<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON NOVEMBER 4, 1999
REGISTRATION NUMBER 333-87287
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
PRE-EFFECTIVE AMENDMENT NO. 1 TO
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
MARINER ENERGY LLC
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C> <C>
DELAWARE 1311 52-2130735
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer Identification
incorporation or Classification Code Number) No.)
organization)
</TABLE>
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)
CHRISTOPHER E. LINDSEY
GENERAL COUNSEL
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:
<TABLE>
<S> <C>
MR. CHARLES H. STILL MR. JAMES M. PRINCE
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
</TABLE>
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.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 2
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 4, 1999
Shares
Mariner Energy Logo
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.
<TABLE>
<CAPTION>
UNDERWRITING PROCEEDS TO
PRICE TO DISCOUNTS AND PROCEEDS TO SELLING
PUBLIC COMMISSIONS MARINER SHAREHOLDERS
----------------- ----------------- ----------------- -----------------
<S> <C> <C> <C> <C>
Per Share............................ $ $ $ $
Total................................ $ $ $ $
</TABLE>
Delivery of the common shares will be made on or about ,
1999.
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 , 1999.
<PAGE> 3
(Map of Primary Properties)
i
<PAGE> 4
[Map depicting our proved properties,
exploratory prospects and prospects subject
to lease awards; blow-up map of the Gulf of
Mexico region;]
WHEN DESCRIBING NATURAL GAS
- ---------------------------
Mcf = One thousand cubic feet of natural gas.
MMBtu = One million British Thermal Units
MMcf = One million cubic feet of natural gas.
Bcf = One billion cubic feet of natural gas.
WHEN DESCRIBING OIL
- -------------------
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.
Mbbls = One thousand barrels of crude oil or other liquid hydrocarbons.
WHEN COMPARING OIL TO NATURAL GAS
- ---------------------------------
1 Bbl of Oil = Six Mcf of natural gas
Mcfe = One thousand cubic feet of natural gas equivalent,
converting one barrel of oil to six Mcf of natural
gas based on commonly accepted rough equivalency of
energy content.
Bcfe = One billion cubic feet of natural gas equivalent,
converting one barrel of oil to six Mcf of natural gas
based on commonly accepted rough equivalency of
energy content.
<PAGE> 5
---------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PROSPECTUS SUMMARY..................... 1
SUMMARY CONSOLIDATED FINANCIAL DATA.... 5
RISK FACTORS........................... 8
CAUTIONARY STATEMENT ABOUT
FORWARD-LOOKING STATEMENTS........... 17
USE OF PROCEEDS........................ 18
DIVIDEND POLICY........................ 18
DILUTION............................... 19
CAPITALIZATION......................... 20
SELECTED CONSOLIDATED FINANCIAL DATA... 21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS........................... 22
BUSINESS AND PROPERTIES................ 33
MARINER HISTORY AND ORGANIZATION....... 48
MANAGEMENT............................. 49
PRINCIPAL AND SELLING SHAREHOLDERS..... 58
</TABLE>
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS......................... 60
DESCRIPTION OF OUR COMPANY AGREEMENT
AND COMMON SHARES.................... 63
SHARES ELIGIBLE FOR FUTURE SALE........ 70
UNDERWRITING........................... 71
NOTICE TO CANADIAN RESIDENTS........... 73
LEGAL MATTERS.......................... 74
EXPERTS................................ 74
INDEPENDENT PETROLEUM ENGINEERS........ 74
WHERE YOU CAN FIND MORE INFORMATION.... 75
GLOSSARY OF OIL AND NATURAL GAS
TERMS................................ 75
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS............................. F-1
REPORT OF INDEPENDENT PETROLEUM
ENGINEERS............................ A-1
</TABLE>
---------------------
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 , 1999 (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.
ii
<PAGE> 6
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 September 30, 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 75 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 15 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:
- operated seven successful subsea development projects in water depths of
400 feet to 2,700 feet;
- developed three deepwater exploitation projects acquired from major oil
companies, including our Pluto project;
- discovered six new fields in ten deepwater Gulf exploration tests,
including a recent potentially significant discovery at our Aconcagua
prospect;
- acquired 64 deepwater Gulf lease blocks, most of which are free of
royalty payment obligations; and
- built an inventory of 18 exploration prospects as of September 30, 1999,
including 14 prospects in the deepwater Gulf.
Ryder Scott Company estimated that we had proved reserves of 175.8 Bcfe as
of September 30, 1999, of which 69% were natural gas and 31% were oil and
condensate. For the nine months ended September 30, 1999, we produced an average
of 68 MMcfe per day.
We expect our production levels and operating cash flow to increase
significantly based on production from our Dulcimer project, which began in
April 1999, and our Pluto project, which we expect to begin producing in the
fourth quarter of 1999 at a rate of approximately 30 to 40 MMcfe per day net to
our interest. We expect further increases on commencement of production from our
Apia and Black Widow projects, currently scheduled for the second quarter and
third quarter of 2000, respectively. We also expect to drill eight of our
exploration prospects by the end of 2000, including six deepwater Gulf prospects
with potential to add significant quantities of proved reserves and future
production.
Our planned capital expenditures for 2000 consist of approximately $110
million for leasehold acquisition, exploration drilling and development
projects, compared to our planned capital expenditures of approximately $63
million for 1999.
1
<PAGE> 7
OUR STRATEGY
Our business strategy is to increase reserves, production and cash flow
profitably by emphasizing growth through the drillbit in the deepwater Gulf, and
consists of the following elements:
- 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 scheduled to become
available via lease sales, we believe we are well-positioned to increase
our deepwater Gulf activity and to continue to generate and exploit
economically attractive prospects.
- 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.
- 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 18 exploration
prospects as of September 30, 1999, were internally generated by our
staff of 12 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.
- MANAGE DEEPWATER RISKS. We intend to reduce our deepwater risks by:
- targeting prospects with relatively low exploratory risk and gross
drilling costs below $20 million;
- using 3-D seismic technology to identify direct hydrocarbon indicators
on projects at drilling depths generally less than 10,000 feet below
the sea floor; and
- limiting the financial exposure of our deepwater prospect portfolio by
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 costs are paid by partners.
- 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. We intend to apply their experience
base to shorten project cycle times and reduce operational risks and full
cycle costs, using proven equipment and procedures in close cooperation
with our experienced deepwater service providers.
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, and our focus in the
Gulf, with its relatively short production periods, subjects us to higher
reserve replacement needs. Our use of seismic data cannot eliminate exploration
risk. We reported significant losses in 1996, 1997 and 1998 primarily due to
asset impairment charges related to the impact of low commodity prices on the
cost ceiling we are limited to under the full cost accounting method and 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.
2
<PAGE> 8
PROVED PROPERTIES
Our proved properties as of September 30, 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 27.0
Garden Banks 73 (Apia)......... Mariner 100% 700 May 2000 17.6
Ewing Bank 966 (Black Widow)... Mariner 45% 1,850 September 2000 14.1
Garden Banks 367 (Dulcimer).... Mariner 41.7% 1,100 April 1999 12.1
Garden Banks 240 (Mustique).... Mariner 33% 830 January 1996 5.8
Green Canyon 136(Shasta)....... Texaco 25% 1,040 November 1995 2.2
SHALLOW WATER GULF:
Brazos A-105................... Spirit Energy 12.5% 192 January 1993 11.6
Galveston 151 (Rembrandt)...... Mariner 33.3% 50 November 1996 8.3
Matagorda Island 683, 703...... Vastar 25% 112 March 1993 3.9
ONSHORE:
Spraberry Aldwell Unit......... Mariner 70.3% Onshore 1949 53.7
Sandy Lake Field............... Mariner 50%/33%(2) Onshore August 1994 4.8
OTHER FIELDS..................... -- -- -- -- 14.7
-----
TOTAL PROVED RESERVES............ 175.8
=====
</TABLE>
- -------------------------
(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
<PAGE> 9
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:
- 2,226,948 common shares that may be issued on the exercise of stock
options, at a weighted average price of $9.53, all of which will be
exercisable immediately following the offering; and
- common shares that may be issued upon conversion of the debt we owe under
one of the Enron credit facilities, 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.
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.
4
<PAGE> 10
SUMMARY CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE DATA)
The following table shows some of our historical financial data. The
results of operations for the nine months ended September 30, 1999 are not
necessarily indicative of the results for the full fiscal year. Effective April
1, 1996 for accounting purposes, our predecessor, Mariner Holdings, Inc.,
acquired all the capital stock of Mariner Energy, Inc. from a subsidiary of
Hardy Oil & Gas, plc, as part of a management-led buyout. In connection with
this acquisition, a substantial amount of our intercompany indebtedness and
receivables and third-party indebtedness were eliminated. This acquisition was
accounted for using the purchase method of accounting. 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. We have not presented basic earnings per share and
average shares outstanding are not presented for the three months ended March
31, 1996, as our capital structure before the acquisition is not comparable. 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>
ACQUIRED
COMPANY
-------------
THREE MONTHS NINE MONTHS YEAR ENDED NINE MONTHS ENDED
ENDED ENDED DECEMBER 31, SEPTEMBER 30,
MARCH 31, DECEMBER 31, -------------------- ---------------------
1996 1996 1997 1998 1998 1999
------------- ------------ -------- --------- --------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
DATA:
Total revenues.............. $13,309 $ 47,079 $ 62,771 $ 56,690 $ 43,598 $ 39,080
Lease operating expenses.... 2,403 6,495 9,376 9,858 7,554 8,380
Depreciation, depletion and
amortization.............. 6,309 24,747 31,719 33,833 25,023 23,488
Impairment of oil and gas
properties................ -- 22,500 28,514 50,800 -- --
General and administrative
expenses.................. 712 2,406 3,195 4,749 3,417 4,007
Provision for litigation.... -- -- -- 2,800(1) 2,960(1) --
------- --------- -------- --------- --------- --------
Operating income (loss)... 3,885 (9,069) (10,033) (45,350) 4,644 3,205
Interest income............. 2,167 515 467 313 299 29
Interest expense............ (3,391) (7,746) (10,644) (13,384) (9,512) (14,754)
Write-off of bridge loan
fees...................... -- (2,392) -- -- -- --
------- --------- -------- --------- --------- --------
Income (loss) before
income taxes............ 2,661 (18,692) (20,210) (58,421) (4,569) (11,520)
Provision for income
taxes..................... -- -- -- -- -- --
------- --------- -------- --------- --------- --------
Net income (loss)......... $ 2,661 $ (18,692) $(20,210) $ (58,421) $ (4,569) $(11,520)
======= ========= ======== ========= ========= ========
Basic and diluted earnings
per share................. $ (1.58) $ (1.71) $ (4.47) $ (0.36) $ (0.83)
Average outstanding
shares.................... 11,831 11,842 13,080 12,744 13,928
CASH FLOW DATA:
Net cash provided by (used
in) operating
activities................ $ 5,630 $ 38,705 $ 52,878 $ 40,345 $ 18,932 $ 5,726
Net cash used in investing
activities................ (5,648) (216,191) (68,868) (141,855) (103,574) (43,702)
Net cash provided by
financing activities...... -- 188,305 14,302 93,181 75,992 39,300
OTHER FINANCIAL DATA:
EBITDA(2)................... $10,194 $ 38,178 $ 50,200 $ 42,083 $ 32,627 $ 26,693
Capital expenditures........ 7,648 38,977 68,868 141,855 103,574 43,702(3)
</TABLE>
5
<PAGE> 11
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.
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1999
------------------------
ACTUAL AS ADJUSTED
--------- ------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents........................................................... $ 1,326 $
Total assets........................................................................ 282,423
Total debt.......................................................................... 217,361
Shareholders' equity................................................................ 16,014
</TABLE>
- -------------------------
(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.
(3) Our capital expenditures for the first nine months of 1999 were $63.5
million, excluding $19.8 million related to our sale of a working interest
in the Pluto project.
6
<PAGE> 12
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 September 30, 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>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- ------------------
1996 1997 1998 1998 1999
------- ------- ------- ------- --------
<S> <C> <C> <C> <C> <C>
PRODUCTION:
Oil (MBbls)............................... 750 977 786 625 502
Natural gas (MMcf)........................ 20,429 18,004 19,477 14,591 15,559
Natural gas equivalent (MMcfe)............ 24,929 23,866 24,193 18,341 18,571
Average daily production (MMcfe).......... 68 65 66 67 68
AVERAGE REALIZED SALES PRICES (INCLUDING
EFFECTS OF HEDGING):
Oil (per Bbl)............................. $ 18.04 $ 18.48 $ 12.80 $ 13.27 $ 14.12
Natural gas (per Mcf)..................... 2.29 2.48 2.39 2.42 2.06
Natural gas equivalent (per Mcfe)......... 2.42 2.63 2.34 2.38 2.10
EXPENSES (PER MCFE):
Lease operating........................... 0.36 0.39 0.41 0.41 0.45
General and administrative, net(1)........ 0.13 0.13 0.20 0.19 0.22
Depreciation, depletion and amortization,
before impairment provision............ 1.25 1.33 1.40 1.36 1.26
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------- AS OF SEPTEMBER 30,
1996 1997 1998 1999
-------- -------- -------- -------------------
(DOLLARS IN THOUSANDS, EXCEPT FOR PER UNIT AMOUNTS)
<S> <C> <C> <C> <C>
PROVED RESERVES:
Total proved reserves (MMcfe)........... 123,964 161,146 185,049 175,756(2)
Annual reserve replacement ratio(3)..... 124% 256% 199% --
Present value of estimated future net
revenues(4).......................... $303,363 $183,829 $147,629 $270,564
Standardized measure of future
discounted net cash flows(5)......... 254,376 176,459 147,629 --
Average prices at indicated date:
Natural gas (per Mcf)................ $ 4.50 $ 2.79 $ 2.22 $ 3.19
Oil (per Bbl)........................ 25.16 16.43 10.36 24.07
</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.
(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. 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 or otherwise exploit prospects or properties will depend in
part on the evaluation of data obtained through geophysical and geological
analyses, production data and engineering studies, the results of which are
often inconclusive or subject to varying interpretations. See "-- Reserve
estimates depend on many assumptions that may turn out to be inaccurate" for a
discussion of the uncertainty involved in these processes. Our cost of drilling,
completing and operating wells, especially offshore wells, is often uncertain
before drilling commences. Overruns in budgeted expenditures are common risks
that can make a particular project uneconomical. Further, many factors may
curtail, delay or cancel drilling, including the following:
- title problems;
- weather conditions;
- compliance with governmental permitting requirements;
- shortages of or delays in obtaining equipment;
- reductions in product prices; and
- limitations in the market for products.
Losses and liabilities arising from uninsured and underinsured events could
have a material adverse effect on our financial condition and operations. Our
oil and natural gas business is subject to all of the operating risks associated
with drilling for and producing oil and natural gas, including:
- uncontrollable flows of oil, natural gas, brine or well fluids into the
environment, including groundwater and shoreline contamination;
- blowouts and cratering;
- mechanical difficulties;
- fires and explosions;
- personal injuries and death;
- pollution;
- natural disasters; and
- environmental hazards such as natural gas leaks, oil spills, pipeline
ruptures and discharges of toxic gases.
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
based on
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environmental or other considerations. Although we maintain insurance at levels
we believe are consistent with industry practices, we are not fully insured
against all risks.
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 longer time
frames and the application of more advanced drilling technologies, involving a
higher risk of technological failure and usually resulting in significantly
higher drilling costs. Our deepwater wells are completed using subsea completion
techniques that involve the installation of 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 involve a high risk of
encountering mechanical difficulties and equipment failures that, if
encountered, could result in significant cost overruns. Furthermore, the
deepwater operations lack the physical and oilfield service infrastructure
present in shallower waters. Therefore, they require a longer lag time between
discovery and marketing, increasing the risk involved with these operations.
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, are subject to
wide fluctuations and depend on numerous factors beyond our control. These
factors include:
- market uncertainty;
- changes in global supply of and demand for oil, natural gas and natural
gas liquids;
- weather conditions;
- the condition of the United States economy;
- the price and quantity of foreign imports;
- the price and availability of alternative fuels;
- political conditions, including embargoes, in or affecting other
oil-producing and natural gas-producing countries;
- the actions of the Organization of Petroleum Exporting Countries; and
- domestic and foreign government regulation, legislation and policies.
It is impossible to predict oil and natural gas price movements with
certainty. 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 outstanding amounts under our revolving credit facility and other
indebtedness. Further, oil prices and natural gas prices do not necessarily move
together. Because approximately 69% of our estimated proved reserves as of
September 30, 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 and requires a writedown of the carrying value of oil and natural
gas properties, resulting in a non-cash charge against earnings for accounting
purposes if the ceiling is exceeded, even if prices declined for only a short
period of time. These writedowns cannot be reversed even if prices increase
later. The risk that we will be required to write down the carrying value of our
oil and natural gas properties increases when oil and natural gas prices are
depressed or decline substantially or when there is an extended delay in
recognizing proved reserves associated with significant capital expenditures.
When a writedown is required, it results in a charge to earnings but does not
affect our cash flow from operating activities. In the last three fiscal years,
we have recorded three 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 fluctuations in the prices of oil and natural
gas, 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
the hedges establish. These hedges also may expose us to the risk of financial
loss in other circumstances, including instances in which our production is less
than expected.
WE MAY NOT BE ABLE TO RAISE SUFFICIENT ADDITIONAL CAPITAL TO IMPLEMENT FULLY OUR
BUSINESS PLAN.
We depend on our ability to obtain financing for operations beyond our
internally generated cash flow. Historically, we have financed these activities
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 2000
exceed our expected cash flow from operations for 2000. We cannot assure you
that additional financing will be available on acceptable terms or at all. If
additional capital resources are unavailable, 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
INDEBTEDNESS OR ENSURE THAT FUTURE CREDIT WILL BE AVAILABLE TO US.
At September 30, 1999, after giving pro forma effect to the offering, we
would have had total indebtedness of approximately $ million and shareholders'
equity of approximately $ million. We intend to incur additional indebtedness
after the offering as we execute our business strategy.
Our leverage could have important consequences, including the following:
- our ability to refinance existing debt or obtain additional debt or
equity financing may be impaired in the future;
- a substantial portion of our cash flow from operations will be required
for the payment of principal and interest on our indebtedness, which will
reduce the funds available to us for our operations and other purposes;
- we may be substantially more leveraged than our competitors, which may
place us at a competitive disadvantage; and
- we may be unable to adjust rapidly to changing market conditions.
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These consequences could make us more vulnerable than a less leveraged
competitor in the event of a downturn 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 make scheduled payments or to 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:
- dispose of assets;
- incur additional indebtedness;
- repay other indebtedness;
- pay dividends;
- enter into specified investments or acquisitions;
- repurchase or redeem capital stock;
- merge or consolidate; or
- 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 maintain compliance with
the financial ratios included in that facility. 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.
The process of estimating oil and natural gas reserves is complex. It
requires interpretations of available technical data and many assumptions,
including assumptions relating to economic factors. 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 order to prepare these estimates we must project production rates and
timing of development expenditures. We must also analyze available geological,
geophysical, production and engineering data. The extent, quality and
reliability of this data can vary. The process 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 September 30, 1999, 61% 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 September 1999, over 85% 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. Also, at September 30, 1999, approximately 91% of our proved reserves
were located on 12 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, are highly dependent 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
reduce indebtedness may limit our ability to slow or shut-in production from
producing wells during periods of low prices for oil and natural gas.
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MARKET CONDITIONS OR OPERATIONAL IMPEDIMENTS MAY HINDER OUR ACCESS TO OIL AND
NATURAL GAS MARKETS OR DELAY OUR PRODUCTION.
Market conditions, the unavailability of satisfactory oil and natural gas
transportation arrangements 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.
Along with another company, on an equally shared basis, in February 1998 we
executed a letter of intent with a third party to use a drilling rig. The third
party is converting the drilling rig for use in the deepwater Gulf. The letter
of intent provided for our use of the rig for two and one-half years of a five-
year term for the drilling rig beginning in early 2000 for a rental rate of
$158,500 per day. We believe this rate is above the present market day rate for
similar rigs in the deepwater Gulf. It is the third party's position that we are
committed to the terms of the letter of intent. We are currently in discussions
with the third party to determine if a mutually acceptable contract can be
negotiated. If a long-term contract is executed, it may require us to pay day
rates in excess of market-based rates over the contract term 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
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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.
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 15 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, seven 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 September 1998 and April 1999, we entered into two credit facilities
with Enron, under which we have borrowed an aggregate of $75 million. We are
required to repay all amounts outstanding under both facilities with Enron with
a portion of the proceeds of the offering. For a discussion of our credit
facilities with Enron and our intention to repay them, see "Use of Proceeds" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity, Capital Expenditures and Capital Resources."
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We expect that from time to time we will engage in various commercial
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 OF CONTROL OCCURS, WE WOULD HAVE TO REPAY INDEBTEDNESS. WE MAY NOT
HAVE THE FINANCIAL RESOURCES TO MEET THIS OBLIGATION.
If a change of 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 of 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 of control of Mariner Energy, Inc. will be deemed to
have occurred under the terms of the indenture if:
- 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
- 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
- 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 Enron has the right
to convert debt and accrued interest into 3,582,201 common shares as of
September 30, 1999. We have granted Joint Energy
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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.
WE AND OUR SUPPLIERS MAY NOT BE YEAR 2000 COMPLIANT, WHICH COULD RESULT IN
DISRUPTION OF OUR OPERATIONS.
Actual effects of the year 2000 issue are uncertain. Our year 2000 program
may not completely identify every potential problem that may arise. Our
inability to solve completely all potential problems or address all potentially
affected systems could partially hurt our business. Likewise our business
suppliers and partners may experience unanticipated year 2000 problems that
could in turn effect our operation. We have relied on representations from third
parties that our systems and the systems of third parties with whom we conduct
business are year 2000 compliant. However, because of the difficulty in
anticipating all effects of the year 2000 issue, these representations are not
guaranties.
If there are year 2000 related failures in our critical systems or our
business suppliers' and partners' critical systems that create substantial or
prolonged complications to our business, the adverse impact on us could
materially affect our financial conditions or results of operations.
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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Some of the information in this prospectus contains forward-looking
statements. These statements express, or are based on, our expectations about
future events. These include such matters as:
- amount, nature and timing of capital expenditures;
- drilling of wells;
- timing and amount of future production of oil and natural gas;
- operating costs and other expenses;
- cash flow and anticipated liquidity;
- prospect development and property acquisitions;
- marketing of oil and natural gas; and
- year 2000 compliance activities.
There are many factors that could cause these forward-looking statements to
be incorrect, including, but not limited to, the risks described under "Risk
Factors" and "Management's Discussion and Analysis of Financial Condition and
Results of Operations." 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.
17
<PAGE> 23
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:
- $ million to repay amounts then outstanding under our revolving
credit facility;
- $ million to repay all amounts then outstanding under the credit
facilities with Enron; and
- 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 September 30, 1999, the balance on our revolving credit facility was
$42.7 million. The indebtedness under our revolving credit facility, which has a
variable interest rate, bore interest at approximately 7% per annum as of
September 30, 1999 and has a final maturity date of October 1, 2002. As of
September 30, 1999, the balance on the Enron credit facility was $50 million and
indebtedness under the Enron credit facility bore interest at approximately 9.5%
per annum. The balance on the senior credit facility with Enron as of September
30, 1999 was $25 million and bore interest at approximately 7.5% 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 credit facilities.
After the offering, both of our credit facilities with Enron will
terminate; otherwise the Enron credit facility would terminate on December 31,
1999 and the senior credit facility with Enron would expire on April 30, 2000.
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.
18
<PAGE> 24
DILUTION
Our net tangible book value as of September 30, 1999, was $16.0 million, or
$1.15 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
September 30, 1999, 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:
<TABLE>
<S> <C> <C>
Assumed initial public offering price per share............. $
Net tangible book value per share as of September 30,
1999................................................... $ 1.15
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................................................. $
</TABLE>
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> <C> <C>
Existing shareholders...... 13,928,304 % $128,926,300 % $ 9.26
New investors..............
Total............
</TABLE>
We had outstanding options entitling the holders to purchase 2,226,948 of
our common shares at a weighted exercise price of $9.53 per share as of
September 30, 1999. Also, Enron had the right to convert debt and accrued
interest into 3,582,201 common shares as of September 30, 1999.
19
<PAGE> 25
CAPITALIZATION
(IN THOUSANDS)
The following table shows our consolidated capitalization as of September
30, 1999, and as adjusted to give pro forma effect to the offering and the
payment of all of our debt under our credit facilities 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.
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1999
-------------------------
ACTUAL AS ADJUSTED
---------- ------------
(UNAUDITED)
<S> <C> <C>
SHORT-TERM DEBT:
Senior credit facility with Enron due December 31, 1999..... $ 25,000 $
Enron credit facility due April 30, 2000.................... 50,000
--------- ---------
Total short-term debt............................. 75,000
LONG-TERM DEBT:
Revolving credit facility due October 1, 2002............... 42,700
10 1/2% senior subordinated notes due 2006.................. 99,661 99,661
--------- ---------
Total long-term debt.............................. 142,361
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.................................. 124,718
Accumulated deficit......................................... (108,843) (108,843)
--------- ---------
Total shareholders' equity........................ 16,014
--------- ---------
TOTAL CAPITALIZATION.............................. $ 233,375 $
========= =========
</TABLE>
20
<PAGE> 26
SELECTED CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE DATA)
The following table shows some of our historical financial data. The
results of operations for the six months ended September 30, 1999 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, a substantial amount 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, 1994 and 1995 or the
three months ended March 31, 1996, as our capital structure before the
acquisition is not comparable.
<TABLE>
<CAPTION>
ACQUIRED COMPANY
-------------------------------
THREE NINE
YEAR ENDED MONTHS MONTHS YEAR ENDED NINE MONTHS ENDED
DECEMBER 31, ENDED ENDED DECEMBER 31, SEPTEMBER 30,
------------------- MARCH 31, DECEMBER 31, -------------------------- -------------------
1994 1995 1996 1996 1997 1998 1998 1999
-------- -------- --------- ------------ ------------ ----------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
DATA:
Total revenues.......... $ 34,861 $ 32,386 $ 13,309 $ 47,079 $ 62,771 $ 56,690 $ 43,598 $ 39,080
Lease operating
expenses.............. 6,123 6,408 2,403 6,495 9,376 9,858 7,554 8,380
Depreciation, depletion
and amortization...... 16,221 15,635 6,309 24,747 31,719 33,833 25,023 23,488
Impairment of oil and
gas properties........ 6,257 -- -- 22,500 28,514 50,800 -- --
General and
administrative
expenses.............. 1,830 2,028 712 2,406 3,195 4,749 3,417 4,007
Provision for
litigation............ -- -- -- -- -- 2,800(1) 2,960(1) --
-------- -------- -------- --------- --------- --------- -------- --------
Operating income
(loss).............. 4,430 8,315 3,885 (9,069) (10,033) (45,350) 4,644 3,205
Interest income......... 1,084 9,255 2,167 515 467 313 299 29
Interest expense........ (8,125) (12,772) (3,391) (7,746) (10,644) (13,384) (9,512) (14,754)
Write-off of bridge loan
fees.................. -- -- -- (2,392) -- -- -- --
-------- -------- -------- --------- --------- --------- -------- --------
Income (loss) before
income taxes........ (2,611) 4,798 2,661 (18,692) (20,210) (58,421) (4,569) (11,520)
Provision for income
taxes................. -- 338 -- -- -- -- -- --
-------- -------- -------- --------- --------- --------- -------- --------
Net income (loss)..... $ (2,611) $ 4,460 $ 2,661 $ (18,692) $ (20,210) $ (58,421) $ (4,569) $(11,520)
======== ======== ======== ========= ========= ========= ======== ========
Basic and diluted
earnings per share.... -- -- -- $ (1.58) $ (1.71) $ (4.47) $ (0.36) $ (0.83)
Average shares
outstanding........... -- -- -- 11,831 11,842 13,080 12,744 13,928
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------------------------------------
ACQUIRED AS OF
COMPANY(1) SEPTEMBER 30,
1994 1995 1996 1997 1998 1999
-------- -------- -------- -------- -------- -------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents........................ $ 4,335 $ 5,456 $ 10,819 $ 9,131 $ 802 $ 1,326
Total assets..................................... 138,202 250,726 196,749 212,577 262,792 282,423
Total debt....................................... 108,500 165,500 99,525 113,574 178,024 217,361
Shareholders' equity............................. 18,798 69,258 77,053 57,174 27,534 16,014
</TABLE>
- ---------------
(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."
21
<PAGE> 27
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 1998 and the first nine months of 1999 we:
- made an exploratory discovery in the deepwater Gulf on the Aconcagua
prospect located in 7,100 feet of water, making us six of ten in
deepwater Gulf exploratory test wells drilled since our acquisition from
Hardy;
- added net reserves in 1998 of 48.1 Bcfe, which were approximately 200% of
our 1998 production of 24.2 Bcfe;
- commenced production from the Dulcimer deepwater project in April 1999,
14 months after discovery;
- added 20 deepwater blocks from successes at three Gulf lease sales,
giving us 125 blocks in the Gulf with 72 in the deepwater Gulf as of
September 30, 1999; and
- sold a 63% interest in the Pluto deepwater exploitation project to
Burlington Resources, retaining a 37% working interest, which will
increase to 51% after payout.
We expect capital expenditures for 1999 to be approximately $63 million and
for 2000 to be approximately $110 million, which we intend to use to explore,
develop 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 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 were to rise substantially over the price established by the hedges.
These hedges also may expose us to the risk of financial loss in some
circumstances, including possibly instances in which our production is less than
expected or there is an unexpected event materially affecting prices.
Another significant factor affecting us will be competition, both from
other sources of energy such as electricity and from within the industry. 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
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.
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
22
<PAGE> 28
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. If a writedown were
required, it would result in a charge to earnings but would not have an impact
on cash flows.
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, 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>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- -----------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
PRODUCTION DATA:
Oil (MBbls)................................ 750 977 786 625 502
Natural gas (MMcf)......................... 20,429 18,004 19,477 14,591 15,559
Natural gas equivalent (MMcfe)............. 24,929 23,866 24,193 18,341 18,571
Average daily production (MMcfe)........... 68 65 66 67 68
AVERAGE REALIZED SALES PRICES (INCLUDING
EFFECTS OF HEDGING):
Oil (per Bbl).............................. $ 18.04 $ 18.48 $ 12.80 $ 13.27 $ 14.12
Natural gas (per Mcf)...................... 2.29 2.48 2.39 2.42 2.06
Natural gas equivalent (per Mcfe).......... 2.42 2.63 2.34 2.38 2.10
EXPENSES (PER MCFE):
Lease operating............................ 0.36 0.39 0.41 0.41 0.45
General and administrative, net(1)......... 0.13 0.13 0.20 0.19 0.22
Depreciation, depletion and amortization,
before impairment provision............. 1.25 1.33 1.40 1.36 1.26
</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.
NINE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO NINE MONTHS ENDED
SEPTEMBER 30, 1998
Net production increased 1% to 18.6 Bcfe for the first nine months of 1999
from 18.3 Bcfe for the same period of 1998. Production from our offshore Gulf
properties increased to 13.0 Bcfe in the nine-month period from 9.6 Bcfe in the
same period of 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
reduced production from our Sandy Lake field onshore Texas. We anticipate that
our total production for the remainder of 1999 will increase as a result of the
expected commencement of production from the Pluto field in the fourth quarter.
Hedging activities for the first nine months of 1999 decreased our average
realized natural gas price received by $0.24 per Mcf and revenues by $3.8
million, compared with an increase of $0.12 per Mcf and revenues of $1.8
million. Our hedging activities with respect to crude oil for the first nine
months of 1999 reduced the average sales price received by $1.32 per Bbl and
revenues by $0.7 million. There were no oil hedges in 1998.
23
<PAGE> 29
Oil and gas revenues decreased 10% to $39.1 million for the first nine
months of 1999 from $43.6 million for the comparable period of 1998 due to a 12%
decrease in realized prices to $2.10 per Mcfe in the first nine months of 1999
from $2.38 per Mcfe in the same period last year. This decrease was offset in
part by the production increase discussed above.
Lease operating expenses increased 11% to $8.4 million for the first nine
months of 1999 from $7.6 million for the comparable period of 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 6% to $23.5
million for the first nine months of 1999 from $25.0 million for the comparable
period of 1998 as a result of the decrease in the unit-of-production
depreciation, depletion and amortization rate to $1.26 per Mcfe from $1.36 per
Mcfe. This decrease was offset in part by a 1% increase in equivalent volumes
produced. The lower rate for the first nine months of 1999 was primarily due to
the $50.8 million non-cash full cost ceiling test impairment recorded in 1998.
General and administrative expenses, which are net of overhead
reimbursements we received from other working interest owners, increased 17% to
$4.0 million for the first nine months of 1999 from $3.4 million for the
comparable period of 1998 due to increased personnel-related costs in 1999
required for us to pursue our deepwater Gulf exploration and development plan.
Interest expense for the first nine months of 1999 increased 55% to $14.8
million from $9.5 million for the comparable period of 1998, due to additional
borrowings under our affiliate credit facilities with Enron totalling $75
million, which were entered into subsequent to the second quarter of 1998.
Income (loss) before income taxes was a $11.5 million loss for the first
nine months of 1999, primarily as a result of the oil and gas revenue decreases
and increased expenses discussed above.
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 realized 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 realized natural gas 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.
24
<PAGE> 30
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 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 49% 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.
1997 COMPARED TO 1996
Net production decreased 4% to 23.9 Bcfe in 1997 from 24.9 Bcfe in 1996.
Natural gas production decreased by 2.4 Bcf, or 12%, to 18 Bcf from 20.4 Bcf.
Natural gas production from our offshore properties decreased 3.8 Bcf or 23%,
due to natural production decline, while natural gas production from our onshore
properties increased 1.4 Bcf or 34%, due to the capacity expansion of the Sandy
Lake Central facility, which became operational in the first quarter of 1997.
Oil and condensate production increased by 227 MBbls to 977 MBbls from 750
MBbls, also due to the expansion of our Sandy Lake Central facility, offset in
part by a decrease in other onshore oil production resulting from the sale of
non-core Permian Basin properties in early 1996.
Oil and natural gas revenues for 1997 increased by $2.4 million, or 4%,
compared to 1996. The increase was the result of increased oil and natural gas
sales prices, offset in part by the production decrease described above. The
average realized sales price of natural gas increased 8%, to $2.48 per Mcf in
1997 from $2.29 per Mcf in 1996, while the realized oil sales price increased by
2% to $18.48 per Bbl in 1997 from $18.04 per Bbl in 1996.
Hedging activities for 1997 reduced our average realized natural gas sales
price received by $0.22 per Mcf and revenues by $3.9 million. In 1996, our
natural gas hedging activities decreased the average realized sales price
received by $0.18 per Mcf and revenues by $3.7 million. Hedging activities of
our crude oil during 1997 reduced the average sales price we received by $0.63
per Bbl and our revenues by $0.6 million, compared with a reduction in the
average realized sales price of $2.55 per Bbl and revenues of $1.9 million
during 1996. During 1997, approximately 60% of our equivalent production was
subject to hedge positions compared to 64% in 1996.
Lease operating expenses increased 6% to $9.4 million for 1997, from $8.9
million for 1996. Lease operating expense per Mcfe increased to $0.39 for 1997
from $0.36 for 1996, due to relatively fixed operating expenses spread over
reduced production volumes.
Depreciation, depletion and amortization expense increased 2% to $31.7
million for 1997, from $31.1 million for 1996, as a result of a 6% increase in
the unit-of-production depreciation, depletion and amortization rate to $1.33
per Mcfe from $1.25 per Mcfe, due to increased drilling and completion costs,
partially offset by a 4% reduction in equivalent volumes produced.
25
<PAGE> 31
Impairment of oil and natural gas properties of $28.5 million was recorded
in the first quarter of 1997 for a non-cash full cost ceiling test impairment
due to relatively low commodity prices in effect at March 31, 1997. During the
second quarter of 1996, a $22.5 million full cost ceiling writedown was recorded
in conjunction with our acquisition from Hardy.
General and administrative expenses, which are net of overhead
reimbursements received by us from other working interest owners on properties
operated by us, increased 3% to $3.2 million in 1997, up from $3.1 million in
1996, due primarily to higher employment and office costs in 1997 which were
almost entirely offset by increased overhead reimbursements during 1997.
Accordingly, there was no change in general and administrative expense per Mcfe
of $0.13 for both 1997 and 1996.
Interest expense decreased 5% to $10.6 million for 1997, from $11.1 million
for 1996, due primarily to the 9% decrease in our average outstanding debt to
$103.2 million in 1997, from $113.2 million in 1996, which decrease was
partially offset by a 7% increase in our average interest rate paid on
outstanding debt to 10.38%, from 9.68%. During 1996, we wrote off $2.4 million
of loan fees related to debt incurred in connection with the management-led
buyout in the second quarter of 1996. Interest income also decreased 83% to $0.5
million for 1997, from $2.7 million for 1996, due primarily to the retirement of
receivables from affiliates resulting from the acquisition by management of our
stock.
Income (loss) before income taxes decreased to a loss of $20.2 million for
1997, from a $16 million loss for 1996, as a result of the factors described
above.
LIQUIDITY, CAPITAL EXPENDITURES AND CAPITAL RESOURCES
CASH FLOW
As of September 30, 1999, we had a working capital deficit of approximately
$97.4 million, compared to a working capital deficit of $30.7 million at
December 31, 1998. The increase was attributable to $50 million of additional
short-term affiliate credit facilities, the reclassification of $25 million of
an affiliate credit facility previously classified as long-term and payment of
accounts payable and accrued liabilities. This increase was offset in part by a
$9.1 million reduction in accounts payable and accrued liabilities. We expect
our 1999 capital expenditures, including capitalized indirect costs and reduced
by proceeds from the sale of 63% of our Pluto project, to be approximately $63
million, which would exceed cash flow from operations. We expect our 2000
capital expenditures to be approximately $110 million, which would exceed cash
flow from operations for 2000. 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 monetize portions of our proved reserves or undeveloped inventory if
additional capital resources are not available to us on terms we consider
reasonable.
Our primary sources of cash during the three year period ended December 31,
1998 were funds generated from operations, proceeds from the sale of oil and gas
properties, proceeds from the issuance of notes, bank borrowings and capital
contributions by our former and present parent companies. Primary uses of cash
for the same period were funds used in exploration and production activities,
repayment of notes and bank debt, and the purchase of Hardy Oil & Gas USA, Inc.
Our primary sources of cash during the first nine months of 1999 were from
$50 million in proceeds from affiliate credit facilities provided by Enron. The
primary uses of cash for the same period were $43.7 million for capital
expenditures, $10.7 million in net payments on our revolving credit facility and
$9.1 million for the reduction of accounts payable. The $43.7 million for
capital expenditures is net of $19.8 million in proceeds from the sale of a
partial interest in the Pluto project.
We had a net cash inflow of $1.3 million for the nine months ended
September 30, 1999, and a net cash outflow of $8.3 million in 1998, compared to
a net cash outflow of $1.7 million in 1997 and a net
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<PAGE> 32
cash inflow of $10.8 million in 1996. A discussion of the major components of
cash flows for these periods follows.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------ --------------
1996 1997 1998 1998 1999
------ ------ ------ ----- ------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Net cash provided by (used for) our operating
activities
(in millions)......................................... $44.3 $52.9 $40.3 $18.9 $ 5.7
</TABLE>
Net cash provided by our operating activities was $5.7 million in the first
nine months of 1999, a decrease of $13.2 million for the same period of 1998
primarily due to decreased oil and gas prices and changes in 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. Cash from our
operating activities in 1997 increased by $8.6 million from 1996 primarily due
to increased oil and gas prices and changes in our working capital.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
----------------------- ---------------
1996 1997 1998 1998 1999
------ ----- ------ ------ -----
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Net cash used in our investing activities (in
millions)........................................... $221.8 $68.9 $141.9 $103.6 $43.7
</TABLE>
Net cash used in our investing activities for the first nine months of 1999
decreased to $43.7 million from $103.6 million for the same period of 1998 due
to fewer exploratory leasehold acquisitions, lower exploratory drilling
expenditures and the 63% sale of 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. Cash flows used
in our investing activities in 1997 decreased by $152.9 million compared to 1996
primarily because in 1996 cash was used to fund our acquisition of Hardy Oil &
Gas USA, Inc. for $184.7 million. This decrease was partially offset by an
increase of $22.6 million for capital expenditures for oil and gas properties in
1997 over 1996 and $7.5 million lower proceeds from the sale of oil and gas
properties in 1997 from 1996.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------- --------------
1996 1997 1998 1998 1999
------- ------ ------ ----- -----
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Net cash provided by our financing activities (in
millions)............................................. $188.3 $14.3 $93.2 $76.0 $39.3
</TABLE>
Net cash provided by our financing activities was $39.3 million for the
first nine months of 1999 compared to $76.0 million for the same period in 1998.
Our primary source of cash for the first nine months of 1999 was $50 million
from the credit facilities with Enron, offset in part by a net $10.7 million
repayment of borrowings under our revolving credit facility. 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. Cash provided by our
financing activities in 1997 decreased by $174 million compared to 1996
primarily because in 1996 cash was provided by $92.2 million of equity
contributed by our shareholders and the issuance of $99.5 million of senior
subordinated notes, offset in part by proceeds of borrowings from the revolving
credit facility in 1997 of $14 million.
CHANGES IN PRICES AND HEDGING ACTIVITIES
The energy markets have historically been very volatile. We cannot assure
you that oil and natural gas prices will not be subject to wide fluctuations in
the future. In an effort to reduce the effects of the
27
<PAGE> 33
volatility of the price of oil and natural gas on our operations, we have
adopted a policy of hedging oil and natural gas prices from time to time through
the use of commodity futures, options and swap agreements. While the use of
these hedging arrangements limits the downside risk of adverse price movements,
it also limits future gains from favorable movements.
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>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------- ------------------
1996 1997 1998 1998 1999
------- ------- ------ ------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Increase (decrease) in our natural gas sales
(in thousands)................................. $(3,701) $(3,931) $2,337 $1,777 $(3,818)
Increase (decrease) in our oil sales (in
thousands)................................... (1,912) (614) -- -- (666)
Effect of hedging transactions on our average
gas sales price (per Mcf).................... (0.18) (0.22) 0.12 0.12 (0.24)
Effect of hedging transactions on our average
oil sales price (per Bbl).................... (2.55) (0.63) -- -- (1.32)
</TABLE>
The following table shows our open hedging positions as of September 30,
1999.
<TABLE>
<CAPTION>
PRICES
NOTIONAL ------------------------
TIME PERIOD QUANTITIES FLOOR CEILING FIXED FAIR VALUE
- ----------- ---------- ----- ------- ----- --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
NATURAL GAS (MMBTU)
July 1 -- October 31, 1999................ 1,860 $1.85 $2.05 $ -- $(1,042)
November 1 -- December 31, 1999
Fixed Price Swap..................... 2,684 -- -- 2.18 (1,759)
Market Sensitive Swap................ 1,220 -- -- 2.60 303
January 1 -- December 31, 2000
Fixed Price Swap..................... 10,980 -- -- 2.18 (5,215)
Market Sensitive Swap................ 1,820 -- -- 2.60 404
January 1 -- December 31, 2001
Fixed Price Swap..................... 4,380 -- -- 2.18 (1,920)
January 1 -- October 31, 2002
Fixed Price Swap..................... 1,824 -- -- 2.18 (774)
CRUDE OIL (BBLS)
October 1 -- December 31, 1999............ 110,400 -- -- 16.54 (868)
November 1 -- December 31, 1999........... 94,583 -- -- 19.89 (418)
January 1 -- December 31, 2000............ 1,481,991 -- -- 18.72 (3,364)
</TABLE>
We purchased two natural gas call options for November 1999 and December
1999 for a cumulative notional quantity of 1,098 MMBtu at exercise prices of
$4.25 per MMBtu for November and $4.50 per MMBtu for December. Hedging
arrangements for 1999 cover approximately 70% of our anticipated equivalent
production for the year. Hedging arrangements for 2000, 2001 and 2002 cover
approximately 41% for 2000, 9% for 2001 and 3% for 2002 of our anticipated
equivalent production. The fair value for our hedging instruments was determined
based on brokers' forward price quotes and NYMEX forward price quotes as of
September 30, 1999. As of September 30, 1999, a commodity price increase of 10%
would have resulted in an unfavorable change in the fair value of our hedging
instruments of $8.5 million and a commodity price decrease of 10% would have
resulted in a favorable change in the fair value of our hedging instruments of
$8.5 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. However, we are subject to interest rate risk
28
<PAGE> 34
under our revolving credit facility and affiliate credit facilities with Enron.
For example a 10% increase in the London Interbank Offered Rate would have
increased our 1998 interest expense by $0.3 million. The carrying value of the
revolving credit facility and affiliate credit facilities approximates market
since these instruments have floating 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, 1998 and the nine month periods ended September 30, 1998 and 1999.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------- --------------
1996 1997 1998 1998 1999
------ ------ ------- ------ -----
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
CAPITAL EXPENDITURES (IN MILLIONS):
Leasehold acquisition -- unproved properties....... $14.3 $21.6 $ 43.1 $ 43.8 $ 1.2
Leasehold acquisition -- proved properties......... -- 3.2 -- -- --
Oil and natural gas exploration.................... 22.7 27.4 35.7 19.3 3.8
Oil and natural gas development and other.......... 9.6 16.7 63.1 40.5 38.7
----- ----- ------ ------ -----
TOTAL CAPITAL EXPENDITURES........................... $46.6 $68.9 $141.9 $103.6 $43.7
===== ===== ====== ====== =====
</TABLE>
Our capital expenditures for the first nine months of 1999 were $63.5
million, excluding the $19.8 million related to our sale of a 63% working
interest in the Pluto project. Our capital expenditures included $17.2 million
for exploration activities, $39.5 million for development activities and $6.8
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 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 increase in both
leasehold acquisition of unproved properties and oil and gas exploration,
and
- increased development related spending, both to acquire additional
interests in existing proved properties and to develop successful
exploratory prospects.
Total capital expenditures for 1997 were $22.3 million more than 1996. The
increase was due primarily to:
- our continued focus on building and evaluating our exploration and
exploitation prospect inventory, as evidenced by the increase in both
leasehold acquisition -- unproved properties and geological and
geophysical expenditures; and
- our increased development related spending, both to acquire additional
interest in an existing proved property and in development expenditures
on successful exploratory prospects.
Our capital expenditure plan for the fourth quarter of 1999 includes
drilling three or four exploratory wells, including two 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 partners in the well. We also
expect to drill two development wells and to complete the drilling of the
production well and related facilities necessary for our Pluto project to
commence production in the fourth quarter of 1999. We also have entered into an
agreement with an affiliate to sell the Pluto flow line and related facilities,
and we entered into a firm
29
<PAGE> 35
transportation agreement for the flow line. We expect our capital expenditures
for 1999, including capitalized indirect costs and reduced by proceeds from the
sale of 63% of our Pluto deepwater Gulf exploitation project, to be
approximately $63 million.
Our planned capital expenditures for 2000 total approximately $110 million.
The plan includes approximately $20 million to drill four exploratory wells, all
in the deepwater Gulf. Our share of exploratory well costs on one of these
deepwater wells will be paid by our partners. Our plan anticipates spending
approximately $20 million to acquire deepwater lease blocks and to build our
seismic inventory. We also anticipate expenditures of approximately $60 million
for development projects, including our Apia, Black Widow and Aconcagua
projects, and costs that are contingent on the success of our future exploratory
drilling.
Our debt outstanding as of September 30, 1999 was approximately $217.4
million, including $99.7 million of senior subordinated notes, $42.7 million
drawn on our revolving credit facility, both of which we classified as long-term
debt, $50 million drawn on our Enron credit facility and $25 million on our
senior credit facility. Following our semi-annual borrowing base redetermination
completed in October 1999, our borrowing base under the revolving credit
facility was reaffirmed at $60 million. In April 1999, we established a $25
million senior credit facility with Enron to obtain funds needed to execute our
1999 capital expenditure program and for short-term working capital needs. As of
September 30, 1999, we had fully drawn this facility. The $50 million drawn on
our Enron credit facility provides for an optional conversion by Enron to our
common shares for the outstanding debt and accrued interest at a rate of $14.58
per common share.
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
senior credit facility with Enron. We expect to repay the facilities 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, 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 anticipated growth will be realized, that our business will
generate sufficient cash flow from operations or that future borrowings or
equity capital will be available in an amount sufficient to enable us to service
our indebtedness or make necessary capital expenditures. In addition, depending
on the levels of 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
obtain financing on acceptable terms to complete a refinancing.
We expect to fund our activities in the remainder of 1999 and for 2000
through a combination of proceeds of the offering, cash flow from operations and
borrowings under our revolving credit facility. However, we cannot assure you
that we will realize our anticipated growth, that our business will generate
sufficient cash flow from operations or that future borrowings or equity capital
will be available in an amount sufficient to enable us to service our
indebtedness or make necessary capital expenditures.
30
<PAGE> 36
YEAR 2000 COMPLIANCE
The year 2000 issue concerns the ability of information technology and
non-information technology systems and processes to recognize and process
properly date-sensitive information before, during and after December 31, 1999.
STATE OF READINESS
We have been following a year 2000 project life cycle methodology that
includes the following phases:
- an initial assessment and inventory of our year 2000 issues;
- the development of a detailed plan to address our year 2000 issues;
- the testing of our systems with year 2000 issues;
- the remediation and upgrade of our year 2000 issues;
- contingency planning related to our worst-case scenarios; and
- an assessment of our business partners' readiness.
We had completed the first three phases and have substantially completed
the remediation and upgrade phase as of October 31, 1999. We are now finalizing
the contingency planning and business partner readiness phases.
We conducted the initial assessment and inventory phase in February 1999.
This phase consisted of an assessment of all computer automation in the
following areas:
- business application systems;
- information technology infrastructure and computing environment;
- geophysical and exploration hardware and software;
- field automation and process control;
- communications; and
- corporate office infrastructure.
Our initial assessment and inventory results showed that, according to
third-party providers, manufacturers and vendors, over 90% of these items were
year 2000-ready. We are currently executing a detailed plan to remediate the
remaining 10%. As of October 31, 1999, we were approximately 97% complete with
all known items that require replacement or remediation. The one remaining
remediation item, integrating non-compliant operations control system to an
existing year 2000-ready system at the Garden Banks 367, is in progress and has
an expected completion date of November 22, 1999.
Because the year 2000 issue is a unique event with no historical
perspective, we cannot guarantee we will have no year 2000 problems or that
these problems will not be material. However, we are taking reasonable measures
to prevent year 2000 business process failures. We are following a structured
plan, we have established an executive committee to oversee the plan and we have
recently completed various technology updates.
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<PAGE> 37
BUSINESS PARTNER READINESS
The year 2000 issue affects all of our customers, vendors and other key
business partners. Therefore, we have implemented a business partner readiness
program and we completed the assessment of all key business partners. Our
assessment procedures include the following:
- directly contacting the business partner;
- accessing the business partner's web site; or
- reviewing the business partner's Securities and Exchange Commission
filings.
This program was substantially completed as of October 31, 1999.
COSTS TO ADDRESS YEAR 2000 ISSUES
Our costs directly related to the year 2000 issue have been approximately
$110,000, including external consulting fees. Approximately $50,000 of this
amount has been capitalized and attributed to the replacement of desktop and
server hardware acquisitions. We expensed the remaining $60,000. We do not
expect to incur any additional costs directly related to the year 2000 issue.
However, we cannot assure you that we will not incur additional costs.
YEAR 2000 RISK FACTORS
Our most significant year 2000 risk factor relates to the readiness of
third-party hardware and software manufacturers and key business partners. We
are relying on their responses that they will be ready. However, we cannot
assure you that these third parties will be ready or predict with certainty the
effect of their unreadiness.
Our most likely "worst case" scenarios are:
- prolonged loss of power or mechanical failure that could jeopardize our
production and transportation operations;
- third-party suppliers' failure to deliver production supplies, which
failure would adversely affect our drilling and production process; and
- our inability to process financial transactions with banks or to bill,
receive or process payments from customers.
CONTINGENCY PLANS
We have developed initial drafts of written contingency plans that address
each of our worst case scenarios. We expect to finalize these drafts by November
22, 1999.
Statements in this section are "Year 2000 Readiness Disclosure" within the
meaning of the Year 2000 Information and Readiness Disclosure Act. This act does
not protect against matters arising under federal securities laws.
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" which was amended in June 1999 by
SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities -- Deferral of the Effective Date of FASB Statement No. 133 -- an
amendment of FASB Statement No. 133." 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. We
are currently evaluating what effect, if any, SFAS No. 133 will have on our
financial statements. We will adopt this statement no later than January 1,
2001.
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<PAGE> 38
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 15 years, and
an affiliate of Enron 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:
- operated seven successful subsea development projects in water depths of
400 feet to 2,700 feet;
- developed three deepwater exploitation projects acquired from major oil
companies, including our Pluto project;
- discovered six new fields in ten deepwater Gulf exploration tests,
including a recent potentially significant discovery at our Aconcagua
prospect;
- acquired 64 deepwater Gulf lease blocks, most of which are free of
royalty payment obligations; and
- built an inventory of 18 exploration prospects as of September 30, 1999,
including 14 prospects in the deepwater Gulf.
Ryder Scott Company estimated that we had proved reserves of 175.8 Bcfe as
of September 30, 1999, of which 69% were natural gas and 31% were oil and
condensate. For the nine months ended September 30, 1999, we produced an average
of 68 MMcfe per day.
We expect our production levels and operating cash flow to increase
significantly based on production from our Dulcimer project, which began in
April 1999, and our Pluto project, which we expect to begin producing in the
fourth quarter of 1999 at a rate of approximately 30 to 40 MMcfe per day net to
our interest. We expect further increases on commencement of production from our
Apia and Black Widow projects, currently scheduled for the second quarter and
third quarter of 2000, respectively. We also expect to drill eight of our
exploration prospects by the end of 2000, including six deepwater Gulf prospects
with potential to add significant quantities of proved reserves and future
production.
Our planned capital expenditures for 2000 consist of approximately $110
million for leasehold acquisition, exploration drilling and development
projects, compared to our planned capital expenditures of approximately $63
million for 1999.
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 seven years in the
deepwater Gulf have provided
33
<PAGE> 39
us with the geophysical and geological skills, operating expertise and
relationships necessary to operate successfully in the deepwater. Our deepwater
Gulf expertise includes:
- a strong understanding of the geology and geophysics of the deepwater
Gulf;
- familiarity with challenges peculiar to operating in the deepwater Gulf;
and
- 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 September 30, 1999, consisted of 125 lease blocks,
including 72 in the deepwater. Our prospect inventory includes 18 exploration
prospects, 14 of which are in the deepwater Gulf. We expect to drill eight of
our exploration prospects by the end of 2000, six of which are in the deepwater
Gulf. Our seismic database includes 3-D seismic that covers approximately 7,500
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.
EXPERIENCED OPERATIONS AND TECHNICAL STAFF AND MANAGEMENT. Our 12
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 15 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 17%. We believe that
management's ownership aligns its interests with those of other shareholders.
STRATEGY
Our business strategy is to increase reserves, production and cash flow
profitably by emphasizing growth through the drillbit in the deepwater Gulf, and
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 scheduled to become
available via lease sales, 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:
- exploring below the reserve potential threshold of the major oil
companies; and
- 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:
- the potential for discovery of large hydrocarbon deposits;
- relatively favorable reservoir characteristics;
- the prevalence of 3-D seismic direct hydrocarbon indicators;
- the relatively under-explored nature of the deepwater Gulf;
- the recent advances in deepwater production technology that reduce
development costs and expedite production; and
34
<PAGE> 40
- 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 18 exploration prospects as of September
30, 1999, were internally generated by our staff of 12 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.
MANAGE DEEPWATER RISKS BY CONTROLLING COSTS. A key to our growth and
operations in the deepwater Gulf is controlling our costs. To control our costs,
we intend to:
- target projects with gross drilling costs of less than $20 million;
- use 3-D seismic analysis to analyze direct hydrocarbon indicators;
- operate the wells in which we participate;
- limit projects generally to drilling depths of less than 10,000 feet
below the sea floor;
- use our expertise in existing technology, including subsea production
technology, to reduce our capital expenditures and accelerate the
commencement of production; and
- use the strong business relationships that we have developed with service
companies to reduce our costs.
MANAGE DEEPWATER RISKS THROUGH COMPLEMENTARY OPERATIONS AND RISK
SPREADING. A key to our strategy is managing our deepwater exploration risks
through complementary operations and risk spreading. To further this strategy,
we intend to:
- complement our exploration activities by developing exploitation
projects, such as the Pluto project, and making strategic acquisitions of
additional deepwater interests;
- maximize production from our proved onshore and shallow water properties
to supplement our cash flow;
- maintain a risk-weighted, diversified portfolio of drilling
opportunities; and
- sell a portion of our working interests to industry partners, typically
on a promoted basis, where all or a portion of our costs are paid by
partners.
APPLY OUR DEEPWATER OPERATIONAL EXPERTISE. We intend to use our deepwater
staff's expertise to:
- develop practical and proven technical solutions to drilling, development
and production problems; and
- shorten project cycle times and manage risks by using proven equipment
and procedures, matching the facilities to the reservoir, focusing on
full cycle costs and leveraging off the experience of our vendors.
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
35
<PAGE> 41
working interest to 100% and submitted a Deepwater Royalty Relief application
that was granted in July 1999. 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, our working interest increases to 51% and Burlington's
working interest decreases to 49%. We are developing the field with a single
subsea well in approximately 2,700 feet of water and a flow line tied back
approximately 29 miles to a production platform on the shelf. The project is
underway, and we expect to begin production in the fourth quarter of 1999 at an
estimated rate of 50 to 60 MMcf of natural gas per day and 6,000 to 8,000 Bbls
of oil per day. As of September 30, 1999, the field had estimated net proved
reserves of 27.0 Bcfe, 72% of which was natural gas.
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 of 1999 we drilled a successful exploration
well which encountered 102 net feet gas pay in a single zone. The field will be
developed by the single subsea well tied back to a host platform approximately
three miles from the well. We expect to initiate production in the second
quarter of 2000 at an estimated rate of 20 to 30 MMcf of natural gas per day.
The field had net proved reserves of 17.6 Bcfe, all of which was natural gas, as
of September 30, 1999.
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 45% 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 third or
fourth quarter of 2000 via subsea tieback to an existing platform at an
estimated rate of 5,000 to 8,000 Bbls of oil per day. Estimated net proved
reserves from Black Widow were approximately 14.1 Bcfe, 85% of which was oil, as
of September 30, 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 at a rate of approximately 58 MMcf
of natural gas per day, after tieback to a production platform located
approximately 14 miles from the well. The field had estimated net proved
reserves of 12.1 Bcfe, 99% of which was natural gas, as of September 30, 1999.
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 September 30, 1999, the field had produced 6.7 Bcfe net to us. Remaining net
proved reserves were estimated to be 5.8 Bcfe, 96% of which is natural gas. The
estimated remaining field life is six 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 two-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. As of September 30, 1999, the field had produced 10.5 Bcfe net to
us and remaining net proved reserves were estimated to be 2.2 Bcfe, 99% of which
is natural gas. The estimated remaining field life is three years.
36
<PAGE> 42
RECENT POTENTIALLY SIGNIFICANT DEEPWATER GULF DISCOVERY
Mississippi Canyon 305 (Aconcagua). We generated the Aconcagua prospect and
acquired it at a federal offshore Gulf lease sale in March 1998. During the
first quarter of 1999, we drilled a successful exploration well on the prospect.
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. We anticipate the operator, Elf Exploration, will drill an appraisal
well in the fourth quarter of 1999 or the first quarter of 2000. We hold a 25%
working interest in the block, and we expect a determination of proved reserves
when we drill the appraisal well.
GULF LEASE ACTIVITIES
At the federal offshore Gulf lease sale in March 1998, we were awarded the
leases on nine deepwater Gulf blocks covering seven drillable prospects in water
depths to approximately 7,000 feet. We generated all of the prospects and will
be the operator on eight of the nine blocks. The net share of our bids was $29.2
million, and our average working interest is 69%. We bid on seven of the ten
most actively-bid deepwater tracts in the sale, winning three. At the federal
offshore Gulf lease sale in August 1998, we were awarded the leases on eight
deepwater Gulf blocks in water depths to 4,700 feet. The net share of our bids
was $6.8 million, and our average working interest is 69%. At the federal
offshore Gulf lease sale in March 1999, we were awarded the leases on three
deepwater Gulf blocks in water depths ranging from 4,000 feet to 5,000 feet. The
net share of our bids was $8.9 million, and our average working interest is 83%.
On three of the blocks we acquired in the lease sales described above, our
partners have agreed to pay approximately $16 million of our exploration
drilling costs, representing most of our share of these costs. None of the
leases acquired in the lease sales described above expire before 2003 and most
of these leases expire in 2008 or later.
DEEPWATER GULF EXPLORATION PROSPECTS
We held an inventory of 18 exploration prospects as of September 30, 1999,
including 14 in the deepwater Gulf, which we expect to drill over the next three
years. Our higher potential exploration prospects, all of which are in the
deepwater Gulf, are summarized in the table below. As part of our risk
management strategy, we expect to sell a portion of our working interest in most
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 296 (Rigel).......... Texaco 23% 5,100 3rd Quarter 1999
Mississippi Canyon 773 (Devil's
Tower)................................ Mariner 50% 5,700 4th Quarter 1999
Keathley Canyon 18 (Kilimanjaro)........ Kerr-McGee 25% 4,700 2nd Quarter 2000
Green Canyon 516 (Yosemite)*............ Mariner 100% 4,075 2nd Quarter 2000
Atwater Valley 133 (Silverfish)......... Mariner 100% 3,500 2nd Quarter 2000
Green Canyon 737 (Mighty Joe Young)*.... Mariner 100% 4,450 1st Quarter 2001
Garden Banks 501 (Baritone)............. Mariner 50% 2,250 2nd Quarter 2001
Green Canyon 649 (Ham)*................. Mariner 100% 4,400 2nd Quarter 2001
East Breaks 623 (Falcon)................ Mariner 50% 3,267 3rd 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>
- -------------------------
* These prospects are part of the Gorilla Area discussed below.
37
<PAGE> 43
The following is a description of several of the more significant
exploration prospects included in our exploration prospect inventory.
Mississippi Canyon 773 (Devil's Tower). The Devil's Tower exploration
prospect is located approximately 130 miles southeast of New Orleans in 5,700
feet of water. We acquired the prospect in the March 1998 federal lease sale for
a gross bid of $24.6 million. We are the operator and we hold a 50% working
interest in the block.
No wells have been drilled on the block, though the prospect is in an area
characterized with significant production history. Immediately east of the block
is Shell's Mensa field. Approximately 20 to 30 miles to the west of the prospect
lie the Mars and Ursa fields. We believe that the objective interval for the
Devil's Tower prospect can be correlated with excellent quality sands in both of
these fields.
We have acquired and interpreted two 3-D seismic surveys over the prospect.
The seismic data show favorable amplitude anomalies at seven levels, which we
interpret to be direct hydrocarbon indicators. We anticipate drilling a 13,000
foot well on the prospect to test those three objective intervals in late 1999.
Green Canyon Blocks 514/516/558/646/649/737 (the Gorilla Area). The Gorilla
Area is located 170 miles south of New Orleans in water depths from 4,100 feet
to 4,400 feet. We, as 100% working interest owner, acquired these blocks at the
1998 and 1999 lease sales at a cost of $15.9 million. We expect to sell portions
of our working interests in these prospects on a promoted basis before drilling.
No drilling has occurred on the Gorilla Area to date. A key producing
analog in the prospect area is the King Kong discovery immediately north of the
prospect. Conoco drilled two wells that encountered hydrocarbons in an interval
that correlates with the objective section on several of the Gorilla Area
blocks. The remaining Gorilla area blocks are correlates with recent discoveries
at Holstein (Green Canyon 644) and Mad Dog (Green Canyon 826). These recent
discoveries, along with ongoing developments at King Kong, Brutus and Allegheny,
offer us the opportunity for cooperative ventures with the working interest
owners that could favorably affect the economic return of our Gorilla Area
prospects.
Using 3-D seismic, we have mapped five primary prospects in the Gorilla
Area. Each of the prospects has amplitude anomalies that we believe to be direct
hydrocarbon indicators. These amplitude anomalies are similar in character to
those observed in the area discoveries we mentioned above. We plan our initial
drilling in the prospect area in 2000.
Keathley Canyon Blocks 17, 18, 62, Garden Banks Block 986 (Kilimanjaro).
This deepwater Gulf prospect is located 230 miles southeast of Houston in 4,700
feet of water. We acquired the four prospect blocks at the August 1998 lease
sale for a gross bid of $11.3 million and we hold a 25% working interest in the
prospect.
The prospect is controlled by a 3-D seismic survey. We have mapped a
structural closure with amplitude anomalies at three levels within the objective
section. We have observed similar amplitude anomalies at several recent
deepwater discoveries. Kerr-McGee, the operator of the prospect, anticipates
drilling the initial well in the first half of 2000.
SHALLOW WATER GULF AND GULF COAST AREAS
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 had produced 5.4 Bcfe net to us
since its inception through September 30, 1999. The field had estimated net
proved reserves of 8.3 Bcfe, 79% of which was natural gas, as of September 30,
1999.
38
<PAGE> 44
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 22.7 Bcfe net to us from its
inception through September 30, 1999. The field has an estimated remaining
economic life of 11 years and estimated remaining net proved reserves of 11.6
Bcfe as of September 30, 1999.
Sandy Lake. 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, four of which
are producing. The field has produced a total of 33.5 Bcfe net to us as of
September 30, 1999. The estimated remaining field life is five years and
estimated net proved reserves are 4.8 Bcfe as of September 30, 1999.
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. However, a significant portion of the field's
remaining reserves are non-producing. We expect to access these reserves by
workover operations in the next six to 12 months. The field has produced, as of
September 30, 1999, a total of 10.0 Bcfe net to us. The field has an estimated
remaining life of eight years and estimated net proved reserves of 3.9 Bcfe.
PERMIAN BASIN (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. One well was a mechanical failure and will
likely be redrilled. Currently there are a total of 83 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 September 30, 1999 were 53.7 Bcfe. We
believe that the field's potential for continued economic oil production exceeds
40 years.
RESERVES
The following table shows information related to our estimated proved
reserves by geographic area as of September 30, 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 September 30, 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
39
<PAGE> 45
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
September 30, 1999 was determined by using actual realized prices as of
September 30, 1999, which averaged $24.07 per Bbl of oil and $3.19 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.
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1999
---------------------------------------------------------------------
PRESENT VALUE OF
PROVED RESERVES ESTIMATED FUTURE NET REVENUES
-------------------------------- ----------------------------------
OIL NATURAL GAS TOTAL DEVELOPED UNDEVELOPED TOTAL
GEOGRAPHIC AREA (MBBLS) (MMCF) (MMCFE) ($000) ($000) ($000)
- --------------- ------- ----------- -------- --------- ----------- --------
<S> <C> <C> <C> <C> <C> <C>
Deepwater Gulf.................. 3,348 62,498 82,584 109,468 $35,237 $144,705
Gulf Shallow Water and Gulf
Coast Areas................... 792 34,643 39,393 71,754 7,463 79,217
Permian Basin................... 4,897 24,398 53,779 24,611 22,031 46,642
----- -------- -------- -------- ------- --------
Total................. 9,037 121,539 175,756 $205,833 $64,731 $270,564
===== ======== ======== ======== ======= ========
Proved Developed Reserves....... 3,869 85,700 108,915 $205,833
===== ======== ======== ========
</TABLE>
The process of 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.
Our estimates of proved reserves in the table above do not differ
materially from those we have filed with other federal agencies.
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>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- -----------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
PRODUCTION DATA:
Oil (MBbls)................................ 750 977 786 625 502
Natural gas (MMcf)......................... 20,429 18,004 19,477 14,591 15,559
Natural gas equivalent (MMcfe)............. 24,929 23,866 24,193 18,341 18,571
Average daily production (MMcfe)........... 68 65 66 67 68
AVERAGE REALIZED SALES PRICES
(INCLUDING EFFECTS OF HEDGING):
Oil (per Bbl).............................. $ 18.04 $ 18.48 $ 12.80 $ 13.27 $ 14.12
Natural gas (per Mcf)...................... 2.29 2.48 2.39 2.42 2.06
Natural gas equivalent (per Mcfe).......... 2.42 2.63 2.34 2.38 2.10
</TABLE>
40
<PAGE> 46
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- -----------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
EXPENSES (PER MCFE):
Lease operating............................ 0.36 0.39 0.41 0.41 0.45
General and administrative, net(1)......... 0.13 0.13 0.20 0.19 0.22
Depreciation, depletion and amortization,
before impairment....................... 1.25 1.33 1.40 1.36 1.26
</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.
PRODUCTIVE WELLS
The following table shows the number of productive oil and natural gas
wells in which we owned a working interest as of September 30, 1999:
<TABLE>
<CAPTION>
TOTAL PRODUCTIVE
WELLS
----------------
GROSS NET
------ -----
<S> <C> <C>
Oil......................................................... 87 60.4
Natural gas................................................. 53 11.5
--- ----
Total............................................. 140 71.9
=== ====
</TABLE>
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 September 30, 1999. 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.
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES
----------------- ------------------
GROSS NET GROSS NET
------- ------ ------- -------
<S> <C> <C> <C> <C>
Texas (Onshore).............................. 22,021 14,055 4,141 2,107
All other states (Onshore)................... 671 212 644 196
Offshore..................................... 206,531 45,814 429,745 218,476
------- ------ ------- -------
Total.............................. 229,223 60,081 434,530 220,779
======= ====== ======= =======
</TABLE>
41
<PAGE> 47
DRILLING ACTIVITY
The following table sets forth information with regard to our drilling
activity during the periods indicated.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------------------- -------------------------
1996 1997 1998 1998 1999
----------- ----------- ------------ ----------- -----------
GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EXPLORATORY WELLS:
Productive.................. 3 0.8 4 1.4 3 1.1 2 0.7 2 1.3
Dry......................... 4 1.4 7 1.6 5 1.5 3 0.9 -- --
-- --- -- --- -- ---- -- --- -- ---
Total............... 7 2.2 11 3.0 8 2.6 5 1.6 2 1.3
== === == === == ==== == === == ===
DEVELOPMENT WELLS:
Productive.................. 5 1.7 11 5.3 19 8.6 11 6.4 6 0.8
Dry......................... -- -- -- -- 3 1.1 1 0.7 -- --
-- --- -- --- -- ---- -- --- -- ---
Total............... 5 1.7 11 5.3 22 9.7 12 7.1 6 0.8
== === == === == ==== == === == ===
TOTAL WELLS:
Productive.................. 8 2.5 15 6.7 22 9.7 13 7.1 8 2.1
Dry......................... 4 1.4 7 1.6 8 2.6 4 1.6 -- --
-- --- -- --- -- ---- -- --- -- ---
Total............... 12 3.9 22 8.3 30 12.3 17 8.7 8 2.1
== === == === == ==== == === == ===
</TABLE>
The results for the nine months ended September 30, 1999 include a
successful exploratory well on the Aconcagua prospect. However, no proved
reserves are yet attributable to this well pending drilling of an appraisal
well. A successful exploratory well was also drilled on the Apia prospect, for
which 17.6 Bcf of proved reserves was added as of September 30, 1999.
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%.
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
42
<PAGE> 48
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.
<TABLE>
<CAPTION>
PERCENTAGE OF TOTAL REVENUES
FOR THE YEARS ENDED
DECEMBER 31,
-----------------------------
CUSTOMER 1996 1997 1998
- -------- ----- ----- -----
<S> <C> <C> <C>
Duke Energy................................................. -- 19% 29%
Transco Energy Marketing Company............................ 15% 14% 16%
Enron North America Corp. .................................. -- 18% 15%
Genesis Crude Oil LP........................................ 13% 19% 10%
Texaco Natural Gas, Inc. ................................... 13% -- --
Seneca Resources Corporation................................ 10% -- --
</TABLE>
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 40% of our equivalent production was subject to hedge
positions during 1998. Hedging arrangements entered into through September 30,
1999, cover approximately 70% of our anticipated equivalent production for 1999.
Hedging arrangements for 2000, 2001 and 2002 cover approximately 41% for 2000,
9% for 2001 and 3% for 2002 of our anticipated equivalent production. In August
1999, we purchased two gas call options for November and December 1999 for a
cumulative notional quantity of 1,098 MMBtu. The November option is at $4.25 per
MMBtu and the December option is at $4.50 per MMBtu. Hedging arrangements may
expose us to the risk of financial loss in certain circumstances, including
instances where our production, which is in effect hedged, is less than expected
or where there is a sudden, unexpected event materially impacting prices. Our
revolving credit facility places restrictions on our use of hedging. 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."
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.
43
<PAGE> 49
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:
<TABLE>
<CAPTION>
WATER DEPTH ROYALTY RELIEF
- ----------- --------------
<S> <C>
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
</TABLE>
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 State 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.
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 qualified for royalty relief and have received
royalty relief on the Pluto leases.
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.
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
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<PAGE> 50
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.
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
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<PAGE> 51
environmental regulation. As with the industry generally, compliance with
existing regulations increases our overall cost of business. The areas affected
include:
- unit production expenses primarily related to the control and limitation
of air emissions and the disposal of produced water;
- 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
- 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:
- to remove or remediate previously disposed wastes, including wastes
disposed of or released by prior owners or operators;
- to clean-up contaminated property, including contaminated groundwater; or
- 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.
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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 September 30, 1999, we had approximately 80 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.
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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:
- Joint Energy acquired approximately 96% of the equity interests of
Mariner Holdings, Inc.; and
- 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.
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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 September 30, 1999. 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.
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- --- --------
<S> <C> <C>
Robert E. Henderson....................... 46 Chairman of the Board, President and Chief
Executive Officer
Richard R. Clark.......................... 44 Executive Vice President and Director
L. V. "Bud" McGuire....................... 57 Senior Vice President -- Operations and
Director
Michael W. Strickler...................... 43 Senior Vice President -- Exploration and
Land and Director
Frank A. Pici............................. 43 Vice President -- Finance, Chief Financial
Officer and Treasurer
Gregory K. Harless........................ 50 Vice President -- Oil and Gas Marketing
W. Hunt Hodge............................. 43 Vice President -- Administration
Thomas E. Young........................... 41 Vice President -- Land
Christopher E. Lindsey.................... 33 General Counsel and Secretary
David S. Huber............................ 49 Consultant and Director of Deepwater
Developments
Richard B. Buy............................ 46 Director
D. Brad Dunn.............................. 36 Director
Mark E. Haedicke.......................... 44 Director
Stephen R. Horn........................... 41 Director
Jeffrey McMahon........................... 37 Director
Jere C. Overdyke, Jr. .................... 46 Director
Frank Stabler............................. 45 Director
</TABLE>
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.
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MR. PICI has been 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
in Pittsburgh. Mr. Pici began his career at Coopers & Lybrand LLP, an accounting
firm, and is a certified public accountant.
MR. HARLESS has been 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 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.
MR. LINDSEY has been General Counsel and Secretary since August 1998.
Before joining us, Mr. Lindsey was associated with Bracewell & Patterson,
L.L.P., a law firm, for five years.
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. BUY has served as a director since January 1997. Since 1994, he has
been an employee of Enron North America Corp. or its affiliates, currently
serving as an Executive Vice President and the Chief Risk Officer of Enron Corp.
Before joining Enron North America Corp., Mr. Buy was a Vice President at
Bankers' Trust Company in the Energy Group.
MR. DUNN has served as a director since May 1999. He is a Vice President of
Enron North America Corp. and has held various positions with Enron North
America Corp. 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 1997. He is currently a
Managing Director and General Counsel of Enron North America Corp. Mr. Haedicke
also serves on the board of directors of the International Swaps and Derivatives
Association, Inc. and holds a seat on the New York Mercantile Exchange. He has
been associated with Enron North America Corp. since its inception in 1990.
MR. HORN has served as a director since November 1997. He has been an
employee of Enron North America Corp. since 1996 and is currently a Vice
President of Enron North America Corp. Before joining Enron North America Corp.,
Mr. Horn was a principal in Yellowstone Energy Partners, a private equity
investing firm in Houston, Texas, a position he had held since 1993.
MR. MCMAHON has served as a director since September 1998. Since 1994, he
has been an employee of Enron North America Corp. or its affiliates, currently
serving as Executive Vice President, Finance and the Treasurer of Enron Corp.
Before joining Enron North America Corp., Mr. McMahon served as Senior Vice
President and Chief Financial Officer of MG Natural Gas Corp., a medium-sized
natural gas marketing and finance company in Houston, Texas.
MR. OVERDYKE has served as a director since May 1996. Since 1991, he has
been an employee of Enron North America Corp. or its affiliates, currently
serving as a Managing Director of Enron Corp. 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. STABLER has served as a director since May 1996. He is currently the
President and Chief Operating Officer of Caribbean Basin Limited, an Enron
affiliate, and has held positions with Enron North
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America Corp. or its affiliates since 1992. From 1989 to 1992, Mr. Stabler
served as manager of investor services for American Exploration Company.
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, 1998, and includes two additional persons
who were not executive officers as of December 31, 1998. These individuals are
sometimes referred to as the "named executive officers."
<TABLE>
<CAPTION>
CURRENT YEAR
COMPENSATION
ANNUAL COMPENSATION UNDER OUR
-------------------------- OVERRIDING
YEAR OTHER ANNUAL ROYALTY ALL OTHER
NAME AND PRINCIPAL POSITION ENDED SALARY COMPENSATION(1) PROGRAM(2) COMPENSATION(3)
- --------------------------- ----- -------- --------------- ------------- ---------------
<S> <C> <C> <C> <C> <C>
Robert E. Henderson............. 1998 $285,000 $4,800 $1,292 $ 522
President and 1997 255,000 6,000 1,904 315
Chief Executive Officer 1996 236,000 6,000 1,167 306
Richard R. Clark................ 1998 225,000 4,800 821 306
Executive Vice President 1997 185,000 6,000 1,205 306
of Production 1996 166,500 6,000 710 306
Michael W. Strickler............ 1998 182,000 4,800 821 306
Senior Vice President 1997 165,000 6,000 1,205 306
of Exploration 1996 150,000 5,880 710 306
Frank A. Pici(4)................ 1998 160,000 4,380 356 306
Vice President of Finance and 1997 146,000 2,747 152 306
Chief Financial Officer 1996 12,167 0 0 26
Gregory K. Harless.............. 1998 143,000 3,813 527 522
Vice President of Oil and Gas 1997 127,100 4,911 779 522
Marketing 1996 121,000 4,760 491 522
Clinton D. Smith(5)............. 1998 111,993 4,221 520 183,229
Formerly Vice President of 1997 140,700 5,367 766 306
Operations 1996 131,500 5,154 468 306
James M. Fitzpatrick(5)......... 1998 107,269 3,720 527 151,227
Formerly Vice President of 1997 124,000 4,762 779 522
Land and Legal 1996 120,000 4,390 491 522
</TABLE>
- -------------------------
(1) These amounts reflect our contribution under the discretionary profit
sharing feature of our 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 those amounts are
not included in the table.
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(2) These amounts include the value conveyed 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 1998, 1997 or 1996.
(3) These amounts reflect insurance premiums paid by us for term life insurance
for the benefit of the named executive officers.
(4) Mr. Pici joined us in December 1996.
(5) Mr. Smith's employment with us terminated in September 1998, and Mr.
Fitzpatrick's employment with us terminated in October 1998. The "All Other
Compensation" column reflects both insurance premiums paid by us for term
life insurance and severance benefits pursuant to their employment
agreements with us.
OPTIONS
We did not grant any options to the named executive officers in 1998. None
of the named executive officers exercised stock options in 1998. The following
table shows the number and value of options owned by our named executive
officers at December 31, 1998. With the exception of options held by Mr. Pici,
all options held by the named executive officers were granted in connection with
our acquisition from Hardy in 1996. All of the options described in the table
below have been issued under the Mariner Energy LLC 1996 Stock Option Plan.
<TABLE>
<CAPTION>
NUMBER OF
COMMON SHARES UNDERLYING VALUE OF UNEXERCISED
UNEXERCISED OPTIONS AT IN-THE-MONEY OPTIONS AT
DECEMBER 31, 1998 DECEMBER 31, 1998(1)
--------------------------- ---------------------------
EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
----------- ------------- ----------- -------------
<S> <C> <C> <C> <C>
Robert E. Henderson............................ 95,448 143,172
Richard R. Clark............................... 67,164 100,764
Michael W. Strickler........................... 67,164 100,764
Frank A. Pici.................................. 14,616 58,464
Gregory K. Harless............................. 17,136 25,704
Clinton D. Smith............................... 107,100 0
James M. Fitzpatrick........................... 107,100 0
</TABLE>
- ---------------
(1) Assumes a market value equal to $ per share, the mid point of the
range shown on the cover of this prospectus.
SHARE OPTION PLAN
Under the Mariner Energy LLC 1996 Stock 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 2,226,948
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
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<PAGE> 58
for outstanding options to purchase an aggregate of 1,682,028 shares under the
1996 plan is $8.33 per share, and the exercise price for options to purchase the
remaining outstanding aggregate of 544,920 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, other than Messrs. Fitzpatrick
and Smith, who are no longer employed by us, are parties to employment
agreements that expire on September 30, 2002.
Following the expiration date of an employment agreement or the expiration
of any extended term, the employment agreements extend for:
- six months in the case of Messrs. Henderson, Clark, Strickler and Pici;
and
- three months in the case of Mr. Harless,
unless notice of termination is given by either us or the named executive
officer at least three or six (as applicable) months before the end of the
initial term or extended term, as applicable.
Under the employment agreements, the current annual salaries are $285,000
for Mr. Henderson, $225,000 for Mr. Clark, $190,000 for Mr. Strickler, $160,000
for Mr. Pici, and $143,000 for Mr. Harless. Effective with the completion of
this offering, the current annual salaries will be $340,000 for Mr. Henderson,
$245,000 for Mr. Clark, $190,000 for Mr. Strickler, $170,000 for Mr. Pici and
$150,000 for Mr. Harless. 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, depending on the employment agreement,
either an automobile allowance or a leased vehicle of our choice and
reimbursement for expenses related to the use of that leased vehicle. As
incentive compensation, the named executive officers are entitled to receive
overriding royalty interests in some oil and gas prospects that we have acquired
under our terminated overriding royalty program. See " -- Overriding Royalty
Program." The named executive officers are also entitled to receive bonuses
under our incentive compensation plan. See "-- Incentive Compensation Plan."
If we terminate a named executive officer's employment agreement without
cause, if the named executive officer terminates his employment contract for
good reason, or if either we or the named executive officer gives notice of
termination on the expiration of his term of employment, then the named
executive officer will be entitled to, among other things:
- the value of his salary and other benefits through the end of the initial
term or any extended term of the employment agreement;
- 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 and Strickler,
and six months salary in the case of Messrs. Pici and Harless;
- a lump sum cash payment equal to all earned and unused vacation time for
the previous year and the then current year; and
- an assignment of his vested interests under our incentive compensation
plans, including overriding royalty interests. See " -- Overriding
Royalty Program."
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If a named executive officer's employment agreement is terminated by the named
executive officer without good reason, he will be entitled to:
- the value of his salary and benefits through the date that his employment
agreement is terminated;
- a lump sum cash payment equal to all earned and unused vacation time for
the previous year and the then current year; and
- an assignment of his vested interests under our incentive compensation
plan, including overriding royalty interests. See "-- Overriding Royalty
Program."
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:
- pay his salary through the day of termination;
- pay him the value of his benefits under the employment agreement through
the month of termination; and
- assign to him his vested interests under our incentive compensation plan,
including overriding royalty interests. See "-- Overriding Royalty
Program."
To the extent any amounts paid on termination of 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 by the named executive officer other
than for good reason, for 12 months after the term expires in the case of
Messrs. Henderson, Clark and Strickler and six months after the term expires in
the case of Messrs. Pici and Harless, he will not compete with us for business
or hire away our employees.
For purposes of the employment agreements with the named executive
officers, "good reason" means:
- 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;
- 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;
- 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;
- 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
- 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.
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CHANGE OF CONTROL AGREEMENTS
We and each of the named executive officers are parties to change of
control agreements. Under these agreements, if a change of control occurs and
the named executive officer's employment is terminated without cause or for good
reason within 18 months of the change of control, Messrs. Henderson, Clark, Pici
and Strickler are entitled to receive three times their base salary and targeted
annual incentive bonus (or, if the change in control is due to an acquisition of
us by another company, three and one-half times their base salary and targeted
annual incentive bonus), and Mr. Harless is entitled to receive double his base
salary and annual incentive bonus. The severance payment will be calculated
assuming we satisfy the applicable base target for a particular year for the
targeted annual incentive bonus; see "-- Incentive Compensation Plan." The
ultimate payment due under the change of control agreements will be the greater
of the payment calculated under the change of control agreements or the
compensation due for the remaining balance under the employment agreements.
OVERRIDING ROYALTY PROGRAM
Effective with the successful completion of this offering, the overriding
royalty program will be terminated as of October 1, 1999. As a result of that
termination, no new overriding royalty interests will be awarded on prospects
that we acquire after October 1, 1999. However, overriding royalty interests
will continue to be awarded with respect to prospects acquired before October 1,
1999 under the terms of the terminated overriding royalty program, and we will
continue to pay overriding royalty interests with respect to those interests
assigned to employees before October 1, 1999.
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 acquired before October 1, 1999. 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
we acquired within the United States and U.S. coastal waters 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.
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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.
<TABLE>
<CAPTION>
AGGREGATE CASH AMOUNTS RECEIVED
FROM PREVIOUSLY ASSIGNED OVERRIDING
ROYALTY INTERESTS(1)
-----------------------------------
NAME 1996 1997 1998
- ---- --------- --------- ---------
<S> <C> <C> <C>
Robert E. Henderson.............................. $421,311 $394,136 $354,857
Richard R. Clark................................. 247,971 237,982 218,077
Michael W. Strickler............................. 258,731 234,603 212,803
Frank A. Pici.................................... 0 0 0
Gregory K. Harless............................... 86,383 81,725 70,541
Clinton D. Smith................................. 96,447 60,449 N/A(2)
James M. Fitzpatrick............................. N/A(2) N/A(2) N/A(2)
</TABLE>
- -------------------------
(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."
(2) Information is not available because the named individuals are no longer our
employees.
NEW COMPENSATION ARRANGEMENTS 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 after October 1, 1999.
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 1999 stock option plan -- to be adopted effective with the completion
of this offering.
Under the incentive compensation plan, each participant receives 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:
<TABLE>
<CAPTION>
PERCENT OF BASE SALARY AT PERCENT OF BASE SALARY AT
NAMED EXECUTIVE OFFICER 100% OF TARGET 120% OF TARGET
----------------------- ------------------------- -------------------------
<S> <C> <C>
Robert H. Henderson............................... 60% 120%
Richard R. Clark.................................. 45% 90%
Michael W. Strickler.............................. 35% 75%
Frank A. Pici..................................... 30% 60%
Gregory K. Harless................................ 25% 40%
</TABLE>
Under the Mariner Energy LLC 1999 stock 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 1999 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
1999 plan, subject to adjustment for any share split, share dividend
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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 1999 plan, none of which will be exercisable upon the completion of
the offering. The exercise price for outstanding options under the 1999 plan
will be the offering price for common shares in the offering. Subject to the
provisions of the 1999 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 1999 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 1999 plan.
Upon completion of this offering, under the 1999 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. Pici will be awarded options to purchase
shares, and Mr. Harless will be awarded options to purchase
shares.
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.
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, Horn and Dunn.
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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:
- the name and address of the selling shareholders; and
- the number of shares beneficially owned by the selling shareholders and
the percentage of outstanding common shares each owns, as of September
30, 1999, 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 September 30, 1999 or become exercisable within 60 days
following September 30, 1999. We had 33 record common shareholders and there
were 13,928,304 common shares outstanding as of September 30, 1999.
<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> <C> <C>
Joint Energy Development
Investments Limited
Partnership(1)..................... 13,334,184 95.7% %
1400 Smith Street
Houston, Texas 77002
Enron North America Corp........... 16,916,385(2) 96.6%(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) Enron has the right to acquire 3,582,201 shares upon the exercise by Enron
of its right to convert into our common shares the principal and accrued
interest we owe Enron under the Enron credit facility, based on the current
conversion price of $14.58 per share (which is subject to adjustment) and
an outstanding balance of principal and accrued interest of $52,240,316 as
of September 30, 1999. 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 common shares into which the Enron credit
facility are convertible are deemed outstanding solely for purposes of
calculating Enron's percentage beneficial ownership.
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The table appearing below shows information as of September 30, 1999,
relating to common shares beneficially owned by
- each of our directors;
- the named executive officers;
- a key consultant; and
- all directors and executive officers and this key consultant as a group.
<TABLE>
<CAPTION>
DIRECTORS, KEY CONSULTANT AND AMOUNT AND NATURE OF PERCENT
NAMED EXECUTIVE OFFICERS BENEFICIAL OWNERSHIP(1) OF CLASS
----------------------------- ----------------------- --------
<S> <C> <C>
Robert E. Henderson......................................... 228,012(2) 1.6%
Richard R. Clark............................................ 162,192(2) 1.2%
Michael W. Strickler........................................ 162,192(2) 1.2%
L. V. McGuire............................................... 42,468(2) *
Frank A. Pici............................................... 49,704(2) *
Gregory K. Harless.......................................... 38,904(2) *
David S. Huber.............................................. 158,976(2) 1.1%
Richard B. Buy.............................................. 0 0
D. Brad Dunn................................................ 0 0
Mark E. Haedicke............................................ 0 0
Stephen R. Horn............................................. 0 0
Jeffrey McMahon............................................. 0 0
Jere C. Overdyke, Jr. ...................................... 0 0
Frank Stabler............................................... 0 0
All directors and executive officers and key consultant as a
group (17 persons)........................................ 955,020 6.6%
</TABLE>
- ---------------
* 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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<PAGE> 65
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, seven of our directors are officers of Enron or of
affiliates of Enron: Mr. Buy is an Executive Vice President and the Chief Risk
Officer of Enron Corp., Mr. Dunn is a Vice President of Enron, Mr. Haedicke is a
Managing Director and the General Counsel of Enron, Mr. McMahon is the Executive
Vice President, Finance and the Treasurer of Enron Corp., Mr. Horn is a Vice
President of Enron, Mr. Overdyke is a Managing Director of Enron Corp. and Mr.
Stabler is the President and Chief Operating Officer of Caribbean Basin Limited.
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
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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."
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:
- any transaction permitted by the shareholders' agreement;
- the grant of options to purchase or sales of equity securities to our
directors, officers, employees and consultants; and
- 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:
- 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;
- transactions under employment agreements or compensation plans entered
into in the ordinary course of business and consistent with industry
practice; and
- 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, we have entered into a number of
agreements with Enron Corp. or affiliates of Enron Corp. for the purpose of
hedging oil and natural gas prices on our future production. 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
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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.
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 provides for unsecured,
subordinated loans of up to $50 million, bearing interest at LIBOR plus 4.5%,
payable at April 30, 2000. The full amount available under this credit facility
had been drawn as of September 30, 1999. This facility requires us to repay the
loan within one day of the closing of a public offering. Enron may convert into
our common shares the outstanding debt and accrued interest owed under this
facility at a rate of $14.58 per common share. We intend to use a portion of the
proceeds of the offering to repay all amounts outstanding under this facility
and terminate this facility. 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 provides
for senior unsecured revolving loans up to $25 million, bearing interest at
LIBOR plus 2.5%, payable quarterly. The full amount available under the senior
credit facility had been drawn as of September 30, 1999. The senior credit
facility requires us to repay the loan by December 31, 1999. We intend to use a
portion of the proceeds of the offering to repay all amounts outstanding under
this facility and terminate this facility. 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.
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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
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number of members of our board of directors has been set at nine but will be
increased to eleven in connection with the offering. For a description and
background of our directors, see "Management -- Directors and Executive
Officers."
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.
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 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:
- 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
- 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
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prior rights, if any, of the holders of any other of our company securities, the
holders of common shares are:
- entitled to receive dividends ratably as our board of directors declare,
if any;
- on our liquidation or dissolution, entitled to share ratably in all
remaining assets after satisfaction of our liabilities to creditors; and
- 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.
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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.
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:
- relieving Enron Corp. and its affiliates, other than Mariner, from any
obligation to offer business opportunities to us or to any of our
subsidiaries;
- 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
- 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:
- 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
- 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
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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.
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:
- 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;
- Enron Corp. and its affiliates, other than Mariner, will have no
obligation to offer to sell us any assets or related interest;
- 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;
- 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;
- 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;
- 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
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conflict between us and Enron Corp. and its affiliates, other than
Mariner, related to the matter is not material; and
- 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:
- approved by our oversight committee without bad faith and after
disclosure of all known material facts;
- made or taken on terms no less favorable to us than those generally
provided to or available from unrelated third parties; or
- 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:
- the consent of the board of directors and holders of a majority of our
equity interest; or
- 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 .
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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:
- that the management of a limited liability company will be conducted by a
board of directors and officers designated by the board; and
- 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:
- our affairs will be managed by our board of directors elected by our
shareholders;
- our officers will be elected by our board of directors and serve at the
discretion and pleasure of our board of directors;
- shareholder actions will be conducted at annual or special meetings of
shareholders called by our board of directors;
- holders of our common shares generally are not personally liable or
assessable for our obligations;
- holders of our common shares are entitled to receive dividends when, as
and if declared by our board of directors;
- holders of our common shares generally are entitled to receive a ratable
portion of our assets after payment of our liabilities upon dissolution;
- holders of our common shares have the right to bring a derivative action
against our management on our behalf;
- holders of our common shares after the offering will not be entitled to
preemptive rights with respect to the issuance of our securities; and
- 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 tradeable 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 October 31, 1999. 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 , 1999, 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:
<TABLE>
<CAPTION>
Number
Underwriter of Shares
----------- ---------
<S> <C>
Credit Suisse First Boston Corporation......................
Banc of America Securities LLC..............................
Morgan Stanley & Co. Incorporated...........................
PaineWebber Incorporated....................................
Petrie Parkman & Co., Inc...................................
--------
Total.............................................
========
</TABLE>
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%
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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.
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:
- our issuance of common shares under our employee benefit plans and
registration of these issuances;
- 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
- 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:
- market conditions for initial public offerings;
- the history of and prospects for our business;
- our past and present operations;
- our past and present earnings and current financial position;
- an assessment of our management;
- the market for securities of companies in businesses similar to our
business; and
- 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.
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- Over-allotment involves syndicate sales in excess of the offering size,
which creates a syndicate short position.
- Stabilizing transactions permit bids to purchase the underlying security
so long as the stabilizing bids do not exceed a specified maximum.
- 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.
- 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.
- 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
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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.
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, 1997 and 1998 and
for each of the three years in the period ended December 31, 1998 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 reports 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.
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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.
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.
75
<PAGE> 81
"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.
"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
76
<PAGE> 82
certainty to be recoverable in the future from known oil and natural gas
reservoirs under existing economic and operating conditions. This classification
includes:
- proved developed producing reserves, which are those expected to be
recovered from currently producing zones under continuation of present
operating methods; and
- 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.
"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.
77
<PAGE> 83
MARINER ENERGY LLC
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Independent Auditors' Report................................ F-2
Consolidated Balance Sheets as of December 31, 1997 and 1998
(Mariner Energy LLC)...................................... F-3
Consolidated Statements of Operations for the three months
ended March 31, 1996, (Acquired Company), the nine months
ended December 31, 1996, and the years ended December 31,
1997 and 1998 (Mariner Energy LLC)........................ F-4
Consolidated Statements of Stockholders' Equity for the
three months ended March 31, 1996, (Acquired Company), the
nine months ended December 31, 1996, and the years ended
December 31, 1997 and 1998 (Mariner Energy LLC)........... F-5
Consolidated Statements of Cash Flow for the three months
ended March 31, 1996 (Acquired Company), the nine months
ended December 31, 1996, and the years ended December 31,
1997 and 1998 (Mariner Energy LLC)........................ F-6
Notes to Consolidated Financial Statements.................. F-7
Condensed Consolidated Balance Sheets as of December 31,
1998 and September 30, 1999 (unaudited)................... F-21
Condensed Consolidated Statements of Operations for the Nine
Months Ended September 30, 1998 and 1999 (unaudited)...... F-22
Condensed Consolidated Statements of Cash Flow for the Nine
Months Ended September 30, 1998 and 1999 (unaudited)...... F-23
Notes to Condensed Consolidated Financial Statements
(unaudited)............................................... F-24
</TABLE>
F-1
<PAGE> 84
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
Mariner Energy LLC
Houston, Texas
We have audited the accompanying financial statements of Mariner Energy LLC
(the "Company"), formerly Hardy Oil & Gas USA Inc. (the "Acquired 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 generally accepted auditing
standards. 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, 1997 and 1998, and the results of its operations
and cash flows for the three months ended March 31, 1996, the nine months ended
December 31, 1996, and the years ended December 31, 1997 and 1998, in conformity
with generally accepted accounting principles.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Houston, Texas
April 14, 1999 (September 1, 1999, with respect to the
first and last paragraph of Note 1 and the
third paragraph of Note 4)
F-2
<PAGE> 85
MARINER ENERGY LLC
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1997 1998
------------ ------------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................................. $ 9,131 $ 802
Receivables............................................... 18,585 15,657
Prepaid expenses and other................................ 3,628 7,234
-------- ---------
Total current assets.............................. 31,344 23,693
-------- ---------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at full cost:
Proved................................................. 222,829 316,056
Unproved, not subject to amortization.................. 36,526 84,076
-------- ---------
Total............................................. 259,355 400,132
Other property and equipment.............................. 2,222 3,300
Accumulated depreciation, depletion and amortization...... (84,236) (167,846)
-------- ---------
Total property and equipment, net................. 177,341 235,586
-------- ---------
OTHER ASSETS, net of amortization........................... 3,892 3,513
-------- ---------
TOTAL ASSETS................................................ $212,577 $ 262,792
======== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable.......................................... $ 5,556 $ 20,375
Accrued liabilities....................................... 29,908 29,082
Accrued interest.......................................... 4,443 4,953
-------- ---------
Total current liabilities................................. 39,907 54,410
-------- ---------
ACCRUAL FOR FUTURE ABANDONMENT COSTS........................ 1,922 2,824
LONG-TERM DEBT:
Subordinated notes........................................ 99,574 99,624
Revolving credit facility................................. 14,000 53,400
Enron credit facility..................................... -- 25,000
-------- ---------
Total long-term debt.............................. 113,574 178,024
-------- ---------
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 1997 -- 11,871,156,
1998 -- 13,928,304 shares)............................. 119 139
Additional paid-in-capital................................ 95,957 124,718
Accumulated deficit....................................... (38,902) (97,323)
-------- ---------
Total stockholders' equity........................ 57,174 27,534
-------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $212,577 $ 262,792
======== =========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-3
<PAGE> 86
MARINER ENERGY LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
ACQUIRED
COMPANY
---------
THREE
MONTHS NINE MONTHS YEAR YEAR
ENDED ENDED ENDED ENDED
MARCH 31, DECEMBER 31, DECEMBER 31, DECEMBER 31,
1996 1996 1997 1998
--------- ------------ ------------ ------------
<S> <C> <C> <C> <C>
REVENUES:
Oil sales................................. $ 3,632 $ 9,897 $ 18,061 $ 10,066
Gas sales................................. 9,677 37,182 44,710 46,624
------- ----------- ----------- -----------
Total revenues.................... 13,309 47,079 62,771 56,690
------- ----------- ----------- -----------
COSTS AND EXPENSES:
Lease operating expenses.................. 2,403 6,495 9,376 9,858
Depreciation, depletion and
amortization........................... 6,309 24,747 31,719 33,833
Impairment of oil and gas properties...... -- 22,500 28,514 50,800
General and administrative expenses....... 712 2,406 3,195 4,749
Provision for litigation.................. -- -- -- 2,800
------- ----------- ----------- -----------
Total costs and expenses.......... 9,424 56,148 72,804 102,040
------- ----------- ----------- -----------
OPERATING INCOME (LOSS)..................... 3,885 (9,069) (10,033) (45,350)
INTEREST:
Related party income...................... 57 -- -- --
Other income.............................. 2,110 515 467 313
Related party expense..................... (381) -- -- (993)
Other expense............................. (3,010) (7,746) (10,644) (12,391)
Write-off of bridge loan fees............. -- (2,392) -- --
------- ----------- ----------- -----------
INCOME (LOSS) BEFORE INCOME TAXES........... 2,661 (18,692) (20,210) (58,421)
PROVISION FOR INCOME TAXES.................. -- -- -- --
------- ----------- ----------- -----------
NET INCOME (LOSS)........................... $ 2,661 $ (18,692) $ (20,210) $ (58,421)
======= =========== =========== ===========
BASIC AND DILUTED EARNINGS (LOSS) PER
SHARE..................................... -- $ (1.58) $ (1.71) $ (4.47)
======= =========== =========== ===========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING............................... -- 11,831,364 11,841,793 13,079,742
======= =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-4
<PAGE> 87
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>
ACQUIRED COMPANY:
Balance at December 31, 1995........ 1,000 $ 1 $ 81,094 $(11,837) $ 69,258
Net income.................. -- -- -- 2,661 2,661
---------- ---- -------- -------- --------
Balance at March 31, 1996............. 1,000 1 81,094 (9,176) 71,919
POST ACQUISITION:
Formation of Mariner Energy LLC..... 11,831,364 118 14,532 9,176 23,826
Net loss.................... -- -- -- (18,692) (18,692)
---------- ---- -------- -------- --------
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
Capital contribution -- proceeds
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
========== ==== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-5
<PAGE> 88
MARINER ENERGY LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
ACQUIRED
COMPANY
-----------
THREE
MONTHS NINE MONTHS YEAR YEAR
ENDED ENDED ENDED ENDED
MARCH 31, DECEMBER 31, DECEMBER 31, DECEMBER 31,
1996 1996 1997 1998
----------- ------------ ------------ ------------
<S> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss)........................... $ 2,661 $(18,692) $(20,210) $(58,421)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation, depletion and
amortization........................... 6,437 27,706 32,588 33,762
Impairment of oil and gas properties..... -- 22,500 28,514 50,800
Provision for litigation................. -- -- -- 2,800
Imputed interest......................... -- 1,322 -- --
Changes in operating assets and liabilities:
Receivables.............................. (1,873) (769) (5,014) 2,928
Receivables from affiliates.............. (2,109) -- -- --
Other current assets..................... (307) (317) (3,210) (3,606)
Other assets............................. -- -- (483) 379
Accounts payable and accrued
liabilities............................ 832 6,955 20,693 11,703
Payables to affiliates................... (11) -- -- --
------- -------- -------- --------
Net cash provided by operating
activities........................ 5,630 38,705 52,878 40,345
------- -------- -------- --------
INVESTING ACTIVITIES:
Purchase of Acquired Company, net of cash of
$5,438................................... -- (184,742) -- --
Additions to oil and gas properties......... (7,495) (38,236) (68,317) (140,777)
Additions to other property and equipment... (153) (741) (551) (1,078)
Proceeds from sale of oil and gas
properties............................... -- 7,528 -- --
Issuance of long-term receivable to
affiliates............................... (1,000) -- -- --
Repayment of long-term receivable from
affiliates............................... 3,000 -- -- --
------- -------- -------- --------
Net cash used in investing
activities........................ (5,648) (216,191) (68,868) (141,855)
------- -------- -------- --------
FINANCING ACTIVITIES:
Principal payments on long-term debt........ -- (92,000) -- --
Principal payments on revolving credit
facility................................. -- (50,000) -- --
Payments of debt issue costs................ -- (3,961) (29) --
Proceeds from subordinated notes............ -- 99,506 -- --
Proceeds from long-term debt................ -- 92,000 -- --
Proceeds from revolving credit facility,
net...................................... -- 50,000 14,000 39,400
Proceeds from Enron credit facility......... -- -- -- 25,000
Additional capital contributed.............. -- 92,150 -- --
Proceeds from sale of common stock.......... -- 610 331 28,781
------- -------- -------- --------
Net cash provided by financing
activities........................ -- 188,305 14,302 93,181
------- -------- -------- --------
INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS................................. (18) 10,819 (1,688) (8,329)
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD...................................... 5,456 -- 10,819 9,131
------- -------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD.... $ 5,438 $ 10,819 $ 9,131 $ 802
======= ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-6
<PAGE> 89
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION -- For the three months ended March 31, 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. ("Enron"), 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"). See Notes 2 and 3.
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, 1998 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 both onshore and offshore Texas and
Louisiana.
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
$22,500,000, $28,514,000 and $50,800,000 were recorded during 1996, 1997 and
1998, respectively. Subsequent to year-end, natural gas prices have declined.
This decline could result in an additional writedown 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.
F-7
<PAGE> 90
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
DEFERRED LOAN COSTS -- Deferred loan costs, which are included in other
assets, are stated at cost and amortized straight-line over their estimated
useful lives, not to exceed 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 $449,000, $729,000 and $1,702,000 for the years ended December 31,
1996, 1997 and 1998, 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.
F-8
<PAGE> 91
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FINANCIAL INSTRUMENTS -- The Company's financial instruments consist of
cash and cash equivalents, receivables, payables, and debt. At December 31, 1997
and 1998, the estimated fair value of the Company's Senior Subordinated Notes
was approximately $100,000,000. The estimated fair value was determined based on
borrowing rates available at December 31, 1997 and 1998, respectively, for debt
with similar terms and maturities. The carrying amount of the Company's other
financial instruments approximates fair value.
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, 1998, sales of oil
and gas to four purchasers, including an affiliate, 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. During the year ended December 31, 1996, sales of oil and gas to four
purchasers accounted for 15%, 13%, 13% and 10% 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"
which was amended in June 1999 by SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities -- Deferral of the Effective Date of FASB
Statement No. 133 -- an amendment of FASB Statement No. 133." 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 is currently evaluating what effect, if any,
SFAS No. 133 will have on the Company's financial statements. The Company will
adopt this statement no later than January 1, 2001.
2. THE ACQUISITION
Effective April 1, 1996, Mariner Holdings acquired all the capital stock of
the Acquired Company from Hardy Holdings Inc. for an aggregate purchase price of
approximately $185.5 million, including $14.5 for net working capital. In
connection with the Acquisition, substantial intercompany indebtedness and
receivables and third-party indebtedness of the Acquired Company were
eliminated.
The sources and uses of funds related to financing the Acquisition (See
Note 1) were as follows:
<TABLE>
<CAPTION>
SOURCES OF FUNDS
----------------
(IN MILLIONS)
<S> <C>
Bridge loan provided by Joint Energy(1)..................... $ 92.0
Common stock purchased by Joint Energy(2)................... 95.0
Working capital provided by the Company..................... 6.0
------
Total............................................. $193.0
======
</TABLE>
F-9
<PAGE> 92
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
USES OF FUNDS
-------------
(IN MILLIONS)
<S> <C>
Acquisition purchase price.................................. $185.5
Acquisition costs and other expenses(3)..................... 7.5
------
Total............................................. $193.0
======
</TABLE>
- -------------------------
(1) The Joint Energy Bridge Loan (see Note 4) was incurred by Mariner Holdings
to fund a portion of the consideration paid in the Acquisition.
(2) As contemplated in connection with the Acquisition and shortly after the
consummation thereof, certain members of the Company's management purchased
approximately 4% of the capital stock of Mariner Holdings for an aggregated
consideration valued at approximately $3.6 million. Such consideration
consisted of approximately $0.6 million in cash and approximately $3.0
million of overriding royalty interests, which amounts are not included in
the above sources and uses of funds related to the Acquisition.
(3) Includes $2.9 million of fees and expenses paid to Joint Energy associated
with the purchase of the common stock by Joint Energy, $2.6 million of
expenses paid to Joint Energy associated with the implementation of the
Joint Energy Bridge Loan and $2.0 million of other transaction fees and
expenses (See Note 4).
The Acquisition was accounted for using the purchase method of accounting.
As such, Joint Energy's cost to acquire the Acquired Company, including
transaction costs, have been allocated to the assets and liabilities acquired
based on estimated fair values. As a result, the Company's financial position
and operating results subsequent to the date of the Acquisition reflect a new
basis of accounting and are not comparable to prior periods. In addition, $1.3
million of interest was imputed for the period from April 1, 1996 to the date of
closing.
The allocation of Joint Energy's purchase price to the assets and
liabilities of the Company resulted in a significant increase in the carrying
value of the Company's oil and gas properties. Under the full cost method of
accounting, the carrying value of oil and gas properties is generally not
permitted to exceed the sum of the present value (10% discount rate) of
estimated future net cash flows from proved reserves, based on current prices
and costs, plus the lower of cost or estimated fair value of unproved properties
(the "cost center ceiling"). Based upon the allocation of Joint Energy's
purchase price, estimated proved reserves and product prices in effect at the
date of the Acquisition, the purchase price allocated to oil and gas properties
was in excess of the cost center ceiling by approximately $22.5 million. The
resulting writedown was a non-cash charge and was included in the results of
operations for the nine months ended December 31, 1996.
The allocation of the purchase price (including fees and expenses) is
summarized as follows (in millions of dollars):
<TABLE>
<S> <C>
Current assets............................................. $ 18.3
Property and equipment..................................... 181.4
Other noncurrent assets.................................... 2.6
Liabilities assumed........................................ (12.2)
------
Total............................................ $190.1
======
</TABLE>
F-10
<PAGE> 93
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following unaudited pro forma financial data have been prepared
assuming that the Acquisition and the related financing were consummated on
January 1, 1996. Amounts are in thousands:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1996
------------
<S> <C>
Revenues............................................... $60,388
Net income............................................. $ 6,511
</TABLE>
3. RELATED-PARTY TRANSACTIONS
RECEIVABLES FROM AFFILIATES -- Prior to the management buyout, the Acquired
Company had four lending facilities with Hardy plc. These facilities earned
interest income of approximately $2,110,000 for the three month period ending
March 31, 1996.
DEBT TO AFFILIATE -- Prior to the management buyout, the Acquired Company
had one loan facility outstanding with Hardy plc. The Acquired Company incurred
approximately $381,000 of interest expense relating to this debt for the three
month period ending March 31, 1996.
SALES TO AFFILIATES -- For the years ending December 31, 1996, 1997 and
1998, sales to affiliates were approximately $29,000, $13.0 million and $8.9
million, respectively.
GENERAL AND ADMINISTRATIVE EXPENSES -- Prior to April 1, 1996, the Acquired
Company paid an affiliate for various administrative support services. Included
in general and administrative expenses was approximately $29,000 for the three
months ended March 31, 1996, for such services. In management's opinion, such
allocated expenses reasonably represented expenses incurred by the affiliate on
behalf of the Acquired Company.
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, six 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.
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
F-11
<PAGE> 94
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
its affiliates will be, on terms no less favorable to the Company than would be
contained in an agreement with a third party.
4. LONG-TERM DEBT
JOINT ENERGY BRIDGE LOAN -- In connection with the Acquisition, Joint
Energy and Mariner Holdings entered into a Credit, Subordination and Further
Assurances Agreement dated May 16, 1996, pursuant to which Joint Energy provided
a loan commitment to Mariner Holdings of $105 million. Under this commitment
Mariner Holdings borrowed $92 million (the "Joint Energy Bridge Loan") to
partially fund the Acquisition. The Joint Energy Bridge Loan bore interest at 6%
above LIBOR. The Joint Energy Bridge Loan was repaid with proceeds of $50
million from borrowings under the Revolving Credit Facility (see below) and $42
million from the issuance of the 10 1/2% Senior Subordinated Notes (see below).
As a result of the repayments, the Joint Energy Bridge Loan was terminated. In
connection with the $92 million repayment, $2.4 million of the Joint Energy
Bridge Loan debt fees were written off during the nine months ended December 31,
1996.
REVOLVING CREDIT FACILITY -- On June 28, 1996, the Company entered into an
unsecured revolving credit facility (the "Revolving Credit Facility") with Bank
of America as agent for a group of lenders (the "Lenders"). On that date, the
Company borrowed $50 million under the Revolving Credit Facility and used the
proceeds to partially repay the Joint Energy Bridge Loan. During August 1996,
the outstanding balances of both the Revolving Credit Facility and the Joint
Energy Bridge Loan were repaid with the proceeds from the issuance of the
Company's 10 1/2% Senior Subordinated Notes.
The Revolving Credit Facility provides for a maximum $150 million revolving
credit loan which matures on October 1, 1999. The borrowing base under the
Revolving Credit Facility is currently $60 million and is subject to periodic
redetermination. The Revolving Credit Facility, had an outstanding balance of
$53.4 million at December 31, 1998. On June 28, 1999, the Revolving Credit
Facility was amended to extend the maturity date to October 1, 2002 and to
pledge certain mineral interests to secure the Revolving Credit Facility.
Accordingly, this liability was classified as long-term at December 31, 1998.
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%. On December 31, 1998
the effective rate was 6.90%. 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 contains various restrictive covenants which,
among other things, restrict the payment of dividends, limit the amount of debt
the Company's subsidiary, Mariner Energy, may incur, limit Mariner Energy's
ability to make certain loans and investments, limit Mariner Energy's ability to
enter into certain hedge transactions and provide that the Mariner Energy must
maintain specified relationships between cash flow and fixed charges and cash
flow and interest on indebtedness. As of December 31, 1998, Mariner Energy was
in compliance with all such requirements.
ENRON CREDIT FACILITY -- Mariner Energy LLC entered into an agreement with
Enron to provide a $25 million unsecured, subordinated credit facility (the
"Enron Credit Facility"). The Enron Credit Facility accrues interest at an
annual rate of LIBOR plus 2.5% and requires a structuring fee of 4% of the
borrowed amount. The effective interest rate as of December 31, 1998 was 8.06%.
The Enron Credit 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 Enron Credit Facility. The terms of the Enron Credit
Facility required that if financing did not become available by March 1, 1999,
up to $25 million of the Enron Credit Facility would be converted to equity.
Interest expense recorded as a
F-12
<PAGE> 95
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
result of this Enron Credit Facility for the year ended December 31, 1998, was
approximately $993,000. Subsequent to December 31, 1998, the Enron Credit
Facility was amended to (i) increase the size of the Enron Credit Facility to
$50 million, (ii) extend the maturity to April 30, 2000, (iii) accrue interest
at an annual rate of LIBOR plus 4.5%, and (iv) provide for an optional
conversion to common shares for the outstanding debt and accrued interest at a
rate of $14.58 per common shares of Mariner Energy LLC by Enron.
SENIOR CREDIT FACILITY WITH ENRON -- In April 1999, the Company established
a $25 million Senior Credit Facility with Enron ("Senior Credit Facility") 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 Senior
Credit Facility is currently $25 million and is subject to periodic
redetermination. The Senior Credit Facility accrues interest at an annual rate
of LIBOR plus 2.5% and requires a structuring fee of 1% of the committed amount.
The Senior Credit Facility will mature on December 31, 1999 and is expected to
be repaid from internally-generated cash flows.
Restrictions for Mariner Energy within the Revolving Credit Facility and
10 1/2% Senior Subordinated Notes restrict Mariner Energy's ability to pay
interest or principal on the Enron Credit Facility and Senior Credit Facility.
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) fully repay the Joint Energy Bridge Loan 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 Mariner Energy 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, 1998, 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.
As required in the indenture, in January 1997 the Company exchanged all of
the Notes for Series B notes with substantially the same terms as to principal
amount, interest rate, maturity and redemption rights. If the exchange offer had
not been consummated, the interest rate on the Notes would have increased by
0.5% per annum.
F-13
<PAGE> 96
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CASH PAID FOR INTEREST, -- Cash paid for interest for the nine month period
ending December 31, 1996, for the years ending December 31, 1997 and 1998 were
$10,656,000, $10,926,000 and $15,649,260, respectively.
5. STOCKHOLDERS' EQUITY
STOCK OPTION PLAN -- During June 1996, Mariner Holdings established the
Mariner Holdings, Inc. 1996 Stock 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, 1996, 1997 and 1998 the Company
granted stock options of 1,539,972, 142,056 and 329,160, respectively. No
options have been exercised or cancelled during the three year period. At
December 31, 1998, options (the "Options") to purchase 2,011,188 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.
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 nine months ended
December 31, 1996 and for the years ended December 31, 1997 and 1998 would have
increased $356,000, $777,000 and $912,000, respectively to $19,048,000,
$20,987,000 and $59,333,000 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 present
value calculation, risk free interest of 4.6%, no dividends and expected life of
5 years. Stock options available for future grant amounted to 422,412 shares at
December 31, 1998. Exercisable stock options amounted to 644,292 shares at
December 31, 1998.
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, the Company reached an agreement with
management shareholders and an affiliate of Enron to purchase common shares of
approximately $28.8 million of net equity capital, which was used to supplement
funding of the Company's 1998 capital expenditure plan.
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
F-14
<PAGE> 97
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 1996, 1997 and 1998, the Company contributed $165,000, $200,000, and
$182,000, 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, 1996, 1997 and 1998 the Company paid
$2.2 million, $1.3 million and $1.0 million, respectively.
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, 1998 are as follows (in thousands):
<TABLE>
<S> <C>
1999........................................................ $1,112
2000........................................................ 1,046
2001........................................................ 1,073
2002........................................................ 1,082
2003........................................................ 464
------
Total............................................. $4,767
======
</TABLE>
Rental expense, before capitalization, was approximately $427,000,
$544,000, and $1,000,000 for the years ended December 31, 1996, 1997 and 1998,
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>
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31,
--------------------------------------
1996 1997 1998
----------- ----------- ----------
<S> <C> <C> <C>
Natural gas quantity hedged (MMBtu)............ 13,482,900 13,573,500 9,800,000
Increase (decrease) in natural gas sales....... $(3,701,000) $(3,931,000) $2,337,000
Crude oil quantity hedged (Bbls)............... 428,000 118,000 0
Increase (decrease) in crude oil sales......... $(1,912,000) $ (614,000) $ 0
</TABLE>
F-15
<PAGE> 98
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Subsequent to year-end, the Company entered into a natural gas collar with
Enron from April to October 1999 with an extension at the collar parties' option
to extend the collar at a higher price through March 2000. In addition, in
March, the Company entered into a three-year gas swap with Enron. The following
tables set forth the Company's position as of March 15, 1999.
<TABLE>
<CAPTION>
NOTIONAL PRICE
QUANTITY -----------------------
TYPE LOCATION TIME PERIOD (MMBTU) FLOOR CEILING FIXED
- ---- -------- ----------- -------- ----- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Collar Henry Hub April 1 -- October 31, 1999 12,840 $1.85 $2.05 --
Swap Henry Hub November 1 -- December 31, 2,684 -- -- $2.18
1999
Swap Henry Hub January 1 -- December 31, 2000 10,980 -- -- $2.18
Swap Henry Hub January 1 -- December 31, 2001 4,380 -- -- $2.18
Swap Henry Hub January 1 -- October 31, 2002 1,824 -- -- $2.18
</TABLE>
DEEPWATER RIG -- The Company executed a letter of intent in February 1998
regarding the provision of a deepwater rig to the Company and another company on
an equally shared basis for five years beginning in late 1999 or early 2000. The
letter of intent also provided for a day rate of $158,500. It is the third
party's position that the Company is committed to the terms of the letter of
intent. The Company is currently in discussions with the owner of the rig to
determine if a mutually acceptable drilling contract can be negotiated.
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>
ACQUIRED
COMPANY
-------------
THREE MONTHS NINE MONTHS
ENDED ENDED YEAR ENDED YEAR ENDED
MARCH 31, DECEMBER 31, DECEMBER 31, DECEMBER 31,
1996 1996 1997 1998
------------- ------------- ------------- -------------
$ % $ % $ % $ %
------ ---- ------- --- ------- --- ------- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Income (loss) before income taxes... 2,661 -- (18,692) -- (20,210) -- (58,421) --
Income tax expense (benefit)
computed at statutory rates....... 931 35 (6,542) (35) (7,074) (35) (20,447) (35)
Change in valuation allowances...... (3,597) (135) 8,125 43 6,871 34 18,804 32
Other............................... 2,666 100 (1,583) (8) 203 1 1,643 3
------ ---- ------- --- ------- --- ------- ---
Tax expense......................... -- -- -- -- -- -- -- --
====== ==== ======= === ======= === ======= ===
</TABLE>
No federal income taxes were paid by the Company during the three months
ending March 31, 1996, the nine months ending December 31, 1996 or the years
ended December 31, 1997 or 1998.
F-16
<PAGE> 99
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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):
<TABLE>
<CAPTION>
1996 1997 1998
------- -------- --------
<S> <C> <C> <C>
Deferred tax assets:
Net operating loss carry forwards................... $ 6,323 $ 10,410 $ 34,771
Differences between book and tax bases of
properties....................................... 1,802 4,586 --
------- -------- --------
8,125 14,996 34,771
Valuation allowance................................... (8,125) (14,996) (33,800)
------- -------- --------
Total net deferred tax assets......................... -- -- 971
------- -------- --------
Deferred tax liabilities --
Differences between book and tax bases of
properties....................................... -- -- (971)
------- -------- --------
Total net deferred taxes.................... $ -- $ -- $ --
======= ======== ========
</TABLE>
As of December 31, 1998, the Company has a cumulative net operating loss
carryforward ("NOL") for federal income tax purposes of approximately $98
million, which begins to expire in the year 2012. 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):
<TABLE>
<CAPTION>
ACQUIRED
COMPANY
--------------
THREE MONTHS NINE MONTHS
ENDED ENDED YEAR ENDED YEAR ENDED
MARCH 31, DECEMBER 31, DECEMBER 31, DECEMBER 31,
1996 1996 1997 1998
-------------- ------------ ------------ ------------
<S> <C> <C> <C> <C>
Oil and gas sales................... $13,309 $ 47,079 $ 62,771 $ 56,690
Production costs.................... (2,403) (6,495) (9,376) (9,858)
Depreciation, depletion and
amortization...................... (6,309) (24,747) (31,719) (33,833)
Impairment of oil and gas
properties........................ -- (22,500) (28,514) (50,800
Income tax expense.................. -- -- -- --
------- -------- -------- --------
Results of operations..... $ 4,597 $ (6,663) $ (6,838) $(37,801)
======= ======== ======== ========
</TABLE>
F-17
<PAGE> 100
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Costs incurred in property acquisition, exploration and development
activities were as follows (in thousands, except per equivalent mcf amounts):
<TABLE>
<CAPTION>
ACQUIRED YEAR ENDED
COMPANY DECEMBER 31,
------------ 1998
THREE MONTHS NINE MONTHS ------------
ENDED ENDED YEAR ENDED
MARCH 31, DECEMBER 31, DECEMBER 31,
1996 1996 1997
------------ -------------- ------------
<S> <C> <C> <C> <C>
Property acquisition costs
Unproved properties............. $ 949 $13,477 $21,569 $ 43,143
Proved properties............... -- -- 3,250 --
Exploration costs................. 3,903 18,627 27,364 35,674
Development costs................. 2,643 6,132 16,134 61,960
------ ------- ------- --------
Total costs............. $7,495 $38,236 $68,317 $140,777
====== ======= ======= ========
Depreciation, depletion and
amortization rate per equivalent
Mcf before impairment
provisions...................... $1.00 $1.33 $1.33 $1.40
</TABLE>
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 $4,362,000, $4,418,000 and $6,386,000,
for the years ended December 31, 1996, 1997 and 1998, respectively.
The following table summarizes costs related to unevaluated properties
which have been excluded from amounts subject to amortization at December 31,
1998. 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.
<TABLE>
<CAPTION>
ACQUIRED COMPANY
------------------
THREE NINE
MONTHS MONTHS
ENDED ENDED YEAR ENDED YEAR ENDED TOTAL AT
PRIOR MARCH 31, DECEMBER 31, DECEMBER 31, DECEMBER 31, DECEMBER 31,
YEARS 1996 1996 1997 1998 1998
------ --------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Property acquisition
costs.................... $1,628 $24 $7,949 $19,509 $53,936 $83,046
Exploration costs........ -- -- -- -- 1,030 1,030
------ --- ------ ------- ------- -------
Total.......... $1,628 $24 $7,949 $19,509 $54,966 $84,076
====== === ====== ======= ======= =======
</TABLE>
Approximately 95% of excluded costs at December 31, 1998 relate to
activities in the Deepwater Gulf of Mexico and the remaining 5% 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, 1998 were reserves expected to be
recovered
F-18
<PAGE> 101
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
ESTIMATED QUANTITIES OF PROVED RESERVES
<TABLE>
<CAPTION>
OIL (BBL) GAS (MCF)
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
December 31, 1995........................................... 6,669 98,330
Revisions of previous estimates........................... 3 (518)
Extensions, discoveries and other additions............... 1,168 24,326
Sales of reserves in place................................ (1,810) (9,425)
Production................................................ (750) (20,429)
------ -------
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
====== =======
</TABLE>
F-19
<PAGE> 102
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ESTIMATED QUANTITIES OF PROVED DEVELOPED RESERVES
<TABLE>
<CAPTION>
OIL (BBL) GAS (MCF)
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
December 31, 1996........................................... 3,456 83,529
December 31, 1997........................................... 3,486 76,343
December 31, 1998........................................... 2,886 86,024
</TABLE>
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,
---------------------------------
1996 1997 1998
--------- --------- ---------
<S> <C> <C> <C>
Future cash inflows....................................... $ 548,451 $ 447,681 $ 383,490
Future production costs................................... (103,777) (109,405) (103,400)
Future development costs.................................. (20,413) (73,568) (81,090)
Future income taxes....................................... (90,971) (35,346) --
--------- --------- ---------
Future net cash flows..................................... 333,290 229,362 199,000
Discount of future net cash flows at 10% per annum........ (78,914) (52,903) (51,371)
--------- --------- ---------
Standardized measure of discounted future net cash
flows................................................... $ 254,376 $ 176,459 $ 147,629
========= ========= =========
</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, 1996, 1997 and 1998, used in the
above table, were $25.16, $16.43 and $10.36 per Bbl, respectively, and $4.50,
$2.79 and $2.22 per Mcf, respectively.
F-20
<PAGE> 103
MARINER ENERGY LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1996 1997 1998
-------- --------- --------
<S> <C> <C> <C>
Sales and transfers of oil and gas produced, net of
production costs.................................... $(51,505) $ (53,395) $(46,832)
Net changes in prices and production costs.......... 120,843 (132,658) (67,815)
Extensions and discoveries, net of future
development and production costs.................. 62,551 42,717 23,730
Development costs during period and net change in
development costs................................. -- 4,188 30,799
Revision of previous quantity estimates............. (1,293) (730) (6,846)
Purchases of reserves in place...................... -- 6,071 --
Sales of reserves in place.......................... (10,813) -- --
Net change in income taxes.......................... (36,082) 29,619 27,193
Accretion of discount before income taxes........... 17,342 30,336 20,365
Changes in production rates (timing) and other...... (7,182) (4,065) (9,424)
-------- --------- --------
Net change.......................................... $ 93,861 $ (77,917) $(28,830)
======== ========= ========
</TABLE>
********************************************************************************
F-21
<PAGE> 104
MARINER ENERGY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(IN THOUSANDS, EXCEPT SHARE DATA)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1998 1999
------------ -------------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................................. $ 802 $ 1,326
Receivables............................................... 15,657 15,276
Prepaid expenses and other................................ 7,234 6,231
--------- ---------
Total current assets.............................. 23,693 22,833
PROPERTY AND EQUIPMENT:
Oil and gas properties, at full cost:
Proved................................................. 316,056 352,715
Unproved, not subject to amortization.................. 84,076 90,573
--------- ---------
Total............................................. 400,132 443,288
Other property and equipment.............................. 3,300 3,846
Accumulated depreciation, depletion and amortization...... (167,846) (190,690)
--------- ---------
Total property and equipment, net................. 235,586 256,444
--------- ---------
OTHER ASSETS, NET OF AMORTIZATION........................... 3,513 3,146
--------- ---------
TOTAL ASSETS................................................ $ 262,792 $ 282,423
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable.......................................... $ 20,375 $ 19,628
Accrued liabilities....................................... 29,082 20,733
Accrued interest.......................................... 4,953 4,881
Enron credit facility..................................... -- 50,000
Senior credit facility.................................... -- 25,000
--------- ---------
Total current liabilities......................... 54,410 120,242
--------- ---------
ACCRUAL FOR FUTURE ABANDONMENT COSTS........................ 2,824 3,806
LONG-TERM DEBT:
Senior Subordinated Notes................................. 99,624 99,661
Revolving credit facility................................. 53,400 42,700
Enron credit facility..................................... 25,000 --
--------- ---------
Total long-term debt.............................. 178,024 142,361
--------- ---------
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, 1999 and December 31, 1998......................... 139 139
Additional paid-in-capital................................ 124,718 124,718
Accumulated deficit....................................... (97,323) (108,843)
--------- ---------
Total stockholders' equity........................ 27,534 16,014
--------- ---------
TOTAL LIABILITIES and STOCKHOLDERS' EQUITY.................. $ 262,792 $ 282,423
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-22
<PAGE> 105
MARINER ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------------
1998 1999
----------- -----------
<S> <C> <C>
REVENUES:
Oil sales................................................. $ 8,294 $ 7,086
Gas sales................................................. 35,304 31,994
----------- -----------
Total revenues.................................... 43,598 39,080
----------- -----------
COSTS AND EXPENSES:
Lease operating expenses.................................. 7,554 8,380
Depreciation, depletion and amortization.................. 25,023 23,488
General and administrative expenses....................... 3,417 4,007
Provision for litigation.................................. 2,960 --
----------- -----------
Total costs and expenses.......................... 38,954 35,875
----------- -----------
OPERATING INCOME............................................ 4,644 3,205
INTEREST:
Income.................................................... 299 29
Expense................................................... (9,512) (14,754)
----------- -----------
LOSS BEFORE TAXES........................................... (4,569) (11,520)
PROVISION FOR INCOME TAXES.................................. -- --
----------- -----------
NET LOSS.................................................... $ (4,569) $ (11,520)
=========== ===========
BASIC AND DILUTED LOSS PER SHARE............................ $ (0.36) $ (0.83)
=========== ===========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING.................. 12,743,957 13,928,304
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-23
<PAGE> 106
MARINER ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------
1998 1999
--------- --------
<S> <C> <C>
OPERATING ACTIVITIES:
Net loss.................................................. $ (4,569) $(11,520)
Adjustments to reconcile net loss to net cash provided by
(used for) operating activities:
Depreciation, depletion and amortization............... 25,287 23,861
Provision for litigation.................................. 2,960 --
Changes in operating assets and liabilities:
Receivables............................................ 3,014 731
Other current assets................................... (868) 1,003
Other assets........................................... 90 367
Accounts payable and accrued liabilities............... (6,982) (8,716)
--------- --------
Net cash provided by (used for) operating activities...... 18,932 5,726
--------- --------
INVESTING ACTIVITIES:
Additions to oil and gas properties....................... (102,661) (62,913)
Sale of mineral interest.................................. -- 19,757
Additions to other property and equipment................. (913) (546)
--------- --------
Net cash used in investing activities.................. (103,574) (43,702)
--------- --------
FINANCING ACTIVITIES:
Proceeds from (repayment of) revolving credit facility.... 37,000 (10,700)
Sale of common stock...................................... 28,992 --
Proceeds from the affiliate credit facilities............. 10,000 50,000
--------- --------
Net cash provided by financing activities.............. 75,992 39,300
--------- --------
DECREASE IN CASH AND CASH EQUIVALENTS....................... (8,650) 1,324
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............ 9,131 2
--------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD.................. $ 481 $ 1,326
========= ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-24
<PAGE> 107
MARINER ENERGY LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION
The consolidated financial statements of Mariner Energy LLC, Mariner Energy
Holdings and Mariner Energy Inc. ("Mariner Energy") (collectively, 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. 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 in the Company's annual consolidated financial
statements for the year ended December 31, 1998. The result of operations for
the nine months ending September 30, 1998 and 1999 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.
In the second quarter of 1999, the Company sold a 63% working interest in
its Pluto Deepwater Gulf exploitation project. Net proceeds from this sale were
approximately $19.8 million.
3. REVOLVING CREDIT FACILITY
Following the semi-annual borrowing base redetermination on June 28, 1999
the borrowing base under the Company's revolving credit facility (the "Revolving
Credit Facility"), with Bank of America as agent for a group of lenders, was
reaffirmed at $60 million, and the maturity date of the Revolving Credit
Facility was extended from October 1, 1999 to October 1, 2002. As part of the
redetermination, the Company pledged certain mineral interests to secure the
Revolving Credit Facility. In October 1999, the borrowing base under the
Revolving Credit Facility was again reaffirmed at $60 million as part of the
semi-annual borrowing base redetermination.
4. AFFILIATE CREDIT FACILITIES
During the first quarter of 1999, the Company and Enron Capital & Trade
Resources Corp., as of September 1, 1999, known as Enron North America Corp.
("Enron") amended an existing unsecured, subordinated credit facility provided
by Enron to the Company to increase the amount available thereunder from $25
million to $50 million (the "Enron Credit Facility"). The Enron Credit Facility
requires that any funds received pursuant to a private or public equity or debt
offering by the Company must first be applied to repay the amount outstanding
thereunder. Once funds outstanding under the Enron Credit Facility have been
repaid, those funds may not be reborrowed. The Enron Credit Facility has been
amended to extend its maturity date from April 30, 1999 to April 30, 2000 and to
give Enron the option to convert the Enron Credit Facility to equity in the
Company at any time through maturity. Interest accruing on the outstanding
principal under the Enron Credit Facility from April 15, 1999 through April 30,
2000 will be payable at maturity by the Company. At September 30, 1999, the
Company had fully drawn the Enron Credit Facility.
F-25
<PAGE> 108
MARINER ENERGY LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In April 1999, the Company established a $25 million borrowing-based,
short-term credit facility with Enron (the "Senior Credit Facility"). The Senior
Credit Facility matures on December 31, 1999 and has an annual interest rate of
LIBOR plus 2.5%, with interest payments due quarterly. As of June 30, 1999, the
Company had fully drawn the Senior Credit Facility.
Restrictions for Mariner Energy within the Revolving Credit Facility and
the 10 1/2% Senior Subordinated Notes restricts the use of Mariner Energy's
assets or cash flow to satisfy interest or principal payments for the Enron
Credit Facility and Senior Credit Facility.
5. COMMITMENTS AND CONTINGENCIES
HEDGING -- The Company uses crude oil and natural gas price swaps and other
similar hedging transactions to reduce its exposure to price decreases. In
January 1999, the Company entered into a 36 month long-term natural gas fixed
price swap ("Fixed Price Swap") to establish the price the Company receives for
a portion of its natural gas production to $2.18 per Mmbtu. In May 1999, the
Company entered into a five month market sensitive swap ("Market Sensitive
Swap") where the Company pays to the counterparty $2.60 per MMBtu in return for
a market sensitive price. The effect of the Market Sensitive Swap is to limit
hedging losses on a portion of the Fixed Price Swap described above. In the
nine-month period ended September 30, 1999, the Company recognized approximately
$4.5 million in losses before recovery in the cash market as a result of these
contracts.
The following table sets forth the Company's open hedging positions as of
September 30, 1999.
<TABLE>
<CAPTION>
NOTIONAL PRICE
QUANTITIES ------------------------ FAIR VALUE AT
TIME PERIOD (MMBTU/BBL) FLOOR CEILING FIXED SEPTEMBER 30, 1999
- ----------- ----------- ----- ------- ------ ------------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
NATURAL GAS
October 1 -- October 31, 1999.......... 1,860 $1.85 $2.05 -- $(1,042)
November 1 -- December 31, 1999
Fixed Price Swap..................... 2,684 -- -- $ 2.18 $(1,759)
Market Sensitive Swap................ 1,220 -- -- $ 2.60 $ 303
January 1 -- December 31, 2000
Fixed Price Swap..................... 10,980 -- -- $ 2.18 $(5,215)
Market Sensitive Swap................ 1,820 -- -- $ 2.60 $ 404
January 1 -- December 31, 2001
Fixed Price Swap..................... 4,380 -- -- $ 2.18 $(1,920)
January 1 -- October 31, 2002
Fixed Price Swap..................... 1,824 -- -- $ 2.18 $ (774)
CRUDE OIL
October 1 -- December 31, 1999......... 110,400 -- -- $16.54 $ (868)
November 1 -- December 31, 1999........ 94,583 -- -- $19.89 $ (418)
January 1 -- December 31, 2000......... 1,481,991 -- -- $18.72 (3,364)
</TABLE>
Subsequent to September 30, 1999 the counterparty exercised its option to
extend the Company's collar on natural gas covering the period July 1, 1999
through October 31, 1999 at a floor price of $2.00 per Mmbtu and a ceiling of
$2.70 per Mmbtu for the period November 1999 through March 2000. All hedging
contracts mentioned above were entered into with Enron. Including these
contracts, hedging arrangements for 1999 cover approximately 70% of the
Company's expected 1999 equivalent production. We purchased two gas call options
for November 1999 and December 1999 for a cumulative notional quantity of 1,098
MMBtu at an exclusive price of $4.25 per MMBtu and $4.50 per MMBtu,
respectively.
F-26
<PAGE> 109
MARINER ENERGY LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The fair value of our hedging instruments were determined based on a
brokers' forward price quote and a NYMEX forward price quote. As of September
30, 1999 a commodity price increase of 10% would have resulted in an unfavorable
change in fair value of $8.5 million and a commodity price decrease of 10% would
have resulted in a favorable change in fair value of $8.5 million.
DEEPWATER RIG -- The Company executed a letter of intent in February 1998
regarding the provision of a deepwater rig to the Company and another company on
an equally shared basis for five years beginning in late 1999 or early 2000. The
letter of intent also provided for a day rate of $158,500. It is the third
party's position that the Company is committed to the terms of the letter of
intent. The Company is currently in discussions with the owner of the rig to
determine if a mutually acceptable drilling contract can be negotiated.
FLOW LINE SALE -- The Company has entered into negotiations with an
affiliate to sell the Pluto flow line and related facilities and enter into a
firm transportation agreement for the same flow line.
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" which was amended in June 1999 by
SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities -- Deferral of the Effective Date of FASB Statement No. 133 -- an
amendment of FASB Statement No. 133." 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 is currently evaluating what effect, if any, SFAS No. 133 will have on
the Company's financial statements. The Company will adopt this statement no
later than January 1, 2001.
F-27
<PAGE> 110
ANNEX A
[Ryder Scott Company, L.P. Letterhead]
November 1, 1999
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 September 30, 1999. 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. September 1999 hydrocarbon prices were used
in the preparation of this report as required by SEC guidelines; however, actual
future prices may vary significantly from September 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 September 30, 1999
<TABLE>
<CAPTION>
DEVELOPED PROVED
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL PROVED
------------ ------------- ------------ ------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate -- Barrels.......... 2,466,466 1,399,052 5,163,528 9,029,046
Plant Products -- Barrels.......... 2,874 772 3,435 7,081
Gas -- MMCF........................ 53,159 32,541 35,839 121,539
INCOME DATA
Future Gross Revenue............... $222,580,612 $138,128,362 $231,138,826 $591,847,800
Deductions......................... 60,111,356 36,265,731 112,660,251 209,037,338
------------ ------------ ------------ ------------
Future Net Revenue (FNR)........... $162,469,256 $101,862,631 $118,478,575 $382,810,462
Discounted FNR @ 10%................. $120,244,324 $ 85,588,505 $ 64,731,376 $270,564,205
</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.
A-1
<PAGE> 111
Mariner Energy, Inc.
November 1, 1999
Page 2
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 64.1 percent of the total future gross
revenue from proved reserves. Liquid hydrocarbon reserves account for
approximately 35.8 percent and plant product reserves account for the remaining
0.1 percent of total future gross revenue from proved reserves.
The discounted future net revenues shown above was calculated using a
discount rate of 10 percent per annum compounded monthly. The discounted future
net revenue 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
Reserves included in this report are proved reserves which 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 reserves are included in the section
"Reserve Definitions and Pricing Assumptions" attached as Appendix A.
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.
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Mariner Energy, Inc.
November 1, 1999
Page 3
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.
HYDROCARBON PRICES
Mariner furnished us with prices in effect at September 30, 1999 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 September 30, 1999 were not taken into account in
this report. Future prices used in this report are discussed in more detail
under the Section "Reserve Definitions and Pricing Assumptions" attached as
Appendix A.
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
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
A-3
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Mariner Energy, Inc.
November 1, 1999
Page 4
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 August 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.
/s/ TIMOTHY J. TORRES P.E.
------------------------------------
Timothy J. Torres, P.E.
Petroleum Engineer
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APPENDIX A
RESERVES DEFINITIONS AND PRICING ASSUMPTIONS
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.
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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.
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HYDROCARBON PRICING PARAMETERS
SECURITIES AND EXCHANGE COMMISSION PARAMETERS
OIL AND CONDENSATE
Mariner furnished us with oil and condensate prices in effect September 30,
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 September 30, 1999 were not considered in this report.
PLANT PRODUCTS
Mariner furnished us with plant product prices in effect at September 30,
1999 and these prices were held constant to depletion of the properties.
GAS
Mariner furnished us with gas prices in effect at September 30, 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 September 30, 1999 gas prices. For gas sold
under contact, 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.
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MARINERLOGO
<PAGE> 118
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. EXPENSES OF THE OFFERING
The estimated expenses in connection with the Offering are:
<TABLE>
<S> <C>
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
==========
</TABLE>
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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<PAGE> 119
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. ("Enron") dated April 15, 1999, Enron 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.
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.
<TABLE>
<CAPTION>
<C> <S>
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.
</TABLE>
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<PAGE> 120
<TABLE>
<CAPTION>
<C> <S>
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 10 1/2% 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) -- Employment Agreement, dated as of August 1, 1998, between
Mariner Energy, Inc. and Christopher E. Lindsey.
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.
</TABLE>
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<PAGE> 121
<TABLE>
<CAPTION>
<C> <S>
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** -- First Amendment to Employment Agreement, effective as of
October 1, 1999, between Mariner Energy, Inc. and
Christopher E. Lindsey.
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 1999 Share Option Plan.
10.32+ -- Form of Option Agreement (pursuant to the Mariner Energy
LLC 1999 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.
</TABLE>
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<PAGE> 122
<TABLE>
<CAPTION>
<C> <S>
10.39+ -- Second Amendment to Amended and Restated Consulting
Services Agreement, effective as of ,
between Mariner Energy, Inc. and David S. Huber.
10.40+ -- Second Amendment to Employment Agreement, effective as of
, between Mariner Energy, Inc. and
Christopher E. Lindsey.
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.
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.
</TABLE>
- -------------------------
(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.
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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.
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.
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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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ ROBERT E. HENDERSON Chairman of the Board, November 4, 1999
- --------------------------------------------------- President and Chief
Robert E. Henderson Executive Officer (Principal
Executive Officer)
/s/ FRANK A. PICI Vice President of Finance and November 4, 1999
- --------------------------------------------------- Chief Financial Officer
Frank A. Pici (Principal Financial Officer
and Principal Accounting
Officer)
* Senior Vice President of November 4, 1999
- --------------------------------------------------- Operations and Director
L. V. McGuire
* Executive Vice President and November 4, 1999
- --------------------------------------------------- Director
Richard R. Clark
* Senior Vice President of November 4, 1999
- --------------------------------------------------- Exploration and Director
Michael W. Strickler
* Director November 4, 1999
- ---------------------------------------------------
Richard B. Buy
* Director November 4, 1999
- ---------------------------------------------------
D. Brad Dunn
* Director November 4, 1999
- ---------------------------------------------------
Mark E. Haedicke
* Director November 4, 1999
- ---------------------------------------------------
Stephen R. Horn
* Director November 4, 1999
- ---------------------------------------------------
Jeffrey McMahon
* Director November 4, 1999
- ---------------------------------------------------
Jere C. Overdyke, Jr.
* Director November 4, 1999
- ---------------------------------------------------
Frank Stabler
*By: /s/ ROBERT E. HENDERSON
---------------------------------------------
Robert E. Henderson
As Attorney-In-Fact
</TABLE>
II-7
<PAGE> 125
SCHEDULE I
MARINER ENERGY LLC
(PARENT COMPANY ONLY)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1997 1998
------------ ------------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ -- $ 800
Prepaid expenses and other................................ -- 457
-------- ---------
Total Current Assets.............................. -- 1,257
INVESTMENT IN SUBSIDIARIES, AT EQUITY....................... 57,174 51,727
-------- ---------
TOTAL ASSETS...................................... 57,174 52,984
======== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES -- Accrued Interest..................... -- 450
LONG-TERM DEBT -- Enron credit facility..................... -- 25,000
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 1997 -- 11,871,156;
1998 -- 13,928,304 shares)............................. 119 139
Additional paid-in-capital................................ 95,957 124,718
Accumulated deficit....................................... (38,902) (97,323)
-------- ---------
Total stockholders' equity........................ 57,174 27,534
-------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $ 57,174 $ 52,984
======== =========
</TABLE>
FS-1
<PAGE> 126
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>
NINE MONTHS ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1996 1997 1998
----------------- ------------ ------------
<S> <C> <C> <C>
Interest expense.................................... $ -- $ -- $ 993
Loss before income taxes and equity in earnings of
wholly owned subsidiaries......................... -- -- (993)
-------- -------- --------
Provision for income taxes.......................... -- -- --
-------- -------- --------
Loss of wholly owned subsidiaries................... $(18,692) $(20,210) $(57,428)
-------- -------- --------
Net loss............................................ (18,692) (20,210) (58,421)
======== ======== ========
Basic and diluted net loss per share................ $ (1.58) $ (1.71) $ (4.47)
======== ======== ========
</TABLE>
FS-2
<PAGE> 127
SCHEDULE I
(CONTINUED)
MARINER ENERGY LLC
(PARENT COMPANY ONLY)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENT OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1996 1997 1998
----------------- ------------ ------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net loss......................................... $(18,692) $(20,210) $(58,421)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Equity in loss of wholly owned subsidiaries... 18,692 20,210 57,428
Changes in operating assets and liabilities:
Prepaid expenses and other.................... -- -- (457)
Accrued interest.............................. -- -- 450
-------- -------- --------
Net cash used in operating activities............ -- -- (1,000)
INVESTING ACTIVITIES
Investment in wholly owned subsidiaries.......... (92,760) (331) (51,981)
-------- -------- --------
Net cash used in operating activities............ (92,760) (331) (51,981)
FINANCING ACTIVITIES
Proceeds from long-term debt..................... 92,000
Principal payments on long-term debt............. (92,000)
Proceeds from Enron credit facility.............. -- -- 25,000
Proceeds from sale of common stock............... 92,760 331 28,781
-------- -------- --------
Net cash provided by financing activities........ 92,760 331 53,781
-------- -------- --------
INCREASE IN CASH AND CASH EQUIVALENTS.............. -- -- 800
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD... -- -- --
-------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD......... $ -- $ -- $ 800
======== ======== ========
Noncash items -- contribution of mineral
interests..................................... $ 2,985 $ -- $ --
======== ======== ========
</TABLE>
FS-3
<PAGE> 128
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION
------- -----------
<C> <S>
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 10 1/2% 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.
</TABLE>
<PAGE> 129
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION
------- -----------
<C> <S>
10.11(h) -- Amended and Restated Employment Agreement, dated June 27,
1996, between Mariner Energy, Inc. and Tom E. Young.
10.12(h) -- Employment Agreement, dated as of August 1, 1998, between
Mariner Energy, Inc. and Christopher E. Lindsey.
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** -- First Amendment to Employment Agreement, effective as of
October 1, 1999, between Mariner Energy, Inc. and
Christopher E. Lindsey.
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 1999 Share Option Plan.
10.32+ -- Form of Option Agreement (pursuant to the Mariner Energy
LLC 1999 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.
</TABLE>
<PAGE> 130
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION
------- -----------
<C> <S>
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+ -- Second Amendment to Employment Agreement, effective as of
, between Mariner Energy, Inc. and
Christopher E. Lindsey.
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.
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.
</TABLE>
- -------------------------
(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.
<PAGE> 1
EXHIBIT 10.21
THIRD AMENDMENT
TO
AMENDED AND RESTATED EMPLOYMENT AGREEMENT
BETWEEN
MARINER ENERGY, INC.
AND
RICHARD R. CLARK
THIS THIRD AMENDMENT TO AMENDED AND RESTATED EMPLOYMENT AGREEMENT (this
"Third Amendment") is made and entered into by and between MARINER ENERGY, INC.
(the "Company") and RICHARD R. CLARK ("Employee").
W I T N E S S E T H :
WHEREAS, (i) the Company and Employee entered into that certain Amended
and Restated Employment Agreement dated effective as of June 27, 1996 (the
"Original Employment Agreement"), and (ii) the Original Employment Agreement was
amended pursuant to (A) that certain First Amendment to Amended and Restated
Employment Agreement executed as of March 18, 1997 (the "First Amendment"), by
and between the Company and Employee, and (B) that certain Second Amendment to
Amended and Restated Employment Agreement effective as of January 1, 1998 (the
"Second Amendment"), by and between the Company and Employee (the Original
Employment Agreement as amended by the First Amendment and Second Amendment is
referred to herein as the "Employment Agreement"); and
WHEREAS, the Company and Employee desire to further amend the
Employment Agreement as hereinafter provided;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants and agreements herein contained, the parties hereto agree as follows:
1. Paragraph 2 of the Employment Agreement is hereby amended to read in
its entirety as follows:
"2. Term.
The term of employment shall be for a term beginning
on and including the Effective Date through and
including September 30, 2002, subject, however, to the
provisions of paragraph 3."
2. All references to "this Agreement" contained in the Employment
Agreement shall be deemed to be a reference to the Employment Agreement, as
amended by this Third Amendment.
3. This Third Amendment is made and will be performed under, and shall be
governed by and construed in accordance with, the law of the State of
Texas.
-1-
<PAGE> 2
4. Except as amended by this Third Amendment, the Employment
Agreement shall remain in full force and effect.
5. This Third Amendment may be executed in one or more
counterparts, and by the different parties hereto in separate
counterparts, each of which when executed shall be deemed to be an
original but all of which shall constitute one and the same agreement.
IN WITNESS WHEREOF, the Company and Employee have executed this Third
Amendment to be effective as of October 1, 1999.
Acknowledged by: MARINER ENERGY, INC.
/s/ Hunt Hodge By: /s/ Robert Henderson
- ------------------------------- ----------------------------------
W. Hunt Hodge Robert E. Henderson
Vice President - Administration President and
Chief Executive Officer
"COMPANY"
/s/ Richard Clark
-------------------------------------
Richard R. Clark
"EMPLOYEE"
-2-
<PAGE> 1
EXHIBIT 10.22
FOURTH AMENDMENT
TO
AMENDED AND RESTATED EMPLOYMENT AGREEMENT
BETWEEN
MARINER ENERGY, INC.
AND
GREGORY K. HARLESS
THIS FOURTH AMENDMENT TO AMENDED AND RESTATED EMPLOYMENT AGREEMENT
(this "Fourth Amendment") is made and entered into by and between MARINER
ENERGY, INC. (the "Company") and GREGORY K. HARLESS ("Employee").
W I T N E S S E T H :
WHEREAS, (i) the Company and Employee entered into that certain Amended
and Restated Employment Agreement dated effective as of June 27, 1996 (the
"Original Employment Agreement"), and (ii) the Original Employment Agreement was
amended pursuant to (A) that certain First Amendment to Amended and Restated
Employment Agreement executed as of March 18, 1997 (the "First Amendment"), by
and between the Company and Employee, (B) that certain Second Amendment to
Amended and Restated Employment Agreement effective as of January 1, 1998 (the
"Second Amendment"), by and between the Company and Employee, and (C) that
certain Third Amendment to Amended and Restated Employment Agreement effective
as of December 27, 1998 (the "Third Amendment"), by and between the Company and
Employee (the Original Employment Agreement as amended by the First Amendment,
the Second Amendment and the Third Amendment is referred to herein as the
"Employment Agreement"); and
WHEREAS, the Company and Employee desire to further amend the
Employment Agreement as hereinafter provided;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants and agreements herein contained, the parties hereto agree as follows:
1. Paragraph 2 of the Employment Agreement is hereby amended to read
in its entirety as follows:
"2. Term.
The term of employment shall be for a term beginning
on and including the Effective Date through and
including September 30, 2002, subject, however, to
the provisions of paragraph 3."
2. All references to "this Agreement" contained in the Employment
Agreement shall be deemed to be a reference to the Employment
Agreement, as amended by this Fourth Amendment.
-1-
<PAGE> 2
3. This Fourth Amendment is made and will be performed under, and
shall be governed by and construed in accordance with, the law of the
State of Texas.
4. Except as amended by this Fourth Amendment, the Employment
Agreement shall remain in full force and effect.
5. This Fourth Amendment may be executed in one or more counterparts,
and by the different parties hereto in separate counterparts, each of
which when executed shall be deemed to be an original but all of which
shall constitute one and the same agreement.
IN WITNESS WHEREOF, the Company and Employee have executed this Fourth
Amendment to be effective as of October 1, 1999.
Acknowledged by: MARINER ENERGY, INC.
/s/ Hunt Hodge By: /s/ Robert Henderson
- ------------------------------------- -------------------------------
W. Hunt Hodge Robert E. Henderson
Vice President - Administration President and
Chief Executive Officer
"COMPANY"
/s/ Greg Harless
-----------------------------------
Gregory K. Harless
"EMPLOYEE"
-2-
<PAGE> 1
EXHIBIT 10.23
THIRD AMENDMENT
TO
AMENDED AND RESTATED EMPLOYMENT AGREEMENT
BETWEEN
MARINER ENERGY, INC.
AND
ROBERT E. HENDERSON
THIS THIRD AMENDMENT TO AMENDED AND RESTATED EMPLOYMENT AGREEMENT (this
"Third Amendment") is made and entered into by and between MARINER ENERGY, INC.
(the "Company") and ROBERT E. HENDERSON ("Employee").
W I T N E S S E T H :
WHEREAS, (i) the Company and Employee entered into that certain Amended
and Restated Employment Agreement dated effective as of June 27, 1996 (the
"Original Employment Agreement"), and (ii) the Original Employment Agreement was
amended pursuant to (A) that certain First Amendment to Amended and Restated
Employment Agreement executed as of March 18, 1997 (the "First Amendment"), by
and between the Company and Employee, and (B) that certain Second Amendment to
Amended and Restated Employment Agreement effective as of January 1, 1998 (the
"Second Amendment"), by and between the Company and Employee (the Original
Employment Agreement as amended by the First Amendment and Second Amendment is
referred to herein as the "Employment Agreement"); and
WHEREAS, the Company and Employee desire to further amend the
Employment Agreement as hereinafter provided;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants and agreements herein contained, the parties hereto agree as follows:
1. Paragraph 2 of the Employment Agreement is hereby amended to read in
its entirety as follows:
"2. Term.
The term of employment shall be for a term beginning
on and including the Effective Date through and
including September 30, 2002, subject, however, to
the provisions of paragraph 3."
2. All references to "this Agreement" contained in the Employment
Agreement shall be deemed to be a reference to the Employment Agreement, as
amended by this Third Amendment.
<PAGE> 2
3. This Third Amendment is made and will be performed under, and shall be
governed by and construed in accordance with, the law of the State of
Texas.
4. Except as amended by this Third Amendment, the Employment Agreement shall
remain in full force and effect.
5. This Third Amendment may be executed in one or more counterparts, and by
the different parties hereto in separate counterparts, each of which when
executed shall be deemed to be an original but all of which shall
constitute one and the same agreement.
IN WITNESS WHEREOF, the Company and Employee have executed this Third
Amendment to be effective as of October 1, 1999.
Acknowledged by: MARINER ENERGY, INC.
/s/ Hunt Hodge By: /s/ Brad Dunn
- ------------------------------- --------------------------------
W. Hunt Hodge Brad Dunn
Vice President - Administration Director and Member of the
Compensation Committee of
the Board of Directors of
Mariner Energy, Inc.
"COMPANY"
/s/ Robert Henderson
------------------------------------
Robert E. Henderson
"EMPLOYEE"
<PAGE> 1
EXHIBIT 10.24
FOURTH AMENDMENT
TO
AMENDED AND RESTATED EMPLOYMENT AGREEMENT
BETWEEN
MARINER ENERGY, INC.
AND
WILLIAM HUNT HODGE
THIS FOURTH AMENDMENT TO AMENDED AND RESTATED EMPLOYMENT AGREEMENT
(this "Fourth Amendment") is made and entered into by and between MARINER
ENERGY, INC. (the "Company") and WILLIAM HUNT HODGE ("Employee").
W I T N E S S E T H :
WHEREAS, (i) the Company and Employee entered into that certain Amended
and Restated Employment Agreement dated effective as of June 27, 1996 (the
"Original Employment Agreement"), and (ii) the Original Employment Agreement was
amended pursuant to (A) that certain First Amendment to Amended and Restated
Employment Agreement executed as of March 18, 1997 (the "First Amendment"), by
and between the Company and Employee, (B) that certain Second Amendment to
Amended and Restated Employment Agreement effective as of January 1, 1998 (the
"Second Amendment"), by and between the Company and Employee, and (C) that
certain Third Amendment to Amended and Restated Employment Agreement effective
as of December 27, 1998 (the "Third Amendment"), by and between the Company and
Employee (the Original Employment Agreement as amended by the First Amendment,
the Second Amendment and the Third Amendment is referred to herein as the
"Employment Agreement"); and
WHEREAS, the Company and Employee desire to further amend the
Employment Agreement as hereinafter provided;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants and agreements herein contained, the parties hereto agree as follows:
1. Paragraph 2 of the Employment Agreement is hereby amended to
read in its entirety as follows:
"2. Term.
The term of employment shall be for a term beginning
on and including the Effective Date through and
including September 30, 2002, subject, however, to
the provisions of paragraph 3."
2. All references to "this Agreement" contained in the Employment
Agreement shall be deemed to be a reference to the Employment
Agreement, as amended by this Fourth Amendment.
-1-
<PAGE> 2
3. This Fourth Amendment is made and will be performed under, and
shall be governed by and construed in accordance with, the law of the
State of Texas.
4. Except as amended by this Fourth Amendment, the Employment
Agreement shall remain in full force and effect.
5. This Fourth Amendment may be executed in one or more
counterparts, and by the different parties hereto in separate
counterparts, each of which when executed shall be deemed to be an
original but all of which shall constitute one and the same agreement.
IN WITNESS WHEREOF, the Company and Employee have executed this Fourth
Amendment to be effective as of October 1, 1999.
Acknowledged by: MARINER ENERGY, INC.
/s/ Christopher Lindsey By: /s/ Robert Henderson
- ---------------------------------- -----------------------------------
Christopher E. Lindsey Robert E. Henderson
General Counsel President and
Chief Executive Officer
"COMPANY"
/s/ William Hunt Hodge
---------------------------------------
William Hunt Hodge
"EMPLOYEE"
-2-
<PAGE> 1
EXHIBIT 10.25
FIRST AMENDMENT
TO
AMENDED AND RESTATED
CONSULTING SERVICES AGREEMENT
BETWEEN
MARINER ENERGY, INC.
AND
DAVID S. HUBER
THIS FIRST AMENDMENT TO AMENDED AND RESTATED CONSULTING SERVICES AGREEMENT
(this "First Amendment") is made and entered into by and between MARINER ENERGY,
INC. (the "Company") and David S. Huber ("Consultant").
W I T N E S S E T H :
WHEREAS, the Company and Consultant entered into that certain Amended and
Restated Consulting Services Agreement dated effective as of June 27, 1996 (the
"Consulting Services Agreement"); and
WHEREAS, the Company and Consultant desire to amend the Consulting Services
Agreement as hereinafter provided;
NOW, THEREFORE, in consideration of the premises and the mutual covenants
and agreements herein contained, the parties hereto agree as follows:
1. Paragraph 2 of the Consulting Services Agreement is amended to read in
its entirety as follows:
"2.
TERM OF AGREEMENT
This Agreement shall continue for a term commencing on and including
the Effective Date and ending on and including September 30, 2002, and
shall automatically be extended for each successive calendar month
thereafter until either COMPANY or HUBER shall give the other party 30
days' advance written notice of intent to terminate, in which event this
Agreement shall terminate upon the expiration of such 30-day period.
Notwithstanding anything contained herein to the contrary, HUBER shall
have the right to terminate this Agreement at any time if COMPANY relocates
its principal office outside of the metropolitan area of Houston, Texas.
During the term of this Agreement, COMPANY shall have the first option
on HUBER's services. At any time during the term of this Agreement that
HUBER and
-1-
<PAGE> 2
COMPANY agree that COMPANY does not have any Deepwater Prospects requiring
HUBER's services, HUBER may provide services to other parties, so long as
HUBER's work for said parties does not violate the provisions of paragraph
10 and otherwise does not conflict with any of the COMPANY'S Deepwater
Prospects."
2. Paragraph 3 of the Consulting Services Agreement is amended to read in
its entirety as follows:
"3.
RETAINER FEE
For the period commencing on the Effective Date and ending on and
including September 30, 2002, COMPANY shall pay HUBER a daily retainer fee
of $850 per day worked, payable semi-monthly on or before the 1st and the
15th days of each month.
COMPANY hereby guarantees HUBER a minimum of 200 days' retainer fee
during each year of this Agreement. Should HUBER and the Company mutually
agree that Huber may provide services directly for other parties during a
year of this Agreement, said services will be credited toward COMPANY'S
guaranteed 200 days per year.
If, by the end of the ninth month of each year of this Agreement,
COMPANY has not paid HUBER for at least 100 days of service during such
year, COMPANY shall pay HUBER the difference between actual days paid and
100 days.
If, by the last day of each such year, COMPANY has not paid HUBER for
at least 200 days of service during said year, COMPANY shall pay HUBER the
difference between actual days paid and 200 days."
3. All references to "this Agreement" contained in the Consulting Services
Agreement shall be deemed to be a reference to the Consulting Services
Agreement, as amended by this First Amendment.
4. This First Amendment is made and will be performed under, and shall be
governed by and construed in accordance with, the law of the State of Texas.
5. Except as amended by this First Amendment, the Consulting Services
Agreement shall remain in full force and effect.
6. This First Amendment may be executed in one or more counterparts, and by
the different parties hereto in separate counterparts, each of which when
executed shall be deemed to be an original but all of which shall constitute one
and the same agreement.
-2-
<PAGE> 3
IN WITNESS WHEREOF, the Company and Consultant have executed this First
Amendment to be effective as of October 1, 1999.
Acknowledged by: MARINER ENERGY, INC.
/s/ Hunt Hodge By: /s/ Robert Henderson
- ----------------------------------- -------------------------------------
W. Hunt Hodge Robert E. Henderson
Vice President - Administration President and
Chief Executive Officer
"COMPANY"
/s/ David Huber
-----------------------------------------
David S. Huber
"CONSULTANT"
<PAGE> 1
EXHIBIT 10.26
FIRST AMENDMENT
TO
EMPLOYMENT AGREEMENT
BETWEEN
MARINER ENERGY, INC.
AND
CHRISTOPHER E. LINDSEY
THIS FIRST AMENDMENT TO EMPLOYMENT AGREEMENT (this "First Amendment")
is made and entered into by and between MARINER ENERGY, INC. (the "Company") and
CHRISTOPHER E. LINDSEY ("Employee").
W I T N E S S E T H :
WHEREAS, the Company and Employee entered into that certain Employment
Agreement dated effective as of August 1, 1998 (the "Employment Agreement"); and
WHEREAS, the Company and Employee desire to amend the Employment
Agreement as hereinafter provided;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants and agreements herein contained, the parties hereto agree as follows:
1. Paragraph 2 of the Employment Agreement is hereby amended to
read in its entirety as follows:
"2. Term.
The term of employment shall be for a term beginning
on and including the Effective Date through and
including September 30, 2002, subject, however, to
the provisions of paragraph 3."
2. All references to "this Agreement" contained in the Employment
Agreement shall be deemed to be a reference to the Employment
Agreement, as amended by this First Amendment.
3. This First Amendment is made and will be performed under, and
shall be governed by and construed in accordance with, the law of the
State of Texas.
4. Except as amended by this First Amendment, the Employment
Agreement shall remain in full force and effect.
-1-
<PAGE> 2
5. This First Amendment may be executed in one or more
counterparts, and by the different parties hereto in separate
counterparts, each of which when executed shall be deemed to be an
original but all of which shall constitute one and the same agreement.
IN WITNESS WHEREOF, the Company and Employee have executed this First
Amendment to be effective as of October 1, 1999.
Acknowledged by: MARINER ENERGY, INC.
/s/ Hunt Hodge By: /s/ Robert Henderson
- ------------------------------------- -------------------------------
W. Hunt Hodge Robert E. Henderson
Vice President - Administration President and
Chief Executive Officer
"COMPANY"
/s/ Christopher Lindsey
----------------------------------
Christopher E. Lindsey
"EMPLOYEE"
-2-
<PAGE> 1
EXHIBIT 10.27
FIRST AMENDMENT
TO
EMPLOYMENT AGREEMENT
BETWEEN
MARINER ENERGY, INC.
AND
L. V. MCGUIRE
THIS FIRST AMENDMENT TO EMPLOYMENT AGREEMENT (this "First Amendment")
is made and entered into by and between MARINER ENERGY, INC. (the "Company") and
L. V. McGuire ("Employee").
W I T N E S S E T H :
WHEREAS, the Company and Employee entered into that certain Employment
Agreement dated effective as of June 1, 1998 (the "Employment Agreement"); and
WHEREAS, the Company and Employee desire to amend the Employment
Agreement as hereinafter provided;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants and agreements herein contained, the parties hereto agree as follows:
1. Paragraph 2 of the Employment Agreement is hereby amended to read in
its entirety as follows:
"2. Term.
The term of employment shall be for a term beginning
on and including the Effective Date through and
including September 30, 2002, subject, however, to
the provisions of paragraph 3."
2. Paragraphs 3.2.1 and 3.2.2 of the Employment Agreement are hereby
amended to read in their entirety as follows:
"3.2.1 Company shall pay to Employee (a) his salary through
the end of such term or extended term, (b) any Annual
Bonus (as defined in Section 9.1) that is payable to
Employee with respect to any year prior to the year
in which notice of such termination is given (it
being understood that in determining whether any such
Annual Bonus is payable, Employee shall be deemed to
have satisfied any requirement relating
-1-
<PAGE> 2
to Employee being employed by Company on any date
after such prior year), (c) on or before the last day
of his employment hereunder, and in lieu of any
Annual Bonus with respect to any period or portion
thereof after the year that is prior to the year in
which notice of such termination is given, an amount
equal to the product of (i) forty percent (40%),
multiplied by (ii) Employee's monthly salary rate for
the month immediately preceding the month in which
notice of such termination is given, multiplied by
(iii) twelve (12), multiplied by (iv) a fraction, the
numerator of which is the number of days elapsed in
the period from and including January 1 of the year
in which the notice of such termination is given
through and including the end of such term or
extended term, and the denominator of which is 365,
and (d) any other benefits provided elsewhere in this
Agreement for Employee's services rendered to Company
hereunder through the end of such term or extended
term.
3.2.2 Company shall pay to Employee, on or before the last
day of his employment hereunder, a lump sum cash
payment equal to the sum of (a) nine (9) months'
salary at Employee's monthly rate for the month
immediately preceding the month in which Company
elects to terminate this Agreement, plus (b) forty
percent (40%) of the amount described in clause (a)
of this sentence."
3. Paragraph 3.4 of the Employment Agreement is hereby amended to read
in its entirety as follows:
"3.4 Company may at its option consent to a request by
Employee to terminate this Agreement at a time other
than that stated in paragraph 2, as extended, in
which case the date requested by Employee and agreed
to by Company will be the end of the term of this
Agreement and the provisions of paragraph 3.3 shall
be applicable (it being understood that in applying
the provisions of paragraph 3.3, any provision of
paragraph 3.2.1 that refers to "notice of such
termination is given" shall be deemed to refer to the
giving of such consent by Company."
4. Paragraph 3.6.1 of the Employment Agreement is hereby amended to
read in its entirety as follows:
"3.6.1 A lump sum cash payment equal to the sum of (a)
Employee's salary, at Employee's monthly rate for the
month immediately preceding the month in which such
termination or discharge occurs, for the unexpired
portion of the term or extended term hereof, plus (b)
any
-2-
<PAGE> 3
Annual Bonus that is payable to Employee with respect
to any year prior to the year in which the date of
such termination or discharge occurs (it being
understood that in determining whether any such
Annual Bonus is payable, Employee shall be deemed to
have satisfied any requirement relating to Employee
being employed by Company on any date after such
prior year), plus (c) in lieu of any Annual Bonus
with respect to any period or portion thereof after
the year that is prior to the year in which the date
of such termination or discharge occurs, an amount
equal to the product of (i) forty percent (40%),
multiplied by (ii) Employee's monthly salary rate for
the month immediately preceding the month in which
the date of such termination or discharge occurs,
multiplied by (iii) twelve (12), multiplied by (iv) a
fraction, the numerator of which is the number of
days elapsed in the period from and including January
1 of the year in which the date of such termination
or discharge occurs through and including the end of
the unexpired portion of the term or extended term
hereof, and the denominator of which is 365."
5. Paragraphs 3.7.1 and 3.7.2 of the Employment Agreement are hereby
amended to read in their entirety as follows:
"3.7.1 A lump sum cash payment equal to the sum of (a)
Employee's salary, at Employee's monthly rate in
effect at the effective time of such termination (but
prior to giving effect to any reduction therein which
precipitated such termination), for the unexpired
portion of the term or extended term hereof plus, (b)
any Annual Bonus that is payable to Employee with
respect to any year prior to the year in which the
date of such termination occurs (it being understood
that in determining whether any such Annual Bonus is
payable, Employee shall be deemed to have satisfied
any requirement relating to Employee being employed
by Company on any date after such prior year), plus
(c) in lieu of any Annual Bonus with respect to any
period or portion thereof after the year that is
prior to the year in which the date of such
termination occurs, an amount equal to the product of
(i) forty percent (40%), multiplied by (ii)
Employee's monthly salary rate for the month
immediately preceding the month in which the date of
such termination occurs (but prior to given effect to
any reduction therein which precipitated such
termination), multiplied by (iii) twelve (12),
multiplied by (iv) a fraction, the numerator of which
is the number of days elapsed in the period from and
including January 1 of the year in which the date of
such termination occurs through and
-3-
<PAGE> 4
including the end of the unexpired portion of the
term or extended term hereof, and the denominator of
which is 365.
3.7.2 A lump sum cash payment equal to the sum of (a) nine
(9) months' salary, at Employee's rate in effect at
the time of such termination (but prior to giving
effect to any reduction therein which precipitated
such termination), plus (b) forty percent (40%) of
the amount described in clause (a) of this sentence."
6. Paragraph 9.1 of the Employment Agreement is hereby amended to read
in its entirety as follows:
"9.1 In addition to the salary provided for in paragraph 5
hereof (the "Base Salary"), and subject to the
provisions of paragraph 3 of this Agreement, Employee
shall be eligible to receive, for each calendar year
or portion thereof occurring during the term of this
Agreement, an annual cash bonus based on performance
(the "Annual Bonus") in an amount up to forty percent
(40%) of the Base Salary for such calendar year or
portion thereof (or such greater percentage of such
Base Salary as the Board of Directors or the
Committee may, in its discretion, determine) upon
approval of such Annual Bonus by the Board of
Directors of Company (the "Board of Directors") or a
committee of the Board of Directors designated by the
Board of Directors (the "Committee"). Subject to the
provisions of paragraph 3 of this Agreement, (i) the
amount of any such Annual Bonus shall be determined
by the Board of Directors or the Committee, as the
case may be, in accordance with the cash incentive
compensation program of Company in effect with
respect to such determination, and (ii) the Annual
Bonus shall be paid to Employee, less such amounts as
shall be required to be deducted or withheld
therefrom by applicable law and regulations, at such
time or times as is in accordance with the then
prevailing policy of Company relating to cash
incentive compensation payments."
7. All references to "this Agreement" contained in the Employment
Agreement shall be deemed to be a reference to the Employment Agreement, as
amended by this First Amendment.
8. This First Amendment is made and will be performed under, and shall
be governed by and construed in accordance with, the law of the State of Texas.
9. Except as amended by this First Amendment, the Employment Agreement
shall remain in full force and effect.
-4-
<PAGE> 5
10. This First Amendment may be executed in one or more counterparts,
and by the different parties hereto in separate counterparts, each of which when
executed shall be deemed to be an original but all of which shall constitute one
and the same agreement.
IN WITNESS WHEREOF, the Company and Employee have executed this First
Amendment to be effective as of October 1, 1999.
Acknowledged by: MARINER ENERGY, INC.
/s/ Hunt Hodge By: /s/ Robert Henderson
- --------------------------------- ------------------------------
W. Hunt Hodge Robert E. Henderson
Vice President - Administration President and
Chief Executive Officer
"COMPANY"
/s/ L.V. McGuire
---------------------------------
L. V. McGuire
"EMPLOYEE"
<PAGE> 1
EXHIBIT 10.28
THIRD AMENDMENT
TO
EMPLOYMENT AGREEMENT
BETWEEN
MARINER ENERGY, INC.
AND
FRANK A. PICI
THIS THIRD AMENDMENT TO EMPLOYMENT AGREEMENT (this "Third Amendment")
is made and entered into by and between MARINER ENERGY, INC. (the "Company") and
FRANK A. PICI ("Employee").
W I T N E S S E T H :
WHEREAS, (i) the Company and Employee entered into that certain
Employment Agreement dated effective as of December 2, 1996 (the "Original
Employment Agreement"), and (ii) the Original Employment Agreement was amended
pursuant to (A) that certain First Amendment to Employment Agreement effective
as of January 1, 1998 (the "First Amendment"), by and between the Company and
Employee, and (B) that certain Second Amendment to Employment Agreement
effective as of December 1, 1998 (the "Second Amendment"), by and between the
Company and Employee (the Original Employment Agreement as amended by the First
Amendment and Second Amendment is referred to herein as the "Employment
Agreement"); and
WHEREAS, the Company and Employee desire to further amend the
Employment Agreement as hereinafter provided;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants and agreements herein contained, the parties hereto agree as follows:
1. Paragraph 3.1 of the Employment Agreement is hereby amended to read in
its entirety as follows:
"3.1 If either Employee or Company elects to terminate this
Agreement at the end of the initial term, or at the end
of any extended term hereof as hereinafter provided,
notice of the election to terminate shall be given to
the other party no later than six (6) months before the
end of this Agreement. Except as otherwise provided in
paragraph 21.1, if no such six-month notice is given by
either party on or before June 2, 1997, the initial
term shall be deemed to have been extended through and
including September 30, 2002 (the "first extended
term"), and thereafter if no such six-month notice is
given by either party before the end of the first
extended term, or at the end of any subsequent extended
term, the first extended term and any such subsequent
extended term of this Agreement, as the case may be,
shall deemed to have been extended for an additional
six (6) months."
-1-
<PAGE> 2
2. All references to "this Agreement" contained in the Employment
Agreement shall be deemed to be a reference to the Employment Agreement, as
amended by this Third Amendment.
3. This Third Amendment is made and will be performed under, and shall be
governed by and construed in accordance with, the law of the State of Texas.
4. Except as amended by this Third Amendment, the Employment Agreement
shall remain in full force and effect.
5. This Third Amendment may be executed in one or more counterparts, and
by the different parties hereto in separate counterparts, each of which when
executed shall be deemed to be an original but all of which shall constitute one
and the same agreement.
IN WITNESS WHEREOF, the Company and Employee have executed this Third
Amendment to be effective as of October 1, 1999.
Acknowledged by: MARINER ENERGY, INC.
/s/ Hunt Hodge By: /s/ Robert Henderson
- ------------------------------- ---------------------------
W. Hunt Hodge Robert E. Henderson
Vice President - Administration President and
Chief Executive Officer
"COMPANY"
/s/ Frank Pici
---------------------------
Frank A. Pici
"EMPLOYEE"
-2-
<PAGE> 1
Exhibit 10.29
FOURTH AMENDMENT
TO
AMENDED AND RESTATED EMPLOYMENT AGREEMENT
BETWEEN
MARINER ENERGY, INC.
AND
MICHAEL W. STRICKLER
THIS FOURTH AMENDMENT TO AMENDED AND RESTATED EMPLOYMENT AGREEMENT
(this "Fourth Amendment") is made and entered into by and between MARINER
ENERGY, INC. (the "Company") and MICHAEL W. STRICKLER ("Employee").
W I T N E S S E T H :
WHEREAS, (i) the Company and Employee entered into that certain Amended
and Restated Employment Agreement dated effective as of June 27, 1996 (the
"Original Employment Agreement"), and (ii) the Original Employment Agreement was
amended pursuant to (A) that certain First Amendment to Amended and Restated
Employment Agreement executed as of March 18, 1997 (the "First Amendment"), by
and between the Company and Employee, (B) that certain Second Amendment to
Amended and Restated Employment Agreement effective as of January 1, 1998 (the
"Second Amendment"), by and between the Company and Employee, and (C) that
certain Third Amendment to Amended and Restated Employment Agreement effective
as of November 1, 1998 (the "Third Amendment"), by and between the Company and
Employee (the Original Employment Agreement as amended by the First Amendment,
the Second Amendment and the Third Amendment is referred to herein as the
"Employment Agreement"); and
WHEREAS, the Company and Employee desire to further amend the
Employment Agreement as hereinafter provided;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants and agreements herein contained, the parties hereto agree as follows:
1. Paragraph 2 of the Employment Agreement is hereby amended to read in
its entirety as follows:
"2. Term.
The term of employment shall be for a term beginning on and
including the Effective Date through and including September
30, 2002, subject, however, to the provisions of paragraph 3."
2. All references to "this Agreement" contained in the Employment
Agreement shall be deemed to be a reference to the Employment Agreement,
as amended by this Fourth Amendment.
<PAGE> 2
3. This Fourth Amendment is made and will be performed under, and shall be
governed by and construed in accordance with, the law of the State of
Texas.
4. Except as amended by this Fourth Amendment, the Employment Agreement
shall remain in full force and effect.
5. This Fourth Amendment may be executed in one or more counterparts, and
by the different parties hereto in separate counterparts, each of which
when executed shall be deemed to be an original but all of which shall
constitute one and the same agreement.
IN WITNESS WHEREOF, the Company and Employee have executed this Fourth
Amendment to be effective as of October 1, 1999.
Acknowledged by: MARINER ENERGY, INC.
/s/ HUNT HODGE By: /s/ ROBERT HENDERSON
- ------------------------------- -------------------------
W. Hunt Hodge Robert E. Henderson
Vice President - Administration President and
Chief Executive Officer
"COMPANY"
/s/ MICHAEL STRICKLER
---------------------------
Michael W. Strickler
"EMPLOYEE"
-2-
<PAGE> 1
EXHIBIT 10.30
FIRST AMENDMENT
TO
AMENDED AND RESTATED
EMPLOYMENT AGREEMENT
BETWEEN
MARINER ENERGY, INC.
AND
THOMAS E. YOUNG
THIS FIRST AMENDMENT TO AMENDED AND RESTATED EMPLOYMENT AGREEMENT (this
"First Amendment") is made and entered into by and between MARINER ENERGY, INC.
(the "Company") and THOMAS E. YOUNG ("Employee").
W I T N E S S E T H :
WHEREAS, (i) the Company and Employee entered into that certain
Employment Agreement effective as of June 27, 1996 (the "Original Employment
Agreement"), and (ii) the Original Employment Agreement was amended pursuant to
that certain First Amendment to Employment Agreement effective as of January 1,
1997 (the "Original Employment Agreement First Amendment"), by and between the
Company and Employee (the Original Employment Agreement as amended by the
Original Employment Agreement First Amendment is referred to herein as the
"Initial Employment Agreement"); and
WHEREAS, the Company and Employee also entered into that certain letter
agreement (including Exhibit A thereto) dated June 27, 1996 (the "Letter
Agreement"), concerning Employee's participation in the Company's Employee
Overriding Royalty Interest Pool Program; and
WHEREAS, the Company and Employee amended and restated the Initial
Employment Agreement and the Letter Agreement, and in connection therewith,
incorporated the provisions of the Letter Agreement, as amended and restated,
into the Initial Employment Agreement, as amended and restated, in and pursuant
to that certain Amended and Restated Employment Agreement effective as of June
27, 1996 (the "Employment Agreement"), by and between the Company and Employee;
and
WHEREAS, the Company and Employee desire to amend the Employment
Agreement as hereinafter provided;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants and agreements herein contained, the parties hereto agree as follows:
1. Paragraph 2 of the Employment Agreement is hereby amended to read in
its entirety as follows:
-1-
<PAGE> 2
"2. Term.
The term of employment shall be for a term beginning
on and including the Effective Date through and
including September 30, 2002, subject, however, to
the provisions of paragraph 3."
2. All references to "this Agreement" contained in the Employment
Agreement shall be deemed to be a reference to the Employment Agreement, as
amended by this First Amendment.
3. This First Amendment is made and will be performed under, and shall be
governed by and construed in accordance with, the law of the State of Texas.
4. Except as amended by this First Amendment, the Employment Agreement
shall remain in full force and effect.
5. This First Amendment may be executed in one or more counterparts, and
by the different parties hereto in separate counterparts, each of which when
executed shall be deemed to be an original but all of which shall constitute
one and the same agreement.
IN WITNESS WHEREOF, the Company and Employee have executed this First
Amendment to be effective as of October 1, 1999.
Acknowledged by: MARINER ENERGY, INC.
/s/ W. HUNT HODGE By: /s/ ROBERT E. HENDERSON
- ------------------------------------- --------------------------------
W. Hunt Hodge Robert E. Henderson
Vice President - Administration President and
Chief Executive Officer
"COMPANY"
/s/ THOMAS E. YOUNG
-----------------------------------
Thomas E. Young
"EMPLOYEE"
-2-
<PAGE> 1
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT AND REPORT ON SCHEDULE
To the Board of Directors and Stockholders of
Mariner Energy LLC
Houston, Texas
We consent to the use in this Amendment No. 1 to Registration Statement No.
333-87287 of Mariner Energy LLC on Form S-1 of our report dated April 14, 1999
(September 1, 1999, with respect to the first and last paragraph of Note 1 and
the third paragraph of Note 4), appearing in the Prospectus, which is a part of
this Registration Statement, and to the references to us under the heading
"Experts" in such Prospectus.
Our audits of the financial statements referred to in our aforementioned
report also included the financial statement schedule of Mariner Energy LLC,
Schedule I Condensed Financial Information of Registrant (Parent Company only).
This financial statement schedule is the responsibility of the Company's
management. Our responsibility is to express an opinion based on our audits. In
our opinion, such financial statement schedule, when considered in relation to
the basic consolidated financial statements taken as a whole, presents fairly in
all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Houston, Texas
November 4, 1999
<PAGE> 1
EXHIBIT 23.2
[RYDER SCOTT COMPANY, L.P. LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the inclusion of our letter dated November 1, 1999
to Mariner Energy LLC (the "Company") regarding our estimates of proved
reserves, future production and income attributable to certain leasehold
interests of the Company in this Registration Statement on Form S-1 (the
"Registration Statement") of the Company and all references to Ryder Scott
Company and/or the reports prepared by Ryder Scott Company entitled, "Estimated
Future Reserves and Income Attributable to Certain Leasehold Interests (SEC
Parameters) as of September 30, 1999" in this Registration Statement to the
reference to our firm as experts in this Registration Statement.
/s/ RYDER SCOTT COMPANY L.P.
RYDER SCOTT COMPANY, L.P.
November 3, 1999
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<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<CASH> 1,326
<SECURITIES> 0
<RECEIVABLES> 15,276
<ALLOWANCES> 0
<INVENTORY> 4,805
<CURRENT-ASSETS> 22,833
<PP&E> 447,134
<DEPRECIATION> 190,690
<TOTAL-ASSETS> 282,423
<CURRENT-LIABILITIES> 68,002
<BONDS> 0
0
0
<COMMON> 1
<OTHER-SE> 16,014
<TOTAL-LIABILITY-AND-EQUITY> 282,423
<SALES> 0
<TOTAL-REVENUES> 39,080
<CGS> 0
<TOTAL-COSTS> 35,754
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 14,754
<INCOME-PRETAX> (11,520)
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (11,520)
<EPS-BASIC> (0.83)
<EPS-DILUTED> (0.83)
</TABLE>
