and during the first six months of 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 "Management's Discussion of Financial Condition and Results of
Operations -- Hedging Activities." The Company accounts for its commodity swaps
as hedging activities and, accordingly, gains or losses are included in oil and
gas revenue for the period production was hedged. See "Risk Factors -- Effects
of Price Risk Hedging."
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. See "Risk Factors -- Volatility of Natural Gas
and Oil Prices."
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
39
<PAGE>
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. See "Risk
Factors -- Competition."
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
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 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, 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 3/4 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 3/4 pipeline to directly connect the DIGS to the
interstate pipeline transportation network and enable the full utilization of
the three 12 3/4 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
40
<PAGE>
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 3/4,
12 3/4 and 8 3/4 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.
CURRENT OPERATIONS
After the purchase of 99% of DIGP, MCN retained the Company to manage and
operate the system. 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 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 $55,000 and the Company's
partnership interest will increase from one percent to 15% when DIGP Payout
occurs, subject to reduction to 13%, however, if the Company does not exercise
the option to increase its interest in the partnership for the NGL facility. 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 2002,
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.
Under the terms of the DIGP partnership agreement, a change of control
occurs (i) upon the failure of any two of Messrs. Strassner, Kiesewetter and
Anderson to be actively involved in the management and operation of the general
partner of DIGP to substantially the same degree as they are presently involved
(other than as a result of their death) or (ii) if any two of Messrs. Strassner,
Kiesewetter and Anderson sells more than 75% of their ownership in the Company
after this Offering. A change of control prior to the earlier of DIGP Payout or
February 28, 2001 would prevent the Company's interest in DIGP from increasing
above its current one percent general partnership interest, and a change of
control at any time would result in removal of the Company as manager of the
DIGS.
The DIGS has a design pressure of 1440 psi and a maximum operating pressure
of 1250 psi. It has an estimated throughput capacity of up to 400 MMcf/d,
depending on where gas enters the system, which could be expanded with looping
and onshore compression. The DIGS is currently gathering an average of 185
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 before the end of
1997.
Customers on the system currently include Chevron U.S.A. Inc., Union Oil
Company of California, BP Exploration & Oil, 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 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
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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. Design activity and field supervision has historically
been performed by independent engineering and consulting firms, subject to
supervision by Company personnel. The Company is paid a construction supervision
fee slightly in excess of one percent of all new construction costs.
EXTENSIONS AND EXPANSION
DIGP is contractually obligated to build approximately 10 miles of 129 line
to connect a production platform operated by EOG (VK 124) and one operated by
the Company (VK 121) to the DIGS. Although both lines are expected to be
operational before the end of 1996, construction projects are subject to delays
beyond the control of the Company and no assurance may be given as to the timing
of the completion of this project.
DIGP has announced plans to construct a 65 mile, 249 diameter pipeline
extension from Mobile Block 73 (where the DIGS has a pigging platform) to
connect new supply sources in the east Main Pass area, utilizing existing DIGS
capacity. In 1997, it is anticipated that the DIGS system will be reconfigured
to serve the differing gathering needs of area producers into a dry gas system
and a wet (I.E., including gas liquids) gas system each of which will be
operated separately by DIGP. The Company anticipates that the wet system will
have a design pressure of 2,200 psi and a maximum operating pressure of 1,800
psi. The reconfiguration would be accomplished by the construction of a 249 line
from Mobile 73 to a site near DIGP's existing meter site at Coden, Alabama. At
that site, the new wet gas system would connect to the NGL plant proposed for
construction by the Company, MCN and PanEnergy (see " -- Natural Gas
Processing") and with the interstate gas pipeline systems. This second
construction phase would increase combined capacity of the two systems to 900
MMcf/d. DIGP's preliminary budget for the 1996-97 expansion and reconfiguration
of the system is approximately $75 million, of which the Company's share would
be one percent, or approximately $750,000.
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.
PROPOSED COMBINATION WITH MAIN PASS GATHERING COMPANY
In September 1996, DIGP entered into a non-binding letter of intent with
the partners of MPGC for a contribution of the assets and liabilities of MPGC to
DIGP. The partners of MPGC are subsidiaries of PanEnergy, Coastal Corporation
and CNG Energy Services Corporation. MPGC owns the MPGS, which is a gas
gathering system operated as a nonjurisdictional facility in the deeper waters
of the Main Pass Area for delivery to Texas Eastern Transmission Company at Main
Pass Block 164, offshore Louisiana. The combination of the two systems would
allow DIGP to have a broader supply base and would create an additional outlet
through the DIGS for the gas committed to the MPGS.
The MPGS is a 50 mile system approximately 30 miles south of the DIGS. Both
the DIGS, as part of the currently planned expansion of DIGP into the east Main
Pass Area, and the MPGS would have receipt points at Main Pass Block 225. It has
an estimated throughput capacity of up to 300 MMcf/d, but is currently gathering
an average of 180 MMcf/d due to capacity restrictions downstream. Producers
attached to the MPGS will have the option to have their gas gathered for
delivery at the terminus of the DIGS onshore Alabama or at the existing terminus
of the MPGS offshore Louisiana.
Customers of the MPGS currently include Coastal Oil & Gas Corporation, CNG
Producing Company, Elf Aquitaine Oil Program, Inc., Santa Fe Energy Resources,
Inc., Chieftain International (U.S.) Inc., Oryx Gas Marketing Limited
Partnership and Piquant Inc. Most commitments to the MPGS are reserve life
commitments.
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If this transaction is consummated, the Company would continue to be the
operator of the combined systems and its monthly management fee would increase
to approximately $62,500. Under the terms of the proposal, each of the existing
partners in DIGP, including the Company, would have their interests in DIGP
reduced as a result of the contribution of the MPGS. The reduction would be
determined based on a formula that compares the book value, subject to certain
adjustments, of the DIGS and the MPGS, as of December 31, 1996. As a result of
the application of a formula, the interest of the Company in DIGP after the
contribution of the MPGS would be approximately .65%. The Company intends to
acquire from MCN, immediately prior to the closing of the contribution by the
MPGC partners, an interest in DIGP sufficient to cause the Company to have a one
percent interest in DIGP after the contribution of the MPGS. The Company expects
to pay MCN approximately $495,000 for this interest. The interest in DIGP to be
earned by the Company on the occurrence of DIGP Payout would also be reduced by
the application of a formula based on current estimates of the book value of the
respective systems and planned extension. If the transaction with MPGC as
completed the interest to be held by the Company in DIGP on the occurrence of
DIGP Payout would be approximately 11.9%.
The letter of intent contemplates completion of the contribution of the
MPGS to DIGP in December 1996, subject to a number of conditions. The conditions
include, among others, the execution of appropriate documentation, completion of
the reviews of the assets and liabilities of DIGP and MPGC, approval of the
Board of Directors of each of the partners of DIGP and MPGC and approval under
the Hart-Scott-Rodino Antitrust Improvements Act of 1976. No assurance may be
given that definitive agreements will be executed; or that the proposed
combination of DIGP with the partners of MPGS will be completed or that, if
completed, it will occur on the schedule originally projected. Whether or not
the transaction with MPGS occurs, the Company will continue with its planned
extension and expansion into the Main Pass area.
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. This is particularly true in the Main Pass area into
which DIGP is currently expanding, since it is entering a new area with
significant uncommitted reserves and several large pipeline companies within
reasonable reach of expansions into this area. See "Risk
Factors -- Competition."
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
The Company has recently entered into an agreement to form a partnership
with MCN and PanEnergy to construct, own and operate a natural gas liquids
processing plant onshore in southern Alabama. The plant would extract
liquifiable hydrocarbons from natural gas prior to delivery of the natural gas
to the interstate system. Much of the gas produced in Mobile, Viosca Knoll and
Main Pass has a high gas liquids content. As 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
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liquifiable hydrocarbons in their natural gas production. With the new plant,
the producers will be able to achieve a higher total price for the sale of their
gas and make attachment to the DIGS more desirable because it will be the only
system that will deliver their gas in proximity to the liquids plant. The
Company, MCN and PanEnergy continue to develop and evaluate design, construction
and market information for the proposed plant. No assurance may be given that
the plant ultimately will be constructed or completed.
The partnership will initially be owned 49.5% by each of MCN and PanEnergy
and one percent by the Company. The Company will acquire from MCN and PanEnergy
for $200,000 an option to buy an additional 32 1/3% partnership interest for
three years after the inception of plant operations at 32 1/3% of the
depreciated book value of the plant (using 25 year straight line depreciation)
increased by 12% each year. The Company will be required to obtain financing in
order to exercise the option to increase its interest, and while the Company
anticipates that such financing will be available, no assurance may be given in
this regard. See "Risk Factors -- Substantial Capital Requirements." If the
Company does not exercise the option to acquire the additional partnership
interest, the Company is obligated to assign to each of PanEnergy and MCN one
fourteenth of the interest to which the Company is entitled on the occurrence of
DIGP Payout. PanEnergy, which is one of the largest liquids processors in the
country, will construct and operate the project for the partners. Preliminary
estimates by the Company are that this will be a $90 million construction
project, which will be constructed in stages and will have an initial capacity
of 600 MMcf/d and a capacity of 900 MMcf/d when completed. The Company expects
the plant to be operational in the first quarter of 1998. No assurance may be
given that, if constructed, the plant will be completed within the initial
estimated construction cost or on the anticipated schedule.
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 October 31, 1996, the Company leased 17 employees from a corporation
owned by a director of the Company, none of whom were represented by any labor
union. See "Management -- Certain Transactions." These individuals will become
employees of the Company as soon as practicable after the completion of the
Combination. 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.
GOVERNMENTAL 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
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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 NGA and 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 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 Company operates the DIGS as a gas gatherer exempt from the FERC's
jurisdiction under the NGA. In February 1996, the FERC issued a Statement of
Policy concerning gas gathering on 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 is subject to regulation of its gathering operations under the
OCSLA. This statute requires the DIGS, 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, as it
currently exists and after giving effect to its planned extension and expansion
and the potential combination
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with MPGS, meets the criteria of the modified primary function test and is
exempt from FERC jurisdiction under the NGA. However, neither the Company nor
DIGP has sought a formal declaration from the FERC confirming its status as an
exempt gatherer. The Company expects DIGP to seek such an order in the near
future. However, no assurance may be given that the FERC will concur with the
Company's view. A determination that the DIGS is subject to FERC's jurisdiction
would require that the Company comply with FERC regulation. The Company does not
believe such a determination would have a material adverse effect on the
Company's operations. See "Risk Factors -- FERC Regulation Risks."
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 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, 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.
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
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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.
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. See
"Risk Factors -- Environmental, Health and Safety Regulation and Risks."
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
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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 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
30, 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 party" includes 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 to 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, to 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
48
<PAGE>
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 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.
LITIGATION
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 FERC under Section 311 of the NGPA 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 allege 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 plaintiffs from further
pursuing the project independently. The plaintiffs also allege 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 allege
"millions of dollars in profits" as actual damages and also seek the award of
unspecified punitive damages, attorneys' fees, pre- and post-judgment interest,
and costs of suit.
The Company denies the plaintiffs' allegations and is vigorously defending
this matter. The Company has raised the affirmative defenses of statute of
frauds, statute of limitations, laches, waiver and estoppel, and intends to file
a motion for summary judgment on its defenses. Discovery is ongoing in the case
and a trial date has not been set. 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 operation, the Company does not believe that the final
resolution of this case will result in a material liability to the Company.
49
<PAGE>
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information with respect to the
directors and executive officers of the Company:
NAME AGE POSITION
- ----------------------------- --- ------------------------------------------
David B. Strassner........... 38 President and Class I Director
Douglas H. Kiesewetter....... 43 Executive Vice President, Chief Operating
Officer and Class II Director
R. Keith Anderson............ 42 Vice President and Class III Director
Joseph L. Savoy, Jr.......... 45 Vice President -- Engineering
Matthew T. Bradshaw.......... 30 Vice President and Treasurer
David R. Albin............... 37 Class III Director
R. Gamble Baldwin............ 73 Class I Director
G. Alan Rafte................ 42 Class II Director
DAVID B. STRASSNER has served as President and a director of the Company
since the Company's formation in January 1988. For two years prior to forming
the Company, Mr. Strassner was an independent explorationist specializing in the
Gulf of Mexico. For five years prior to that time, Mr. Strassner was a
geophysicist employed by Amoco Production Company. Mr. Strassner is a director
of Gulf Coast Bank and Trust, New Orleans, Louisiana, and God's World
Publications, Asheville, North Carolina. Mr. Strassner holds a B.S. degree in
Geology from the University of North Carolina at Chapel Hill.
DOUGLAS H. KIESEWETTER has served as Executive Vice President, Chief
Operating Officer and a director of the Company since the Company's formation in
January 1988. From June 1984 through October 1987, Mr. Kiesewetter was an
executive officer of Cartrex Corporation, a high technology company in the
computer media business co-founded by Mr. Kiesewetter. Serving as Chief
Financial Officer for the first year, Mr. Kiesewetter thereafter served as
President of the start-up company. Mr. Kiesewetter also has served as Chairman
(1979 to present) of Christian Community Foundation, a charitable foundation
founded by Mr. Kiesewetter, and as President (1975 - present) of CSA Financial
Services, an international consulting firm founded by Mr. Kiesewetter, initially
specializing in financial planning for closely-held businesses and high net
worth individuals and since 1987 operating as an employee leasing company from
which the Company has obtained its employees. Mr. Kiesewetter has a B.A. in
History from Emory University and an M.B.A. from North Texas State University.
R. KEITH ANDERSON has served as Vice President and a director of the
Company since 1989. Prior to that time Mr. Anderson served as Vice President
(1988-1989) of Endevco, Inc. in charge of managing an independent marketing
division, and as President, Chief Executive Officer and a director (1987-1988)
of Stellar Gas Company, an independent natural gas marketer founded by Mr.
Anderson. For two years prior to that, Mr. Anderson served as Business Manager
of Hadson Gas Systems Corporation, a start-up natural gas marketer. From 1979
through 1984 Mr. Anderson served in various capacities for Texas Oil and Gas.
Mr. Anderson holds a B.B.A. from Texas Tech University and a J.D. from the
Pepperdine University School of Law.
JOSEPH L. SAVOY, JR. has served as Vice President of Engineering since May
1994. Mr. Savoy began his career with Amoco Production Company, where he worked
in drilling, completions, operations, reservoir engineering and construction.
From March 1989 to May 1994 Mr. Savoy was Chief Engineer for Operators and
Consulting Services, Inc., a firm providing contract consulting services to the
oil and gas industry, where he was assigned in 1991 to work on the Company's
account. Mr. Savoy has more than twenty years experience in the oil and gas
business, and holds a B.S. degree in Petroleum Engineering from the University
of Southwestern Louisiana.
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<PAGE>
MATTHEW T. BRADSHAW joined the Company in 1993 and serves as Vice President
of Finance. Prior to joining the Company, he worked as an energy banker from
1990 to 1992 with Hibernia Bank and from 1992 to 1993 with First National Bank
of Commerce, each in New Orleans, Louisiana. Mr. Bradshaw has a B.S. degree from
Auburn University and an M.B.A. from Baylor University.
DAVID R. ALBIN has been a director of the Company since September 1992.
Since November 1988, Mr. Albin has been a limited partner of G.F.W. Energy, L.P.
(" GFW" ), which in turn serves as general partner of NGP, an investment fund
organized to make equity-related investments in the North American oil and gas
industry. Since November 1988, Mr. Albin has been responsible for the management
of NGP's portfolio. He is a member/manager of the limited liability companies
which are the general partners of Natural Gas Partners II, L.P. ("NGP II" )
and Natural Gas Partners III, L.P. ("NGP III" ). From December 1984 until
November 1988, Mr. Albin was employed by Bass Investment Limited Partnership,
where he was also responsible for portfolio management.
R. GAMBLE BALDWIN has been a director of the Company since September 1992.
Since November 1988, he has been the general partner of GFW. He is also a
member/manager of NGP II and NGP III, and is active in the management of both.
From 1974 until November 1988, Mr. Baldwin was a Managing Director of The First
Boston Corporation, an investment banking firm, specializing in all aspects of
the natural gas business. Mr. Baldwin has been a member of the International
Advisory Board of Creditanstalt Bankverein, Vienna, Austria, since 1982, and a
director of Coflexip Stena Offshore, a provider of industrial technology
oilfield equipment and service, since 1993.
G. ALAN RAFTE was elected to the Board of Directors of the Company in
August 1996. For more than the past five years, Mr. Rafte has been a partner in
the law firm of Bracewell & Patterson, L.L.P., specializing in energy law and
finance. Mr. Rafte holds a Bachelor of Arts degree from Syracuse University and
a J.D. from Emory Law School.
The Company's Certificate of Incorporation provides for a Board of
Directors of not less than six nor more than nine, divided into three classes
having as equal a number of directors as practicable. The members of each class
generally serve three-year staggered terms with one class to be elected at each
annual meeting of stockholders. The terms of the Class I, II and III directors
expire at the Company's 1997, 1998 and 1999 annual meetings, respectively. The
Company's executive officers are elected by the Board of Directors for one-year
terms and serve at the discretion of the Board of Directors.
The Board of Directors has established audit and compensation committees.
The Audit Committee currently consists of Messrs. Baldwin and Rafte, neither of
whom is an employee of the Company. The Audit Committee will review the general
scope of the audit conducted by the Company's independent auditors, the fees
charged therefor and matters relating to the Company's internal control systems.
In performing its functions, the Audit Committee will meet separately with
representatives of the Company's independent auditors and with representatives
of senior management.
The Compensation Committee currently consists of Messrs. Albin and Rafte,
neither of whom is an employee of the Company. The Compensation Committee will
administer the Company's 1996 Stock Awards Plan, and in this capacity will make
all option grants or awards to Company employees, including executive officers,
under such plans. In addition, the Compensation Committee is responsible for
making recommendations to the Board of Directors with respect to the
compensation of the Company's President and its other executive officers, and is
responsible for the establishment of policies dealing with various compensation
and employee benefit matters for the Company.
Directors currently receive no compensation for serving on the Board of
Directors. Upon completion of this Offering, each director who is not also an
officer or employee of the Company will receive an annual fee in cash of $15,000
per year for service on the Board. The amounts payable to Messrs. Albin and
Baldwin will be paid to NGP pursuant to a Financial Advisory Services Agreement.
See "-- Certain Transactions."
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<PAGE>
1996 STOCK AWARDS PLAN
The Company recently adopted the Offshore Energy Development Corporation
1996 Stock Awards Plan (the "1996 Stock Awards Plan"). The 1996 Stock Awards
Plan is intended to provide key employees with an opportunity to acquire a
proprietary interest in the Company and additional incentive and reward
opportunities based on the profitable growth of the Company and to aid the
Company in attracting and retaining outstanding personnel. The 1996 Stock Awards
Plan provides for the granting of options (either incentive stock options within
the meaning of Section 422(b) of the Internal Revenue Code of 1986, as amended
(the "Code"), or options that do not constitute incentive stock options
("nonqualified stock options")), restricted stock awards, stock appreciation
rights, performance awards, and phantom stock awards, or any combination
thereof. The 1996 Stock Awards Plan covers an aggregate of 835,000 shares of
Common Stock (subject to certain adjustments in the event of stock dividends,
stock splits and certain other events).
GRANTS. Effective as of the closing of this Offering, the Company will
have granted options to purchase 540,000 shares at an exercise price equal to
the public offering price. In addition, effective as of the closing of this
Offering, the Company will exchange certain outstanding nonqualified stock
options, which were granted prior to the adoption of the 1996 Stock Awards Plan
and have an exercise price of $3.61 per share, for an aggregate of 187,580
options having the same exercise price under the 1996 Stock Awards Plan.
ADMINISTRATION. The 1996 Stock Awards Plan is administered by the
Compensation Committee. The Compensation Committee has the power to determine
which employees will receive an award, the time or times when such award will be
made, the type of the award and the number of shares of Common Stock to be
issued under the award or the value of the award. Only persons who at the time
of the award are key employees of the Company or of any subsidiary of the
Company are eligible to receive awards under the 1996 Stock Awards Plan.
OPTIONS. The 1996 Stock Awards Plan provides for two types of options:
incentive stock options and nonqualified stock options. The Compensation
Committee will designate the key employees to receive the options, the number of
shares subject to the options, and the terms and conditions of each option
granted under the 1996 Stock Awards Plan. The term of any option granted under
the 1996 Stock Awards Plan shall be determined by the Compensation Committee;
provided, however, that the term of any incentive stock option cannot exceed ten
years from the date of the grant and any incentive stock option granted to an
employee who possesses more than 10% of the total combined voting power of all
classes of stock of the Company or of its subsidiary within the meaning of
Section 422(b)(6) of the Code must not be exercisable after the expiration of
five years from the date of grant. No option may be exercised earlier than six
months from the date of grant. The exercise price per share of Common Stock of
options granted under the 1996 Stock Awards Plan will be determined by the
Compensation Committee; provided, however, that an incentive stock exercise
price cannot be less than the fair market value of a share of Common Stock on
the date such option is granted (subject to adjustments). Further, the exercise
price of any incentive stock option granted to an employee who possesses more
than 10% of the total combined voting power of all classes of stock of the
Company or of its subsidiaries within the meaning of Section 422(b)(6) of the
Code must be at least 110% of the fair market value of the share at the time
such option is granted. The exercise price of options granted under the 1996
Stock Awards Plan will be paid in full in a manner prescribed by the
Compensation Committee. The 1996 Awards Plan permits holders of options, with
approval of the Compensation Committee, to relinquish all or any part of the
unexercised portion thereof in exchange for replacement options under certain
circumstances.
RESTRICTED STOCK AWARDS. Pursuant to a restricted stock award, shares of
Common Stock will be issued or delivered to the employee at any time the award
is made without any cash payment to the Company, except to the extent otherwise
provided by the Compensation Committee or required by law; provided, however,
that such shares will be subject to certain restrictions on the disposition
thereof and certain obligations to forfeit such shares to the Company as may be
determined in the discretion of the Compensation Committee. The restrictions on
disposition may lapse based upon (a) the Company's
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<PAGE>
attainment of specific performance targets established by the Compensation
Committee that are based on (i) the price of a share of Common Stock, (ii) the
Company's earnings per share, (iii) the Company's income, (iv) the income of a
business unit of the Company designated by the Committee, (v) the return on
stockholders' equity achieved by the Company, or (vi) the Company's pre-tax cash
flow from operations, (b) the grantee's tenure with the Company, or (c) a
combination of both factors. The Company retains custody of the shares of Common
Stock issued pursuant to a restricted stock award until the disposition
restrictions lapse. An employee may not sell, transfer, pledge, exchange,
hypothecate, or otherwise dispose of such shares until the expiration of the
restriction period. However, upon the issuance to the employee of shares of
Common Stock pursuant to a restricted stock award, except for the foregoing
restrictions, such employee will have all the rights of a stockholder of the
Company with respect to such shares, including the right to vote such shares and
to receive all dividends and other distributions paid with respect to such
shares.
STOCK APPRECIATION RIGHTS. A stock appreciation right permits the holder
thereof to receive an amount (in cash, Common Stock, or a combination thereof)
equal to the number of stock appreciation rights exercised by the holder
multiplied by the excess of the fair market value of Common Stock on the
exercise date over the stock appreciation rights' exercise price. Stock
appreciation rights may or may not be granted in connection with the grant of an
option and no stock appreciation right may be exercised earlier than six months
from the date of grant. A stock appreciation right may be exercised in whole or
in such installments and at such time as determined by the Compensation
Committee.
PERFORMANCE AND PHANTOM STOCK AWARDS. The 1996 Stock Awards Plan permits
grants of performance awards and phantom stock awards, which may be paid in
cash, Common Stock, or a combination thereof as determined by the Compensation
Committee. Performance awards granted under the 1996 Stock Awards Plan will have
a maximum value established by the Compensation Committee at the time of the
grant. A grantee's receipt of such amount will be contingent upon satisfaction
by the Company, or any subsidiary, division or department thereof, of future
performance conditions established by the Compensation Committee prior to the
beginning of the performance period. Such performance awards, however, are
subject to later revisions as the Compensation Committee deems appropriate to
reflect significant unforeseen events or changes. A performance award will
terminate if the grantee's employment with the Company terminates during the
applicable performance period except as otherwise provided by the Compensation
Committee at the time of grant. Phantom stock awards granted under the 1996
Stock Awards Plan are awards of Common Stock or rights to receive amounts equal
to share appreciation over a specific period of time. Such awards vest over a
period of time or upon the occurrence of a specific event(s) (including, without
limitation, a change of control) established by the Compensation Committee,
without payment of any amounts by the holder thereof (except to the extent
required by law) or satisfaction of any performance criteria or objectives. A
phantom stock award will terminate if the grantee's employment with the Company
terminates during the applicable vesting period or, if applicable, the
occurrence of a specific event(s), except as otherwise provided by the
Compensation Committee at the time of grant. In determining the value of
performance awards or phantom stock awards, the Compensation Committee must take
into account the employee's responsibility level, performance, potential, other
awards under the 1996 Stock Awards Plan, and other such consideration as it
deems appropriate. Such payment may be made in a lump sum or in installments as
prescribed by the Compensation Committee. Any payment made in Common Stock will
be based upon the fair market value of the Common Stock on the payment date.
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<PAGE>
EXECUTIVE COMPENSATION
The following table sets forth certain summary information concerning the
compensation provided by the Company in 1995 to its President and each other
person serving as an executive officer during 1995 who earned $100,000 or more
in combined salary and bonus during such year (collectively, the "Named
Executive Officers").
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION(1)
---------------------- ALL OTHER
NAME AND PRINCIPAL POSITION SALARY BONUS COMPENSATION
- ------------------------------------- ---------- ---------- ------------
David B. Strassner, President........ $ 125,000(2) $ -- $ --
Douglas H. Kiesewetter, Executive
Vice
President and Chief Operating
Officer............................ 125,000(2) -- --
R. Keith Anderson, Vice President.... 125,000(2) -- --
Joseph L. Savoy, Vice President...... 112,000(2) -- --
- ------------
(1) Amounts exclude perquisites and other personal benefits because such
compensation did not exceed the lesser of $50,000 or 10% of the total annual
salary and bonus reported for each executive officer.
(2) Subsequent to the completion of this Offering, Messrs. Strassner,
Kiesewetter, Anderson and Savoy will receive annual salaries of $175,000,
$175,000, $175,000 and $125,000, respectively.
The following table sets forth certain information with respect to options
that will be held by the persons named in the Summary Compensation Table upon
consummation of the Offering. See "-- 1996 Stock Awards Plan."
OPTION VALUES
<TABLE>
<CAPTION>
VALUE OF
NUMBER OF UNEXERCISED
SECURITIES UNDERLYING IN-THE-MONEY
UNEXERCISED OPTIONS OPTIONS(1)
NAME EXERCISABLE/UNEXERCISABLE EXERCISABLE/UNEXERCISABLE
- ---------------------------------------- ------------------------- -------------------------
<S> <C> <C>
David B. Strassner...................... 0/120,000 --/--
Douglas H. Kiesewetter.................. 0/120,000 --/--
R. Keith Anderson....................... 0/120,000 --/--
Joseph L. Savoy......................... 72,708/88,472 $610,020/$406,680
</TABLE>
- ------------
(1) Reflects the difference between the exercise price of the options and the
public offering price of the Common Stock in the Offering. The exercise
price of all options held by Messrs. Strassner, Kiesewetter and Anderson is
the public offering price. The exercise price of all of the exercisable
options and 48,472 of the unexercisable options held by Mr. Savoy is $3.61
per share, and the exercise price of the other 40,000 options held by Mr.
Savoy is the public offering price. Values given are based on a public
offering price of $12.00 per share.
CERTAIN TRANSACTIONS
Prior to this Offering, all of the Company's employees were provided by CSA
Financial Services, Inc. ("CSA"). CSA is wholly owned by Douglas H.
Kiesewetter, Executive Vice President, Chief Operating Officer and a director of
the Company. The employees were provided to the Company by CSA at cost. The
Company made payments to CSA aggregating $855,491, $1,064,818 and $1,197,281
during 1993, 1994 and 1995, respectively. The Company believes that its
arrangement with CSA was on terms no less favorable than could be obtained from
an unaffiliated third party. This arrangement will be terminated as soon as
practicable after completion of the Combination and consummation of this
Offering.
The Company and NGP are parties to a Financial Advisory Services Agreement
effective as of April 1, 1996 pursuant to which the Company has engaged NGP to
serve as financial advisor with respect to the public offering process. The
agreement expires on earlier of (i) the dissolution of OEDC Partners, L.P., and
(ii) the later of (y) the date that representatives of NGP no longer serve on
the board of directors of the Company, and (z) the second anniversary of the
closing date of the first issuance of securities by the Company in a public
offering. In consideration of its services NGP receives an annual fee of $15,000
for
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<PAGE>
each representative of NGP that serves on the board of directors of the Company
(currently two), and an annual fee of $30,000 commencing as of the date of
consummation of the first issuance of securities by the Company and continuing
for a two-year period. Consequently, for a two-year period after completion of
this Offering NGP will be paid $60,000 per year.
From 1993 through the first six months of 1996, the Company made preference
unit payments of $2,703,750 to NGP in respect of the Preference Units in OEDC
Partners, L.P. held by NGP. The Company will redeem all of the outstanding
Preference Units with the proceeds of this Offering. See "Use of Proceeds." In
addition, in 1993 and 1994 the Company made interest payments of $355,748 to NGP
under a short-term credit facility that was repaid in 1994. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Results of Operations."
Certain contracts to which the Company or its affiliated partnerships are a
party require the continued employment of certain of the Company's senior
executives. See "Risk Factors -- Dependence Upon Key Personnel,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Financing Activities" and
"Business -- Natural Gas Gathering -- Current Operations."
The Company has entered into the Registration Rights Agreement with NGP
(including certain affiliates) and Messrs. Strassner, Kiesewetter and Anderson.
Pursuant to the Registration Rights Agreement, on three separate occasions
commencing on the first anniversary of the effective date of the Company's
initial registration statement under the securities laws, the holders of at
least 35% of the shares of Common Stock held by NGP (including certain
affiliates) and Messrs. Strassner, Kiesewetter and Anderson may require the
Company to register shares held by them under applicable securities laws
provided that the shares to be registered have an estimated aggregate offering
price to the public of at least $3,000,000. However, if after two such
registrations, NGP continues to own shares of Common Stock, NGP may require the
Company to effect the third such registration regardless of its percentage
ownership. The Registration Rights Agreement also provides that NGP and Messrs.
Strassner, Kiesewetter and Anderson (and, for two years after the effective date
of the Company's initial registration statement under the securities laws,
certain other stockholders) have "piggyback" registration rights pursuant to
which such persons may include shares of Common Stock held by them in certain
registrations initiated by the Company; provided, that in an underwritten
registered offering, if the underwriters determine that the number of shares
requested to be included in the registration exceeds the number that the
underwriters believe can be sold, the Company will be given first priority and
the persons requesting piggyback registration will be allowed to include shares
pro rata based on the number of shares each such person requested to be
included.
The Registration Rights Agreement provides for customary indemnity by the
Company in favor of persons including shares in a registration pursuant to the
Registration Rights Agreement, and by such persons in favor of the Company, with
respect to information to be included in the relevant registration statement.
Each of Messrs. Strassner, Kiesewetter and Anderson has entered into an
Affiliates Agreement that provides that (i) during such person's employment with
the Company, such person shall engage in oil and gas activities solely for the
benefit of the Company and shall devote no more than 10% of such person's time
to other commercial activities, (ii) after the termination of such person's
employment with the Company, such person will not promote, participate in the
development of, or consult or work in any capacity on any prospect, lease,
project or business opportunity in which the Company has an economic interest or
for a period of one year following such termination is evaluating for
investment, and (iii) information received by such persons relating to the
business, operations and prospects of the Company must be kept confidential.
Each of Messrs. Strassner, Kiesewetter and Anderson has agreed with the
Company that, prior to the earlier of DIGP Payout or February 28, 2001, he will
not voluntarily (i) cease to be actively involved as the management of and in
the operation of DIGP to substantially the same degree as he was involved in
such management and operation on July 1, 1996, or (ii) reduce his respective
ownership interest in the Company following the Company's initial public
offering by 75% or more.
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<PAGE>
PRINCIPAL AND SELLING STOCKHOLDERS
A total of 182,000 shares of Common Stock is being sold hereby by certain
of the Selling Stockholders, assuming no exercise of the Underwriters'
overallotment option. R. Keith Anderson, a Vice President and a director of the
Company, is selling 45,500 shares. Gaylen J. Byker, a Vice President and a
director of the Company from 1992 to 1995, when he ceased to be actively
involved in the business of the Company, is selling 136,500 shares. The Company
and each of the Selling Stockholders have entered into a Registration Agreement
pursuant to which the Selling Stockholders will bear the underwriting discount
applicable to the shares sold by them, and will indemnify the Underwriters from
certain liabilities, including liabilities under the Securities Act.
The following table sets forth certain information as of October 31, 1996,
giving effect to the Combination, concerning all stockholders who may sell
shares in this Offering, the persons known by the Company to be beneficial
owners of more than five percent of the Company's outstanding Common Stock, the
members of the Board of Directors of the Company, the Named Executive Officers
listed in the Summary Compensation Table above and all directors and executive
officers of the Company as a group. Except as otherwise noted, each stockholder
has sole voting and investment power with respect to the shares beneficially
owned.
<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP
----------------------------------------------------------------------------
NUMBER OF SHARES PERCENT
------------------------------------ ------------------------------------
NAME OF BENEFICIAL OWNER BEFORE OFFERING AFTER OFFERING(1) BEFORE OFFERING AFTER OFFERING(1)
- ------------------------------------- --------------- ----------------- --------------- -----------------
<S> <C> <C> <C> <C>
David B. Strassner(2)................ 816,978(3) 816,978 16.17% 9.55%
Douglas H. Kiesewetter(2)............ 606,656(4) 606,656 12.01% 7.09%
R. Keith Anderson(2)................. 387,536(5) 342,036 7.67% 4.00%
Joseph L. Savoy, Jr.(2).............. 72,708(6) 72,708 1.42% *
Matthew T. Bradshaw(2)............... 33,226(7) 33,226 * *
David R. Albin(8).................... 57,150(9) 57,150 1.13% *
R. Gamble Baldwin(10)................ 2,438,825(11) 2,438,825 48.28% 28.52%
G. Alan Rafte........................ 0 0 * *
All Executive Officers and Directors
as a Group (eight persons)......... 4,413,079 4,367,579 85.72% 50.49%
Natural Gas Partners, L.P.(10)....... 2,400,750 2,400,750 47.52% 28.07%
Gaylen J. Byker(12).................. 279,544 143,044 5.53% 1.67%
The Christian Community Foundation... 50,298 50,298 * *
</TABLE>
- ------------
* Less than one percent
(1) Assumes that the Underwriters' overallotment option is not exercised. The
Company and Messrs. David B. Strassner and Douglas H. Kiesewetter (for his
own account and as trustee for the benefit of his mother and sister), the
President and Executive Vice President of the Company, respectively, Mr.
Anderson (for his own account and as trustee for the benefit of his
grandmother, mother and father), NGP and The Christian Community Foundation
have granted the Underwriters an option to purchase 150,000, 68,250,
48,850, 34,000, 201,150 and 50,050 additional shares of Common Stock,
respectively, to cover overallotments, if any. If the Underwriters'
overallotment option is exercised in full Messrs. Strassner, Kiesewetter
and Anderson will own 748,728, 557,806 and 308,036 shares, respectively,
representing 8.60%, 6.41% and 3.54%, respectively, of the 8,701,885 shares
that would be outstanding. Under such circumstances, NGP would own
2,199,600 shares representing 25.28% of the Common Stock outstanding,
resulting in Mr. Baldwin beneficially owning 2,237,675 shares, or 25.71%.
The Christian Community Foundation would own 248 shares, less than one
percent of the shares outstanding. If the overallotment option is exercised
in part, shares will be purchased pro rata from the Company and the Selling
Stockholders selling shares to cover overallotments.
(2) The address of Messrs. Strassner, Kiesewetter, Anderson, Savoy and Bradshaw
is c/o the Company, 1400 Woodloch Forest Drive, Suite 200, The Woodlands,
Texas 77380.
(FOOTNOTES CONTINUED ON FOLLOWING PAGE)
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(3) Includes (i) 737,298 shares held in trust by Mr. Strassner and his spouse
for their benefit and (ii) 79,680 shares held by Mr. Strassner's spouse as
custodian for their minor children. Excludes 120,000 shares of Common
Stock, issuable on the exercise of certain options, none of which are
presently exercisable.
(4) Includes (i) 518,344 shares held in trust by Mr. Kiesewetter and his spouse
for their benefit, (ii) 33,200 shares held by Mr. Kiesewetter's spouse as
custodian for their minor children, (iii) 11,952 shares held in trust by
Mr. Kiesewetter for the benefit of his sister, and (iv) 43,160 shares held
in trust by Mr. Kiesewetter for the benefit of his mother. Excludes 120,000
shares of Common Stock issuable on the exercise of certain options, none of
which are presently exercisable.
(5) Includes (i) 343,380 shares held by Mr. Anderson, (ii) 21,248 shares held
by Mr. Anderson's spouse as trustee for their minor children, (iii) 7,636
shares held in trust by Mr. Anderson for the benefit of his grandmother,
(iv) 7,636 shares held in trust by Mr. Anderson for the benefit of his
mother, and (v) 7,636 shares held in trust by Mr. Anderson for the benefit
of his father. Excludes 120,000 shares issuable on the exercise of certain
options which are not presently exercisable.
(6) Includes 72,708 shares issuable on the exercise of certain presently
exercisable options. Excludes 88,472 shares issuable on the exercise of
certain options.
(7) Includes (i) 6,666 shares held by Mr. Bradshaw and his spouse and (ii)
26,560 issuable on the exercise of certain presently exercisable options.
Excludes 79,840 shares issuable upon the exercise of certain options which
are not presently exercisable.
(8) The address of Mr. Albin is 100 North Guadalupe Street, Suite 205, Santa
Fe, New Mexico 87501.
(9) Includes (i) 28,575 shares held by Mr. Albin and (ii) 28,575 shares held in
trust for Mr. Albin.
(10) The address of Mr. Baldwin and Natural Gas Partners, L.P. is 115 East
Putnam Ave., Greenwich, Connecticut 06830.
(11) Includes (i) 38,075 shares held by Mr. Baldwin and (ii) 2,400,750 shares
held by Natural Gas Partners, L.P., over which Mr. Baldwin exercises sole
voting and investment power. Mr. Baldwin is the sole general partner of the
sole general partner of Natural Gas Partners, L.P.
(12) The address of Mr. Byker is 3201 Burton Street, S.E., Grand Rapids,
Michigan 49546.
DESCRIPTION OF CAPITAL STOCK
The Company's authorized capital stock consists of 10,000,000 shares of
Common Stock, par value $0.01 per share ("Common Stock"), and 1,000,000 shares
of Preferred Stock, par value $0.01 per share. Upon completion of the
Combination and this Offering, 8,551,885 shares of Common Stock and no shares of
preferred stock will be issued and outstanding. The following summary is
qualified by reference to the Certificate of Incorporation of the Company (the
"Certificate"), which is filed as an exhibit to the Registration Statement of
which this Prospectus is a part.
COMMON STOCK
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
and do not have cumulative voting rights. Holders of Common Stock are entitled
to receive ratably such 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. See "Dividend
Policy." Upon the liquidation, dissolution or winding up of the Company, the
holders of Common Stock are entitled to receive ratably the net assets of the
Company available after payment of all debts and other liabilities, subject to
the prior rights of any outstanding shares of Preferred Stock. Holders of Common
Stock have no preemptive, subscription, redemption or conversion rights.
PREFERRED STOCK
The Board of Directors of the Company is empowered, without approval of the
stockholders, to cause shares of Preferred Stock to be issued in one or more
series, with the numbers of shares of each series to be determined by it. The
Board of Directors is authorized to fix and determine variations in the
designations, preferences, and relative, participating, optional or other
special rights (including, without limitation, special
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voting rights, rights to receive dividends or assets upon liquidation, rights of
conversion into Common Stock or other securities, redemption provisions and
sinking fund provisions) between series and between the Preferred Stock or any
series thereof and the Common Stock, and the qualifications, limitations or
restrictions of such right. The shares of Preferred Stock or any series thereof
may have full or limited voting powers, or be without voting powers.
Although the Company has no present intention to issue shares of Preferred
Stock, the issuance of shares of Preferred Stock, or the issuance of rights to
purchase such shares, could be used to discourage an unsolicited acquisition
proposal. For instance, the issuance of a series of Preferred Stock might impede
a business combination by including class voting rights that would enable the
holders to block such a transaction; or such issuance might facilitate a
business combination by including voting rights that would provide a required
percentage vote of the stockholders. In addition, under certain circumstances,
the issuance of Preferred Stock could adversely affect the voting power of the
holders of the Common Stock. Although the Board of Directors is required to make
any determination to issue such stock based on its judgment as to the best
interests of the stockholders of the Company, the Board of Directors could act
in a manner that would discourage an acquisition attempt or other transaction in
that some or a majority of the stockholders might believe to be in their best
interest or in which stockholders might receive a premium for their stock over
the then market price for such stock. The Board of Directors does not at present
intend to seek stockholder approval prior to any issuance of currently
authorized stock, unless otherwise required by law or the regulations of any
exchange or interdealer quotation system on which its Common Stock is listed or
included for trading.
CERTAIN PROVISIONS OF THE COMPANY'S CHARTER AND BYLAWS AND DELAWARE LAW
Certain provisions of the Certificate and the Company's Bylaws are intended
to enhance the likelihood of continuity and stability in the Board of Directors
of the Company and in its policies, but might have the effect of delaying or
preventing a change in control of the Company and may make more difficult the
removal of incumbent management even if such transactions could be beneficial to
the interest of stockholders. Set forth below is a description of such
provisions.
NUMBER AND CLASSIFICATION OF DIRECTORS; REMOVAL. The Certificate provides
that the number of directors of the Company shall be not less than six nor more
than nine. The Certificate provides that the Board of Directors is divided into
three classes of two or three directors serving staggered terms. One class is
elected at each annual stockholders' meeting to serve for a three-year term. The
classification of directors has the effect of making it more difficult than it
would be without classification to change the composition or gain control of the
Board of Directors. At least two stockholders' meetings, instead of one, are
required to effect a change in the majority control of the Board of Directors,
except in the event of vacancies resulting from removal for cause. Under the
Delaware General Corporation Law and the Certificate, directors serving on a
classified board may be removed by the stockholders only for cause by the vote
of 80% of the shares entitled to vote.
FILLING VACANCIES; STOCKHOLDER MEETINGS. The Board of Directors of the
Company, acting by a majority of the directors then in office, may fill any
vacancy or newly created directorship. The Company's Bylaws provide that special
meetings of stockholders may be called only by the President or by a majority of
the directors.
ADVANCE NOTICE PROVISIONS. The Bylaws of the Company impose certain
procedural requirements on stockholders of the Company who wish to make
nominations for elections of directors or propose other action to be taken at
the annual meeting of the Company's stockholders. The requirements include,
among other things, the timely delivery to the Company's Secretary of notice of
the nomination or proposal and (i) evidence of the stockholder's status as such,
(ii) the number of shares the stockholder beneficially owns, (iii) a list of the
persons with whom the stockholder is acting in concert, and (iv) the number of
shares beneficially owned by such persons. The Bylaws provide that failure to
follow the required procedures renders the nominee or proposal ineligible to be
voted upon by the stockholders at the meeting.
LIMITATION ON PERSONAL LIABILITY OF DIRECTORS. Delaware law authorizes
corporations to limit or eliminate the personal liability of directors to
corporations and their stockholders for monetary damages for
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breach of a director's fiduciary duty of care. The duty of care requires that,
when acting on behalf of the corporation, directors must exercise an informed
business judgment based on all material information reasonably available to
them. Absent the limitations authorized by Delaware law, directors are
accountable to corporations and their stockholders for monetary damages for
conduct constituting gross negligence in the exercise of their duty of care.
Delaware law enables corporations to limit available relief to equitable
remedies such as injunction or rescission. The Certificate limits the liability
of directors of the Company to the Company or its stockholders (in their
capacity as directors but not in their capacity as officers) to the fullest
extent permitted by Delaware law. Specifically, directors of the Company will
not be personally liable for monetary damages for breach of a director's
fiduciary duty as a director, except for liability (i) for any breach of the
director's duty of loyalty to the Company or its stockholders, (ii) for acts or
omissions not in good faith or which involve intentional misconduct or a knowing
violation of law, (iii) for unlawful payments of dividends or unlawful stock
repurchases or redemptions as provided in Section 174 of the Delaware General
Corporation Law, or (iv) for any transaction from which the director derived an
improper personal benefit.
The inclusion of this provision in the Certificate may have the effect of
reducing the likelihood of derivative litigation against directors and may
discourage or deter stockholders or management from bringing a lawsuit against
directors for breach of their duty of care, even though such an action, if
successful, might otherwise have benefited the Company and its stockholders. The
Company's Bylaws provide for indemnification to the Company's officers and
directors and certain other persons with respect to certain matters, and the
Company has entered into indemnification agreements with its executive officers
and its directors providing for indemnification with respect to certain matters.
DELAWARE LAW. The Company is a Delaware corporation and is subject to
Section 203 of the Delaware General Corporation Law. In general, Section 203
prevents an "interested stockholder" (defined generally as a person owning 15%
or more of a corporation's outstanding voting stock) from engaging in a
"business combination" (as defined) with a Delaware corporation for three
years following the date such person became an interested stockholder unless (i)
before such person became an interested stockholder, the board of directors of
the corporation approved the transaction in which the interested stockholder
became an interested stockholder or approved the business combination; (ii) upon
consummation of the transaction that resulted in the interested stockholder
becoming an interested stockholder, the interested stockholder owned at least
85% of the voting stock of the corporation outstanding at the time the
transaction commenced (excluding stock held by directors who are also officers
of the corporation and by employee stock plans that do not provide employees
with the rights to determine confidentially whether shares held subject to the
plan will be tendered in a tender or exchange offer); or (iii) following the
transaction in which such person become an interested stockholder, the business
combination was approved by the board of directors of the corporation and
authorized at a meeting of the stockholders by the affirmative vote of the
holders of two-thirds of the outstanding voting stock of the corporation not
owned by the interested stockholder. Under Section 203, the restrictions
described above also do not apply to certain business combinations proposed by
an interested stockholder following the announcement or notification of one of
certain extraordinary transactions involving the corporation and a person who
had not been an interested stockholder during the previous three years or who
become an interested stockholder with the approval of a majority of the
corporation's directors, if such extraordinary transaction is approved or not
opposed by a majority of the directors who were directors prior to any person
becoming an interested stockholder during the previous three years or were
recommended for election or elected to succeed such directors by a majority of
such directors.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the Common Stock is KeyCorp
Shareholder Services, Inc.
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SHARES ELIGIBLE FOR FUTURE SALE
Upon completion of this Offering, the Company will have 8,551,885 shares of
Common Stock outstanding. The shares sold in this Offering will be freely
tradeable without restriction or further registration, except for shares owned
by "affiliates" of the Company (as such term is defined under the Securities
Act) which may be sold subject to the resale limitations of Rule 144 promulgated
under the Securities Act ("Rule 144"). The remaining 4,869,885 outstanding
shares constitute "restricted securities" within the meaning of Rule 144. Such
shares must be held for two years before they may be resold pursuant to Rule
144, unless the resale of such shares is made pursuant to an effective
registration statement under the Securities Act or another exemption from
registration is available. The Company has entered into the Registration Rights
Agreement with NGP (including certain affiliates) and Messrs. Strassner,
Kiesewetter and Anderson. Pursuant to the Registration Rights Agreement, one
year after the effective date of the Company's initial registration statement
under the securities laws these persons are entitled to demand that the resale
of the Common Stock held by them be registered. In addition, these and certain
other shareholders have the right to include shares held by them in registration
statements filed by the Company (other than registration statements filed with
respect to employee benefit plans and business combinations). See
"Management -- Certain Transactions."
Generally, Rule 144 provides that beginning 90 days after the date of this
Prospectus, a person (or persons whose shares are aggregated) who has
beneficially owned "restricted" securities for at least two years, including a
person who may be deemed an "affiliate" of the Company, as the term
"affiliate" is defined under the Securities Act, is entitled to sell in
"brokers' transactions" or in transactions directly with a "market maker,"
within any three-month period, a number of shares that does not exceed the
greater of one percent of the then outstanding shares of Common Stock or the
average weekly trading volume of the Common Stock on any national securities
exchange and/or over-the-counter market during the four calendar weeks preceding
such sale. Sales under Rule 144 are also subject to certain notice requirements
and the availability of current public information about the Company. A person
(or persons whose shares are aggregated) who is not deemed an "affiliate" of
the Company would be entitled to sell such shares under Rule 144 without regard
to the volume, public information, manner of sale or notice provisions and
limitations described above, once a period of at least three years has elapsed
since the later of the date the shares were acquired from the Company or from an
"affiliate" of the Company.
There are currently outstanding options to purchase 727,580 shares of
Common Stock under the 1996 Stock Awards Plan. After this Offering, the Company
intends to file a registration statement on Form S-8 under the Securities Act to
register the shares of Common Stock issuable upon exercise of such options.
Accordingly, such shares will be freely tradeable by holders who are not
affiliates of the Company and, subject to the volume and manner of sale
limitations of Rule 144, by holders who are affiliates of the Company.
Prior to this Offering, there has been no public market for the Common
Stock of the Company, and no prediction can be made as to the effect, if any,
that future sales of shares or the availability of shares for sale will have on
the market price for Common Stock prevailing from time to time. Sales of
substantial amounts of Common Stock in the public market, or the perception of
the availability of shares for sale, could adversely affect the prevailing
market price of the Common Stock and could impair the Company's ability to raise
capital through the sale of its equity securities.
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UNDERWRITING
Subject to the terms and conditions of the Underwriting Agreement among the
Company and the Underwriters named below (the "Underwriting Agreement"), the
Company has agreed to sell to each of such Underwriters named below, and each of
such Underwriters, for whom Morgan Keegan & Company, Inc. and Principal
Financial Securities, Inc. are acting as representatives, has severally agreed
to purchase from the Company, the respective number of shares of Common Stock
set forth opposite its name below.
NUMBER OF
SHARES
UNDERWRITER OF COMMON STOCK
- ------------------------------------- ---------------
Morgan, Keegan & Company, Inc........ 1,016,000
Principal Financial Securities,
Inc................................ 1,016,000
Banque Paribas....................... 75,000
J.C. Bradford & Co................... 75,000
Brean Murray & Co., Inc.............. 75,000
Crowell, Weedon & Co................. 75,000
Dain Bosworth Incorporated........... 75,000
Equitable Securities Corporation..... 75,000
Hanifen, Imhoff Inc.................. 75,000
Interstate/Johnson Lane
Corporation........................ 75,000
Jefferies & Company.................. 75,000
Johnson Rice & Company L.L.C......... 75,000
Legg Mason Wood Walker,
Incorporated....................... 75,000
McDonald & Company Securities,
Inc................................ 75,000
Nesbitt Burns Securities Inc......... 75,000
Petrie Parkman & Co.................. 75,000
Rauscher Pierce Refsnes, Inc......... 75,000
Raymond James & Associates, Inc...... 75,000
The Robinson-Humphrey Company,
Inc................................ 75,000
Simmons & Company International...... 75,000
Southwest Securities, Inc............ 75,000
Stephens Inc......................... 75,000
Stifel, Nicolaus & Company,
Incorporated....................... 75,000
Wheat First Butcher Singer........... 75,000
---------------
Total........................... 3,682,000
===============
Under the terms and conditions of the Underwriting Agreement, the
Underwriters are committed to take and pay for all of the shares of Common Stock
offered hereby, if any are taken.
The Underwriters propose to offer the shares of Common Stock in part
directly to the public at the initial public offering price set forth on the
cover page of this Prospectus, and in part to certain securities dealers at such
price less a concession of $.50 per share. The Underwriters may allow, and such
dealers may allow, a concession not in excess of $.10 per share to certain
brokers and dealers. After the shares of Common Stock are released for sale to
the public, the offering price and other selling terms may from time to time be
varied by the representatives.
The Company and certain of the Selling Stockholders have granted the
Underwriters an option exercisable for 30 days after the date of this Prospectus
to purchase up to an aggregate of 552,300 additional shares of Common Stock
solely to cover overallotments, if any. See "Principal and Selling
Stockholders." If the Underwriters exercise their overallotment option, the
Underwriters have severally agreed, subject to certain conditions, to purchase
approximately the same percentage thereof that the number of shares of Common
Stock to be purchased by each of them, as shown in the table above, bears to the
3,682,000 shares of Common Stock.
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The Company and all of its officers and directors and NGP have agreed,
during the period beginning from the date of this Prospectus and continuing to
and including the date 180 days after the date of the Prospectus, not to offer,
sell, contract to sell or otherwise dispose of any securities of the Company
(other than, with respect to the Company, pursuant to employee stock option
plans existing, or on the conversion or exchange of convertible or exchangeable
securities outstanding, on the date of this Prospectus) which are substantially
similar to the shares of the Common Stock or which are convertible or
exchangeable into securities which are substantially similar to the shares of
the Common Stock without the prior consent of the representatives.
The representatives of the Underwriters have informed the Company that the
Underwriters do not expect sales to accounts over which the Underwriters
exercise discretionary authority to exceed five percent of the total number of
shares of Common Stock offered by them.
Prior to this Offering, there has been no public market for the Common
Stock. The initial public offering price of the Common Stock will be negotiated
between the Company and the representatives of the Underwriters. Among the
factors to be considered in determining the initial public offering price of the
Common Stock, in addition to prevailing market conditions, are current and
historical oil and gas prices, current and prospective conditions in the supply
and demand for oil and natural gas, reserve and production quantities for the
Company's oil and natural gas properties, the history of, and prospects for, the
industry in which the Company operates, the price earnings multiples of publicly
traded common stocks of comparable companies, the cash flow and earnings of the
Company and comparable companies in recent periods and the Company's business
potential and cash flow and earnings prospects.
The Company and the Selling Stockholders have agreed to indemnify the
several Underwriters against certain liabilities, including liabilities under
the Securities Act.
LEGAL MATTERS
The validity of the shares of Common Stock offered hereby is being passed
upon for the Company by Bracewell & Patterson, L.L.P., Houston, Texas. G. Alan
Rafte, a director of the Company, is a partner in Bracewell & Patterson, L.L.P.
Certain legal matters in connection with the shares of Common Stock offered
hereby are being passed upon for the Underwriters by Vinson & Elkins L.L.P.,
Houston, Texas.
EXPERTS
The balance sheet of Offshore Energy Development Corporation as of July 24,
1996 and the consolidated financial statements of OEDC, Inc. and OEDC Partners,
L.P. as of December 31, 1995 and 1994 and June 30, 1996 and for each of the
years in the three-year period ended December 31, 1995 and for the six-month
period ended June 30, 1996, have been included in the Prospectus and in the
Registration Statement in reliance upon the reports of KPMG Peat Marwick LLP,
independent certified accountants, appearing elsewhere herein, and upon the
authority of said firm as experts in accounting and auditing.
Information relating to the estimated proved reserves of natural gas at
January 1, 1996 and the related estimates of future net cash flows and present
values thereof included herein, and the information related to the estimated
proved reserves of natural gas as of October 7, 1996, have been derived from an
engineering report prepared by Ryder Scott Company, and are included herein in
reliance upon the authority of such firm as experts in petroleum engineering.
AVAILABLE INFORMATION
The Company has not previously been subject to the reporting requirements
of the Securities Exchange Act of 1934, as amended. The Company has filed with
the Commission a Registration Statement on Form S-1 (the "Registration
Statement") under the Securities Act, with respect to the offer and sale of
Common Stock pursuant to this Prospectus. This Prospectus, filed as a part of
the Registration Statement, does not contain all of the information set forth in
the Registration Statement or the exhibits and schedules thereto in accordance
with the rules and regulations of the Commission and reference is hereby made to
such omitted
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information. Statements made in this Prospectus concerning the contents of any
contract, agreement or other document filed as an exhibit to the Registration
Statement are summaries of the terms of such contract, agreement or document and
are not necessarily complete. Reference is made to each such exhibit for a more
complete description of the matters involved and such statements shall be deemed
qualified in their entirety by such reference. The Registration Statement and
the exhibits and schedules thereto filed with the Commission may be inspected,
without charge, and copies may be obtained at prescribed rates, at the public
reference facility maintained by the Commission at Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549 and at the regional offices of the
Commission at 7 World Trade Center, New York, New York 10048 and Citicorp
Center, 500 West Madison Street, Chicago, Illinois 60661. This Registration
Statement was filed with the Commission electronically. The Commission maintains
a site on the World Wide Web that contains documents filed with the Commission
electronically. The address of such site is http://www.sec.gov, and the
Registration Statement may be inspected at such site. For further information
pertaining to the Common Stock offered by this Prospectus and the Company,
reference is made to the Registration Statement.
The Company intends to furnish holders of its Common Stock annual reports
containing audited consolidated financial statements as well as quarterly
reports containing unaudited consolidated financial statements for the first
three quarters of each fiscal year.
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GLOSSARY OF CERTAIN OIL AND GAS TERMS
All volumes of natural gas referred to herein are stated at the legal
pressure base of the state or area where the reserves exist and at 60 degrees
Fahrenheit and in most instances are rounded to the nearest major multiple.
BCF. Billion cubic feet.
BCFE. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one barrel of crude oil, condensate or natural gas liquids.
COMPLETION. The installation of permanent equipment for the production of
oil or gas.
DEVELOPED ACREAGE. The number of acres which are allocated or assignable
to producing wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
DRY HOLE OR WELL. A well found to be incapable of producing either oil or
gas in sufficient quantities to justify completion as an oil or gas well.
EXPLORATORY WELL. A well drilled to find and produce oil or gas in another
reservoir or to extend a known reservoir.
GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be,
in which a working interest is owned.
HORIZONTAL DRILLING. A drilling technique that permits the operator to
contact and intersect a larger portion of the producing horizon than
conventional vertical drilling techniques and can result in both increased
production rates and greater ultimate recoveries of hydrocarbons.
MCF; MCF/D. One thousand cubic feet; one thousand cubic feet per day.
MCFE. One thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one barrel of crude oil, condensate or natural gas
liquids.
MMBTU. One million British thermal units.
MMCF; MMCF/D. One million cubic feet; one million cubic feet per day.
MMCFE. One million cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one barrel of crude oil, condensate or natural gas
liquids.
NET ACRES OR NET WELLS. The sum of the fractional working interests owned
in gross acres or gross wells.
OIL. Crude oil and condensate.
PRESENT VALUE. The estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect as of the date indicated,
without giving effect to non-property related expenses such as general and
administrative expenses, debt service and future income tax expenses or to
depreciation, depletion and amortization, discounted using an annual discount
rate of 10%.
PRODUCTIVE WELL. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
PROVED DEVELOPED PRODUCING RESERVES. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.
PROVED DEVELOPED NONPRODUCING RESERVES. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED UNDEVELOPED LOCATION. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
PROVED UNDEVELOPED RESERVES. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required from recompletion.
RECOMPLETION. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
RESERVOIR. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
ROYALTY INTEREST. An interest in an oil and gas property entitling the
owner to a share of oil or gas production free of costs of production.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
UPDIP. A higher point in the reservoir.
WORKING INTEREST. The operating interest which gives the owner the right
to drill, produce and conduct operating activities on the property and a share
of production.
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INDEX TO FINANCIAL STATEMENTS
PAGE
--------
Unaudited Pro Forma Financial
Information of Offshore Energy
Development Corporation ................................... F-2
Unaudited Pro Forma Consolidated
Balance Sheet ......................................... F-3
Unaudited Pro Forma Consolidated
Statements of Operations .............................. F-4, F-5
Notes to Unaudited Pro Forma
Consolidated Financial
Statements ............................................ F-6
Balance Sheet of Offshore Energy
Development Corporation
Independent Auditors' Report ........................... F-7
Balance Sheet as of July 24,
1996 .................................................. F-8
Notes to Balance Sheet ................................. F-9
Consolidated Financial Statements of
OEDC, Inc. and OEDC Partners, L.P. ........................
Independent Auditors' Report ........................... F-10
Consolidated Balance Sheets as
of December 31, 1995 and 1994
and June 30, 1996 and 1995
(Unaudited) ........................................... F-11
Consolidated Statements of
Operations for Years Ended
December 31, 1995, 1994 and
1993 and for the Six Month
Periods Ended June 30, 1996 and
1995 (Unaudited) ...................................... F-12
Consolidated Statements of
Stockholders'/Partners' Equity
as of December 31, 1995, 1994
and 1993 and June 30, 1996 ............................ F-13
Consolidated Statements of Cash
Flows for Years Ended December
31, 1995, 1994 and 1993 and for
the Six Month Periods Ended
June 30, 1996
and 1995 (Unaudited) ................................. F-14
Notes to Consolidated Financial
Statements ............................................ F-15
F-1
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OFFSHORE ENERGY DEVELOPMENT CORPORATION
(A NEWLY FORMED DELAWARE CORPORATION)
UNAUDITED PRO FORMA FINANCIAL INFORMATION
The unaudited pro forma consolidated balance sheet as of June 30, 1996 and
the unaudited pro forma consolidated statements of operations for the year ended
December 31, 1995 and the six months ended June 30, 1996 are presented to show
the pro forma effects of the consummation of the Combination, through exchange,
by Offshore Energy Development Corporation, of the common stock of OEDC, Inc.
and the partners' interest in OEDC Partners, L.P. for common stock in the
Company as described on page 21 in the Prospectus.
Pursuant to the Securities and Exchange Commission's Staff Accounting
Bulletin 47, as the Combination involves an exchange of shares in Offshore
Energy Development Corporation for interests in oil and gas properties and
because a high degree of common ownership and common control between Offshore
Energy Development Corporation and OEDC, Inc. and OEDC Partners, L.P. exists, as
well as Offshore Energy Development Corporation's non-public status prior to the
Combination, the Combination is treated as a reorganization of entities under
common control and therefore, historical cost is used in accounting for the
Combination.
The unaudited pro forma consolidated financial statements are provided for
information purposes only. The unaudited pro forma consolidated balance sheet is
prepared assuming that the Combination was consummated as of June 30, 1996. The
unaudited pro forma consolidated statements of operations have been prepared
assuming the Combination was consummated as of January 1, 1995.
The unaudited pro forma consolidated financial statements and the pro forma
adjustments have been prepared on the basis of generally accepted accounting
principles and are based upon available information and certain assumptions and
estimates described in the notes to the unaudited pro forma consolidated
financial statements that management of the Company believes are reasonable. The
unaudited pro forma consolidated financial statements are not necessarily
indicative of what the Company's financial position would have been had the
Combination occurred on the date indicated. In addition, future results may vary
significantly from the results reflected in such financial statements due to
production, price and cost changes, agreements and other factors.
The unaudited pro forma consolidated financial statements are based upon
the historical consolidated financial statements of OEDC, Inc. and OEDC
Partners, L.P. and should be read in conjunction with their audited consolidated
financial statements and the related notes thereto which are included elsewhere
in this Prospectus.
F-2
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
(A NEWLY FORMED DELAWARE CORPORATION)
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
JUNE 30, 1996
<TABLE>
<CAPTION>
OEDC, INC. OFFSHORE
OFFSHORE AND ENERGY
ENERGY OEDC PARTNERS, L.P. DEVELOPMENT
DEVELOPMENT (HISTORICAL PRO FORMA CORPORATION
CORPORATION CONSOLIDATED) ADJUSTMENTS PRO FORMA
----------- ------------------- ----------- -----------
<S> <C> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents........... $ 30 $ 1,577,455 $ $ 1,577,485
Accounts receivable -- trade, net... -- 1,239,298 1,239,298
Accounts receivables -- affiliate... -- 97,343 97,343
Accounts receivable -- other........ -- 1,254,508 1,254,508
Prepaids and other assets........... -- 340,466 340,466
--- ------------------- ----------- -----------
Total current assets........... 30 4,509,070 -- 4,509,100
Oil and gas properties -- at cost
(successful efforts method)......... -- 26,230,131 26,230,131
Other property and equipment.......... -- 342,657 342,657
Accumulated depreciation, depletion
and amortization.................... -- (9,271,502) (9,271,502)
--- ------------------- ----------- -----------
-- 17,301,286 -- 17,301,286
Investments in affiliates and
others.............................. 508,477 508,477
Restricted investments................ 1,938,950 1,938,950
Deferred and other assets............. -- 293,251 293,251
--- ------------------- ----------- -----------
Total Assets................... $ 30 $24,551,034 $ -- $24,551,064
=== =================== =========== ===========
LIABILITIES AND STOCKHOLDERS'/PARTNERS'
EQUITY
Current Liabilities:
Accounts payable.................... $ -- $ 1,916,911 $ $ 1,916,911
Payable to affiliate................ -- 21 21
Capital lease payable -- current.... -- 177,543 177,543
Accrued liabilities................. -- 926,548 926,548
Current portion of long-term debt... -- 2,500,000 2,500,000
--- ------------------- ----------- -----------
Total current liabilities...... -- 5,521,023 -- 5,521,023
Deferred tax liability................ -- 13,130 1,937,000(A) 1,950,130
Capital lease payable -- noncurrent... -- 740,512 740,512
Reserve for abandonment............... -- 305,402 305,402
--- ------------------- ----------- -----------
Total Liabilities.............. -- 6,580,067 1,937,000 8,517,067
Redeemable preference units, net...... -- 10,647,603 10,647,603
Stockholders'/Partners' Equity
Partners' equity.................... -- 7,031,080 (1,937,000)(A) --
(5,094,080)(B)
Stockholders' equity
Class A common stock, $.01 par
value; authorized 6,000 shares;
issued 6,000 shares............ -- 60 (60)(B) --
Class B common stock, $.01 par
value; authorized 6,000 shares;
issued 6,000 shares............ -- 60 (60)(B) --
Preferred stock -- Offshore Energy
Development Corporation, $.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; issued and
outstanding 5,051,885 shares... -- -- 50,519(B) 50,519
Additional paid-in capital........ 30 90,843 (90,843)(B) 5,134,554
5,134,524(B)
Retained earnings................. -- 201,321 201,321
--- ------------------- ----------- -----------
Total Stockholders'/Partners'
Equity....................... 30 7,323,364 (1,937,000) 5,386,394
Commitments and contingencies.........
--- ------------------- ----------- -----------
Total Liabilities and
Stockholders'/Partners' Equity...... $ 30 $24,551,034 $ -- $24,551,064
=== =================== =========== ===========
</TABLE>
See accompanying notes to unaudited pro forma consolidated financial statements.
F-3
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
(A NEWLY FORMED DELAWARE CORPORATION)
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1995
<TABLE>
<CAPTION>
OFFSHORE
OFFSHORE OEDC, INC. AND ENERGY
ENERGY OEDC PARTNERS, L.P. DEVELOPMENT
DEVELOPMENT (HISTORICAL PRO FORMA CORPORATION
CORPORATION CONSOLIDATED) ADJUSTMENTS PRO FORMA
----------- ------------------- ----------- -----------
<S> <C> <C> <C> <C>
Income:
Exploration and production...... $ -- $ 6,168,591 $ $ 6,168,591
Pipeline and marketing.......... -- 166,419 466,200(D) 632,619
Equity in earnings of equity
investments................... 496,979 (492,009)(E) 4,970
----------- ------------------- ----------- -----------
Total Income............... -- 6,831,989 (25,809) 6,806,180
----------- ------------------- ----------- -----------
Expenses:
Operations and maintenance...... -- 2,210,070 2,210,070
Exploration charges............. -- 404,836 -- 404,836
Depreciation, depletion and
amortization.................. -- 5,501,072 5,501,072
Abandonment expense............. -- 84,219 84,219
General and administrative...... -- 2,191,877 163,000(F) 2,354,877
----------- ------------------- ----------- -----------
Total Expenses............. -- 10,392,074 163,000 10,555,074
----------- ------------------- ----------- -----------
Earnings (losses) before interest and
taxes.............................. -- (3,560,085) (188,809) (3,748,894)
Interest Income (Expense) and Other:
Interest expense................ -- (1,651,063) (1,651,063)
Interest income and other....... -- 122,974 122,974
----------- ------------------- ----------- -----------
Total Interest Income
(Expense) and Other..... -- (1,528,089) -- (1,528,089)
----------- ------------------- ----------- -----------
Income (Loss) Before Income Taxes.... -- (5,088,174) (188,809) (5,276,983)
Income Tax Benefit................... -- 21,375 1,931,110(G) 1,952,485
----------- ------------------- ----------- -----------
Net Income (Loss).................... -- (5,066,799) 1,742,301 (3,324,498)
Preference unit payments and
accretion of discount......... -- (1,141,865) (1,141,865)
----------- ------------------- ----------- -----------
Income (loss) available to common
unit holders and stockholders...... $ -- $(6,208,664) $ 1,742,301 $(4,466,363)
=========== =================== =========== ===========
Income (loss) available to common
unit holders and stockholders per
common share....................... $ (0.88)(H)
===========
Weighted average of common shares
outstanding........................ 5,051,885(H)
===========
</TABLE>
See accompanying notes to unaudited pro forma consolidated financial statements.
F-4
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
(A NEWLY FORMED DELAWARE CORPORATION)
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE SIX-MONTHS ENDED JUNE 30, 1996
<TABLE>
<CAPTION>
OFFSHORE
OFFSHORE OEDC, INC. AND ENERGY
ENERGY OEDC PARTNERS, L.P. DEVELOPMENT
DEVELOPMENT (HISTORICAL PRO FORMA CORPORATION
CORPORATION CONSOLIDATED) ADJUSTMENTS PRO FORMA
------------ -------------------- --------------- --------------
<S> <C> <C> <C> <C>
Income:
Exploration and production......... $ -- 5,548,829 $ $ 5,548,829
Pipeline and marketing............. -- 493,750 493,750
Equity in earnings of equity
investments...................... 23,171 23,171
Gain on sales of oil and gas
properties or partnership
investments, net................. -- 10,661,433 (10,661,433 (C) --
------------ -------------------- --------------- --------------
Total income.................. -- 16,727,183 (10,661,433) 6,065,750
------------ -------------------- --------------- --------------
Expenses:
Operations and maintenance......... -- 1,025,003 1,025,003
Exploration charges................ -- 421,368 421,368
Depreciation, depletion and
amortization..................... -- 2,876,566 2,876,566
Abandonment expense................ -- 216,121 216,121
General and administrative......... -- 1,154,915 81,500(F) 1,236,415
------------ -------------------- --------------- --------------
Total Expenses................ -- 5,693,973 81,500 5,775,473
------------ -------------------- --------------- --------------
Earnings (losses) before interest and
taxes................................. -- 11,033,210 (10,742,933) 290,277
Interest Income (Expense) and Other:
Interest expense................... -- (622,132) (622,132)
Interest income and other.......... -- (64,823) (64,823)
------------ -------------------- --------------- --------------
Total Interest Income
(Expense) and Other........ -- (686,955) -- (686,955)
------------ -------------------- --------------- --------------
Income (Loss) Before Income Taxes....... -- 10,346,255 (10,742,933) (396,678)
Income Tax Benefit (Expense)............ -- (13,130) 159,900(G) 146,770
------------ -------------------- --------------- --------------
Net Income (Loss)....................... -- 10,333,125 (10,583,033) (249,908)
------------ -------------------- --------------- --------------
Preference unit payments and
accretion of discount............ -- (893,238) (893,238)
------------ -------------------- --------------- --------------
Income (loss) available to common unit
holders and stockholders.............. $ -- $ 9,439,887 $ (10,583,033) $ (1,143,146)
============ ==================== =============== ==============
Income (loss) available to common unit
holders and stockholders per common
share................................. $ (0.23)(H)
Weighted average of common shares
outstanding........................... 5,051,885(H)
==============
</TABLE>
See accompanying notes to unaudited pro forma consolidated financial statements.
F-5
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
(A NEWLY FORMED DELAWARE CORPORATION)
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
The accompanying unaudited pro forma consolidated balance sheet has been
prepared assuming the Combination was consummated as of June 30, 1996. The
unaudited pro forma consolidated statements of operations have been prepared
assuming the Combination was consummated as of January 1, 1995.
2. PRO FORMA ADJUSTMENTS
The unaudited pro forma consolidated financial statements reflect the
following pro forma adjustments related to the consummation of the Combination.
(A) To record the estimated deferred tax liability recognized by OEDC
Partners, L.P. and expensed to its operations as required in instances
when OEDC Partners, L.P., a partnership, becomes subject to federal
income taxes through inclusion in Offshore Energy Development
Corporation's federal tax returns. The net deferred tax liability
consists of the following:
Deferred tax liability -- excess of
book basis over tax basis of oil
and gas properties................. $ 2,116,000
Deferred tax asset -- expenses not
currently deductible for tax
purposes........................... (179,000)
------------
Net deferred tax liability........... $ 1,937,000
============
(B) To record the issuance of 5,051,882 shares of common stock of
Offshore Energy Development Corporation in the combination for the
exchange of OEDC, Inc. common stock and the OEDC Partners, L.P.
partners' equity.
(C) To eliminate the net gain on sales of oil and gas properties or
partnership investments.
(D) To record the contractual increase in pipeline fees earned by the
Company for operating the Dauphin Island Gathering System.
(E) To reduce equity in earnings of equity investments to reflect a 1%
interest in Dauphin Island Gathering Partners.
(F) To record the increase in executive compensation effective upon the
Combination.
(G) To record Offshore Energy Development Corporation estimated income tax
benefit for federal and state tax purposes.
(H) Income (loss) available to common unit holders and stockholders per
common share is computed based on the weighted average number of
common shares outstanding subsequent to the exchange of stockholders'
equity of OEDC, Inc. and partners' equity of OEDC Partners, L.P. for
common shares of Offshore Energy Development Corporation.
F-6
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Offshore Energy Development Corporation:
We have audited the accompanying balance sheet of Offshore Energy
Development Corporation as of July 24, 1996. This balance sheet is the
responsibility of the Company's management. Our responsibility is to express an
opinion on the balance sheet based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the balance sheet is free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the balance sheet. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the balance sheet referred to above, presents fairly, in
all material respects, the financial position of Offshore Energy Development
Corporation as of July 24, 1996 in conformity with generally accepted accounting
principles.
KPMG Peat Marwick LLP
Houston, Texas
August 23, 1996
F-7
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
(A NEWLY FORMED DELAWARE CORPORATION)
BALANCE SHEET
JULY 24, 1996
Assets
Cash............................ $ 30
=========
Stockholders' Equity
Preferred Stock, $.01 par value,
1,000,000 shares authorized,
none issued or outstanding..... $ --
Common Stock, $.01 par value,
10,000,000 shares authorized, 3
shares issued and
outstanding.................... --
Additional paid-in capital...... 30
---------
Total Stockholders'
Equity....................... $ 30
=========
See accompanying notes to balance sheet.
F-8
<PAGE>
OFFSHORE ENERGY DEVELOPMENT CORPORATION
(A NEWLY FORMED DELAWARE CORPORATION)
NOTES TO BALANCE SHEET
JULY 24, 1996
1. ORGANIZATION AND BUSINESS PURPOSE
Offshore Energy Development Corporation (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' interests in OEDC Partners, L.P. (the
"Combination").
In completing the Combination, the Company expects to issue 5,051,882
shares of common stock to the stockholders of OEDC, Inc. and the partners of
OEDC Partners, L.P.
As a condition to the Combination, the Company expects to initiate a public
issuance of 3,500,000 shares of common stock.
2. STOCKHOLDERS' EQUITY
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 July 24, 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 receive 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.
3. 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, nonqualified stock options, restricted stock
awards, stock appreciation rights, performance awards and phantom stock awards,
or any combination thereof. Options to purchase 727,580 shares of common stock
will be outstanding and subject to vesting requirements. Of such, options to
purchase 187,580 shares of common stock (of which 99,268 are currently
exercisable) will be 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. The exercise price of the balance of the options to
purchase 727,580 shares of common stock will be at the initial public offering
price.
F-9
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Board of Directors
OEDC, Inc.
The Partners
OEDC Partners, L.P.:
We have audited the accompanying consolidated balance sheets of OEDC, Inc. and
OEDC Partners, L.P. as of December 31, 1995 and 1994 and as of June 30, 1996,
and the related consolidated statements of operations, stockholders'/partners'
equity, and cash flows for each of the years in the three-year period ended
December 31, 1995 and for the six-month period ended June 30, 1996. These
consolidated financial statements are the responsibility of the Companies'
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 consolidated financial position of
OEDC, Inc. and OEDC Partners, L.P. as of December 31, 1995 and 1994 and as of
June 30, 1996, and the results of their operations and their cash flows for each
of the years in the three-year period ended December 31, 1995 and for the
six-month period ended June 30, 1996 in conformity with generally accepted
accounting principles.
As discussed in note 1 to the consolidated financial statements, the Companies
adopted the provisions of the Financial Accounting Standards Board Statement of
Financial Accounting Standards No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed of in 1996.
KPMG Peat Marwick LLP
Houston, Texas
August 23, 1996
F-10
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
-------------------------- --------------------------
1994 1995 1995 1996
------------ ------------ ----------- ------------
(UNAUDITED)
<S> <C> <C> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents........ $ 8,413,782 $ 710,306 $ 1,550,389 $ 1,577,455
Accounts receivable -- trade,
net............................ 174,776 1,660,193 338,558 1,239,298
Accounts
receivables -- affiliate....... 844,537 653,068 1,589,228 97,343
Accounts receivable -- other..... 72,968 38,930 531,577 1,254,508
Prepaids and other assets........ 115,486 27,484 47,683 340,466
------------ ------------ ----------- ------------
Total current assets........ 9,621,549 3,089,981 4,057,435 4,509,070
Oil and gas properties -- at cost
(successful efforts method)...... 10,434,526 26,153,845 21,191,736 26,230,131
Other property and equipment....... 218,775 329,923 325,320 342,657
Accumulated depreciation, depletion
and amortization................. (1,053,960) (6,376,095) (2,528,321) (9,271,502)
------------ ------------ ----------- ------------
9,599,341 20,107,673 18,988,735 17,301,286
Investments in affiliates and
others........................... (473,603) 245,783 104,473 508,477
Restricted investments............. 820,170 1,378,601 1,295,232 1,938,950
Deferred and other assets.......... 467,828 348,347 412,237 293,251
------------ ------------ ----------- ------------
Total Assets................ $ 20,035,285 $ 25,170,385 $24,858,112 $ 24,551,034
============ ============ =========== ============
LIABILITIES AND
STOCKHOLDERS'/PARTNERS' EQUITY
Current Liabilities:
Accounts payable................. $ 2,480,924 $ 3,136,223 $ 4,533,356 $ 1,916,911
Payable to affiliate............. 725 1,124 12,131 21
Capital lease
payable -- current............. 36,960 168,168 160,102 177,543
Abandonment reserve.............. 292,425 -- -- --
Federal income taxes payable..... 3,705 -- -- --
Accrued liabilities.............. 569,331 357,766 142,285 926,548
Current portion of long-term
debt........................... 1,430,772 12,260,962 1,430,772 2,500,000
------------ ------------ ----------- ------------
Total current liabilities... 4,814,842 15,924,243 6,278,646 5,521,023
Long-term debt..................... 5,969,228 -- 10,921,579 --
Deferred tax liability............. 23,018 -- -- 13,130
Capital lease
payable -- noncurrent............ 308,805 831,692 918,056 740,512
Reserve for abandonment............ 227,305 236,608 502,833 305,402
------------ ------------ ----------- ------------
Total Liabilities........... 11,343,198 16,992,543 18,621,114 6,580,067
Redeemable preference units, net... 6,500,000 10,294,365 6,500,000 10,647,603
Stockholders'/partners' equity
(deficit)
Partners' equity (deficit)
Natural Gas Partners,
L.P. -- limited partner..... (788,375) (524,990) (788,375) 4,097,478
Offshore Energy Development
Corporation -- limited
partner..................... 2,821,184 (1,688,864) 379,137 2,933,602
------------ ------------ ----------- ------------
Total Partners' Equity
(Deficit)................. 2,032,809 (2,213,854) (409,238) 7,031,080
Stockholders' equity
Class A common stock, $.01 par
value; authorized 6,000
shares; issued 6,000 shares
(1995) and 600 shares
(1994)...................... 6 60 6 60
Class B common stock, $.01 par
value; authorized 6,000
shares; issued 6,000 shares
(1995 and 1994)............. 60 60 60 60
Additional paid-in capital..... 90,843 90,843 90,843 90,843
Retained earnings.............. 68,369 6,368 55,327 201,321
------------ ------------ ----------- ------------
Total
Stockholders'/Partners'
Equity (Deficit).......... 2,192,087 (2,116,523) (263,002) 7,323,364
------------ ------------ ----------- ------------
Commitments and contingencies......
Total Liabilities and
Stockholders'/Partners'
Equity.................... $ 20,035,285 $ 25,170,385 $24,858,112 $ 24,551,034
============ ============ =========== ============
</TABLE>
See accompanying notes to consolidated financial statements.
F-11
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
SIX MONTH PERIOD
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
---------------------------------------- --------------------------
1993 1994 1995 1995 1996
------------ ------------ ------------ ----------- ------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Income:
Exploration and production....... $ 1,744,466 $ 5,512,496 $ 6,168,591 $ 1,859,093 $ 5,548,829
Pipeline operating and
marketing...................... 357,758 358,150 166,419 93,514 493,750
Equity in earnings (loss) of
equity investments............. (255,493) (2,779) 496,979 314,538 23,171
Gain on sales of oil and gas
properties or partnership
investments, net............... -- 13,655,225 -- -- 10,661,433
------------ ------------ ------------ ----------- ------------
Total Income................ 1,846,731 19,523,092 6,831,989 2,267,145 16,727,183
------------ ------------ ------------ ----------- ------------
Expenses:
Operations and maintenance....... 570,167 1,410,231 2,210,070 1,063,927 1,025,003
Exploration charges.............. 32,349 2,231,349 404,836 153,353 421,368
Depreciation, depletion and
amortization................... 354,617 2,112,350 5,501,072 1,597,913 2,876,566
Abandonment expense.............. 59,120 2,735,253 84,219 13,159 216,121
General and administrative....... 1,724,443 2,358,668 2,191,877 1,155,591 1,154,915
------------ ------------ ------------ ----------- ------------
Total Expenses.............. 2,740,696 10,847,851 10,392,074 3,983,943 5,693,973
------------ ------------ ------------ ----------- ------------
Earnings (losses) before interest and
taxes.............................. (893,965) 8,675,241 (3,560,085) (1,716,798) 11,033,210
Interest Income (Expense) and Other:
Interest expense................. (228,385) (589,948) (1,651,063) (696,688) (622,132)
Preferential payments by
subsidiaries................... -- (1,430,722) -- -- --
Interest income and other........ (225,566) 316,668 122,974 229,612 (64,823)
------------ ------------ ------------ ----------- ------------
Total Interest Income
(Expense) and Other....... (453,951) (1,704,002) (1,528,089) (467,076) (686,955)
------------ ------------ ------------ ----------- ------------
Income (Loss) Before Income Taxes.... (1,347,916) 6,971,239 (5,088,174) (2,183,874) 10,346,255
Income Tax Benefit (Expense)......... -- (26,723) 21,375 10,045 (13,130)
------------ ------------ ------------ ----------- ------------
Net Income (Loss).................... (1,347,916) 6,944,516 (5,066,799) (2,173,829) 10,333,125
Preference unit payments and
accretion of discount.......... (731,250) (585,000) (1,141,865) (292,500) (893,238)
------------ ------------ ------------ ----------- ------------
Income (loss) available to common
unit holders and stockholders...... $ (2,079,166) $ 6,359,516 $ (6,208,664) $(2,466,329) $ 9,439,887
============ ============ ============ =========== ============
Pro forma net income (loss) data
(unaudited)
Net income (loss) as reported.... $ (5,066,799) $ 10,333,125
Pro forma adjustment for federal
income tax benefit (expense)....... 1,874,716 (3,823,256)
------------ ------------
Pro forma net income (loss).......... (3,192,083) 6,509,869
Preference unit payments......... (1,141,865) (893,238)
------------ ------------
Pro forma income (loss) available to
common unit holders and
stockholders....................... (4,333,948) 5,616,631
============ ============
Pro forma income (loss) available to
common unit holders and
stockholders per common share...... $ (0.86) $ 1.11
============ ============
Pro forma weighted average of common
shares outstanding................. 5,051,885 5,051,885
============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
F-12
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS'/PARTNERS' EQUITY
<TABLE>
<CAPTION>
PARTNERS' EQUITY (DEFICIT)
------------------------------------------------
OFFSHORE ENERGY STOCKHOLDERS' EQUITY (DEFICIT)
DEVELOPMENT NATURAL GAS --------------------------------
CORPORATION PARTNERS, L.P. TOTAL ADDITIONAL RETAINED
(LIMITED (LIMITED PARTNERS' COMMON PAID-IN EARNINGS
PARTNER) PARTNER) EQUITY STOCK CAPITAL (DEFICIT)
--------------- --------------- ---------- ------ ---------- --------
<S> <C> <C> <C> <C> <C> <C>
January 1, 1993...................... $ 1,008,912 $ (119,805) $ 889,107 $ 66 $ 90,843 $(9,153)
Adjustments to assets contributed at
August 31, 1992.................... 17,555 -- 17,555 -- -- --
Net loss............................. (1,336,749) -- (1,336,749) -- -- (11,167)
Preference unit payments............. (723,937) -- (723,937) -- -- (7,313)
--------------- --------------- ---------- ------ ---------- --------
December 31, 1993.................... (1,034,219) (119,805) (1,154,024) 66 90,843 (27,633)
Capital distributions................ (2,408,111) (668,570) (3,076,681) -- -- --
Net income........................... 6,842,664 -- 6,842,664 -- -- 101,852
Preference unit payments............. (579,150) -- (579,150) -- -- (5,850)
--------------- --------------- ---------- ------ ---------- --------
December 31, 1994.................... 2,821,184 (788,375) 2,032,809 66 90,843 68,369
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 -- --
Net loss............................. (3,700,038) (1,316,179) (5,016,217) -- -- (50,582)
Preference unit payments............. (564,300) (274,725) (839,025) -- -- (8,475)
Accretion of discount on preference
units.............................. (145,710) (145,711) (291,421) -- -- (2,944)
--------------- --------------- ---------- ------ ---------- --------
December 31, 1995.................... (1,688,864) (524,990) (2,213,854) 120 90,843 6,368
Net income........................... 5,064,619 5,064,621 10,129,240 -- -- 203,885
Preference unit payments............. (267,300) (267,300) (534,600) -- -- (5,400)
Accretion of discount on preference
units.............................. (174,853) (174,853) (349,706) -- -- (3,532)
--------------- --------------- ---------- ------ ---------- --------
June 30, 1996........................ $ 2,933,602 $ 4,097,478 $7,031,080 $120 $ 90,843 $201,321
=============== =============== ========== ====== ========== ========
</TABLE>
TOTAL
STOCKHOLDERS'/
PARTNERS'
EQUITY (DEFICIT)
----------------
January 1, 1993...................... $ 970,863
Adjustments to assets contributed at
August 31, 1992.................... 17,555
Net loss............................. (1,347,916)
Preference unit payments............. (731,250)
----------------
December 31, 1993.................... (1,090,748)
Capital distributions................ (3,076,681)
Net income........................... 6,944,516
Preference unit payments............. (585,000)
----------------
December 31, 1994.................... 2,192,087
Capital distributions................ (100,000)
Issuance of common units, 99,000
units.............................. 2,000,000
Issuance of common stock, 5,400
shares............................. 54
Net loss............................. (5,066,799)
Preference unit payments............. (847,500)
Accretion of discount on preference
units.............................. (294,365)
----------------
December 31, 1995.................... (2,116,523)
Net income........................... 10,333,125
Preference unit payments............. (540,000)
Accretion of discount on preference
units.............................. (353,238)
----------------
June 30, 1996........................ $7,323,364
================
See accompanying notes to consolidated financial statements.
F-13
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
SIX MONTH PERIOD
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------------------- ------------------------
1993 1994 1995 1995 1996
----------- ----------- ----------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
OPERATING ACTIVITIES
Net income (loss)..................... $(1,347,916) $ 6,944,516 $(5,066,799) $(2,173,829) $10,333,125
Adjustments to reconcile net income
(loss) to cash provided
by (used in) operations
Depreciation, depletion and
amortization.................... 422,074 2,234,000 5,652,841 1,643,010 2,954,580
Abandonment expense............... 59,120 2,735,253 84,219 13,159 68,944
Gain on sales, net................ -- (13,655,225) -- -- (10,661,433)
Dry hole expense.................. -- 1,585,872 -- -- --
Transfer of partnership equity
interest........................ -- 1,300,000 41,126 -- --
Equity in (earnings) loss of
equity investments, net......... 255,493 2,779 (496,979) (314,538) (23,171)
Change in interest of oil and gas
partnerships.................... (491,593) 25,864 344,590 262,483 (1,269)
Deferred taxes.................... -- 23,018 (23,018) -- 13,130
Changes in assets and liabilities:
Accounts receivable............. (597,441) 1,211,677 (1,561,151) (243,429) 464,203
Deferred and other assets....... (104,410) (72,381) 134,016 (380,312) (1,528,034)
Accounts payable................ 535,673 443,173 719,648 2,090,514 (1,220,361)
Accrued liabilities............. 454,115 54,839 (211,565) (427,046) 568,788
----------- ----------- ----------- ----------- -----------
Total adjustments........... 533,031 (4,111,131) 4,683,727 2,643,841 (9,364,623)
----------- ----------- ----------- ----------- -----------
Net cash provided by (used in)
operating activities.......... (814,885) 2,833,385 (383,072) 470,012 968,502
INVESTING ACTIVITIES
Investment in equity interests........ 1,442,908 (192,474) (263,534) (263,537) (252,678)
Advances to equity investees.......... -- (714,918) (836,137) (717,940) --
Repayments from equity investees...... -- 40,624 997,791 7,553 512,640
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) 246,030 -- -- --
Restricted investments in certificates
of deposit.......................... (220,500) (134,682) (558,431) (506,722) (560,349)
Acquisition of property and
equipment........................... (10,993,011) (18,418,340) (15,965,301) (10,493,078) (758,292)
----------- ----------- ----------- ----------- -----------
Net cash provided by (used in)
investing activities.......... (10,016,633) 21,133,109 (16,625,612) (11,973,724) 10,281,414
FINANCING ACTIVITIES
Capital contributions................. 17,555 -- -- 11,240 --
Capital distributions................. -- (3,076,681) (100,000) -- --
Preference unit payments.............. (731,250) (585,000) (847,500) (292,500) (540,000)
Proceeds from issuance of redeemable
preference units and common units... -- -- 5,500,000 -- --
Proceeds (payment) of note payable to
partner............................. 2,000,000 (2,000,000) -- -- --
Proceeds from borrowings.............. -- 7,400,000 8,291,492 6,291,493 --
Principal payments on borrowings...... -- -- (3,430,530) (1,339,142) (9,760,962)
Fees paid to acquire financing........ -- (560,003) -- -- --
Proceeds from (settlement of)
production payment.................. 12,414,604 (20,237,945) -- -- --
Principal payments on capital lease... (51,299) (490,513) (108,254) (30,772) (81,805)
----------- ----------- ----------- ----------- -----------
Net cash provided by (used in)
financing activities.......... 13,649,610 (19,550,142) 9,305,208 4,640,319 (10,382,767)
----------- ----------- ----------- ----------- -----------
Increase (decrease) in cash and
cash equivalents.............. 2,818,092 4,416,352 (7,703,476) (6,863,393) 867,149
Cash and cash equivalents balance,
beginning of period................. 1,179,338 3,997,430 8,413,782 8,413,782 710,306
----------- ----------- ----------- ----------- -----------
Cash and cash equivalents balance, end
of period........................... $ 3,997,430 $ 8,413,782 $ 710,306 $ 1,550,389 $ 1,577,455
=========== =========== =========== =========== ===========
Supplemental disclosures of cash flow
information:
Cash paid during the period for
interest........................ $ 785,862 $ 353,809 $ 1,760,571 $ 830,078 $ 307,762
=========== =========== =========== =========== ===========
Cash paid during the period for
income taxes.................... $ -- $ -- $ -- $ -- $ --
=========== =========== =========== =========== ===========
Supplemental disclosure of non-cash
activities
Capital lease acquisition......... $ 406,921 $ 256,553 $ 762,349 $ 763,164 $ --
Net contribution to affiliate..... 13,692 -- -- -- --
Issuance of stock................. -- -- 54 -- --
Accretion of discount on
preference units................ -- -- 294,365 -- 353,238
</TABLE>
See accompanying notes to consolidated financial statements.
F-14
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
1. GENERAL INFORMATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF PRESENTATION
The stockholders of OEDC, Inc. ("Inc.") and the partners of OEDC
Partners, L.P. ("Partners") have agreed to consummate a combination (the
"Combination") through the exchange of their interests for shares of common
stock of a newly formed entity, Offshore Energy Development Corporation
("OEDC"). The stockholders and partners hold interests in both Inc. and
Partners. OEDC will serve as the parent company of Inc. and Partners.
OEDC intends to initiate a public issuance of approximately 35% of its
authorized common stock (the Offering) as a condition to consummation of the
Combination.
The consolidated financial statements include the accounts of Inc. and
Partners (collectively the "Company"). 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 due to the commonality of the stockholders and partners of Inc. and
Partners. As a result of the consolidated presentation, Inc.'s 1% general
partner interest in Partners has been eliminated. Partners' investments in
associated oil and gas partnerships are accounted for using the proportionate
consolidation method, whereby Partners' proportionate share of each oil and gas
partnerships' assets, liabilities, revenues, and expenses is included in the
appropriate classifications in Partners' financial statements. Investments in
non-oil and gas partnerships where the Company has ownership interests of less
than 50% are accounted for on the equity method, all investments with ownership
interests 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.
ORGANIZATION
OEDC, INC. Inc. was formed on August 31, 1992 for the purpose of investing
in certain partnerships involved in drilling, producing, marketing, gathering
and storing oil and gas. Inc.'s only significant assets are its general
partnership interests.
Inc. accounts for income taxes under the asset and liability method.
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to temporary differences between the financial
reporting basis and tax basis of Inc.'s assets and liabilities. Deferred tax
assets are also recognized for the tax effect of operating loss carryforwards
and other tax credit carryforwards available to Inc. Deferred tax assets and
liabilities are measured using the enacted tax rates expected to apply to
taxable income in the years in which those temporary differences are expected to
be recovered or settled. Total deferred tax assets are reduced by a valuation
allowance to an amount that in management's judgment is more likely than not to
be realized as a future tax benefit.
OEDC PARTNERS, L.P. Partners was formed on August 31, 1992 for the purpose
of investing in certain partnerships involved in drilling, producing, marketing,
gathering and storing oil and gas. On the date of formation, Inc., the general
partner, contributed approximately $90,000 and the limited partners, Offshore
Energy Development Corporation (a Texas Corporation) and Natural Gas Partners,
L.P. and affiliates (NGP), contributed net assets approximating $1,496,000 and
$6,380,000, including cash of approximately $6,375,000, in exchange for 2,000
common units, 99,000 common units and 100,000 preference units, respectively.
These contributions were recorded by Partners at the partners' historical cost.
Partners' partnership agreement was amended effective July 31, 1995. In
accordance with the amended partnership agreement, NGP contributed $5,500,000 in
exchange for an additional 20,000 preference units, and 99,000 common units and
an increase in the redemption price of all 120,000 preference units to $100
F-15
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
from $65 per unit, resulting in a redemption value of $12 million. The NGP
contribution has been allocated $3,500,000 to preference units and $2,000,000 to
common 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. Subsequent to the amendment, the ownership interests
of Inc., Offshore Energy Development Corporation (an S Corporation) and NGP were
1%, 49.5% and 49.5%, respectively. At December 31, 1997 Partners is required to
redeem 50% of the preference units outstanding at a rate of $100 per unit. At
December 31, 1998 Partners is required to redeem all remaining preference units
outstanding at a rate of $100 per unit. Under the partnership agreement,
Partners pays NGP a 9% coupon on the preference units outstanding. Partners is
scheduled to make the following preference payments in equal quarterly
installments: $1,080,000 in 1996; $1,080,000 in 1997; and $540,000 in 1998. If
the preference payments are not made according to schedule, the rate of
preference increases from 9% per annum to 15% per annum and any distributions by
Partners are first applied to preference payments in arrears. If more than two
preference payments are not made as scheduled, NGP becomes entitled to certain
voting rights in Partners.
Partners is not subject to federal income taxes. Income and losses earned
by Partners are passed through to its partners on the basis of the earnings
ratio established in the partnership agreement.
UNAUDITED PRO FORMA CONSOLIDATED INFORMATION
Pro forma net income (loss) at June 30, 1996 and December 31, 1995,
respectively, reflects federal income taxes that would have been recorded had
Partners been subject to such taxes. Such amounts have been included in the
statements of operations pursuant to the rules and regulations of the Securities
and Exchange Commission ("SEC") for instances when a partnership becomes
subject to federal income taxes. Pro forma net income (loss) per common share is
presented giving effect to the number of shares outstanding subsequent to the
exchange of stockholders' equity of Inc. and partners' equity of Partners for
5,051,882 common shares of OEDC.
Pro forma net income (loss) available to common unit holders and
stockholders per common share adjusted as if the redemption of the redeemable
preference units had occurred on January 1, 1995 would be $(0.52) and $1.05 at
December 31, 1995 and June 30, 1996, respectively. Pro forma net income (loss)
available to common unit holders and stockholders is presented giving effect to
the number of shares, 1,128,405, whose proceeds would be necessary to redeem the
redeemable preference units at the face value thereof based on the offering
price of $12.00 per common share, reduced for offering costs, and after
conversion of stockholders' equity of Inc. and partners' equity of Partners for
5,051,882 common shares of OEDC.
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.
F-16
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
Capitalized costs of producing oil and gas properties are amortized using the
unit-of-production method based on units of proved reserves for each property.
The costs of unproved leaseholds are capitalized pending the results of
exploration efforts. Significant unproved leasehold costs are assessed
periodically, on a property-by-property basis, and a loss is recognized to the
extent, if any, that the cost 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 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
cash flows (undiscounted) of the asset. Under SFAS No. 121, the Company
performed 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, was estimated to be the present value of expected 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 a world-wide basis. Using the world-wide 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, 1994 or 1993.
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 interests in the properties. Gas balancing obligations
as of December 31, 1995 1994 and 1993 and as of June 30, 1996, 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. Gains and
losses on closed natural gas swap agreements will be deferred and
F-17
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
amortized over the original term of the agreement. Should the natural gas price
swaps cease to become recognized as a hedge, subsequent changes in value will be
recorded in the Statement 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 of five to seven years.
DEFERRED AND OTHER ASSETS
The June 30, 1996 and December 31, 1995 and 1994 balances primarily
consists of financing fees incurred in securing a long-term note payable. The
financing fees are being amortized over the life of the loan.
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 June 30, 1996 and at December
31, 1995 and 1994 approximates fair value as this debt bears interest at rates
which approximate current market rates.
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 Inc. and Partners, the Company has an investment in Dauphin
Island Gathering Partners ("DIGP") that is accounted for using the equity
method. This investment includes undistributed earnings (losses) of
approximately $23,000 in 1996, $497,000 in 1995, $(3,000) in 1994 and $(255,000)
in 1993.
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 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.
F-18
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
On March 25, 1994, DIGP entered into a contribution agreement with Tenneco
Gas, Inc. ("Tenneco"), whereby Tenneco contributed $19 million in cash,
contracts and material 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 material 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% of its remaining interest in
DIGP to a subsidiary of MCN Investment Corporation ("MCN") thereby reducing
its interest in DIGP to 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 15% when MCN receives the return of its investment
plus a 10% rate of return, subject to certain other conditions.
Summarized financial data of DIGP as of December 31, 1995, 1994 and 1993
and for the years then ended follows:
<TABLE>
<CAPTION>
1993 1994 1995
-------------- -------------- --------------
<S> <C> <C> <C>
Current assets.......................... $ 1,492,855 $ 3,496,164 $ 1,963,998
Long-term assets........................ 19,112,141 51,714,521 58,172,859
-------------- -------------- --------------
Total assets....................... $ 20,604,996 $ 55,210,685 $ 60,136,857
============== ============== ==============
Current liabilities..................... $ 1,744,302 $ 6,702,506 $ 9,689,455
Long-term liabilities................... 8,244,290 18,461,633 18,375,242
Partners' capital....................... 10,616,404 30,046,546 32,072,160
-------------- -------------- --------------
Total liabilities and partners'
capital.......................... $ 20,604,996 $ 55,210,685 $ 60,136,857
============== ============== ==============
Revenues................................ $ 2,007,780 $ 4,482,987 $ 9,526,215
Operating expenses...................... (2,535,848) (4,299,971) (7,500,601)
-------------- -------------- --------------
Net income (loss).................. $ (528,068) $ 183,016 $ 2,025,614
============== ============== ==============
The Company's share of net income
(loss)................................ $ (264,034) $ 29,661 $ 506,403
============== ============== ==============
</TABLE>
Summarized financial data for the six-month period ending and as of June
30, 1996 is not presented since the Company's ownership interest in DIGP is not
material to its current operations.
The Company has approximately $250,000 invested in Asia-Pacific Refinery
Investment, L.P. ("APRI"), representing a 13% limited partnership interest.
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 and transported to Papua New Guinea. APRI has already
purchased the necessary refinery site in Papua New Guinea. The refinery is
expected to begin operations in 1997. The Company also has a $4,109 investment
in the Salach Partnership
F-19
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
("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 (8.25% at June 30,
1996). 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 are to begin on or before March 20, 1995 for the
term loan. 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 agreement. At June 30, 1996 and December 31, 1995 and
1994, the Company had borrowed $2,500,000, $5,000,000 and $5,000,000,
respectively, against the revolving loan. At June 30, 1996 there are no amounts
outstanding under the term loan and at December 31, 1995 and 1994 there is
$7,260,962 and $2,400,000 outstanding, respectively, against the term loan. As
the revolving loan is payable in full in August 1996, the entire balance is
classified as short-term at June 30, 1996 and December 31, 1995.
The debt is collateralized by the Company's investments in oil and gas
properties. The debt agreement contains restrictions on working capital and
tangible net worth. In addition, the agreement restricts the assumption of
additional debt and the sale of oil and gas properties.
The Company is in compliance with all debt covenants for all periods
presented.
The Company is currently negotiating a credit facility with a third party
lending institution and plans to use the proceeds to pay its outstanding debt
balance and finance future development of oil and gas properties.
4. ABANDONMENT OF OIL AND GAS OF PROPERTIES
Oil and gas properties at December 31, 1993 included capitalized costs
associated with the Company's interest in Eugene Island Block 163 which was
damaged by Hurricane Andrew.
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.
F-20
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
5. 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 $822,000 in 1996 as a result of the
swap agreements. At June 30, 1996, the Company had the following commitments
under swap agreements:
VOLUME FIXED PRICE
TIME PERIOD (MMBTU) ($/MMBTU)
- ------------------------------------- --------- ------------
August 1996.......................... 260,000 $1.849
September 1996....................... 290,000 2.512
October 1996......................... 280,000 2.482
November 1996........................ 270,000 2.482
December 1996........................ 260,000 2.544
January 1997......................... 260,000 2.537
February 1997........................ 250,000 2.428
March 1997 to September 1997......... 60,000 2.009
October 1997 to December 1997........ 50,000 2.009
The natural gas price swap agreement for July 1996 production was closed
prior to June 30, 1996. Recognition of the related decrease in exploration and
production revenues of approximately $206,000 has been deferred and is currently
recorded as a deferred item in prepaids and other assets in the balance sheet at
June 30, 1996. At June 30, 1996, the Company estimates the cost of unwinding
these positions to be approximately $679,000.
During 1995 and 1994, the Company entered into natural gas price 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. During 1993, the
Company did not participate in natural gas hedging activities.
6. 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.
F-21
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
7. CAPITAL LEASE
During 1994, the Company entered into a capital lease agreement for a
compressor unit. The compressor, with a net book value at June 30, 1996 of
approximately $915,000, 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 June 30, 1996 are as follows:
YEAR ENDED
DECEMBER 31,
- ---------------
1996............................... $ 135,684
1997............................... 271,368
1998............................... 271,368
1999............................... 271,368
2000............................... 22,614
----------
Total future minimum lease
obligations........................ 972,402
Less amounts representing interest... 54,347
----------
Present value of future minimum lease
payments........................... 918,055
Less current installments of
obligation under capital lease..... 177,543
----------
Obligations under capital leases,
excluding current installments..... $ 740,512
==========
8. 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 six-month period ending
June 30, 1996, the Company charged $281,337 in operator fees to DIGP, of which
$57,087 is a receivable at June 30, 1996. In 1995, the Company charged $139,544
in operator's 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's fees and construction overhead fees to DIGP, of which $90,162 is a
receivable at December 31, 1994.
RECEIVABLE FROM AFFILIATE
At June 30, 1996, the Company had affiliated receivables from DIGP and the
Company's officers of $38,338 and $1,864, respectively, for expenses paid by the
Company on behalf of DIGP and the officers. Also at June 30, 1996, the Company
had a receivable from NGP in the amount of $54 for the purchase of the Company's
common stock in 1995.
Also at June 30, 1996, the Company had a receivable from Enron Capital &
Trade Resources ("ECT") for $1,234,401 for development costs paid by the
Company on behalf of ECT. This receivable is included in the accounts receivable
from others balance at June 30, 1996.
At December 31, 1995, the Company had affiliated receivables from DIGP of
$585,732, representing expenses paid by the Company on behalf of the affiliates
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 Company's common stock and $1,713 from the Company's
officers for expenses paid by the Company on behalf of the officers.
F-22
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
At December 31,1994, the Company had affiliated receivables of $752,669
from DIGP, and $1,706 from the Company's officers for expenses paid by the
Company on behalf of the affiliates and officers.
PAYABLE TO AFFILIATES
At June 30, 1996, the Company had an affiliated payables of $21 to officers
of the Company for expenses paid by the officers on behalf of the Company.
At December 31, 1995, the Company had affiliated payables $725 to DIGP and
$399 to officers of the Company for expenses paid by DIGP and the officers on
behalf of the Company.
At December 31, 1994, the Company had an affiliated payable of $725 to DIGP
representing expenses paid by DIGP on behalf of the Company.
PREFERENCE UNIT PAYMENTS
Preference unit payments totaling $540,000, $847,500, $585,000 and $731,250
were paid to NGP for preference units outstanding during the six-month period
ending June 30, 1996 and during the annual periods ending December 31, 1995,
1994 and 1993 respectively.
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 majority shareholders of the Company is also the 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 $622,000 for the period ending June 30, 1996 and approximately
$1,197,000, $1,065,000 and $855,000 for each of the years ending December 31,
1995, 1994 and 1993, respectively. No amounts were outstanding or payable under
this arrangement at the end of any of the periods presented.
9. INCOME TAXES
As discussed in Note 1, Inc. accounts for income taxes under the asset and
liability method.
Income tax expense (benefit) relating to Inc.'s pretax operating results
for the six-month period ended June 30, 1996 and the years ended December 31,
1995, 1994 and 1993 consists of:
<TABLE>
<CAPTION>
1993 1994 1995 1996
--------- --------- ---------- ---------
<S> <C> <C> <C> <C>
Current federal expense................. $ -- $ 3,705 $ 1,643 $ --
Deferred federal expense (benefit)...... -- 23,018 (23,018) 13,130
--------- --------- ---------- ---------
$ -- $ 26,723 $ (21,375) $ 13,130
========= ========= ========== =========
</TABLE>
Income and tax expense (benefit) is different from expected tax expense at
34% due to the increase in valuation allowance and the effects of progressive
tax rates.
F-23
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
Tax effects of temporary differences that give rise to significant portions
of the deferred tax assets and deferred tax liabilities at June 30, 1996 and at
December 31, 1995 and 1994 are presented below:
1994 1995 1996
--------- ---------- ---------
Net operating loss carry forwards....... $ -- $ 54,706 $ 74,645
--------- ---------- ---------
Total gross deferred tax assets.... -- 54,706 74,645
Valuation allowance................ -- (22,864) --
--------- ---------- ---------
Net deferred tax assets............ -- 31,842 74,645
--------- ---------- ---------
Investments in partnerships, principally
due to
differences in book and tax bases..... 23,018 31,842 87,775
--------- ---------- ---------
Total gross deferred tax
liabilities...................... 23,018 31,842 87,775
--------- ---------- ---------
Net deferred tax liability.... $ 23,018 $ -- $ 13,130
========= ========== =========
There was an increase in the valuation allowance for deferred tax assets of
$22,864 as of January 1, 1996. The change in the total valuation allowance for
the six-months ended June 30, 1996 was a decrease of $22,864. There was no
valuation allowance for any period presented prior to December 31, 1995.
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. The net deferred tax asset primarily relates to net
operating loss carryforwards which will begin to expire in 2010 if not
previously utilized. At June 30, 1996, Partners' tax basis in oil and gas
operations is approximately $11,462,000.
10. RESTRICTED INVESTMENTS
The Company carries a $3 million 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 June
30, 1996 and approximately $1.4 million and $800,000 at December 31, 1995 and
1994, respectively.
The Company also has approximately $500,000 invested in an escrow account
at June 30, 1996 maintained in connection with a turnkey drilling contract.
11. COMMITMENTS AND CONTINGENCIES
OPERATING LEASES
The Company has a noncancelable 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 ended:
1996.................................... $ 53,804
1997.................................... 116,976
1998.................................... 87,732
----------
$ 258,512
==========
Rent expense was $115,698, $82,583 and $35,639 in 1995, 1994 and 1993,
respectively and $56,845 for the six-month period ended June 30, 1996.
F-24
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
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.
The Company denies the plaintiffs' allegations and is vigorously defending
this matter. The Company has raised the affirmative defenses of statute of
frauds, statute of limitations, laches, waiver and estoppel, and plans to file a
motion for summary judgment on its defenses. Discovery is ongoing in the case
and a trial date has not been set. 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 operation, 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 June 30, 1996, the Company has taken the
steps necessary to terminate its obligations under the commitment with no
significant additional cost to future operations.
During 1995 and 1994 and for the first six months of 1996, approximately
80% of the Company's natural gas sales were to a single customer. During 1993,
approximately 58% 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.
12. 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, 1995 have been estimated by an independent petroleum
engineer in accordance with guidelines established by the SEC. Total proved and
proved developed oil and gas reserves at December 31, 1994 and 1993 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 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 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. All of
the Company's properties are located onshore in the United States or offshore in
the Gulf of Mexico in federal or state waters.
F-25
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
DECEMBER 31,
------------------------------
1994 1995
-------------- --------------
Proved properties.................... $ 1,074,431 $ 22,234,125
Unproved properties.................. 9,360,095 3,919,720
-------------- --------------
10,434,526 26,153,845
Accumulated depreciation, depletion,
and amortization................... (932,338) (6,210,210)
-------------- --------------
$ 9,502,188 $ 19,943,635
============== ==============
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------------
1993 1994 1995
-------------- -------------- --------------
<S> <C> <C> <C>
Acquisition of properties:
Proved.......................... $ 3,477,431 $ 2,173,901 $ 1,850,000
Unproved........................ -- 2,422,080 --
Exploration costs.................... 32,349 2,231,349 404,836
Development costs.................... 7,980,263 14,070,818 13,876,703
-------------- -------------- --------------
$ 11,490,043 $ 20,898,148 $ 16,131,539
============== ============== ==============
</TABLE>
RESULTS OF OPERATIONS FOR GAS AND OIL PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------------
1993 1994 1995
------------ -------------- --------------
<S> <C> <C> <C>
Revenues............................. $ 1,744,466 $ 5,512,496 $ 6,168,591
Lifting costs:
Lease operating expense......... 570,167 1,410,231 1,876,186
------------ -------------- --------------
1,174,299 4,102,265 4,292,405
General operating expense............ (202,966) (388,097) (423,742)
Exploration charges.................. (32,349) (2,231,349) (404,836)
Depreciation, depletion, and
amortization....................... (354,617) (2,112,350) (5,501,072)
Abandonment of oil and gas
properties......................... (59,120) (2,735,253) (84,219)
------------ -------------- --------------
Results of operations from producing
activities......................... $ 525,247 $ (3,364,784) $ (2,121,464)
============ ============== ==============
</TABLE>
F-26
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
RESERVE QUANTITY INFORMATION
GAS
(MCF)
--------------
Year Ended December 31, 1993:
Proved Developed and Undeveloped
Reserves:
Beginning of year.......... 309,260
Purchases of reserves in
place................... --
Sales of reserves in
place................... --
Revisions of previous
estimates............... 1,539,460
Extensions and
discoveries............. 22,756,762
Production................. (672,838)
--------------
End of year................ 23,932,644
==============
Year Ended December 31, 1994:
Proved Developed and Undeveloped
Reserves:
Beginning of year.......... 23,932,644
Purchases of reserves in
place................... --
Sales of reserves in
place................... (19,849,128)
Revisions of previous
estimates............... 4,315,561
Extensions and
discoveries............. --
Production................. (3,685,681)
--------------
End of year................ 4,713,396
==============
Year Ended December 31, 1995:
Proved Developed and Undeveloped
Reserves:
Beginning of year.......... 4,713,396
Purchases of reserves in
place................... 5,299,000
Sales of reserves in
place................... --
Revisions of previous
estimates............... 8,718,305
Extensions and
discoveries............. 5,223,000
Production................. (3,667,701)
--------------
End of year................ 20,286,000
==============
Proved Developed Reserves:
December 31, 1993............... 23,932,644
December 31, 1994............... 4,713,396
December 31, 1995............... 14,987,000
==============
F-27
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------------------
1993 1994 1995
-------------- -------------- --------------
<S> <C> <C> <C>
Future cash inflows..................... $ 50,182,689 $ 6,719,617 $ 46,478,461
Future development costs................ (258,771) (138,771) (7,173,990)
Future production costs................. (8,165,645) (1,935,929) (7,589,878)
-------------- -------------- --------------
Future net cash inflows................. 41,758,273 4,644,917 31,714,593
10% annual discount..................... (6,434,319) (694,423) (5,270,803)
-------------- -------------- --------------
Standardized measure of discounted
future
net cash inflows...................... $ 35,323,954 $ 3,950,494 $ 26,443,790(1)
============== ============== ==============
</TABLE>
(1) The earnings of the Company are not subject to corporate income taxes as the
Company is a combination of predominantly non-taxpaying entities. Once the
Company consummates the proposed Combination, it will become a taxable
corporation. The estimated pro forma income taxes discounted at 10%, are
approximately $6,400,000 as of December 31, 1995, resulting in estimated pro
forma discounted future net cash flows of approximately $20,331,153 as of
December 31, 1995.
PRINCIPAL SOURCES OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------------
1993 1994 1995
-------------- --------------- --------------
<S> <C> <C> <C>
Standardized measure of discounted
future
net cash flows,
Beginning of year.................. $ 417,298 $ 35,323,954 $ 3,950,494
Purchases of reserves in
place...................... -- -- 3,318,239
Sales of reserves in place.... -- (36,329,095) --
Revisions of previous quantity
estimates less related
costs...................... 2,519,201 6,034,804 17,051,312
Extensions and discoveries
less
related costs.............. 13,768,699 -- 6,678,479
Net changes in prices and
production costs........... 88,121 (3,500,358) 3,655,966
Acquisition/development costs
incurred during period and
changes in estimated future
development costs.......... 16,862,824 5,530,947 (1,329,510)
Sales of oil and gas produced
during period, net of
lifting costs.............. (1,174,299) (4,102,265) (4,292,405)
Accretion of discount......... 41,730 3,532,395 395,049
Other......................... 2,800,380 (2,539,888) (2,983,834)
-------------- --------------- --------------
Standardized measure of discounted
future
net cash flows, end of year........... $ 35,323,954 $ 3,950,494 $ 26,443,790
============== =============== ==============
</TABLE>
13. SUBSEQUENT EVENTS
Subsequent to June 30, 1996, the Company entered into an agreement to form
a partnership with MCN and PanEnergy Corp (PanEnergy) to construct, own and
operate a natural gas liquids processing plant onshore in Alabama. The
partnership will initially be owned 49.5% by each of MCN and PanEnergy and one
percent by the Company. The Company will have an option to purchase up to an
additional 32 1/3% interest in the partnership during the first three years of
plant operations. The Company will be required to
F-28
<PAGE>
OEDC, INC.
AND
OEDC PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
JUNE 30, 1996 AND DECEMBER 31, 1995, 1994 AND 1993
pay a $200,000 premium for an option to acquire the additional partnership
interest. The cost 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.
Subsequent to June 30, 1996, the Company entered into a two-year line of
credit with Union Bank of California, N.A. At August 28, 1996, the closing date,
the borrowing base was $6,250,000 and $2,633,606 was outstanding under this
facility. The borrowing base will be reduced by $312,500 per month for 12 months
commencing September 30, 1996, 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%, with an effective rate of
interest at closing of 7.84%.
Subsequent to June 30, 1996, the Company and an affiliate of ECT (the "ECT
Affiliate") formed the South Dauphin II Limited Partnership ("SDPII"). The
ECT Affiliate and the Company fund 85% and 15%, respectively, of an agreed
drilling and development budget, with the Company generally responsible for
costs in excess of budgeted amounts. The financing of SDPII will be nonrecourse
to the Company's other assets. Pursuant to the terms of the partnership
agreement, the ECT Affiliate will receive 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%. The Company has
the option to prepay the ECT Affiliate's investment and accelerate the ownership
change. If such repayment 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. During the first quarter of 1997, the Company intends to
cause SDPII to use a portion of the proceeds of the Offering to repay such
obligations 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, net of distributions.
F-29
<PAGE>
[Inside Back Cover]
Photographs of rigs and platforms.
================================================================================
NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS NOT CONTAINED IN THIS PROSPECTUS IN
CONNECTION WITH THE OFFER CONTAINED HEREIN, AND, IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED
BY THE COMPANY OR ANY UNDERWRITER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER
TO SELL OR A SOLICITATION OF AN OFFER TO BUY THE SHARES OF COMMON STOCK OFFERED
HEREBY BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT
AUTHORIZED, OR IN WHICH THE PERSON MAKING SUCH OFFER OR SOLICITATION IS NOT
QUALIFIED TO DO SO, OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH
SOLICITATION OR OFFER. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE AN IMPLICATION THAT THERE HAS
BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF OR THAT THE
INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS DATE.
------------------------
TABLE OF CONTENTS
PAGE
----
Prospectus Summary ....................................................... 3
Risk Factors ............................................................. 9
Use of Proceeds .......................................................... 17
Dividend Policy .......................................................... 18
Dilution ................................................................. 18
Capitalization ........................................................... 19
Selected Consolidated Financial Data ..................................... 20
Management's Discussion and Analysis of Financial Condition and Results
of Operations .......................................................... 21
Business and Properties .................................................. 30
Management ............................................................... 50
Principal and Selling Stockholders ....................................... 56
Description of Capital Stock ............................................. 57
Shares Eligible for Future Sale .......................................... 60
Underwriting ............................................................. 61
Legal Matters ............................................................ 62
Experts .................................................................. 62
Available Information .................................................... 63
Glossary of Certain Oil and Gas Terms .................................... 64
Index to Financial Statements ............................................ F-1
------------------------
UNTIL NOVEMBER 26, 1996 (25 DAYS AFTER THE DATE OF THIS PROSPECTUS), ALL
DEALERS EFFECTING TRANSACTIONS IN THE COMMON STOCK, WHETHER OR NOT PARTICIPATING
IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS. THIS IS IN
ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS WHEN ACTING AS
UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR SUBSCRIPTIONS.
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3,682,000 SHARES
[LOGO FOR OFFSHORE]
OFFSHORE ENERGY
DEVELOPMENT CORPORATION
COMMON STOCK
-------------------
PROSPECTUS
-------------------
MORGAN KEEGAN & COMPANY, INC.
PRINCIPAL FINANCIAL
SECURITIES, INC.
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