Registration Number 333-87287
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
PRE-EFFECTIVE AMENDMENT NO. 2 TO
Form S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
Mariner Energy LLC
(Exact name of registrant as specified in its charter)
Delaware 1311 52-2130735
(State or other (Primary Standard (I.R.S. Employer
jurisdiction of Classification Identification No.)
incorporation or Code Number)
organization)
580 WestLake Park Blvd., Suite 1300
Houston, Texas 77079
(281) 584-5500
(Address, including zip code, and telephone number, including area code, of
principal executive offices)
Frank A. Pici
Vice President Finance and Chief Financial Officer
Mariner Energy LLC
580 WestLake Park Blvd., Suite 1300
Houston, Texas 77079
(281) 584-5500
(Name, address, including zip code, and telephone number, including area
code, of agent for service)
Copies to:
Mr. Charles H. Still Mr. Robert V. Jewell
Fulbright & Jaworski L.L.P. Andrews & Kurth L.L.P.
1301 McKinney, Suite 5100 600 Travis, Suite 4200
Houston, Texas 77010-3095 Houston, Texas 77002
(713) 651-5151 (713) 220-4200
Approximate date of commencement of proposed sale to the public: As soon as
practicable after this registration statement becomes effective.
If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933 (the "Securities Act"), check the following box. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(c) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
The Registrant hereby amends this Registration Statement on such date or
dates as may be necessary to delay its effective date until the Registrant shall
file a further amendment which specifically states that this Registration
Statement shall thereafter become effective in accordance with Section 8(a) of
the Securities Act of 1933, as amended, or until this Registration Statement
shall become effective on such date as the Commission, acting pursuant to said
Section 8(a), may determine.
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1
The information in this prospectus is not complete and may be changed. We
may not sell these securities until the registration statement filed with
the Securities and Exchange Commission is effective. This prospectus is not
an offer to sell these securities and it is not soliciting an offer to buy
these securities in any state where the offer or sale is not permitted.
SUBJECT TO COMPLETION, DATED NOVEMBER 1, 2000
Shares
Mariner Energy LLC
Common Shares
---------------
We are selling common shares and the selling shareholders are selling
common shares.
Prior to this offering, there has been no public market for our common
shares. The initial public offering price of the common shares is expected to be
between $_____ and $_____ per share. We have made application to list our common
shares on The Nasdaq Stock Market's National Market under the symbol "MEGY."
The underwriters have an option to purchase a maximum of _____ additional
shares to cover over-allotments of shares.
We have elected to be treated as a taxable corporation for United States
federal income tax purposes. Under current United States federal income tax law,
the tax treatment of ownership of common shares will be identical to the tax
treatment of ownership of common stock in a publicly traded corporation.
Investing in the common shares involves risks. See "Risk Factors" on page 8.
Underwriting Proceeds to
Price to Discounts and Proceeds to Selling
Public Commissions Mariner Shareholders
-------- --------------- ------------ ------------
Per Share. $ $ $ $
Total..... $ $ $ $
Delivery of the common shares will be made on or about _____, 2000.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.
Credit Suisse First Boston
Banc of America Securities LLC
Morgan Stanley Dean Witter
PaineWebber Incorporated
Petrie Parkman & Co.
The date of this prospectus is _____, 2000.
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2
(Map of Primary Properties)
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3
---------------
TABLE OF CONTENTS
PROSPECTUS SUMMARY............................................................1
Summary Consolidated Financial Data...........................................7
RISK FACTORS..................................................................9
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS........................18
USE OF PROCEEDS..............................................................19
DIVIDEND POLICY..............................................................19
DILUTION.....................................................................20
CAPITALIZATION...............................................................21
SELECTED CONSOLIDATED FINANCIAL DATA.........................................22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF......................................24
FINANCIAL CONDITION AND RESULTS OF OPERATIONS................................24
BUSINESS AND PROPERTIES......................................................32
MARINER HISTORY AND ORGANIZATION.............................................46
MANAGEMENT...................................................................47
PRINCIPAL AND SELLING SHAREHOLDERS...........................................56
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS...............................58
DESCRIPTION OF OUR COMPANY AGREEMENT AND COMMON SHARES.......................61
SHARES ELIGIBLE FOR FUTURE SALE..............................................68
UNDERWRITING.................................................................69
NOTICE TO CANADIAN RESIDENTS.................................................71
LEGAL MATTERS................................................................72
EXPERTS......................................................................72
INDEPENDENT PETROLEUM ENGINEERS..............................................72
WHERE YOU CAN FIND MORE INFORMATION..........................................72
GLOSSARY OF OIL AND NATURAL GAS TERMS........................................73
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS..................................F-1
REPORT OF INDEPENDENT PETROLEUM ENGINEERS...................................A-1
---------------
You should rely only on the information contained in this document or to
which we have referred you. We have not authorized anyone to provide you with
information that is different. This document may only be used where it is legal
to sell these securities. The information in this document may only be accurate
on the date of this document.
---------------
Dealer Prospectus Delivery Obligation
Until , 2000 (25 days after the date of this prospectus), all dealers that
effect transactions in these securities, whether or not participating in this
offering, may be required to deliver a prospectus. This is in addition to the
dealer's obligation to deliver a prospectus when acting as an underwriter and
with respect to unsold allotments or subscriptions.
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4
PROSPECTUS SUMMARY
This summary highlights selected information from this prospectus but does
not contain all information that may be important to you. The estimates of our
proved reserves as of December 31, 1999, included in this prospectus are derived
from the report of Ryder Scott Company, L.P., our independent petroleum
engineers, a summary of which report is attached to this prospectus as Annex A.
The "Glossary of Oil and Natural Gas Terms" on page 72 of this prospectus
defines some of the industry terms used in this prospectus.
About Mariner
Mariner Energy is an independent oil and natural gas exploration,
development and production company with principal operations in the Gulf of
Mexico and along the U.S. Gulf Coast. Our increasing focus on Gulf water depths
greater than 600 feet, or the deepwater, since the early 1990s has made us one
of the most experienced independent operators in the deepwater Gulf. We have
been an active explorer in the Gulf Coast area since the mid-1980s, when we
operated as Hardy Oil & Gas USA Inc., and have increased our production and
reserve base through the exploitation and development of internally generated
prospects, which we refer to as growth "through the drillbit." Members of our
senior management team, most of whom have worked together for over 16 years, and
an affiliate of Enron North America Corp. led a buyout of Mariner from Hardy Oil
& Gas, plc in April 1996. We believe that our operating experience, exploration
expertise, extensive deepwater lease inventory and seasoned management team give
us a unique competitive advantage with substantial growth potential.
Since beginning deepwater operations in 1994, we have:
o operated seven successful subsea development projects in water depths of
400 feet to 2,700 feet;
o developed three deepwater exploitation projects acquired from major oil
companies, including our Pluto project, and acquired a fourth deepwater
exploitation project, King Kong, from Shell Oil Company in July 2000;
o discovered eight new fields in fifteen deepwater Gulf exploration tests,
including potentially significant discoveries at our Aconcagua and Devils
Tower prospects, on which appraisal operations are in progress;
o acquired 70 deepwater Gulf lease blocks, most of which are free of royalty
payment obligations; and
o built an inventory of 13 deepwater Gulf exploration prospects, many of
which have potential to significantly increase our proved reserves and
future production.
Ryder Scott Company estimated that we had proved reserves of 178.4 Bcfe as
of December 31, 1999, of which 67% were natural gas and 33% were oil and
condensate. Proved reserve estimates as of December 31, 1999 did not include
estimates related to discoveries at our Aconcagua and Devils Tower prospects.
For the year ended December 31, 1999, we produced an average of 68 MMcfe per
day. For the six months ended June 30, 2000, we produced an average of 110 MMcfe
per day, reflecting production from our Pluto project, which began in late
December 1999 and is currently producing approximately 35 MMcfe per day net to
our interest and our Apia project, which began in late April 2000 and is
currently producing approximately 13 MMcfe per day net to our interest.
We expect our production levels and operating cash flow to increase
significantly in 2000 over 1999 based on production from our Pluto project, our
Apia project, and our Black Widow project, which is expected to begin producing
in the fourth quarter of 2000.
Our planned capital expenditures for 2000, net of approximately $29 million
from property conveyances, consist of approximately $103 million for leasehold
acquisition, exploration drilling and development projects, compared to capital
expenditures of approximately $62 million for 1999. During the first nine months
of 2000, we:
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o drilled successful appraisal wells on our Aconcagua and Devils Tower
discoveries;
o drilled three exploratory wells in the deepwater Gulf, one of which was
successful;
o sold a portion of our Devils Tower discovery to one of our partners in the
prospect, reducing our working interest from 50% to 20% to better manage
financial and operational risk; and
o acquired from Shell Oil Company a fifty percent interest in the "King Kong"
deepwater Gulf exploitation project, which we expect to commence production
by early 2002.
During the remainder of 2000 and 2001, we expect to drill six to eight
deepwater Gulf prospects with potential to add significant quantities of proved
reserves and future production. We also expect to drill two appraisal wells on
our Devils Tower discovery, to drill development wells and complete facilities
needed to commence production on our King Kong project by early 2002, and to
complete most of the infrastructure necessary for our Aconcagua project to
commence production in early 2002. We anticipate our 2001 capital expenditures,
net of proceeds from property conveyances, will be approximately $160 million,
with the majority planned for the development of existing discoveries, new
exploration drilling and leasehold and prospect acquisition.
Our Strategy
Our business strategy is to increase reserves, production and cash flow
profitably by emphasizing growth through the drillbit in our deepwater Gulf
niche; the use of subsea technology to develop mid-sized fields that are either
acquired from major oil companies or discovered via low-cost exploration. Our
strategy consists of the following elements:
o Focus on the Deepwater Gulf. Our early entry into the deepwater Gulf in
1992 has allowed us to develop the geophysical and geological skills,
operating expertise and relationships with partners necessary to operate
successfully in the deepwater. With our current prospect and seismic
inventory and many more deepwater Gulf lease blocks expected to become
available via lease sales and farmouts from existing leaseholders, we
believe we are well-positioned to increase our deepwater Gulf activity and
to continue to generate and exploit economically attractive prospects.
o Pursue a Balanced Portfolio Approach to our Drilling Program. We target
four to eight new prospects each year, with a strong deepwater Gulf
emphasis. The program is designed to provide reserve replacement and
production growth through low-risk deepwater exploitation projects and
opportunities for substantial growth through moderate-risk exploration
prospects that can significantly increase our reserve base.
o Internally Generate Most of Our Prospects. By internally generating most of
our prospects, we believe we have better control over the quality of the
prospects in which we participate, thereby increasing our chances for
commercial success. Almost all of our inventory of exploration prospects
were internally generated by our staff of geoscientists, which has
extensive experience in the deepwater Gulf. Through our technical staff's
understanding of the geology and geophysics of the deepwater Gulf and our
inventory of leasehold blocks and seismic data, we intend to continue to
generate the majority of our prospects internally.
o Manage Deepwater Risks. We intend to reduce our deepwater risks by
continuing to:
o target prospects with relatively low gross drilling costs ranging from
$5 million to $20 million;
o use 3-D seismic technology to identify direct hydrocarbon indicators
and to lessen the risk of dry holes; and
o limit the financial exposure of our deepwater prospect portfolio by:
o selling a portion of our working interests in our deepwater
projects to industry partners, typically on a promoted basis
where all or a portion of our exploratory costs are paid by
partners;
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6
o generally maintaining a 25% to 50% interest during the appraisal
phase of a successful exploratory project; and
o reducing our interest in the development phase of a project when
appropriate, considering other opportunities in our investment
portfolio, the need to avoid becoming overly concentrated in a
few projects and the availability of capital.
o Apply Our Deepwater Operational Expertise. Our deepwater operations
managers average over 25 years of experience with major oil companies and
large independents around the world. By operating most of our deepwater
projects, we intend to apply the experience of our staff to continue to:
o maintain efficient drilling performance;
o shorten project cycle times;
o reduce operational risks and life of project finding and development
costs; and
o innovatively use proven subsea production technology and develop low
cost, mobile floating production facilities.
Prospective investors should carefully read the "Risk Factors" section, as
well as other information contained in this prospectus. The oil and natural gas
business involves many operational and financial risks, especially in the
deepwater Gulf. Most of our production and cash flows comes from a small number
of fields, increasing our exposure to production problems. Our focus in the
Gulf, with its relatively short production periods, also subjects us to higher
reserve replacement needs. Our use of seismic data cannot eliminate exploration
risk. We reported significant losses in 1997 and 1998 primarily because low
commodity prices resulted in asset write-downs under the full cost accounting
method. We have significant long-term indebtedness with restrictive covenants
and payment obligations. We also may have to pay above-market rates for a
long-term drilling rig. One or more of these matters could negatively impact our
ability to successfully implement our strategy.
Proved Properties
Our proved properties as of December 31, 1999 are summarized in the table
below:
<TABLE>
<CAPTION>
Net
Mariner Approximate Date Proved
Working Water Depth Production Reserves
Operator Interest (Feet) Commenced/Expected (Bcfe)
<S> <C> <C> <C> <C> <C>
Deepwater Gulf:
Mississippi Canyon 718(Pluto)......... Mariner 37%/51%(1) 2,710 December 1999 26.6
Ewing Bank 966 (Black Widow) ......... Mariner 69% 1,850 4th Quarter 2000 21.4
Garden Banks 73 (Apia) ............... Mariner 100% 700 April 2000 17.6
Garden Banks 367 (Dulcimer) ......... Mariner 41.7% 1,100 April 1999 14.9
Garden Banks 240 (Mustique) ......... Mariner 33.3% 830 January 1996 2.8
Green Canyon 136(Shasta) ............. Texaco 25% 1,040 November 1995 1.7
Gulf Shallow Water and Gulf............
Coast Onshore:
Spirit
Brazos A-105 ......................... Energy 12.5% 192 January 1993 11.1
Galveston 151 (Rembrandt) ............ Mariner 33.3% 50 November 1996 6.8
Sandy Lake Field ..................... Mariner 50%/33%(2) Onshore August 1994 3.9
Matagorda Island 683, 703 ............ Vastar 25% 112 March 1993 3.6
Permian Basin of West Texas:
Spraberry Aldwell Unit ............... Mariner 70.3%(3) Onshore 1949 52.5
Other Fields ........................... -- -- -- -- 15.5
-----
Total Proved Reserves .................. 178.4
=====
</TABLE>
3
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7
(1) We have a 37% working interest before project payout and a 51% working
interest after project payout.
(2) We have a 50% working interest in three production units in the Sandy Lake
Field, a 40% working interest in a fourth unit and a 33% interest in the
fifth unit.
(3) We have working interests in individual wells ranging from approximately
33% to 84%.
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8
The Offering
Common shares offered by:
Mariner......................... shares
Selling shareholders............ shares
Common shares to be
outstanding after the
offering........................ shares
Voting rights...................... One vote per common share
Dividend policy................... We do not anticipate that we will pay
cash dividends in the foreseeable future.
Use of proceeds.................. We expect the net proceeds to us from the
offering to be approximately $ million
or $ million if the underwriters exercise
their over-allotment option. We intend to
use these net proceeds to repay all
outstanding borrowings under our revolving
credit facility and under credit facilities
with Enron. We will use any remaining net
proceeds, as well as additional future
borrowings under our revolving credit
facility, to fund a portion of our
exploration and development program. See
"Use of Proceeds" for a more complete
discussion of how we intend to use the
proceeds from the offering. We will not
receive any of the proceeds of the sale of
common shares by the selling shareholders.
Risk factors....................... For a discussion of factors you should
consider in making an investment, see
"Risk Factors."
Proposed Nasdaq
National Market
symbol.......................... MEGY
Unless we state otherwise, the information in this prospectus does not take
into account the issuance of up to _____ common shares that the underwriters
have the option to purchase solely to cover over-allotments. If the underwriters
exercise this option in full, common shares will be outstanding after the
offering.
The number of common shares to be outstanding immediately after the
offering does not take into account:
o 2,216,904 common shares that may be issued on the exercise of stock
options, at a weighted average price of $9.84, all of which will be
exercisable immediately following the offering; and
o common shares that may be issued upon the exercise of warrants granted to
Enron under a term loan with Enron, which debt will not be outstanding
after the offering.
Unless the context indicates otherwise, the information in this prospectus,
including share and per share data, has been adjusted to give effect to our
internal reorganization in October 1998, under which each share of the common
stock of Mariner Holdings, Inc. was exchanged for 12 of our common shares. The
purpose of this reorganization was to change the form of the parent entity to a
limited liability company. Although we have a corporate management structure, we
were legally organized as a limited liability company, rather than a Delaware
corporation, solely for purposes of creating more certainty regarding the duties
of Enron and our officers and directors to us and our shareholders. See
"Description of our Company Agreement and Common Shares" for a more complete
discussion of the reasons we chose the limited liability company form. Mariner
Holdings, Inc. was formed in 1996 and in April 1996 acquired all of the
outstanding shares of Mariner Energy, Inc., formerly known as Hardy Oil & Gas
USA Inc. Before April 1996, Hardy Oil & Gas USA Inc. was an indirect wholly
owned subsidiary of Hardy Oil & Gas, plc.
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Executive Offices
Our executive offices are located at 580 WestLake Park Blvd., Suite 1300,
Houston, Texas 77079, and our telephone number is (281) 584-5500.
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Summary Consolidated Financial Data
(in millions, except per share data)
The following table shows some of our historical financial data. The
results of operations for the six months ended June 30, 2000 are not necessarily
indicative of the results for the full fiscal year. You should read the
following data in connection with "Capitalization," "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the consolidated
financial statements included elsewhere in this prospectus, where there is
additional disclosure regarding that information.
<TABLE>
<CAPTION>
(in millions except per share data) Year Ended Six Months Ended
December 31, June 30, 2000
--------------------------------- ------------------
1997 1998 1999 1999 2000
--------- -------- -------- ------- -------
<S> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Total revenues ............................. $ 62.8 $ 56.7 $ 52.5 $ 25.8 $ 58.3
Lease operating expenses ................... 9.4 9.9 11.5 5.8 8.5
Depreciation, depletion and amortization ... 31.7 33.8 32.5 15.8 29.1
Impairment of oil and gas properties ....... 28.5 50.8 -- -- --
General and administrative expenses ........ 3.2 4.7 5.4 2.8 3.3
Provision for litigation ................... -- 2.8(1) -- -- --
------ ------- ------ ------ ------
Operating income (loss) .................... (10.0) (45.3) 3.1 1.4 17.4
Interest income ............................ 0.5 0.3 -- -- --
Interest expense ........................... (10.7) (13.4) (19.4) (9.9) (12.0)
------ ------- ------ ------ ------
Income (loss) before income taxes .......... (20.2) (58.4) (16.3) (8.5) 5.4
Provision for income taxes ................. -- -- -- -- --
------ ------- ------ ------ ------
Net income (loss) .......................... $ (20.2) $ (58.4) $ (16.3) $ (8.5) $ 5.4
------ ------- ------ ------ ------
Basic and diluted earnings (loss) per share $ (1.71) $ (4.47) $ (1.17) (0.61) $ 0.39
Average outstanding shares ................. 11.8 13.1 13.9 13.9 13.9
Cash Flow Data:
Net cash provided by (used in) operating
activities ................................. $ 52.9 $ 40.3 $ 21.9 $ (21.6) $ 16.0
Net cash used in investing activities ...... (68.9) (141.9) (61.7) (19.3) (25.0)
Net cash provided by financing activities .. 14.3 93.2 39.2 40.6 15.0
Other Financial Data:
EBITDA(2) .................................. $ 50.2 $ 42.1 35.6 $ 17.3 $ 46.6
Capital expenditures ....................... 68.9 141.9 61.7(3) 19.3 25.0(3)
</TABLE>
The adjusted balance sheet data reflect the sale of common shares in this
offering at a purchase price of $ per share and the payment of all of our debt
to Enron and of all of our debt under our revolving credit facility.
As of June 30, 2000
Actual As Adjusted
Balance Sheet Data:
Cash and cash equivalents....... $ 6.2 $
Total assets.................... 324.1
Total debt...................... 224.1
Shareholders' equity............ 28.2
----------
(1) Represents a non-cash charge recorded in the first quarter of 1998 to
provide for a litigation-related cost contingency. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
(2) EBITDA means earnings before interest, income taxes, depreciation,
depletion and amortization, provision for litigation and impairment of oil
and gas properties. We believe that EBITDA is a widely accepted financial
indicator that provides additional information about our ability to meet
our future requirements for debt service, capital expenditures and working
capital, but EBITDA should not be considered in isolation or as a
substitute for net income, operating income, net cash provided by operating
activities or any other measure of financial performance presented in
accordance with generally accepted accounting principles or as a measure of
a company's profitability or liquidity. Our definition of EBITDA may not be
comparable to similarly titled measures of other companies.
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(3) Our capital expenditures for 1999 and 2000 were $81.5 million and $53.9
million respectively, excluding $19.8 million and $29.0 million
respectively related to proceeds from property conveyances.
Summary Operating and Reserve Data
The following table shows some of our operating and reserve data. Reserve
data are based on reserve reports prepared by Ryder Scott Company, L.P. A
summary of Ryder Scott's report on our proved reserves as of December 31, 1999
is attached to this prospectus as Annex A. You should refer to "Risk Factors,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," "Business and Properties -- Reserves," "Business and Properties --
Production" and the Ryder Scott report included in this prospectus in evaluating
the material presented below.
<TABLE>
<CAPTION>
Year Ended Six Months Ended
December 31, June 30,
--------------------- --------------
1997 1998 1999 1999 2000
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Production:
Oil (MMBbls) .............................................. 1.0 0.8 0.6 0.3 0.8
Natural gas (Bcf) ......................................... 18.0 19.5 21.1 10.6 15.0
Natural gas equivalent (Bcfe) ............................. 23.9 24.2 24.9 12.7 20.0
Average daily production (MMcfe) .......................... 65.0 66.0 68.0 69.6 109.6
Average Realized Sales Prices (including effects of hedging):
Oil (per Bbl) ............................................. $18.48 $12.80 $13.65 $13.28 $20.15
Natural gas (per Mcf) ..................................... 2.48 2.39 2.08 2.01 2.78
Natural gas equivalent (per Mcfe) ......................... 2.63 2.34 2.11 2.04 2.92
Expenses (per Mcfe):
Lease operating ........................................... 0.39 0.41 0.46 0.45 0.42
General and administrative, net(1) ........................ 0.13 0.20 0.22 0.22 0.16
Depreciation, depletion and amortization, before
impairment provision ...................................... 1.33 1.40 1.31 1.24 1.46
</TABLE>
<TABLE>
<CAPTION>
--------------------------------
As of
December 31,
--------------------------------
1997 1998 1999
---- ---- ----
(dollars in millions except
for per unit amounts)
<S> <C> <C> <C> <C>
Proved Reserves:
Total proved reserves (Bcfe) ......................... 161.1 185.0 178.4(2)
Annual reserve replacement ratio(3) .................. 256% 199% 126%
Present value of estimated future net revenues(4) .... $ 183.8 147.6 $ 211.2
Standardized measure of future discounted net cash
flows(5) ............................................. 176.5 147.6 211.2
Average prices at indicated date:
Natural gas (per Mcf) ............................. $ 2.79 $ 2.22 $ 2.23
Oil (per Bbl) ..................................... 16.43 10.36 23.85
</TABLE>
(1) General and administrative expenses are shown net of amounts capitalized
under the full cost method of accounting and overhead reimbursements we
receive from owners of working interests in the properties we operate.
(2) In June 1999, we sold a portion of our working interest in the Pluto
project, resulting in a reduction to our proved reserves of 14.4 MMcfe.
Also, proved reserve estimates as of December 31, 1999 did not include
estimates related to discoveries at our Aconcagua and Devils Tower
prospects.
(3) We calculate the annual reserve replacement ratio for a year by dividing
aggregate net reserve additions from all sources for the year by actual
production for the year ended on the indicated date.
(4) Discounted at an annual rate of 10%. See "Glossary of Oil and Natural Gas
Terms" included elsewhere in this prospectus for the definition of "present
value of estimated future net revenues."
(5) Represents year-end after-tax present value of estimated future net
revenues.
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RISK FACTORS
Investing in our common shares will provide you with an equity ownership
interest in Mariner. The trading price of your shares will be affected by the
performance of our business relative to, among other things, competition, market
conditions and general economic and industry conditions. The value of your
investment may decrease, resulting in a loss of part or all of your investment.
You should consider carefully the following factors and the other information
contained in this prospectus before deciding to invest in our common shares. The
following important factors could affect our actual future results.
Exploring and developing oil and natural gas wells involve business and
operating risks and other uninsured risks, any one of which could adversely
affect our business.
Our oil and natural gas drilling activities are subject to numerous risks
beyond our control, including the risk that drilling will not result in
commercially viable oil or natural gas production. Our decisions to purchase,
explore, develop and exploit prospects or properties depends in part on data
obtained through geophysical and geological analyses, production data and
engineering studies, the results of which are often uncertain. See "-- Reserve
estimates depend on many assumptions that may turn out to be inaccurate." We
cannot fully predict our cost of drilling, completing and operating wells,
especially offshore wells. Cost overruns can make a particular project
uneconomical. Further, many factors may curtail, delay or cancel drilling,
including the following:
o title problems;
o weather conditions;
o compliance with governmental permitting requirements;
o shortages of or delays in obtaining equipment;
o reductions in product prices; and
o limitations in the market for products.
Losses and liabilities from uninsured and underinsured events could have a
material adverse effect on our financial condition and operations. Our business
is subject to all of the operating risks associated with drilling for and
producing oil and natural gas, including:
o uncontrollable flows of oil, natural gas, brine or well fluids into the
environment, including groundwater and shoreline contamination;
o blowouts and cratering;
o mechanical difficulties;
o fires and explosions;
o personal injuries and death;
o pollution;
o natural disasters; and
o environmental hazards such as natural gas leaks, oil spills, pipeline
ruptures and discharges of toxic gases.
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Any of these risks could result in substantial losses to us and others.
Moreover, offshore operations are subject to a variety of operating risks
associated with the marine environment, such as hurricanes or other adverse
weather conditions, and to interruption or termination by government authorities
for environmental or other reasons. Although we maintain insurance at levels we
believe are consistent with industry practices, we are not fully insured against
all risks, including drilling and completion risks that are generally not
recoverable from third parties or insurance.
Our deepwater operations involve special risks that could negatively affect our
operations.
Drilling operations in the deepwater are by their nature more difficult and
costly than drilling operations in shallower water. They require more time and
more advanced drilling technologies, involving a higher risk of technological
failure and usually higher drilling costs. Our deepwater wells use subsea
completion techniques with subsea wellheads tied back to host production
facilities with flow lines. The installation of these subsea wellheads and flow
lines requires substantial time and the use of advanced remote installation
mechanics. These operations may encounter mechanical difficulties and equipment
failures that could result in significant cost overruns. Furthermore, the
deepwater operations lack the service and transportation infrastructure present
in shallower waters. Therefore, they require a longer lag time between discovery
and marketing.
Oil and natural gas price decreases may adversely affect our financial condition
and our ability to meet our capital expenditure obligations and financial
commitments.
The price we receive for production heavily influences our revenue,
profitability, access to capital and future rate of growth. Oil, natural gas and
natural gas liquids are commodities and, therefore, their prices are subject to
wide fluctuations in response to relatively minor changes in supply and demand.
Historically, the markets for oil, natural gas and natural gas liquids have been
volatile. These markets may continue to be volatile in the future. The prices we
receive for our production, and the levels of our production, fluctuate and
depend on numerous factors beyond our control. These factors include:
o market uncertainty;
o changes in global supply of and demand for oil, natural gas and natural gas
liquids;
o weather conditions;
o the condition of the United States economy;
o the price and quantity of foreign imports;
o the price and availability of alternative fuels;
o political conditions, including embargoes, in or affecting other
oil-producing and natural gas-producing countries;
o the actions of the Organization of Petroleum Exporting Countries; and
o domestic and foreign government regulation, legislation and policies.
It is impossible to predict oil and natural gas price movements. Lower oil
and natural gas prices may not only decrease our revenues on a per unit basis
but also may reduce the amount of oil and natural gas that we can produce
economically. Declines in oil and natural gas prices may materially and
adversely affect our future financial condition, results of operations,
liquidity and ability to finance planned capital expenditures and repay debt.
Further, oil prices and natural gas prices do not necessarily move together.
Because approximately 67% of our estimated proved reserves as of December 31,
1999 were natural gas reserves, our financial results are more sensitive to
movements in natural gas prices.
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Oil or natural gas price decreases and other events may require us to record
carrying value writedowns, which would result in a charge to earnings.
We periodically review the carrying value of our oil and natural gas
properties under the full cost accounting rules of the Securities and Exchange
Commission. Under these rules, capitalized costs of oil and natural gas
properties may not exceed the present value of estimated future net revenues
from proved reserves, discounted at 10%, plus the lower of cost or fair market
value of unproved properties. Application of this "ceiling" test generally
requires pricing future revenues at the prices in effect as of the end of each
fiscal quarter. If the ceiling is exceeded we must write down the carrying value
of oil and natural gas properties, resulting in a non-cash charge against
earnings for accounting purposes, even if prices declined for only a short
period of time. These writedowns cannot be reversed even if prices increase
later. The risk of writedowns increases when oil and natural gas prices decline
or when an extended delay arises in recognizing proved reserves after we have
made significant capital expenditures. Any writedown results in a charge to
earnings but does not affect our cash flow from operating activities. In each of
the fiscal years ended December 31, 1996, 1997 and 1998, we recorded writedowns.
We refer to writedowns as impairments of oil and gas properties. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and Note 1 of our consolidated financial statements for additional
discussion of our writedowns.
Our hedging transactions could limit potential gains if oil and natural gas
prices rise substantially.
To reduce our exposure to changes in the prices of oil and natural gas, we
regularly enter into hedges for our production. These transactions may limit our
potential gains if oil and natural gas prices rise substantially over the price
the hedges establish. These hedges also may expose us to other risks of
financial loss in other instances, including possible production shortfalls.
We may not be able to raise sufficient additional capital to implement fully our
business plan.
We depend on our ability to obtain financing beyond our cash flow from
operations. Historically, we have financed our business plan and operations
primarily with bank borrowings, proceeds from the sale of oil and natural gas
properties, the issuance of notes, privately raised equity and borrowings from
Enron. In the future, we will require substantial additional financing to fund
our business plan and operations. Our planned capital expenditures for the
remainder of 2000 and 2001 exceed our expected cash flow from operations for the
same period. We cannot assure you that additional financing will be available on
acceptable terms or at all. If we cannot obtain additional capital resources, we
may curtail our drilling, development and other activities or be forced to sell
some of our assets on an untimely or unfavorable basis.
We may not be able to generate sufficient cash flow to service our existing debt
or ensure that future credit will be available to us.
At June 30, 2000, after giving pro forma effect to the offering, we would
have had total debt of approximately $_____ million and shareholders' equity of
approximately $_____ million. We intend to incur additional debt to execute our
business strategy.
Our debt could have important consequences, including the following:
o our ability to refinance existing debt or obtain additional debt or equity
financing may be impaired;
o a substantial portion of our cash flow from operations will be required to
pay principal and interest on our debt, which reduces the funds available
to us for our operations and other purposes;
o we may be substantially more leveraged than our competitors, which may
place us at a competitive disadvantage; and
o we may be unable to adjust rapidly to changing market conditions.
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Our debt could make us more vulnerable than a less leveraged competitor if
a downturn occurs in general economic conditions or our business. For additional
discussion of our leverage, see "-- We may not be able to raise sufficient
additional capital to implement fully our business plan," "Capitalization," and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
Our ability to repay or refinance our indebtedness depends on our future
performance and successful implementation of our strategy, both of which are
subject not only to our actions but also to general economic, financial,
competitive, legislative and regulatory conditions, the prevailing market prices
for oil, natural gas and natural gas liquids and other factors beyond our
control. For additional discussion of our loan payment obligations, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity, Capital Expenditures and Capital Resources."
Restrictive debt covenants limit our operational and capital flexibility.
Our revolving credit facility and the indenture relating to our subsidiary
Mariner Energy, Inc.'s 10 1/2% senior subordinated notes due 2006 contain
significant covenants that, among other things, restrict our ability to:
o dispose of assets;
o incur additional indebtedness;
o repay other indebtedness;
o pay dividends;
o enter into specified investments or acquisitions;
o repurchase or redeem capital stock;
o merge or consolidate; or
o engage in specified transactions with subsidiaries and affiliates and that
otherwise restrict corporate activities.
These restrictions could adversely affect our ability to finance our future
operations or capital needs or engage in other business activities that may be
in our interest.
Also, our revolving credit facility requires us to comply with stated
financial ratios. Our ability to comply with these ratios may be affected by
events beyond our control. A breach of any of these covenants or our inability
to comply with the required financial ratios could result in a default under our
revolving credit facility. If a default were to occur, the lenders could require
us to repay all borrowings outstanding under our revolving credit facility,
require us to apply all of our available cash to repay these borrowings or
prevent us from making debt service payments on the senior subordinated notes.
We cannot assure you that, if the indebtedness under the revolving credit
facility or the senior subordinated notes were accelerated, our assets would be
sufficient to repay this indebtedness in full. See Note 4 of our consolidated
financial statements.
Reserve estimates depend on many assumptions that may turn out to be inaccurate.
Any material inaccuracies in these reserve estimates or underlying assumptions
will materially affect the quantities and present value of our reserves.
Estimating oil and natural gas reserves is complex. It requires
interpretations of available technical data and many assumptions, including
pricing and other economic assumptions. Any significant inaccuracies in these
interpretations or assumptions could materially affect the estimated quantities
and present value of reserves shown in this prospectus. See "Business and
Properties -- Reserves" for information about our oil and gas reserves.
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In preparing these estimates we project production rates and timing of
development expenditures. We also analyze available geological, geophysical,
production and engineering data. The extent, quality and reliability of this
data can vary. Estimations also requires economic assumptions about matters such
as natural gas and oil prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. Therefore, estimates of oil and
natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves most likely will vary from our estimates. Any
significant variance could materially affect the estimated quantities and
present value of reserves shown in this prospectus. In addition, we may adjust
estimates of proved reserves to reflect production history, results of
exploration and development, prevailing oil and natural gas prices and other
factors, many of which are beyond our control. At December 31, 1999, 47% of our
proved reserves were either proved undeveloped or proved non-producing.
You should not assume that the present value of future net revenues from
our proved reserves referred to in this prospectus is the current market value
of our estimated oil and natural gas reserves. In accordance with SEC
requirements, we generally base the estimated discounted future net cash flows
from our proved reserves on prices and costs on the date of the estimate. Actual
future prices and costs may differ materially from those used in the present
value estimate.
A significant part of the value of our production and reserves is concentrated
in a small number of properties. Because of this concentration, any production
problems or inaccuracies in reserve estimates related to those properties are
more likely to impact our business adversely.
During June 2000, approximately 84% of our daily production came from seven
of our fields. If mechanical problems, storms or other events curtailed a
substantial portion of this production, our cash flow would be affected
adversely. At December 31, 1999, approximately 90% of our proved reserves were
located on 11 properties. If the actual reserves associated with any one of
these properties are less than our estimated reserves, our results of operations
and financial condition could be adversely affected.
Unless we replace our oil and natural gas reserves, our reserves and production
will decline.
Without reserve additions in excess of production, our reserves and
production will decline. Producing oil and natural gas reservoirs generally are
characterized by declining production rates that vary depending upon reservoir
characteristics and other factors. Our future oil and natural gas reserves and
production, and, therefore, our cash flow and income, depend on our success in
efficiently developing and exploiting our current reserves and economically
finding additional recoverable reserves. We cannot assure you that we will be
able to find and develop or acquire additional reserves to replace our current
and future production.
Relatively short production periods for Gulf properties subject us to higher
reserve replacement needs and may impair our ability to reduce production during
periods of low oil and natural gas prices.
Production of reserves from reservoirs in the Gulf generally declines more
rapidly than from reservoirs in many other producing regions of the world. This
results in recovery of a relatively higher percentage of reserves from
properties in the Gulf during the initial few years of production, and as a
result, our reserve replacement needs from new prospects are relatively greater.
Also, our revenues and return on capital will depend significantly on
prices prevailing during these relatively short production periods. Our
potential need to generate revenues to fund ongoing capital commitments or repay
debt may limit our ability to slow or shut in production from producing wells
during periods of low prices for oil and natural gas.
Market conditions or transportation impediments may hinder our access to oil and
natural gas markets or delay our production.
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Market conditions, the unavailability of satisfactory oil and natural gas
transportation or the remote location of our drilling operations may hinder our
access to oil and natural gas markets or delay our production. The availability
of a ready market for our oil and natural gas production depends on a number of
factors, including the demand for and supply of oil and natural gas and the
proximity of reserves to pipelines or trucking and terminal facilities. In
offshore operations, the availability of a ready market depends on the proximity
of and our ability to tie into existing production platforms owned or operated
by others and the ability to negotiate commercially satisfactory arrangements
with the owners or operators. We may be required to shut in natural gas wells
for lack of a market or because of inadequacy or unavailability of natural gas
pipeline or gathering system capacity. When that occurs, we are unable to
realize revenue from those wells until the production can be tied to a gathering
system. As a result of our strategy of using subsea technology to tie offshore
wells back to existing platforms, we sometimes drill away from gathering
systems. Currently, we have drilling operations miles from existing
infrastructure. This can result in considerable delays from the initial
discovery of a reservoir to the actual production of the oil and natural gas and
realization of revenues.
We may have to pay above-market rates for a long-term drilling rig commitment.
During the first quarter of 2000, we agreed to use a deepwater drilling rig
for a minimum of 660 days over a five-year period, paying market-based day rates
for comparable drilling rigs in comparable water depths subject to a floor day
rate ranging from $65,000 to $125,000. This floor day rate may require us to pay
day rates in excess of market-based rates over the five-year period that could
cause significant increased costs on our projects.
The unavailability or high cost of additional drilling rigs, equipment, supplies
and personnel could adversely affect our ability to execute on a timely basis
our exploration and development plans within budget.
Shortages or the high cost of drilling rigs, equipment, supplies or
personnel could delay or adversely affect our development and exploration
operations, which could have a material adverse effect on our financial
condition and results of operations. If drilling activity in the United States
increases, associated costs may also increase, including more related to
drilling rigs, equipment, supplies and personnel and the services and products
of other vendors to the industry. Increased drilling activity in the Gulf could
decrease the availability and increase the costs of offshore rigs. We cannot
assure you that costs will not increase or that necessary equipment and services
will be available to us at economical prices.
Competition in the oil and natural gas industry is intense, and we may be unable
to compete successfully.
We may not be able to compete successfully in our industry. We operate in a
highly competitive environment for acquiring prospects, marketing oil and
natural gas and securing trained personnel. Many of our competitors possess and
employ financial, technical and personnel resources substantially greater than
ours, which can be particularly important in deepwater Gulf activities. Those
companies 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 our financial or personnel
resources permit. Our ability to acquire additional prospects and to discover
reserves in the future will depend on our ability to evaluate and select
suitable properties and to consummate transactions in a highly competitive
environment. Also, there is substantial competition for capital available for
investment in the oil and natural gas industry. We cannot assure you that we
will be able to compete successfully in the future in acquiring prospective
reserves, developing reserves, marketing hydrocarbons, attracting and retaining
quality personnel and raising additional capital.
Government laws and regulations can increase our costs.
From time to time, in varying degrees, political developments and federal
and state laws and regulations affect our operations. In particular, price
controls, taxes and other laws relating to the oil and natural gas industry,
changes in these laws and changes in administrative regulations have affected
oil and natural gas production, operations and economics. We cannot predict how
agencies or courts will interpret existing laws and regulations, whether
additional laws and regulations will be adopted or the effect these
interpretations and adoptions may have on our business or financial condition.
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Our operations are subject to complex and constantly changing federal,
state and local environmental laws and regulations. The discharge of oil and
natural gas and production wastes or other pollutants into the air, soil or
water may make us liable to the government and third parties for remediation
costs and other damages. Also, we may have to make large expenditures to comply
with environmental and other governmental regulations. We cannot assure you that
existing environmental laws or regulations, as currently interpreted or
reinterpreted in the future, or future laws or regulations, will not materially
adversely affect our operations and financial condition or that material
indemnity claims will not arise against us related to properties we acquire or
sell. See "Business and Properties -- Regulation" for an additional discussion
of government regulations that affect us.
We may be adversely affected if we are unable to retain our key executives and
consultants.
We believe that our operations are dependent to a significant extent on the
efforts of several members of our senior management and one of our consultants,
most of whom have been with us for more than 16 years. The loss of the services
of any of these key individuals could have a material adverse effect on us. We
do not maintain any insurance against the loss of any of these individuals.
Our relationship with Enron may result in conflicts of interest that may not be
resolved in our favor.
Enron will be able to exercise significant control over us, and Enron's
interests may conflict with ours and Enron may not resolve these conflicts in
our favor. Enron Corp. is the parent of Enron North America Corp., which we
refer to as Enron in this prospectus. An affiliate of Enron Corp. and Enron is
the general partner of Joint Energy Development Investments Limited Partnership,
which currently owns approximately 96% of our outstanding common shares and will
own approximately % of our outstanding common shares following the offering.
Also, eight of our directors are officers of Enron or of affiliates of Enron. As
the beneficial owners of a significant portion of our outstanding common shares,
Enron Corp. and Enron will have the ability to influence our management and may
be deemed to control us. Enron and certain of its subsidiaries and other
affiliates collectively participate in nearly all phases of the oil and natural
gas industry and may, therefore, compete with us. Also, Enron affiliates may
provide or arrange for financing for our competitors. Because of these various
possible conflicting interests, our company agreement, which is analogous to the
certificate of incorporation and bylaws of a corporation, includes provisions
designed to clarify that Enron and its affiliates have no duty to make business
opportunities available to us and no duty to refrain from conducting activities
that may be competitive with us. Enron and its affiliates are not contractually
obligated to resolve in our favor conflicts of interest that arise. See
"Description of Our Company Agreement and Common Shares."
In March 2000, we entered into a term loan with Enron, under which, as of
May 1, 2000, we had borrowed an aggregate of $112 million. We are required to
repay the amounts outstanding under the loan with Enron with a portion of the
proceeds of the offering. For a discussion of our loan with Enron and our
intention to repay it, see "Use of Proceeds" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity, Capital
Expenditures and Capital Resources."
We expect that from time to time we will engage in various commercial and
hedging transactions and have various commercial relationships with Enron and
certain affiliates of Enron. The terms of future arrangements between us and
Enron or affiliates of Enron will not necessarily be on terms as favorable to us
as would exist in an agreement with a third party. See "Certain Relationships
and Related Transactions" for an additional discussion of our relationship with
Enron.
If a change in control occurs, we would have to repay indebtedness. We may not
have the financial resources to meet this obligation.
If a change in control occurs, we may not have the financial resources to
repay all of our indebtedness that would become payable. On the occurrence of a
change in control of Mariner Energy, Inc., a holder of senior subordinated notes
may require Mariner Energy, Inc. to repurchase all or a portion of the holder's
notes at 101% of the principal amount of the notes, together with accrued and
unpaid interest to the date of repurchase. An aggregate of $100 million
principal amount of the senior subordinated notes is outstanding. The senior
subordinated notes indenture requires that, prior to this repurchase, we must
either repay all outstanding senior indebtedness or obtain any required consents
to the repurchase. A change in control of Mariner Energy, Inc. will be deemed to
have occurred under the terms of the indenture if:
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o Joint Energy and its affiliates, including Enron, cease to beneficially own
35% of the voting power of Mariner Energy, Inc. and another person or
entity acquires a greater ownership in Mariner Energy, Inc. than Joint
Energy and its affiliates; and
o during any two-year period, the directors of Mariner Energy, Inc. at the
beginning of that period, and their nominees, cease to control the board of
directors of Mariner Energy, Inc.; or
o Mariner Energy, Inc. merges or consolidates with another entity and the
stockholders of Mariner Energy, Inc. do not hold a majority of the voting
power of the surviving entity.
Further, under our revolving credit facility, an event of default is deemed
to occur if Joint Energy and its affiliates, or a combination of these entities,
cease to own, directly or indirectly, outstanding capital shares of Mariner, on
either a basic or diluted basis, that in the aggregate permits these entities to
elect a majority of our board of directors. In those circumstances, the lenders
could require the repayment of all outstanding borrowings under the revolving
credit facility.
You will experience immediate and substantial dilution.
If you purchase common shares, the tangible net book value of your common
shares will immediately be diluted by approximately $_____ per share. See
"Dilution" for a more complete discussion of the dilution you will experience.
Our debt instruments restrict our ability to pay dividends, and we do not intend
to pay dividends in the foreseeable future.
Our debt instruments restrict us from declaring or paying dividends on the
common shares. We do not intend to pay cash dividends on the common shares in
the foreseeable future. See "Dividend Policy" for additional information
relating to our dividend policy.
Shares eligible for future sale by our current shareholders could adversely
affect our common share price.
Sales of a substantial number of common shares after the offering could
adversely affect the market price of common shares and could impair our ability
to raise capital through the sale of equity securities. After giving effect to
the offering, we will have approximately _____ common shares, assuming no
exercise of the underwriters' over-allotment option. Of these, approximately
_____ may be freely tradeable in the public market following the offering.
Also, Joint Energy holds 13,334,184 common shares and, as part of the term
loan entered into in March 2000, Enron received warrants permitting it to
purchase 900,000 common shares for $0.01 per share, 600,000 of which are
immediately exercisable and 300,000 will be exercisable on March 21, 2001, if
the term loan is unpaid on that date. We have granted Joint Energy and Enron
demand and piggyback registration rights related to these shares. The exercise
of these rights would permit Joint Energy and Enron to sell all or a portion of
these shares. The sale by Joint Energy or Enron of a significant number of
common shares could adversely impact the market price of the common shares. See
"Shares Eligible for Future Sale" for more complete information about the
potential for future sales of our common shares.
Anti-takeover provisions in our governing documents and debt instruments could
prevent or delay a change in control.
Our company agreement and our debt instruments contain provisions that may
delay, deter or prevent the acquisition of us or a substantial portion of the
common shares. For example, our company agreement authorizes our board of
directors to issue preferred shares in one or more series and to fix the rights
and preferences of the shares of a series without shareholder approval. Any
series of preferred shares may be senior to the common shares as to dividends,
liquidation rights and, possibly, voting rights of the common shares. The
ability to issue preferred shares could discourage unsolicited acquisition
proposals. Also, on a change of control of Mariner Energy LLC or Mariner Energy,
Inc., we may be required to repay or repurchase outstanding debt at a premium to
the principal amount of the debt. Furthermore, our company agreement includes a
provision of Delaware corporate law not normally applicable to Delaware limited
liability companies that prohibits, in some circumstances, significant
transactions without the approval of the board of directors. These provisions
also may discourage attempted acquisitions, unsolicited or otherwise. By
deterring takeover attempts, these provisions could inhibit an increase in the
market price of the common shares that otherwise might result from a takeover
attempt. See "Description of Our Company Agreement and Common Shares" for a more
complete discussion of the anti-takeover provisions in our company agreement.
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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Our disclosure and analysis in this prospectus contain some forward-looking
statements. Forward-looking statements give our current expectations or
forecasts of future events. You can identify these statements by the fact that
they do not relate strictly to historical or current facts. These statements may
include words such as "anticipate," "estimate," "project," "intend," "plan,"
"believe" and other words and terms of similar meaning in connection with any
discussion of future operating or financial performance. In particular, these
include, among other things, statements relating to:
o amount, nature and timing of capital expenditures;
o drilling of wells;
o timing and amount of future production of oil and natural gas;
o operating costs and other expenses;
o cash flow and anticipated liquidity;
o prospect development and property acquisitions; and
o marketing of oil and natural gas.
Any or all of our forward-looking statements in this prospectus may turn
out to be wrong. They can be affected by inaccurate assumptions we might make or
by known or unknown risks and uncertainties. Many factors mentioned in our
discussion in this prospectus, including the risks outlined under "Risk
Factors," will be important in determining future results. Actual future results
may vary materially. Factors that could cause our results to differ materially
from the results discussed in the forward-looking statements include the risks
described under "Risk Factors," including:
o the risks associated with exploration;
o our ability to find, acquire, market, develop and produce new properties;
o oil and natural gas price volatility;
o uncertainties in the estimation of proved reserves and in the projection of
future rates of production and timing of exploitation expenditures;
o operating hazards attendant to the oil and natural gas business;
o drilling and completion risks that are generally not recoverable from third
parties or insurance;
o potential mechanical failure or underperformance of significant wells;
o climatic conditions;
o availability and cost of material and equipment;
o actions or inactions of third-party operators of our properties;
o our ability to find and retain senior management and skilled personnel;
o availability of capital;
o the strength and financial resources of our competitors;
o regulatory developments;
o environmental risks; and
o general economic conditions.
When you consider these forward-looking statements, you should keep in mind
these risk factors and the other cautionary statements in this prospectus. Our
forward-looking statements speak only as of the date made.
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USE OF PROCEEDS
Our net proceeds from the offering are estimated to be approximately $_____
million, or $_____ million if the underwriters exercise their over-allotment
option in full. We will use the net proceeds as follows:
o $_____ million to repay the amount then outstanding under a term loan with
Enron;
o $_____ million to repay amounts then outstanding under our revolving credit
facility; and
o any remaining net proceeds, as well as additional future borrowings under
our revolving credit facility, to continue funding our exploration and
development program.
We used the proceeds we received during the last year from our borrowings
under our revolving credit facility and our credit facilities with Enron to
finance our exploration and development activities.
As of June 30, 2000, the balance on our revolving credit facility was $20.0
million. The indebtedness under our revolving credit facility, which has a
variable interest rate, bore interest at approximately 8% per annum as of June
30, 2000 and has a final maturity date of October 1, 2002. The balance on the
term loan with Enron as of June 30, 2000 was $112 million and bore interest at
15% per annum. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Liquidity, Capital Expenditures and Capital
Resources" for a more complete discussion of these loans.
We will not receive any proceeds from the sale of common shares by the selling
shareholders.
DIVIDEND POLICY
We have not paid cash dividends since our formation in 1996 and do not
anticipate paying cash dividends in the foreseeable future. We presently intend
to retain any future earnings to finance our exploration and development
program. Also, covenants in our debt instruments prohibit or significantly
restrict our ability to pay dividends. The declaration and payment in the future
of any cash dividends will be at the election of our board of directors and will
depend on our earnings, capital requirements and financial position, future loan
covenants, general economic conditions and other pertinent factors.
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DILUTION
Our net tangible book value as of June 30, 2000, was $_____ million, or
$____ per common share. Net tangible book value per share represents the amount
of our total tangible assets less the amount of our total liabilities divided by
the total number of common shares outstanding. After giving effect to our sale
of _____ common shares in the offering, and after deducting the underwriting
discounts and our estimated offering expenses, the net tangible book value on
June 30, 2000, would have been $_____ million, or $_____ per common share. This
represents an immediate increase in net tangible book value of $_____ per share
to existing shareholders and an immediate dilution of $_____ per share to
investors purchasing common shares in the offering.
The following table illustrates this dilution per common share to investors
purchasing shares in the offering:
Assumed initial public offering price per share..................... $
Net tangible book value per share as of June 30, 2000............ $
Increase in net tangible book value per share
attributable to the sale of shares offered
in this prospectus............................................... $
Pro forma net tangible book value per share after the offering...... $
Dilution in net tangible book value per share to new investors...... $
The following table shows the number of common shares purchased from us,
the total consideration paid, and the average price per share paid by existing
shareholders and by purchasers of common shares offered in the offering, before
deducting underwriting discounts and commissions and estimated offering
expenses:
<TABLE>
<CAPTION>
Shares Purchased Total Consideration Average
Price per
Number Percentage Amount Percentage Share
------------- ------------- ------------- -------------- ---------
(in thousands) (in thousands)
<S> <C> <C> <C>
Existing shareholders.. 13,928 % $ 128,926 % $ 9.26
New investors..........
Total........
</TABLE>
The table above assumes that no outstanding stock options have been
exercised. We had outstanding options entitling the holders to purchase
2,216,904 of our common shares at a weighted exercise price of $9.84 per share
as of July 5, 2000. Also, as part of the term loan entered into in March 2000,
Enron received warrants permitting it to purchase 900,000 common shares for
$0.01 per share, 600,000 of which are immediately exercisable and 300,000 will
be exercisable on March 21, 2001, if the term loan is unpaid on that date.
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CAPITALIZATION
(in thousands)
The following table shows our consolidated capitalization as of June 30,
2000, and as adjusted to give pro forma effect to the offering and the payment
of all of our debt under our term loan with Enron and all of our debt under our
revolving credit facility, assuming an aggregate of shares sold in the offering
at $_____ per share and net proceeds of $_____ million. You should refer to
"Selected Consolidated Financial Data," "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the financial statements
included elsewhere in this prospectus in evaluating the material presented
below. The table excludes the _____ common shares to be sold by the selling
shareholders in the offering, _____ common shares if the over allotment option
is exercised, _____ common shares reserved for issuance under our stock option
plan and _____ warrants outstanding.
June 30, 2000
-------------------------
Actual As Adjusted
----------- -----------
Long-term Debt:
Revolving credit facility due October 1, 2002 ...... $ 20,000
101/2% senior subordinated notes due 2006 .......... 99,698
Enron term loan due March 21, 2003 ................. 104,419
----------
Total long-term debt ..................... 224,117
Shareholders' Equity:
Preferred shares, par value $.01 per share,
1,000,000 shares authorized, none issued ........... -- --
Common shares, par value $.01 per share,
50,000,000 shares authorized, 13,928,304
shares issued and outstanding historically,
shares issued and outstanding pro forma ............ 139
Additional paid-in capital ......................... 136,299
Accumulated deficit ................................ (108,249)
---------- ---------
Total shareholders' equity ............... 28,189
---------- ---------
Total Capitalization ..................... $ 252,306 $
========== =========
21
<PAGE>
24
SELECTED CONSOLIDATED FINANCIAL DATA
(in millions, except per share data)
The following table shows some of our historical financial data. The
statement of operations data for the three-year period ended December 31, 1999
and the balance sheet data as of December 31, 1998 and 1999 has been derived
from our audited consolidated financial statements and are included in this
prospectus. The statement of operations data for the year ended December 31,
1995, the three months ended March 31, 1996 and the nine months ended December
31, 1996 and the balance sheet data as of December 31, 1995 and 1996 has been
derived from our audited consolidated financial statements which are not part of
this prospectus. The statement of operations data for the six months ended June
30,1999 and 2000 and the balance sheet data as of June 30, 2000 has been derived
from our unaudited consolidated financial statements and are included in this
prospectus. The results of operations of prior periods are not necessarily
indicative of results that may be expected for any other period. The results of
operations for the six months ended June 30, 2000 are not necessarily indicative
of the results for the full fiscal year. You should read the following data in
connection with "Capitalization," "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the consolidated financial
statements included elsewhere in this prospectus. Effective April 1, 1996 for
accounting purposes, Mariner Holdings, Inc. acquired all the capital stock of
Mariner Energy, Inc. from Hardy Holdings Inc., a subsidiary of Hardy Oil & Gas,
plc, as part of a management-led buyout. In connection with this acquisition,
substantial amounts of our intercompany indebtedness and receivables and
third-party indebtedness were eliminated. This acquisition was accounted for
using the purchase method of accounting, and Mariner Holdings, Inc.'s
acquisition costs were allocated to our assets and liabilities based on
estimated fair values. As a result, our financial position and operating results
subsequent to this acquisition reflect a new basis of accounting and are not
comparable to prior periods. "Acquired Company" refers to Mariner Energy, Inc.
(formerly Hardy Oil & Gas USA Inc.) before the effective date of this
acquisition. We have not presented basic earnings per share and average shares
outstanding for the years ended December 31, 1995 or the three months ended
March 31, 1996, as our capital structure before the acquisition is not
comparable.
<TABLE>
<CAPTION>
Acquired Company
-----------------------
(in millions except per Share data) Three
Months Nine Months
Year Ended Ended Ended Six Months
December 31, March 31, December 31, Year Ended December 31, Ended June 30,
------------ ---------- ------------ ------------------------ ----------------
1995 1996 1996 1997 1998 1999 1999 2000
------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Statement of Operations Data:
Total revenues.......................... $32.4 $13.3 $47.1 $62.8 $56.7 $52.5 $25.8 $58.3
Lease operating expenses................ 6.4 2.4 6.5 9.4 9.9 11.5 5.8 8.5
Depreciation, depletion and amortization 15.6 6.3 24.8 31.7 33.8 32.5 15.8 29.1
Impairment of oil and gas properties ... -- -- 22.5 28.5 50.8 -- -- --
General and administrative expenses .... 2.0 0.7 2.4 3.2 4.7 5.4 2.8 3.3
Provision for litigation ............... -- -- -- -- 2.8(1) -- -- --
----- ----- ----- ----- ----- ----- ------ -----
Operating income (loss)............... 8.4 3.9 (9.1) (10.0) (45.3) 3.1 1.4 17.4
Interest income......................... 9.3 2.2 0.5 0.5 0.3 -- -- --
Interest expense........................ (12.8) (3.4) (7.7) (10.7) (13.4) (19.4) (9.9) (12.0)
Write-off of bridge loan fees .......... -- -- (2.4) -- -- -- -- --
----- ----- ----- ----- ----- ----- ------ -----
Income (loss) before income taxes..... $4.9 2.7 (18.7) (20.2) (58.4) (16.3) (8.5) 5.4
Provision for income taxes.............. 0.4 -- -- -- -- -- -- --
----- ----- ----- ----- ----- ----- ------ -----
Net income (loss)..................... $4.5 $2.7 $(18.7) $(20.2) $(58.4) (16.3) ($8.5) $5.4
===== ===== ===== ===== ===== ===== ====== =====
Basic and diluted earnings per share ... -- -- $(1.58) $(1.71) $(4.47) $(1.17) $(0.61) $0.39
Average shares outstanding ............. -- -- 11.8 11.8 13.1 13.9 13.9 13. 9
</TABLE>
<TABLE>
<CAPTION>
Acquired As of
Company As of December 31, June 30,
-------------------------------------- -----------
1995 1996 1997 1998 1999 2000
(unaudited)
------ ------ ------ ------ ------ -----------
<S> <C> <C> <C> <C> <C> <C>
Balance Sheet Data:
Cash and cash equivalents...... $5.5 $10.8 $9.1 $0.8 $0.1 $6.2
Total assets................... 250.7 196.7 212.6 262.8 297.2 324.1
Total debt..................... 165.5 99.5 113.6 178.0 217.3 224.1
Shareholders' equity........... 69.3 77.1 57.2 27.5 11.2 28.2
</TABLE>
22
<PAGE>
25
(1) Provision for litigation represents a non-cash charge recorded in the first
quarter of 1998 to provide for a litigation-related cost contingency. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
23
<PAGE>
26
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should refer to the financial statements included in this prospectus in
evaluating the material presented below.
Overview
We are an independent oil and natural gas exploration, development and
production company with principal operations in the Gulf and along the U.S. Gulf
Coast. Our strategy is to profitably increase reserves, production and cash flow
primarily through the drillbit with a heavy emphasis on the deepwater Gulf.
During 1999 and the first nine months of 2000 we:
o drilled seven exploratory wells, with four successes, in the deepwater Gulf
of Mexico, including our potentially significant Aconcagua and Devils Tower
prospects, making us eight of fifteen in deepwater Gulf exploratory test
wells drilled since the acquisition from Hardy;
o drilled successful appraisal wells on our Aconcagua and Devils Tower
prospects;
o commenced production from three significant deepwater projects; Dulcimer in
April 1999, Pluto in December 1999, and Apia in April 2000;
o sold a 63% interest in the Pluto deepwater exploitation project to
Burlington Resources in June 1999, retaining a 37% working interest, which
will increase to 51% after payout;
o sold a portion of our Devils Tower discovery to one of our partners in the
prospect reducing our working interest from 50% to 20% to better manage
financial and operational risk; and
o acquired from Shell Oil Company a 50% interest in the "King Kong" deepwater
Gulf exploitation project.
We expect capital expenditures for 2000 and 2001, net of proceeds from
property conveyances, to be approximately $103 million and $160 million
respectively, which we intend to use to develop existing discoveries and to
explore and continue to build our prospect inventory. We expect to fund our
capital expenditures by a combination of proceeds of the offering, internally
generated cash flow, proceeds from property conveyances, contributions from
affiliates of our principal shareholder and borrowings against our revolving
credit facility.
Our revenue, profitability, access to capital and future rate of growth are
heavily influenced by the price we receive for our production. The markets for
oil, natural gas and natural gas liquids have been historically volatile and may
continue to be volatile in the future. We regularly enter into hedging
transactions for our oil and natural gas production and intend to continue doing
so. These transactions may limit our potential gains if oil and natural gas
prices rise substantially over the price established by the hedges. These hedges
also may expose us to the risk of financial loss in some instances, including
possible production shortfalls and unexpected price changes.
Competition, both from other sources of energy such as electricity and from
within the industry, also affects our performance. Many of our larger
competitors possess and employ financial and personnel resources substantially
greater than those available to us, which can be particularly important in
deepwater Gulf activities. These companies may be able to pay more than we can
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.
We use the full cost method of accounting for our investments in oil and
natural gas properties. Under this methodology, all costs of exploration,
development and acquisition of oil and natural gas reserves are capitalized into
a "full cost pool" as incurred and properties in the pool are depleted and
charged to operations using the unit-of-production method based on a ratio of
current production to total proved oil and natural gas reserves. To the extent
that capitalized costs less deferred applicable taxes exceed the present value,
using a 10% discount rate, of estimated future net cash flows from proved oil
and natural gas reserves and the lower of cost or fair market value of unproved
properties, the excess costs are charged to operations. Capitalized costs are
net of accumulated depreciation, depletion and amortization. Any writedown would
result in a charge to earnings but would not have an impact on cash flows.
24
<PAGE>
27
Our results of operations may vary significantly from year to year based on
the factors discussed above and on other factors such as exploratory and
development drilling success, availability of transportation for our production
volumes, curtailments of production due to workover and recompletion activities
and the timing and amount of reimbursement for overhead costs we receive from
co-owners. Therefore, the results of any one year may not be indicative of
future results.
Results of Operations
The following table shows information related to our oil and natural gas
production, average sales price received and expenses per unit of production
during the periods indicated.
<TABLE>
<CAPTION>
Year Ended Six Months Ended
December 31, June 30,
------------ --------
1997 1998 1999 1999 2000
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Production:
Oil (MMBbls) ........................................................... 1.0 0.8 0.6 0.3 0.8
Natural gas (Bcf) ...................................................... 18.0 19.5 21.1 10.6 15.0
Natural gas equivalent (Bcfe) .......................................... 23.9 24.2 24.9 12.7 20.0
Average daily production (MMcfe) ....................................... 65.0 66.0 68.0 69.6 109.6
Average Realized Sales Prices (including effects of hedging):
Oil (per Bbl) .......................................................... $18.48 $12.80 $13.65 $13.28 $20.15
Natural gas (per Mcf) .................................................. 2.48 2.39 2.08 2.01 2.78
Natural gas equivalent (per Mcfe) ...................................... 2.63 2.34 2.11 2.04 2.92
Expenses (per Mcfe):
Lease operating ........................................................ 0.39 0.41 0.46 0.45 0.42
General and administrative, net(1) ..................................... 0.13 0.20 0.22 0.22 0.16
Depreciation, depletion and amortization, before impairment provision... 1.33 1.40 1.29 1.24 1.46
</TABLE>
----------
(1) General and administrative expenses are presented net of amounts
capitalized under the full cost method of accounting and overhead
reimbursements we received from owners of working interests in the
properties we operate.
Six months ended June 30, 2000 compared to six months ended June 30, 1999
Net production increased 57% to 20.0 Bcfe for the first six months of 2000
from 12.7 Bcfe for the same period of 1999. Production from our offshore Gulf of
Mexico properties increased to 17.7 Bcfe in the six month period ending June 20,
2000 from 8.7 Bcfe in the same period of 1999, primarily as a result of
production commencing from new wells in the Pluto field located in Mississippi
Canyon 674 and the Apia field located in Garden Banks 73. This increase was
offset in part by anticipated production declines in shallow water and onshore
production and sooner than anticipated production declines at our Dulcimer
deepwater Gulf field, located in Garden Banks 367. Total production for the
second half of 2000 is expected to decrease approximately 5% to 10% from the
first half of 2000, due to production decline, offset in part by first
production in the fourth quarter from the Black Widow project located in Ewing
Bank 966.
Oil and gas revenues increased 126% to $58.3 million for the first six
months of 2000 from $25.8 million for the comparable period of 1999, primarily
due to a 43% increase in realized prices to $2.92 per Mcfe in the first six
months of 2000 from $2.04 per Mcfe in the same period last year, and the
production increase discussed above.
Hedging activities for the first six months of 2000 decreased our average
natural gas sales price received by $0.43 per Mcf and revenues by $6.4 million.
Hedging related to crude oil during the first six months of 2000 decreased our
average crude oil sales price received by $7.46 per Bbl and revenues by $6.2
million. Hedging activities for the first six months of 1999 reduced our average
natural gas and crude oil prices received by $0.08 per Mcf and $0.28 per Bbl,
resulting in reductions in revenue of $0.8 million and $0.1 million,
respectively. Hedging arrangements entered into through June 30, 2000 cover
approximately 60% of our anticipated equivalent production for 2000.
25
<PAGE>
28
Lease operating expenses increased 47% to $8.5 million for the first six
months of 2000, from $5.8 million for the comparable period of 1999, primarily
due to the higher offshore production discussed above.
Depreciation, depletion, and amortization expense (DD&A) increased 84% to
$29.1 million for the first six months of 2000 from $15.8 million for the
comparable period of 1999, as a result of the increase in the unit-of-production
depreciation, depletion, and amortization rate to $1.46 per Mcfe from $1.24 per
Mcfe, and a 57% increase in equivalent volumes produced. The higher rate for the
second quarter of 2000 was due to the occurrence of three dry holes since the
second quarter of 1999, and does not include the impact on the rate of two
potentially significant discoveries during the same period for which proved
reserves may be recorded after certain appraisal activities are completed.
General and administrative expenses, which are net of overhead
reimbursements received by us from other working interest owners, increased 15%
to $3.3 million for the first six months of 2000 from $2.8 million for the
comparable period of 1999, due primarily to increased headcount-related costs
required for us to pursue our deepwater Gulf exploration and development plan.
Interest expense for the first six months of 2000 increased 22% to $12.1
million from $9.9 million for the comparable period of 1999, primarily due to
the additional long-term debt provided by Enron to refinance our existing credit
facilities with them as well as to provide additional funds for capital
expenditures.
Income (loss) before income taxes increased to income of $5.4 million for
the first six months of 2000 from a loss of $8.5 million for the same period in
1999, primarily as a result of oil and gas revenue increases and partially
offset by increased expenses discussed above.
1999 compared to 1998
Net production increased 3% to 24.9 Bcfe for 1999 from 24.2 Bcfe for 1998.
Production from our offshore Gulf properties increased to 18.2 Bcfe in 1999 from
13.1 Bcfe in 1998, as a result of production commencing from a new well in the
Dulcimer field located in Garden Banks block 367 and two new wells in the
Rembrandt field located in Galveston block 151. This increase was offset by less
than expected production from our Sandy Lake field onshore Texas.
Hedging activities in 1999 decreased our average natural gas price received
by $0.32 per Mcf and revenues by $6.7 million, compared with an increase of
$0.12 per Mcf and revenues of $2.3 million in 1998. Our hedging activities with
respect to crude oil during 1999 reduced the average sales price received by
$3.42 per Bbl and revenues by $2.2 million. There were no oil hedges in 1998.
During 1999, approximately 85% of our production was subject to hedge positions,
compared to 40% in 1998.
Oil and gas revenues decreased 7% to $52.5 million for 1999 from $56.7
million for 1998, due to a 10% decrease in realized prices to $2.11 per Mcfe in
1999 from $2.34 per Mcfe in 1998.
Lease operating expenses increased 16% to $11.5 million for 1999 from $9.9
million for 1998 due to the higher offshore production discussed above and well
workovers on three offshore wells and two wells in our Sandy Lake field.
Depreciation, depletion, and amortization expense decreased 4% to $32.5
million for 1999 from $33.8 million for 1998 as a result of the decrease in the
unit-of-production depreciation, depletion and amortization rate to $1.31 per
Mcfe from $1.40 per Mcfe. This decrease was offset in part by a 3% increase in
equivalent volumes produced. The lower rate for 1999 was primarily due to the
$50.8 million non-cash full cost ceiling test impairment recorded in 1998. No
impairment was necessary for 1999.
General and administrative expenses, which are net of overhead
reimbursements we received from other working interest owners, increased 14% to
$5.4 million for 1999 from $4.7 million for 1998 due to increased
headcount-related costs in 1999 required for us to pursue our deepwater Gulf
exploration and development plan.
26
<PAGE>
29
Interest expense for 1999 increased 1% to $13.5 million from $13.4 million
for 1998.
Income (loss) before income taxes improved to a loss of $16.3 million for
1999 from a loss of $58.4 million in 1998 as a result of a $50.8 million full
cost ceiling test impairment in 1998, offset in part by oil and gas revenue
decreases and increased expenses in 1999.
1998 compared to 1997
Net production increased 1% to 24.2 Bcfe in 1998 from 23.9 Bcfe in 1997.
Natural gas production increased by 1.5 Bcf, or 8%, to 19.5 Bcf from 18 Bcf.
Natural gas production from our offshore properties decreased 0.3 Bcf, or 3%,
due to the natural production decline offset by the addition of two offshore
properties, while natural gas production from our onshore properties increased
1.8 Bcf, or 32%.
Oil and natural gas revenues for 1998 decreased by $6.1 million, or 10%,
compared to 1997 due to decreased oil and natural gas sales prices partially
offset by the production increase described above. The average realized sales
price of natural gas decreased 4%, to $2.39 per Mcf in 1998 from $2.48 per Mcf
in 1997, while the average realized oil sales price decreased by 31% to $12.80
per Bbl in 1998 from $18.48 per Bbl in 1997.
Hedging activities in 1998 increased our average natural gas sales price
received by $0.12 per Mcf and revenues by $2.3 million. In 1997, our natural gas
hedging activities decreased the average sales price received by $0.22 per Mcf
and revenues by $3.9 million. We had no hedging activities for oil in 1998. Our
hedging activities with respect to crude oil during 1997 reduced the average
sales price received by $0.63 per Bbl and revenues by $0.6 million. During 1998,
approximately 40% of our equivalent production was subject to hedge positions
compared to 60% in 1997.
Lease operating expenses increased 5% to $9.9 million for 1998 from $9.4
million for 1997. Lease operating expense per Mcfe increased to $0.41 per Mcfe
for 1998 from $0.39 per Mcfe for 1997, due to higher fixed costs associated with
offshore properties.
Depreciation, depletion and amortization expense increased 7% to $33.8
million for 1998, from $31.7 million for 1997, as a result of a 5% increase in
the unit-of-production depreciation, depletion and amortization rate to $1.40
per Mcfe from $1.33 per Mcfe, due primarily to increased drilling and completion
costs, and a 1% increase in equivalent volumes produced.
Impairment of oil and gas properties of $50.8 million was recorded in the
fourth quarter of 1998 for a non-cash full cost ceiling test impairment using
prices in effect at December 31, 1998. During the first quarter of 1997, a $28.5
million non-cash full cost ceiling writedown was also recorded due to low
commodity prices in effect as of the end of that period.
A provision for litigation of $2.8 million was provided in the first
quarter of 1998 to reflect the settlement of a lawsuit with one of our joint
interest partners over damages claimed due to our refusal to drill an additional
well in the Sandy Lake field.
General and administrative expenses, which are net of overhead
reimbursements received from other working interest owners on properties
operated by us, increased 47% to $4.7 million in 1998, up from $3.2 million in
1997, due to higher employment levels to build the necessary expertise for
deepwater Gulf projects and related office costs in 1998. General and
administrative expense increased $0.07 per Mcfe from 1997 to 1998.
Interest expense increased 26% to $13.4 million for 1998, from $10.6
million for 1997, due to the 47% increase in average outstanding debt to $151.4
million in 1998, from $103.2 million in 1997, which was partially offset by a
10% decrease in the average interest rate paid on outstanding debt to 9.33%,
from 10.38%.
Income (loss) before income taxes decreased to a loss of $58.4 million for
1998, from a loss of $20.2 million for 1997, as a result of the factors
described above.
27
<PAGE>
30
Liquidity, Capital Expenditures and Capital Resources
Cash flow
As of June 30, 2000, we had a working capital deficit of approximately $9.9
million, compared to a working capital deficit of $36.7 million at December 31,
1999. The reduction in the working capital deficit was primarily a result of
proceeds from a new $112 million term loan with Enron North America Corp.
("ENA") which was used to repay the two credit facilities with ENA and provide
funds for capital and other corporate expenditures. We expect our capital
expenditures for 2000, net of $29 million proceeds from property conveyances, to
be approximately $103 million, which would exceed cash flow from operations. We
expect our 2001 capital expenditures to be approximately $160 million, which
would exceed cash flow from operations for 2001. We cannot assure you that our
access to capital will be sufficient to meet our needs for capital. As such, we
may be required to reduce our planned capital expenditures and forego planned
exploratory drilling or sell portions of our proved reserves or undeveloped
inventory if additional capital resources are not available to us on acceptable
terms.
Our primary sources of cash during the three year period ended December 31,
1999 were funds generated from operations, proceeds from affiliate credit
facilities provided by Enron, proceeds from property conveyances, bank
borrowings and capital contributions by an affiliate of our principal
shareholder. Primary uses of cash for the same period were funds used in
exploration and production activities and repayment of notes and bank debt.
Our primary sources of cash during the first six months of 2000 were from
$112.6 million in proceeds from a term loan provided by Enron and $16.0 million
in proceeds from operating activities. The term loan will be repaid with
proceeds from this offering. The primary uses of cash for the same period were
$25.0 million for capital expenditures and $97.6 million used to repay two
credit facilities with Enron and reduce our revolving credit facility.
We had a net cash inflow of $6.1 million for the six months ended June 30,
2000, and a net cash inflow of $0.7 million in 1999, compared to a net cash
outflow of $8.3 million in 1998 and a net cash outflow of $1.7 million in 1997.
A discussion of cash flows for these periods follows.
Six Months
Ended
Year Ended December 31, June 30,
----------------------------- ----------------
1997 1998 1999 1999 2000
------ ------ ------ ------ ------
Net cash provided by
(used for) our operating
activities (in millions)... $52.9 $40.3 $21.9 $(21.6) $(16.0)
Net cash provided by our operating activities was $16.0 million in the
first six months of 2000, an increase of $37.6 million for the same period of
1999 primarily due to increased oil and gas prices and production offset in part
by decreases in working capital. Currently, our Pluto well on Mississippi Canyon
Block 674 is not required to pay royalties to the Minerals Management Service
("MMS"). This royalty relief was granted assuming oil and natural gas prices
remained below certain predetermined levels. If average commodity prices for
2000 exceed these predetermined levels, we may be required to pay up to $7
million in royalties to the MMS. Cash provided from our operating activities in
1999 decreased by $18.4 million from 1998 primarily due to decreased oil and gas
prices and changes in our working capital. Cash provided by our operating
activities in 1998 decreased by $12.6 million compared to 1997 primarily due to
decreased oil and gas prices.
Six Months
Ended
Year Ended December 31, June 30,
----------------------------- ----------------
1997 1998 1999 1999 2000
------ ------ ------ ------ ------
Net cash used in our
investing activities
(in millions)............ $68.9 $141.9 $61.8 $19.3 $25.0
Net cash used in our investing activities for the first six months of 2000
increased to $25.0 million from $19.3 million for the same period of 1999
primarily due to higher development expenditures. Cash flows used in our
investing activities in 1999 decreased by $80.1 million compared to 1998 due to
decreased capital expenditures and the sell-down of a 63% interest in our Pluto
project. Cash used in our investing activities in 1998 increased by $73 million
compared to 1997 primarily due to increased capital expenditures to acquire
leasehold inventory.
28
<PAGE>
31
Six Months
Ended
Year Ended December 31, June 30,
----------------------------- -----------
1997 1998 1999 1999 2000
------ ------ ------ ------ ------
Net cash provided
by our financing
activities (in millions).... $14.3 $93.2 $39.2 $40.6 $15.0
Net cash provided by our financing activities was $15.0 million for the
first six months of 2000 compared to $40.6 million for the same period in 1999.
Our primary source of cash for the first six months of 2000 was $112.6 million
from a term loan provided by Enron offset by the repayment of two Enron credit
facilities. The term loan will be repaid with proceeds from this offering. Cash
provided by our financing activities in 1999 decreased by $54 million compared
to 1998 due to a $10.8 million net reduction in borrowings against our revolving
credit facility as compared to a $39.4 million increase in borrowings against
that facility for the previous year. Cash provided by our financing activities
in 1998 increased by $78.9 million as compared to 1997 due to us receiving
approximately $28.8 million in equity contributions and $64.4 million from our
revolving credit facilities.
Changes in prices and hedging activities
The energy markets have historically been very volatile. Oil and natural
gas prices will probably continue to fluctuate widely. In an effort to reduce
the effects of price volatility on our operations, we have adopted a policy of
hedging oil and natural gas prices from time to time through commodity futures,
options and swap agreements. While the use of these hedges limits the downside
risk of price declines, it also limits future gains from price increases.
The following table shows the increase (decrease) in our oil and gas sales
as a result of hedging transactions and the effects of hedging transactions on
prices during the periods indicated.
<TABLE>
<CAPTION>
Six Months Ended
Year Ended December 31, June 30,
------------------------ ---------------
1997 1998 1999 1999 2000
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Increase (decrease) in our natural gas sales (in millions) .............. $ (3.9) $ 2.3 $ (6.7) (0.8) $ (6.4)
Increase (decrease) in our oil sales (in millions) ..................... (0.6) -- (2.2) (0.1) (6.2)
Effect of hedging transactions on our average gas sales price (per Mcf).. (0.22) 0.12 (0.32) (0.08) (0.43)
Effect of hedging transactions on our average oil sales (per Bbl) ....... (0.63) -- (3.42) (0.28) (7.46)
</TABLE>
The following table shows our open hedging positions as of June 30, 2000.
<TABLE>
<CAPTION>
Price Fair Value
Notional ------------------------------- Asset/(Liability)
Time Period Quantities Floor Ceiling Fixed (in millions)
----------- ---------- ----- ------- ----- -------------
<S> <C> <C> <C> <C> <C>
Natural Gas (MMBtu)
July 1 - October 31, 2000
Collar purchased 1,353 $2.25 $2.49 $ (2.9)
July 1 - December 31, 2000
Fixed price swap purchased 4,407 $2.18 (10.7)
January 1 - December 31, 2001
Fixed price swap purchased 4,501 2.18 (7.4)
January 1 - December 31, 2002
Fixed price swap purchased 1,831 2.18 (1.8)
Crude Oil (MBbls)
January 1 - December 31, 2000
Fixed price swap purchased 1,155 18.66 (9.8)
Market sensitive price swap (416) 24.16 (2.4)
-------
Total Fair Value $(30.2)
=======
</TABLE>
29
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32
Subsequent to June 30, 2000, we purchased a natural gas collar for a
notional quantity of 5,550 MMbtu with a floor of $3.50 per MMbtu and a ceiling
of $4.92 per MMbtu for the time period October 1, 2000 through September 30,
2001. We also purchased a floor option for a notional quantity of 5,551 MMbtu at
$3.50 per MMbtu for the time period October 1, 2000 through September 30, 2001.
The fair value of our hedging instruments was determined based on a broker's
forward price quote and a NYMEX forward price quote as of June 30, 2000. As of
June 30, 2000, a commodity price increase of 10% would have resulted in an
unfavorable change in fair value of $8.4 million and a commodity price decrease
of 10% would have resulted in a favorable change in fair value of $8.4 million.
Mariner Energy, Inc.'s senior subordinated notes have a fixed rate and,
therefore, do not expose us to risk of earnings loss due to changes in market
interest rates. The market value of the senior subordinated notes was
approximately $100 million based on borrowing rates available at the end of the
periods presented.
Capital expenditures and capital resources
The following table presents major components of our capital and
exploration expenditures for each of the three years in the period ended
December 31, 1999 and the six month periods ended June 30, 1999 and 2000.
<TABLE>
<CAPTION>
Six Months
Ended
Year Ended December 31, June 30,
-------------------------------- --------
1997 1998 1999 1999 2000
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Capital expenditures (in millions):
Leasehold acquisition-- unproved properties ........ $ 21.6 $ 43.1 $ 3.0 $ (0.1) $(10.2)
Leasehold acquisition-- proved properties .......... 3.2 -- -- -- --
Oil and natural gas exploration .................... 27.4 35.7 13.5 0.4 2.8
Oil and natural gas development and other .......... 16.7 63.1 45.2 19.0 32.4
----- ----- ----- ----- -----
Total capital expenditures, net of proceeds from sales $ 68.9 $141.9 $ 61.7 $ 19.3 $ 25.0
===== ===== ===== ===== =====
</TABLE>
Our capital expenditures for the first six months of 2000 were $19.9
million excluing $5.1 million of capitalized indirect costs. The majority of
expenditures for the first six months of 2000 were for the appraisal of our
Aconcagua and Devils Tower discoveries and the development of our Apia and Black
Widow discoveries. These expenditures were offset by the $29.0 million in
proceeds from property conveyances.
Our capital expenditures for 1999 were $81.5 million (excluding $19.8
million related to our sale of a 63% working interest in the Pluto project),
which was $60.4 million less than 1998. The decrease was primarily a result of
lower leasehold acquisition, geological and geophysical, exploratory drilling
and development costs as we operated with reduced access to capital. Excluding
the Pluto sale, our 1999 capital expenditures included $24.0 million for
exploration activities, $48.1 million for development activities and $9.4
million of capitalized indirect costs. Included in exploration expenditures was
$8.9 million for lease bonus payments on three deepwater Gulf blocks awarded to
us in the March 1999 central Gulf lease sale.
Our total capital expenditures for 1998 of 141.9 million were $73 million
more than 1997. The increase was due primarily to our continued focus on
building and evaluating our exploration and exploitation prospect inventory, as
evidenced by the increased leasehold acquisition of unproved properties and
increased oil and gas exploration, and increased development spending, both to
acquire additional interests in existing proved properties and to develop
successful exploratory prospects.
Our capital expenditure plan for the remainder of 2000 and 2001 includes
drilling six to eight exploratory wells in the deepwater Gulf. The majority of
our share of exploratory costs on one of the anticipated deepwater Gulf wells
would be covered by our partner in the well. We also expect to drill two
appraisal wells on our Devils Tower discovery, on which we recently sold a
portion of our working interest to one of our partners, and to complete the
facilities necessary for our Black Widow project to commence production in the
fourth quarter of 2000. We expect our capital expenditures for 2000, including
capitalized indirect costs and reduced by $29.0 million in proceeds from
property conveyances, to be approximately $103 million.
Our anticipated capital expenditures for 2001 total approximately $160
million. The plan includes approximately $25 million to drill three to five
exploratory wells, all in the deepwater Gulf. Our plan anticipates spending
approximately $20 million to acquire deepwater lease blocks and to build our
seismic inventory. We also anticipate expenditures of over $100 million for
existing development projects and costs that are contingent on the success of
our future exploratory drilling.
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Our long-term debt outstanding as of June 30, 2000 was approximately $224.1
million, including $99.7 million of senior subordinated notes, $20 million drawn
on our revolving credit facility, and $104.4 million (net of unamortized warrant
discount) on our term loan with ENA, which was entered into in March 2000,
providing us with approximately $30 million of new capital and funding the
repayment of the $50 million and $25 million credit facilities with Enron at
their maturity in May 2000. Following our semi-annual borrowing base
redetermination completed in April 2000, our borrowing base under the revolving
credit facility was increased from $60 million to $70 million. In October 2000,
the borrowing base was re-affirmed at $70 million.
Our revolving credit facility and the senior subordinated notes contain
various restrictive covenants that, among other things, restrict the payment of
dividends, limit the amount of debt Mariner Energy, Inc. may incur, limit
Mariner Energy, Inc.'s ability to make certain loans, investments, enter into
transactions with affiliates, sell assets, enter into mergers, limit Mariner
Energy, Inc.'s ability to enter into certain hedge transactions and provide that
Mariner Energy, Inc. must maintain specified relationships between cash flow and
fixed charges and cash flow and interest on indebtedness. In addition,
restrictions on Mariner Energy, Inc. in the revolving credit facility and the
senior subordinated notes effectively restrict us from using Mariner Energy,
Inc.'s assets or cash flow to satisfy interest or principal payments for our
term loan with Enron. We expect to repay the term loan from internally generated
cash flows or from proceeds of the offering.
In the second quarter of 1998, management shareholders and an affiliate of
Enron contributed $28.8 million of net equity capital through the sale of common
shares, which was used to reduce borrowings on our revolving credit facility and
to supplement funding of our 1998 capital expenditure plan.
In future periods, our capital resources may not be sufficient to meet our
anticipated future requirements for working capital, capital expenditures and
scheduled payments of principal and interest on our indebtedness. We cannot
assure you that we will grow as expected, generate sufficient cash flow, or
obtain future loans or equity capital sufficient to service our debt or make
necessary capital expenditures. In addition, depending on our cash flow and
capital expenditures, we may need to refinance a portion of the principal amount
of our senior subordinated debt at or prior to maturity. However, we cannot
assure you that we would be able to refinance on acceptable terms.
We expect to fund our activities in the remainder of 2000 and for 2001
through a combination of proceeds of the offering, cash flow from operations,
proceeds from property conveyances and borrowings under our revolving credit
facility.
Recent Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities". SFAS No. 133, as amended, is
effective for fiscal years beginning after June 15, 2000 and establishes
accounting and reporting standards for derivative instruments and for hedging
activities. Had we implemented SFAS No. 133 as of June 30, 2000, a $30.2 million
liability would have been recorded. The offset at the future date of
implementation would be reflected as a cumulative effect adjustment to income
and as other comprehensive income in stockholder's equity. We will adopt this
statement on January 1, 2001.
In December 1999, the Securities and Exchange Commission ("SEC") issued
Staff Accounting Bulletin ("SAB") No. 101, "Revenue Recognition in Financial
Statements." SAB 101 summarizes certain of the SEC's views in applying generally
accepted accounting principles to revenue recognition in financial statements.
The Company is required to adopt SAB 101, as amended, in the fourth quarter of
fiscal 2000. The Company does not expect the adoption of SAB 101 to have a
material effect on its financial position or results of operations.
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34
BUSINESS AND PROPERTIES
About Mariner
Mariner Energy is an independent oil and natural gas exploration,
development and production company with principal operations in the Gulf of
Mexico and along the U.S. Gulf Coast. Our increasing focus on Gulf water depths
greater than 600 feet, or the deepwater, since the early 1990s has made us one
of the most experienced independent operators in the deepwater Gulf. We have
been an active explorer in the Gulf Coast area since the mid-1980s, when we
operated as Hardy Oil & Gas USA Inc., and have increased our production and
reserve base through the exploitation and development of internally generated
prospects, which we refer to as growth "through the drillbit." Members of our
senior management team, most of whom have worked together for over 16 years, and
an affiliate of Enron North America Corp. led a buyout of Mariner from Hardy Oil
& Gas, plc in April 1996. We believe that our operating experience, exploration
expertise, extensive deepwater lease inventory and seasoned management team give
us a unique competitive advantage with substantial growth potential.
Since beginning deepwater operations in 1994, we have:
o operated seven successful subsea development projects in water depths of
400 feet to 2,700 feet;
o developed three deepwater exploitation projects acquired from major oil
companies, including our Pluto project, and acquired a fourth deepwater
exploitation project, King Kong, from Shell Oil Company in July 2000;
o discovered eight new fields in fifteen deepwater Gulf exploration tests,
including potentially significant discoveries at our Aconcagua and Devils
Tower prospects, on which appraisal operations are in progress;
o acquired 70 deepwater Gulf lease blocks, most of which are free of royalty
payment obligations; and
o built an inventory of 13 deepwater Gulf exploration prospects, many of
which have potential to significantly increase our proved reserves and
future production.
Ryder Scott Company estimated that we had proved reserves of 178.4 Bcfe as
of December 31, 1999, of which 67% were natural gas and 33% were oil and
condensate. Proved reserve estimates as of December 31, 1999 did not include
estimates related to discoveries at our Aconcagua and Devils Tower prospects.
For the year ended December 31, 1999, we produced an average of 68 MMcfe per
day. For the six months ended June 30, 2000, we produced an average of 110 MMcfe
per day, reflecting production from our Pluto project, which began in late
December 1999 and is currently producing approximately 35 MMcfe per day net to
our interest and our Apia project, which began in late April 2000 and is
currently producing approximately 13 MMcfe per day net to our interest.
We expect our production levels and operating cash flow to increase
significantly in 2000 over 1999 based on production from our Pluto project, our
Apia project, and our Black Widow project, which is expected to begin producing
in the fourth quarter of 2000.
Our planned capital expenditures for 2000, net of approximately $29 million
from property conveyances, consist of approximately $103 million for leasehold
acquisition, exploration drilling and development projects, compared to capital
expenditures of approximately $62 million for 1999. During the first nine months
of 2000, we:
o drilled successful appraisal wells on our Aconcagua and Devils Tower
discoveries;
o drilled three exploratory wells in the deepwater Gulf, one of which was
successful;
o sold a portion of our Devils Tower discovery to one of our partners in the
prospect, reducing our working interest from 50% to 20% to better manage
financial and operational risk; and
o acquired from Shell Oil Company a fifty percent interest in the "King Kong"
deepwater Gulf exploitation project, which we expect to commence production
by early 2002.
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35
During the remainder of 2000 and 2001, we expect to drill six to eight
deepwater Gulf prospects with potential to add significant quantities of proved
reserves and future production. We also expect to drill two appraisal wells on
our Devils Tower discovery, to drill development wells and complete facilities
needed to commence production on our King Kong project by early 2002, and to
complete most of the infrastructure necessary for our Aconcagua project to
commence production in early 2002. We anticipate our 2001 capital expenditures,
net of proceeds from property conveyances, will be approximately $160 million,
with the majority planned for the development of existing discoveries, new
exploration drilling and leasehold and prospect acquisition.
Strategy
Our business strategy is to increase reserves, production and cash flow
profitably by emphasizing growth through the drillbit in our deepwater Gulf
niche; the use of subsea technology to develop mid-sized fields that are either
acquired from major oil companies or discovered via low-cost exploration. Our
strategy consists primarily of the following elements:
Focus on the Deepwater Gulf. With our current prospect and seismic
inventory and many more deepwater Gulf lease blocks expected to become available
via lease sales and farmouts from existing leaseholders, we believe we are
well-positioned to increase our deepwater Gulf activity and to continue to
generate and exploit economically attractive prospects. We intend to continue:
o exploring for reserve targets that are smaller than the threshold of the
major oil companies, allowing us to avoid direct competition with the
majors; and
o generating prospects and operating projects within our expertise but beyond
the capability of most independents.
Pursue a Balanced Portfolio Approach to our Drilling Program. We target
four to eight new prospects each year, with a strong deepwater Gulf emphasis.
The program is designed to provide reserve replacement and production growth
through low-risk deepwater exploitation projects and opportunities for
substantial growth through moderate-risk exploration prospects that can
significantly increase our reserve base. We intend to use up to 90% of our
available capital on deepwater Gulf exploration and exploitation projects. We
focus on the deepwater Gulf because of:
o the potential for discovery of large hydrocarbon deposits;
o relatively favorable reservoir characteristics;
o the prevalence of 3-D seismic direct hydrocarbon indicators;
o the relatively under-explored nature of the deepwater Gulf;
o the recent advances in deepwater production technology that reduce
development costs and expedite production; and
o the favorable operating margins resulting from generally favorable prices
for Gulf production and lower operating costs per unit. These lower costs
per unit are associated with prolific wells, concentration of labor and
equipment, absence of severance and ad valorem taxes and generally lower
royalties.
Internally Generate Most of Our Prospects. By internally generating most of
our prospects, we believe we have better control over the quality of the
prospects in which we participate, thereby increasing our chances for commercial
success. Almost all of our inventory of 12 exploration prospects as of June 30,
2000, were internally generated by our staff of 11 geoscientists, which has
extensive experience in the deepwater Gulf. Through our technical staff's
understanding of the geology and geophysics of the deepwater Gulf and our
inventory of leasehold blocks and seismic data, we intend to continue to
generate the majority of our prospects internally.
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36
Manage Deepwater Risks. We intend to reduce our deepwater risks by
continuing to:
o target prospects with relatively low gross drilling costs ranging from $5
million to $20 million;
o use 3-D seismic technology to identify direct hydrocarbon indicators and to
lessen the risk of dry holes; and
o limit the financial exposure of our deepwater prospect portfolio by:
o selling a portion of our working interests in our deepwater projects to
industry partners, typically on a promoted basis where all or a portion of
our exploratory costs are paid by partners;
o generally maintaining a 25% to 50% interest during the appraisal phase of a
successful exploratory project; and
o reducing our interest in the development phase of a project when
appropriate, considering other opportunities in our investment portfolio,
the need to avoid becoming overly concentrated in a few projects and the
availability of capital.
Apply Our Deepwater Operational Expertise. Our deepwater operations
managers average over 25 years of experience with major oil companies and large
independents around the world. By operating most of our deepwater projects, we
intend to apply the experience of our staff to continue to:
o maintain efficient drilling performance;
o shorten project cycle times;
o reduce operational risks and life of project finding and development costs;
and
o innovatively use proven subsea production technology and develop low cost,
mobile floating production facilities.
Competitive Strengths
We have several competitive strengths that we believe will allow us to
compete successfully in oil and natural gas exploration, production and
development activities in the Gulf:
Early Entry Into the Deepwater Gulf. We began focusing in the deepwater
Gulf in 1992 as one of the first independent oil and natural gas companies to
recognize the opportunity for acquiring smaller deepwater discoveries not
meeting a large company's field size threshold and for partnering with major oil
companies to develop these discoveries. We believe our nine years in the
deepwater Gulf have provided us with the geophysical and geological skills,
operating expertise and relationships necessary to operate successfully in the
deepwater. Our deepwater Gulf expertise includes:
o a strong understanding of the geology and geophysics of the deepwater Gulf;
o familiarity with challenges peculiar to operating in the deepwater Gulf;
and
o relationships with vendors, major oil companies and other partners having
complementary skills and knowledge of the area.
Substantial Acreage, Seismic Data and Prospect Inventory. Our Gulf
leasehold inventory as of June 30, 2000, consisted of 110 lease blocks,
including 70 in the deepwater. Our prospect inventory included 12 exploration
prospects, all of which are in the deepwater Gulf. We expect to drill one or two
of these exploration prospects by the end of 2000. Our seismic database includes
3-D seismic that covers approximately 7,800 square miles of the Gulf and modern
2-D seismic that covers more than 250,000 miles of the deepwater Gulf. We
internally generate substantially all of our exploration and exploitation
prospects using 3-D seismic data.
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37
Experienced Operations and Technical Staff and Management. Our 11
geoscientists average more than 20 years of experience in the exploration and
production business, including extensive experience in the deepwater Gulf and
with major oil companies. Our four deepwater operations managers average over 25
years of experience with major oil companies and large independents around the
world. Most of our senior management team participated in our acquisition from
Hardy and have worked together for over 16 years. Management and other key
personnel currently own approximately 4% of the common shares and have options
that, if exercised, would increase their ownership to approximately 16%. We
believe that management's ownership aligns its interests with those of other
shareholders.
Principal Oil and Natural Gas Properties
Deepwater Gulf of Mexico
Mississippi Canyon 718 (Pluto). We acquired a 30% interest in this project
in 1997, two years after British Petroleum discovered gas on the project. We
later increased our ownership to 97%, acquiring operatorship and gaining overall
control of project planning and implementation. In 1998, we increased our
working interest to 100% and submitted a deepwater royalty relief application
that was granted in July 1999. Due to high natural gas commodity prices,
however, it is possible that royalty relief may not apply to natural gas
production in 2000. In June 1999, we sold a 63% working interest in the project
to Burlington Resources, Inc., reducing our working interest to 37%. After
project payout, which is expected in the third or fourth quarter of 2000, our
working interest increases to 51% and Burlington's working interest decreases to
49%. We developed the field with a single subsea well which is located in the
deepwater Gulf approximately 150 miles southeast of New Orleans, Louisiana at a
water depth of 2,700 feet and a flow line tied back approximately 29 miles to a
production platform on the shelf. Production began on December 29, 1999, and
production was reduced or curtailed during January and February while start-up
problems were resolved. As of December 31, 1999, the field had estimated net
proved reserves of 26.6 Bcfe, 72% of which was natural gas.
Ewing Bank 966 (Black Widow). We generated the Black Widow prospect and
acquired it at a federal offshore Gulf lease sale in March 1997. We operate and
have a 69% working interest in this project, which is located in the deepwater
Gulf approximately 130 miles south of New Orleans, Louisiana at a water depth of
approximately 1,850 feet. In early 1998, we drilled a successful exploration
well on the prospect. We expect the well to commence production in the fourth
quarter of 2000 via subsea tieback to an existing platform at an estimated rate
of 6,000 to 8,000 Bbls of oil per day. Estimated net proved reserves from Black
Widow were approximately 21.4 Bcfe, 85% of which was oil, as of December 31,
1999.
Garden Banks 73 (Apia). We generated the Apia prospect and acquired it in a
federal offshore lease sale in August 1998. We operate and own a 100% working
interest in this project which is located offshore Louisiana in a water depth of
approximately 700 feet. In September 1999 we drilled a successful exploration
well which encountered 102 net feet gas pay in a single zone. The field was
developed by the single subsea well tied back to a host platform approximately
three miles from the well. Production began on April 29, 2000. The field had
estimated net proved reserves of 17.6 Bcfe, all of which was natural gas, as of
December 31, 1999.
Garden Banks 367 (Dulcimer). We generated the Dulcimer prospect and
acquired it at a federal offshore Gulf lease sale in September 1996. The well is
located in the deepwater Gulf approximately 170 miles south of Lake Charles,
Louisiana at a water depth of approximately 1,100 feet. We operate and have a
42% working interest in the property. In late 1997, we drilled a successful
exploration well in two productive intervals between 9,900 feet and 10,500 feet.
The well commenced production in April 1999, after tieback to a production
platform located approximately 14 miles from the well. In May 2000, Dulcimer
began to produce lower gas rates in conjunction with the onset of
reservoir-related water production. The well had been producing approximately 43
MMcf of gas per day after cumulative production of approximately 19 Bcfe. The
well continues to produce additional natural gas volumes at lower rates. Other
possibilities exist for the project including production of additional reserves
in the existing well bore as well as sidetracking the well to an updip location
in this fault block. An additional exploratory target has previously been
defined on the block that, if drilled successfully, would benefit from the
existing infrastructure. Through December 31, 1999, the field had produced 4.8
Bcfe net to us. The field had estimated net proved reserves of 14.9 Bcfe, 99% of
which was natural gas, as of December 31, 1999.
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Garden Banks 240 (Mustique). We generated the Mustique prospect and
acquired it through a swap transaction with Shell Oil Company. Mustique is
located offshore Louisiana in a water depth of approximately 830 feet. We own a
33% working interest in and operate this single well subsea development. The
well is tied back via a subsea flowline to a Chevron-operated platform
approximately 11 miles from the wellsite, where its production is commingled and
marketed with Chevron's production. Initial production was in January 1996. As
of December 31, 1999, the field had produced 6.9 Bcfe net to us. Remaining net
proved reserves were estimated to be 2.8 Bcfe, 96% of which was natural gas, and
the estimated remaining field life was approximately five years.
Green Canyon 136 (Shasta). We generated the Shasta prospect and obtained it
in a farmout agreement with Texaco, Inc. Shasta is located offshore Louisiana in
water depths of 840 to 1,040 feet. We operated subsea development of this
project from planning through drilling and equipment installation until the date
of first production. Following completion of this development, Texaco assumed
operation of the project. We own a 25% working interest in this one-well subsea
development that is tied back via subsea flowline to a Texaco-operated platform
approximately ten miles from the well sites. At the platform, production is
commingled and marketed with Texaco's production. Initial production was in
November 1995. Through December 31, 1999, the field had produced 10.9 Bcfe net
to us. Remaining net proved reserves were estimated to be 1.7 Bcfe, 99% of which
was natural gas as of December 31, 1999.
Shallow Water Gulf and Gulf Coast Onshore
Brazos A-105. We generated the Brazos A-105 prospect and own a 13% working
interest in this Spirit Energy-operated property, which commenced production in
January 1993. Five wells exploit a single reservoir. No additional wells are
currently anticipated. The field has produced 23.2 Bcfe net to us from its
inception through December 31, 1999. The field had estimated remaining net
proved reserves of 11.1 Bcfe as of December 31, 1999, 99% of which was natural
gas.
Galveston 151 (Rembrandt). We generated the Rembrandt prospect and acquired
it at a federal offshore Gulf of Mexico lease sale in September 1995. In late
1996, we drilled a successful exploration well on the prospect. In June 1998, we
drilled a second successful well on the prospect in a separate fault block
adjacent to the initial discovery well. The second well commenced production in
August 1998. We drilled a third successful well in another fault block on the
prospect in 1998 and commenced production in November 1998. We operate and have
a 33% working interest in this project, which is located offshore Texas at a
water depth of approximately 50 feet. The field has produced 6.5 Bcfe net to us
since its inception through December 31, 1999. The field had estimated remaining
net proved reserves of 6.8 Bcfe, 79% of which was natural gas, as of December
31, 1999.
Sandy Lake Field. We generated the Sandy Lake prospect, located in the Pine
Island Bayou Field, and commenced production there in August 1994. We operate
the field and own 33% to 50% working interest in the producing wells. The
majority of the 4,680-acre property is located within the city limits of
Beaumont, Texas. Nine productive wells have been drilled thus far, three of
which are producing. We expect to drill another development well in the field
during the fourth quarter of 2000. The field has produced a total of 34.0 Bcfe
net to us as of December 31, 1999. The estimated remaining net proved reserves
are 3.9 Bcfe as of December 31, 1999, 77% of which was natural gas.
Matagorda Island 683,703. We acquired Matagorda Island blocks 683 and 703
as part of a bid group and commenced production in March 1993. We own a 25%
working interest in the two 5,760-acre, Vastar Resources, Inc.-operated blocks.
Four successful wells have been drilled on the property and no additional
drilling is currently planned. Through December 31, 1999 the field has produced
a total of 10.1 Bcfe net to us. As of December 31, 1999 the field had estimated
net proved reserves of 3.6 Bcfe.
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Permian Basin of West Texas
Spraberry Aldwell Unit. We acquired our interest in the Spraberry Aldwell
Unit, located in Reagan County, Texas, in 1985. The 18,250-acre unit is located
in the heart of the Spraberry Trend southeast of Midland, Texas and has produced
oil since 1949. We operate the unit and own working interests in individual
wells ranging from approximately 33% to 84%. We initiated an infill drilling
program in 1987 innovatively commingling the unitized Spraberry formation with
the non-unitized Dean formation. To date, 72 infill wells have been drilled
resulting in 71 productive wells. Currently there are a total of 82 producing
wells in the unit. Depending on, among other things, the future prices of oil
and natural gas, we may drill 20 to 40 additional infill wells, bringing proved
undeveloped reserves into production, in the next two to four years at a
projected cost of approximately $340,000 to $400,000 per well. We estimate that
the field's remaining net proved reserves as of December 31, 1999 was 52.5 Bcfe.
We believe that the field's potential for continued economic oil production
exceeds 40 years.
Recent Potentially Significant Deepwater Gulf Discoveries
As of December 31, 1999, no proved reserves had yet been determined or
recorded from the following discoveries.
Mississippi Canyon 305 (Aconcagua). We generated the Aconcagua prospect and
acquired it at a federal offshore Gulf lease sale in March 1998. We hold a 25%
working interest in the block. During the first quarter of 1999, the operator,
Elf Exploration, drilled a successful exploration well on the prospect, on which
our share of the drilling cost was paid by one of our partners. The well logged
multiple pay sands, which are geological formations where deposits of oil or gas
are found in commercial quantities, and we encountered additional sands with
productive potential. The well is located 40 miles from the shelf edge in 7,100
feet of water approximately 150 miles southeast of New Orleans. Elf Exploration
drilled a successful appraisal well in March 2000, encountering over 250 net
feet of gas pay and confirming that reservoirs found in the discovery well
extend approximately two miles to the northeast. Aconcagua is included in the
recently announced Canyon Express joint subsea development project, which will
gather production from three deepwater natural gas fields and transport it over
40 miles to the platform in shallow water on the outercontinental shelf. The
development plan is expected to be finalized in the fourth quarter of 2000. We
anticipate that production will commence in the second quarter of 2002. We also
anticipate a determination of proved reserves in the fourth quarter of 2000.
Mississippi Canyon 773 (Devils Tower). We generated the Devils Tower
prospect and acquired it in the March 1998 federal lease sale. We hold a 20%
working interest in the prospect, which is located approximately 140 miles
southeast of New Orleans in 5,600 feet of water. During the fourth quarter of
1999, we drilled a successful exploration well on the prospect, encountering
multiple hydrocarbon bearing zones. Casing was run in the well and the well was
temporarily suspended. Our share of the drilling cost for the exploration well
was paid by our partners in the prospect, and in May 2000 we sold a 30% working
interest in the project to one of our partners, Dominion Exploration &
Production, Inc., who subsequently became the operator. During the second
quarter of 2000, a successful appraisal well was drilled to a total measured
depth of 15,000 feet. The well encountered hydrocarbons in three zones in a
separate fault block northeast of the discovery well. A successful sidetrack of
the appraisal well was also drilled immediately thereafter. Future plans include
drilling two more appraisal wells in 2001 and the determination of the
appropriate development plan. First production from the project is anticipated
in 2003.
Recent Acquisition of Deepwater Gulf Exploitation Project
In July 2000, we entered into an agreement to acquire Shell Exploration and
Production Company's 50% working interest in the "King Kong" Deepwater Gulf of
Mexico development project. The project is located in approximately 3,900 feet
of water in Green Canyon Blocks 472, 473 and 517, approximately 150 miles
southeast of New Orleans. We purchased Shell's interest for an undisclosed
amount of cash and overriding royalty interest in the field, and have been named
operator for development of the project. Agip Petroleum Co. Inc., as a successor
to British Borneo, owns the remaining 50% working interest. We intend to develop
gas reserves from two separate reservoirs discovered by three exploration wells
that were previously drilled in the project. The initial development plan calls
for completing a previously-drilled well and drilling an additional development
well, with both subsea wells tied back 16 miles to the Allegheny mini-TLP
operated by Agip. We also plan to drill our "Yosemite" exploration prospect
located adjacent to King Kong in Green Canyon Block during 2001. If successful,
we expect Yosemite to be jointly developed with King Kong. We anticipate
production from the project to commence by early 2002. The King Kong development
project is located in the same area of Green Canyon where we have assembled four
other exploration prospects, including Yosemite, providing us with the
opportunity to capitalize on synergies for the development of any discoveries.
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Deepwater Gulf Exploration Prospects
We hold an inventory of 13 deepwater Gulf exploration prospects. We expect
to drill and evaluate these prospects over the next two to three years, which
are summarized in the table below. As part of our risk management strategy, we
expect to sell a portion of our working interest in many of these prospects to
industry partners.
<TABLE>
<CAPTION>
Current
Mariner Approximate Quarter Drilling
Working Water Depth Expected
Operator Interest (Feet) to Commence
<S> <C> <C> <C> <C>
Mississippi Canyon 322 (Crater Lake) Mariner 45% 700 4th Quarter 2000
East Breaks 832 (Key West).......... Mariner 100% 3,600 4th Quarter 2000
East Breaks 513/514/558 (LaSalle)... Anadarko 33% 3,300 1st Quarter 2001
East Breaks 623 (Falcon)............ Mariner 50% 3,267 1st Quarter 2001
Garden Banks 501 (Baritone)......... Mariner 50% 2,250 2nd Quarter 2001
Green Canyon 516 (Yosemite)......... Mariner 100% 4,075 2nd Quarter 2001
Keathley Canyon 18 (Kilimanjaro).... Kerr-McGee 25% 4,700 3rd Quarter 2001
Garden Banks 939 (Cherie)........... Mariner 100% 4,500 4th Quarter 2001
Green Canyon 649 (Ham).............. Mariner 100% 4,400 4th Quarter 2001
Mississippi Canyon 767 (Cascade).... Mariner 50% 4,200 4th Quarter 2001
Garden Banks 208 (Cello)............ Kerr-McGee 50% 1,270 1st Quarter 2002
Green Canyon 646 (Daniel Boone)..... Mariner 100% 4,376 2nd Quarter 2002
Green Canyon 514 (Kootenay)......... Mariner 100% 4,070 3rd Quarter 2002
</TABLE>
Although we expect to drill these prospects, there can be no assurance that
these wells will be drilled at all or within the expected time frame. Please
read "Risk Factors" for a discussion of some factors that may affect the timing
of drilling.
Reserves
The following table shows information related to our estimated proved
reserves by geographic area as of December 31, 1999. Estimated reserve volumes
and values were determined under the method prescribed by the Securities and
Exchange Commission that requires the application of period-end prices for each
period, held constant throughout the projected reserve life. You should not
assume that the present value of estimated future net revenues referred to in
this prospectus is the current market value of our estimated oil and natural gas
reserves.
The reserve information as of December 31, 1999 is based upon a reserve
report prepared by the independent petroleum consulting firm of Ryder Scott
Company, L.P. Producing oil and natural gas reservoirs generally are
characterized by declining production rates that vary depending upon reservoir
characteristics and other factors. Therefore, without reserve additions in
excess of production through successful exploration and development activities,
our reserves and production will decline. Although we estimate our reserves and
the estimated costs of developing them according to industry standards, the
estimated costs may be inaccurate, development may not occur as scheduled and
actual results will likely differ from estimates. The reserve report does not
reflect the effects of financial hedging. For a discussion of our present oil
and natural gas hedging positions, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity, Capital Expenditures
and Capital Resources -- Changes in prices and hedging activities."
The present value of estimated future net revenues before income tax as of
December 31, 1999 was determined by using period end prices as of December 31,
1999, which were $23.85 per Bbl of oil and $2.23 per Mcf of natural gas. The
present values of estimated future net revenues shown in the table below were
calculated by discounting estimated future net revenues at a 10% rate, with
period-end prices held constant. The amounts under the projected value of
estimated future net revenues are before income taxes and, therefore, are not
the same as the "Standardized Measure of Discounted Future Net Cash Flows"
disclosed in Note 10 of the notes to our consolidated financial statements.
38
<PAGE>
41
<TABLE>
<CAPTION>
As of December 31, 1999
--------------------------------------------------------------
Present Value of
Proved Reserves Estimated Future Net Revenues
--------------------------- --------------------------------
(Dollars in Millions)
--------------------------------
Oil Natural Gas Total Developed Undeveloped Total
(MmBbls) (Bcf) (Bcfe)
<S> <C> <C> <C> <C> <C> <C>
Deepwater Gulf ........................ 4.3 62.5 88.4 $ 83.7 $ 34.9 $ 118.6
Gulf Shallow Water and Gulf Coast Areas 0.8 32.7 37.5 49.9 4.3 54.2
Permian Basin ......................... 4.8 23.6 52.5 20.1 18.3 38.4
----- ----- ----- ----- ----- ------
Total ................................. 9.9 118.8 178.4 153.7 57.5 211.2
===== ===== ===== ===== ===== ======
Proved Developed Reserves ............. 3.8 82.8 105.6 153.7
===== ===== ===== =====
</TABLE>
Our estimates of proved reserves in the table above do not differ
materially from those we have filed with other federal agencies.
Estimating oil and natural gas reserves is complex. It requires many
assumptions, including assumptions relating to natural gas and oil prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds. Actual future production, oil and natural gas prices, operating expenses
and quantities of oil and natural gas reserves most likely will vary from our
estimates. See Note 10 of the notes to our consolidated financial statements for
a discussion of the risks inherent in oil and natural gas estimates and for
additional information concerning our proved reserves.
Production
The following table shows information related to oil and natural gas
production, average sales price received and expenses per unit of production
during the periods indicated.
<TABLE>
<CAPTION>
Year Ended Six Months Ended
December 31, June 30,
----------------------- ----------------
1997 1998 1999 1999 2000
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Production:
Oil (MMBbls) .............................................. 1.0 0.8 0.6 0.3 0.8
Natural gas (Bcf) ......................................... 18.0 19.5 21.1 10.6 15.0
Natural gas equivalent (Bcfe) ............................. 23.9 24.2 24.9 12.7 20.0
Average daily production (MMcfe) .......................... 65.0 66.0 68.0 69.6 109.6
Average Realized Sales Prices (including effects of hedging):
Oil (per Bbl) ............................................. $18.48 $12.80 $13.65 $13.28 $20.15
Natural gas (per Mcf) ..................................... 2.48 2.39 2.08 2.01 2.78
Natural gas equivalent (per Mcfe) ......................... 2.63 2.34 2.11 2.04 2.92
Expenses (per Mcfe):
Lease operating ........................................... 0.39 0.41 0.46 0.45 0.42
General and administrative, net(1) ........................ 0.13 0.20 0.22 0.22 0.16
Depreciation, depletion and amortization, before
impairment provision ...................................... 1.33 1.40 1.31 1.24 1.46
</TABLE>
----------
(1) General and administrative expenses are shown net of amounts capitalized
under the full cost method of accounting and overhead reimbursements we
receive from owners of working interests in the properties operated by us.
39
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42
Productive Wells
The following table shows the number of productive oil and natural gas
wells in which we owned a working interest as of June 30, 2000:
Total Productive
Wells
Gross Net
----- -----
Oil.......... 89 62.5
Natural gas.. 62 12.4
----- -----
Total 151 74.9
Productive wells consist of producing wells and wells capable of
production, including natural gas wells awaiting pipeline connections. We have
six wells that are completed in more than one producing horizon; those wells
have been counted as single wells.
Acreage
The following table shows information relating to our developed and
undeveloped acreage as of June 30, 2000. Developed acres are acres spaced or
assigned to productive wells. Undeveloped acres are acres on which wells have
not been drilled or completed to a point that would permit the production of
commercial quantities of oil and natural gas regardless of whether this acreage
contains proved reserves.
(Thousands of Acres)
Developed Acres Undeveloped Acres
------------------ ------------------
Gross Net Gross Net
-------- -------- --------- --------
Texas (Onshore).............. 19.8 13.0 0.9 0.5
All other states (Onshore)... 0.7 0.2 0.6 0.1
Offshore..................... 212.3 54.7 348.5 178.9
-------- -------- --------- --------
Total.............. 232.8 67.9 350.0 179.5
======== ======== ========= ========
Drilling Activity
The following table sets forth information with regard to our drilling
activity during the periods indicated.
Six Months
Year Ended December 31, Ended June 30,
-------------------------------------- ----------
1997 1998 1999 2000
----------- ---------- ---------- ----------
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- ---
Exploratory wells:
Productive ............. 4 1.4 3 1.1 3 1.8 -- --
Dry .................... 7 1.6 5 1.5 2 0.5 2 1.1
-- ---- -- ---- -- --- -- ---
Total .......... 11 3.0 8 2.6 5 2.3 2 1.1
== ==== == ==== == === == ===
Development wells:
Productive ............. 11 5.3 19 8.6 8 1.6 2 0.5
Dry .................... -- -- 3 1.1 -- -- -- --
-- ---- -- ---- -- --- -- ---
Total .......... 11 5.3 22 9.7 8 1.6 2 0.5
== ==== == ==== == === == ===
Total wells:
Productive ............. 15 6.7 22 9.7 11 3.4 2 0.5
Dry .................... 7 1.6 8 2.6 2 0.5 2 1.1
-- ---- -- ---- -- --- -- ---
Total .......... 22 8.3 30 12.3 13 3.9 4 1.6
== ==== == ==== == === == ===
40
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43
Disposition of Properties
We periodically evaluate, and, when appropriate, sell, some of our
producing properties that we consider to be marginally profitable or outside of
our areas of concentration. These sales enable us to maintain financial
flexibility, reduce overhead and redeploy the proceeds from the sale to
activities that we believe have a higher potential financial return. We made no
property dispositions during 1997 or 1998. During 1999, we sold a 63% working
interest in the Pluto deepwater Gulf exploitation project to Burlington
Resources, Inc., reducing our working interest to 37%. After project payout, our
working interest increases to 51% and Burlington's working interest decreases to
49%. In May 2000, we sold a 30% working interest in our Devils Tower deepwater
Gulf discovery to one of our partners in the discovery, reducing our working
interest to 20%.
Title to Properties
Our properties are subject to customary royalty interests, liens incident
to operating agreements, liens for current taxes and other burdens, including
other mineral encumbrances and restrictions. We do not believe that any of these
burdens materially interferes with the use of our properties in the operation of
our business.
We believe that we have satisfactory title to or rights in all of our
producing properties. As is customary in the oil and natural gas industry,
minimal investigation of title is made at the time of acquisition of undeveloped
properties. We investigate title and obtain title opinions from local counsel,
only before commencement of drilling operations. We believe that title issues
generally are not as likely to arise on offshore oil and gas properties as on
onshore properties.
Marketing, Customers and Hedging Activities
We market substantially all of the oil and gas production from properties
we operate and from properties others operate where our interest is significant.
The majority of our natural gas, oil and condensate production is sold to a
variety of purchasers under short-term (less than 12 months) contracts, usually
at market-sensitive prices. We have a gas processing agreement for our gas
production from Sandy Lake. We believe that the price we receive for that gas
production is favorable compared to market prices at that location. The
following table lists customers accounting for more than 10% of our total
revenues for the year indicated. A "--" indicates that revenues from the
customer accounted for less than 10% of our total revenues for that year.
Percentage of Total Revenues
For the Years Ended
December 31,
Customer 1997 1998 1999
-------------------------------- ---------- ---------- -------
Enron North America Corp........ 18% 15% 26%
Transco Energy Marketing Company 14% 16% 21%
Duke Energy..................... 19% 29% 13%
Genesis Crude Oil LP............ 19% 10% --
Due to the nature of the markets for oil and natural gas, we do not believe
that the loss of any one of these customers would have a material adverse effect
on our financial condition or results of operations.
Historically, demand for natural gas has been seasonal in nature, with peak
demand and typically higher prices during the colder winter months.
We regularly use hedging transactions related to a portion of our oil and
natural gas production to reduce our exposure to price fluctuations and to
achieve a more predictable cash flow. We do not hedge for speculative purposes.
We customarily hedge through swap arrangements that establish an index-related
price above which we pay the hedging partner and below which the hedging partner
pays us. Approximately 85% of our equivalent production was subject to hedge
positions during 1999. Hedging arrangements entered into through June 30, 2000,
cover approximately 60% of our anticipated equivalent production for 2000.
Hedging arrangements for 2001 and 2002 cover approximately 15% for 2001 and 4%
for 2002 of our anticipated equivalent production. Hedging arrangements may
expose us to the risk of financial loss in certain instances, including possible
shortfalls in our production or sudden unexpected price changes. Our revolving
credit facility places restrictions on our use of hedging to 85%, 65%, 40% and
25% of anticipated production from proved producing reserves for immediately
following twelve months, twenty-four months and thirty-six months, and all
months thereafter, respectively. For additional discussion of our hedging
activities, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity, Capital Expenditures and Capital Resources
-- Changes in prices and hedging activities."
41
<PAGE>
44
Competition
We believe that the locations of our leasehold acreage; our exploration,
drilling and production capabilities; and the experience of our management
generally enable us to compete effectively. However, our competitors include
major integrated oil and natural gas companies and numerous independent oil and
natural gas companies, individuals and drilling and income programs. Many of our
larger competitors possess and employ financial and personnel resources
substantially greater than those available to us. These companies 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 our financial or personnel resources permit. Our ability to
acquire additional prospects and to discover reserves in the future depends on
our ability to evaluate and select suitable properties and to close transactions
in a highly competitive environment. Also, there is substantial competition for
capital available for investment in the oil and natural gas industry.
Royalty Relief
The Outer Continental Shelf Deep Water Royalty Relief Act (the "RRA"),
signed into law on November 28, 1995, provides that all tracts in the Gulf of
Mexico west of 87 degrees, 30 minutes West longitude in water more than 200
meters deep offered for bid within five years of the RRA will be relieved from
normal federal royalties as follows:
Water Depth Royalty Relief
------------------- ----------------------------
200-400 meters..... no royalty payable on the first 105 Bcfe produced
400-800 meters..... no royalty payable on the first 315 Bcfe produced
800 meters or deeper no royalty payable on the first 525 Bcfe produced
The RRA also allows mineral interest owners the opportunity to apply for
royalty relief for new production on leases acquired before the RRA was enacted.
If the United States Minerals Management Service determines that new production
would not be economical without royalty relief, then a portion of the royalty
may be relieved to make the project economical. Also, for certain leases,
royalty relief is suspended in years in which average commodity index prices
exceed inflation adjusted thresholds established in the RRA.
The impact of royalty relief is significant, as normal royalties for leases
in water depths of 400 meters or less is 16.7% and normal royalties for leases
in water depths greater than 400 meters is 12.5%. Royalty relief can
substantially improve the economics of projects in deep water. We have acquired
50 new deepwater leases that are eligible for royalty relief and have received
royalty relief on the Pluto leases. Due to high natural gas commodity prices in
2000, it is possible that royalty relief may not apply to natural gas production
from Pluto in 2000.
Regulation
Our operations are subject to extensive and continually changing
regulation, as legislation affecting the oil and natural gas industry is under
constant review for amendment and expansion. Many departments and agencies, both
federal and state, are authorized by statute to issue and have issued rules and
regulations binding on the oil and natural gas industry and its individual
participants. The failure to comply with these rules and regulations can result
in substantial penalties, as a number of the statutes applicable to our
operations authorize penalties of more than $20,000 for a violation of the
statute and allow each day of a continuing violation to be considered a separate
violation. The regulatory burden on the oil and natural gas industry increases
our cost of doing business and, consequently, affects our profitability.
However, our competitors in the oil and natural gas industry are subject to the
same regulatory requirements and restrictions that affect our operations.
42
<PAGE>
45
Transportation and Sale of Natural Gas
The Federal Energy Regulatory Commission ("FERC") regulates interstate
natural gas pipeline transportation rates and service conditions, both of which
affect the marketing of natural gas we produce, as well as the revenues received
for sales of such natural gas. Since the latter part of 1985, culminating in the
Order No. 636 series of orders, the FERC has endeavored to make natural gas
transportation more accessible to natural gas buyers and sellers on an open and
non-discriminatory basis. The FERC believes open access policies are necessary
to improve the competitive structure of the interstate natural gas pipeline
industry and to create a regulatory framework that will put natural gas sellers
into more direct contractual relations with natural gas buyers. As a result of
the Order No. 636 program, the marketing and pricing of natural gas has been
significantly altered. The interstate pipelines' traditional role as wholesalers
of natural gas has been terminated and replaced by regulations which require
pipelines to provide transportation and storage service to others who buy and
sell natural gas. Although the FERC's orders do not directly regulate natural
gas producers, they are intended to foster increased competition within all
phases of the natural gas industry.
Some aspects of the Order No. 636 program are still being reviewed by the
courts and the FERC. In addition, on July 29, 1998, the FERC issued a Notice of
Proposed Rulemaking in Docket No. RM98-10 proposing yet another round of
revisions to its regulations governing the market for short-term transportation
services on regulated natural gas pipelines. If adopted, these new regulations
will create even greater competition among short-term service offerings and
will, among other things, require all available short-term capacity to be
subject to capacity auctions. The FERC also issued a Notice of Inquiry on July
29, 1998 in Docket No. RM98-12 requesting comments on its pricing policies in
the existing long-term transportation services market and the market for new
capacity. While the Notice of Inquiry does not propose any specific changes to
existing regulations, the FERC seeks comments on whether fundamental aspects of
its pricing for long-term service and new capacity should be modified to be more
effective in the current, more competitive environment.
It is unclear what impact, if any, increased competition within the natural
gas transportation industry will have on us and our natural gas sales efforts.
It is not possible to predict what, if any, effect the FERC's open access
policies or the proceedings in Docket Nos. RM98-10 and RM98-12 will have on us.
Additional proposals or proceedings that might affect the natural gas industry
may be considered by the FERC, Congress or state regulatory bodies. It is not
possible to predict when or if any of these proposals may become effective or
what effect, if any, they may have on our operations. We do not believe,
however, that our operations will be affected any differently than those of
other natural gas producers or marketers with which we compete.
Regulation of Production
The production of oil and natural gas is subject to regulation under a wide
range of state and federal statutes, rules, orders and regulations. State and
federal statutes and regulations require permits for drilling operations,
drilling bonds and reports concerning operations. Most states in which we own
and operate properties have regulations governing conservation matters,
including provisions for the unitization or pooling of oil and natural gas
properties, the establishment of maximum rates of production from oil and
natural gas wells and the regulation of the spacing, plugging and abandonment of
wells. Many states also restrict production to the market demand for oil and
natural gas and several states have indicated interest in revising applicable
regulations. The effect of these regulations is to limit the amount of oil and
natural gas we can produce from our wells and to limit the number of wells or
the locations at which we can drill. Moreover, each state generally imposes a
production or severance tax with respect to production and sale of crude oil,
natural gas and gas liquids within its jurisdiction.
Most of our offshore operations are conducted on federal leases that are
administered by the United States Minerals Management Service (the "MMS") and
are required to comply with the regulations and orders promulgated by MMS. Among
other things, we are required to obtain prior MMS approval for our exploration
plans and our development and production plans for these leases. The MMS
regulations also establish construction requirements for production facilities
located on our federal offshore leases and govern the plugging and abandonment
of wells and the removal of production facilities from these leases. Under
certain circumstances, the MMS could require us to suspend or terminate our
operations on a federal lease.
In addition, a portion of our Sandy Lake Properties are located within the
boundaries of the Big Thicket National Preserve (the "BTNP"), which is under the
jurisdiction of the United States National Park Service (the "NPS"). Our
operations within the BTNP must comply with regulations of the NPS. In general,
these regulations require us to obtain NPS approval of a plan of operations for
any activity within the BTNP or to demonstrate that a waiver of a plan of
operations is appropriate. Compliance with these regulations increases our cost
of operations and may delay the commencement of specific operations.
43
<PAGE>
46
Environmental Regulations
General. Various federal, state and local laws and regulations governing
the discharge of materials into the environment, or otherwise relating to the
protection of the environment, affect our operations and costs. In particular,
our exploration, development and production operations, our activities in
connection with storage and transportation of crude oil and other liquid
hydrocarbons and our use of facilities for treating, processing or otherwise
handling hydrocarbons and related wastes are subject to stringent environmental
regulation. As with the industry generally, compliance with existing regulations
increases our overall cost of business. The areas affected include:
o unit production expenses primarily related to the control and limitation of
air emissions and the disposal of produced water;
o capital costs to drill exploration and development wells resulting from
expenses primarily related to the management and disposal of drilling
fluids and other oil and gas exploration wastes; and
o capital costs to construct, maintain and upgrade equipment and facilities.
Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as "Superfund," imposes liability, without
regard to fault or the legality of the original act, on some classes of persons
that contributed to the release of a "hazardous substance" into the environment.
These persons include the "owner" or "operator" of the site and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. CERCLA also authorizes the Environmental Protection Agency and, in some
instances, third parties to act in response to threats to the public health or
the environment and to seek to recover from the responsible classes of persons
the costs they incur. In the course of our ordinary operations, we may generate
waste that may fall within CERCLA's definition of a "hazardous substance." We
may be jointly and severally liable under CERCLA or comparable state statutes
for all or part of the costs required to clean up sites at which these wastes
have been disposed.
We currently own or lease, and have in the past owned or leased, numerous
properties that for many years have been used for the exploration and production
of oil and gas. Although we have used operating and disposal practices that were
standard in the industry at the time, hydrocarbons or other wastes may have been
disposed of or released on or under the properties owned or leased by us or on
or under other locations where these wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
actions with respect to the treatment and disposal or release of hydrocarbons or
other wastes were not under our control. These properties and wastes disposed on
these properties may be subject to CERCLA and analogous state laws. Under these
laws, we could be required:
o to remove or remediate previously disposed wastes, including wastes
disposed of or released by prior owners or operators;
o to clean-up contaminated property, including contaminated groundwater; or
o to perform remedial plugging operations to prevent future contamination.
Oil Pollution Act of 1990. The Oil Pollution Act of 1990 (the "OPA") and
regulations thereunder impose liability on "responsible parties" for damages
resulting from crude oil spills into or upon navigable waters, adjoining
shorelines or in the exclusive economic zone of the United States. Liability
under the OPA is strict, joint and several, and potentially unlimited. A
"responsible party" includes the owner or operator of an onshore facility and
the lessee or permittee of the area in which an offshore facility is located.
The OPA also requires the lessee or permittee of the offshore area in which a
covered offshore facility is located to establish and maintain evidence of
financial responsibility in the amount of $35 million ($10 million if the
offshore facility is located landward of the seaward boundary of a state) to
cover liabilities related to a crude oil spill for which such person is
statutorily responsible. The amount of required financial responsibility may be
increased above the minimum amounts to an amount not exceeding $150 million
depending on the risk represented by the quantity or quality of crude oil that
is handled by the facility. The MMS has promulgated regulations that implement
the financial responsibility requirements of the OPA. A failure to comply with
the OPA's requirements or inadequate cooperation during a spill response action
may subject a responsible party to civil or criminal enforcement actions. We are
not aware of any action or event that would subject us to liability under the
OPA and we believe that compliance with the OPA's financial responsibility and
other operating requirements will not have a material adverse effect on us.
44
<PAGE>
47
Clean Water Act. The Federal Water Pollution Control Act of 1972, as
amended (the "Clean Water Act"), imposes restrictions and controls on the
discharge of produced waters and other oil and gas wastes into navigable waters.
These controls have become more stringent over the years, and it is possible
that additional restrictions will be imposed in the future. Permits must be
obtained to discharge pollutants into state and federal waters. Certain state
regulations and the general permits issued under the Federal National Pollutant
Discharge Elimination System program prohibit the discharge of produced waters
and sand, drilling fluids, drill cuttings and certain other substances related
to the oil and gas industry into certain coastal and offshore water. The Clean
Water Act provides for civil, criminal and administrative penalties for
unauthorized discharges for oil and other hazardous substances and imposes
liability on parties responsible for those discharges for the costs of cleaning
up any environmental damage caused by the release and for natural resource
damages resulting from the release. Comparable state statutes impose liabilities
and authorize penalties in the case of an unauthorized discharge of petroleum or
its derivatives, or other hazardous substances, into state waters. We believe
that our operations comply in all material respects with the requirements of the
Clean Water Act and state statutes enacted to control water pollution.
Resources Conservation Recovery Act. The Resource Conservation Recovery Act
("RCRA") is the principle federal statute governing the treatment, storage and
disposal of hazardous wastes. RCRA imposes stringent operating requirements, and
liability for failure to meet such requirements, on a person who is either a
"generator" or "transporter" of hazardous waste or an "owner" or "operator" of a
hazardous waste treatment, storage or disposal facility. At present, RCRA
includes a statutory exemption that allows most crude oil and natural gas
exploration and production waste to be classified as nonhazardous waste. A
similar exemption is contained in many of the state counterparts to RCRA. As a
result, we are not required to comply with a substantial portion of RCRA's
requirements because our operations generate minimal quantities of hazardous
wastes. At various times in the past, proposals have been made to amend RCRA to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste. Repeal or modification of
the exemption by administrative, legislative or judicial process, or
modification of similar exemptions in applicable state statutes, would increase
the volume of hazardous waste we are required to manage and dispose of and would
cause us to incur increased operating expenses.
Employees
As of June 30, 2000, we had approximately 70 full-time employees. Our
employees are not represented by any labor union. We consider relations with our
employees to be good. We have never experienced a work stoppage or strike.
Legal Proceedings
In the ordinary course of business, we are a claimant or a defendant in
various other legal proceedings, including proceedings as to which we have
insurance coverage. We do not consider our exposure in these proceedings,
individually or in the aggregate, to be material.
In December 1996, ETOCO, Inc., which owns a 20% interest in one producing
well operated by the Company, filed a lawsuit against the Company in the
district court of Hardin County, Texas, alleging damage due to the Company's
refusal to drill an additional well. In April 1998, after a trial on the merits,
a jury awarded ETOCO $2.38 million in damages. In August 1998, the court awarded
ETOCO $0.5 million in attorney's fees. On February 8, 1999, the case was
settled.
45
<PAGE>
48
MARINER HISTORY AND ORGANIZATION
The issuer in this offering is Mariner Energy LLC, a Delaware limited
liability company. Mariner Energy LLC owns all of the common stock of Mariner
Holdings, Inc., a Delaware corporation. Mariner Holdings, Inc. owns all of the
common stock of Mariner Energy, Inc., a Delaware corporation and currently our
only operating company.
Mariner Energy, Inc. was formed in 1983 as Trafalgar Oil & Gas Co. and
later changed its name to Hardy Oil & Gas USA, Inc. Before April 1996, Hardy Oil
& Gas USA, Inc. was an indirect, wholly owned subsidiary of Hardy Oil & Gas plc.
In April 1996, Enron, Joint Energy and members of Hardy Oil & Gas USA, Inc.'s
management created Mariner Holdings, Inc., for the purpose of acquiring Hardy
Oil & Gas USA, Inc. The acquisition was completed in May 1996. We refer to this
transaction as our "acquisition."
In connection with our acquisition:
o Joint Energy acquired approximately 96% of the equity interests of Mariner
Holdings, Inc.; and
o management members and employees purchased the remaining 4% for cash and
other value.
In September 1998, we formed Mariner Energy LLC, which became the parent
company of Mariner Holdings, Inc. We effected this reorganization so that we
could clarify, through our limited liability company agreement, the fiduciary
duties of our principal shareholder and its affiliates.
46
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49
MANAGEMENT
Directors and Executive Officers
Shown below are the names, ages and positions of our executive officers and
directors and a key consultant as of June 30, 2000. All directors are elected
for a term of one year and serve until their successors are elected and
qualified. All executive officers hold office until their successors are elected
and qualified.
Name Age Position
Chairman of the Board, President and Chief
Robert E. Henderson..... 47 Executive Officer
Richard R. Clark........ 44 Executive Vice President and Director
L. V. "Bud" McGuire..... 57 Senior Vice President-- Operations and Director
Senior Vice President-- Exploration and Land and
Michael W. Strickler.... 44 Director
Vice President-- Finance, Chief Financial Officer
Frank A. Pici........... 44 and Treasurer
Gregory K. Harless...... 50 Vice President-- Oil and Gas Marketing
W. Hunt Hodge........... 44 Vice President-- Administration
Thomas E. Young......... 41 Vice President-- Land
Kelly D. Zelikovitz..... 41 General Counsel and Secretary
David S. Huber.......... 49 Consultant and Director of Deepwater Developments
Raymond M. Bowen........ 44 Director
Richard B. Buy.......... 47 Director
Jeffrey M. Donahue, Jr.. 38 Director
D. Brad Dunn............ 36 Director
Mark E. Haedicke........ 44 Director
Jesus G. Melendrez...... 41 Director
Jere C. Overdyke, Jr.... 47 Director
Jeffrey B. Sherrick..... 45 Director
Mr. Henderson has been our President and Chief Executive Officer since
1987, our Chairman of the Board of Directors since May 1996, and a director
since 1985. Mr. Henderson served as a director of London-based Hardy plc, our
former parent company, between 1989 and 1996. From 1984 to 1987, he served us or
our predecessors as Vice President of Finance and Chief Financial Officer. From
1976 to 1984, he held various positions with ENSTAR Corporation, including
treasurer of ENSTAR Petroleum, which operated in the United States and
Indonesia.
Mr. Clark has been our Executive Vice President since May 1998. He served
as Senior Vice President of Production from 1991 to 1998, and has been a
director since 1988. Before joining us in 1984, he worked for Shell Oil Company
in their offshore division.
Mr. McGuire has been our Senior Vice President -- Operations since joining
us in June 1998. He has been a director since June 1999. Before joining us, Mr.
McGuire was Vice President -- Operations for Enron Oil & Gas International, Inc.
Before joining Enron, he served five years with Kerr-McGee Corporation, an
energy and chemical company, as Senior Vice President overseeing worldwide
production operations. His experience before Kerr-McGee included employment with
Hamilton Oil Corporation from 1981 to 1991, where he served as Vice President of
Production for Hamilton in the North Sea. He began his career in 1966 with
Conoco Inc.
Mr. Strickler has been our Senior Vice President -- Exploration and Land
since 1991 and a director since 1989. Before joining us in 1984, Mr. Strickler
worked for several independent oil companies as an exploration geologist
generating and evaluating exploration plays in various domestic and overseas
basins.
Mr. Pici has been our Vice President -- Finance and Chief Financial Officer
since joining us in December 1996. From 1989 to 1996, Mr. Pici was employed by
Cabot Oil & Gas Corporation, holding several financial management positions
including Corporate Controller. Before joining Cabot Oil & Gas, an exploration
and production company, he was controller of an independent oil and gas company.
Mr. Pici began his career at Coopers & Lybrand LLP, an accounting firm, and is a
certified public accountant.
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50
Mr. Harless has been our Vice President -- Oil and Gas Marketing since
1990. His experience before joining us in 1988 included Vice President of
marketing and regulatory affairs of Enron Oil and Gas Company and District
Operations Manager with Coastal States Oil & Gas Co.
Mr. Hodge has been our Vice President-- Administration since 1991. Before
joining us in 1985, he was Purchasing Manager of Santa Fe Minerals Company.
Mr. Young has been our Vice President -- Land since November 1998. Before
November 1998, he was our Manager of International Negotiations since December
1997. Before December 1997, he was our Land Manager-Central Gulf. Before joining
us in 1985, Mr. Young served as a landman for TXO Production Corp.
Ms. Zelikovitz has been our General Counsel and Secretary since August
2000. She is in private practice and has a contractual relationship with us.
Prior to May 1998, she held various legal and management positions with Mobil
Oil Corporation, Greenhill Petroleum Corporation, Union Texas Petroleum
Corporation, and with a Houston-based law firm.
Mr. Huber began his association with us in 1991 as a deepwater project
management consultant. Before joining us, Mr. Huber was employed by Hamilton Oil
Corporation in the North Sea from 1981 to 1991, holding positions of Production
Manager, Planning and Economics Manager and Engineering Manager. He was the
Deepwater Drilling Engineering Supervisor for Esso Exploration, Inc. from 1974
to 1980.
Mr. Bowen has served as a director since January 2000. He is currently
Managing Director of ENA and Co-Head of the Commercial Transactions Group and
has held various management positions with ENA since 1996. Prior to joining ENA,
Mr. Bowen was a Vice President and Senior Banker in Citicorp's Petroleum, Metals
and Mining Department in Houston.
Mr. Buy has served as a director since January 1998. Since 1994 he has been
an employee of ENA or its affiliates, currently serving as Senior Vice President
and Chief Risk Officer of Enron Corp. Prior to joining ENA Mr. Buy was a Vice
President at Bankers Trust in the Energy Group.
Mr. Donahue has served as a director since August 2000. He joined Enron in
April 1998 as Vice President responsible for Corporate Development for Enron
North America. Prior to joining Enron, Mr. Donahue was an investment banker
focusing on the energy industry at UBS Securities, CS First Boston and Kidder
Peabody. He was also a management consultant with McKinsey & Company and an
economic policy consultant at ICF Incorporated.
Mr. Dunn has served as a director since May 1999. He is a Vice President of
ENA and has held various positions with ENA since September 1994. Before 1994,
Mr. Dunn worked as a Petroleum Engineer with Delhi Gas Pipeline Corporation and
Mobil Oil Corporation.
Mr. Haedicke has served as a director since October 1998. He is currently
Managing Director, Legal, of ENA. Mr. Haedicke also serves on the board of
directors of the International Swaps and Derivatives Association, Inc. and he
holds a seat on the New York Mercantile Exchange. He has been associated with
ENA since its inception in 1990.
Mr. Melendrez is a Vice President of ENA and is responsible for the
execution and structuring of upstream transactions. Prior to joining ENA in
1999, Mr. Melendrez was Sr. Vice President of Enserch Energy Services, Inc. He
has held financial positions with several Enron affiliates since the early
1990's which involved loan restructuring and power marketing.
Mr. Overdyke has served as a director since May 1996. Since 1991 he has
been an employee of ENA or one of its affiliates, currently serving as a
Managing Director of ENA. Mr. Overdyke has over 20 years of experience in the
energy sector and has held various financial and management positions with
public and private independent exploration and production companies.
Mr. Sherrick has served as a director since January 2000. He is currently
the President and Chief Executive Officer of Enron Global Exploration &
Production Inc. and has held various management positions with Enron Oil & Gas
Company, or one of its affiliates, since 1993.
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51
We anticipate that two additional directors will be elected before the
closing of the offering.
Committees of the Board of Directors
Our board of directors has established three standing committees: an audit
committee, a compensation committee and an executive committee. The audit
committee is charged with recommending to our board of directors the appointment
of our independent auditors, reviewing the compensation of our auditors and
reviewing with our accountants the plans for and the results of their auditing
engagement. The compensation committee reviews the performance and compensation
of directors, executive officers and key employees and makes recommendations to
the board of directors regarding those matters. It also administers any
long-term incentive compensation and share option plans.
Summary Compensation Table
The following table shows the annual compensation for our chief executive
officer and the four other most highly compensated executive officers for the
three fiscal years ended December 31, 1999. These individuals are sometimes
referred to as the "named executive officers."
<TABLE>
<CAPTION>
Current Year
Annual Compensation Compensation
------------------------------- Under our
Other Annual Overriding
Royalty All Other
Name and Principal Position Salary Compensation(1) Program(2) Compensation(3)
------------- --------------- ----------------- ---------------
<S> <C> <C> <C> <C> <C>
Robert E. Henderson 1999 $285,000 $6,400 $5,438 $396
President and 1998 285,000 4,800 1,292 522
Chief Executive Officer 1997 255,000 6,000 1,904 315
Richard R. Clark 1999 225,000 6,400 3,508 243
Executive Vice President 1998 225,000 4,800 821 306
of Production 1997 185,000 6,000 1,205 306
L. V. "Bud" McGuire (4) 1999 190,000 4,433 0 44,573
Senior Vice President 1998 110,834 0 0 788
of Operations 1997 0 0 0 0
Michael W. Strickler 1999 190,000 6,400 3,508 243
Senior Vice President 1998 182,000 4,800 821 306
of Exploration 1997 165,000 6,000 1,205 306
Frank A. Pici 1999 160,000 6,400 2,043 243
Vice President of Finance and 1998 160,000 4,380 356 306
Chief Financial Officer 1997 146,000 2,747 152 306
</TABLE>
(1) Amounts shown reflect our contribution under the discretionary profit
sharing feature of its Employee Capital Accumulation Plan. See "--401(k) Plan".
For each of the named executive officers, the aggregate amount of perquisites
and other personal benefits did not exceed the lesser of $50,000 or 10% of the
officer's total annual salary and bonus and information with respect thereto is
not included.
(2) These amounts include the value conveyed but not the cash paid during
the applicable year attributable to overriding royalty interests assigned to the
named executive officer during the applicable year and distributions received,
if any, during the applicable year attributable to overriding royalty interests
assigned to the named executive officers during the applicable year. For
information on overriding royalty payments received during the applicable year
attributable to overriding royalty interests assigned to the named executive
officer during past years, see the table below under "--Overriding Royalty
Program." These amounts also do not include amounts received during the
applicable year as a result of sales of overriding royalty interests by
individuals, normally in connection with sales of properties by us. No such
sales were made in 1999, 1998 or 1997.
(3) Amounts shown reflect insurance premiums paid by us with respect to
term life insurance for the benefit of the named executive officers and any
performance bonuses paid during the year.
(4) Mr. McGuire joined us in June 1998 and is eligible for guideline
bonuses and incentive stock option awards under our incentive compensation plan.
He does not participate in the Overriding Royalty Program.
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52
Number of
Common Shares Underlying Value of Unexercised
Unexercised Options at in-the-money Options at
December 31, 1999 December 31, 1999(1)
Exercisable Unexercisable Exercisable Unexercisable
Robert E. Henderson.... 143,172 95,448
Richard R. Clark....... 100,757 67,171
L.V. "Bud" McGuire..... 36,480 121,584
Michael W. Strickler... 100,757 67,171
Frank A. Pici.......... 29,232 43,848
----------
(1) Assumes a market value equal to $_____ per share, the mid point of the
range shown on the cover of this prospectus.
1996 Share Option Plan
Under the Mariner Energy LLC 1996 Share Option Plan, a committee of our
board of directors is authorized to grant options to purchase common shares,
including options qualifying as "incentive stock options" under Section 422 of
the Internal Revenue Code and options that do not so qualify, to employees and
consultants as additional compensation for their services to us. The 1996 plan
is intended to promote our long term financial interests by providing a means by
which designated employees and consultants may develop a sense of proprietorship
and personal involvement in our development and financial success. We believe
that this encourages them to remain with and devote their best efforts to our
business and to advance the mutual interests of us and our shareholders. A total
of 2,433,600 common shares may be issued under options granted under the 1996
plan, subject to adjustment for any share split, share dividend or other change
in the common shares or our capital structure. Options to purchase 2,185,740
common shares are outstanding under the 1996 _____ plan, of which are currently
exercisable and _____ of which will be exercisable on the successful completion
of this offering. The exercise price for outstanding options to purchase an
aggregate of _____ shares under the 1996 plan is $8.33 per share, and the
exercise price for options to purchase the remaining outstanding aggregate of
_____ shares under the 1996 plan is $14.58 per share. Subject to the provisions
of the 1996 plan, the compensation committee is authorized to determine who may
participate in the 1996 plan, the number of shares that may be issued under each
option granted under the 1996 plan, and the terms, conditions and limitations
applicable to each grant. Subject to some limitations, our board of directors is
authorized to amend, alter or terminate the 1996 plan. If the offering is
completed, no further options will be granted under the 1996 plan.
Employment Agreements
We and each of the named executive officers are parties to employment
agreements with an initial term that expires on September 30, 2002, except that
the employment agreements extend for six months unless notice of termination is
given by either us or the named executive officer at least six months before the
end of the initial term or extended term, as applicable.
Under the employment agreements, the current annual salaries are $295,000
for Mr. Henderson, $235,000 for Mr. Clark, $198,000 for Mr. Strickler, $198,000
for Mr. McGuire and $167,000 for Mr. Pici. Our board of directors may in its
discretion increase their salaries.
The named executive officers are entitled to participate in any medical,
dental, life and accidental death and dismemberment insurance programs and
retirement, pension, deferred compensation and other benefit programs instituted
by us from time to time. The employees are also entitled to vacation,
reimbursement of specified expenses and an automobile allowance and
reimbursement for expenses related to the use of that vehicle. As incentive
compensation, the named executive officers, except for Mr. McGuire, are entitled
to receive overriding royalty interests in some oil and gas prospects that we
have acquired under our overriding royalty program. Mr. McGuire is entitled to
receive annual cash bonuses and stock option awards under an incentive
compensation plan separate from other named executive officers.
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53
If we terminate a named executive officer's employment agreement without
cause, if the named executive officer terminates his employment agreement for
good reason, or if we give notice of termination on the expiration of the
initial term or any extended term of his employment, then the named executive
officer will be entitled to, among other things:
o the value of his salary and other benefits through the end of the initial
term or any extended term of the employment agreement;
o a lump sum cash payment equal to 12 months salary in the case of Mr.
Henderson, nine months salary in the case of Messrs. Clark, Strickler and
McGuire and six months salary in the case of Mr. Pici plus, in the case of
Mr. McGuire, an amount equal to 40% of nine months salary;
o a lump sum cash payment equal to all earned and unused vacation time for
the previous year and the then current year;
o except in the case of Mr. McGuire who does not participate in the
overriding royalty program, an assignment of his vested interests under our
overriding royalty program; and
o in the case of Mr. McGuire, a lump sum payment equal to any unpaid bonus
from prior years under our incentive compensation plan, plus, in lieu of
any bonus for subsequent years, an amount equal to 40% of his base salary
through the end of the remaining term of his employment agreement.
If a named executive officer's employment agreement is terminated by the
named executive officer without good reason, the named executive officer gives
notice of termination on the expiration of his term of employment or if we
consent to a request by the named executive officer to terminate his employment
agreement before the expiration of his term, he will be entitled to:
o the value of his salary and benefits through the date that his employment
agreement is terminated;
o a lump sum cash payment equal to all earned and unused vacation time for
the previous year and the then current year;
o except in the case of Mr. McGuire who does not participate in the
overriding royalty program, an assignment of his vested interests in our
overriding royalty program through the date of termination; and
o in the case of Mr. McGuire, a lump sum payment equal to any unpaid bonus
from prior years under our incentive compensation plan, plus, in lieu of
any bonus for subsequent years, an amount equal to 40% of his base salary
through the end of the remaining term of his employment agreement.
If a named executive officer's employment agreement is terminated by us for
cause, we will have no obligation to that employee other than to:
o pay his salary through the day of termination;
o pay him the value of his benefits under the employment agreement through
the month of termination; and
o except in the case of Mr. McGuire who does not participate in the
overriding royalty program, assign to him his vested interests in our
overriding royalty program through the date of termination.
To the extent any amounts paid under an employment agreement are subject to
the "golden parachutes" excise tax, those amounts are grossed-up to cover the
excise tax and any applicable taxes on the gross-up amount.
Each named executive officer has agreed that during the term of his
employment agreement, and, if the named executive officer's employment agreement
is terminated by us for cause or terminated before the end of the initial term
or any extended term by the named executive officer other than for good reason,
for 12 months after the term expires in the case of Messrs. Henderson, Clark,
Strickler and McGuire and six months after the term expires in the case of Mr.
Pici, he will not compete with us for business or hire away our employees.
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54
For purposes of the employment agreements with the named executive
officers, "good reason" means:
o The assignment to the employee of any duties materially inconsistent with
the employee's position, authority, duties or responsibilities with us or
any other action that results in a material diminution in, or interference
with, such position, authority, duties or responsibilities, if the
assignment or action is not cured within 30 days after the employee has
provided us with written notice;
o The failure to continue to provide the employee with office space, related
facilities and support personnel (a) that are commensurate with the
employee's responsibilities to, and position with, us and not materially
dissimilar to the office space, related facilities and support personnel
provided to our other employees having comparable responsibilities or (b)
that are physically located at our principal executive offices, if that
failure is not cured within 30 days after the employee has provided us with
written notice;
o Any (a) reduction in the employee's monthly salary, (b) reduction in,
discontinuance of, or failure to allow or continue to allow the employee's
participation in, our incentive compensation program, or (c) reduction in,
or failure to allow or continue the employee's participation in, any
employee benefit plan in which the employee is participating or is eligible
to participate before the reduction or failure, and that reduction,
discontinuance or failure is not cured within 30 days after the employee
has provided us with written notice;
o The relocation of the employee's or our principal office and principal
place of the employee's performance of his duties and responsibilities to a
location more than 50 miles outside of the central business district of
Houston, Texas; or
o A breach of any material provision of the employment agreement that is not
cured within 30 days after the employee has provided us with written
notice.
Change in Control Agreements
We and each of the named executive officers are parties to change in
control agreements. These agreements will no longer be effective upon the
successful completion of this offering unless a change in control occurs under
certain conditions before such completion. Under these agreements, if a change
in control occurs under certain conditions before the successful completion of
this offering and the named executive officer's employment is terminated by us
other than for cause of his death or disability or by the named executive
officer for good reason within 18 months of the change in control, he is
entitled to receive a cash payment equal to three and one-half times the sum of
(a) the higher of his annual base salary on the date of termination or on the
date the change in control occurs, plus (b) in the case of Mr. McGuire, the
bonus award for achieving the target performance goals provided in the incentive
bonus program in which he was a participant on the date the change in control
occurs, but only if he was a participant when the target performance goals were
established for the year in which the change in control occurs. The named
executive officer would also, at our election either (x) be entitled to receive
from us a cash payment equal to two times the annual value of the cost of
welfare benefits available in the market and similar to those in which he was a
participant on the date of his termination, or (y) continue to be provided
welfare benefits for two years under our plans. The ultimate payment due under a
change in control agreement will be the greater of the payment calculated under
the change in control agreement or the compensation due for the remaining
balance under the employment agreements. To the extent any amounts paid under
the change in control agreements are subject to the "golden parachute" excise
tax, those amounts are grossed up to cover the excise tax and any applicable
taxes on the gross-up amount.
Overriding Royalty Program
Effective with the date of the successful completion of this offering, the
overriding royalty program will be terminated. As a result of that termination,
no new overriding royalty interests will be awarded on prospects that were not
designated as such under the program before that date. However, overriding
royalty interests will continue to be awarded with respect to prospects
designated as such before that date under the terms of the terminated overriding
royalty program, and we will continue to pay overriding royalties with respect
to those interests and overriding royalty interests assigned to employees before
that date.
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55
Employees participating in our overriding royalty program receive incentive
compensation in the form of overriding royalty interests in some of the oil and
natural gas prospects we designated under the program before the date of the
successful completion of this offering. The aggregate overriding royalty
interests do not exceed 1.5% of our working interest in these prospects before
well payout or 6% of our working interest in these prospects after payout. An
employee receives overriding royalty interests equal to specified undivided
percentages of our working interest percentage in prospects within the United
States and U.S. coastal waters that are designated as prospects under the
program during the term of the employee's employment.
The overriding royalty interest percentage of our working interest to which
each named executive officer is entitled for the period before well payout is
one-fourth of the overriding royalty interest percentage for the period after
well payout. These percentages currently range from 0.09375% to 0.23250% before
payout and from 0.37500% to 0.93000% after payout for the named executive
officers.
If all or a portion of our working interest in a prospect is sold or farmed
out to unaffiliated third parties and we determine in good faith that our
interest will not be marketable on satisfactory terms if marketed subject to the
named executive officer's overriding royalty interest affecting the prospect, we
may adjust the named executive officer's overriding royalty interest in the
prospect. These adjustments are determined by a committee designated by our
board of directors, at least half of the members of which are individuals who
have been granted an overriding royalty interest by us. Some committee decisions
require the approval of our board of directors. These adjustments apply only to
the portion of our working interest sold or farmed out to a third party and do
not affect the named executive officer's overriding royalty interest in the
portion of a prospect retained by us.
We may also elect, within 60 days after the end of our fiscal year, to
reduce a named executive officer's overriding royalty interest in prospects that
we acquired during the fiscal year. We must base these reductions on the levels
of exploration and development costs related to these prospects actually
incurred during the fiscal year. With respect to certain deepwater prospects, we
also may elect, in our sole discretion, to make other reductions and adjustments
to the employee's overriding royalty interest based on estimated exploration
levels and development costs to be incurred in connection with these deepwater
prospects. We retain a right of first refusal to purchase any overriding royalty
interest assigned to a named executive officer. This right applies to any
third-party offer received by the named executive officer during or within one
year after the named executive officer's employment is terminated.
The following table shows distributions received during the applicable year
by the named executive officers, some of which were paid by third parties, from
overriding royalty interests we granted to the officers during the last 15
years.
Aggregate Cash Amounts Received
from Previously Assigned Overriding
Royalty Interests(1)
-------------------------------------------
Name 1999 1998 1997
---------------------------- ---- ---- ----
Robert E. Henderson......... $227,054 $354,857 $ 394,136
Richard R. Clark............ 137,774 218,077 237,982
Michael W. Strickler........ 131,103 212,803 234,603
Frank A. Pici............... 1,093 0 0
----------
(1) For information on the value conveyed and distributions received, if any,
during the applicable year attributable to overriding royalty interests
assigned to the named executive officer during the applicable year, see the
table under " -- Summary Compensation Table."
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56
New Compensation Arrangements and Change in Control Agreements Upon Completion
of the Offering
Upon the successful completion of the offering, our overriding royalty
program will be terminated as to prospects acquired by us that were not
designated as such under the program before _____. See -- "Overriding Royalty
Program." As a result of this termination, the five named executive officers
will receive awards under our existing incentive compensation program and
options under a new stock option plan -- the Mariner Energy LLC _____ Share
Option Plan -- to be adopted effective with the completion of this offering. We
and the named executive officers will also enter into new change in control
agreements upon the successful completion of the offering.
Under the incentive compensation plan, each participant is eligible to
receive a bonus based on a comparison of our performance and predetermined
targets adopted by our board of directors based on various economic factors. If
we meet our targets, 75% of the incentive payment is guaranteed. The remaining
25% is subject to an evaluation of the participant's performance. This
evaluation is administered by our compensation committee in the case of all
participants. Upon completion of the offering, the five named executive officers
will have received incentive payment percentages as follows:
Percent of Base Salary
at Percent of Base Salary at
Named Executive Officer 100% of Target 120% of Target
------------------------- ---------------- -----------------
Robert H. Henderson...... 60% 120%
Richard R. Clark......... 45% 90%
Michael W. Strickler..... 35% 75%
L.V. "Bud" McGuire....... 35% 75%
Frank A. Pici............ 30% 60%
Under the Mariner Energy LLC _____ Share Option Plan, the compensation
committee will be authorized to grant options to purchase common shares,
including options qualifying as "incentive stock options" under Section 422 of
the Internal Revenue Code and options that do not so qualify, to employees and
consultants as additional compensation for their services to us. The _____ plan
is intended to promote our long term financial interests by providing a means by
which designated employees and consultants may develop a sense of proprietorship
and personal involvement in our development and financial success. We believe
that this will encourage them to remain with and devote their best efforts to
our business and to advance the mutual interests of us and our shareholders. A
total of _____ common shares may be issued under options granted under the _____
plan, subject to adjustment for any share split, share dividend or other change
in the common shares or our capital structure. On completion of the offering,
options to purchase _____ common shares will be outstanding under the _____
plan, none of which will be exercisable upon the completion of the offering. The
exercise price for outstanding options under the _____ plan will be the offering
price for common shares in the offering. Subject to the provisions of the _____
plan, the compensation committee will be authorized to determine who may
participate in the plan, the number of shares that may be issued under each
option granted under the _____ plan, and the terms, vesting schedules,
conditions and limitations applicable to each grant. Subject to some
limitations, our board of directors will be authorized to amend, alter or
terminate the _____ plan.
Upon completion of this offering, under the _____ plan, Mr. Henderson will
be awarded options to purchase _____ shares, Mr. Clark will be awarded options
to purchase _____ shares, Mr. Strickler will be awarded options to purchase
_____ shares, Mr. McGuire will be awarded options to purchase _____ shares, and
Mr. Pici will be awarded options to purchase _____ shares.
Under the new change in control agreements, if a change in control occurs
under certain conditions and the named executive officer's employment is
terminated by use other than for cause or his death or disability or by the
named executive officer for good reason within 18 months of the change in
control, he is entitled to receive a cash payment equal to three and one-half
times the sum of (a) the higher of his annual base salary on the date of
termination or on the date the change in control occurs, plus (b) the bonus
award for achieving the target performance goals provided in the incentive bonus
program in which he was a participant on the date the change in control occurs,
but only if he was a participant when the target performance goals were
established for the year in which the change in control occurs. The named
executive officer would also, at our election, either (x) be entitled to receive
from us a cash payment equal to two times the annual value of the cost of
welfare benefits available in the market and similar to those in which he was a
participant on the date of his termination, or (y) continue to be provided
welfare benefits for two years under our plans. The ultimate payment due under a
change in control agreement will be the greater of the payment calculated under
the change in control agreement or the compensation due for the remaining
balance under the employment agreement. To the extent any amounts paid under the
change in control agreements are subject to the "golden parachute" excise tax,
those amounts are grossed-up to cover the excise tax and any applicable taxes on
the gross-up amount.
Directors' Compensation
Following the offering, we expect that members of our board of directors
who are not employees of us, Enron or Enron's subsidiaries will be compensated
in an amount to be determined for any services provided in their capacities as
directors, in addition to the reimbursement of reasonable expenses incurred in
connection with attending meetings of the board of directors.
401(k) Plan
We have an employee capital accumulation plan that is intended to be a
Section 401(k) plan under the Internal Revenue Code. All of our employees,
including the named executive officers, are eligible to participate in this
plan. Employees may make contributions to the plan under a salary withholding
program. We may, in our discretion, make contributions to the plan on behalf of
the plan participants. Employee contributions and our contributions to the plan
are restricted in number and amount. Our aggregate contributions are not
significant.
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57
Compensation Committee Interlocks and Insider Participation
Until our acquisition from Hardy Oil & Gas, plc in April 1996, we were a
wholly owned subsidiary of Hardy, which, through its board of directors and
officers, set the compensation of our executive officers. As a director of Hardy
until our acquisition, Mr. Henderson participated in deliberations concerning
the compensation of our executive officers. After our acquisition, our board of
directors set the compensation of the executive officers, and Mr. Henderson
participated in deliberations on those matters. In January 1997, our board of
directors established a compensation committee, currently composed of Messrs.
Henderson, Melendrez and Dunn. Mr. Sherrick serves an advisor to the
compensation committee.
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58
PRINCIPAL AND SELLING SHAREHOLDERS
The selling shareholders, Joint Energy and Enron, are the only shareholders
that we know own more than 5% of our outstanding common shares. The following
table shows:
o the name and address of the selling shareholders; and
o the number of shares beneficially owned by the selling shareholders
and the percentage of outstanding common shares each owns, as of June
30, 2000, and as adjusted to reflect the offering.
In computing the number of shares a person beneficially owns, the person is
deemed to own common shares subject to options the person holds that were
exercisable as of June 30, 2000 or become exercisable within 60 days following
June 30, 2000. We had 33 record common shareholders and there were 13,928,304
common shares outstanding as of June 30, 2000.
<TABLE>
<CAPTION>
Shares Beneficially Shares Beneficially
Owned Owned
Before the Offering Shares To Be After the Offering
Name and Address Sold
of Beneficial Owner Number Percentage In the Offering Number Percentage
<S> <C> <C> <C>
Joint Energy Development
Investments Limited
Partnership(1)................. 13,334,184 95.7% %
1400 Smith Street
Houston, Texas 77002
Enron North America Corp......... 600,000(2) 0.2% %
1400 Smith Street
Houston, Texas 77002
</TABLE>
----------
(1) Joint Energy primarily invests in and manages natural gas and energy
related assets. Joint Energy's general partner is Enron Capital Management
Limited Partnership, a Delaware limited partnership, whose general partner
is Enron Capital Corp., a Delaware corporation and a wholly owned
subsidiary of Enron. The general partner of Joint Energy exercises shared
voting and investment power over these shares.
(2) Under the ENA term loan, Enron has the right to acquire 600,000 of our
common shares for $0.01 per share upon the exercise by Enron of a warrant.
Enron may be deemed to be the beneficial owner of the shares owned by Joint
Energy because of the relationships described in footnote 1, but Enron
disclaims such beneficial ownership. Enron is a wholly owned subsidiary of
Enron Corp., which may be deemed to be the beneficial owner of all shares
beneficially owned by Enron; Enron Corp. disclaims any beneficial ownership
of any shares beneficially owned by Joint Energy or Enron. The 600,000
common shares that may be acquired by Enron upon the exercise of the
warrant issued under the ENA term loan are deemed outstanding solely for
purposes of calculating Enron's percentage beneficial ownership.
The table appearing below shows information as of June 30, 2000, relating
to common shares beneficially owned by
o each of our directors;
o the named executive officers;
o a key consultant; and
o all directors and executive officers and this key consultant as a group.
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Amount and
Nature of
Directors, Key Consultant and Beneficial Percent
Named Executive Officers Ownership(1) of Class
---------------------------------------------- -------------- ----------
Robert E. Henderson........................... 323,460(2) 1.9%
Richard R. Clark.............................. 229,368(2) 1.3%
Michael W. Strickler.......................... 229,368(2) 1.3%
L. V. McGuire................................. 79,080(2) *
Frank A. Pici................................. 93,552(2) *
David S. Huber................................ 224,016(2) 1.3%
Raymond M. Bowen.............................. 0 0
Richard B. Buy................................ 0 0
Jeffrey M. Donahue, Jr........................ 0 0
D. Brad Dunn.................................. 0 0
Mark E. Haedicke.............................. 0 0
Jesus G. Melendrez............................ 0 0
Jere C. Overdyke, Jr.......................... 0 0
Jeffrey B. Sherrick........................... 0 0
All directors and executive officers
and key consultant as a group (18 persons).... 1,389,660 8.2%
----------
* Less than one percent.
(1) All shares are owned directly by the named person and the named person has
sole voting and investment power over the shares.
(2) Includes common shares subject to options that are currently exercisable or
will become exercisable on completion of the offering.
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Shareholders' Agreement and Related Matters
Mariner, Joint Energy, Enron and other shareholders are parties to a
shareholders' agreement. The shareholders' agreement was originally entered into
by us, Enron, and Messrs. Henderson, Clark, Strickler and Huber (the "Management
Shareholders") in contemplation of our acquisition from Hardy. The shareholders'
agreement will terminate on closing of the offering, except for provisions
relating to registration rights of the current shareholders and indemnities for
tax losses in favor of members of management. See "Description of Our Company
Agreement and Common Shares -- Registration Rights."
Also, in connection with the acquisition and pursuant to the requirements
of the shareholders' agreement, our predecessor and Joint Energy entered into a
credit, subordination and further assurances agreement dated May 16, 1996 under
which Joint Energy provided a loan commitment to us. We borrowed $92 million
under this Joint Energy bridge loan to partially fund the acquisition. We repaid
all amounts outstanding under the Joint Energy bridge loan, including
approximately $2.6 million in fees, in August 1996. There is no outstanding
balance under the Joint Energy bridge loan, and it has terminated according to
its terms. We believe that the Joint Energy bridge loan was entered into on
terms that are at least as favorable as those that we could have obtained from
unaffiliated parties.
In August 1996, our subsidiary issued the senior subordinated notes. An
affiliate of Enron was a placement agent in connection with that issuance, and
our subsidiary paid that affiliate approximately $2.9 million in fees in
connection with that issuance. We believe that the placement agent arrangements
made with Enron were entered into on terms that are at least as favorable as
those that we could have obtained from unaffiliated parties.
Under the shareholders' agreement, we paid or agreed to pay certain
amounts, including payment or reimbursement to Enron, Joint Energy and the
Management Shareholders for all reasonable fees and expenses of third parties
they incur in connection with the shareholders' agreement, the Joint Energy
bridge loan and the acquisition. Also, we agreed to reimburse each Management
Shareholder who paid for our equity by assigning overriding royalty interests
for any additional taxes and related costs the Management Shareholder incurs to
the extent, if any, that the transfer of the overriding royalty interests did
not qualify as a tax-free exchange under federal tax laws. This obligation will
survive the offering. We believe that these agreements made under the
shareholders' agreement were entered into on terms that are at least as
favorable as those that we could have obtained from unaffiliated parties.
Enron and Affiliates
Enron North American Corp., or Enron, is formerly known as Enron Capital &
Trade Resources Corp. Enron Corp. is the parent of Enron, and an affiliate of
Enron Corp. and Enron is the general partner of Joint Energy. Accordingly, Enron
may be deemed to control Joint Energy and us. See "Principal and Selling
Shareholders." Also, eight of our directors are officers of Enron or of
affiliates of Enron: Mr. Bowen is a Managing Director of Enron, Mr. Buy is a
Senior Vice President and the Chief Risk Officer of Enron Corp., Mr. Donahue is
a Vice President of Enron, Mr. Dunn is a Vice President of Enron, Mr. Haedicke
is a Managing Director, Legal of Enron, Mr. Melendrez is a Vice President of
Enron, Mr. Overdyke is a Managing Director of Enron and Mr. Sherrick is the
President and Chief Executive Officer of Enron Global Exploration & Production,
Inc.
Enron Corp. and certain of its subsidiaries and other affiliates
collectively participate in nearly all phases of the oil and natural gas
industry and, therefore, compete with us. Also, Enron Corp. affiliates may
provide or arrange for financing for our competitors. Because of these various
possible conflicting interests, our company agreement includes provisions
designed to clarify that generally Enron Corp. and its affiliates have no duty
to make business opportunities available to us and no duty to refrain from
conducting activities that may be competitive with us.
Under the terms of the company agreement, Enron Corp. and its affiliates,
which include Enron and Joint Energy, are specifically permitted to compete with
us. Neither Enron Corp. nor any of its affiliates has any obligation to bring
any business opportunity to us. For a more complete discussion of the provisions
of our company agreement relating to our shareholders' duties to us, see
"Description of Our Company Agreement and Common Shares -- Reasons We Chose the
Limited Liability Company Form."
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Transactions with Affiliates under our Revolving Credit Facility
Under our revolving credit facility, we have covenanted that we will not
engage in any transaction with any of our affiliates providing for the rendering
of services or sale of property unless the transaction is as favorable to us as
could be obtained in an arm's-length transaction with an unaffiliated party in
accordance with prevailing industry customs and practices. The revolving credit
facility excludes from this covenant:
o any transaction permitted by the shareholders' agreement;
o the grant of options to purchase or sales of equity securities to our
directors, officers, employees and consultants; and
o the assignment of any overriding royalty interest pursuant to an employee
incentive compensation plan.
Transactions with Affiliates Under our Indenture
The indenture, dated as of August 1, 1996, between Mariner Energy, Inc. and
United States Trust Company of New York, under which the senior subordinated
notes were issued, contains similar restrictions. Under the indenture, our
subsidiary has covenanted not to engage in any transaction with an affiliate
unless the terms of that transaction are no less favorable to our subsidiary
than could be obtained in an arm's-length transaction with a nonaffiliate.
Further, if the transaction involves more than $1 million, it must be approved
in writing by a majority of our subsidiary's disinterested directors. If the
transaction involves more than $5 million, it must be determined by a nationally
recognized investment banking firm to be fair, from a financial standpoint, to
our subsidiary. However, this covenant is subject to several significant
exceptions, including:
o some industry-related agreements made in the ordinary course of business
where the agreements are approved by a majority of our subsidiary's
disinterested directors as being the most favorable of several bids or
proposals;
o transactions under employment agreements or compensation plans entered into
in the ordinary course of business and consistent with industry practice;
and
o some prior transactions.
Further, Mariner Energy LLC is not a party to the indenture and these
provisions of the indenture are not applicable to Mariner Energy LLC.
Other Transactions with Affiliates
We expect that from time to time we will engage in various commercial
transactions and have various commercial relationships with Enron Corp. and
affiliates of Enron Corp., such as holding, exploring, exploiting and developing
joint working interests in particular prospects and properties, engaging in
hydrocarbon price hedging arrangements and entering into other oil and gas
related or financial transactions. For example, there are several prospects in
which both an affiliate of Enron Corp. and we have working interests. These
interests were acquired in the ordinary course of business pursuant to bids,
joint or otherwise. Any wells drilled will be subject to joint operating
agreements relating to exploration and possible production and will be subject
to customary business terms. Furthermore, all of the open agreements we have
entered into for the purpose of hedging oil and natural gas prices on our future
production have been entered into with Enron Corp. or affiliates of Enron Corp.
We also have sold a flow line and related facilities to an affiliate of Enron
Corp. in exchange for a long-term commitment to pay a tariff rate for the use of
that flow line. We believe that our current agreements with Enron Corp. and its
affiliates are on terms no less favorable to us than would be contained in an
agreement with a third party, but we cannot assure you that future agreements
will be on similar terms.
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1998 Equity Investment
In June 1998, Mariner Holdings, Inc. issued additional equity to its
existing shareholders, including Joint Energy, for approximately $14.58 per
share, for an aggregate investment of $30 million. Mariner Holdings, Inc. paid
approximately $1.2 million as a structuring fee, on a pro rata basis, to
existing shareholders participating in this transaction. Approximately $1
million of this fee was paid to ECT Securities Corp., an affiliate of Joint
Energy. We believe that the payment of the structuring fee to ECT Securities
Corp. was on terms that are at least as favorable as those that we could have
obtained from unaffiliated parties.
Enron Credit Facility
We established the Enron credit facility in September 1998 to provide us
with additional capital. The Enron credit facility provided for unsecured,
subordinated loans of up to $50 million, bearing interest at LIBOR plus 4.5%,
payable at April 30, 2000. The full amount borrowed under this credit facility
was repaid on May 1, 2000 with proceeds from the ENA term loan described below.
This facility would have required us to repay the loan within one day of the
closing of a public offering. Had it not been repaid, Enron could have converted
into our common shares the outstanding debt and accrued interest owed under this
facility at a rate of $14.58 per common share. We believe that the Enron credit
facility was entered into on terms that are at least as favorable as those that
we could have obtained from unaffiliated parties.
Senior Credit Facility with Enron
We established the senior credit facility with Enron in April 1999
primarily to provide us with additional working capital. The facility provided
for senior unsecured revolving loans up to $25 million, bearing interest at
LIBOR plus 2.5%, payable quarterly. The full amount borrowed under the senior
credit facility was repaid on May 1, 2000 with proceeds from the ENA term loan
described below. The senior credit facility requires us to repay the loan by
December 31, 1999. We believe that the senior credit facility with Enron was
entered into on terms that are at least as favorable as those that we could have
obtained from unaffiliated parties.
ENA Term Loan
We established the term loan with ENA in March 2000 to repay amounts
outstanding under the Enron credit facility and the senior credit facility with
Enron, and to provide us with approximately $31 million of additional working
capital. The loan matures in March 2003 and bears interest at 15%; which
interest accrues and is added to the loan principal. Repayment of the loan and
accrued interest, which was approximately $112.6 million as of June 30, 2000, is
required upon the receipt of proceeds from this offering. As part of the loan
agreement, two five-year warrants were issued to ENA providing the right to
purchase up to 900,000 of our common shares for $0.01 per share. One warrant for
600,000 shares is exercisable by ENA immediately and another warrant for 300,000
shares is exercisable on March 21, 2001, if the term loan is unpaid on that
date. We believe that the ENA term loan was entered into on terms that are at
least as favorable as those that we could have obtained from unaffiliated
parties.
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DESCRIPTION OF OUR COMPANY AGREEMENT AND COMMON SHARES
The following is a description of the material terms of our limited
liability company agreement. This company agreement is analogous to the
certificate of incorporation and bylaws of a corporation. Our company agreement
is filed as an exhibit to the registration statement of which this prospectus is
a part. We refer you to that exhibit for a more complete description of its
provisions. Our company agreement sets forth our purpose, our duration,
provisions relating to our capital structure and other matters relating to our
governance. Except for matters specifically described below, our company
agreement provides for our operation in a manner that is substantially identical
to the operation of a Delaware corporation.
Organization and Duration
We were recently organized as a limited liability company under Delaware
limited liability company law. We will have perpetual existence unless sooner
dissolved pursuant to the terms of our company agreement. See "-- Termination
and Dissolution" for a description of the provisions of our company agreement
that relate to our termination and dissolution.
Purpose
Our purpose is to engage in any lawful act or activity for which limited
liability companies may be formed under the Delaware limited liability company
law and engage in any and all activities necessary, convenient, desirable or
incidental to this act or activity, including the acquisition, disposition,
ownership, exploration, development and operation of oil or natural gas
producing properties and the purchase, transportation, sale and marketing of
natural gas, crude oil, natural gas liquids and other hydrocarbons.
Tax Treatment
We have elected to be treated as a taxable corporation for United States
federal income tax purposes. Under current United States federal income tax law,
the tax treatment of ownership of common shares will be identical to the tax
treatment of ownership of common stock in a publicly traded corporation.
Management
General
Although we are a limited liability company, our management and corporate
governance structure is similar to that of a corporation in that our business is
managed by a board of directors and officers whose authority and functions are
identical to the authority and functions of the board of directors and officers
of a corporation organized under Delaware corporate law. Our company agreement
provides explicitly that, except as otherwise specifically provided in our
company agreement, the duties and obligations our officers and directors owe us
and our shareholders, and any duties that may be owed by any shareholder or by
any affiliates of any shareholder, are the same as the respective duties and
obligations owed to a corporation organized under Delaware corporate law by its
officers and directors and any similarly situated stockholder or its affiliate.
However, our company agreement contains provisions that relieve Enron and its
affiliates from some duties that would otherwise be owed to us and our
shareholders. See "-- Reasons We Chose the Limited Liability Company Form" for a
more complete description of these duties.
Board of Directors
Our business is managed by, or under the direction of, our board of
directors. Each board member serves until the next annual meeting of
shareholders and until the director's successor has been elected and qualified.
Our company agreement provides that the number of directors to serve on our
board of directors will be determined from time to time by our board of
directors but may not be less than one. Our board of directors may not decrease
the size of our board of directors if doing so would shorten the term of any
director. A majority of the directors then in office may elect any person to
fill a vacancy on our board of directors, including a vacancy created by virtue
of an increase in the size of our board of directors. The number of members of
our board of directors has been set at twelve but will be increased to _____ in
connection with the offering. For a description and background of our directors,
see "Management -- Directors and Executive Officers."
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Our company agreement provides that our board of directors may have a
standing oversight committee and that a majority of the oversight committee will
be composed of directors who are not with Enron Corp. The oversight committee,
among other things, would be charged with reviewing proposed transactions
between Enron Corp. and its affiliates, other than Mariner and us. The Board of
Directors has not established an oversight committee.
An election of directors will be held and new directors will be elected, or
existing directors will be reelected, at each annual meeting of shareholders. We
will hold this meeting annually at the time our board of directors determines.
We must have an annual meeting at least once every 13 months. At each election
of directors, the holders of common shares will be entitled to one vote per
share, and the presence, in person or by proxy, of the holders of shares of all
classes or series of our equity securities possessing a majority of the voting
power of all outstanding equity securities entitled to vote will constitute a
quorum. To be elected as a director, a person who has been properly nominated
must receive a majority of the votes cast on the election of directors at the
meeting, in person or by proxy, or, if the nomination is contested, a plurality
of the votes cast. Since Joint Energy is expected to hold a substantial majority
of the common shares, it will control the election of all directors.
Any director may be removed, with or without cause, by written consent or
other approval of the holders of a majority of our equity securities.
Officers
Our board of directors has the authority to appoint our officers. We will
have a chairman of the board of directors and chief executive officer, a
president, a general counsel and a secretary, and we may have one or more vice
presidents, a treasurer and one or more assistant secretaries and assistant
treasurers and other officers as our board of directors may appoint. Each of our
officers will have certain authority by virtue of being appointed an officer and
may be further authorized from time to time to take any action that our board of
directors delegates to the officer.
Shareholders' Meetings; Voting
Holders of record of common shares will be entitled to notice of, and to
vote at, meetings of the shareholders and to act on matters as to which
approvals may be solicited. There will be an annual meeting of the shareholders.
Special meetings of the shareholders may be called by our board of directors or
by shareholders holding at least 35% of our voting power. Each record holder of
common shares will have one vote per share, although additional classes or
series of equity securities may have special voting rights. See "-- Preferred
Shares" for a description of our ability to issue preferred shares. Our company
agreement provides that:
o our equity securities held in nominee accounts will be voted by the
clearing agent, or other nominee, pursuant to the instruction of the
beneficial owner, unless the arrangement between the beneficial owner and
the beneficial owner's nominee provides otherwise; and
o we may assume without inquiry that the nominee is so voting.
Common Shares
Our company agreement authorizes the issuance of up to 50 million common
shares for the consideration and on the terms and conditions that our board of
directors establishes, in its sole discretion, without the approval of any
holders of common shares. Shares so issued and paid for will be fully paid and
nonassessable, except to the extent a shareholder knowingly receives an illegal
dividend. Subject to the prior rights, if any, of the holders of any other of
our company securities, the holders of common shares are:
o entitled to receive dividends ratably as our board of directors declare, if
any;
o on our liquidation or dissolution, entitled to share ratably in all
remaining assets after satisfaction of our liabilities to creditors; and
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o entitled to one vote per common share on the election of directors and on
all other matters submitted to a vote of shareholders.
Each common share is identical in all respects with each other common
share. Holders of common shares have no preemptive rights and no cumulative
voting rights. The affirmative vote of a majority of the outstanding common
shares is required to constitute shareholder action. The common shares will be
our only equity interests outstanding immediately following the offering.
Payment of dividends on the common shares is subject to restrictions
contained in our revolving credit facility. The decision to pay dividends is
subject to the other financial considerations our board of directors may deem
relevant. We cannot assure you as to the timing or amount of any dividend that
we may declare on the common shares. We have not paid any dividends to our
shareholders.
Preferred Shares
Our company agreement authorizes the issuance of up to one million
preferred shares for the consideration and on the terms and conditions our board
of directors establishes, in its sole discretion, without the approval of any
holders of common shares. Preferred shares may be entitled to preference over
the common shares on dividends, voting rights, conversion or redemption rights,
amounts payable on liquidation and other matters. Preferred shares of any class
or series may be entitled to other rights and privileges, or subject to other
restrictions, our board of directors establishes in its sole discretion.
Transfers of Shares
The common shares are generally freely transferable, subject to applicable
securities laws, in the same manner as capital stock of a corporation. Our
company agreement provides that each purchaser of common shares, by virtue of
the purchase, will become a member of Mariner and will be bound by our company
agreement, without the need to execute the company agreement.
Limited Liability
Generally, the debts, obligations and liabilities of a Delaware limited
liability company, whether arising in contract, tort or otherwise, are solely
the debts, obligations and liabilities of the limited liability company. No
owner of an equity interest in us is obligated personally for any debt,
obligation or liability of the limited liability company solely by reason of
being an owner of the equity interest.
Merger, Consolidation or Sale of All or Substantially All Assets
We may merge or consolidate with, or sell all or substantially all of our
assets to, one or more corporations, limited liability companies, business
trusts or associations, real estate investment trusts, common law trusts or
unincorporated businesses, including general or limited partnerships, only if
the transaction is approved by our board of directors and a majority in interest
of our equity securities.
A holder of common shares opposing any proposed merger or consolidation,
where the proposed transaction requires shareholder approval, will be afforded
appraisal rights in the same manner and to the same extent that these rights
would be available to the holder of stock of a Delaware corporation under the
Delaware corporate law. Those rights must be perfected by the same procedure
that would be required of a holder of stock of a Delaware corporation.
Amendment of Company Agreement
In order to adopt a proposed amendment to our company agreement, our board
of directors must seek written approval of the shareholders required to approve
the amendment or call a meeting of shareholders to consider and vote upon the
proposed amendment, except as described below. Proposed amendments must be
approved by a majority in interest of our equity securities unless otherwise
provided in our company agreement.
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Reasons We Chose the Limited Liability Company Form
Although we have a corporate management structure, we were legally
organized as a limited liability company, rather than a Delaware corporation,
solely for purposes of creating more certainty regarding the duties of Enron
Corp. and our officers and directors to us and our shareholders. Section 18-110
of the Delaware Limited Liability Company Act contains explicit provisions
designed to give the maximum effect to the principle of freedom of contract and
enforceability of limited liability company agreements. It provides explicitly
that to the extent a shareholder or other person, including a director or
officer, has fiduciary or other duties or liabilities to a Delaware limited
liability company or its shareholders, these duties or liabilities may be
expanded or restricted by provisions of the limited liability company agreement.
It also provides that no person who relies in good faith on the provisions of
the limited liability company agreement will be liable to the limited liability
company or its shareholders. There are no comparably explicit provisions under
Delaware corporate law. These duties for corporate directors, officers and
shareholders in Delaware are defined in varying degrees of clarity through
various case law opinions. As a result, the enforceability of provisions
limiting fiduciary liability or defining these duties in corporate charters is
less certain.
Under Delaware law, a controlling shareholder of a Delaware corporation has
certain fiduciary duties to the corporation, including the duty not to pursue
for its own account a business opportunity that is in the same line of business
as the corporation or in which the corporation has an interest or expectancy,
unless the controlling shareholder first offers the opportunity to the
corporation and the corporation declines to pursue it. Not all business
opportunities are required to be offered, and there is a lack of clear guidance
in case law regarding which opportunities are required to be offered and which
are not. Our company agreement contains provisions explicitly:
o relieving Enron Corp. and its affiliates, other than Mariner, from any
obligation to offer business opportunities to us or to any of our
subsidiaries;
o waiving any claim that any business opportunity pursued by or to be pursued
by Enron Corp. or any of its affiliates constitutes a business opportunity
that was misappropriated; and
o providing generally that neither Enron Corp. nor any affiliate of Enron
Corp. has any obligation to refrain from engaging in activities that may be
competitive with our activities.
Our company agreement does not, however, permit:
o a natural person to usurp, solely for his or her personal benefit, a
business opportunity of ours presented to that person in his or her
capacity as an officer or director, unless the officer or director first
presented the opportunity to us and we declined to pursue it; or
o Enron Corp. or any of its affiliates, other than Mariner, to usurp a
business opportunity of ours presented to an officer or director serving as
such at the request of Enron Corp. solely in his or her capacity as an
officer or director of Mariner unless the officer or director first
presented the opportunity to us and we declined to pursue it.
Our company agreement does provide that Enron Corp. or any of its
affiliates, other than us, may pursue any business opportunity that is
separately presented to or identified by Enron Corp. or any of its affiliates,
other than us, even if the opportunity has also been presented to one of our
officers or directors. The provisions of the company agreement applicable to
Enron Corp. may also be applicable to an entity that acquires Enron Corp.'s
common shares other than in a public offering.
Fiduciary and Other Duties
The fiduciary obligations of officers, directors and affiliates of limited
liability companies is a developing area of the law. In an effort to create more
certainty regarding the duties of Enron Corp. and its affiliates, other than
Mariner, to us and our shareholders and the duties of our officers and directors
to us and our shareholders, our company agreement specifies the standards of
behavior required of these persons, establishes procedures that may be used for
resolutions of conflicts of interest and describes activities that will not be
deemed to violate fiduciary or other duties.
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Our company agreement provides that, except as otherwise specifically
provided, the duties and obligations of our officers, directors and affiliates
to us and our shareholders will be the same as the duties owed by officers,
directors and affiliates of a corporation organized under the Delaware corporate
law to the corporation and its stockholders. We believe that there is more
certainty under the Delaware corporate law regarding duties owed by these
persons than under Delaware limited liability company law, primarily because
there are many judicial decisions under the Delaware corporate law and
comparable corporate statutes. Other provisions of our company agreement modify
these fiduciary duties and limit the liability of officers, directors and
affiliates to us and our shareholders. These provisions are intended to permit
Enron Corp. and its affiliates, other than Mariner, to deal with us and others,
and to permit our officers and directors to perform their duties to us, without
undue uncertainty regarding the standards by which they will be judged or undue
risk of liability. We believe that these provisions are necessary to provide
certainty and fairness in the relationships between Enron Corp. and its
affiliates, other than Mariner, and us, many of which involve conflicts of
interest, and to permit Enron Corp. to continue to conduct its business without
undue risk of liability. See "Certain Relationships and Related Transactions --
Enron Corp. and Affiliates" for a description of our transactions with Enron
Corp. Our company agreement provides, among other things, that:
o our officers, directors or affiliates will not be liable for errors in
judgment or for any act or omission if the person acted in good faith;
o Enron Corp. and its affiliates, other than Mariner, will have no obligation
to offer to sell us any assets or related interest;
o it will not constitute a breach of fiduciary or other duty for Enron Corp.
and its affiliates to engage in activities of the type we conduct, even if
in direct competition with us, including the ownership and operation of
interests in companies that engage in oil and gas exploration and
production activities;
o the approval by our oversight committee of the terms of any proposed
transaction between Enron Corp. or its affiliates, other than Mariner, and
us, including the amendment of any contract, shall be deemed to be a
conclusive determination that this transaction does not constitute a breach
of fiduciary or other duty owed by Enron Corp. or its affiliates, other
than Mariner, as long as the material facts known to Enron Corp. or its
affiliates regarding this proposed transaction were disclosed to our
oversight committee at the time it gave its approval;
o it will not constitute a breach of fiduciary or other duty for Enron Corp.
and its affiliates and our officers or directors, including the oversight
committee, to resolve conflicts of interest, as long as the resolution of
these conflicts is fair to us, taking into account the relevant interests
of the parties;
o it will not constitute a breach of fiduciary or other duty for one of our
officers or directors to engage attorneys, accountants, engineers and other
advisors on our behalf or our board of directors or any committee, even
though these persons may also be retained from time to time by Enron Corp.
or its affiliates; and these persons may be engaged with respect to any
matter in which our interests and Enron Corp. and its affiliates may
differ, or may be engaged by both us and Enron Corp. or its affiliates with
respect to a matter, as long as the officer or director reasonably believes
that any conflict between us and Enron Corp. and its affiliates, other than
Mariner, related to the matter is not material; and
o each holder of common shares, in becoming a holder of common shares,
consents to the terms and provisions of our company agreement.
Our company agreement provides that any resolution or course of action
related to a conflict of interest will be conclusively deemed fair to us if the
resolution or course of action is:
o approved by our oversight committee without bad faith and after disclosure
of all known material facts;
o made or taken on terms no less favorable to us than those generally
provided to or available from unrelated third parties; or
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o a commercially fair resolution or course of action, taking into account the
circumstances surrounding the course of action or conflict of interest and
the totality of the relationships among the parties involved and the
relative interests of the parties.
Indemnification
Our company agreement provides that we will indemnify our directors and
officers from liabilities arising in the course of these persons' service to us.
The indemnitee must have acted in good faith and in a manner that the indemnitee
believed to be in or not opposed to our best interests. If the proceeding is
criminal, the indemnity must have had no reasonable cause to believe the
indemnitee's conduct was unlawful. These liabilities include all damages,
including reasonable legal fees and expenses. We carry directors' and officers'
liability insurance for potential liability under this indemnification. The
holders of common shares will not be personally liable for the indemnification,
although our responsibility for the cost of this indemnification could adversely
affect the value of the common shares.
Right to Information
In addition to other rights specifically listed in our company agreement,
and subject to the reasonable standards as we establish, each shareholder is
entitled to all information to which a member of a Delaware limited liability
company is entitled to have access pursuant to Section 18-305 of the Delaware
Limited Liability Company Act under the circumstances and subject to the
conditions stated in that provision.
Termination and Dissolution
We will have perpetual existence, unless sooner terminated pursuant to our
company agreement. Our company agreement provides that we will be dissolved
upon:
o the consent of the board of directors and holders of a majority of our
equity interest; or
o the entry of a decree of our judicial dissolution.
The death, resignation, dissolution or bankruptcy of any shareholder will not
constitute a dissolution event.
Liquidation and Distribution of Proceeds
On our dissolution, the liquidator will liquidate our assets and apply the
proceeds of liquidation in the order of priority our company agreement
establishes. Generally, after discharging our debts and liabilities, including
the costs of liquidation, any remaining proceeds will be distributed to our
shareholders.
Transfer Agent and Registrar
The transfer agent and registrar for our common shares is .
Comparison of us with a Delaware Corporation
We will be managed in a manner similar to that of a corporation. Under the
Delaware limited liability company act, a limited liability company may elect in
its limited liability company agreement to be governed in a manner essentially
the same as a Delaware corporation, a Delaware general or limited partnership, a
Delaware close corporation or any combination. Our company agreement establishes
the relationship of our shareholders to us and to one another and how we will
conduct our operations and the manner by which we will be governed, much like
the articles and bylaws of a Delaware corporation does for that corporation.
Although we are not subject to the Delaware corporate law, the Delaware limited
liability act permits a limited liability company agreement to provide, and our
company agreement does provide:
o that the management of a limited liability company will be conducted by a
board of directors and officers designated by the board; and
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o that the holders of shares in the limited liability company, as is the case
with the holders of our common shares, except as otherwise expressly
provided in our company agreement, will be afforded substantially all of
the rights that are afforded holders of common stock issued by a
corporation organized under the Delaware corporate law.
Specifically, our company agreement and the Delaware limited liability
company act provide the following corporate governance provisions and
shareholders rights, among others, that are consistent with the analogous
features of a Delaware corporation:
o our affairs will be managed by our board of directors elected by our
shareholders;
o our officers will be elected by our board of directors and serve at the
discretion and pleasure of our board of directors;
o shareholder actions will be conducted at annual or special meetings of
shareholders called by our board of directors;
o holders of our common shares generally are not personally liable or
assessable for our obligations;
o holders of our common shares are entitled to receive dividends when, as and
if declared by our board of directors;
o holders of our common shares generally are entitled to receive a ratable
portion of our assets after payment of our liabilities upon dissolution;
o holders of our common shares have the right to bring a derivative action
against our management on our behalf;
o holders of our common shares after the offering will not be entitled to
preemptive rights with respect to the issuance of our securities; and
o holders of our common shares opposing any proposed merger or consolidation,
where the proposed transaction requires shareholder approval, will be
afforded appraisal rights in the same manner and to the same extent that
these rights would be available to the holder of stock of a Delaware
corporation under the Delaware corporate law, and those rights must be
perfected by the same procedure that would be required of a holder of stock
of a Delaware corporation.
Registration Rights
Under the terms of our shareholders' agreement, we are obligated to
register, on three occasions, the common shares held by Joint Energy and Enron
under certain circumstances, after the expiration of 90 days after the
consummation of any underwritten initial public offering. In connection with the
offering, Joint Energy and Enron have agreed with the underwriters that they
will not exercise these rights or sell any shares, other than shares Joint
Energy and Enron may sell in the offering, within 180 days of the offering. In
addition, if we propose to register any common shares under applicable
securities laws, we are required to afford our existing shareholders the right
to include their common shares in that registration, with some limitations.
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SHARES ELIGIBLE FOR FUTURE SALE
There is currently no public market for our common shares. Future sales of
substantial amounts of our common shares in the public market, or the perception
that those sales could occur, could adversely affect the market price of our
common shares.
After the offering, we will have outstanding _____ common shares. Of these
shares, the shares sold in the offering will be freely tradable without
restriction or further registration under the Securities Act, unless they are
purchased by our "affiliates," as that term is defined in Rule 144 under the
Securities Act, which sales would be subject to certain restrictions under Rule
144. The remaining _____ outstanding common shares will be "restricted
securities," as that term is defined in Rule 144, and may be sold only if
registered or pursuant to an exemption from registration such as that provided
by Rule 144. Joint Energy, Enron and the existing shareholders also have
registration rights. See "Description of Our Company Agreement and Common Shares
-- Registration Rights" for a description of these registration rights. In
connection with the offering, we, our officers and directors, Joint Energy and
Enron, who in the aggregate own or have the right to acquire common shares, have
agreed that, subject to exceptions relating to transfers that will not occur in
market transactions and other exceptions, will not sell, offer or contract to
sell any common shares without the prior written consent of Credit Suisse First
Boston Corporation for a period of 180 days after the date of this prospectus.
For a discussion of the exceptions to this restriction, see "Underwriting."
We also had outstanding options to purchase an aggregate of 2,226,948
common shares as of June 30, 2000. We intend to file a Registration Statement on
Form S-8 under the Securities Act to register _____ common shares reserved for
issuance under our _____ Share Option Plan.
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UNDERWRITING
Under the terms and subject to the conditions contained in an underwriting
agreement dated _____, 2000, we and the selling shareholders have agreed to sell
to the underwriters named below, for whom Credit Suisse First Boston
Corporation, Banc of America Securities LLC, Morgan Stanley & Co. Incorporated,
PaineWebber Incorporated and Petrie Parkman & Co., Inc. are acting as
representatives, the following respective numbers of common shares:
Number
Underwriter of Shares
---------------------------------- ----------
Credit Suisse First Boston Corporation....
Banc of America Securities LLC............
Morgan Stanley & Co. Incorporated.........
PaineWebber Incorporated..................
Petrie Parkman & Co., Inc.................
Total...........................
The underwriting agreement provides that the underwriters are obligated to
purchase all the common shares in this offering if any are purchased, other than
those shares covered by the over-allotment option described below. The
underwriting agreement also provides that if an underwriter defaults, the
purchase commitments of non-defaulting underwriters may be increased or this
offering of common shares may be terminated.
We and the selling shareholders have granted to the underwriters a 30-day
option to purchase on a pro-rata basis up to _____ additional shares from us and
_____ additional outstanding shares from the selling shareholders at the initial
public offering price less the underwriting discounts and commissions. The
option may be exercised only to cover any over-allotments of common shares.
The underwriters propose to offer the common shares initially at the public
offering price set forth on the cover page of this prospectus and to selling
group members at that price less a concession of $_____ per share. The
underwriters and the selling group members may allow a discount of $_____ per
share on sales to other broker/dealers. After the initial public offering, the
public offering price and concession and discount to broker/dealers may be
changed by the underwriters.
The following table summarizes the compensation and the estimated expenses
we and the selling shareholders will pay.
<TABLE>
<CAPTION>
Per Share Total
Without With Without With
Over-allotment Over-allotment Over-allotment Over-allotment
<S> <C> <C> <C> <C>
Underwriting Discounts and Commissions payable by us.. $ $ $ $
Expenses payable by us................................ $ $ $ $
Underwriting Discounts and Commissions paid by the
selling shareholders.................................. $ $ $ $
Expenses payable by the selling shareholders.......... $ $ $ $
</TABLE>
The underwriters do not intend to confirm sales to any accounts over which
they exercise discretionary authority.
Bank of America, N.A. is the agent and a lender under our revolving credit
facility. We have paid Bank of America, N.A. customary interest, fees and
compensation in connection with our revolving credit facility. We may use more
than 10% of the net proceeds from the sale of the common shares to repay all
indebtedness owed by us to Bank of America, N.A. under the revolving credit
facility. Accordingly, this offering is being made in compliance with the
requirements of Rule 2710(c)(8) of the National Association of Securities
Dealers, Inc. Conduct Rules. This rule provides generally that if more than 10%
of the net proceeds from the sale of common stock, not including underwriting
compensation, is paid to the underwriters or their affiliates, the initial
public offering price of the shares may not be higher than that recommended by a
"qualified independent underwriter" meeting specified standards. Accordingly, if
Bank of America, N.A. receives more than 10% of the net proceeds, Credit Suisse
First Boston Corporation will assume the responsibilities of acting as the
qualified independent underwriter in pricing this offering and conducting due
diligence. The initial public offering price of the common shares set forth on
the cover page of this prospectus will be no higher than the price recommended
by Credit Suisse First Boston Corporation.
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We, each of our directors and officers, Joint Energy and Enron have agreed
not to offer, sell, contract to sell, pledge or otherwise dispose of, directly
or indirectly, or file with the SEC a registration statement under the
Securities Act relating to any of our common shares, other than the shares Joint
Energy and Enron sell in the offering, or any securities convertible into or
exchangeable or exercisable for any of our common shares, or publicly disclose
the intention to make any such offer, sale, pledge, disposition or filing,
without the prior written consent of Credit Suisse First Boston Corporation for
a period of 180 days after the date of this prospectus. The primary exceptions
to these restrictions are:
o our issuance of common shares under our employee benefit plans and
registration of these issuances;
o transfers by Joint Energy and Enron of common shares, or securities
convertible into common shares, to an affiliate that agrees to be bound by
the restrictions; and
o bona fide gifts by individuals if the donee agrees to be bound by these
restrictions.
We and the selling shareholders have agreed to indemnify the underwriters
against liabilities under the Securities Act, or to contribute to payments that
the underwriters may be required to make in that respect.
We have made application to list our common shares on The Nasdaq Stock
Market's National Market.
In the ordinary course of their business, some of the underwriters and
their affiliates have in the past and may in the future engage in investment
banking and other financial transactions with us, including providing financial
advisory services.
Before this offering, there has been no public market for our common
shares. The initial public offering price will be determined by negotiations
between us and the underwriters. The principal factors considered in determining
the initial public offering price include:
o market conditions for initial public offerings;
o the history of and prospects for our business;
o our past and present operations;
o our past and present earnings and current financial position;
o an assessment of our management;
o the market for securities of companies in businesses similar to our
business; and
o the general condition of the securities markets.
We cannot assure you that the initial public offering price will correspond
to the price at which the common shares will trade in the public market after
the offering or that an active trading market for the common shares will develop
and continue after the offering.
The underwriters may engage in over-allotment, stabilizing transactions,
syndicate covering transactions, penalty bids and "passive" market making in
accordance with Regulation M under the Securities Exchange Act of 1934.
o Over-allotment involves syndicate sales in excess of the offering size,
which creates a syndicate short position.
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o Stabilizing transactions permit bids to purchase the underlying security so
long as the stabilizing bids do not exceed a specified maximum.
o Syndicate covering transactions involve purchases of the common shares in
the open market after the distribution has been completed in order to cover
syndicate short positions.
o Penalty bids permit the underwriters to reclaim a selling concession from a
syndicate member when the common shares originally sold by the syndicate
member are purchased in a stabilizing transaction or in a syndicate
covering transaction to cover syndicate short positions.
o In "passive" market making, market makers in the common shares who are
underwriters or prospective underwriters may, subject to certain
limitations, make bids for or purchases of the common shares until the
time, if any, at which a stabilizing bid is made.
These stabilizing transactions, syndicate covering transactions and penalty
bids may cause the price of our common shares to be higher than it would
otherwise be in the absence of these transactions. These transactions may be
effected on The Nasdaq National Market or otherwise and, if commenced, may be
discontinued at any time.
NOTICE TO CANADIAN RESIDENTS
Resale Restrictions
The distribution of the common shares in Canada is being made only on a
private placement basis exempt from the requirement that we prepare and file a
prospectus with the securities regulatory authorities in each province where
trades of common shares are effected. Accordingly, any resale of the common
shares in Canada must be made in accordance with applicable securities laws
which will vary depending on the relevant jurisdiction and which may require
resales to be made in accordance with available statutory exemptions or pursuant
to a discretionary exemption granted by the applicable Canadian securities
regulatory authority. Purchasers are advised to seek legal advice prior to any
resale of the common shares.
Representations of Purchasers
Each purchaser of common shares in Canada who receives a purchase
confirmation will be deemed to represent to us and the dealer from whom the
purchase confirmation is received that: (i) the purchaser is entitled under
applicable provincial securities laws to purchase common shares without the
benefit of a prospectus qualified under those securities laws; (ii) where
required by law, the purchaser is purchasing as principal and not as agent; and
(iii) the purchaser has reviewed the text above under "-- Resale Restrictions."
Rights of Action (Ontario Purchasers)
The securities being offered are those of a foreign issuer and Ontario
purchasers will not receive the contractual right of action prescribed by
Ontario's securities law. As a result, Ontario purchasers must rely on other
remedies that may be available, including common law rights of action for
damages, rescission or rights of action under the civil liability provisions of
the United States federal securities laws.
Enforcement of Legal Rights
All of the issuer's directors and officers as well as the experts named in
this prospectus may be located outside of Canada and, as a result, it may not be
possible for Canadian purchasers to effect service of process within Canada upon
the issuer or these persons. All or a substantial portion of the assets of the
issuer and these persons may be located outside of Canada and, as a result, it
may not be possible to satisfy a judgment against the issuer or these persons in
Canada or to enforce a judgment obtained in Canadian courts against the issuer
or persons outside of Canada.
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Notice to British Columbia Residents
A purchaser of common shares to whom the Securities Act (British Columbia)
applies is advised that the purchaser is required to file with the British
Columbia Securities Commission a report within ten days of the sale of any
common shares acquired by the purchaser pursuant to the offering. This report
must be in the form attached to British Columbia Securities Commission Blanket
Order BOR #95/17, a copy of which may be obtained from us. Only one report must
be filed related to the common shares acquired on the same date and under the
same prospectus exemption.
Taxation and Eligibility for Investment
Canadian purchasers of common shares should consult their own legal and tax
advisors with respect to the tax consequences of an investment in the common
shares in their particular circumstances and with respect to the eligibility of
the common shares for investment by the purchaser under relevant Canadian
legislation.
LEGAL MATTERS
Legal matters related to the common shares being issued in the offering are
being passed upon for us by Fulbright & Jaworski L.L.P., Houston, Texas. Legal
matters in connection with the offering will be passed upon for the underwriters
by Andrews & Kurth L.L.P., Houston, Texas.
EXPERTS
The consolidated financial statements as of December 31, 1998 and 1999 and
for each of the three years in the period ended December 31, 1999 included in
this prospectus and the related financial statement schedule included elsewhere
in the registration statement have been audited by Deloitte & Touche LLP,
independent auditors, as stated in their report appearing in this prospectus,
and have been so included in reliance upon the report of such firm given upon
their authority as experts in accounting and auditing.
INDEPENDENT PETROLEUM ENGINEERS
The estimated reserve evaluations and related calculations of Ryder Scott
Company, L.P., our independent petroleum engineers, have been included in this
prospectus in reliance upon the authority of that firm as an expert in petroleum
engineering.
WHERE YOU CAN FIND MORE INFORMATION
This prospectus is part of a registration statement on Form S-1 under the
Securities Act relating to our common shares. As permitted by Securities and
Exchange Commission rules, this prospectus does not include all the information
we have included in the registration statement. You may refer to the
registration statement and the related exhibits and schedules we filed with the
Securities and Exchange Commission for more information about us and our common
shares. You can read and copy the registration statement, exhibits and schedules
at the Securities and Exchange Commission's public reference room at 450 Fifth
Street, N.W., Room 1024, Washington, D.C. 20549, and at the Securities and
Exchange Commission's regional offices located at 500 West Madison Street, Suite
1400, Chicago, Illinois 60661 and at Seven World Trade Center, Suite 1300, New
York, New York 10048. You can obtain information about the operation of the
Securities and Exchange Commission's public reference room at 1-800-SEC-0330.
The Securities and Exchange Commission also maintains an Internet site that
contains reports, proxy and information statements, and other information about
issuers that file electronically with the Securities and Exchange Commission.
The address of that site is http://www.sec.gov.
Following this offering, we will be required to file current reports,
quarterly reports, annual reports, proxy statements and other information with
the Securities and Exchange Commission. You may read and copy those reports,
proxy statements and other information at the Securities and Exchange
Commission's public reference room and regional offices or through its Internet
site. We intend to furnish our shareholders with annual reports that will
include a description of our operations and audited financial statements
certified by an independent public accounting firm.
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GLOSSARY OF OIL AND NATURAL GAS TERMS
"3-D seismic" (Three-Dimensional Seismic Data) Geophysical data that
depicts the subsurface strata in three dimensions. 3-D seismic typically
provides a more detailed and accurate interpretation of the subsurface strata
than 2-D seismic.
"2-D seismic" Seismic data that are acquired and processed to yield a
two-dimensional cross section of the substance.
"appraisal well" means a well drilled several spacing locations away from a
producing well to determine the boundaries or extent of a productive formation
and to establish the existence of additional reserves.
"Bbl" One stock tank barrel, or 42 U.S. gallons liquid volume, used in this
prospectus in reference to crude oil, condensate or other liquid hydrocarbons.
"Bcf" One billion cubic feet of natural gas.
"Bcfe" One billion cubic feet of natural gas equivalent (see Mcfe for
equivalency).
"development well" A well drilled within the proved boundaries of an oil or
natural gas reservoir with the intention of completing the stratigraphic horizon
known to be productive.
"exploitation well" Ordinarily considered to be a development well drilled
within a known reservoir. We use the word to refer to deepwater wells that are
drilled on offshore leaseholds held (usually under farmout agreements) where a
previous exploratory well showing the existence of potentially productive
reservoirs was drilled, but the reservoir was by-passed for development by the
owner who drilled the exploratory well; thus we distinguish our development
wells on our own properties from these exploitation wells.
"exploratory well" A well drilled to find and produce oil or natural gas in
an unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir, or to extend a known
reservoir.
"farmout" The term used to describe the action taken by the person making a
transfer of a leasehold interest in an oil and gas property pursuant to a
farmout agreement.
"farmout agreement" A common form of agreement between oil and gas
operators pursuant to which an owner of an oil and gas leasehold interest that
does not want to drill at the time agrees to assign the leasehold interest, or
some portion of it, to another operator that does want to drill the tract. The
assignor in these transactions may retain some interest in the property such as
an overriding royalty interest or a production payment, and, typically, the
assignee of the leasehold interest has an obligation to drill one or more wells
on the assigned acreage as a prerequisite to completion of the transfer to it.
"generate" Generally refers to the creation of an exploration or
exploitation idea after evaluation of seismic and other available data.
"infill well" A well drilled between known producing wells to better
exploit the reservoir.
"lease operating expenses" The expenses of lifting oil or gas from a
producing formation to the surface, and the transportation and marketing
thereof, constituting part of the current operating expenses of a working
interest, and also including labor, superintendence, supplies, repairs,
short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and
other expenses incidental to production, but not including lease acquisition or
drilling or completion expenses.
"MBbls" One thousand barrels of crude oil or other liquid hydrocarbons.
"Mcf" One thousand cubic feet of natural gas.
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"Mcfe" One thousand cubic feet of natural gas equivalent, assuming the
conversion of one barrel of oil to six Mcf of natural gas based on commonly
accepted rough equivalency of energy content.
"MMBtu" One million British thermal units.
"MMcf" One million cubic feet of natural gas.
"MMcfe" One million cubic feet of natural gas equivalent (see Mcfe for
equivalency).
"net revenue interest" An interest in all oil and natural gas produced and
saved from, or attributable to, a particular property, net of all royalties,
overriding royalties, net profits interests, carried interests, reversionary
interests and any other burdens to which the person's interest is subject.
"payout" Generally refers to the recovery by the incurring party to an
agreement of its costs of drilling, completing, equipping and operating a well
before another party's participation in the benefits of the well commences or is
increased to a new level.
"present value of estimated future net revenues" An estimate of the present
value of the estimated future net revenues from proved oil and gas reserves at a
date indicated after deducting estimated production and ad valorem taxes, future
capital costs and operating expenses, but before deducting any estimates of
federal income taxes. The estimated future net revenues are discounted at an
annual rate of 10%, in accordance with the Securities and Exchange Commission's
practice, to determine their "present value." The present value is shown to
indicate the effect of time on the value of the revenue stream and should not be
construed as being the fair market value of the properties. Estimates of future
net revenues are made using oil and natural gas prices and operating costs at
the date indicated and held constant for the life of the reserves.
"producing well" or "productive well" A well that is producing oil or
natural gas or that is capable of production without further capital
expenditure.
"proved developed reserves" Proved developed reserves are those quantities
of crude oil, natural gas and natural gas liquids that, upon analysis of
geological and engineering data, are expected with reasonable certainty to be
recoverable in the future from known oil and natural gas reservoirs under
existing economic and operating conditions. This classification includes:
o proved developed producing reserves, which are those expected to be
recovered from currently producing zones under continuation of present
operating methods; and
o proved developed non-producing reserves, which consist of (1) reserves from
wells that have been completed and tested but are not yet producing due to
lack of market or minor completion problems that are expected to be
corrected, and (2) reserves currently behind the pipe in existing wells
that are expected to be productive due to both the well log characteristics
and analogous production in the immediate vicinity of the well.
"proved reserves" The estimated quantities of crude oil, natural gas and
other hydrocarbon liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
"proved undeveloped reserves" Proved reserves that may be expected to be
recovered from existing wells that will require a relatively major expenditure
to develop or from undrilled acreage adjacent to productive units that are
reasonably certain of production when drilled.
"royalty interest" An interest in an oil and gas lease that gives the owner
of the interest the right to receive a portion of the production from the leased
acreage or the proceeds from the sale of the production, but generally does not
require the owner to pay any portion of the costs of drilling or operating the
wells on the leased acreage. Royalty interests may be either landowner's royalty
interests, which are reserved by the owner of the leased acreage at the time the
lease is granted, or overriding royalty interests, which are usually carved from
the leasehold interest pursuant to an assignment to a third party or reserved by
an owner of the leasehold in connection with a transfer of the leasehold to a
subsequent owner.
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"subsea tieback" A productive well that has its wellhead equipment located
on the sea floor and is connected by control and flow lines to an existing
production platform located in the vicinity.
"working interest" The interest in an oil and gas property (normally a
leasehold interest) that gives the owner the right to drill, produce and conduct
oil and gas operations on the property and the right to a share of production,
subject to all royalties, overriding royalties and other burdens and to all
costs of exploration, development and operations and all risks in connection
therewith.
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MARINER ENERGY LLC
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
INDEPENDENT AUDITORS' REPORT..............................................F-2
CONSOLIDATED BALANCE SHEETS...............................................F-3
As of December 31, 1998 and 1999
CONSOLIDATED STATEMENTS OF OPERATIONS.....................................F-4
Years Ended December 31, 1997, 1998 and 1999
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY...........................F-5
Years Ended December 31, 1997, 1998 and 1999
CONSOLIDATED STATEMENTS OF CASH FLOWS.....................................F-6
Years Ended December 31, 1997, 1998 and 1999
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS................................F-7
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)........................F-19
As of December 31, 1999 and June 30, 2000
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)..............F-20
For the Six Months Ended June 30, 2000 and 1999
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)..............F-21
For the Six Months Ended June 30, 2000 and 1999
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED).........F-22
F-1
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79
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
Mariner Energy LLC
Houston, Texas
We have audited the accompanying consolidated financial statements of
Mariner Energy LLC (the "Company"), as listed in the Index to Consolidated
Financial Statements. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Mariner
Energy LLC as of December 31, 1998 and 1999, and the results of its operations
and cash flows for the years ended December 31, 1997, 1998 and 1999, in
conformity with accounting principles generally accepted in the United States of
America.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Houston, Texas
March 28, 2000
F-2
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80
MARINER ENERGY LLC
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
ASSETS
December 31,
1998 1999
--------- ---------
CURRENT ASSETS:
Cash and cash equivalents ............................ $ 802 $ 123
Receivables .......................................... 15,657 22,766
Prepaid expenses and other ........................... 7,234 4,891
--------- ---------
Total current assets ......................... 23,693 27,780
--------- ---------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at full cost:
Proved ............................................ 316,056 379,301
Unproved, not subject to amortization ............. 84,076 81,897
--------- ---------
Total ........................................ 400,132 461,198
Other property and equipment ......................... 3,300 3,982
Accumulated depreciation, depletion and amortization.. (167,846) (199,233)
--------- ---------
Total property and equipment, net ............ 235,586 265,947
--------- ---------
OTHER ASSETS, net of amortization ...................... 3,513 3,489
--------- ---------
TOTAL ASSETS ........................................... $ 262,792 $ 297,216
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable ..................................... $ 20,375 $ 30,269
Accrued liabilities .................................. 29,082 25,389
Accrued interest ..................................... 4,953 8,868
--------- ---------
Total current liabilities ............................ 54,410 64,526
--------- ---------
ACCRUAL FOR FUTURE ABANDONMENT COSTS ................... 2,824 4,226
LONG-TERM DEBT:
Subordinated notes ................................... 99,624 99,673
Revolving credit facility ............................ 53,400 42,600
Senior credit facility ............................... -- 25,000
Enron credit facility ................................ 25,000 50,000
--------- ---------
Total long-term debt ......................... 178,024 217,273
--------- ---------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred stock $0.01 par value
(authorized 1,000,000 shares; none issued)........... -- --
Common stock, $0.01 par value
(authorized 50,000,000 shares;
issued and outstanding
1998-- 13,928,304, 1999-- 13,928,304 shares).......... 139 139
Additional paid-in-capital ........................... 124,718 124,718
Accumulated deficit .................................. (97,323) (113,666)
--------- ---------
Total stockholders' equity ................... 27,534 11,191
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ............. $ 262,792 $ 297,216
========= =========
The accompanying notes are an integral part of these financial statements
F-3
<PAGE>
81
MARINER ENERGY LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
<TABLE>
<CAPTION>
Year Year Year
Ended Ended Ended
December 31, December 31, December 31,
1997 1998 1999
-------------- -------------- ---------------
<S> <C> <C> <C>
REVENUES:
Oil sales ............................... $ 18,061 $ 10,066 $ 8,600
Gas sales ............................... 44,710 46,624 43,868
------------ ------------ ------------
Total revenues .................. 62,771 56,690 52,468
------------ ------------ ------------
COSTS AND EXPENSES:
Lease operating expenses ................ 9,376 9,858 11,453
Depreciation, depletion and amortization 31,719 33,833 32,526
Impairment of oil and gas properties .... 28,514 50,800 --
General and administrative expenses ..... 3,195 4,749 5,396
Provision for litigation ................ -- 2,800 --
------------ ------------ ------------
Total costs and expenses ........ 72,804 102,040 49,375
------------ ------------ ------------
OPERATING INCOME (LOSS) ................... (10,033) (45,350) 3,093
INTEREST:
Other income ............................ 467 313 36
Other expense ........................... (10,644) (13,384) (19,472)
------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES ......... (20,210) (58,421) (16,343)
PROVISION FOR INCOME TAXES ................ -- -- --
------------ ------------ ------------
NET INCOME (LOSS) ......................... $ (20,210) $ (58,421) $ (16,343)
============ ============ ============
BASIC AND DILUTED EARNINGS (LOSS) PER SHARE $ (1.71) $ (4.47) $ (1.17)
============ ============ ============
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 11,841,793 13,079,742 13,928,304
============ ============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements
F-4
<PAGE>
82
MARINER ENERGY LLC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands, except number of shares)
<TABLE>
<CAPTION>
Common Stock Additional Total
----------------------- Paid-in Accumulated Stockholders'
Shares Amount Capital Deficit Equity
------------- --------- ----------- ------------ -------------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1996................ 11,831,364 119 95,626 (18,692) 77,053
Sale of common stock ..................... 39,792 -- 331 -- 331
Net loss ......................... -- -- -- (20,210) (20,210)
----------- ------- --------- --------- --------
Balance at December 31, 1997................ 11,871,156 119 95,957 (38,902) 57,174
Proceeds from sale of common stock.......... 2,057,148 20 28,761 -- 28,781
Net loss ......................... -- -- -- (58,421) (58,421)
----------- ------- --------- --------- --------
Balance at December 31, 1998................ 13,928,304 139 124,718 (97,323) 27,534
Net loss ......................... -- -- -- (16,343) (16,343)
----------- ------- --------- ---------
Balance at December 31, 1999................ $13,928,304 $ 139 $ 124,718 $(113,666) $ 11,191
=========== ======= ========= ========== ========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-5
<PAGE>
83
MARINER ENERGY LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------
1997 1998 1999
------------ ---------- -----------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) ................................................... $ (20,210) $ (58,421) $ (16,343)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation, depletion and amortization ......................... 32,588 33,762 32,837
Impairment of oil and gas properties ............................. 28,514 50,800 --
Provision for litigation ......................................... -- 2,800 --
Changes in operating assets and liabilities:
Receivables ...................................................... (5,014) 2,928 (7,559)
Other current assets ............................................. (3,210) (3,606) 2,343
Other assets ..................................................... (483) 379 24
Accounts payable and accrued liabilities ......................... 20,693 11,703 10,566
--------- --------- ---------
Net cash provided by operating activities ................... 52,878 40,345 21,868
--------- --------- ---------
INVESTING ACTIVITIES:
Additions to oil and gas properties ................................. (68,317) (140,777) (80,823)
Additions to other property and equipment ........................... (551) (1,078) (682)
Proceeds from property conveyances .................................. -- -- 19,758
--------- --------- ---------
Net cash used in investing activities ....................... (68,868) (141,855) (61,747)
--------- --------- ---------
FINANCING ACTIVITIES:
Payments of debt issue costs ........................................ (29) -- --
Proceeds from revolving credit facility, net ........................ 14,000 39,400 (10,800)
Proceeds from Senior credit facility ................................ -- 25,000 --
Proceeds from Enron credit facility ................................. -- -- 50,000
Proceeds from sale of common stock .................................. 331 28,781 --
--------- --------- ---------
Net cash provided by financing activities ................... 14,302 93,181 39,200
--------- --------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ...................... (1,688) (8,329) (679)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ...................... 10,819 9,131 802
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ............................ $ 9,131 $ 802 $ 123
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-6
<PAGE>
84
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the Years
Ended December 31, 1997, 1998 and 1999
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization -- In 1996, Hardy Oil & Gas USA Inc., (the "Acquired
Company"), was a wholly owned subsidiary of Hardy Holdings Inc., which is a
wholly owned subsidiary of Hardy Oil & Gas plc ("Hardy plc"), a public company
incorporated in the United Kingdom. Pursuant to a stock purchase agreement dated
April 1, 1996, Joint Energy Development Investments Limited Partnership ("Joint
Energy"), which is an affiliate of Enron Capital & Trade Resources Corp., as of
September 1, 1999 known as Enron North America Corp. ("ENA"), together with
members of management of the Acquired Company, formed Mariner Holdings, Inc.
("Mariner Holdings"), which then purchased from Hardy Holdings Inc. all of the
issued and outstanding stock of the Acquired Company for a purchase price of
approximately $185.5 million effective April 1, 1996 for financial accounting
purposes (the "Acquisition"). As a result of the sale of Hardy Oil & Gas USA
Inc.'s common stock, the Acquired Company changed its name to Mariner Energy,
Inc. ("Mariner Energy"). Additionally, Enron and Mariner Holdings entered into
agreements with certain members of the Acquired Company's management providing
for a continued role of management after the Acquisition. In October 1998
Mariner Energy Inc., Joint Energy and other management shareholders exchanged
all of their common shares of Mariner Holdings for an equivalent ownership
percentage in common shares of Mariner Energy LLC. As of December 31, 1999
Mariner Energy LLC owns 100% of Mariner Holdings (collectively, the "Company").
The Company is primarily engaged in the exploration and exploitation for and
development and production of oil and gas reserves, with principal operations in
the Gulf of Mexico and along the U.S. Gulf Coast.
Principles of Consolidation -- The consolidated financial statements
include the Company and all subsidiaries in which a controlling interest is
held. All significant intercompany accounts and transactions have been
eliminated in consolidation.
Cash and Cash Equivalents -- All short-term, highly liquid investments that
have an original maturity date of three months or less are considered cash
equivalents.
Receivables -- Substantially all of the Company's receivables arise from
sales of oil or natural gas, or from reimbursable expenses billed to the other
participants in oil and gas wells for which the Company serves as operator.
Oil and Gas Properties -- Oil and gas properties are accounted for using
the full-cost method of accounting. Consequently, costs directly associated with
the acquisition, exploration and development of oil and gas properties are
capitalized. Costs associated with production and general corporate activities
are expensed. Amortization of oil and gas properties is provided using the
unit-of-production method based on estimated proved oil and gas reserves. No
gains or losses are recognized upon the sale or disposition of oil and gas
properties unless the sale or disposition represents a significant quantity of
oil and gas reserves. The net carrying value of proved oil and gas properties is
limited to an estimate of the future net revenues (discounted at 10%) from
proved oil and gas reserves based on period-end prices and costs plus the lower
of cost or estimated fair value of unproved properties. As a result of this
limitation, permanent impairments of oil and gas properties of approximately
$28,514,000 and $50,800,000 were recorded during 1997 and 1998, respectively. No
writedown was necessary in 1999.
The costs of unproved properties are excluded from amortization using the
full-cost method of accounting. These costs are assessed quarterly for possible
impairments or reduction in value based on geological and geophysical data. If a
reduction in value has occurred, costs being amortized are increased. The
majority of the costs will be evaluated over the next three years.
Other Property and Equipment -- Depreciation of other property and
equipment is provided on a straight-line basis over their estimated useful lives
which range from five to seven years.
F-7
<PAGE>
85
Deferred Loan Costs -- Deferred loan costs, which are included in other
assets, are stated at cost and amortized straight-line over the life of the
related debt.
Income Taxes -- The Acquired Company's taxable income was and the Company's
taxable income is included in a consolidated United States income tax return
with Hardy Holdings Inc. and Mariner Holdings Inc., respectively. The
intercompany tax allocation policy provides that each member of the consolidated
group compute a provision for income taxes on a separate return basis. The
Company records its income taxes using an asset and liability approach which
results in the recognition of deferred tax assets and liabilities for the
expected future tax consequences of temporary differences between the book
carrying amounts and the tax bases of assets and liabilities. (See Note 8)
Capitalized Interest Costs -- The Company capitalizes interest based on the
cost of major development projects which are excluded from current depreciation,
depletion, and amortization calculations. Capitalized interest costs were
approximately $729,000, $1,702,000 and $3,028,000 for the years ended December
31, 1997, 1998 and 1999, respectively.
Accrual for Future Abandonment Costs -- Provision is made for abandonment
costs calculated on a unit-of-production basis, representing the Company's
estimated liability at current prices for estimated costs in the removal and
abandonment of production facilities at the end of the producing life of each
property.
Hedging Program -- The Company utilizes derivative instruments in the form
of natural gas and crude oil price swap and price collar agreements in order to
manage price risk associated with future crude oil and natural gas production
and fixed-price crude oil and natural gas purchase and sale commitments. Such
agreements are accounted for as hedges using the deferral method of accounting.
Gains and losses resulting from these transactions are deferred and included in
other assets or accrued liabilities, as appropriate, until recognized as
operating income in the Company's Consolidated Statement of Operations as the
physical production required by the contracts is delivered.
The net cash flows related to any recognized gains or losses associated
with these hedges are reported as cash flows from operations. If the hedge is
terminated prior to expected maturity, gains or losses are deferred and included
in income in the same period as the physical production required by the
contracts is delivered.
The conditions to be met for a derivative instrument to qualify as a hedge
are the following: (i) the item to be hedged exposes the Company to price risk;
(ii) the derivative reduces the risk exposure and is designated as a hedge at
the time the derivative contract is entered into; and (iii) at the inception of
the hedge and throughout the hedge period there is a high correlation of changes
in the market value of the derivative instrument and the fair value of the
underlying item being hedged.
When the designated item associated with a derivative instrument matures,
is sold, extinguished or terminated, derivative gains or losses are recognized
as part of the gain or loss on sale or settlement of the underlying item. When a
derivative instrument is associated with an anticipated transaction that is no
longer expected to occur or if correlation no longer exists, the gain or loss on
the derivative is recognized in income to the extent the future results have not
been offset by the effects of price or interest rate changes on the hedged item
since the inception of the hedge.
Revenue Recognition -- The Company recognizes oil and gas revenue from its
interests in producing wells as oil and gas from those wells is produced and
sold. Oil and gas sold is not significantly different from the Company's share
of production.
Financial Instruments -- The Company's financial instruments consist of
cash and cash equivalents, receivables, payables, and debt. At December 31, 1998
and 1999, the estimated fair value of the Company's Senior Subordinated Notes
was approximately $100,000,000 and $92,000,000, respectively. The estimated fair
value was determined based on borrowing rates available at December 31, 1998 and
1999, respectively, for debt with similar terms and maturities. The carrying
amount of the Company's other financial instruments approximate fair value.
F-8
<PAGE>
86
Earnings Per Share -- The Company calculates earnings per share by dividing
net income or loss by the weighted average number of outstanding common shares
as the Company has incurred losses since establishing its own capital structure
and therefore any common stock equivalents, options or conversions would be
antidilutive.
Use of Estimates in the Preparation of Financial Statements -- The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amount of revenues and expenses during the reporting period. Actual
results could differ from these estimates.
Major Customers -- During the year ended December 31, 1999, sales of oil
and gas to three purchasers, including an affiliate, accounted for 26%, 21%, and
13% of total revenues. During the year ended December 31, 1998, sales of oil and
gas to four purchasers accounted for 29%, 16%, 15% and 10% of total revenues.
During the year ended December 31, 1997, sales of oil and gas to four purchasers
accounted for 19%, 19%, 18% and 14% of total revenues. Management believes that
the loss of any of these purchasers would not have a material impact on the
Company's financial condition or results of operations.
Recent Accounting Pronouncement -- In June 1998, the Financial Accounting
Standards Board ("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities". SFAS No. 133, as amended is effective for fiscal years beginning
after June 15, 2000 and establishes accounting and reporting standards for
derivative instruments and for hedging activities. The Company will adopt this
statement on January 1, 2001.
2. RELATED-PARTY TRANSACTIONS
Sales to Affiliates -- For the years ending December 31, 1997, 1998 and
1999, sales to affiliates were approximately $13.0 million, $8.9 million and
$16.2 million, respectively.
Affiliate Transactions Subsequent to the Acquisition-- Enron Corp. is the
parent of Enron, and an affiliate of Enron Corp. and Enron is the general
partner of Joint Energy. Accordingly, Enron Corp. may be deemed to control Joint
Energy and the Company. In addition, eight of the Company's directors are
officers of Enron Corp. or affiliates of Enron Corp. Enron Corp. and certain of
its subsidiaries and other affiliates collectively participate in many phases of
the oil and natural gas industry and are, therefore, competitors of the Company.
In addition, Enron and Joint Energy have provided, and may in the future
provide, and another affiliate has assisted, and may in the future assist, in
arranging financing to non-affiliated participants in the oil and natural gas
industry who are or may become competitors of the Company. Because of these
various conflicting interests, Enron, the Company, Joint Energy and the members
of the Company's management have entered into an agreement that is intended to
make clear that Enron Corp. and its affiliates have no duty to make business
opportunities available to the Company.
Transportation Contract -- In 1999 the Company constructed a 29 mile
flowline from a third party platform to the Mississippi Canyon 718 subsea well.
After commissioning, MEGS LLC, an Enron affiliate, purchased the flowline from
the Company and its joint interest partners. The Company received $8.8 million
in cash proceeds which were offset against the cost of constructing the
flowline. No gain or loss was recognized. In addition the Company entered into a
firm transportation contract at a rate of $0.26 per MMbtu with MEGS LLC to
transport its share of 86 Bcf of natural gas from the commencement of production
through March 2009. The Company's working interest at December 31, 1999 was 37%
and will increase to 51% after the project reaches payout.
F-9
<PAGE>
87
The Company expects that from time to time it will engage in various
commercial transactions and have various commercial relationships with Enron
Corp. and certain affiliates of Enron Corp., such as holding and exploring,
exploiting and developing joint working interests in particular prospects and
properties, engaging in hydrocarbon price hedging arrangements and entering into
other oil and gas related or financial transactions. For example, there are
several prospects in which both an affiliate of Enron Corp. and the Company have
working interests. Such interests were acquired in the ordinary course of
business pursuant to bids, joint or otherwise. Any wells drilled will be subject
to joint operating agreements relating to exploration and possible production
and will be subject to customary business terms. Furthermore, the Company has
entered into several agreements with Enron Corp. or affiliates of Enron Corp.
for the purpose of hedging oil and natural gas prices on the Company's future
production. Certain of the Company's debt instruments restrict the Company's
ability to engage in transactions with its affiliates, but those restrictions
are subject to significant exceptions. The Company believes that its current
agreements with Enron Corp. and its affiliates are, and anticipates that any
future agreements with Enron Corp. and its affiliates will be, on terms no less
favorable to the Company than would be contained in an agreement with a third
party.
3. LONG-TERM DEBT
Revolving Credit Facility -- The Company has an unsecured revolving credit
facility (the "Revolving Credit Facility") with Bank of America as agent for a
group of lenders (the "Lenders").
The Revolving Credit Facility provides for a maximum $150 million revolving
credit loan. The available borrowing base under the Revolving Credit Facility
was $60 million as of December 31, 1999 and is subject to periodic
redetermination. The Revolving Credit Facility has an outstanding balance of
$42.6 million at December 31, 1999. On June 28, 1999, the Revolving Credit
Facility was amended to extend the maturity date from October 1, 1999 to October
1, 2002 and to pledge certain Mariner interests to secure the Revolving Credit
Facility.
Borrowings under the Revolving Credit Facility bear interest, at the option
of the Company, at either (i) LIBOR plus 0.75% to 1.25% (depending upon the
level of utilization of the Borrowing Base) or (ii) the higher of (a) the
agent's prime rate or (b) the federal funds rate plus 0.5%. The effective
interest rate at December 31, 1999 was 8.50%. The Company incurs a quarterly
commitment fee ranging from 0.25% to 0.375% per annum on the average unused
portion of the Borrowing Base, depending upon the level of utilization.
The Revolving Credit Facility, as amended, contains various restrictive
covenants which, among other things, restrict the payment of dividends, limit
the amount of debt the Company may incur, limit the Company's ability to make
certain loans and investments, limit the Company's ability to enter into certain
hedge transactions and provide that the Company must maintain specified
relationships between cash flow and fixed charges and cash flow and interest on
indebtedness. As of December 31, 1999, the Company was in compliance with all
such requirements.
ENA Credit Facility -- The Company entered into an agreement with ENA to
provide a $50 million unsecured, subordinated credit facility (the "Facility").
The Facility accrues interest at an annual rate of LIBOR plus 4.5% and required
a structuring fee of 4% of the borrowed amount. The effective interest rate was
10.96% as of December 31, 1999. The Facility requires that a portion of the
proceeds of any private or public equity or debt offering by the Company be
applied to repay amounts outstanding under the Facility.
Senior Credit Facility with ENA -- In April 1999, the Company established a
$25 million short-term credit facility with ENA to obtain funds needed to
execute the Company's 1999 capital expenditure program and for short-term
working capital needs. The borrowing base under the short-term credit facility
is currently $25 million and is subject to periodic redetermination. The
facility accrues interest at an annual rate of LIBOR plus 2.5% and required a
structuring fee of 1% of the committed amount. The effective interest rate at
December 31, 1999 was 8.69%.
Term Loan with ENA --In March 2000, the Company entered into a three year
$112 million unsecured term loan with Enron North America. This facility accrues
interest at an annual rate of 15% and required a structuring fee of 1% of the
committed account. Principal and interest will be payable at the end of the
borrowing term. As part of the loan agreement, the Company issued two five-year
warrants to ENA providing ENA the right to purchase up to 900,000 common shares
of the Company for $0.01 per share. One warrant for 600,000 shares is
exercisable by ENA immediately and another warrant for 300,000 shares is
exercisable on March 21, 2001, if the term loan is unpaid on that date. The fair
value of these warrants was recognized in March 2000 as additional paid in
capital and treated as a debt discount. The terms of the credit facility require
that the Company meet certain financial covenant requirements as well as limit
the Company's ability to incur additional indebtedness.
F-10
<PAGE>
88
10 1/2% Senior Subordinated Notes -- On August 14, 1996 the Company
completed the sale of $100 million principal amount of 10 1/2% Senior
Subordinated Notes Due 2006, (the "Notes"). The proceeds of the Notes were used
by the Company to (i) pay a dividend to Mariner Holdings, which used the
dividend to fully repay a bridge loan from JEDI incurred in the Acquisition, and
(ii) repay the Revolving Credit Facility. The Notes bear interest at 10 1/2%
payable semiannually in arrears on February 1 and August 1 of each year. The
Notes are unsecured obligations of the Company, and are subordinated in right of
payment to all senior debt (as defined in the indenture governing the Notes) of
the Company, including indebtedness under the Revolving Credit Facility.
The indenture pursuant to which the Notes are issued contains certain
covenants that, among other things, limit the ability of the Company to incur
additional indebtedness, pay dividends, redeem capital stock, make investments,
enter into transactions with affiliates, sell assets and engage in mergers and
consolidations. As of December 31, 1999, the Company was in compliance with all
such requirements.
The Notes are redeemable at the option of the Company, in whole or in part,
at any time on or after August 1, 2001, initially at 105.25% of their principal
amount, plus accrued interest, declining ratably to 100% of their principal
amount, plus accrued interest, on or after August 1, 2003. In addition, at the
option of the Company, at any time prior to August 1, 1999, up to an aggregate
of 35% of the original principal amount of the Notes may be redeemable from the
net proceeds of one or more public equity offerings, at 110.5% of their
principal amount, plus accrued interest, provided that any such redemption shall
occur within 60 days of the date of the closing of such public equity offering.
In the event of a change of control of the Company (as defined in the
indenture pursuant to which the Notes are issued), each holder of the Notes (the
"Holder") will have the right to require the Company to repurchase all or any
portion of such Holder's Notes at a purchase price equal to 101% of the
principal amount thereof, plus accrued interest.
Cash paid for interest for the years ending December 31, 1997, 1998 and
1999 was $10.9 million, $15.7 million and $15.1 million, respectively.
5. STOCKHOLDERS' EQUITY
Stock Option Plan -- During June 1996, Mariner Holdings established the
Mariner Holdings, Inc. 1996 Share Option Plan (the "Plan") providing for the
granting of stock options to key employees and consultants. Options granted
under the Plan will not be less than the fair market value of the shares at the
date of grant. The maximum number of shares of Mariner Holdings common shares
that may be issued under the Plan was 142,800. In June 1998, the Plan was
amended to increase the number of eligible shares to be issued to 202,800. In
September 1998, concurrent with the exchange of each common share of Mariner
Holdings for twelve common shares of Mariner Energy LLC the maximum number of
shares of common shares that can be issued under the Plan was 2,433,600.
During the years ending December 31, 1997, 1998 and 1999 the Company
granted stock options of 73,080, 329,172 and 215,748, respectively. No options
have been exercised or cancelled during the three year period. At December 31,
1999, options (the "Options") to purchase 2,228,304 shares had been granted at
exercise prices ranging from $8.33 to $14.58 per share. The Options generally
become exercisable as to one-fifth to one-third on each of the first three or
five anniversaries of the date of grant. The Options expire from seven years to
ten years after the date of grant.
F-11
<PAGE>
89
<TABLE>
<CAPTION>
December 31,
-----------------------------------
1997 1998 1999
--------- --------- ---------
<S> <C> <C> <C>
Options Outstanding
Number of Options.............................. 1,683,384 2,012,556 2,228,304
Weighted average exercise price................ $ 8.33 $ 9.38 $ 9.89
Weighted average fair value.................... 10.82 11.29 18.50
Weighted average contractual term (in years)... 7.00 7.50 7.75
Options Exercisable
Number of Options.............................. 308,266 759,667 1,211,882
Weighted average exercise price................ $ 8.33 $ 8.33 $ 8.91
</TABLE>
The Company applies APB Opinion 25 and related interpretations in
accounting for the Plan. Accordingly, no compensation cost has been recognized
for the Plan. Had compensation cost for the Company's Plan been determined based
on the fair value at the grant date for awards under the Plan consistent with
the method of SFAS No. 123, the Company's net loss for the years ended December
31, 1997, 1998 and 1999 would have increased $777,000, $912,000and $1,172,000,
respectively to $20,987,000, $59,333,000 and $17,515,000 respectively. The
effects of applying SFAS No. 123 in this pro forma disclosure are not indicative
of future amounts. The fair value of each option grant is estimated on the date
of grant using a minimum value option pricing model, risk free interest of 4.6%,
no dividends or volatility and expected life of 5 years. Stock options available
for future grant amounted to 205,296 shares at December 31, 1999. Exercisable
stock options amounted to 1,211,882 shares at December 31, 1999.
Preferred Shares -- The Company Agreement authorizes the issuance of up to
one million preferred shares for the consideration and on the terms and
conditions the board of directors establishes, in its sole discretion, without
the approval of any holders of common shares. Preferred shares may be entitled
to preference over the common shares on dividends, voting rights, conversion or
redemption rights, amounts payable on liquidation and other matters. Preferred
shares of any class or series may be entitled to other rights and privileges, or
subject to other restrictions, the board of directors establishes in its sole
discretion.
Equity Investment-- In June 1998, Mariner Holdings, Inc. issued additional
equity to its existing shareholders, including Joint Energy, for approximately
$14.58 per share, for an aggregate investment of $30 million. Mariner Holdings,
Inc. paid approximately $1.2 million as a structuring fee, on a pro rata basis,
to existing shareholders participating in this transaction. Approximately $1
million of this fee was paid to ECT Securities Corp., an affiliate of Joint
Energy. We believe that the payment of the structuring fee to ECT Securities
Corp. was on terms that are at least as favorable as those that we could have
obtained from unaffiliated parties.
6. EMPLOYEE BENEFIT AND ROYALTY PLANS
Employee Capital Accumulation Plan -- The Company provides all full-time
employees participation in the Employee Capital Accumulation Plan (the "Plan")
which is comprised of a contributory 401(k) savings plan and a discretionary
profit sharing plan. Under the 401(k) feature, the Company, at its sole
discretion, may contribute an employer-matching contribution equal to a
percentage not to exceed 50% of each eligible participant's matched salary
reduction contribution as defined by the Plan. Under the discretionary profit
sharing contribution feature of the Plan, the Company's contribution, if any,
shall be determined annually and shall be 4% of the lesser of the Company's
operating income or total employee compensation and shall be allocated to each
eligible participant pro rata to his or her compensation. During 1997, 1998 and
1999, the Company contributed $200,000, $182,000, and $180,000, respectively, to
the Plan. This plan is a continuation of a plan provided by the Acquired
Company.
Overriding Royalty Interests -- Pursuant to agreements, certain key
employees and consultants are entitled to receive, as incentive compensation,
overriding royalty interests ("Overriding Royalty Interests") in certain oil and
gas prospects acquired by the Company. Such Overriding Royalty Interests entitle
the holder to receive a specified percentage of the gross proceeds from the
future sale of oil and gas (less production taxes), if any, applicable to the
prospects. For the year ending December 31, 1997, 1998 and 1999 the Company paid
$1.3 million, $1.0 million and $1.0 million, respectively.
F-12
<PAGE>
90
7. COMMITMENTS AND CONTINGENCIES
Minimum Future Lease Payments -- The Company leases certain office
facilities and other equipment under long-term operating lease arrangements.
Minimum rental obligations under the Company's operating leases in effect at
December 31, 1999 are as follows (in thousands):
2000......... 1,207
2001......... 1,110
2002......... 1,090
2003......... 1,077
2004......... 1,065
--------
Total $ 5,549
========
Rental expense, before capitalization, was approximately $544,000,
$1,000,000, and $1,170,000 for the years ended December 31, 1997, 1998 and 1999,
respectively.
Hedging Program -- The Company conducts a hedging program with respect to
its sales of crude oil and natural gas using various instruments whereby monthly
settlements are based on the differences between the price or range of prices
specified in the instruments and the settlement price of certain crude oil and
natural gas futures contracts quoted on the open market. The instruments
utilized by the Company differ from futures contracts in that there is no
contractual obligation which requires or allows for the future delivery of the
product.
The following table sets forth the results of hedging transactions during
the periods indicated:
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1998 1999
------------- ------------- -------------
<S> <C> <C> <C>
Natural gas quantity hedged (Mmbtu)..................... 13,573 9,800 18,818
Increase (decrease) in natural gas sales (thousands).... ($3,931) $2,337 ($6,741)
Crude oil quantity hedged (MBbls)....................... 118 0 389
Increase (decrease) in crude oil sales (thousands)...... ($614) $0 ($2,152)
</TABLE>
The following tables set forth the Company's position as of December 31, 1999.
<TABLE>
<CAPTION>
Price Fair Value
Notional ---------------------- Asset / (Liability)
Time Period Quantities Floor Ceiling Fixed (in millions)
----------- ---------- ----- ------- ----- -----------
<S> <C> <C> <C> <C> <C>
Natural Gas (MMBtu)
January 1 - March 31, 2000
Collar purchased 5,460 $ 2.00 $ 2.70 -
Fixed price swap purchased 3,550 $ 2.18 (0.6)
Market sensitive swap sold (1,820) 2.60 (0.5)
April 1 - October 31, 2000
Collar purchased 2,263 2.25 $ 2.49 -
July 1 - December 31, 2000
Fixed price swap purchased 7,445 2.18 (1.7)
January 1 - December 31, 2001
Fixed price swap purchased 4,501 2.18 (1.3)
January 1 - December 31, 2002
Fixed price swap purchased 1,831 2.18 (0.5)
Crude Oil (MBbls)
January 1 - December 31, 2000
Fixed price swap purchased 1,482 18.66 (5.6)
-----
(10.2)
</TABLE>
F-13
<PAGE>
91
Subsequent to year-end, we purchased a natural gas collar for a notional
quantity of 5,550 MMbtu with a floor of $3.50 per Mmbtu and a ceiling of $4.92
per Mmbtu for the time period October 1, 2000 through September 30, 2001. In
addition we purchased a floor option for a notional quantity of 5,551 Mmbtu at
$3.50 per Mmbtu for the time period October 1, 2000 through September 30, 2001.
The fair value of our hedging instruments was determined based on a broker's
forward price quote and a NYMEX forward price quote as of December 31, 1999. As
of December 31, 1999, a commodity price increase of 10% would have resulted in
an unfavorable change in fair value of $7.4 million and a commodity price
decrease of 10% would have resulted in a favorable change in fair value of $7.3
million.
Deepwater Rig -- In the fourth quarter of 1999, Noble Drilling Corporation
filed suit against the Company alleging breech of contract regarding a letter of
intent for a five year Deepwater rig contract. In February 2000, both the
Company and Noble Drilling Corporation entered into a settlement agreement
whereby the lawsuit was dismissed and the Company committed to using this
Deepwater rig for a minimum of 660 days over a five-year period at market-based
day rates for comparable drilling rigs in comparable water depths subject to a
floor day rate ranging from $65,000 to $125,000. In exchange for market-based
day rates, Noble Drilling was assigned working interests in seven of the
Company's deepwater exploration prospects. The Company will pay Noble Drilling's
share of the costs of drilling the initial test well on each of these prospects.
Litigation -- In the ordinary course of business, the Company is a claimant
and/or a defendant in various legal proceedings, including proceedings as to
which the Company has insurance coverage. The Company does not consider its
exposure in these proceedings, individually or in the aggregate, to be material.
In December, 1996, ETOCO, Inc., which owns a 20% interest in one producing
well operated by the Company, filed a lawsuit against the Company in the
district court of Hardin County, Texas, alleging damage due to the Company's
refusal to drill an additional well. In April 1998, after a trial on the merits,
a jury awarded ETOCO $2.38 million in damages. In August, the court awarded
ETOCO $0.5 million in attorneys' fees. On February 8, 1999, the case was
settled.
8. INCOME TAXES
The following table sets forth a reconciliation of the statutory federal
income tax with the income tax provision (in thousands):
<TABLE>
<CAPTION>
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
1997 1998 1999
------------------ ------------------ ------------------
$ % $ % $ %
------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Income (loss) before income taxes .............................. (20,210) -- (58,421) -- (16,343) --
Income tax expense (benefit) computed at statutory rates........ (7,074) (35) (20,447) (35) (5,720) (35)
Change in valuation allowances ................................. 6,871 34 18,804 32 5,658 34
Other .......................................................... 203 1 1,643 3 62 1
------- ------- ------- ------- ------- -------
Tax expense .................................................... -- -- -- -- -- --
======= ======= ======= ======= ======= =======
</TABLE>
No federal income taxes were paid by the Company during the years ended
December 31, 1997, 1998 or 1999.
The Company's deferred tax position reflects the net tax effects of the
temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax reporting.
Significant components of the deferred tax assets and liabilities are as follows
(in thousands):
F-14
<PAGE>
92
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1997 1998 1999
-------- -------- --------
<S> <C> <C> <C>
Deferred tax assets:
Net operating loss carry forwards ...................... $ 10,410 $ 34,771 $ 46,728
Differences between book and tax bases of properties.... 4,586 -- --
-------- -------- --------
14,996 34,771 46,728
Valuation allowance ...................................... (14,996) (33,800) (39,458)
-------- -------- --------
Total net deferred tax assets ............................ -- 971 7,270
-------- -------- --------
Deferred tax liabilities ............................... -- (971) 7,270
Differences between book and taxbases of properties -------- -------- --------
Total net deferred taxes ....................... $ -- $ -- $ --
-------- -------- --------
</TABLE>
As of December 31, 1999, the Company has a cumulative net operating loss
carryforward ("NOL") for federal income tax purposes of approximately $132
million, which begins to expire in the year 2011. A valuation allowance is
recorded against tax assets which are not likely to be realized. Because of the
uncertain nature of their ultimate realization, as well as past performance and
the NOL expiration date, the Company has established a valuation allowance
against this NOL carryforward benefit and for all net deferred tax assets in
excess of net deferred tax liabilities.
9. OIL AND GAS PRODUCING ACTIVITIES and CAPITALIZED COSTS
The results of operations from the Company's oil and gas producing
activities were as follows (in thousands):
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
1997 1998 1999
---------- ---------- ----------
Oil and gas sales ....................... $ 62,771 $ 56,690 $ 52,468
Production costs ........................ (9,376) (9,858) (11,453)
Depreciation, depletion and amortization. (31,719) (33,833) (32,526)
Impairment of oil and gas properties .... (28,514) (50,800) --
Income tax expense ...................... -- -- --
-------- -------- --------
Results of operations ......... $ (6,838) $(37,801) $ 8,489
======== ======== ========
Costs incurred in property acquisition, exploration and development
activities were as follows (in thousands, except per equivalent mcf amounts):
Year Ended December 31,
------------------------------
1997 1998 1999
-------- -------- --------
Property acquisition costs unproved properties. $ 21,569 $ 43,143 $ 10,449
Property acquisition costs proved properties... 3,250 -- --
Exploration costs ............................. 27,364 35,674 13,522
Development costs ............................. 16,134 61,960 56,852
-------- -------- --------
Total costs ......................... $ 68,317 $140,777 $ 80,823
======== ======== ========
Depreciation, depletion and amortization
rate per equivalent Mcf before impairment
provisions .................................... $ 1.33 $ 1.40 $ 1.31
-------- -------- --------
Under the full cost method of accounting, the Company capitalizes costs
directly associated with acquisition, exploration and development of oil and gas
properties. Such costs were approximately $4,418,000, $6,386,000, and $9,440,000
for the years ended December 31, 1997, 1998 and 1999, respectively.
The following table summarizes costs related to unevaluated properties
which have been excluded from amounts subject to amortization at December 31,
1999. The Company regularly evaluates these costs to determine whether
impairment has occurred. The majority of these costs are expected to be
evaluated and included in the amortization base within three years.
F-15
<PAGE>
93
Year Ended December 31, Total at
--------------------------- December 31,
1997 1998 1999 1999
------- ------- ------- -------
Property acquisition costs $20,827 $44,203 $10,993 $76,023
Exploration costs ........ 10 115 5,749 5,874
------- ------- ------- -------
Total .......... $20,837 $44,318 $16,742 $81,897
======= ======= ======= =======
Approximately 97% of excluded costs at December 31, 1999 relate to
activities in the Deepwater Gulf of Mexico and the remaining 3% relates to
activities in the Gulf of Mexico shallow waters and onshore areas near the Gulf.
10. SUPPLEMENTAL OIL AND GAS RESERVE AND STANDARDIZED MEASURE
INFORMATION (UNAUDITED)
Estimated proved net recoverable reserves as shown below include only those
quantities that are expected to be commercially recoverable at prices and costs
in effect at the balance sheet dates under existing regulatory practices and
with conventional equipment and operating methods. Proved developed reserves
represent only those reserves expected to be recovered through existing wells.
Proved undeveloped reserves include those reserves expected to be recovered from
new wells on undrilled acreage or from existing wells on which a relatively
major expenditure is required for recompletion. Also included in the Company's
proved undeveloped reserves as of December 31, 1999 were reserves expected to be
recovered from wells for which certain drilling and completion operations had
occurred as of that date, but for which significant future capital expenditures
were required to bring the wells into commercial production.
Reserve estimates are inherently imprecise and may change as additional
information becomes available. Furthermore, estimates of oil and gas reserves,
of necessity, are projections based on engineering data, and there are
uncertainties inherent in the interpretation of such data as well as in the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured
exactly, and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
Accordingly, estimates of the economically recoverable quantities of oil and
natural gas attributable to any particular group of properties, classifications
of such reserves based on risk of recovery and estimates of the future net cash
flows expected therefrom prepared by different engineers or by the same
engineers at different times may vary substantially. There also can be no
assurance that the reserves set forth herein will ultimately be produced or that
the proved undeveloped reserves set forth herein will be developed within the
periods anticipated. It is likely that variances from the estimates will be
material. In addition, the estimates of future net revenues from proved reserves
of the Company and the present value thereof are based upon certain assumptions
about future production levels, prices and costs that may not be correct when
judged against actual subsequent experience. The Company emphasizes with respect
to the estimates prepared by Ryder Scott Company, L.P., independent petroleum
engineers, that the discounted future net cash flows should not be construed as
representative of the fair market value of the proved reserves owned by the
Company since discounted future net cash flows are based upon projected cash
flows which do not provide for changes in oil and natural gas prices from those
in effect on the date indicated or for escalation of expenses and capital costs
subsequent to such date. The meaningfulness of such estimates is highly
dependent upon the accuracy of the assumptions upon which they are based. Actual
results will differ, and are likely to differ materially, from the results
estimated.
F-16
<PAGE>
94
Estimated Quantities of Proved Reserves
Oil (Bbl) Gas (Mcf)
----------- -----------
(in thousands)
December 31, 1996 .................................. 5,280 92,284
Revisions of previous estimates .................. 210 (1,817)
Extensions, discoveries and other additions ...... 2,062 46,166
Purchase of reserves in place .................... 55 2,737
Production ....................................... (977) (18,004)
-------- --------
December 31, 1997 .................................. 6,630 121,366
Revisions of previous estimates .................. (836) (410)
Extensions, discoveries and other additions....... 4,351 27,416
Production ....................................... (786) (19,477)
-------- --------
December 31, 1998 .................................. 9,359 128,895
======== ========
Revisions of previous estimates .................. 715 (5,098)
Extensions, discoveries and other additions....... 1,225 24,972
Sale of reserves in place......................... (742) (8,856)
Production ....................................... (630) (21,123)
-------- --------
December 31, 1999 .................................. 9,927 118,790
======== ========
Estimated Quantities of Proved Developed Reserves
Oil (Bbl) Gas (Mcf)
(in thousands)
December 31, 1997... 3,486 76,343
December 31, 1998... 2,886 86,024
December 31, 1999... 3,799 82,760
The following is a summary of a standardized measure of discounted net cash
flows related to the Company's proved oil and gas reserves. The information
presented is based on a valuation of proved reserves using discounted cash flows
based on year-end prices, costs and economic conditions and a 10% discount rate.
The additions to proved reserves from new discoveries and extensions could vary
significantly from year to year. Additionally, the impact of changes to reflect
current prices and costs of reserves proved in prior years could also be
significant. Accordingly, the information presented below should not be viewed
as an estimate of the fair value of the Company's oil and gas properties, nor
should it be considered indicative of any trends.
Standardized Measure of Discounted Future Net Cash Flows
(in thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------
1997 1998 1999
--------- --------- ---------
<S> <C> <C> <C>
Future cash inflows ....................................... $ 447,681 $ 383,490 $ 490,239
Future production costs ................................... (109,405) (103,400) (122,681)
Future development costs .................................. (73,568) (81,090) (70,774)
Future income taxes ....................................... (35,346) -- --
--------- --------- ---------
Future net cash flows ..................................... 229,362 199,000 296,784
Discount of future net cash flows at 10% per annum......... (52,903) (51,371) (85,558)
--------- --------- ---------
Standardized measure of discounted future net cash flows... $ 176,459 $ 147,629 $ 211,226
========= ========= =========
</TABLE>
During recent years, there have been significant fluctuations in the prices
paid for crude oil in the world markets and in the United States, including the
posted prices paid by purchasers of the Company's crude oil. The year-end
average prices of oil and gas at December 31, 1997, 1998 and 1999, used in the
above table, were $16.43, $10.36, and $23.85 per Bbl, respectively, and $2.79,
$2.22, and $2.23 per Mcf, respectively.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands):
F-17
<PAGE>
95
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------
1997 1998 1999
--------- --------- ---------
<S> <C> <C> <C>
Sales and transfers of oil and gas produced, net of production costs ....... $ (53,395) $ (46,832) $ (41,015)
Net changes in prices and production costs ................................. (132,658) (67,815) 77,532
Extensions and discoveries, net of future development and production costs.. 42,717 23,730 33,357
Development costs during period and net change in development costs ....... 4,188 30,799 (3,661)
Revision of previous quantity estimates .................................... (730) (6,846) (984)
Purchases of reserves in place ............................................. 6,071 -- --
Sales of reserves in place ................................................. -- -- (15,535)
Net change in income taxes ................................................. 29,619 27,193 --
Accretion of discount before income taxes .................................. 30,336 20,365 19,900
Changes in production rates (timing) and other ............................. (4,065) (9,424) (5,997)
--------- --------- ---------
Net change ................................................................. $ (77,917) $ (28,830) $ 63,597
========= ========= =========
</TABLE>
*****************************************************************************
F-18
<PAGE>
96
MARINER ENERGY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
ASSETS
<TABLE>
<CAPTION>
June 30,
December 31, 2000
1999 (unaudited)
-------------- --------------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents............................. $ 123 $ 6,181
Receivables........................................... 22,766 43,395
Prepaid expenses and other............................ 4,891 6,853
--------- ---------
Total current assets.......................... 27,780 56,429
--------- ---------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at full cost:
Proved............................................. 379,301 417,824
Unproved, not subject to amortization.............. 81,897 68,238
--------- ---------
Total......................................... 461,198 486,062
Other property and equipment.......................... 3,982 4,082
Accumulated depreciation, depletion and amortization.. (199,233) (227,190)
--------- ---------
Total property and equipment, net............. 265,947 262,954
--------- ---------
OTHER ASSETS, NET OF AMORTIZATION....................... 3,489 4,748
--------- ---------
TOTAL ASSETS............................................ $ 297,216 $ 324,131
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable...................................... $ 30,269 $ 18,668
Accrued liabilities................................... 25,389 43,244
Accrued interest...................................... 8,868 4,397
--------- ---------
Total current liabilities..................... 64,526 66,309
--------- ---------
ACCRUAL FOR FUTURE ABANDONMENT COSTS.................... 4,226 5,516
LONG-TERM DEBT:
Subordinated notes..................................... 99,673 99,698
Revolving credit facility............................. 42,600 20,000
Senior credit facility................................ 25,000
Enron credit facility................................. 50,000 --
ENA term loan......................................... -- 104,419
--------- ---------
Total long-term debt.......................... 217,273 224,117
--------- ---------
STOCKHOLDERS' EQUITY:
Preferred Stock $0.01 par value
(authorized 1,000,000 shares, none issued)......... -- --
Common stock, $.01 par value;
50,000,000 shares authorized, 13,928,304
issued and outstanding, at June 30, 2000
and December 31, 1999, respectively.................. 139 139
Additional paid-in-capital............................ 124,718 136,299
Accumulated deficit................................... (113,666) (108,249)
--------- ---------
Total stockholders' equity.................... 11,191 28,189
--------- ---------
TOTAL LIABILITIES and STOCKHOLDERS' EQUITY.............. $ 297,216 $ 324,131
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-19
<PAGE>
97
MARINER ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except share data)
Six Months Ended
June 30,
----------------------------
1999 2000
------------ ------------
REVENUES:
Oil sales .............................. $ 4,624 $ 16,691
Gas sales .............................. 21,222 41,617
------------ ------------
Total revenues ................. 25,846 58,308
------------ ------------
COSTS AND EXPENSES:
Lease operating expenses ............... 5,764 8,470
Depreciation, depletion and amortization 15,803 29,134
General and administrative expenses .... 2,821 3,254
------------ ------------
Total costs and expenses ....... 24,388 40,858
------------ ------------
OPERATING INCOME ......................... 1,489 17,450
------------ ------------
INTEREST:
Income ................................. 21 53
Expense ................................ (9,924) (12,086)
LOSS BEFORE TAXES ........................ (8,445) 5,417
PROVISION FOR INCOME TAXES ............... -- --
------------ ------------
NET INCOME (LOSS)......................... $ (8,445) $ 5,417
============ ============
BASIC AND DILUTED LOSS PER SHARE ......... $ (0.61) $ 0.39
============ ============
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 13,928,304 13,928,304
============ ============
The accompanying notes are an integral part of these financial statements.
F-20
<PAGE>
98
MARINER ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)
Six Months Ended
June 30,
---------------------
1999 2000
---------- ---------
OPERATING ACTIVITIES:
Net income (loss)..................................... $ (8,445) $ 5,417
Adjustments to reconcile net loss to net cash
provided by (used for) operating activities:
Depreciation, depletion and amortization .......... 16,059 29,271
Interest paid in kind ............................. -- 3,374
Changes in operating assets and liabilities:
Receivables ....................................... (2,010) (20,629)
Other current assets .............................. (32) (1,962)
Other assets ...................................... 222 (1,259)
Accounts payable and accrued liabilities .......... (27,382) 1,783
--------- ---------
Net cash provided by (used for) operating activities.. (21,588) 15,995
--------- ---------
INVESTING ACTIVITIES:
Additions to oil and gas properties .................. (38,758) (53,866)
Proceeds from property conveyances ................... 19,758 29,002
Additions to other property and equipment ............ (290) (100)
--------- ---------
Net cash used in investing activities ............. (19,290) (24,964)
--------- ---------
FINANCING ACTIVITIES:
Proceeds from (repayment of) revolving credit facility (9,400) (22,600)
Proceeds from the affiliate credit facilities ........ 50,000 --
Payment of Senior credit facility .................... -- (25,000)
Payment of Enron credit facility ..................... -- (50,000)
Proceeds from ENA term loan .......................... -- 112,627
--------- ---------
Net cash provided by financing activities ......... 40,600 15,027
--------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ....... (278) 6,058
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ....... 802 123
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ............. $ 524 $ 6,181
========= =========
The accompanying notes are an integral part of these financial statements.
F-21
<PAGE>
99
MARINER ENERGY LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. Basis of Presentation
The financial statements of Mariner Energy, LLC. (the "Company") included
herein have been prepared, without audit, pursuant to the rules and regulations
of the Securities and Exchange Commission ("SEC"). Accordingly, they reflect all
adjustments (consisting only of normal, recurring accruals) which are, in the
opinion of management, necessary for a fair presentation of the financial
results for the interim periods. Certain information and notes normally included
in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such rules and
regulations, although the Company believes that the disclosures are adequate to
make the information presented not misleading. These financial statements should
be read in conjunction with the financial statements and notes thereto included
elsewhere in this filing for the year ended December 31, 1999. The results of
operations for the six months ending June 30, 2000 and the cash flows for the
six months ending June 30, 2000 are not necessarily indicative of the results
for the full year.
2. Oil and Gas Properties
Under the full cost method of accounting for oil and gas properties, the
net carrying value of proved oil and gas properties is limited to an estimate of
the future net revenues, discounted at 10%, from proved oil and gas reserves
based on period-end prices and costs plus the lower of cost or estimated fair
value of unproved properties.
3. Revolving Credit Facility
In April 2000 the Company requested a $10 million borrowing base increase
under the terms of the Revolving Credit Agreement. This increase was approved in
May 2000, raising the borrowing base from $60 million to $70 million.
4. Term Loan With ENA
In March 2000, the Company entered into a three year $112 million unsecured
term loan with Enron North America. This facility accrues interest at an annual
rate of 15% and required a structuring fee of 1% of the committed account.
Proceeds from the term loan were used to repay the Senior and Enron Credit
Facilities. Principal and interest will be payable at the end of the borrowing
term. As part of the loan agreement, the Company issued two five-year warrants
to ENA providing ENA the right to purchase up to 900,000 common shares of the
Company for $0.01 per share. One warrant for 600,000 shares is exercisable by
ENA immediately and another warrant for 300,000 shares is exercisable on March
21, 2001, if the term loan is unpaid on that date. The fair value of these
warrants of $11.6 million was recognized as additional paid in capital and
treated as a debt discount. The terms of the loan require that the Company meet
certain financial covenant requirements as well as limit the Company's ability
to incur additional indebtedness.
5. Commitments and Contingencies
Hedging Program -- The Company conducts a hedging program with respect to
its sales of crude oil and natural gas using various instruments whereby monthly
settlements are based on the differences between the price or range of prices
specified in the instruments and the settlement price of certain crude oil and
natural gas futures contracts quoted on the open market. The instruments
utilized by the Company differ from futures contracts in that there is no
contractual obligation which requires or allows for the future delivery of the
product. The counter party to all of the Company's current contracts are with an
affiliate.
F-22
<PAGE>
100
The following table sets forth the Company's position as of June 30, 2000:
<TABLE>
<CAPTION>
Price Fair Value
Notional ---------------------------- Asset / (Liability)
Time Period Quantities Floor Ceiling Fixed (in millions)
----------- ---------- ----- ------- ----- -----------
<S> <C> <C> <C> <C> <C>
Natural Gas (MMBtu)
July 1 - December 31, 2000
Collar purchased 1,353 $ 2.25 $ 2.49 $ (2.9)
Fixed price swap purchased 4,407 $ 2.18 (10.7)
January 1 - December 31, 2001
Fixed price swap purchased 4,501 2.18 (7.4)
January 1 - December 31, 2002
Fixed price swap purchased 1,831 2.18 (1.8)
Crude Oil (MBbls)
July 1 - December 31, 2000
Fixed price swap purchased 1,155 18.46 (9.8)
Market sensitive price swap sold (416) 24.16 2.4
------
Total $(30.2)
======
</TABLE>
Subsequent to June 30, 2000, we purchased a natural gas collar for a
notional quantity of 5,550 MMbtu with a floor of $3.50 per Mmbtu and a ceiling
of $4.92 per Mmbtu for the time period October 1, 2000 through September 30,
2001. The Company also purchased a floor option for a notional quantity of 5,551
Mmbtu at $3.50 per Mmbtu for the time period October 1, 2000 through September
30, 2001. The fair value of our hedging instruments was determined based on a
broker's forward price quote and a NYMEX forward price quote as of June 30,
2000. As of June 30, 2000, a commodity price increase of 10% would have resulted
in an unfavorable change in fair value of $8.4 million and a commodity price
decrease of 10% would have resulted in a favorable change in fair value of $8.4
million.
Royalty Relief - Currently, the Company's Pluto well on Mississippi Canyon
Block 674 is not required to pay royalties to the Minerals Management Service
("MMS"). This royalty relief was granted assuming oil and natural gas prices
remained below certain predetermined levels. If average commodity prices for
2000 exceed these predetermined levels, the Company may be required to pay up to
$7 million in royalties to the MMS.
Litigation - The Company, in the ordinary course of business, is a claimant
and/or a defendant in various legal proceedings, including proceedings as to
which the Company has insurance coverage. The Company does not consider its
exposure in these proceedings, individually and in the aggregate, to be
material.
6. New Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities". SFAS No. 133, as amended, is
effective for fiscal years beginning after June 15, 2000 and establishes
accounting and reporting standards for derivative instruments and for hedging
activities. Had the Company implemented SFAS No. 133 as of June 30, 2000, a
$30.2 million liability would have been recorded. The offset at the future date
of implementation, would be reflected as a cumulative effect adjustment to
income as other comprehensive income in stockholder's equity. The Company will
adopt this statement on January 1, 2001.
In December 1999, the Securities and Exchange Commission ("SEC") issued
Staff Accounting Bulletin ("SAB") No. 101, "Revenue Recognition in Financial
Statements." SAB 101 summarizes certain of the SEC's views in applying generally
accepted accounting principles to revenue recognition in financial statements.
The Company is required to adopt SAB 101, as amended, in the fourth quarter of
fiscal 2000. The Company does not expect the adoption of SAB 101 to have a
material effect on its financial position or results of operations.
F-23
<PAGE>
101
APPENDIX A
Ryder Scott Letterhead
March 7, 2000
Mariner Energy, Inc.
580 WestLake Park Blvd., Suite 1300
Houston, Texas 77079
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold interests of Mariner
Energy, Inc. (Mariner) as of January 1, 2000. The subject properties are located
in the states of Louisiana, Mississippi, and Texas and in the federal waters
offshore Louisiana and Texas. The income data were estimated using the
Securities and Exchange Commission (SEC) guidelines for future price and cost
parameters.
The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. December 1999 hydrocarbon prices were used in
the preparation of this report as required by SEC guidelines; however, actual
future prices may vary significantly from December 1999 prices. Therefore,
volumes of reserves actually recovered and amounts of income actually received
may differ significantly from the estimated quantities presented in this report.
The results of this study are summarized below.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold Interests of
Mariner Energy, Inc.
As of January 1, 2000
----------------------------------------------------------------------------
<TABLE>
<CAPTION>
Proved
---------------------------------------------------------
Developed
----------------------------- Total
Producing Non-Producing Undeveloped Proved
------------ ------------- ----------- ------------
<S> <C> <C> <C> <C>
Net Remaining Reserves
Oil/Condensate - Barrels ................ 3,630,055 158,931 6,125,830 9,914,816
Plant Products - Barrels ................ 4,292 6,003 1,385 11,680
Gas - MMCF .............................. 73,308 9,452 36,030 118,790
Income Data
Future Gross Revenue .................... $246,981,784 $ 24,406,318 $218,853,706 $490,238,808
Deductions .............................. 70,401,284 8,177,354 114,876,803 193,455,441
------------ ------------ ------------ ------------
Future Net Income (FNI) ................. $176,580,500 $ 16,228,964 $103,973,903 $296,783,367
Discounted FNI @ 10% .................... $141,110,144 $ 12,552,032 $ 57,563,969 $211,226,145
</TABLE>
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas
volumes are sales gas expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of the areas in which the gas reserves are
located.
The future gross revenue is after the deduction of production taxes. The
deductions are comprised of the normal direct costs of operating the wells, ad
valorem taxes, recompletion costs, development costs, and certain abandonment
costs net of salvage. The future net income is before the deduction of state and
federal income taxes and general administrative overhead, and has not been
adjusted for outstanding loans that may exist nor does it include any adjustment
for cash on hand or undistributed income. No attempt was made to quantify or
otherwise account for any accumulated gas production imbalances that may exist.
Gas reserves account for approximately 52.8 percent, liquid hydrocarbon account
for approximately 47.1 percent, and plant product reserves account for the
remaining .1 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded monthly. Future net income was
discounted at four other discount rates which were also compounded monthly.
These results are shown on each estimated projection of future production and
income presented in a later section of this report and in summary form below.
<PAGE>
102
Discounted Future
Net Income
As of
January 1, 2000
--------------------------------
Discount Rate Total
Percent Proved
--------------- ------------
15 $187,191,557
20 $168,461,313
25 $153,163,797
30 $140,291,355
The results shown above are presented for your information and should not
be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission Staff Accounting Bulletins. The definitions
of proved, probable, and possible reserves are included under the tab "Reserve
Definitions and Pricing Assumptions" in this report.
Estimates of Reserves
In general, the reserves included herein were estimated by performance
methods or the volumetric method; however, other methods were used in certain
cases where characteristics of the data indicated such other methods were more
appropriate in our opinion. The reserves estimated by the performance method
utilized extrapolations of various historical data in those cases where such
data were definitive. Reserves were estimated by the volumetric method in those
cases where there were inadequate historical performance data to establish a
definitive trend or where the use of production performance data as a basis for
the reserve estimates was considered to be inappropriate.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.
Future Production Rates
Initial production rates are based on the current producing rates for those
wells now on production. Test data and other related information were used to
estimate the anticipated initial production rates for those wells or locations
which are not currently producing. If no production decline trend has been
established, future production rates were held constant, or adjusted for the
effects of curtailment where appropriate, until a decline in ability to produce
was anticipated. An estimated rate of decline was then applied to depletion of
the reserves. If a decline trend has been established, this trend was used as
the basis for estimating future production rates. For reserves not yet on
production, sales were estimated to commence at an anticipated date furnished by
Mariner.
In general, we estimate that future gas production rates limited by
allowables or marketing conditions will continue to be the same as the average
rate for the latest available 12 months of actual production until such time
that the well or wells are incapable of producing at this rate. The well or
wells were then projected to decline at their decreasing delivery capacity rate.
Our general policy on estimates of future gas production rates is adjusted when
necessary to reflect actual gas market conditions in specific cases.
The future production rates from wells now on production may be more or
less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.
<PAGE>
103
Hydrocarbon Prices
Mariner furnished us with prices in effect at January 1, 2000 and these
prices were held constant except for known and determinable escalations. In
accordance with Securities and Exchange Commission guidelines, changes in liquid
and gas prices subsequent to December 31, 1999, were not taken into account in
this report. Future prices used in this report are discussed in more detail
under the tab "Reserve Definitions and Pricing Assumptions" in this report.
Costs
Operating costs for the leases and wells in this report are based on the
operating expense reports of Mariner and include only those costs directly
applicable to the leases or wells. When applicable, the operating costs include
a portion of general and administrative costs allocated directly to the leases
and wells under terms of operating agreements. No deduction was made for
indirect costs such as general administration and overhead expenses, loan
repayments, interest expenses, and exploration and development prepayments that
are not charged directly to the leases or wells.
Development costs were furnished to us by Mariner and are based on
authorizations for expenditure for the proposed work or actual costs for similar
projects. The estimated net cost of abandonment after salvage was included for
properties where abandonment costs net of salvage are significant. The estimates
of the net abandonment costs furnished by Mariner were accepted without
independent verification.
Current costs were held constant throughout the life of the properties.
General
Table A presents a one line summary of proved reserve and income data for
each of the subject properties which are ranked according to their future net
income discounted at 10 percent per year. Table B presents a one line summary of
gross and net reserves and income data for each of the subject properties. Table
C presents a one line summary of initial basic data for each of the subject
properties. Tables 1 through 335 present our estimated projection of production
and income by years beginning January 1, 2000, by state, field, and lease or
well.
While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were, in accordance with rules adopted by the SEC, omitted from consideration in
making this evaluation.
The estimates of reserves presented herein were based upon a detailed study
of the properties in which Mariner owns an interest; however, we have not made
any field examination of the properties. No consideration was given in this
report to potential environmental liabilities which may exist nor were any costs
included for potential liability to restore and clean up damages, if any, caused
by past operating practices. Mariner has informed us that they have furnished us
all of the accounts, records, geological and engineering data, and reports and
other data required for this investigation. The ownership interests, prices, and
other factual data furnished by Mariner were accepted without independent
verification. The estimates presented in this report are based on data available
through December 1999.
Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation is
contingent on our estimates of reserves and future income for the subject
properties.
This report was prepared for the exclusive use and sole benefit of Mariner
Energy, Inc. The data, work papers, and maps used in this report are available
for examination by authorized parties in our offices. Please contact us if we
can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
Timothy J. Torres, P.E.
Petroleum Engineer
JRW/sw
Approved:
/s/ John R. Warner, P.E._______
John R. Warner, P.E.
Senior Vice President
<PAGE>
104
DEFINITIONS OF RESERVES
PROVED RESERVES (SEC DEFINITION)
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalation based on
future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. In certain instances,
proved reserves are assigned on the basis of a combination of core analysis and
electrical and other type logs which indicate the reservoirs are analogous to
reservoirs in the same field which are producing or have demonstrated the
ability to produce on a formation test. The area of a reservoir considered
proved includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Proved natural gas reserves are comprised of non-associated, associated and
dissolved gas. An appropriate reduction in gas reserves has been made for the
expected removal of natural gas liquids, for lease and plant fuel, and for the
exclusion of non-hydrocarbon gases if they occur in significant quantities and
are removed prior to sale. Estimates of proved reserves do not include crude
oil, natural gas, or natural gas liquids being held in underground or surface
storage.
Proved reserves are estimates of hydrocarbons to be recovered from a given
date forward. They may be revised as hydrocarbons are produced and additional
data become available.
<PAGE>
105
Reserve Status Categories
Reserve status categories define the development and producing status of
wells and/or reservoirs.
Proved Developed (SEC Definition)
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Developed reserves may be subcategorized as producing or non-producing
using the SPE/SPEE Definitions:
Producing
Producing reserves are expected to be recovered from completion intervals
open at the time of the estimate and producing. Improved recovery reserves
are considered to be producing only after an improved recovery project is
in operation.
Non-Producing
Non-producing reserves include shut-in and behind pipe reserves. Shut-in
reserves are expected to be recovered from completion intervals open at the
time of the estimate, but which had not started producing, or were shut-in
for market conditions or pipeline connection, or were not capable of
production for mechanical reasons, and the time when sales will start is
uncertain. Behind pipe reserves are expected to be recovered from zones
behind casing in existing wells, which will require additional completion
work or a future recompletion prior to the start of production.
Proved Undeveloped (SEC Definition)
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Estimates for proved undeveloped reserves are attributable to any
acreage for which an application of fluid injection or other improved technique
is contemplated, only when such techniques have been proved effective by actual
tests in the area and in the same reservoir.
<PAGE>
106
HYDROCARBON PRICING PARAMETERS
Securities and Exchange Commission Parameters
Oil and Condensate
Mariner furnished us with oil and condensate prices in effect at December
31, 1999 and these prices were held constant to depletion of the properties. In
accordance with Securities and Exchange Commission guidelines, changes in liquid
prices subsequent to December 31, 1999 were not considered in this report.
Plant Products
Mariner furnished us with plant product prices in effect at December 31,
1999 and these prices were held constant to depletion of the properties.
Gas
Mariner furnished us with gas prices in effect at December 31, 1999 and
with its forecasts of future gas prices which take into account SEC guidelines,
current spot market prices, contract prices, and fixed and determinable price
escalations where applicable. In accordance with SEC guidelines, the future gas
prices used in this report make no allowances for future gas price increases
which may occur as a result of inflation nor do they make any allowance for
seasonal variations in gas prices which may cause future yearly average gas
prices to be somewhat lower than December 31, 1999 gas prices. For gas sold
under contract, the contract gas price including fixed and determinable
escalations, exclusive of inflation adjustments, was used until the contract
expires and then was adjusted to the current market price for the area and held
at this adjusted price to depletion of the reserves.
<PAGE>
107
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. Expenses of the Offering
The estimated expenses in connection with the Offering are:
Securities and Exchange Commission Registration
Fee............................................ $ 55,600
NASD Filing Fee................................ 20,500
NASDAQ Listing Fee............................. 95,000
Legal Fees and Expenses........................ 350,000
Accounting Fees and Expenses................... 150,000
Engineering Fees and Expenses.................. 120,000
Printing Expenses.............................. 115,000
Transfer Agent and Registrar Fees.............. 5,000
Miscellaneous.................................. 88,900
------------
Total................................ $ 1,000,000
============
ITEM 14. Indemnification of Directors and Officers.
The limited liability agreement (the "Company Agreement") of Mariner Energy
LLC (the "Company") contains provisions that eliminate the personal liability of
a director to the Company and its shareholders for monetary damages for breach
of his fiduciary duty as a director to the extent currently allowed under the
Delaware General Corporation Law ("Delaware Corporation Law") and to the extent
that Delaware law may impose a duty on certain persons to bring or share a
business opportunity with the Company. These provisions are discussed in greater
detail under the heading "Description of Our Company Agreement and Common
Shares" in the prospectus included in this registration statement. If a director
were to breach this duty in performing his duties as a director, neither the
Company nor its shareholders could recover monetary damages from the director,
and the only course of action available to the Company's shareholders would be
equitable remedies, such as an action to enjoin or rescind a transaction
involving a breach of fiduciary duty. To the extent certain claims against
directors are limited to equitable remedies, the Company Agreement may therefore
reduce the likelihood of derivative litigation and may discourage shareholders
or management from initiating litigation against directors for breach of their
fiduciary duty. Additionally, equitable remedies may not be effective in many
situations. If a shareholder's only remedy is to enjoin the completion of the
directors' action, the remedy would be ineffective if the shareholder does not
become aware of a transaction or event until after it has been completed. In
that situation, it is possible that the shareholders and the Company would have
no effective remedy against the directors. Under the Company Agreement,
liability for monetary damages remains for (i) any breach of the duty of loyalty
to the Company or its shareholders, (ii) acts or omissions not in good faith or
that involve intentional misconduct or a knowing violation of law, (iii) payment
of an improper dividend or improper repurchase of the Company's securities that
would violate Section 174 of the Delaware Corporation Law if the Company were a
corporation organized under Delaware law and (iv) any transaction from which the
director derived an improper personal benefit.
Under the Company Agreement, the Company will indemnify each person who is
or was a director or officer of the Company or a subsidiary of the Company, or
who serves or served any other enterprise or organization at the request of the
Company or a subsidiary of the Company, to the full extent permitted by Delaware
law.
Under Delaware law, to the extent that a person is successful on the merits
in defense of a suit or proceeding brought against him by reason of the fact
that he is or was a director or officer of the Company, or serves or served any
other enterprise or organization at the request of the Company, the Company will
indemnify that person against expenses (including attorneys' fees) actually and
reasonably incurred in connection with the action.
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108
Under Delaware law, to the extent an indemnified person is not successful
in defense of a third-party civil suit or a criminal suit, or if such suit is
settled, the Company may indemnify that person against both (i) expenses,
including attorneys' fees, and (ii) judgments, fines and amounts paid in
settlement if he acted in good faith and in a manner he reasonably believed to
be in, or not opposed to, the best interests of the Company and, with respect to
any criminal action, had no reasonable cause to believe his conduct was
unlawful, except that if the person is adjudged to be liable in the suit for
negligence or misconduct in the performance of his duty to the Company, he
cannot be made whole even for expenses unless the court determines that he is
fully and reasonably entitled to indemnity for those expenses.
The Company maintains insurance to protect officers and directors from
certain liabilities, including liabilities against which the corporation cannot
indemnify its directors and officers.
The above discussion of Delaware law and of the Company Agreement is not
intended to be exhaustive and is qualified in its entirety by Delaware law and
the Company Agreement.
Reference is made to the form of Underwriting Agreement filed as Exhibit
1.1 to the Registration Statement for certain provisions regarding the
indemnification of the Company, its officers and directors and any controlling
persons by the underwriters against certain liabilities for information
furnished by the underwriters.
Insofar as indemnification for liabilities arising under the Securities Act
may be permitted to directors, officers or persons controlling the Company
pursuant to the foregoing provisions, the Company has been informed that in the
opinion of the Commission such indemnification is against public policy as
expressed in the Securities Act and is therefore unenforceable.
ITEM 15. Recent Sales of Unregistered Securities.
The Company was formed in September 1998. Shortly following the Company's
formation, it offered to exchange twelve of its common shares for each
outstanding share of the common stock of Mariner Holdings, Inc. Pursuant to this
exchange, the Company issued an aggregate of 13,928,304 common shares on October
13, 1998 and Mariner Holdings, Inc. became a wholly owned subsidiary of the
Company. These issuances were exempt from registration pursuant to Section 4(2)
of the Securities Act of 1933 and Regulation D promulgated thereunder, as no
public offerings were involved.
Under the amended and restated credit agreement between the Company and
Enron North America Corp. ("ENA") dated April 15, 1999, ENA was granted the
right to convert all or any part of the principal and interest outstanding under
that agreement into the Company's common shares at a rate of $14.5833 per share.
The issuance of that conversion right was exempt from registration pursuant to
Section 4(2) of the Securities Act of 1933, as no public offering was involved.
In March 2000, this credit agreement was repaid with the proceeds from a three
year unsecured term loan with ENA, causing the expiration of the conversion
rights.
As part of the March 2000 term loan with ENA, the Company issued two
five-year warrants to ENA providing ENA the right to purchase up to 900,000
common shares of the Company for $0.01 per share. One warrant for 600,000 shares
is exercisable by ENA immediately and another warrant for 300,000 shares is
exercisable on March 21, 2001, if the term loan is unpaid on that date. The
issuance of the warrants was exempt from registration pursuant to Section 4(2)
of the Securities Act of 1933, as no public offering was involved.
ITEM 16. Exhibits And Financial Statement Schedules
(a) Exhibits.
Exhibits designated by the symbol * have been previously filed with this
Registration Statement. Exhibits designated by the symbol + will be filed with a
future amendment. Exhibits designated by a ** are filed with this amendment. All
exhibits not so designated are incorporated by reference to a prior filing as
indicated.
1.1+ -- Form of Underwriting Agreement.
3.1* -- Certificate of Formation of the Company.
3.2* -- The Company Agreement.
4.1+ -- Form of Common Share Certificate.
4.2(a) -- Indenture, dated as of August 1, 1996, between Mariner
Energy, Inc. and United States Trust Company of New York,
as Trustee.
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109
4.3(d) -- First Amendment to Indenture, dated as of January 31, 1997,
between Mariner Energy, Inc. and United States Trust
Company of New York, as Trustee.
4.4(a) -- Form of Mariner Energy, Inc.'s 101/2% Senior
Subordinated Note Due 2006, Series B.
4.5(g) -- Amended and Restated Credit Agreement, dated June 28, 1999,
among Mariner Energy, Inc., NationsBank of Texas, N.A.,
as Agent, Toronto Dominion (Texas), Inc., as Co-agent, and
the financial institutions listed on schedule 1 thereto.
4.6(i) -- Second Amended and Restated Credit Agreement, dated as of April
15, 1999, between Mariner Energy LLC and Enron North America
Corp. (formerly Enron Capital & Trade Resources Corp.).
4.7(i) -- Revolving Credit Agreement dated as of April 15, 1999,
between Mariner Energy, Inc. and Enron North America
Corp. (formerly Enron Capital & Trade Resources Corp.).
5.1+ -- Form of opinion of Fulbright & Jaworski L.L.P.
8.1+ -- Form of opinion of Fulbright & Jaworski L.L.P.
regarding the tax treatment of Mariner Energy LLC's common
shares.
10.1(h) -- Amended and Restated Shareholders' Agreement, dated October 12,
1998, among Enron North America Corp. (formerly Enron Capital
& Trade Resources Corp.), Mariner Energy LLC, Mariner
Holdings, Inc., Joint Energy Development Investments Limited
Partnership and the other shareholders of Mariner Energy LLC.
10.2(a) -- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and Robert E. Henderson.
10.3(a) -- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and Richard R. Clark.
10.4(a) -- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and Michael W. Strickler.
10.5(a) -- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and Gregory K. Harless.
10.6* -- Third Amendment to Amended and Restated Employment Agreement,
dated as of December 27, 1998, between Mariner Energy, Inc.
and Gregory K. Harless.
10.7(b) -- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and W. Hunt Hodge.
10.8(h) -- Third Amendment to Amended and Restated Employment Agreement,
dated as of December 27, 1998, between Mariner Energy, Inc.
and William Hunt Hodge.
10.9(d) -- Employment Agreement, dated as of December 2, 1996, between
Mariner Energy, Inc. and Frank A. Pici.
10.10* -- Second Amendment to Employment Agreement, dated as of December 1,
1998, between Mariner Energy, Inc. and Frank A. Pici.
10.11(h) -- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and Tom E. Young.
10.12(h) -- Intentionally Omitted
10.13(h) -- Employment Agreement, dated as of June 1, 1998, between
Mariner Energy, Inc. and L. V. McGuire.
10.14(a) -- Amended and Restated Consulting Services Agreement, dated June 27,
1996, between Mariner Energy, Inc. and David S. Huber.
10.15(a) -- Mariner Energy LLC 1996 Share Option Plan.
10.16(a) -- Form of Incentive Share Option Agreement (pursuant to the Mariner
Energy LLC 1996 Share Option Plan).
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110
10.17(h) -- List of executive officers who are parties to an Incentive
Share Option Agreement.
10.18(a) -- Form of Nonstatutory Share Option Agreement (pursuant to
the Mariner Energy LLC 1996 Share Option Plan).
10.19(h) -- List of executive officers who are parties to a Nonstatutory
Stock Option Agreement.
10.20(a) -- Nonstatutory Stock Option Agreement, dated June 27, 1996, between
Mariner Holdings, Inc. and David S. Huber.
10.21* -- Third Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Richard R. Clark.
10.22* -- Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Gregory K. Harless.
10.23* -- Third Amendment to Amended to Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Robert E. Henderson.
10.24* -- Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and William Hunt Hodge.
10.25* -- First Amendment to Amended and Restated Consulting Services
Agreement, effective as of October 1, 1999, between Mariner
Energy, Inc. and David S. Huber.
10.26* -- Intentionally Omitted
10.27* -- First Amendment to Employment Agreement, effective as of October
1, 1999, between Mariner Energy, Inc. and L.V. McGuire.
10.28* -- Third Amendment to Employment Agreement, effective as of October
1, 1999, between Mariner Energy, Inc. and Frank A. Pici.
10.29* -- Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Michael W. Strickler.
10.30* -- First Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Thomas E. Young.
10.31+ -- Mariner Energy LLC _____ Share Option Plan.
10.32+ -- Form of Option Agreement (pursuant to the Mariner Energy LLC _____
Share Option Plan).
10.33+ -- Form of Change of Control Agreement.
10.34+ -- Incentive Compensation Plan.
10.35+ -- Fourth Amendment to Amended and Restated Employment Agreement,
effective as of _____, between Mariner Energy, Inc.
and Richard R. Clark.
10.36+ -- Fifth Amendment to Amended and Restated Employment Agreement,
effective as of _____, between Mariner Energy, Inc.
and Gregory K. Harless.
10.37+ -- Fourth Amendment to Amended to Restated Employment Agreement,
effective as of _____, between Mariner Energy, Inc.
and Robert E. Henderson.
10.38+ -- Fifth Amendment to Amended and Restated Employment Agreement,
effective as of _____, between Mariner Energy, Inc.
and William Hunt Hodge.
10.39+ -- Second Amendment to Amended and Restated Consulting Services
Agreement, effective as of _____, between Mariner Energy, Inc.
and David S. Huber.
10.40 -- Intentionally Omitted
10.41+ -- Second Amendment to Employment Agreement, effective as of _____,
between Mariner Energy, Inc. and L.V. McGuire.
10.42+ -- Fourth Amendment to Employment Agreement, effective as of _____,
between Mariner Energy, Inc. and Frank A. Pici.
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111
10.43+ -- Fifth Amendment to Amended and Restated Employment Agreement,
effective as of _____, between Mariner Energy, Inc.
and Michael W. Strickler.
10.44+ -- Second Amendment to Amended and Restated Agreement, effective as
of _____, between Mariner Energy, Inc. and Thomas E. Young.
10.45** -- Term Loan Agreement between Mariner Energy LLC and Enron North
America Corp. dated March 21, 2000
10.46** -- Bank of America Letter Credit Agreement dated May 19, 2000
21.1* -- Subsidiaries of Registrant.
23.1** -- Consent of Deloitte & Touche LLP.
23.2** -- Consent of Ryder Scott Company, L.P.
23.3+ -- Consent of Fulbright & Jaworski L.L.P. (Included in Exhibit 5.1).
24.1* -- Powers of Attorney (included as part of the signature
page).
27.1** -- Financial Data Schedule.
----------
(a) Incorporated by reference to Mariner Energy, Inc.'s Registration Statement
on Form S-4 (Registration No. 333-12707), filed September 25, 1996.
(b) Incorporated by reference to Amendment No. 1 to Mariner Energy, Inc.'s
Registration Statement on Form S-4 (Registration No. 333-12707), filed
December 6, 1996.
(c) Incorporated by reference to Amendment No. 2 to Mariner Energy, Inc.'s
Registration Statement on Form S-4 (Registration No. 333-12707), filed
December 19, 1996.
(d) Incorporated by reference to Mariner Energy, Inc.'s Annual Report on Form
10-K for the year ended December 31, 1996 filed March 31, 1997.
(e) Incorporated by reference to Mariner Energy, Inc.'s Annual Report on Form
10-K for the year ended December 31, 1997 filed March 30, 1998.
(f) Incorporated by reference to Mariner Energy, Inc.'s Quarterly Report on
Form 10-Q for the quarter ended June 30, 1998 filed August 14, 1998.
(g) Incorporated by reference to Mariner Energy, Inc.'s Quarterly Report on
Form 10-Q for the quarter ended June 30, 1999 filed August 16, 1999.
(h) Incorporated by reference to Mariner Energy, Inc.'s Annual Report on Form
10-K for the year ended December 31, 1998 filed April 15, 1999.
(i) Incorporated by reference to Mariner Energy, Inc.'s Quarterly Report on
Form 10-Q for the quarter ended March 30, 1999 filed May 17, 1999. (b)
Financial Statement Schedule.
Schedule I Condensed Financial Information of Registrant (Parent only)
(FS-1-FS-3)
All schedules other than the one listed above, for which provision is made
in applicable accounting regulations of the Securities and Exchange Commission
have been omitted as the schedules are either not required under the related
instructions, are not applicable or the information required thereby is set
forth in the Financial Statements or the Notes thereto.
ITEM 17. Undertakings.
Insofar as indemnification for liabilities arising under the Securities Act
may be permitted to directors, officers and controlling persons of the Company,
the Company has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as expressed in the
Securities Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the Company
of expenses incurred or paid by a director, officer or controlling person of the
Company in the successful defense of any action, suit or proceeding) is asserted
by such director, officer or controlling person in connection with the
securities being registered, the Company will, unless in the opinion of its
counsel the matter has been settled by controlling precedent, submit to a court
of appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Securities Act and will be governed by
the final adjudication of such issue.
II-5
<PAGE>
112
The undersigned Company hereby undertakes to provide to the underwriters at
the closing specified in the Underwriting Agreement certificates in such
denominations and registered in such names as required by the underwriters to
permit prompt delivery to each purchaser.
The undersigned Company hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act, the
information omitted from the form of prospectus filed as part of this
Registration Statement in reliance upon Rule 430A and contained in a form
of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or
497(h) under the Securities Act shall be deemed to be a part of this
Registration Statement as of the time it was declared effective.
(2) For the purpose of determining any liability under the Securities Act,
each post-effective amendment that contains a form of prospectus shall be
deemed to be a new registration statement relating to the securities
offered therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.
II-6
<PAGE>
113
SIGNATURES
Pursuant to the requirements of the Securities Act, the Company has duly
caused this Amendment No. 1 to Registration Statement to be signed on its behalf
by the undersigned, thereunto duly authorized, in the City of Houston, State of
Texas, on November 4, 1999.
MARINER ENERGY LLC
By: /s/ ROBERT E. HENDERSON
--------------------------------------------------------------------------------
Robert E. Henderson,
Chairman of the Board, President and Chief Executive Officer
This report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
/s/ ROBERT E. HENDERSON Chairman of the Board, October 31, 2000
----------------------- President and Chief
Robert E. Henderson Executive Officer
(Principal Executive
Officer)
Vice President of Finance October 31, 2000
/s/ FRANK A. PICI and Chief-Financial
----------------- Officer
Frank A. Pici (Principal Financial
Officer and Principal
Accounting Officer)
/s/ L. V. MCGUIRE Senior Vice President of October 31, 2000
----------------- Operations and Director
L. V. McGuire
/s/ RICHARD R. CLARK Executive Vice President October 31, 2000
-------------------- and Director
Richard R. Clark
/s/ MICHAEL W. STRICKLER Senior Vice President of October 31, 2000
------------------------ Exploration and Director
Michael W. Strickler
/s/ RAYMOND M. BOWEN Director October 31, 2000
--------------------
Raymond M. Bowen
/s/ RICHARD B. BUY Director October 31, 2000
------------------
Richard B. Buy
/s/ JEFFREY M. DONAHUE, JR. Director October 31, 2000
---------------------------
Jeffrey M. Donahue, Jr..
/s/ D. BRAD DUNN Director October 31, 2000
----------------
D. Brad Dunn
/s/ MARK E. HAEDICKE Director October 31, 2000
--------------------
Mark E. Haedicke
/s/ JESUS G. MELENDREZ Director October 31, 2000
----------------------
Jesus G. Melendrez
II-7
<PAGE>
114
/s/ JERE C. OVERDYKE, JR. Director October 31, 2000
-------------------------
Jere C. Overdyke, Jr.
/s/ JEFFREY B. SHERRICK Director October 31, 2000
-----------------------
Jeffrey B. Sherrick
*By: /s/ ROBERT E. HENDERSON
Robert E. Henderson
As Attorney-In-Fact
II-8
<PAGE>
115
Schedule I
MARINER ENERGY LLC
(Parent Company Only)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
(in thousands, except share data)
December 31, December 31,
1998 1999
--------- ---------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents .................... $ 800 $
Prepaid expenses and other ................... 457 621
--------- ---------
Total Current Assets ................. 1,257 621
INVESTMENT IN SUBSIDIARIES, AT EQUITY .......... 51,727 65,027
--------- ---------
TOTAL ASSETS ......................... 52,984 65,648
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accrued Interest ............................. 450 3,539
Related Party Payable ........................ 918
LONG-TERM DEBT-- Enron credit facility ......... 25,000 50,000
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred Stock, $0.01 par value
(authorized 1,000,000 shares; none issued) . -- --
Common stock, $0.01 par value
(authorized 50,000,000 shares; issued
and outstanding 1998-- 13,928,304;
1999-- 13,928,304 shares) ................... 139 139
Additional paid-in-capital ................... 124,718 124,718
Accumulated deficit .......................... (97,323) (113,666)
--------- ---------
Total stockholders' equity ........... 27,534 11,191
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ..... $ 52,984 $ 65,648
========= =========
FS-1
<PAGE>
116
Schedule I
(continued)
MARINER ENERGY LLC
(Parent Company Only)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
<TABLE>
<CAPTION>
1997 1998 1999
-------- -------- --------
<S> <C> <C> <C>
Depreciation, depletion and amortization............................. $ -- $ -- $ 405
Interest expense .................................................... -- 993 5,968
-------- -------- --------
Loss before income taxes and equity in
earnings of wholly owned subsidiaries................................ -- (993) (6,373)
-------- -------- --------
Provision for income taxes .......................................... -- -- --
-------- -------- --------
Loss of wholly owned subsidiaries.................................... $(20,210) $(57,428) $ (9,970)
-------- -------- --------
Net loss ............................................................ (20,210) (58,421) (16,343)
======== ======== ========
Basic and diluted net loss per share................................. $ (1.71) $ (4.47) $ (1.17)
======== ======== ========
</TABLE>
FS-2
<PAGE>
117
Schedule I
(continued)
MARINER ENERGY LLC
(Parent Company Only)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENT OF CASH FLOWS
(in thousands)
Years Ended December 31,
------------------------------
1997 1998 1999
-------- -------- --------
OPERATING ACTIVITIES ........................... $(20,210) $(58,421) $(16,343)
Net loss
Adjustments to reconcile net
loss to net cash provided by operating
activities:
Equity in loss of wholly owned subsidiaries 20,210 57,428 9,970
Depreciation, depletion and amortization .. -- -- 405
Changes in operating assets and liabilities:
Prepaid expenses and other ................ -- (457) (164)
Accrued interest .......................... -- 450 3,089
-------- -------- --------
Net cash used in operating activities ........ -- (1,000) (3,043)
INVESTING ACTIVITIES
Investment in wholly owned subsidiaries ...... (331) (51,981) (22,757)
-------- -------- --------
Net cash used in operating activities ........ (331) (51,981) (22,757)
FINANCING ACTIVITIES
Proceeds from long-term debt ................. 92,000
Principal payments on long-term debt ......... (92,000)
Proceeds from Enron credit facility .......... -- 25,000 25,000
Proceeds from sale of common stock ........... 331 28,781 --
-------- -------- --------
Net cash provided by financing activities .... 331 53,781 25,000
-------- -------- --------
INCREASE IN CASH AND CASH EQUIVALENTS .......... -- 800 (800)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD -- -- 800
-------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ..... $ -- $ 800 $ --
======== ======== ========
FS-3
<PAGE>
118
INDEX TO EXHIBITS
Exhibits designated by the symbol * have been previously filed with this
Registration Statement. Exhibits designated by the symbol + will be filed with a
future amendment. Exhibits designated by a ** are filed with this amendment. All
exhibits not so designated are incorporated by reference to a prior filing as
indicated.
Exhibit
No. Description
1.1+ -- Form of Underwriting Agreement.
3.1* -- Certificate of Formation of the Company.
3.2* -- The Company Agreement.
4.1+ -- Form of Common Share Certificate.
4.2(a) -- Indenture, dated as of August 1, 1996, between Mariner Energy, Inc.
and United States Trust Company of New York, as Trustee.
4.3(d) -- First Amendment to Indenture, dated as of January 31, 1997, between
Mariner Energy, Inc. and United States Trust Company of
New York, as Trustee.
4.4(a) -- Form of Mariner Energy, Inc.'s 101/2% Senior Subordinated Note Due
2006, Series B.
4.5(g) -- Amended and Restated Credit Agreement, dated June 28, 1999, among
Mariner Energy, Inc., NationsBank of Texas, N.A., as Agent,
Toronto Dominion (Texas), Inc., as Co-agent, and the financial
institutions listed on schedule 1 thereto.
4.6(i) -- Second Amended and Restated Credit Agreement dated as of April 15,
1999, between Mariner Energy LLC and Enron North America Corp.
(formerly Enron Capital & Trade Resources Corp.).
4.7(i) -- Revolving Credit Agreement dated as of April 15, 1999, between
Mariner Energy, Inc. and Enron North America Corp.
(formerly Enron Capital & Trade Resources Corp.).
5.1+ -- Form of opinion of Fulbright & Jaworski L.L.P.
8.1+ -- Form of opinion of Fulbright & Jaworski L.L.P. regarding the tax
treatment of Mariner Energy LLC's common shares.
10.1(h) -- Amended and Restated Shareholders' Agreement, dated October 12, 1998,
among Enron North America Corp. (formerly Enron Capital & Trade
Resources Corp.), Mariner Energy LLC, Mariner Holdings, Inc.,
Joint Energy Development Investments Limited Partnership and
the other shareholders of Mariner Energy LLC.
10.2(a) -- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and Robert E. Henderson.
10.3(a) -- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and Richard R. Clark.
10.4(a) -- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and Michael W. Strickler.
10.5(a) -- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and Gregory K. Harless.
10.6* -- Third Amendment to Amended and Restated Employment Agreement,
dated as of December 27, 1998, between Mariner Energy, Inc.
and Gregory K. Harless.
10.7(b) -- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and W. Hunt Hodge.
10.8(h) -- Third Amendment to Amended and Restated Employment Agreement,
dated as of December 27, 1998, between Mariner Energy, Inc.
and William Hunt Hodge.
<PAGE>
119
10.9(d) -- Employment Agreement, dated as of December 2, 1996,
between Mariner Energy, Inc. and Frank A. Pici.
10.10* -- Second Amendment to Employment Agreement, dated as of December 1,
1998, between Mariner Energy, Inc. and Frank A. Pici.
10.11(h)-- Amended and Restated Employment Agreement, dated June 27, 1996,
between Mariner Energy, Inc. and Tom E. Young.
10.12(h)-- Intentionally Omitted
10.13(h)-- Employment Agreement, dated as of June 1, 1998, between
Mariner Energy, Inc. and L. V. McGuire.
10.14(a)-- Amended and Restated Consulting Services Agreement, dated June 27,
1996, between Mariner Energy, Inc. and David S. Huber.
10.15(a)-- Mariner Energy LLC 1996 Share Option Plan.
10.16(a)-- Form of Incentive Share Option Agreement (pursuant to the Mariner
Energy LLC 1996 Share Option Plan).
10.17(h)-- List of executive officers who are parties to an Incentive Share
Option Agreement.
10.18(a)-- Form of Nonstatutory Share Option Agreement (pursuant
to the Mariner Energy LLC 1996 Share Option Plan).
10.19(h)-- List of executive officers who are parties to a Nonstatutory Stock
Option Agreement.
10.20(a)-- Nonstatutory Stock Option Agreement, dated June 27, 1996, between
Mariner Holdings, Inc. and David S. Huber.
10.21* -- Third Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Richard R. Clark.
10.22* -- Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Gregory K. Harless.
10.23* -- Third Amendment to Amended to Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Robert E. Henderson.
10.24* -- Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and William Hunt Hodge.
10.25* -- First Amendment to Amended and Restated Consulting Services
Agreement, effective as of October 1, 1999, between Mariner
Energy, Inc. and David S. Huber.
10.26* -- Intentionally Omitted
10.27* -- First Amendment to Employment Agreement, effective as of October
1, 1999, between Mariner Energy, Inc. and L.V. McGuire.
10.28* -- Third Amendment to Employment Agreement, effective as of October
1, 1999, between Mariner Energy, Inc. and Frank A. Pici.
10.29* -- Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Michael W. Strickler.
10.30* -- First Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Thomas E. Young.
10.31+ -- Mariner Energy LLC _____ Share Option Plan.
10.32+ -- Form of Option Agreement (pursuant to the Mariner Energy LLC
_____ Share Option Plan).
10.33+ -- Change of Control Agreement.
10.34+ -- Incentive Compensation Plan.
10.35+ -- Fourth Amendment to Amended and Restated Employment Agreement,
effective as of _____, between Mariner Energy, Inc.
and Richard R. Clark.
<PAGE>
120
10.36+ -- Fifth Amendment to Amended and Restated Employment Agreement,
effective as of _____, between Mariner Energy, Inc.
and Gregory K. Harless.
10.37+ -- Fourth Amendment to Amended to Restated Employment Agreement,
effective as of _____, between Mariner Energy, Inc.
and Robert E. Henderson.
10.38+ -- Fifth Amendment to Amended and Restated Employment Agreement,
effective as of _____, between Mariner Energy, Inc.
and William Hunt Hodge.
10.39+ -- Second Amendment to Amended and Restated Consulting Services
Agreement, effective as of _____, between Mariner Energy, Inc.
and David S. Huber.
10.40 -- Intentionally Omitted
10.41+ -- Second Amendment to Employment Agreement, effective as of _____,
between Mariner Energy, Inc. and L.V. McGuire.
10.42+ -- Fourth Amendment to Employment Agreement, effective as of _____,
between Mariner Energy, Inc. and Frank A. Pici.
10.43+ -- Fifth Amendment to Amended and Restated Employment
Agreement, effective as of _____, between
Mariner Energy, Inc. and Michael W. Strickler.
10.44+ -- Second Amendment to Amended and Restated Agreement, effective as of
_____, between Mariner Energy, Inc. and Thomas E. Young.
10.45** -- Term Loan Agreement between Mariner Energy LLC and Enron North
America Corp. dated March 21, 2000
10.46** -- Bank of America Letter Credit Agreement dated May 19, 2000
21.1* -- Subsidiaries of Registrant.
23.1** -- Consent of Deloitte & Touche LLP.
23.2** -- Consent of Ryder Scott Company, L.P.
23.3+ -- Consent of Fulbright & Jaworski L.L.P. (Included in Exhibit 5.1).
24.1* -- Powers of Attorney (included as part of the signature page).
27.1** -- Financial Data Schedule.
----------
(a) Incorporated by reference to Mariner Energy, Inc.'s Registration Statement
on Form S-4 (Registration No. 333-12707), filed September 25, 1996.
(b) Incorporated by reference to Amendment No. 1 to Mariner Energy, Inc.'s
Registration Statement on Form S-4 (Registration No. 333-12707), filed
December 6, 1996.
(c) Incorporated by reference to Amendment No. 2 to Mariner Energy, Inc.'s
Registration Statement on Form S-4 (Registration No. 333-12707), filed
December 19, 1996.
(d) Incorporated by reference to Mariner Energy, Inc.'s Annual Report on Form
10-K for the year ended December 31, 1996 filed March 31, 1997.
(e) Incorporated by reference to Mariner Energy, Inc.'s Annual Report on Form
10-K for the year ended December 31, 1997 filed March 30, 1998.
(f) Incorporated by reference to Mariner Energy, Inc.'s Quarterly Report on
Form 10-Q for the quarter ended June 30, 1998 filed August 14, 1998.
(g) Incorporated by reference to Mariner Energy, Inc.'s Quarterly Report on
Form 10-Q for the quarter ended June 30, 1999 filed August 16, 1999.
(h) Incorporated by reference to Mariner Energy, Inc.'s Annual Report on Form
10-K for the year ended December 31, 1998 filed April 15, 1999.
(i) Incorporated by reference to Mariner Energy, Inc.'s Quarterly Report on
Form 10-Q for the quarter ended March 30, 1999 filed May 17, 1999.
