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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
COMMISSION FILE NUMBER 333-12707
MARINER ENERGY, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 86-0460233
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
2101 CITYWEST BLVD., SUITE 1900
HOUSTON, TEXAS 77042
(Address of principal executive offices including Zip Code)
(713) 954-5500
(Registrant's telephone number)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes[ ] No[X]
Note: The Company is not subject to the filing requirements of the
Securities Exchange Act of 1934. This annual report is filed pursuant to
contractual obligations imposed on the Company by an Indenture, dated as of
August 1, 1996, under which the Company is the issuer of certain debt.
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Exchange Act Rule 12b-2) Yes[ ] No [X]
The aggregate market value of the 1380 shares of voting stock held by
affiliates of registrant as of June 28, 2002 (the last business day of the most
recently completed second quarter) is indeterminable, as there is no established
public trading market for the registrant's common stock.
As of March 4, 2003, there were 1,380 shares of the registrant's common
stock outstanding. See Part III, Item 13. "Certain Relationships and Related
Party Transactions" related to common stock ownership and other entities related
to registrant.
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TABLE OF CONTENTS
Item Page
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PART I 3
ITEMS 1. AND 2. BUSINESS AND PROPERTIES 4
(a) Overview 46
(b) Recent Events 6
(c) Business Strategy 6
(d) Reserves 7
(e) Oil and Gas Properties 8
(f) Production 11
(g) Productive Wells 11
(h) Acreage 12
(i) Drilling Activity 13
(j) Marketing, Customers and Hedging Activities 13
(k) Competition 14
(l) Royalty Relief 15
(m) Regulation 15
(n) Employees 18
ITEM 3. LEGAL PROCEEDINGS 18
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 18
PART II 19
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 19
ITEM 6. SELECTED FINANCIAL DATA 20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 20
(a) Introduction 20
(b) General 20
(c) Recent Events 21
(d) Enron-Control Relationships and Related Party Transactions 22-28
(e) Risk Factors 28-32
(f) Critical Accounting Policies and Estimates 34-32
(g) Results of Operations 34-36
(h) Liquidity and Capital Resources 36-39
(i) Contractual Commitments 40
(j) Recent Accounting Pronouncements 40
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 41
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 41-42
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTING AND FINANCIAL DISCLOSURE 42-68
44PART III 69
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 69
ITEM 11. EXECUTIVE COMPENSATION 71
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 74
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 75
Item 14. Control & Procedures 82
PART IV 82
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 82
GLOSSARY 86
2
PART I
Mariner Energy, Inc. ("Mariner" or the "Company") has provided
definitions for some of the natural gas and oil industry terms used in this
report in the "Glossary" on page 82.
Cautionary Statement About Forward-Looking Statements
Some of the information in this Form 10-K contains forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. The forward-looking
statements speak only as of the date made, and we undertake no obligation to
update such forward-looking statements. These forward-looking statements may be
identified by the use of the words "believe," "expect," "anticipate," "will,"
"contemplate," "would" and similar expressions that contemplate future events
and subject to uncertainties. Actual results and trends in the future may differ
materially depending on a variety of factors including, but not limited to the
following matters:
- Impact of bankruptcy proceedings related to our ultimate parent, Enron
Corp. and affiliates;
- cash flow and liquidity;
- financial position;
- business strategy;
- budgets;
- amount, nature and timing of capital expenditures, including future
development costs;
- drilling of wells;
- natural gas and oil reserves;
- timing and amount of future production of natural gas and oil;
- operating costs and other expenses;
- prospect development and property acquisitions; and
- marketing of natural gas and oil.
Numerous important factors, risks and uncertainties may affect our
operating results, including:
- The risks associated with exploration;
- the ability to find, acquire, market, develop and produce new properties;
- natural gas and oil price volatility;
- uncertainties in the estimation of proved reserves and in the projection
of future rates of production and timing of development expenditures;
- operating hazards attendant to the natural gas and oil business;
- downhole drilling and completion risks that are generally not recoverable
from third parties or insurance;
- potential mechanical failure or under-performance of significant wells;
- climatic conditions;
- availability and cost of material and equipment;
- delays in anticipated start-up dates;
- Loss of Royalty Relief on certain blocks
3
- actions or inactions of third-party operators of our properties;
- the ability to find and retain skilled personnel;
- availability of capital;
- the strength and financial resources of competitors;
- regulatory developments;
- environmental risks; and
- general economic conditions.
Any of the factors listed above and other factors contained in this
annual report could cause our actual results to differ materially from the
results implied by these or any other forward-looking statements made by us or
on our behalf. We cannot provide assurance that future results will meet our
expectations. You should pay particular attention to the risk factors and
cautionary statements described under "Risk Factors" in "Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
(a) OVERVIEW
Mariner Energy, Inc. ("Mariner" or "Company") 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. 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." In 1996, Joint Energy
Development Investments Limited Partnership ("JEDI"), an affiliate of Enron
Corp. ("Enron") and Enron North America Corp. ("ENA") (also see further
description under "Enron" in "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations"), along with management led a
buyout from Hardy Oil & Gas, Plc. JEDI currently owns approximately 96%, while
employees and former employees own the remaining 4% of Mariner Energy LLC, which
owns 100% of Mariner Holdings, Inc. Mariner Holdings, Inc. owns all of the
common stock of Mariner.
Since 1996, we significantly increased our focus in the Gulf of Mexico.
Currently our strategy is to primarily focus our exploration efforts on Gulf of
Mexico shelf (less than 1000 feet water depth) prospects with a secondary focus
on Gulf of Mexico deepwater (greater than 1000 feet) opportunities leveraging
our expertise in deepwater subsea field development technology that were
tiebacks to near existing infrastructures (offshore platforms). Management
believes that no other U.S. independent oil and gas exploration company has more
experience then Mariner utilizing this technology in deepwater. In addition we
operate the onshore Aldwell field located West Texas comprised of 80 producing
wells and over 100 undeveloped locations
During 2002, we drilled 6 exploratory wells with 2 successes. We also
commenced a 42 well drilling program in the Aldwell unit and as of December 31,
2002, 8 wells were completed and on production. Ryder Scott Company estimated
that we had proved reserves of 202 Bcfe before the sale of our remaining
interest in the Falcon Corridor (see Recent Events) as of December 31, 2002, of
which 67% were natural gas and 33% were oil and condensate. Proved reserves
included net reserve additions of 39 Bcfe, representing 100% of 2002's Company's
production.
We expect our production for 2003 to be slightly lower than 2002's
average rate of 100 MMcfe per day, after the sale of our remaining interest in
the Falcon Corridor (see Recent Events). Our 2003 production rate is expected to
average 93 Mcfe per day. As of March 4, 2003, our daily production was 98 Mcfe.
4
In 2003, we expect to drill 8 to 12 exploratory wells. As of March 20,
2003 we have drilled three exploratory wells of which two have been successful
(see Recent Events). Development activities in 2003 include the completion of
our Roaring Fork and Vermillion 144 projects and development of the Swordfish
discovery and several development wells in currently producing fields.
We anticipate capital expenditures for 2003, before capitalized
indirect costs and proceeds from property conveyances of $103 million, to be
approximately $41 million for leasehold acquisition, exploration drilling and
$62 million for development projects, compared to our 2002 capital expenditures
of approximately $96.4 million, before capitalized indirect costs and proceeds
from property conveyances of $52.3 million. We expect to fund our capital
expenditures by a combination of internally generated cash flow and proceeds
from property conveyances, including the recently-announced sale of our
remaining interest in the Falcon development project.
The following table sets forth certain summary information with respect
to our oil and gas activities and results during the five years ended December
31, 2002. Reserve volumes and values were determined under the method prescribed
by the Securities and Exchange Commission, which requires the application of
year-end oil and natural gas prices, held constant throughout the projected
reserve life. The year-end oil and gas prices utilized do not include any impact
relating to hedging activities. See "Reserves" later in this item and Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations".
YEAR ENDING DECEMBER 31,
(dollars in millions unless otherwise indicated)
---------------------------------------------------------
2002 2001 2000 1999 1998
------ ------ -------- ------ ------
PROVED RESERVES:
Oil (MMbbls)....................................... 11.0 10.1 12.4 9.9 9.4
Natural gas (Bcf).................................. 136.1 176.5 129.3 118.8 128.9
Natural gas equivalent (Bcfe)...................... 202.2 237.1 203.6 178.4 185.1
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES (1) $515.0 $232.0 $1,043.2 $211.2 $147.6
ANNUAL RESERVE REPLACEMENT RATIO (2) 1.0 3.2 1.7 1.3 2.0
CAPITAL EXPENDITURES AND DISPOSAL DATA:
Capital costs incurred............................. $106.1 $164.5 $ 108.1 $ 81.5 $141.9
Proceeds from property conveyances................. (52.3) (90.5) (29.0) (19.8) --
------ ------ -------- ------ ------
Capital costs net of proceeds from property
conveyances...................................... 53.8 74.0 79.1 61.7 141.9
------ ------ -------- ------ ------
PERCENTAGE OF NET CAPITAL COSTS ATTRIBUTABLE TO:
Lease acquisition.................................. 14.0% 5.4% 10.5% 12.8% 30.4%
Exploratory drilling, geological and geophysical... 24.3% 35.0% 19.6% 16.6% 25.1%
Development and other.............................. 61.7% 59.6% 69.9% 70.6% 44.5%
PRODUCTION:
Oil (MMbls)........................................ 1.7 3.0 1.8 0.6 0.8
Natural gas (Bcf) 29.6 18.8 25.7 21.1 19.5
Natural gas equivalent (Bcfe)...................... 39.8 36.7 36.3 24.9 24.2
AVERAGE REALIZED SALES PRICE PER UNIT
(excluding the effects of hedging):
Oil ($/Bbl)........................................ $21.60 $22.41 $ 29.53 $17.53 $12.99
Natural gas ($/Mcf)................................ 3.35 4.86 4.07 2.48 2.33
Gas equivalent ($/Mcfe)............................ 3.41 4.31 4.32 2.58 2.30
AVERAGE REALIZED SALES PRICE PER UNIT
(including the effects of hedging):
Oil ($/Bbl)........................................ $22.85 $23.22 $ 21.54 $14.11 $12.99
Natural gas ($/Mcf)................................ 4.03 4.57 3.24 2.16 2.45
5
Gas equivalent ($/Mcfe)............................ 3.97 4.22 3.24 2.19 2.40
EXPENSES ($/MCFE):
Lease operating.................................... $ 0.65 $ 0.55 $ 0.47 $ 0.46 $ 0.41
Transportation..................................... 0.26 0.33 0.22 0.08 0.05
General and administrative, net.................... 0.19 0.25 0.18 0.22 0.20
(1) Discounted at an annual rate of 10%. See "Glossary" included
elsewhere in this annual report for the definition of "present
value of estimated future net revenues".
(2) The annual reserve replacement ratio for a year is calculated by
dividing aggregate reserve additions, including revisions, on a
Mcfe basis for the year by actual production on a Mcfe basis for
such year.
(b) RECENT EVENTS
On March 20, 2003, with bids totaling $3.9 million net to us, we were
the apparent high bidder solely or with industry partners, on 11 out of 11
blocks on which we and our partners submitted bids in the Central Gulf of Mexico
Oil and Gas Lease Sale 185 held on that date. The blocks are in water depths
ranging from approximately 20 feet to 1,500 feet. Mariner has a 100% working
interest in five of the block and a 50% working interest in six blocks.
In January 2003 we made a deepwater Gulf of Mexico Discovery at
"Harrier", East Breaks 759, and a shelf Gulf of Mexico discovery at Vermillion
144. Harrier was drilled in 4,100 feet of water to a total measured depth of
9,510 feet and encountered 315 net feet of gas pay. Mariner Energy holds a 25%
working interest. Vermilion 144 was drilled in 87 feet of water to a total
measured depth of 16,522 feet and encountered 90 net feet of pay. Mariner Energy
is operator with a 42% working interest. First production is expected in June
2003.
In March 2003, we sold our remaining 25% working interest in our Falcon
and Harrier discoveries and surrounding blocks, located in East Breaks area in
the western Gulf of Mexico, for $121.6 million. We retained a 4 1/4 percent
overriding royalty interest on seven non-producing blocks. The proceeds from the
sale are expected to be used for debt reduction, capital expenditures, and other
corporate purposes. At December 31, 2002, the Falcon project had 33.3 Bcfe
assigned as proven oil and gas reserves to our interest.
(c) BUSINESS STRATEGY
Our business strategy is to increase reserves, production and cash flow
by emphasizing growth through the drillbit. Our strategy consists of the
following elements:
- BULK SEISMIC PURCHASES. In 2001 and the first quarter of 2002, we acquired
three bulk seismic databases covering blocks in both the shelf and deepwater
Gulf of Mexico. We believe maintaining a large 3-D seismic database allows
us to identify high quality exploratory prospects. This seismic data allows
us to better understand the geology before selecting prospects and increases
the probability of accurately identifying the hydrocarbon-bearing zones.
- DIVERSIFY OUR PORTFOLIO. Currently, we maintain a significant amount of both
shelf and deepwater Gulf of Mexico lease positions. Our strategy is to
allocate approximately 30% to 40% of our capital budget for moderate risk
exploration opportunities on both the Shelf and Deepwater. Shelf wells are
less expensive, lower risk, and can be connected to market relatively
quickly compared to Deepwater wells; however, the reserve targets are
typically smaller than in the Deepwater. To manage the typical higher cost
of Deepwater projects we focus on projects that will most likely utilize
subsea tie back technology. Management believes that no other U.S.
independent oil and gas company has utilized this technology more than
Mariner. We believe this gives us a competitive advantage. In addition, we
plan allocate 60% to 70% of our capital budget to develop our existing asset
base to realize full asset value. This includes development of our Swordfish
and Roaring Fork projects as well as our onshore infill drilling program at
our Aldwell field located in West Texas.
6
- REDUCE DEPENDENCE ON CAPITAL INFUSIONS AND BORROWINGS. Historically, we have
been required to sell various properties in order to manage our cash flow.
In 2002, we sold half of our 50% working interest in our Falcon project for
$52.3 million. This sale allowed us to maintain a high level of exploratory
activity in addition to repaying our Revolving Credit Facility. In March
2003, we sold our remaining 25% working interest in our Falcon and Harrier
projects for $121.6 million. The proceeds of the sale are expected to be
used to reduce our corporate debt, maintain an active exploration program
and other corporate purposes. We will continue to consider monetizing assets
to achieve high rates of returns for our shareholders and reduce our overall
risk profile.
- 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. Our geoscientists average more than 20 years of
experience in the exploration and production business, including extensive
experience in the Gulf and with major oil companies. Through our technical
staff's understanding of the geology and geophysics of the Gulf, we intend
to continue to generate the majority of our prospects internally.
- CONTROL ADMINISTRATIVE COSTS. In order for us to be competitive, we understand
we must control administrative costs. In 2002, we continued to reduce our
workforce and have caused an approximate 40% reduction since third quarter
of 2001. We believe these reductions will allow us to control costs while
maintaining necessary technical expertise. In addition, we expect to
continue to generate reimbursements of costs through joint ventures with
partners.
(d) RESERVES
The following table sets forth certain information with respect to our
proved reserves by geographic area as of December 31, 2002. Reserve volumes and
values were determined under the method prescribed by the Securities and
Exchange Commission which requires the application of year-end prices held
constant throughout the projected reserve life. The reserve information as of
December 31, 2002 is based upon a reserve report prepared by the independent
petroleum consulting firm of Ryder Scott Company, independent reserve engineers.
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, the Company's
reserves and production will decline. See Note 11 to the Financial Statements
included elsewhere in this Annual Report for a discussion of the risks inherent
in oil and natural gas estimates and for certain additional information
concerning the proved reserves.
AS OF DECEMBER 31, 2002
-----------------------
PRESENT VALUE OF
PROVED RESERVE QUANTITIES ESTIMATED FUTURE NET RESERVES(1)
------------------------------------ ----------------------------------------
DOLLARS IN MILLIONS
OIL NATURAL GAS TOTAL ----------------------------------------
GEOGRAPHIC AREA (MMBbls) (Bcf) (Bcfe) DEVELOPED UNDEVELOPED TOTAL
--------------- -------- ----------- ------ --------- ----------- ------
Deepwater Gulf............. 3.2 92.0 111.2 175.6 $ 147.8 $323.4
Gulf Shallow Water and
Gulf Coast Onshore...... 1.9 14.0 25.4 24.8 55.6 80.4
Permian Basin.............. 5.9 30.1 65.5 43.8 67.4 111.2
---- ----- ----- ------- --------- ------
Total................ 11.0 136.1 202.1 $ 244.2 $ 270.8 $515.0
==== ===== ===== ======= ========= ======
Proved Developed Reserves.. 3.6 64.6 86.1 $ 240.0
---- ----- ----- -------
(1) Discounted (at 10%) present value as of December 31, 2002 (year-end prices
held constant).
Our estimates of proved reserves set forth in the foregoing table do
not differ materially from those filed by us with other federal agencies.
7
(e) OIL AND GAS PROPERTIES
(i) SIGNIFICANT PROPERTIES WITH PROVED RESERVES AS OF DECEMBER 31, 2002
We own oil and gas properties, both producing and non-producing,
onshore in Texas and offshore in the Gulf, primarily in federal waters. Our 10
largest producing properties, as shown in the following table, accounted for
approximately 93% of the Company's proved reserves as of December 31, 2002.
DATE NET
MARINER APPROXIMATE PRODUCTION PROVED
WORKING WATER PRODUCING COMMENCED/ RESERVES
OPERATOR INTEREST DEPTH (FEET) WELLS(3) EXPECTED (BCFE)
---------- -------- ------------ --------- ----------- --------
DEEPWATER GULF:
East Breaks 579 (Falcon)(1)........... Pioneer 25% 3,400 - 2nd quarter 2003 33.3
Green Canyon 472 (King Kong).......... AGIP 50% 3,900 2 February 2002 21.1
Mississippi Canyon 718 (Pluto)........ Mariner 51% 2,710 1 December 1999 8.2
Ewing Bank 966 (Black Widow).......... Mariner 69% 1,850 1 October 2000 10.1
Green Canyon 516 (Yosemite)........... AGIP 44% 3,850 1 April 2002 15.1
Viosca Knoll 917 (Swordfish).......... Mariner 15% 4,200 1 2nd quarter 2004 9.9
Mississippi Canyon 322 (Crater Lake) Walter O&G 40% 700 - February 2002 3.8
GULF SHALLOW WATER AND GULF COAST
ONSHORE:
South Timbalier 316 (Roaring Fork).... Westport 20% 450 - 4th quarter 2003 15.5
Brazos A-105.......................... Unocal 12.5% 192 4 January 1993 4.3
PERMIAN BASIN OF WEST TEXAS:
Spraberry Aldwell Unit(2)............. Mariner 70.3% Onshore 91 1949 65.1
OTHER PROPERTIES: -- -- -- 36 -- 15.7
--- -----
TOTAL PROVED RESERVES: 137 202.1
=== =====
(1) In March 2003 our remaining 25 working interest was sold for $121.6 million.
(2) We operate the unit and own working interests in individual wells ranging
from approximately 33% to 84%.
(3) Producing wells or wells capable of producing.
Following is additional information regarding the properties in the table shown
above.
GULF OF MEXICO
East Breaks 579 (Falcon) Mariner generated and acquired the Falcon
prospect at a federal lease sale in August 1997. Currently Mariner has a 25%
working interest in this Pioneer operated discovery located in the deepwater
Gulf of Mexico 95 miles southeast of Corpus Christi, Texas in a water depth of
3,400 feet. In April 2001, the Mariner EB 579 #1 well was drilled and yielded a
significant discovery that was sanctioned for development in October of the same
year. Estimated net proved reserves from Falcon are 33.3 Bcfe. First production
is anticipated to commence in March of 2003. (also see "Recent Events").
Green Canyon 472 / Green Canyon 516 (King Kong / Yosemite) In July
2000, we entered into an agreement to acquire Shell Exploration and Production
Company's 50% working interest in the "King Kong" Gulf of Mexico development
project. The project is located in approximately 3,900 feet of water in Green
Canyon Blocks 472 and 473, approximately 150 miles southeast of New Orleans. We
purchased Shell's interest for an undisclosed amount of cash and overriding
royalty interest in the field, and have been named operator for development of
the project. Agip Petroleum Co. Inc., as a successor to British Borneo, owns the
remaining 50% working interest. This project began production in February 2002
and it ties back 16 miles to the Allegheny mini-TLP operated by Agip. In 2001 we
drilled our "Yosemite" exploration prospect located adjacent to King Kong in
Green Canyon Block 516. Yosemite is jointly developed with King Kong. As of
December 31, 2002 the fields have produced 18.7 Bcfe net to us with the combined
projects having an estimated net remaining proved reserves of 36.2 Bcfe.
8
Mississippi Canyon 718 (Pluto) We acquired a 30% interest in this
project in 1997, two years after British Petroleum discovered gas on the
project. We later increased our ownership to 97%, acquiring operatorship and
gaining overall control of project planning and implementation. In 1998, we
increased our working interest to 100% and submitted a deepwater royalty relief
application that was granted in July 1999. Due to high natural gas commodity
prices, however, royalty relief did not apply to natural gas production in 2000
or 2001. In June 1999, we sold a 63% working interest in the project to
Burlington Resources, Inc., reducing our working interest to 37%. After project
payout, which occurred in the third quarter of 2000, our working interest
increased to 51% and Burlington's working interest decreased to 49%. We
developed the field with a single subsea well which is located in the Gulf
approximately 150 miles southeast of New Orleans, Louisiana at a water depth of
2,710 feet and a flow line tied back approximately 29 miles to a production
platform on the shelf. Production began on December 29, 1999 and through
December 31, 2002 the field produced net 30.8 Bcfe and has an estimated
remaining net proved reserves of 8.2 Bcfe, 60% of which was natural gas.
Ewing Bank 966 (Black Widow) We acquired the Black Widow prospect at a
federal offshore Gulf lease sale in March 1997. We operate and have a 69%
working interest in this project, which is located in the 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 commenced production in the fourth quarter of 2000 via subsea tieback to an
existing platform, and the field has produced through December 31, 2002 net 22.3
Bcfe. Estimated remaining net proved reserves from Black Widow are approximately
10.1 Bcfe, 87.6% of which is oil.
Viosca Knoll 917 (Swordfish) Mariner entered into a farmout agreement
with BP (Amoco) in September 2001 to drill the Swordfish prospect. We operate
and have a 15% working interest in this project, which is located in the
deepwater Gulf of Mexico 105 miles southeast of New Orleans, Louisiana in water
depths that range from 4,200 feet. In November and December of 2001, Mariner
drilled two successful exploration wells on the prospect. Estimated net proved
reserves for the Swordfish prospect are 9.9 Bcfe. First production is
anticipated to commence in the second quarter of 2004.
Mississippi Canyon 322 (Crater Lake) Mariner generated and acquired the
Crater Lake prospect at a federal sale in March of 1998. Mariner has a 40%
working interest in this Walter Oil & Gas operated project, which is located in
the deepwater Gulf of Mexico 75 miles southeast of New Orleans, Louisiana in a
water depth of 700 feet. In May of 2001, Walter Oil and Gas drilled a successful
exploration well and a successful appraisal that were later completed. First
production from the initial discovery well began February 2002. Production from
the second well will begin upon depletion of the initial well. The field has
produced through December 31, 2002 net 1.0 Bcfe with the estimated net proved
remaining reserves from Crater Lake at 3.8 Bcfe.
South Timbalier 316 (Roaring Fork) Mariner entered into a farmout
agreement with Westport and Samedan in October 2001 to participate in the
drilling of the Roaring Fork prospect. Mariner has a 20% working interest in
this Westport operated project, which is located in the Gulf of Mexico 135 miles
south of New Orleans, Louisiana in a water depth of 450 feet. Westport drilled a
successful exploration well on the prospect followed by two successful appraisal
wells. The estimated net proved reserves for the Roaring Fork prospect are 15.5
Bcfe. First production is anticipated to commence in the fourth quarter of 2003.
Brazos A-105 We generated the Brazos A-105 prospect and own a 12.5%
working interest in this Unocal-operated property, which commenced production in
January 1993. Five wells exploit a single gas reservoir. No additional wells are
currently anticipated. The field has produced 28.5 Bcfe net to us from its
inception through December 31, 2002. The field has estimated remaining net
proved reserves of 4.3 Bcfe as of December 31, 2002, 99% of which is natural
gas.
PERMIAN BASIN OF WEST TEXAS
Spraberry Aldwell Unit. We acquired our interest in the Spraberry
Aldwell Unit, located in Reagan County, Texas, in 1985. The 18,250-acre unit is
located in the heart of the Spraberry Trend southeast of Midland, Texas and has
produced oil since 1949. We operate the unit and own working interests in
individual wells ranging from approximately 33% to 84%. We initiated an infill
drilling program in 1987 innovatively commingling the unitized Spraberry
formation with the non-unitized Dean formation. To date, 82 infill wells have
been drilled resulting in 82
9
productive wells. Currently, there are a total of 91 producing wells in the
unit. With Mariner having initially contracted 15 infill drilling wells for
2003. Plans are to drill over the next two to four years, the remaining 98
Proved Undeveloped Infill wells. Average cost to drill an Infill Spraberry Well
is approximately $400,000(gross). We estimate that the field's remaining net
proved reserves as of December 31, 2002 is 65.1 Bcfe. We believe that the
field's potential for continued economic oil production exceeds 40 years.
(ii) DISPOSITION OF PROPERTIES
We periodically evaluate and, when appropriate, sell certain of our
producing properties that we consider to be marginally profitable or outside of
our areas of concentration. We also consider the sale of discoveries that are
not yet producing when we believe we can obtain acceptable returns on our
investment without holding the investment through depletion. Such sales enable
us to maintain financial flexibility, reduce overhead and redeploy the proceeds
to activities that we believe have a higher potential financial return. No
property dispositions of producing properties were made during the three years
ending December 31, 2002. However, in 2000, 2001 and 2002 we sold a 20% gross
interest in our Devils Tower project for $29 million, a 30% gross interest in
our Devils Tower project and 50% interest in our Aconcagua project for $39.5
million and $51 million respectively and a 25% working interest in the Falcon
project for $52.3 million. In March of 2003, we sold our remaining 25% working
interest in Falcon and Harrier for $121.6 million. See "Recent Events" above.
(iii) TITLE TO PROPERTIES
Our properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and other burdens,
including other mineral encumbrances and restrictions. We do not believe that
any of these burdens materially interferes with the use of such properties in
the operation of our business.
We believe that we have satisfactory title to or rights in all of our
producing properties. As is customary in the oil and natural gas industry,
minimal investigation of title is made at the time of acquisition of undeveloped
properties. Title investigation is made, and title opinions of local counsel are
generally obtained, only before commencement of drilling operations. We believe
that title issues generally are not as likely to arise on offshore oil and gas
properties as on onshore properties.
10
(f) PRODUCTION
The following table presents certain information with respect to oil
and natural gas production attributable to our properties, average sales price
received and expenses per unit of production during the periods indicated.
YEAR ENDING DECEMBER 31,
----------------------------------
2002 2001 2000
------ ------ ------
PRODUCTION:
Oil (MMbbls) 1.7 3.0 1.8
Natural gas (Bcf) 29.6 18.8 25.7
Natural Gas equivalent (Bcfe) 39.8 36.7 36.3
AVERAGE REALIZED SALES PRICE PER UNIT
(EXCLUDING EFFECTS OF HEDGING):
Oil ($/Bbl) $21.60 $22.41 $29.53
Natural gas ($/Mcf) 3.35 4.86 4.07
Natural Gas equivalent ($/Mcfe) 3.41 4.31 4.32
AVERAGE REALIZED SALES PRICE PER UNIT
(INCLUDING EFFECTS OF HEDGING):
Oil ($/Bbl) $22.85 $23.22 $21.54
Natural gas ($/Mcf) 4.03 4.57 3.24
Natural Gas equivalent ($/Mcfe) 3.97 4.22 3.24
EXPENSES ($/MCFE):
Lease operating $ 0.65 $ 0.55 $ 0.47
Transportation 0.26 0.33 0.22
General and administrative, net (1) 0.19 0.25 0.18
Depreciation, depletion and amortization 1.78 1.73 1.57
CASH MARGIN ($/MCFE) (2) $ 2.66 $ 2.86 $ 2.26
(1) Net of overhead reimbursements received from other working interest
owners and amounts capitalized under the full cost accounting method.
(2) Average equivalent gas sales price (including the effects of hedging
prior to de-designation as a hedge), minus lease operating and gross
general and administrative expenses.
(g) PRODUCTIVE WELLS
The following table sets forth the number of productive oil and gas
wells in which we owned a working interest at December 31, 2002:
TOTAL PRODUCTIVE
WELLS
-----------------------
GROSS NET
----- -----
Oil.............................. 88 61.6
Gas.............................. 49 8.9
--- ----
Total....................... 137 70.5
=== ====
Productive wells consist of producing wells and wells capable of
production, including 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.
11
(h) ACREAGE
The following table sets forth certain information with respect to the
developed and undeveloped acreage as of December 31, 2002.
DEVELOPED UNDEVELOPED
ACRES(1) ACRES(2)
-------------------- ----------------------
GROSS NET GROSS NET
------- ------- -------- -------
Texas (Onshore)............... 18,337 12,300 282 117
Other states (Onshore)........ 671 212 574 126
Offshore...................... 307,325 89,367 400,882 192,572
------- ------- ------- -------
Total (3).............. 326,333 101,879 401,738 192,815
======= ======= ======= =======
(1) Developed acres are acres spaced or assigned to productive wells.
(2) 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 such acreage
contains proved reserves.
(3) Prior to the sale of our remaining 25% working interest in the Falcon and
Harrier discoveries and their surrounding blocks.
12
(i) DRILLING ACTIVITY
Certain information with regard to our drilling activity during the
years ended December 31, 2002, 2001 and 2000 is set forth below.
YEAR ENDING DECEMBER 31,
----------------------------------------------------------------
2002 2001 2000
--------------- ---------------- -----------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ---- ----- -----
EXPLORATORY WELLS:
Producing............. 2 1.08 7 2.48 1 0.40
Dry................... 4 1.60 4 1.50 3 2.08
--- ---- --- ---- --- ----
Total.............. 6 2.68 11 3.98 4 2.48
=== ==== === ==== === ====
DEVELOPMENT WELLS:
Producing............. 13 7.93 7 2.40 2 0.45
Dry................... 0 0.00 1 0.33 -- --
--- ---- --- ---- --- ----
Total.............. 3 7.93 8 2.73 2 0.45
=== ==== === ==== === ====
TOTAL WELLS:
Producing............. 15 9.01 14 4.88 3 0.85
Dry .................. 4 1.60 5 1.83 3 2.08
--- ---- --- ---- --- ----
Total.............. 9 10.61 19 6.71 6 2.93
=== ==== === ==== === ====
(j) MARKETING, CUSTOMERS AND HEDGING ACTIVITIES
We market substantially all oil and gas production from properties we
operate and properties operated by others where our interest is significant. The
majority of our natural gas, oil and condensate production is sold to a variety
of purchasers under short-term (less than 12 months) contracts at
market-sensitive prices. As to gas produced from the Spraberry Aldwell Unit, we
have a long-term agreement for the sale and processing of such gas on terms that
we believe to be competitive. The following table lists customers accounting for
more than 10% of our total revenues for the year indicated.
PERCENTAGE OF TOTAL REVENUES
FOR THE YEAR ENDING
DECEMBER 31,
----------------------------------------
CUSTOMER 2002 2001 2000
-------- ---- ---- ----
Bridgeline Gas Distributing Company.......... 42% -- --
Conoco Inc......................................... 14% -- --
Duke Energy...................................... 9% 14% 16%
Enron North America and affiliates
(An affiliate of the Company)................... -- 32% 49%
Genesis Crude Oil LP............................. 4% 24% --
On June 28, 2002 the Company commenced price risk activities with a
third party. These activities are intended to manage the Company's exposure to
fluctuations in commodity prices for natural gas and crude. As of December 31,
2002, the Company had the following fixed price swaps outstanding.
13
DECEMBER 31, 2002
FAIR VALUE
NOTIONAL FIXED (millions)
TIME PERIOD QUANTITIES PRICE Gain/(Loss)
----------- ---------- ----- -----------------
CRUDE OIL (MBbl)
January 1 - December 31, 2003
Fixed Price Swap 548 $24.02 $ (1.8)
Fixed Price Swap 183 $24.81 (0.4)
NATURAL GAS (MMbtu)
January 1 - December 31, 2003
Fixed Price Swap 730 $ 3.54 (7.5)
Fixed Price Swap 730 $ 3.60 (7.1)
------
$(16.8)
------
------
The Company has reviewed the financial strength of counterparts to
these transactions and believes credit risk to be minimal. As of December 31,
2002 the Company had on deposit, classified as restricted cash, $15.2 million
with a third party for collateral. This collateral included $5.8 million in
initial margin in cash and $16.7 million in mark-to-market exposure which is
recorded as a liability with an offset in accumulated other comprehensive
income. Initial margin decreases as contracts settle.
As a result of increasing natural gas prices, in January and February
of 2003, the Company unwound, through the purchase of counter positions, all
natural gas swap contracts for the months of February through October 2003
locking in a loss of $23.2 million. This loss will be settled over the original
contract period.
Subsequent to their unwinding the Company will have approximately 24%
of 2003 production subject to hedges. Mark to market value changes approximately
$8.6 million for every 10% overall change in commodity prices.
The following table sets forth the results of hedging transactions
during the periods indicated that were made with non-Enron related parties.
DECEMBER 31,
2002 2001
------ ----
NATURAL GAS -- --
Quantity hedged (Mmbtu)
Increase (Decrease) in Natural Gas Sales (in thousands) -- --
CRUDE OIL
Quantity hedged (MBbls) 169 --
Increase (Decrease) in Crude Oil Sales (in thousands) $(325) --
(k) COMPETITION
We believe that the locations of our leasehold acreage, our
exploration, drilling and production capabilities, and our experience 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. Such companies may be able to
pay more for productive oil and natural gas properties and exploratory prospects
and to define, evaluate, bid for and
14
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 is dependent upon our ability to evaluate and
select suitable properties and to consummate transactions in a highly
competitive environment. In addition, there is substantial competition for
capital available for investment in the oil and natural gas industry.
(l) ROYALTY RELIEF
The Outer Continental Shelf Deep Water Royalty Relief Act (the "RRA"),
signed into law on November 28, 1995, provides that all tracts in the Gulf of
Mexico west of 87 degrees, 30 minutes West longitude in water more than 200
meters deep offered for bid within five years of the RRA will be relieved from
normal federal royalties as follows:
WATER DEPTH ROYALTY RELIEF
----------- --------------
200-400 meters.......................... no royalty payable on the first 105 Bcfe produced
400-800 meters.......................... no royalty payable on the first 315 Bcfe produced
800 meters or deeper.................... no royalty payable on the first 525 Bcfe produced
The RRA also allows mineral interest owners the opportunity to apply
for royalty relief for new production on leases acquired before the RRA was
enacted. If the United States Minerals Management Service ("MMS") 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. In the event that
prices exceed certain prescribed thresholds royalty relief is suspended. In 2000
and 2001, our Pluto, Black Widow, Garden Banks 179 and King Kong projects
qualified for royalty relief; however, natural gas prices exceeded the
thresholds. Consequently, we have been required to pay royalties on natural gas
for both 2000 and 2001. Natural gas prices did not exceed threshold for 2002. We
are currently disputing the MMS right to suspend royalty relief on certain
blocks solely because of the threshold prices and consequently filed an
administrative appeal. We have accrued $5.5 million related to this obligation
to provide for the event that we lose our appeal.
(m) REGULATION
Our operations are subject to extensive and continually changing
regulation affecting the oil and natural gas industry. 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 such rules and
regulations can result in substantial penalties. The regulatory burden on the
oil and natural gas industry increases our cost of doing business and,
consequently, affects our profitability. We do not believe that we are affected
in a significantly different manner by these regulations than are our
competitors.
(i) TRANSPORTATION AND SALE OF NATURAL GAS
The FERC (Federal Energy Regulatory Commission) regulates interstate
natural gas pipeline transportation rates and service conditions, which affect
the marketing of gas produced by us and the revenues received by us for sales of
such natural gas. In 1985, the FERC adopted policies that make natural gas
transportation accessible to natural gas buyers and sellers on an open-access,
non-discriminatory basis. The FERC issued Order No. 636 on April 8, 1992, which,
among other things, prohibits interstate pipelines from tying sales of gas to
the provision of other services and requires pipelines to "unbundle" the
services they provide. This has enabled buyers to obtain natural gas supplies
from any source and secure independent delivery service from the pipelines. All
of the interstate pipelines subject to FERC's jurisdictions are now operating
under Order No. 636 open access tariffs. On July 29, 1998, the FERC issued a
Notice of Proposed Rulemaking regarding the regulation of short term natural gas
transportation services. In a related initiative, FERC issued a Notice of
Inquiry on July 29, 1998 seeking input from natural gas industry players and
affected entities regarding virtually every aspect of the regulation of
interstate natural gas transportation services. As a result, the FERC issued
Order No. 637 (final rule on February 9, 2000) amending its transportation
regulation in response to the growing
15
development of more competitive markets for natural gas and the transportation
of natural gas. Order No. 637 revises the regulatory framework to improve the
efficiency of the natural gas market and provide captive customers with the
opportunity to reduce their cost of holding long-term pipeline capacity. The
rate revises the FERC's pricing policy to enhance market efficiency for short
term released capacity and permit pipelines to file for peak and off-peak and
term differentiated rate structures. Order No. 637 further improves the
Commission's reporting requirements and permits more effective monitoring of the
natural gas market.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. We cannot predict when or if any such
proposals might become effective or their effect, if any, on our operations. The
natural gas industry historically has been closely regulated; thus, there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue indefinitely into the future.
(ii) 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 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 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, 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 is 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.
(iii) 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, activities
in connection with storage and transportation of crude oil and other liquid
hydrocarbons and use of facilities for treating, processing or otherwise
handling hydrocarbons and wastes therefrom are subject to stringent
environmental regulation. As with the industry generally, compliance with
existing regulations increases our overall cost of business. Such 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.
16
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 certain 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 its 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 for
all or part of the costs required to clean up sites at which such 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 utilized 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 such 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 thereon may be subject to CERCLA and analogous state laws. Under
such 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.
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 principal 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,
17
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.
(n) EMPLOYEES
As of December 31, 2002, we had 43 full-time employees. Our employees
are not represented by any labor unions. We consider relations with our
employees to be satisfactory. We have never experienced a work stoppage or
strike.
(o) Our internet website is www.mariner-energy.com. While our website includes a
link to EDGAR, we do not otherwise make our Exchange Act reports available on
our website. [Our Exchange Act reports are available free of charges by request
to Mike Wichterich at mwichterich@mariner-energy.com.
ITEM 3. LEGAL PROCEEDINGS
MMS APPEAL - Mariner operates numerous properties in the Gulf of
Mexico. Three of such properties were leased from the Mineral Management Service
subject to the 1996 Royalty Relief Act. This Act relieved the obligation to pay
royalties on certain predetermined leases until a designated volume is produced.
These three leases contained language, which limited royalty relief if commodity
prices exceeded predetermined levels. Beginning in January 2000 commodity prices
exceeded the predetermined levels. Management believes the MMS did not have the
authority to set pricing limits and the Company has filed an administrative
appeal with the MMS and has withheld royalties regarding this matter. The
Company has recorded a liability for 100% of the exposure on this matter which
on December 31, 2002 was $5.5 million.
In the ordinary course of business, we are a claimant and/or a
defendant in various legal proceedings, including proceedings as to which we
have insurance coverage, in which the exposure, individually and in the
aggregate, is not considered material to us.
Also see further description under "Enron" in "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations"
regarding matters that could impact the Company operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
18
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
There is no established public trading market for our common stock, our
only class of equity securities.
Equity Compensation Plan Information
The following table provides information about our shares of Common
Stock that may be issued upon the exercise of options under our stock
compensation plan as of December 31, 2002.
Number of securities
remaining available for
future issuance under
equity compensation
Number of securities to Weighted average plans (excluding
be issued upon exercise exercise price of securities reflected in the
of outstanding options outstanding options previous column)
---------------------------------------------------------------------------------------
Plan Category
Equity compensation plans
approved by shareholders - - -
Equity compensation plans, not
approved by shareholders 1,926,468 9.47 507,132
See Part III, Item 13. "Certain Relationships and Related Party
Transactions" related to common stock ownership and other entities related to
registrant.
19
ITEM 6. SELECTED FINANCIAL DATA
The information below should be read in conjunction with Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the financial statements included in Item 8 of this report. The
following table sets forth selected financial data for the periods indicated.
(ALL AMOUNTS IN MILLIONS)
YEAR ENDING DECEMBER 31,
----------------------------------------------------
STATEMENT OF OPERATIONS DATA: 2002 2001(1) 2000 1999 1998
------ ------ ------ ------ ------
Total revenues............................ $158.2 $155.0 $121.1 $ 54.5 $ 58.0
Lease operating expenses.................. 26.1 20.1 17.2 11.5 9.9
Transportation............................ 10.5 12.0 7.8 2.0 1.3
Depreciation, depletion and amortization.. 70.8 63.5 56.8 32.1 33.8
Impairment of oil and gas properties...... - - - - 50.8
Impairment of Enron related receivables... 3.2 29.5 - - -
Provision for Litigation.................. - - - - 2.8
General and administrative expenses....... 7.7 9.3 6.5 5.4 4.8
------ ------ ------ ------ ------
Operating income (loss).............. 39.9 20.6 32.8 3.5 (45.4)
Interest income........................... 0.4 0.7 0.1 - 0.3
Interest expense.......................... (10.3) (8.9) (11.0) (13.5) (13.3)
Income (loss) before income taxes.... 30.0 12.4 21.9 (10.0) (58.4)
Provision for income taxes................ - - - - -
------ ------ ------ ------ ------
Net income (loss).................... $ 30.0 $ 12.4 $ 21.9 $(10.0) $(58.4)
====== ====== ====== ====== ======
CAPITAL EXPENDITURE AND DISPOSAL DATA:
Exploration, including leasehold/seismic.. $ 40.4 $ 66.3 $ 46.7 $ 24.0 $ 78.8
Development and other..................... 65.7 98.2 61.4 57.5 63.1
Proceeds from property conveyances........ (52.3) (90.5) (29.0) (19.8) -
------ ------ ------ ------ ------
Total capital expenditures net of
proceeds from property conveyances $ 53.8 $ 74.0 $ 79.1 $ 61.7 $141.9
====== ====== ====== ====== ======
BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net, at full cost. $286.0 $290.6 $287.8 $263.6 $233.3
Total assets.............................. 360.2 363.9 335.4 297.5 262.3
Long-term debt, less current maturities... 99.8 99.8 129.7 167.3 124.6
Stockholder's equity...................... 170.1 180.1 141.9 65.0 27.5
(1) Historically we have recorded all derivative transactions utilizing hedge
accounting treatment. On January 1, 2001 we adopted Financial Accounting
Standard No. 133 "Accounting for Derivative Instruments and Hedging
Activities". In addition, beginning on December 2, 2001, due to the Enron
bankruptcy, we ceased hedging accounting treatment. In 2002 we began hedging
with a new third party.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
(a) INTRODUCTION
The following discussion is intended to assist in an understanding of
our financial position and results of operations for each of the three years in
the period that began January 1, 2000 and ended December 31, 2002. This
discussion should be read in conjunction with the information contained in the
financial statements included elsewhere in this annual
20
report. All statements other than statements of historical fact included in this
annual report, including, without limitation, statements contained in this
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" regarding our financial position, business strategy, plans and
objectives of management for future operations and industry conditions, are
forward-looking statements. Although we believe that the expectations reflected
in such forward-looking statements are reasonable, we can give no assurance that
such expectations will prove to have been correct.
(b) GENERAL
We are 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 strategy is to profitably increase reserves, production and
cash flow primarily through the drillbit.
During 2002 we:
- drilled 6 exploratory wells, with 2 successes, in the Gulf of Mexico;
- drilled successful appraisal wells on our Falcon and Roaring Fork
prospects;
- commenced first production on our King Kong/Yosemite project;
- sold half of our 50% working interest in Falcon project, with proceeds
from these sales being used to pay off our Revolving Credit Facility;
- added proved reserves of 39.8 Bcfe, which were approximately 100% of our
2002 production and resulted in proven reserves of 202 Bcfe net of the
33.3 Bcfe in attributable to the 2002 sold working interest in our
Falcon project.
We anticipate capital expenditures for 2003, before capitalized
indirect costs and proceeds from property conveyances, to be approximately $103
million of which $41 million is expected to be used for leasehold acquisition,
seismic data and exploration drilling and $62 million for development
expenditures. This is approximately equal to our 2002 capital expenditures of
approximately $97.3 million, before capitalized indirect costs and proceeds from
property conveyances of $52.3 million. We expect to fund our capital
expenditures by a combination of internally generated cash flow and proceeds
from property conveyances, including the recently announced sale of the
remaining interest in our Falcon Corridor project.
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.
(c) RECENT EVENTS
On March 19, 2003, with bids totaling $3.9 million net to us, we were
the apparent high bidder solely or with industry partners, on 11 out of 11
blocks on which we and our partners submitted bids in the Central Gulf of Mexico
Oil and Gas Lease Sale 185 held on that date. Each of the blocks is in water
depths ranging from approximately 20 feet to 1,500 feet. Mariner has a 100%
working interest in five of the blocks and a 50% working interest in six blocks.
In January 2003 we made a deepwater Gulf of Mexico Discovery at
"Harrier", East Breaks 759, and a shelf Gulf of Mexico discovery at Vermillion
144. Harrier was drilled in 4,100 feet of water to a total measured depth of
9,510 feet and encountered 315 net feet of gas pay. Mariner holds a 25% working
interest. Vermilion 144 was drilled in 87 feet of water to a total measured
depth of 16,522 feet and encountered 90 net feet of pay. Mariner is operator
with a 42% working interest. First production is expected in June 2003.
In March 2003, we sold our remaining 25% working interest in our Falcon
and Harrier discoveries and surrounding blocks, located in East Breaks area in
the western Gulf of Mexico, for $121.6 million. We retained a 4 1/4 percent
overriding royalty interest on seven non-producing blocks. The proceeds from the
sale are expected to be used for debt reduction, capital expenditures, and other
corporate purposes. At December 31, 2002, the Falcon project had 33.3 Bcfe
assigned as proven oil and gas reserves to our interest.
21
(d) ENRON-CONTROL RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
ENRON BANKRUPTCY - Commencing on December 2, 2001, Enron Corp.
("Enron") and certain of its affiliates, including Enron North America Corp.
("ENA"), filed voluntary petitions for bankruptcy protection. We have been
informed that of our various direct or indirect owners, only Enron and ENA are
debtors in the bankruptcy. We do not know at this time if any other owners will
seek bankruptcy protection or what effect, if any, this may have on the
ownership of Mariner Energy LLC which owns 100% of Mariner Holdings, Inc. (our
direct parent) or on Joint Energy Development Investments Limited Partnership
("JEDI"), which owns approximately 96% of the issued and outstanding equity of
Mariner Energy LLC. Enron is the parent of ENA, and an affiliate of ENA is the
general partner of JEDI. JEDI is 100% owned by Enron and affiliates of ENA.
Accordingly, Enron may be deemed to control JEDI, Mariner Energy LLC, Mariner
Holdings and us. Additionally, five of the Company's directors are officers of
Enron or affiliates of Enron. Because of these various potentially conflicting
interests, ENA, the Company, JEDI and the minority shareholders of Mariner
Energy LLC have entered into an agreement that is intended to make clear that
Enron and its affiliates have no duty to make business opportunities available
to the Company.
Mariner Energy LLC's only asset is 100% of the common stock of Mariner
Holdings, Inc., our direct parent. The only asset of Mariner Holdings is 100% of
the common shares of Mariner.
Management cannot predict with certainty what impact Enron's bankruptcy
may have on us. However, it does believe that our assets and liabilities will
not become part of the Enron estate in bankruptcy. Although JEDI owns 96% of
Mariner Energy LLC's common shares, we, as a separate corporation own or lease
the assets used in its business and our management, separate from Enron, is
responsible for our day-to-day operations. Contractual provisions restrict Enron
access to our assets. We maintain our own accounting system as well as separate
debt ratings. We maintain our own separate and complete cash management system
and finance its operations separately from Enron, on both a short-term and
long-term basis. We file a consolidated tax return with Mariner Energy LLC.
Notwithstanding the above, we may have potential exposure to certain
liabilities and asset impairments as a result of Enron's bankruptcy. Portions
following Enron-related disclosures are based on discussions with Enron's legal
advisors and management, including members of our Board of Directors. Although
our management has implemented with Enron's legal advisor and management a
systematic method of identifying Enron matters which may have a material impact
on us, management cannot provide any assurance as the completeness or accuracy
of the information provided by or on behalf of Enron.
ORGANIZATION AND OWNERSHIP OF THE COMPANY - Through March 31, 1996,
Hardy Oil & Gas USA Inc. (the "Predecessor Company") was a wholly-owned
subsidiary of Hardy Holdings Inc., which is a wholly-owned subsidiary of Hardy
Oil & Gas Plc ("Hardy Plc"), a company incorporated in the United Kingdom.
Pursuant to a stock purchase agreement dated April 1, 1996, JEDI and ENA,
together with members of management of the Predecessor Company, formed Mariner
Holdings, Inc. ("Mariner Holdings"). Mariner Holdings then purchased from Hardy
Holdings Inc. all of the issued and outstanding stock of the Predecessor Company
for a purchase price of approximately $185.5 million (the "Acquisition"). After
the Acquisition, the name of the Predecessor Company was changed to Mariner
Energy, Inc. In October 1998, JEDI and other shareholders exchanged all of their
common shares of Mariner Holdings, the Company's direct parent, for an
equivalent ownership percentage in common shares of Mariner Energy LLC. Mariner
Energy LLC owns 100% of Mariner Holdings.
22
The following chart represents our current ownership structure and affiliation
with Enron entities.
------------------ ------------------
Enron North ____________________100%__________________ Enron Corp.
America Corp. _____ ------------------
------------------ | |
| | |
| | |
| | |
| | ------------------ |
| |________ JILP-LP, Inc. |
| ------------------ |
| | |
| | (Asset Specific) |
| | |
| ------------------ |
| Ponderosa |
| Assets LP LP
| ------------------ |
| | |
| | (Limited Partnership) |
| | |
------------------ ------------------ |
Enron Capital _____GP______ Enron Capital |
Corp. ________ Management LP |
------------------ | ------------------ |
| | |
| GP |
| | |
------------------ | ------------------ |
Enron Capital _____| Joint Energy |
Management, LLC ____SLP______ Development ___________________|
------------------ Investments (JEDI)
------------------
|
96%
|
------------------ ------------------
Mariner _____4%_____ Employees and
Energy, LLC Former Employees
------------------ ------------------
|
100%
|
------------------
Mariner
Holdings, Inc.
------------------
|
100%
|
------------------
Mariner
Energy, Inc.
------------------
Subsequent to the Acquisition, Mariner Energy LLC, Mariner Holdings and
Mariner have each entered into various financing and operating transactions with
affiliates. In addition the Company may have from time to time engaged in
various commercial transactions and have various commercial relationships with
Enron and certain affiliates of Enron, such as holding and exploring, exploiting
and developing joint working interests in particular prospects and properties
and entering into other oil and gas related or financial transactions. Certain
of the Company's third-party debt instruments and arrangements 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 and its affiliates are, and anticipates that
any future agreements with Enron and its affiliates will be, on terms no less
favorable to the Company than would be obtained in an agreement with a third
party. Below is a summary of key transactions between the Company and affiliate
entities.
23
MARINER ENERGY LLC
ENA Affiliate Term Loan - In March 2000, Mariner Energy LLC established
an unsecured term loan with ENA to repay amounts outstanding under various
affiliate credit facilities at Mariner Energy LLC and Mariner and to provide
additional working capital. The additional working capital of $55 million was
contributed to Mariner in 2000. The loan bears interest at 15%, which interest
accrues and is added to the loan principal. Repayment of the balance of loan
principal and accrued interest, which was approximately $164.4 million as of
December 31, 2002, is due March 20, 2004. In conjunction with the loan
agreement, two five-year warrants were issued to ENA providing the right to
purchase up to 900,000 of common shares of Mariner Energy LLC for $0.01 per
share.
Covenants in Mariner's Senior Subordinated Notes restrict the funds of
Mariner that can be distributed to Mariner Energy LLC. Accordingly, Mariner
Energy LLC is restricted in its ability to repay the unsecured Term Loan or to
distribute earnings to its shareholders. In the event Mariner Energy LLC is
unable to restructure or extend the maturity of its obligations prior to March
2004 it would either default under the Term Loan or be forced to sell its
interest in Mariner or cause Mariner to sell a substantial portion of its assets
to repay any outstanding Senior Subordinated Notes so that it could distribute
any remaining cash proceeds to Mariner Energy LLC to be used to repay the Term
Loan.
We have been informed by Enron's legal advisors and management that the
Term Loan and warrants were transferred from ENA to an ENA affiliate, which
affiliate is part of a finance structure formed by ENA. Because debt obligations
of the finance structure are in default and ENA therefore does not have complete
control over decisions made by the ENA affiliate, it may be difficult for
Mariner Energy LLC to obtain any consents, waivers or amendments needed from the
ENA affiliate in connection with the Term Loan or the warrants.
MARINER HOLDINGS, INC.
1998 Equity Investment - In June 1998, Mariner Holdings issued
additional equity to its existing shareholders, including JEDI, for
approximately $14.58 per share, for a net investment of $28.8 million, all of
which was contributed to Mariner. Mariner Holdings 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 Limited Partnership.
MARINER ENERGY, INC.
Oil and Gas Production Sales to ENA or Affiliates - During the three
years ending December 31, 2002, 2001 and 2000, sales of oil and gas production
to ENA or affiliates were $56.4million, $50.2 million and $73.4 million,
respectively. These sales were generally made on 1 to 3 month contracts. At the
time ENA filed its petition for bankruptcy protection, the Company immediately
ceased selling its physical production to ENA, however, we continued to sell our
production to Bridgeline which ENA owned a minority interest. All amounts sold
to this party have been collected. As of December 31, 2002, we had an
outstanding receivable for $3 million from ENA. This amount was not paid as
scheduled and is still outstanding. Mariner has submitted a proof of claim to
the bankruptcy court for amounts owed to it by ENA. The Company has estimated
100% of this balance is uncollectible and has recorded a full allowance and
related expense.
24
Management Activities - We engage in price risk management activities
from time to time. These activities are intended to manage our exposure to
fluctuations in commodity prices for natural gas and crude oil. We primarily
utilize price swaps and costless collars as a means to manage such risk.
Historically, all of our hedging contracts were with ENA. As a result of ENA's
bankruptcy, the contracts are currently in default. The November 2001 through
April 30, 2002 settlements for oil and gas have not been collected. In addition,
on May 14, 2002, we elected under our Master Service Agreement with ENA to
terminate all open contracts. The effect of this termination is to fix the
nominal value on all remaining contracts on May 14, 2002. Subsequent to this
termination, the value of all oil and natural gas unpaid hedge contracts was
$7.7 million. We have estimated 100% of this balance is uncollectible and has
recorded a full allowance. We have submitted a proof of claims to the bankruptcy
court for amounts owed under this agreement. In accordance with Statement of
Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 137 and No. 138, we
have de-designated our contracts effective December 2, 2001 and are recognizing
all market value changes subsequent to such de-designation in our earnings. The
value recorded up to the time of de-designation and included in Accumulated
Other Comprehensive Income ("AOCI"), will reverse out of AOCI and into earnings
as the original corresponding production, as hedged by the contracts, is
produced. For the year ending December 31, 2002 approximately $23.2 million has
reversed out to earnings. As of December 31, 2002, $2.6 million remained in AOCI
to be reversed out to earnings.
The following table sets forth the results of hedging transactions
during the periods indicated that were made with ENA (all amounts shown are
non-cash items):
YEAR ENDING DECEMBER 31,
--------------------------------------------
2002 2001 2000
------- ------- --------
Natural gas quantity hedged (Mmbtu).......................... 18,090 17,733 19,569
Increase (decrease) in natural gas sales (thousands)......... $20,413 $(5,523) ($21,364)
Crude oil quantity hedged (MBbls)............................ 446 752 1,059
Increase (decrease) in crude oil sales (thousands)........... $ 2,787 $ 2,393 ($14,053)
25
Supplemental Affiliate Data - provided below is a supplemental balance sheet and
income statement for affiliate entities:
DECEMBER 31, 2002 DECEMBER 31, 2001
----------------------- ------------------------
AMOUNTS AMOUNTS
BALANCE SHEET DATA (IN MILLIONS) (IN MILLIONS)
------------------
TOTAL TOTAL
--------------------------------------------------------
RELATED PARTY RECEIVABLE:
Derivative Asset $ - $ 2.5 $ -
Settled Hedge Receivable - 0.4 -
Oil and Gas Receivable 8.2 8.2 0.3 3.2
ACCRUED LIABILITIES:
Transportation Contract - - 0.9 -
Service Agreement 0.6 1.5 0.3 1.2
STOCKHOLDER'S EQUITY:
Common Stock $ .001 - $ .001 -
Additional Paid in Capital $ 227.3 $227.3
Accumulated other Comprehensive Income $ 2.3 $229.6 $ 25.8 $253.1
YEAR ENDED
DECEMBER 31
--------------------------------------
INCOME STATEMENT DATA
2002 2001
------ ------
Oil and Gas Sales $ 56.4 $ 50.2
General and Administrative Expenses 0.4 0.2
Transportation Expenses 2.7 4.2
Unrealized loss and other non-cash derivative 3.2 29.5
instrument adjustments
As a result of the Enron and ENA bankruptcies, among other
implications, we may not be able to obtain credit from banks or trade vendors or
enter into hedging arrangements on acceptable terms. To date, our operations
have not been materially affected by the bankruptcies; however, our ability to
enter into certain transactions including purchase or sale arrangements and to
conduct significant capital programs may be affected in the future. Oil and gas
sales and the related accounts receivable for the year ending December 31, 2002
relate to sales made to a minority owed affiliate of Enron.
CONTROLLED GROUP LIABILITY
On November 12, 2002, Enron's legal advisors and management informed
us that we may be an Enron Corp. Controlled Group Member as defined under the
Employee Retirement Income Security Act of 1974 ("ERISA") due to Enron's
indirect ownership interest in Mariner Energy LLC. Enron management has not made
a final determination if we are in fact a Controlled Group Member. Because of
numerous ownership issues within the Enron Group, we are unable to make our own
determination as to whether we agree or disagree that we are a Controlled Group
Member. In the event we are a Controlled Group Member, we may have potential
liability for certain employee benefit plan obligations of Enron discussed
below.
26
Pension Plans - Applicable federal law authorizes the Pension Benefit
Guaranty Corporation ("PBGC") to institute proceedings in federal district court
for the termination of a pension plan if it determines the plan has failed to
comply with minimum funding standards, the plan is or will be unable to pay
benefits when due, or the failure to terminate the plan may reasonably be
expected to unreasonably increase the possible long-run loss to the PBGC.
Federal law also authorizes the sponsor of a pension plan to terminate the plan
at a time when the plan is underfunded, subject to PBGC or court approval.
Based on discussions with Enron management, it is our management's
understanding that, as of December 31, 2002 the assets of Enron's pension plan
(the "Enron Plan") were less than the present value of all accrued benefits by
approximately $52 million on a SFAS No. 87 basis and approximately $182 million
on a plan termination basis. Further, Enron's management has informed Mariner
management that the PBGC has filed claims in the Enron bankruptcy cases. The
claims are duplicative in nature, representing unliquidated claims for PBGC
insurance premiums (the "Premium Claims") and unliquidated claims for due but
unpaid minimum funding contributions (the "Contribution Claims") under the
Internal Revenue Code of 1986, as amended (the "Tax Code") 29 U.S.C. Sections
412(a) and 1082 and claims for unfunded benefit liabilities (the "UBL" Claims").
Enron and the relevant sponsors of the defined benefit plans are current on
their PBGC premiums and their contributions to the pension plans. Therefore,
Enron has valued the Premium Claims and the Contribution Claims at $0. The total
amount of the UBL Claims is $305.5 million (including $271 million for the Enron
Plan). In addition Enron Management has informed Mariner Management that the
PBGC has informally alleged in pleadings filed with the bankruptcy court that
the UBL Claim related to the Enron Plan could increase by as much as 100%. PBGC
has provided no support (statutory or otherwise) for this assertion and Enron
Management disputes the validity of any such claim. Because the Enron Plan is
under funded and Enron is in bankruptcy, in certain circumstances the Enron Plan
may be terminated and taken control of by the PBGC upon approval of a Federal
District Court.
Mariner's employees have not been participants in the Enron Plan.
However, upon termination of a pension plan, all of the members of the
controlled group of the plan sponsor become jointly and severally liable for the
plan are under funding. The PBGC can demand payment from one or more of the
members of the controlled group. If payment is not made, a lien in favor of the
PBGC automatically arises against all of the assets of that member of the
controlled group. The amount of the lien is equal to the lesser of the
underfunding or 30% of the aggregate net worth of all of the controlled group
members. In addition, if the sponsor of a pension plan does not timely satisfy
its minimum funding obligation to the pension plan, once the aggregate missed
amounts exceed $1 million, a lien in favor of the plan in the amount of the
missed funding automatically arises against the assets of every member of the
controlled group. In either case, the PBGC may file to perfect the lien and
attempt to enforce it against the assets of members of the Enron Controlled
Group. Mariner has been informed by Enron that Enron's management believes that
the lien would be subordinate to prior perfected liens on the assets of the
member of the Controlled Group. Based on discussions with Enron's management,
Mariner's management understands that Enron has made all required contributions
to date through October 15, 2002. Enron's management has advised us that it
intends to make its next contribution, due in the first quarter of 2003.
Management cannot predict the outcome of the above matters or estimate
any potential loss. In addition, if the PBGC did look solely to Mariner to pay
any amount with respect to the Enron Plan, Mariner would exercise all legal
rights, available to it to defend against such a demand and to recover any
contributions from the other solvent members of the Controlled Group. No
reserves have been established by Mariner for any amounts related to this issue.
Mariner has also been informed by Enron management that Enron has
contacted the PBGC as well as Unsecured Creditors Committee regarding their
intention to terminate the Enron Plan, subject to approval by such parties, the
bankruptcy court and authorization to fully fund the Enron Plan in accordance
with its terms. If approved Enron would fully fund the Enron Plan in accordance
with the terms, the plan could be terminated without any liability to Mariner.
Enron has also stated that it believes it has the necessary funds to consummate
such a termination. In addition to the extent that entities in the Controlled
Group are sold prior to termination of the Plan, proceeds of the sale of such
entities may be available to satisfy this liability. Enron estimates proceeds
from such sale of Enron Control Group entities would far exceed any plan
obligations.
27
Retiree Health Benefits - Under COBRA, if certain retirees of Enron
lose coverage under Enron's group health plan due to Enron's bankruptcy
proceedings, they would be entitled to elect continuation of their health
coverage in a group plan maintained by Enron or a member of its Controlled
Group. Mariner's employees have not participated in this plan. Mariner
management understands, based on discussions with Enron management, that Enron
had provided a plan for retiree health insurance and that the actuarial
liability for such coverage was approximately $70 million as of December 31,
2001. Management further understands that to meet its obligation, Enron, at
December 31, 2001, had set aside approximately $34 million of assets in a VEBA
trust, which may be protected under ERISA from Enron's creditors, leaving an
unfunded liability of approximately $36 million.
In the event that Enron terminates its retiree group health plan, the
retirees must be provided the opportunity to purchase continuing coverage from
Enron's group health plan, if any, or the most appropriate existing group health
plan of another member of the Enron Controlled Group. Retirees electing to
purchase COBRA coverage would be provided the same coverage that is provided to
similarly situated retirees under the appropriate existing plan. Retirees
electing to purchase COBRA coverage would be required to pay for the coverage,
up to an amount not to exceed 102% of the cost of coverage for similarly
situated beneficiaries. Retirees are not required to purchase coverage under
COBRA. Retirees may, instead, shop for coverage from third party sources and
determine which is the least expensive coverage.
Management cannot predict the outcome of the above matter or estimate
any potential loss. However, management believes that in the event Enron
terminates coverage, any liability to Mariner associated with the number of
retirees that choose to remain under Enron's retiree health plan will not be
material. No reserves have been established by Mariner for any amounts related
to this issue.
SALE OF ENRON INTEREST IN MARINER
On May 3, 2002, Enron presented to its Unsecured Creditors' Committee a
proposal under which certain of Enron's core energy assets, including JEDI's
ownership of Mariner Energy LLC, would be separated from Enron's bankruptcy
estate and operated prospectively as a new integrated power and pipeline
company.
On August 27, 2002, Enron announced that it had commenced a formal
sales process for its interests in certain major assets, including JEDI's
ownership of Mariner Energy LLC. In its announcement, Enron indicated that it
was extending invitations to visit electronic data rooms containing information
on 12 of its most valuable businesses, including Mariner, to a broad universe of
potential bidders with whom Enron had executed confidentiality agreements.
Enron has announced its intent to move forward with the sale
of four companies, however, it continues to evaluate its alternatives with
regard to Mariner. Management is unable to give assurances that the Company will
be or not be sold in the near future and there can be no assurance as to whether
JEDI's ownership of Mariner Energy LLC will be sold in the future.
(e) RISK FACTORS
EXPLORATION RISKS - In addition to the other information set forth
elsewhere in this annual report, including the potential impact of the Enron
bankruptcy matters, the following factors should be carefully considered when
evaluating us. Exploration is a high-risk activity, and the 3-D seismic data and
other advanced technologies we use cannot eliminate exploration risk. In
addition, use of these technologies requires experienced technical personnel who
we may be unable to attract or retain.
Our future success will depend on the success of our exploratory
drilling program. Exploration activities involve numerous risks, including the
risk that no commercially productive natural gas or oil reservoirs will be
discovered. In addition, we are often uncertain as to the future cost or timing
of drilling, completing and producing wells. Furthermore, drilling operations
may be curtailed, delayed or canceled as a result of the additional exploration
time and expense associated with a variety of factors, including unexpected
drilling conditions, pressure or irregularities in formations, equipment
failures or accidents, adverse weather conditions, compliance with governmental
requirements and shortages or delays in the availability of drilling rigs or
equipment.
28
Even when used and properly interpreted, 3-D seismic data and
visualization techniques only assist geoscientists and geologists in identifying
subsurface structures and hydrocarbon indicators. They do not allow the
interpreter to know conclusively if hydrocarbons are present or economically
producible. We could incur losses as a result of exploratory drilling
expenditures. Poor results from exploration activities could affect future cash
flows and results of operations materially and adversely.
Our exploratory drilling success will depend, in part, on our ability
to attract and retain experienced explorationists and other professional
personnel. Competition for explorationists and engineers with experience in the
Gulf of Mexico is intense. If we cannot retain our current personnel or attract
additional experienced personnel, our ability to compete in the Gulf of Mexico
could be adversely affected.
Exploration for natural gas and oil at deeper drilling depths and in
the deep waters of the Gulf of Mexico involves greater operational and financial
risks than exploration at shallower depths and in shallower waters. These risks
could result in substantial losses.
PROSPECT DEVELOPMENT RISKS - Our 2001 discoveries on South Timbalier
("Roaring Fork") and Viosca Knoll 917 ("Swordfish") have required and over the
next year will continue to require significant financial resources. We do not
expect production from these discoveries to commence prior to October 2003 and
April 2004, respectively, but we must commit substantial resources in advance of
the expected production date and cannot predict the price of oil if and when
production commences.
OPERATING RISKS - The natural gas and oil business involves a variety
of operating risks, including fires, explosions, blow-outs and surface
cratering, uncontrollable flows of underground natural gas, oil and formation
water, natural disasters, pipe or cement failures, casing collapses, embedded
oilfield drilling and service tools, abnormally pressured formations and
environmental hazards such as natural gas leaks, oil spills, pipeline ruptures
and discharges of toxic gases. If any of these events occur, we could incur
substantial losses as a result of injury or loss of life, severe damage to and
destruction of property, natural resources and equipment, pollution and other
environmental damage, clean-up responsibilities, regulatory investigation and
penalties, suspension of our operations and repairs to resume operations. If we
experience any of these problems, well bores, platforms, gathering systems and
processing facilities could be adversely affected, which in turn could adversely
affect our ability to conduct operations.
Offshore operations are also subject to a variety of operating risks
specific to the marine environment, such as capsizing, collisions and damage or
loss from hurricanes or other adverse weather conditions. These conditions can
cause substantial damage to facilities and interrupt production. As a result, we
could incur substantial liabilities that could reduce or eliminate the funds
available for exploration, development or leasehold acquisitions, or result in
loss of equipment and properties.
Production of reserves from reservoirs in the Gulf of Mexico 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 of Mexico during the initial few years of
production. As a result, reserve replacement needs from new prospects are
greater and require us to incur significant capital expenditures to replace
production.
FINANCIAL POSITION RISKS - For some risks, we may not obtain insurance
if we believe the cost of available insurance is excessive relative to the risks
presented. In addition, pollution and environmental risks generally are not
fully insurable. If a significant accident or other event occurs and is not
fully covered by insurance, it could adversely affect our operations.
As part of our strategy, we explore for natural gas and oil at deeper
drilling depths and in the deep waters of the Gulf of Mexico, where operations
are more difficult and costly than at shallower depths. Deep depth and deep
water drilling and operations require the application of recently developed
technologies that involve a higher risk of mechanical failure. We have
experienced and will continue to experience significantly higher drilling costs
for our deepwater prospects. Furthermore, the deep waters of the Gulf of Mexico
lack the physical and oilfield service infrastructure present in the shallower
waters. As a result, a significant amount of time may elapse
29
between a deep water discovery and our marketing of the associated natural gas
or oil, increasing both the financial and operational risk involved with these
operations.
Our revenues, profitability and future growth depend substantially on
prevailing prices for natural gas and oil. Prices also affect the amount of cash
flow available for capital expenditures and our ability to borrow and raise
additional capital.
Conversely, 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 natural
gas and oil.
Prices for natural gas and oil fluctuate widely. For example, natural
gas prices declined significantly in 2002. Prices for natural gas and oil also
declined significantly in 1998 and, for an extended period of time, remained
substantially below prices obtained in previous years. Among the factors that
can cause this fluctuation are the level of consumer product demand, weather
conditions, domestic and foreign governmental regulations, the price and
availability of alternative fuels, political conditions in natural gas and oil
producing regions, the domestic and foreign supply of natural gas and oil, the
price of foreign imports and overall economic conditions. If natural gas and oil
prices decline, even if for only a short period of time, it is possible that
write-downs of natural gas and oil properties could occur. While we attempt to
partially minimize this risk through our hedging arrangements, hedging
production has limited and may continue to limit potential gains from increases
in commodity prices or result in losses.
We enter into hedging arrangements from time to time to reduce our
exposure to fluctuations in natural gas and oil prices and to achieve more
predictable cash flow. These financial arrangements take the form of swap
contracts or costless collars. The Company had in place both financial hedge and
physical contracts with ENA at the time ENA filed for bankruptcy in December
2001. We did not receive payment as required under these contracts. We cannot
provide assurance that other trading counterparties will not become credit risks
in the future. Hedging arrangements expose us to risks in some circumstances,
including situations when the other party to the hedging contract defaults on
its contract obligations or there is a change in the expected differential
between the underlying price in the hedging agreement and actual prices
received. These hedging arrangements have limited and may continue to limit the
benefit we could receive from increases in the prices for natural gas and oil.
We cannot provide assurance that our hedging transactions will adequately
protect us from fluctuations in natural gas and oil prices. We may choose not to
engage in hedging transactions in the future. As a result, we may be adversely
affected during periods of declining natural gas and oil prices.
We have experienced and expect to continue to experience substantial
capital expenditure and working capital needs, particularly as a result of our
drilling program. In the future, we expect we will require additional financing,
in addition to cash generated from our operations, to fund our planned growth.
We cannot be certain that additional financing will be available on acceptable
terms or at all. In the event 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 incurred net losses of $10.0 million, $58.4 million, and $20.2
million in 1999, 1998, and 1997, respectively. Our development of and
participation in a larger number of prospects has required and will continue to
require substantial capital expenditures. We cannot provide assurance that it
will sustain profitability or positive cash flows from operating activities in
the future. Our failure to sustain profitability in the future could adversely
affect our company.
CONCENTRATION RISKS - We are subject to risks associated with the Gulf
of Mexico, where substantially all of our exploration activities and production
are located. This concentration of activity makes us more vulnerable than many
of our competitors to the risks associated with the Gulf of Mexico, including
delays and increased costs relating to adverse weather conditions, drilling rig
and other oilfield services and compliance with environmental and other laws and
regulations.
A significant part of the value of our production and reserves is
concentrated in a small number of offshore properties. Because of this
concentration, any production problems or inaccuracies in reserve estimates
30
related to those properties are more likely to adversely impact our business.
During 2002, over 62 percent of our production came from four properties in the
Gulf of Mexico. If mechanical problems, storms or other events curtailed a
substantial portion of this production, our cash flow would be adversely
affected. In addition, at December 31, 2002 approximately 88 percent of the
proved reserves was attributable to 7 properties. If the actual reserves
associated with any one of these 7 properties are substantially less than the
estimated reserves, our results of operations and financial condition could be
adversely affected.
INDUSTRY RISKS - Our industry is subject to rapid and significant
advancements in technology, including the introduction of new products and
services using new technologies. As competitors use or develop new technologies,
we may be placed at a competitive disadvantage, and competitive pressures may
force us to implement new technologies at a substantial cost. In addition,
competitors may have greater financial, technical and personnel resources that
allow them to enjoy technological advantages and may in the future allow them to
implement new technologies before we can. We cannot be certain that we will be
able to implement technologies on a timely basis or at a cost that is acceptable
to us. One or more of the technologies that we currently use or that we may
implement in the future may become obsolete, and we may be adversely affected.
For example, marine seismic acquisition technology has been characterized by
rapid technological advancements in recent years and further significant
technological developments could substantially impair the 3-D seismic data's
value.
We compete with major and independent natural gas and oil companies for
property acquisitions. We also compete for the equipment and labor required to
operate and develop properties. Most of our competitors have substantially
greater financial and other resources than we do. As a result, in the deep water
where exploration is more expensive, competitors may be better able to withstand
sustained periods of unsuccessful drilling. In addition, larger competitors may
be able to absorb the burden of any changes in federal, state and local laws and
regulations more easily than we can, which would adversely affect our
competitive position. These competitors may be able to pay more for exploratory
prospects and productive natural gas and oil properties and may be able to
define, evaluate, bid for and purchase a greater number of properties and
prospects than we can. Our ability to explore for natural gas and oil prospects
and to acquire additional properties in the future will depend on our ability to
conduct operations, to evaluate and select suitable properties and to consummate
transactions in this highly competitive environment. In addition, most of our
competitors have been operating in the Gulf of Mexico for a much longer time
than we have and have demonstrated the ability to operate through industry
cycles.
Other companies operate some of the properties in which we have an
interest. As a result, we have a limited ability to exercise influence over
operations for these properties or their associated costs. Our dependence on the
operator and other working interest owners for these projects and our limited
ability to influence operations and associated costs could materially adversely
affect the realization of our targeted returns on capital in drilling or
acquisition activities. The success and timing of drilling and development
activities on properties operated by others therefore depend upon a number of
factors that are outside of our control, including timing and amount of capital
expenditures, the operator's expertise and financial resources, approval of
other participants in drilling wells and selection of technology.
RESERVE RISKS - The process of estimating natural gas and oil reserves
is complex. It requires interpretations of available technical data and various
assumptions, including assumptions relating to economic factors. Any significant
inaccuracies in these interpretations or assumptions could materially affect the
estimated quantities and net present value of reserves.
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, and the extent,
quality and reliability of this data can vary. The process also requires
economic assumptions such as natural gas and oil prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. Therefore,
estimates of natural gas and oil reserves are inherently imprecise.
Actual future production, natural gas and oil prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable
natural gas and oil reserves most likely will vary from our estimates. Any
significant variance could materially affect the estimated quantities and net
present value of reserves. In addition, we may adjust estimates of proved
reserves to reflect production history, results of
31
exploration and development, prevailing natural gas and oil prices and other
factors, many of which are beyond our control. At December 31, 2002,
approximately 67 percent of our proved reserves were either proved undeveloped
or proved non-producing. Moreover, some of the producing wells included in our
reserve report had produced for a relatively short period of time as of December
31, 2002. Because most of the reserve estimates are not based on a lengthy
production history and are calculated using volumetric analysis, these estimates
are less reliable than estimates based on a lengthy production history.
It should not be assumed that the present value of future net cash
flows from our proved reserves is the current market value of its estimated
natural gas and oil reserves. In accordance with Securities and Exchange
Commission requirements, we 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 net present
value estimate.
Our future natural gas and oil production depends on our success in
finding or acquiring additional reserves. If we fail to replace reserves, our
level of production and cash flows could be adversely impacted. In general,
production from natural gas and oil properties declines as reserves are
depleted, with the rate of decline depending on reservoir characteristics. Our
total proved reserves decline as reserves are produced unless we conduct other
successful exploration and development activities or acquire properties
containing proved reserves, or both. Our ability to make the necessary capital
investment to maintain or expand our asset base of natural gas and oil reserves
would be impaired to the extent cash flow from operations is reduced and
external sources of capital become limited or unavailable. We may not be
successful in exploring for, developing or acquiring additional reserves. If we
are not successful, our future production and revenues will be adversely
affected.
REGULATION RISKS - We are subject to complex laws and regulations,
including environmental regulations which can adversely affect the cost, manner
or feasibility of doing business.
Exploration for and development, production and sale of natural gas and
oil in the U.S. and especially in the Gulf of Mexico are subject to extensive
federal, state and local laws and regulations, including environmental laws and
regulations. We may be required to make large expenditures to comply with
environmental and other governmental regulations. Matters subject to regulation
include discharge permits for drilling operations, drilling bonds, reports
concerning operations and taxation.
Under these laws and regulations, we could be liable for personal
injuries, property damage, oil spills, discharge of hazardous materials,
remediation and clean-up costs and other environmental damages. We do not
believe that full insurance coverage for all potential environmental damages is
available at a reasonable cost. Failure to comply with these laws and
regulations also may result in the suspension or termination of our operations
and subject us to administrative, civil and criminal penalties. Moreover, these
laws and regulations could change in ways that substantially increase costs. For
example, Congress or the MMS could decide to limit exploratory drilling or
natural gas production in additional areas of the Gulf of Mexico. Accordingly,
any of these liabilities, penalties, suspensions, terminations or regulatory
changes could materially and adversely affect our financial condition and
results of operations.
(f) CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion and analysis of Mariner's financial condition and
results of operation are based upon financial statements that have been prepared
in accordance with accounting principles generally accepted in the United States
of America. The preparation of these financial statements requires us to make
estimates and judgments that affect the reported amounts of assets, liabilities,
revenues and expenses. Our significant accounting policies are described in Note
1 to our financial statements. In response to SEC Release No. 33-8040,
"Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we
have identified certain of these policies as being of particular importance to
the portrayal of our financial position and results of operations and which
require the application of significant judgment by our management. We analyze
our estimates, including those related to oil and gas revenues, oil and gas
properties, fair value of derivative instruments, income taxes and contingencies
and litigation, and base our estimates on historical experience and various
other assumptions that we believe to be reasonable under the circumstances.
Actual results may differ from these estimates under
32
different assumptions or conditions. We believe the following critical
accounting policies affect our more significant judgments and estimates used in
the preparation of our financial statements:
OIL AND GAS PROPERTIES - Oil and gas properties are accounted for using
the full-cost method of accounting. All direct costs and certain indirect costs
associated with the acquisition, exploration and development of oil and gas
properties are capitalized. 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.
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.
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 $1,022,000, $2,836,000, and $3,885,000 for the years
ended December 31, 2002, 2001 and 2000, 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 costs which may be incurred
in the removal and abandonment of production facilities at the end of the
producing life of each property. On January 1, 2003, the Company adopted
Statement of Financial Accounting Standards No. 143 "Accounting for Asset
Retirement Obligations" (See Recent Accounting Pronouncements).
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,
recorded at market value are deferred, and recorded in Accumulated Other
Comprehensive Income ("AOCI") as appropriate, until recognized as operating
income in the Company's Statement of Operations as the physical production
hedged by the contracts is delivered.
The net cash flows related to any recognized gains or losses associated
with these hedges are reported as oil and gas revenues and presented in 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 hedged by the contracts is delivered.
The conditions to be met for a derivative instrument to qualify as a
cash 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.
33
FINANCIAL INSTRUMENTS - The Company's financial instruments consist of
cash and cash equivalents, receivables, payables, and debt. At December 31,
2002, 2001 and 2000, the estimated fair value of the Company's $100,000,000
Senior Subordinated Notes was approximately $99,000,000 and $95,000,000,
respectively. The estimated fair value was determined based on borrowing rates
available at December 31, 2001 and 2000, respectively, for debt with similar
terms and maturities. The carrying amount of the Company's other instruments
noted above approximate fair value.
MAJOR CUSTOMERS - During the year ended December 31, 2002, sales of oil
and gas to three purchasers, including Enron affiliate, Bridgeline, accounted
for 42%, 14% and 9% of total revenues. During the year ended December 31, 2001,
sales of oil and gas to three purchasers, including an Enron affiliate,
accounted for 32%, 24% and 14% of total revenues. During the year ended December
31, 2000, sales of oil and gas to two purchasers, including an affiliate,
accounted for 49% and 16% of total revenues. Management believes that the loss
of any of these purchasers would not have a material impact on the Company's
financial condition or results of operations.
(g) RESULTS OF OPERATIONS
The following table repeats certain operating information found in Item
2 of this report with respect to oil and natural gas production, average sales
price received and expenses per unit of production during the periods indicated.
YEAR ENDING DECEMBER 31,
----------------------------------
2002 2001 2000
------ ------ ------
PRODUCTION:
Oil (MMbbls).............................................. 1.7 3.0 1.8
Natural gas (Bcf)......................................... 29.6 18.8 25.7
Gas equivalent (Bcfe)..................................... 39.8 36.7 36.3
AVERAGE REALIZED SALES PRICE
(EXCLUDING THE EFFECTS OF HEDGING):
Oil ($/Bbl)............................................... $21.60 $22.41 $29.53
Natural gas ($/Mcf)....................................... 3.35 4.86 4.07
Gas equivalent ($/Mcfe)................................... 3.41 4.31 4.32
AVERAGE REALIZED SALES PRICE
(INCLUDING THE EFFECTS OF HEDGING):
Oil ($/Bbl)............................................... $22.85 $23.22 $21.54
Natural gas ($/Mcf)....................................... 4.03 4.57 3.24
Gas equivalent ($/Mcfe)................................... 3.97 4.22 3.34
EXPENSES ($/MCFE):
Lease operating........................................... $ 0.65 $ 0.55 $ 0.47
Transportation............................................ 0.26 0.33 0.22
General and administrative, net........................... 0.19 0.25 0.18
Depreciation, depletion and
amortization (excluding impairments).................... 1.78 1.73 1.57
34
(i) 2002 COMPARED TO 2001
NET PRODUCTION increased during 2002 to 39.8 billion cubic feet of
natural gas equivalent (Bcfe) from 36.7 Bcfe in 2001, an 8% improvement.
Production from our King Kong and Yosemite projects more than offset production
declines in our other fields, primarily the Pluto and Black Widow fields,
located offshore.
HEDGING ACTIVITIES in 2002 increased our average realized natural gas
price received by $0.68 per Mcf and revenues by $20.3 million, compared with a
decrease of $0.29 per Mcf and revenues of $5.5 million in 2001. Our hedging
activities with respect to crude oil during 2002 increased the average sales
price received by $1.25 per Bbl and revenues by $2.1 million compared with an
increase of $0.81 per Bbl and revenues of $2.4 million in 2001. Approximately
$23.2 million of these hedge revenues were related to our ENA hedges and were
not collected.
OIL AND GAS REVENUES increased 2% to $158.2 million for 2002 from
$155.0 million for 2001, due to an 8% increase in Mcfe production offset by a 6%
decrease in realized prices to $4.03 per Mcfe in 2002 from $4.22 per Mcfe in
2001.
LEASE OPERATING EXPENSES increased 30% to $26.1 million for 2002 from
$20.1 million for 2001 due to the higher production costs associated with our
King Kong and Yosemite projects.
TRANSPORTATION EXPENSES decreased 13% to $10.5 million for 2002 from
$12.0 million for 2001. The decrease was attributable to lower production from
our Pluto and Black Widow projects.
DEPRECIATION, DEPLETION, AND AMORTIZATION EXPENSE increased 11% to
$70.8 million for 2002 from $63.5 million for 2001 as a result of the increase
in the unit-of-production depreciation, depletion and amortization rate to $1.78
per Mcfe from $1.73 per Mcfe.
IMPAIRMENT OF ENRON RELATED RECEIVABLES of $3.2 million was recorded as
a result of increasing our allowance from 90% to 100% of Enron receivables. In
2001 we recorded a $29.5 million allowance related to Enron receivables.
GENERAL AND ADMINISTRATIVE EXPENSES, which are net of overhead
reimbursements received from other working interest owners, decreased 17% to
$7.7 million for 2002 from $9.3 million for 2001 due lower personnel costs as a
result of 2001 employee terminations.
NET INTEREST EXPENSE for 2002 increased 26% to $9.9 million from $8.2
million for 2001, primarily due to a reduction in capitalized interest.
INCOME (LOSS) BEFORE INCOME TAXES increased to a net income of $30.0
million for 2002 from $12.4 million in 2001, primarily a result of a $26.3
decrease in Enron related receivable allowance offset in part by increased
expenses noted above.
(ii) 2001 COMPARED TO 2000
NET PRODUCTION increased during 2001 to 36.7 billion cubic feet of
natural gas equivalent (Bcfe) from 36.3 Bcfe in 2000, a 1% improvement.
Production from a full year of our Black Widow project more than offset
production declines in our other fields, primarily the Sandy Lake field, located
onshore, and the Dulcimer and Apia fields, located offshore.
HEDGING ACTIVITIES in 2001 (before de-designation due to the impact of
the ENA bankruptcy) decreased our average realized natural gas price received by
$0.29 per Mcf and revenues by $5.5 million, compared with a decrease of $0.83
per Mcf and revenues of $21.4 million in 2000. Our hedging activities with
respect to crude oil during 2001 increased the average sales price received by
$0.81 per Bbl and revenues by $2.4 million compared with a decrease of $7.99 per
Bbl and revenues of $14.3 million.
35
OIL AND GAS REVENUES increased 28% to $155.0 million for 2001 from
$121.1 million for 2000, due to a 26% increase in realized prices to $4.22 per
Mcfe in 2001 from $3.34 per Mcfe in 2000.
LEASE OPERATING EXPENSES increased 17% to $20.1 million for 2001 from
$17.2 million for 2000 due to the higher production costs associated with our
Black Widow project.
TRANSPORTATION EXPENSES increased 54% to $12.0 million for 2001 from
$7.8 million for 2000. The increase was attributable to a full year's
transportation expenses on Black Widow as well as mandatory minimum
transportation charges on our Pluto project.
DEPRECIATION, DEPLETION, AND AMORTIZATION EXPENSE increased 12% to
$63.5 million for 2001 from $56.8 million for 2000 as a result of the increase
in the unit-of-production depreciation, depletion and amortization rate to $1.73
per Mcfe from $1.57 per Mcfe.
IMPAIRMENT OF ENRON RELATED RECEIVABLES of $29.5 million was taken as a
result of ENA filing a petition for bankruptcy protection (also see "Enron").
The allowance represents a 90% allowance on $7.0 million of settled physical and
hedge contracts through December 31, 2001 and a 90% allowance on $25.3 million
of hedge contracts marked to market value.
(h) LIQUIDITY AND CAPITAL RESOURCES
(i) CASH FLOWS AND LIQUIDITY
As of December 31, 2002, we had working capital deficit of
approximately $9.2 million, of which $15.2 million was restricted, compared to a
working capital deficit of $19.6 million at December 31, 2001. The improvement
in the working capital was primarily a result of the sale, during 2002 of half
of the Company's 50% working interest in its Falcon Project for approximately
$52.3 million including reimbursements, with a portion of the proceeds being
used to repay the Revolving Credit Facility. We expect our 2003 capital
expenditures, excluding capitalized indirect costs and proceeds from property
conveyances (see "Note 2. Oil & Gas Properties"), to be approximately $103.0
million, which approximates anticipated cash flow from operations. However, we
believe that cash on hand together with expected cash flow and proceeds from our
recent property conveyances (See Recent Events) will permit us to fund our
planned activities in 2003. There can be no assurance that our access to capital
will be sufficient to meet our needs for capital. Accordingly, we may be
required to reduce our planned capital expenditures and forego planned
exploratory drilling.
The Company's Revolving Credit Facility matured in October 2002, at
which time there were no amounts outstanding. We are in discussions with other
third party banks to provide a new revolving credit facility. There is no
assurance that a new credit facility will be obtained. In addition, our parent,
Mariner Energy LLC, is currently obligated under an unsecured term loan with an
ENA affiliate. Mariner Energy LLC negotiated an extension of the ENA Affiliate
Term Loan to March 20, 2004. In the event Mariner Energy LLC is unable to
refinance or restructure its obligations prior to March 2004, Mariner Energy LLC
would either default or be forced to sell its interest in the Company, or cause
the Company to sell a substantial portion of its assets to repay its outstanding
Senior Subordinated Notes so that it could distribute cash to Mariner Energy LLC
to be used to repay the term loan. In the event of either a merger or
consolidation of Mariner Energy LLC or the Company resulting in a change of
control or a sale of all or substantially all of the Company's assets, holders
of the Senior Subordinated Notes would have the right to require the Company to
repurchase the Senior Subordinated Notes held by them at a purchase price in
cash equal to 101% of the principal amount thereof plus accrued and unpaid
interest. Any such transaction would also trigger a mandatory prepayment of all
amounts outstanding under the ENA Affiliate Term Loan. The Company's ability to
pay dividends and make other distributions of cash to Mariner Energy LLC are
generally restricted under the indenture governing the Senior Subordinated
Notes. As a result, following any change of control transaction or sale of all
or substantially all of its assets, the Company would most likely be required to
repurchase any Senior Subordinated Notes tendered to it under the indenture and
redeem the balance of the Senior Subordinated Notes outstanding as permitted
under the indenture before it could distribute cash to Mariner Energy LLC to
repay the ENA Affiliate Term Loan.
36
We had a net cash inflow of $6.5 million in 2002, compared to a net
cash inflow of $9.5 million in 2001 and a net cash outflow of $2.3 million in
2000. A discussion of the major components of cash flows for these years
follows.
2002 2001 2000
---- ---- ----
Cash flows provided by operating activities (in millions).... $60.2 $113.6 $63.9
Cash flows provided by operating activities in 2002 decreased by $53.4
million compared to 2001 due to lower oil and gas prices in 2002 and cash
deposits for hedging activities. Cash flows from operating activities in 2001
increased by $49.6 million from 2000 primarily due to increased oil and gas
prices, production lease operating and general and administrative expenses.
2002 2001 2000
---- ---- ----
Cash flows used in investing activities (in millions)........ $53.8 $74.0 $79.1
Cash flows used in investing activities in 2002 decreased by $20.2
million compared to 2001 due to decreased proceeds from property conveyances.
Cash flows used in investing activities in 2001 increased by $5.1 million
compared to 2000 increased capital expenditures offset by $90.5 million in
proceeds from property conveyances
2002 2001 2000
---- ---- ----
Cash flows provided by financing activities (in millions).... $ 0 $(30.0) $17.4
Cash flows provided by financing activities in 2002 increased by $30.0
million compared to 2001. This increase was attributable to repayments of our
Revolving Credit Facility in 2001 using proceeds from property conveyances
mentioned above. Cash flows provided by financing activities in 2001 decreased
by $47.4 million as compared to 2000 due to a $30 million net reduction in
borrowings against our Revolving Credit Facility. In addition, capital
contributions resulting from the sale of stock to Mariner Energy LLC increased
by $31.7 million.
(ii) CHANGES IN PRICES AND HEDGING ACTIVITIES
The energy markets have historically been very volatile, and there can
be no assurance that oil and gas prices will not be subject to wide fluctuations
in the future. In an effort to reduce the effects of the volatility of the price
of oil and natural gas on our operations, management has adopted a policy of
hedging oil and natural gas prices from time to time primarily through the use
of commodity swap and costless collar agreements. While the use of these hedging
arrangements limits the downside risk of adverse price movements, it also limits
future gains from favorable movements. Prior to 2002 all hedge activities
historically have been conducted with Enron. As a result of the Enron bankruptcy
we have de-designated all hedge positions (see "Enron"). In 2002 we implemented
a new hedging program with a third party.
On June 28, 2002 the Company commenced price risk activities with a
third party. These activities are intended to manage the Company's exposure to
fluctuations in commodity prices for natural gas and crude. As of December 31,
2002 the Company had the following fixed price swaps outstanding.
DECEMBER 31, 2002
FAIR VALUE
NOTIONAL FIXED (millions)
TIME PERIOD QUANTITIES PRICE Gain/(Loss)
----------- -------------- ----------- --------------------
CRUDE OIL (MBbl)
January 1 - December 31, 2003
Fixed Price Swap 548 $24.02 $ (1.8)
Fixed Price Swap 183 $24.81 (0.4)
NATURAL GAS (MMbtu)
January 1 - December 31, 2003
Fixed Price Swap 730 $ 3.54 (7.5)
Fixed Price Swap 730 $ 3.60 (7.1)
------
$(16.8)
======
37
The Company has reviewed the financial strength of its counterparts and
believes credit risk to be minimal. As of December 31, 2002 the Company had on
deposit, classified as restricted cash, $22.3 million with the third party for
collateral. This collateral included $5.8 million in initial margin in cash and
$16.5 million in mark-to-market exposure. Initial margin decreases as contracts
settle.
As a result of increasing natural gas prices, in January and February
of 2003, the Company unwound, through the purchase of counter positions, all
natural gas swap contracts for the months of February through October 2003
locking in a loss of $23.2 million. This loss will be settled over the original
contract period.
As a result of these swaps and other hedging transactions the Company
will have approximately 31% of 2003 production subject to hedges. Mark to market
value changes approximately $8.6 million for every 10% overall change in
commodity prices.
The following table sets forth the results of hedging transactions
during the periods indicated that were made with non-Enron related parties.
DECEMBER 31,
2002 2001
----------- -----------
NATURAL GAS
Quantity hedged (Mmbtu) -- --
Increase (Decrease) in Natural Gas Sales (in thousands) -- --
CRUDE OIL
Quantity hedged (MBbls) 169 --
Increase (Decrease) in Crude Oil Sales (in thousands) $(325) --
Our Senior Subordinated Notes bear interest at a fixed rate and,
therefore, do not expose us to risk of earnings loss due to changes in market
interest rates. The market value of the Senior Subordinated Notes was
approximately $100 million based on borrowing rates available at December 31,
2002.
(iii) CAPITAL EXPENDITURES AND CAPITAL RESOURCES
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, 2002.
YEAR ENDING
DECEMBER 31,
----------------------------------
2002 2001 2000
-------- --------- ---------
CAPITAL EXPENDITURES (IN MILLIONS):
LEASEHOLD ACQUISITION $ 14.8 $ 8.8 $ 14.0
OIL AND NATURAL GAS EXPLORATION 25.5 57.5 17.2
OIL AND NATURAL GAS DEVELOPMENT AND OTHER 65.7 98.2 76.9
PROCEEDS FROM PROPERTY CONVEYANCES (52.3) (90.5) (29.0)
------- ------- -------
TOTAL CAPITAL EXPENDITURES, NET OF PROCEEDS FROM
PROPERTY CONVEYANCES $ 53.7 $ 74.0 $ 79.1
======= ======= =======
Our capital expenditures for 2002 decreased $21.1 million as compared
to 2001 as a result of lower proceeds from property conveyances and overall
lower capital expenditures as result of our shift to a more balanced portfolio.
38
Our capital expenditures for 2001 were $74.0 million, including the
$90.5 million of proceeds from property conveyances, which was $5.1 million less
than 2000. The decrease was primarily a result of higher property conveyance
proceeds offset in part by higher leasehold acquisition, geological and
geophysical, and development expenditures.
Our estimated capital expenditure for 2003 is approximately $103
million before capitalized indirect costs and proceeds from property
conveyances. Our budget includes approximately $41 million for exploration
activities, $62 million for development activities and $121.6 million in
proceeds from property conveyances. An active Gulf exploration program is
underway, with funds budgeted to drill 8 to 12 wells. The development budget
includes funds for completion of our Roaring Fork and Vermillion 144 projects
and development costs for our Swordfish projects and other smaller fields.
Our long-term debt outstanding as of December 31, 2002 was
approximately $99.8 million, comprised entirely of Senior Subordinated Notes.
Our Senior Subordinated Notes contain various restrictive covenants
that, among other things, restrict the payment of dividends, limit the amount of
debt we may incur, limit our ability to make certain loans, investments, enter
into transactions with affiliates, sell assets, enter into mergers, limit our
ability to enter into certain hedge transactions and provide that we must
maintain specified relationships between cash flow and fixed charges and cash
flow and interest on indebtedness.
We expect to fund our activities for 2003 through a combination of cash
flow from operations and proceeds from property conveyances. 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.
39
(i) CONTRACTUAL COMMITMENTS
We have numerous contractual commitments in the ordinary course of
business, debt service requirements and operating lease commitments. The
following table summarizes these commitments at December 31, 2002 (in
millions):
BEYOND
2003 2004 2005 2006 2006
-------- ------- -------- ------- -------
DEBT AND OTHER OBLIGATIONS...................... $ -- $ -- $ -- $ 100 $ --
OPERATING LEASES................................ 0.7 0.6 0.6 0.5 --
TRANSPORTATION EXPENSES......................... 1.7 1.2 0.9 0.7 0.9
OTHER COMMITMENTS............................... 6.3 0.7 -- -- --
-------- ------- -------- ------- -------
TOTAL CONTRACTUAL CASH COMMITMENTS.......... $ 8.7 $ 2.5 $ 1.5 $ 101.2 $ 0.9
======== ======= ======== ======= =======
OTHER COMMITMENTS - In the ordinary course of business we enter into
long-term commitments to purchase seismic data. The minimum annual payments
under these contracts are $6.3 million in 2003 and $0.7 million in 2004.
MMS APPEAL - Mariner operates numerous properties in the Gulf of
Mexico. Three of such properties were leased from the Mineral Management Service
subject to the 1996 Royalty Relief Act. This Act relieved the obligation to pay
royalties on certain predetermined leases until a designated volume is produced.
These three leases contained language, which limited royalty relief if commodity
prices exceeded predetermined levels. Beginning in January 2000 commodity prices
exceeded the predetermined levels. Management believes the MMS did not have the
authority to set pricing limits and the Company filed an administrative appeal
with the MMS and has withheld royalties regarding this matter. The Company has
recorded a liability for 100% of the exposure on this matter which on December
31, 2002 was $5.5 million.
(j) RECENT ACCOUNTING PRONOUNCEMENTS
Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting
for Asset Retirement Obligations," addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. SFAS No. 143 will be effective for us January
1, 2003 and early adoption is encouraged. SFAS No. 143 requires that the fair
value of a liability for an asset's retirement obligation be recorded in the
period in which it is incurred and the corresponding cost capitalized by
increasing the carrying amount of the related long-lived asset. The liability is
accreted to its then present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or loss is
recognized. Currently, we include estimated future costs of abandonment and
dismantlement in our full cost amortization base and amortize these costs as a
component of our depletion expense. We adopted the provisions of SFAS 143 on
January 1, 2003.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative
effect adjustment to record (i) a $7.4 million increase in the carrying values
of proved properties, (ii) a $2.1 million decrease in current abandonment
liabilities. The net impact of items (i) through (ii) was to record a gain of
$9.5 million as a cumulative effect adjustment of a change in accounting
principle in our statements of operations upon adoption on January 1, 2003.
40
In April 2002 the Financial Accounting Standards Board ("FASB") issued
SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44, and No. 64,
Amendment to FASB Statement No. 13 and Technical Corrections." SFAS No. 145
streamlines the reporting of debt extinguishments and requires that only gains
and losses from extinguishments meeting the criteria in Accounting Policies
Board Opinion 30 would be classified as extraordinary. Thus, gains or losses
arising from extinguishments that are part of a company's recurring operations
would not be reported as an extraordinary item. SFAS No. 145 is effective for
fiscal years beginning after May 15, 2002 with earlier adoption encouraged. We
do not expect the adoption of SFAS No. 145 to have a material impact on our
financial position, results of operations or cash flows.
In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" and addresses accounting and
reporting for costs associated with exit or disposal activities and nullifies
Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires
that a liability for a cost associated with an exit or disposal activity be
recognized when the liability is incurred. Under Issue 94-3, a liability for an
exit cost was recognized at the date of an entity's commitment to an exit plan.
Under SFAS No. 146, fair value is the objective for initial measurement of the
liability. SFAS No. 146 is effective for exit or disposal activities that are
initiated after December 31, 2002, with early application encouraged. We do not
expect the adoption of SFAS No. 146 to have a material impact on our financial
position, results of operations or cash flows.
In December 2002 the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure" and the transition
guidance and annual disclosure provisions are effective for us for the year
ended December 31, 2002. SFAS No. 148 amends SFAS Statement No. 123, "Accounting
for Stock Based Compensation" and provides alternative methods of transition for
a voluntary change to the fair value method of accounting for stock-based
employee compensation. In addition, the statement amends the disclosure
requirements of SFAS No. 123 to require prominent disclosures in both annual and
interim financial statements about the method of accounting for stock-based
compensation and the effect of the method used. We adopted SFAS No. 148 for
2002.
In November 2002, the FASB issued Interpretation No. 45 (FIN 45), "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others," which addresses the disclosures to be
made by a guarantor in its interim and annual financial statements about its
obligations under guarantees. FIN 45 also requires the recognition of a
liability by a guarantor at the inception of certain guarantees that are entered
into or modified after December 31, 2002.
The company has adopted the disclosure requirements of FIN 45 and will apply the
recognition and measurement provisions for all material guarantees entered into
or modified in periods beginning January 1, 2003. The impact of FIN 45 on the
company's future Financial Statements will depend upon whether the company
enters into or modifies any material guarantee arrangements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
See Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - (d) (ii) Changes in Prices and Hedging Activities.
41
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Independent Auditors' Report.................................................................................... 43
Balance Sheets at December 31, 2002 and 2001.................................................................... 44
Statements of Operations for the years ended December 31, 2002, 2001 and 2000................................... 45
Statements of Stockholder's Equity for the years ended December 31, 2002, 2001 and 2000......................... 46
Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000................................... 47
Notes to Financial Statements................................................................................... 48
42
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholder
Mariner Energy, Inc.
Houston, Texas
We have audited the accompanying balance sheets of Mariner Energy, Inc. (the
"Company") as of December 31, 2002 and 2001 and the related statements of
operations, stockholder's equity and cash flows for each of the three years in
the period ended December 31, 2002. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Mariner Energy, Inc. as of
December 31, 2002 and 2001, and the results of its operations and cash flows for
each of the three years in the period ended December 31, 2002 in conformity with
accounting principles general accepted in the United States of America.
As described in Note 2, the Company has various related-party transactions and
certain control relationships with Enron Corp.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
April 14, 2003
43
MARINER ENERGY, INC.
BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
YEAR ENDED DECEMBER 31,
------------------------------------
2002 2001
--------------- -----------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................ $ 18,344 $ 11,838
Restricted cash.......................................... 15,195 --
Receivables.............................................. 29,673 34,122
Prepaid expenses and other............................... 6,757 10,006
--------- ---------
Total current assets............................... 69,969 55,966
--------- ---------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at full cost:
Proved............................................. 620,949 583,207
Unproved, not subject to amortization.............. 44,630 29,341
--------- ---------
Total......................................... 665,579 612,548
Other property and equipment....................... 5,601 5,750
Accumulated depreciation, depletion and amortization..... (383,601) (316,567)
--------- ---------
Total property and equipment, net.................. 287,579 301,731
--------- ---------
OTHER ASSETS, NET OF AMORTIZATION............................. 2,636 2,980
LONG-TERM RELATED PARTY RECEIVABLE............................ -- 3,223
--------- ---------
TOTAL ASSETS.................................................. $ 360,184 $ 363,900
========= =========
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES:
Accounts payable......................................... $ 38,438 $ 43,579
Accrued liabilities...................................... 36,313 27,543
Accrued interest......................................... 4,375 4,469
--------- ---------
Total current liabilities.......................... 79,126 75,591
--------- ---------
OTHER LIABILITIES............................................. 11,141 8,454
LONG-TERM DEBT:
Senior Subordinated Notes................................ 99,821 99,772
STOCKHOLDER'S EQUITY:
Common stock, $1 par value; 2,000 and 1,000
shares authorized, 1,380 issued and outstanding,
at December 31 2002 and December 31, 2001.............. 1 1
Additional paid-in-capital............................... 227,318 227,318
Accumulated other comprehensive income(loss)............. (14,177) 25,803
Accumulated deficit...................................... (43,046) (73,039)
--------- ---------
Total stockholder's equity......................... 170,096 180,083
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 360,184 $ 363,900
========= =========
The accompanying notes are an integral part of these financial statements
44
MARINER ENERGY, INC.
STATEMENTS OF OPERATIONS
(IN THOUSANDS)
YEAR ENDING DECEMBER 31,
------------------------------------------------------
2002 2001 2000
-------------- -------------- --------------
REVENUES:
Oil sales...................................... $ 38,792 $ 69,145 $ 37,959
Gas sales...................................... 119,436 85,855 83,191
-------- -------- --------
Total revenues.......................... 158,228 155,000 121,150
-------- -------- --------
COSTS AND EXPENSES:
Lease operating expense........................ 26,076 20,063 17,192
Transportation expense......................... 10,480 12,011 7,789
General and administrative expense............. 7,716 9,274 6,549
Depreciation, depletion and amortization....... 70,821 63,503 56,846
Impairment of Enron related receivables........ 3,234 29,529 --
-------- -------- --------
Total costs and expenses................ 118,327 134,380 88,376
-------- -------- --------
OPERATING INCOME 39,901 20,620 32,774
INTEREST:
Income......................................... 390 663 124
Expense........................................ (10,298) (8,890) (11,037)
-------- -------- --------
INCOME BEFORE TAXES............................... 29,993 12,393 21,861
PROVISION FOR INCOME TAXES........................ -- -- --
-------- -------- --------
NET INCOME........................................ 29,993 $ 12,393 $ 21,861
======== ======== ========
The accompanying notes are an integral part of these financial statements
45
MARINER ENERGY, INC.
STATEMENTS OF STOCKHOLDER'S EQUITY
(IN THOUSANDS, EXCEPT NUMBER OF SHARES)
ACCUMULATED
ADDITIONAL OTHER TOTAL
COMMON STOCK PAID-IN COMPREHENSIVE ACCUMULATED STOCKHOLDER'S
SHARES AMOUNT CAPITAL INCOME DEFICIT EQUITY
-------- ---------- ------------ --------------- ------------- ------------
BALANCE AT DECEMBER 31, 2000 1,380 $ 1 $227,318 $ -- $(85,432) $141,887
----- ----- -------- --------- -------- --------
Net income................... 12,393 12,393
Cumulative effect of change
in accounting principle... -- - -- (32,976) -- (32,976)
Change in fair value of
derivative hedging
instruments............... -- - -- 61,909 -- 61,909
Hedge settlements
reclassified to income.... -- - -- (3,130) -- (3,130)
--------
Total comprehensive income... -- - -- -- -- 38,196
--------
----- ----- -------- --------- -------- --------
BALANCE AT DECEMBER 31, 2001 1,380 $ 1 $227,318 $ 25,803 $(73,039) $180,083
----- ----- -------- --------- -------- --------
Net income................... 29,993 29,993
Change in fair value of
derivative hedging
instruments............... -- - -- (17,105) -- (17,105)
Hedge settlements
reclassified to income.... -- - -- (22,875) -- (22,875)
--------
Total comprehensive income... -- - -- -- -- (10,044)
----- ----- -------- --------- -------- --------
BALANCE AT DECEMBER 31, 2002 1,380 $ 1 $227,318 $ (14,177) $(43,046) $170,096
===== ===== ======== ========= ======== ========
The accompanying notes are an integral part of these financial statements
46
MARINER ENERGY, INC.
STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDING
DECEMBER 31,
------------------------------------------------
2002 2001 2000
------------- ------------- -------------
OPERATING ACTIVITIES:
Net income $ 29,993 $ 12,393 $ 21,861
Adjustments to reconcile net loss to net cash provided by operating
activities:
Depreciation, depletion and amortization...................... 70,588 64,118 57,538
Hedge Gain (23,200) -- --
Impairment of Enron related receivables....................... 3,223 29,529 --
Loss on sale of fixed assets 69 -- --
Changes in operating assets and liabilities:
Receivables................................................... 4,449 (1,041) (9,851)
Prepaid expenses and other.................................... 3,249 (4,015) (1,100)
Other assets.................................................. 344 (5,773) (785)
Restricted Cash............................................... (15,195)
Accounts payable and accrued liabilities...................... (13,245) 18,331 (3,721)
--------- --------- ---------
Net cash provided by operating activities..................... 60,275 113,542 63,942
--------- --------- ---------
INVESTING ACTIVITIES:
Additions to oil and gas properties............................... (105,360) (163,385) (107,468)
Proceeds from property conveyances................................ 52,329 90,500 29,002
Additions to other property and equipment......................... (738) (1,158) (610)
--------- --------- ---------
Net cash used in investing activities (53,769) (74,043) (79,076)
--------- --------- ---------
FINANCING ACTIVITIES:
Repayment of revolving credit facility............................ -- (30,000) (12,600)
Capital contributed by sale of stock to parent.................... -- -- 55,000
Proceeds from (payments to) the affiliate credit facility......... -- -- (25,000)
--------- --------- ---------
Net cash (used in) provided by financing activities........... -- (30,000) 17,400
--------- --------- ---------
INCREASE IN CASH AND CASH EQUIVALENTS................................. 6,506 9,449 2,266
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD...................... 11,838 2,389 123
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD............................ $ 18,344 $ 11,838 $ 2,389
========= ========= =========
The accompanying notes are an integral part of these financial statements
47
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION - Through March 31, 1996, Hardy Oil & Gas USA Inc. (the
"Predecessor Company") was a wholly owned subsidiary of Hardy Holdings Inc.,
which is a wholly owned subsidiary of Hardy Oil & Gas Plc ("Hardy Plc"), a
company incorporated in the United Kingdom. Pursuant to a stock purchase
agreement dated April 1, 1996, Joint Energy Development Investments Limited
Partnership ("JEDI"), Enron North America Corp. ("ENA") (see "Note 2.
Related-Party Transactions"), together with members of management of the
Predecessor Company, formed Mariner Holdings, Inc. ("Mariner Holdings"), which
then purchased from Hardy Holdings Inc. all of the issued and outstanding stock
of the Predecessor Company for a purchase price of approximately $185.5 million
effective April 1, 1996 for financial accounting purposes (the "Acquisition").
After the acquisition, the name of the predecessor company was changed to
Mariner Energy, Inc. (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.
EXCHANGE OFFERING - In October 1998, JEDI and other shareholders
exchanged all of their common shares of Mariner Holdings, the Company's parent,
for an equivalent ownership percentage in common shares of Mariner Energy LLC.
As of December 31, 1999 Mariner Energy LLC owned 100% of Mariner Holdings.
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. All direct costs and certain indirect costs
associated with the acquisition, exploration and development of oil and gas
properties are capitalized. 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, which would have a significant impact on the
depreciation, depletion and amortization. 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.
The costs of unproved properties are excluded from amortization using
the full-cost method of accounting. These costs are assessed quarterly for
possible impairments or reduction in value based on geological and geophysical
data. If a reduction in value has occurred, costs being amortized are increased.
The majority of the costs will be evaluated over the next three years.
OTHER PROPERTY AND EQUIPMENT - Depreciation of other property and
equipment is provided on a straight-line basis over their estimated useful
lives, which range from three to seven years.
OTHER ASSETS - Other assets are primarily deferred loans stated at cost
subject to amortization over the life of the related debt. Accumulated
amortization as of December 31, 2002 and 2001 was $5.3 million and $4.9 million,
respectively.
48
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
INCOME TAXES - The Company's taxable income is included in a
consolidated United States income tax return with Mariner Energy LLC. 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. Valuation
allowances are established when necessary to reduce deferred tax assets to the
amount more likely than not to be recovered.
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 $1,022,000, $2,836,000, and $3,885,000 for the years
ended December 31, 2002, 2001 and 2000, 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 costs which may be incurred
in the removal and abandonment of production facilities at the end of the
producing life of each property. On January 1, 2003, the Company adopted
Statement of Financial Accounting Standards No. 143 "Accounting for Asset
Retirement Obligations" (See Recent Accounting Pronouncements).
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,
recorded at market value are deferred, and recorded in Accumulated Other
Comprehensive Income ("AOCI") as appropriate, until recognized as operating
income in the Company's Statement of Operations as the physical production
hedged by the contracts is delivered.
The net cash flows related to any recognized gains or losses associated
with these hedges are reported as oil and gas revenues and presented in 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 hedged by the contracts is delivered.
The conditions to be met for a derivative instrument to qualify as a
cash flow hedge are the following: (i) the item to be hedged exposes the Company
to price risk; (ii) the derivative reduces the risk exposure and is designated
as a hedge at the time the derivative contract is entered into; and (iii) at the
inception of the hedge and throughout the hedge period there is a high
correlation of changes in the market value of the derivative instrument and the
fair value of the underlying item being hedged.
When the designated item associated with a derivative instrument
matures, is sold, extinguished or terminated, derivative gains or losses are
recognized as part of the gain or loss on sale or settlement of the underlying
item. When a derivative instrument is associated with an anticipated transaction
that is no longer expected to occur or if correlation no longer exists, the gain
or loss on the derivative is recognized in income to the extent the future
results have not been offset by the effects of price or interest rate changes on
the hedged item since the inception of the hedge.
REVENUE RECOGNITION - The Company recognizes oil and gas revenue from
its interests in producing wells as oil and gas from those wells is produced and
sold. Oil and gas sold is not significantly different from the Company's share
of production.
FINANCIAL INSTRUMENTS - The Company's financial instruments consist of
cash and cash equivalents, receivables, payables, and debt. At December 31, 2002
and 2001, the estimated fair value of the Company's $100,000,000 Senior
Subordinated Notes was approximately $99,000,000 and $95,000,000, respectively.
The estimated fair value was determined based on borrowing rates available at
December 31, 2002 and 2001, respectively, for debt with similar terms and
maturities. The carrying amount of the Company's other instruments noted above
approximate fair value.
49
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS - The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America 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, 2002, sales of oil
and gas to three purchasers, including an Enron affiliate, accounted for 42%,
14% and 9% of total revenues. During the year ended December 31, 2001, sales of
oil and gas to three purchasers, including an Enron affiliate, accounted for
31%, 24% and 14% of total revenues. During the year ended December 31, 2000,
sales of oil and gas to two purchasers, including an affiliate, accounted for
49% and 16% 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.
RECLASSIFICATIONS - Certain reclassifications were made to the prior
year's financial statements to conform to the current year presentation.
STOCK OPTIONS - Historically, we have accounted for stock-based
compensation using the intrinsic value method prescribed in Accounting
Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations. Accordingly, compensation cost for
stock options is measured as the excess, if any, of the fair value of common
stock at the date of the grant over the amount the employee must pay to acquire
the common stock. If the exercise price of a stock option is equal to the fair
market value at the time of grant, no compensation expense is incurred.
RECENT ACCOUNTING PRONOUNCEMENTS - Statement of Financial Accounting
Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations,"
addresses accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement
costs. SFAS No. 143 will be effective for us January 1, 2003 and early adoption
is encouraged. SFAS No. 143 requires that the fair value of a liability for an
asset's retirement obligation be recorded in the period in which it is incurred
and the corresponding cost capitalized by increasing the carrying amount of the
related long-lived asset. The liability is accreted to its then present value
each period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. Currently, we include estimated future
costs of abandonment and dismantlement in our full cost amortization base and
amortize these costs as a component of our depletion expense. We adopted the
provisions of SFAS 143 on January 1, 2003.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative
effect adjustment to record (i) a $2.1 million increase in the carrying values
of proved properties, (ii) a $7.4 million increase in current abandonment
liabilities. The net impact of items (i) through (ii) was to record a gain of
$9.5 million as a cumulative effect adjustment of a change in accounting
principle in our statements of operations upon adoption on January 1, 2003.
50
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
In April 2002 the Financial Accounting Standards Board ("FASB") issued
SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44, and No. 64,
Amendment to FASB Statement No. 13 and Technical Corrections." SFAS No. 145
streamlines the reporting of debt extinguishments and requires that only gains
and losses from extinguishments meeting the criteria in Accounting Policies
Board Opinion 30 would be classified as extraordinary. Thus, gains or losses
arising from extinguishments that are part of a company's recurring operations
would not be reported as an extraordinary item. SFAS No. 145 is effective for
fiscal years beginning after May 15, 2002 with earlier adoption encouraged. We
do not expect the adoption of SFAS No. 145 to have a material impact on our
financial position, results of operations or cash flows.
In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" and addresses accounting and
reporting for costs associated with exit or disposal activities and nullifies
Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires
that a liability for a cost associated with an exit or disposal activity be
recognized when the liability is incurred. Under Issue 94-3, a liability for an
exit cost was recognized at the date of an entity's commitment to an exit plan.
Under SFAS No. 146, fair value is the objective for initial measurement of the
liability. SFAS No. 146 is effective for exit or disposal activities that are
initiated after December 31, 2002, with early application encouraged. We do not
expect the adoption of SFAS No. 146 to have a material impact on our financial
position, results of operations or cash flows.
In December 2002 the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure" and the transition
guidance and annual disclosure provisions are effective for us for the year
ended December 31, 2002. SFAS No. 148 amends SFAS Statement No. 123, "Accounting
for Stock Based Compensation" and provides alternative methods of transition for
a voluntary change to the fair value method of accounting for stock-based
employee compensation. In addition, the statement amends the disclosure
requirements of SFAS No. 123 to require prominent disclosures in both annual and
interim financial statements about the method of accounting for stock-based
compensation and the effect of the method used. We adopted SFAS No. 148 for
2002.
In November 2002, the FASB issued Interpretation No. 45 (FIN 45),
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others," which addresses the disclosures
to be made by a guarantor in its interim and annual financial statements about
its obligations under guarantees. FIN 45 also requires the recognition of a
liability by a guarantor at the inception of certain guarantees that are entered
into or modified after December 31, 2002.
The company has adopted the disclosure requirements of FIN 45 (see Note
2 "Related-Party Transactions) and will apply the recognition and measurement
provisions for all material guarantees entered into or modified in periods
beginning January 1, 2003. The impact of FIN 45 on the company's future
Financial Statements will depend upon whether the company enters into or
modifies any material guarantee arrangements.
51
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
2. RELATED-PARTY TRANSACTIONS
ENRON BANKRUPTCY - Commencing on December 2, 2001, Enron Corp.
("Enron") and certain of its affiliates, including Enron North America Corp.
("ENA"), filed voluntary petitions for bankruptcy protection. We have been
informed that of our various direct or indirect owners, only Enron and ENA are
debtors in the bankruptcy. We do not know at this time if any other owners will
seek bankruptcy protection or what effect, if any, this may have on the
ownership of Mariner Energy LLC which owns 100% of Mariner Holdings, Inc. (our
direct parent) or on Joint Energy Development Investments Limited Partnership
("JEDI"), which owns approximately 96% of the issued and outstanding equity of
Mariner Energy LLC. Enron is the parent of ENA, and an affiliate of ENA is the
general partner of JEDI. JEDI is 100% owned by Enron and affiliates of ENA.
Accordingly, Enron may be deemed to control JEDI, Mariner Energy LLC, Mariner
Holdings and us. Additionally, five of the Company's directors are officers of
Enron or affiliates of Enron. Because of these various potentially conflicting
interests, ENA, the Company, JEDI and the minority shareholders of Mariner
Energy LLC have entered into an agreement that is intended to make clear that
Enron and its affiliates have no duty to make business opportunities available
to the Company.
Mariner Energy LLC's only asset is 100% of the common stock of Mariner
Holdings, Inc., our direct parent. The only asset of Mariner Holdings is 100% of
the common shares of Mariner.
Management cannot predict with certainty what impact Enron's bankruptcy
may have on us. However, it does believe that our assets and liabilities will
not become part of the Enron estate in bankruptcy. Although JEDI owns 96% of
Mariner Energy LLC's common shares, we, as a separate corporation own or lease
the assets used in its business and our management, separate from Enron, is
responsible for our day-to-day operations. Contractual provisions restrict Enron
access to our assets. We maintain our own accounting system as well as separate
debt ratings. We maintain our own separate and complete cash management system
and finance its operations separately from Enron, on both a short-term and
long-term basis. We file a consolidated tax return with Mariner Energy LLC.
Notwithstanding the above, we may have potential exposure to certain
liabilities and asset impairments as a result of Enron's bankruptcy. Portions
following Enron-related disclosures are based on discussions with Enron's legal
advisors and management, including members of our Board of Directors. Although
our management has implemented with Enron's legal advisor and management a
systematic method of identifying Enron matters which may have a material impact
on us, management cannot provide any assurance as the completeness or accuracy
of the information provided by or on behalf of Enron.
ORGANIZATION AND OWNERSHIP OF THE COMPANY - Through March 31, 1996,
Hardy Oil & Gas USA Inc. (the "Predecessor Company") was a wholly-owned
subsidiary of Hardy Holdings Inc., which is a wholly-owned subsidiary of Hardy
Oil & Gas Plc ("Hardy Plc"), a company incorporated in the United Kingdom.
Pursuant to a stock purchase agreement dated April 1, 1996, JEDI and ENA,
together with members of management of the Predecessor Company, formed Mariner
Holdings, Inc. ("Mariner Holdings"). Mariner Holdings then purchased from Hardy
Holdings Inc. all of the issued and outstanding stock of the Predecessor Company
for a purchase price of approximately $185.5 million (the "Acquisition"). After
the Acquisition, the name of the Predecessor Company was changed to Mariner
Energy, Inc. In October 1998, JEDI and other shareholders exchanged all of their
common shares of Mariner Holdings, the Company's direct parent, for an
equivalent ownership percentage in common shares of Mariner Energy LLC. Mariner
Energy LLC owns 100% of Mariner Holdings.
52
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Subsequent to the Acquisition, Mariner Energy LLC, Mariner
Holdings and Mariner have each entered into various financing and operating
transactions with affiliates. In addition, the Company may have from time to
time engaged in various commercial transactions and have various commercial
relationships with Enron and certain affiliates of Enron, such as holding and
exploring, exploiting and developing joint working interests in particular
prospects and properties and entering into other oil and gas related or
financial transactions. Certain of the Company's third-party debt instruments
and arrangements 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 and its affiliates
are, and anticipates that any future agreements with Enron and its affiliates
will be, on terms no less favorable to the Company than would be obtained in an
agreement with a third party. Below is a summary of key transactions between the
Company and affiliate entities.
MARINER ENERGY LLC
ENA Affiliate Term Loan - In March 2000, Mariner Energy LLC established
an unsecured term loan with ENA to repay amounts outstanding under various
affiliate credit facilities at Mariner Energy LLC and Mariner and to provide
additional working capital. The additional working capital of $55 million was
contributed to Mariner in 2000. The loan bears interest at 15%, which interest
accrues and is added to the loan principal. Repayment of the balance of loan
principal and accrued interest, which was approximately $164.4 million as of
December 31, 2002, is due March 20, 2004. In conjunction with the loan
agreement, two five-year warrants were issued to ENA providing the right to
purchase up to 900,000 of common shares of Mariner Energy LLC for $0.01 per
share.
Covenants in Mariner's Senior Subordinated Notes restrict the funds of
Mariner that can be distributed to Mariner Energy LLC. Accordingly, Mariner
Energy LLC is restricted in its ability to repay the unsecured Term Loan or to
distribute earnings to its shareholders. In the event Mariner Energy LLC is
unable to restructure or extend the maturity of its obligations prior to March
2004 it would either default under the Term Loan or be forced to sell its
interest in Mariner or cause Mariner to sell a substantial portion of its assets
to repay any outstanding Senior Subordinated Notes so that it could distribute
any remaining cash proceeds to Mariner Energy LLC to be used to repay the Term
Loan.
We have been informed by Enron's legal advisors and management that the
Term Loan and warrants were transferred from ENA to an ENA affiliate, which
affiliate is part of a finance structure formed by ENA. Because debt obligations
of the finance structure are in default and ENA therefore does not have complete
control over decisions made by the ENA affiliate, it may be difficult for
Mariner Energy LLC to obtain any consents, waivers or amendments needed from the
ENA affiliate in connection with the Term Loan or the warrants.
MARINER HOLDINGS, INC.
1998 Equity Investment - In June 1998, Mariner Holdings issued
additional equity to its existing shareholders, including JEDI, for
approximately $14.58 per share, for a net investment of $28.8 million, all of
which was contributed to Mariner. Mariner Holdings 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 Limited Partnership.
MARINER ENERGY, INC.
Oil and Gas Production Sales to ENA or Affiliates - During the three
years ending December 31, 2002, 2001 and 2000, sales of oil and gas production
to ENA or affiliates were $56.4million, $50.2 million and $73.4 million,
respectively. These sales were generally made on 1 to 3 month contracts. At the
time ENA filed its petition for bankruptcy protection, the Company immediately
ceased selling its physical production to ENA, however, we continued to sell our
production to Bridgeline which ENA owned a minority interest. All amounts sold
to this party have been collected. As of December 31, 2002, we had an
outstanding receivable for $3 million from ENA. This amount was not paid as
scheduled and is still outstanding. Mariner has submitted a proof of claim to
the bankruptcy court for amounts owed to it by ENA. The Company has estimated
100% of this balance is uncollectible and has recorded a full allowance and
related expense.
53
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Management Activities - We engage in price risk management activities
from time to time. These activities are intended to manage our exposure to
fluctuations in commodity prices for natural gas and crude oil. We primarily
utilize price swaps and costless collars as a means to manage such risk.
Historically, all of our hedging contracts were with ENA. As a result of ENA's
bankruptcy, the contracts are currently in default. The November 2001 through
April 30, 2002 settlements for oil and gas have not been collected. In addition,
on May 14, 2002, we elected under its Master Service Agreement with ENA to
terminate all open contracts. The effect of this termination is to fix the
nominal value on all remaining contracts on May 14, 2002. Subsequent to this
termination, the value of all oil and natural gas unpaid hedge contracts was
$7.7 million. We have estimated 100% of this balance is uncollectible and have
recorded a full allowance. We have submitted a proof of claims to the bankruptcy
court for amounts owed under this agreement. In accordance with Statement of
Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 137 and No. 138, we
have de-designated our contracts effective December 2, 2001 and are recognizing
all market value changes subsequent to such de-designation in our earnings. The
value recorded up to the time of de-designation and included in Accumulated
Other Comprehensive Income ("AOCI"), will reverse out of AOCI and into earnings
as the original corresponding production, as hedged by the contracts, is
produced. For the year ending December 31, 2002 approximately $23.2 million has
reversed out to earnings. As of December 31, 2002, $2.6 million remained in AOCI
to be reversed out to earnings.
The following table sets forth the results of hedging transactions
during the periods indicated that were made with ENA (all amounts shown are
non-cash items):
YEAR ENDING DECEMBER 31,
---------------------------------------------------
2002 2001 2000
-------------- ------------- --------------
Natural gas quantity hedged (Mmbtu).......................... 18,090 17,733 19,569
Increase (decrease) in natural gas sales (thousands)......... $ 20,413 $ (5,523) $ (21,364)
Crude oil quantity hedged (MBbls)............................ 446 752 1,059
Increase (decrease) in crude oil sales (thousands)........... $ 2,787 $ 2,393 $ (14,053)
54
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Supplemental Affiliate Data - provided below is a supplemental balance sheet and
income statement for affiliate entities:
DECEMBER 31, 2002 DECEMBER 31, 2001
----------------- -----------------
AMOUNTS AMOUNTS
BALANCE SHEET DATA (IN MILLIONS) (IN MILLIONS)
------------------ TOTAL TOTAL
------------ ---------------------------------------------------
RELATED PARTY RECEIVABLE:
Derivative Asset $ -- $ 2.5 $ --
Settled Hedge Receivable -- 0.4 --
Oil and Gas Receivable 8.2 8.2 0.3 3.2
ACCRUED LIABILITIES:
Transportation Contract -- -- 0.9 --
Service Agreement 0.6 1.5 0.3 1.2
STOCKHOLDER'S EQUITY:
Common Stock $ .001 -- $ .001 --
Additional Paid in Capital $227.3 $227.3
Accumulated other Comprehensive Income $ 2.3 $ 229.6 $ 25.8 $253.1
YEAR ENDED
DECEMBER 31
-----------------------------------------
INCOME STATEMENT DATA
2002 2001
-------- --------
Oil and Gas Sales $ 56.4 $ 50.2
General and Administrative Expenses 0.4 0.2
Transportation Expenses 2.7 4.2
Unrealized loss and other non-cash 3.2 29.5
derivative instrument adjustments
As a result of the Enron and ENA bankruptcies, among other
implications, we may not be able to obtain credit from banks or trade vendors or
enter into hedging arrangements on acceptable terms. To date, our operations
have not been materially affected by the bankruptcies; however, our ability to
enter into certain transactions including purchase or sale arrangements and to
conduct significant capital programs may be affected in the future. Oil and gas
sales and the related accounts receivable for the year ending December 31, 2002
relate to sales made to a minority owed affiliate of Enron.
CONTROLLED GROUP LIABILITY
On November 12, 2002, Enron's legal advisors and management informed us
that we may be an Enron Corp. Controlled Group Member as defined under the
Employee Retirement Income Security Act of 1974 ("ERISA") due to Enron's
indirect ownership interest in Mariner Energy LLC. Enron management has not made
a final determination if we are in fact a Controlled Group Member. Because of
numerous ownership issues within the Enron Group, we are unable to make our own
determination as to whether we agree or disagree that we are a Controlled Group
Member. In the event we are a Controlled Group Member, we may have potential
liability for certain employee benefit plan obligations of Enron discussed
below.
55
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Pension Plans - Applicable federal law authorizes the Pension Benefit
Guaranty Corporation ("PBGC") to institute proceedings in federal district court
for the termination of a pension plan if it determines the plan has failed to
comply with minimum funding standards, the plan is or will be unable to pay
benefits when due, or the failure to terminate the plan may reasonably be
expected to unreasonably increase the possible long-run loss to the PBGC.
Federal law also authorizes the sponsor of a pension plan to terminate the plan
at a time when the plan is underfunded, subject to PBGC or court approval.
Based on discussions with Enron management, it is our management's
understanding that, as of December 31, 2002 the assets of Enron's pension plan
(the "Enron Plan") were less than the present value of all accrued benefits by
approximately $52 million on a SFAS No. 87 basis and approximately $182 million
on a plan termination basis. Further, Enron's management has informed Mariner
management that the PBGC has filed claims in the Enron bankruptcy cases. The
claims are duplicative in nature, representing unliquidated claims for PBGC
insurance premiums (the "Premium Claims") and unliquidated claims for due but
unpaid minimum funding contributions (the "Contribution Claims") under the
Internal Revenue Code of 1986, as amended (the "Tax Code") 29 U.S.C. Sections
412(a) and 1082 and claims for unfunded benefit liabilities (the "UBL" Claims").
Enron and the relevant sponsors of the defined benefit plans are current on
their PBGC premiums and their contributions to the pension plans. Therefore,
Enron has valued the Premium Claims and the Contribution Claims at $0. The total
amount of the UBL Claims is $305.5 million (including $271 million for the Enron
Plan). In addition Enron Management has informed Mariner Management that the
PBGC has informally alleged in pleadings filed with the bankruptcy court that
the UBL Claim related to the Enron Plan could increase by as much as 100%. PBGC
has provided no support (statutory or otherwise) for this assertion and Enron
Management disputes the validity of any such claim. Because the Enron Plan is
under funded and Enron is in bankruptcy, in certain circumstances the Enron Plan
may be terminated and taken control of by the PBGC upon approval of a Federal
District Court.
Mariner's employees have not been participants in the Enron Plan.
However, upon termination of a pension plan, all of the members of the
controlled group of the plan sponsor become jointly and severally liable for the
plan are under funding. The PBGC can demand payment from one or more of the
members of the controlled group. If payment is not made, a lien in favor of the
PBGC automatically arises against all of the assets of that member of the
Controlled Group. The amount of the lien is equal to the lesser of the
underfunding or 30% of the aggregate net worth of all of the controlled group
members. In addition, if the sponsor of a pension plan does not timely satisfy
its minimum funding obligation to the pension plan, once the aggregate missed
amounts exceed $1 million, a lien in favor of the plan in the amount of the
missed funding automatically arises against the assets of every member of the
controlled group. In either case, the PBGC may file to perfect the lien and
attempt to enforce it against the assets of members of the Enron Controlled
Group. Mariner has been informed by Enron that Enron's management believes that
the lien would be subordinate to prior perfected liens on the assets of the
member of the controlled group. Based on discussions with Enron's management,
Mariner's management understands that Enron has made all required contributions
to date through October 15, 2002. Enron's management has advised us that it
intends to make its next contribution, due in the first quarter of 2003.
Management cannot predict the outcome of the above matters or estimate
any potential loss. In addition, if the PBGC did look solely to Mariner to pay
any amount with respect to the Enron Plan, Mariner would exercise all legal
rights, available to it to defend against such a demand and to recover any
contributions from the other solvent members of the Controlled Group. No
reserves have been established by Mariner for any amounts related to this issue.
Mariner has also been informed by Enron management that Enron has
contacted the PBGC as well as Unsecured Creditors Committee regarding their
intention to terminate the Enron Plan, subject to approval by such parties, the
bankruptcy court and authorization to fully fund the Enron Plan in accordance
with its terms. If approved Enron would fully fund the Enron Plan in accordance
with the terms, the plan could be terminated without any liability to Mariner.
Enron has also stated that it believes it has the necessary funds to consummate
such a termination. In addition to the extent that entities in the Controlled
Group are sold prior to termination of the Plan, proceeds of the sale of such
entities may be available to satisfy this liability. Enron estimates proceeds
from such sale of Enron Control Group entities would far exceed any plan
obligations.
56
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Retiree Health Benefits - Under COBRA, if certain retirees of Enron
lose coverage under Enron's group health plan due to Enron's bankruptcy
proceedings, they would be entitled to elect continuation of their health
coverage in a group plan maintained by Enron or a member of its Controlled
Group. Mariner's employees have not participated in this plan. Mariner
management understands, based on discussions with Enron management, that Enron
had provided a plan for retiree health insurance and that the actuarial
liability for such coverage was approximately $70 million as of December 31,
2001. Management further understands that to meet its obligation, Enron, at
December 31, 2001, had set aside approximately $34 million of assets in a VEBA
trust, which may be protected under ERISA from Enron's creditors, leaving an
unfunded liability of approximately $36 million.
In the event that Enron terminates its retiree group health plan, the
retirees must be provided the opportunity to purchase continuing coverage from
Enron's group health plan, if any, or the most appropriate existing group health
plan of another member of the Enron Controlled Group. Retirees electing to
purchase COBRA coverage would be provided the same coverage that is provided to
similarly situated retirees under the appropriate existing plan. Retirees
electing to purchase COBRA coverage would be required to pay for the coverage,
up to an amount not to exceed 102% of the cost of coverage for similarly
situated beneficiaries. Retirees are not required to purchase coverage under
COBRA. Retirees may, instead, shop for coverage from third party sources and
determine which is the least expensive coverage.
Management cannot predict the outcome of the above matter or estimate
any potential loss. However, management believes that in the event Enron
terminates coverage, any liability to Mariner associated with the number of
retirees that choose to remain under Enron's retiree health plan will not be
material. No reserves have been established by Mariner for any amounts related
to this issue.
SALE OF ENRON INTEREST IN MARINER
On May 3, 2002, Enron presented to its Unsecured Creditors' Committee a
proposal under which certain of Enron's core energy assets, including JEDI's
ownership of Mariner Energy LLC, would be separated from Enron's bankruptcy
estate and operated prospectively as a new integrated power and pipeline
company.
On August 27, 2002, Enron announced that it had commenced a formal
sales process for its interests in certain major assets, including JEDI's
ownership of Mariner Energy LLC. In its announcement, Enron indicated that it
was extending invitations to visit electronic data rooms containing information
on 12 of its most valuable businesses, including Mariner, to a broad universe of
potential bidders with whom Enron had executed confidentiality agreements.
Enron has announced its intent to move forward with the sale of four
companies, however, it continues to evaluate its alternatives with regard to
Mariner. Management is unable to give assurances that the Company will be or not
be sold in the near future and there can be no assurance as to whether JEDI's
ownership of Mariner Energy LLC will be sold in the future.
3. LIQUIDITY
As of December 31, 2002, we had working capital deficit of
approximately $10.2 million, of which $15.2 million is restricted, compared to a
working capital deficit of $19.6 million at December 31, 2001. The improvement
in the working capital was primarily a result of the sale of half of the
Company's working interest in its Falcon Project for approximately $52.3 million
including reimbursements with a portion of the proceeds being used to repay the
Revolving Credit Facility. We expect our 2003 capital expenditures, excluding
capitalized indirect costs and proceeds from property conveyances (see "Note 4.
Recent Events"), to be approximately $103.0 million, which would exceed cash
flow from operations. However, we believe that cash on hand together with
expected cash flow for operations to permit us to fund our remaining planned
activities in 2003. There can be no assurance that our access to capital will be
sufficient to meet our needs for capital. Accordingly, we may be required to
reduce our planned capital expenditures and forego planned exploratory drilling.
57
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
The Company's Revolving Credit Facility matured in October 2002. We
have begun discussions with other third party banks to provide a new revolving
credit facility. There is no assurance that a new credit facility will be
obtained. In addition, our parent, Mariner Energy LLC, is currently obligated
under an unsecured term loan with an ENA affiliate. Mariner Energy LLC
negotiated an extension of the ENA Affiliate Term Loan to March 20, 2004. In the
event Mariner Energy LLC is unable to refinance or restructure its obligations
prior to March 2004, Mariner Energy LLC would either default or be forced to
sell its interest in the Company, or cause the Company to sell a substantial
portion of its assets to repay its outstanding Senior Subordinated Notes so that
it could distribute cash to Mariner Energy LLC to be used to repay the term
loan. In the event of either a merger or consolidation of Mariner Energy LLC or
the Company resulting in a change of control or a sale of all or substantially
all of the Company's assets, holders of the Senior Subordinated Notes would have
the right to require the Company to repurchase the Senior Subordinated Notes
held by them at a purchase price in cash equal to 101% of the principal amount
thereof plus accrued and unpaid interest. Any such transaction would also
trigger a mandatory prepayment of all amounts outstanding under the ENA
Affiliate Term Loan. The Company's ability to pay dividends and make other
distributions of cash to Mariner Energy LLC are generally restricted under the
indenture governing the Senior Subordinated Notes. As a result, following any
change of control transaction or sale of all or substantially all of its assets,
the Company would most likely be required to repurchase any Senior Subordinated
Notes tendered to it under the indenture and redeem the balance of the Senior
Subordinated Notes outstanding as permitted under the indenture before it could
distribute cash to Mariner Energy LLC to repay the ENA Affiliate Term Loan.
4. RECENT EVENTS
On March 19, 2003, with bids totaling $3.9 million net to us, we were
the apparent high bidder solely or with industry partners, on 11 out of 11
blocks on which we and our partners submitted bids in the Central Gulf of Mexico
Oil and Gas Lease Sale 185 held on that date. Each of the blocks is in water
depths ranging from approximately 20 feet to 1,500 feet. Mariner has a 100%
working interest in five of the blocks and a 50% working interest in six blocks.
In January 2003 we made a deepwater Gulf of Mexico Discovery at
"Harrier", East Breaks 759, and a shelf Gulf of Mexico discovery at Vermillion
144. Harrier was drilled in 4,100 feet of water to a total measured depth of
9,510 feet and encountered 315 net feet of gas pay. Mariner holds a 25% working
interest. Vermilion 144 was drilled in 87 feet of water to a total measured
depth of 16,522 feet and encountered 90 net feet of pay. Mariner is operator
with a 42% working interest. First production is expected in June 2003.
In March 2003, we sold our remaining 25% working interest in our Falcon
and Harrier discoveries and surrounding blocks, located in East Breaks area in
the western Gulf of Mexico, for $121.6 million. We retained a 4 1/4 percent
overriding royalty interest on seven non-producing blocks. The proceeds from the
sale are expected to be used for debt reduction, capital expenditures, and other
corporate purposes. At December 31, 2002, the Falcon project had 33.3 Bcfe
assigned as proven oil and gas reserves to our interest.
5. LONG-TERM DEBT
REVOLVING CREDIT FACILITY - In 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"). The Revolving Credit
Facility provided for a maximum $150 million revolving credit loan. On October
1, 2002 the Revolving Credit Facility matured. This facility has not yet been
replaced; however, management is in discussions with third party banks to
provide a replacement facility.
58
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
10 1/2% SENIOR SUBORDINATED NOTES - On August 14, 1996, the Company
completed the sale of $100 million principal amount of 10 1/2% Senior
Subordinated Notes Due 2006, (the "Notes"). The proceeds of the Notes were used
by the Company to (i) pay a dividend to Mariner Holdings, which used the
dividend to fully repay a bridge loan from JEDI incurred in the Acquisition, and
(ii) repay a previous 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.
The indenture pursuant to which the Notes are issued contains certain
covenants that, among other things, limit the ability of the Company to incur
additional indebtedness, pay dividends, redeem capital stock, make investments,
enter into transactions with affiliates, sell assets and engage in mergers and
consolidations. As of December 31, 2002, 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 the event of a change of control of the Company (as defined in the
indenture pursuant to which the Notes are issued), each holder of the Notes (the
"Holder") will have the right to require the Company to repurchase all or any
portion of such Holder's Notes at a purchase price equal to 101% of the
principal amount thereof, plus accrued interest.
Cash paid for interest for the years ending December 31, 2002, 2001 and 2000 was
$11.1, $11.4 million, $15.3 million, respectively.
6. STOCKHOLDER'S 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 must 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 Plan was amended to
make Mariner Energy LLC the Plan sponsor. The maximum number of shares of common
shares that can be issued under the Plan was correspondingly increased to
2,433,600.
During the years ended December 31, 2002, 2001 and 2000, Mariner Energy
LLC granted stock options ("Options") of 0, 13,166, and 39,144, respectively. No
options have been exercised, but 212,882 options have been canceled during the
three year period. At December 31, 2002, options to purchase 1,926,468 shares
were outstanding at an exercisable. The exercise price for outstanding options
to purchase an aggregate of 1,574,244 shares under the 1996 plan is $8.33 per
share, and the exercise price for options to purchase the remaining outstanding
aggregate of 352,224 shares under the 1996 plan is $14.58 per share. These
Options generally become exercisable as to one-fifth to one-third on each of the
first three to five anniversaries of the date of grant. The Options expire from
seven years to ten years after the date of grant. All of the 1,574,244 options
issued at $8.33 will expire in June 2003. The remaining options expire in
various months between 2008 through 2010.
59
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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 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 income for the year ended December 31,
2002 would not have changed, the net income for the year ending 2001 would have
decreased $325,000 and the net income for the year ending 2000 would have
decreased $422,000, respectively. Pro forma earnings per share would be $21,734,
$8,744 and $15,535 for the years ending December 31, 2002, 2001 and 2000,
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 4.54% and 4.75% for the years ending December 31, 2001 and 2000,
respectively. No options were granted in 2002. Stock options available for
future grant amounted to 507,132 shares at December 31, 2002. Exercisable stock
options amounted to 1,926,468 shares at December 31, 2002.
60
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
7. EMPLOYEE BENEFIT AND ROYALTY PLANS
EMPLOYEE CAPITAL ACCUMULATION PLAN - The Company provides all full-time
employees participation in the Employee Capital Accumulation Plan (the "Plan")
which is comprised of a contributory 401(k) savings plan and a discretionary
profit sharing plan. Under the 401(k) feature, the Company, at its sole
discretion, may contribute an employer-matching contribution equal to a
percentage not to exceed 50% of each eligible participant's matched salary
reduction contribution as defined by the Plan. Under the discretionary profit
sharing contribution feature of the Plan, the Company's contribution, if any,
must be determined annually and must 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 2002, 2001 and
2000, the Company contributed $249,205, $369,677 and $291,940, respectively, to
the Plan. This plan is a continuation of a plan provided by the Predecessor
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. Cash payments made by the Company under these agreements for the
three years ended December 31, 2002, 2001 and 2000 were $2.5, $5.8 and $2.9
million, respectively.
8. COMMITMENTS AND CONTINGENCIES
ENRON MATTERS - See "Note 2. Related-Party Transactions", the Company
has various related-party transactions and certain control relationships with
Enron Corp. and affiliates.
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, 2002 are as follows (in thousands):
2003.................... $ 645
2004.................... 611
2005.................... 547
2006.................... 445
2007.................... 9
-------
TOTAL.............. $ 2,257
=======
Rental expense, before capitalization, was approximately $1,723,000,
$1,492,000 and $1,228,000 for the years ended December 31, 2002, 2001 and 2000,
respectively.
HEDGING PROGRAM -The energy markets have historically been very
volatile, and there can be no assurance that oil and gas prices will not be
subject to wide fluctuations in the future. In an effort to reduce the effects
of the volatility of the price of oil and natural gas on our operations,
management has adopted a policy of hedging oil and natural gas prices from time
to time primarily through the use of commodity swap and costless collar
agreements. While the use of these hedging arrangements limits the downside risk
of adverse price movements, it also limits future gains from favorable
movements. Prior to 2002 all hedge activities historically have been conducted
with Enron. As a result of the Enron bankruptcy we have de-designated all hedge
positions (see "Note 2 - Related-Party Transactions"). In 2002 we implemented a
new hedging program with a third party.
On June 28, 2002 the Company commenced price risk activities with a
third party. These activities are intended to manage the Company's exposure to
fluctuations in commodity prices for natural gas and crude. As of December 31,
2002 the Company had the following fixed price swaps outstanding.
61
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
TIME PERIOD NOTIONAL FIXED DECEMBER 31, 2002
----------- QUANTITIES PRICE FAIR VALUE
(millions)
Gain/(Loss)
------------- --------- -----------------------
CRUDE OIL (MBbl)
January 1 - December 31, 2003
Fixed Price Swap 548 $ 24.02 $ (1.8)
Fixed Price Swap 183 $ 24.81 (0.4)
NATURAL GAS (MMbtu)
January 1 - December 31, 2003
Fixed Price Swap 730 $ 3.54 (7.5)
Fixed Price Swap 730 $ 3.60 (7.1)
-------
$ (16.8)
=======
The Company has reviewed the financial strength of its counterparts and
believes credit risk to be minimal. As of December 31, 2002 the Company had on
deposit, classified as restricted cash, $22.3 million with the third party for
collateral. This collateral included $5.8 million in initial margin in cash and
$16.5 million in mark-to-market exposure. Initial margin decreases as contracts
settle.
As a result of increasing natural gas prices, in January and February
of 2003, the Company unwound, through the purchase of counter positions, all
natural gas swap contracts for the months of February through October 2003
locking in a loss of $23.2 million. This loss will be settled over the original
contract period.
As a result of these swaps and other hedging transactions the Company
will have approximately 31% of 2003 production subject to hedges. Mark to market
value changes approximately $8.6 million for every 10% overall change in
commodity prices.
The following table sets forth the results of hedging transactions
during the periods indicated that were made with non-Enron related parties.
DECEMBER 31,
2002 2001
----------- -----------
NATURAL GAS
Quantity hedged (Mmbtu) -- --
Increase (Decrease) in Natural Gas Sales (in thousands) -- --
CRUDE OIL
Quantity hedged (MBbls) 169 --
Increase (Decrease) in Crude Oil Sales (in thousands) $ (325) --
OTHER COMMITMENTS - In the ordinary course of business we enter into
long-term commitments to purchase seismic data. The minimum annual payments
under these contracts are $6.3 million in 2003 and $2.7 million in 2004.
62
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DEEPWATER RIG - In the fourth quarter of 1999, Noble Drilling
Corporation filed suit against the Company alleging breach of contract regarding
a letter of intent for a five year Deepwater rig contract. In February 2000,
both the Company and Noble Drilling Corporation entered into a settlement
agreement whereby the Company committed to using this Deepwater rig for a
minimum of 660 days over a five-year period at market-based day rates for
comparable drilling rigs in comparable water depths subject to a floor day rate
ranging from $65,000 to $125,000. In exchange for market-based day rates, Noble
Drilling was assigned working interests in seven of the Company's deepwater
exploration prospects. The Company will pay Noble Drilling's share of the costs
of drilling the initial test well on each of these prospects. As of December 31,
2002, 43 days remained on this commitment and the Company has drilled five of
the seven prospects.
MMS APPEAL - Mariner operates numerous properties in the Gulf of
Mexico. Three of such properties were leased from the Mineral Management Service
subject to the 1996 Royalty Relief Act. This Act relieved the obligation to pay
royalties on certain predetermined leases until a designated volume is produced.
These three leases contained language, which limited royalty relief if commodity
prices exceeded predetermined levels. Beginning in January 2000 commodity prices
exceeded the predetermined levels. Management believes the MMS did not have the
authority to set pricing limits and the Company filed an administrative appeal
with the MMS and has withheld royalties regarding this matter. The Company has
recorded a liability for 100% of the exposure on this matter which on December
31, 2002 was $5.5 million.
LITIGATION - The Company, in the ordinary course of business, is a
claimant and/or a defendant in various legal proceedings, including proceedings
as to which the Company has insurance coverage. The Company does not consider
its exposure in these proceedings, individually and in the aggregate, to be
material.
9. INCOME TAXES
The following table sets forth a reconciliation of the statutory
federal income tax with the income tax provision (in thousands):
YEAR ENDING DECEMBER 31,
-------------------------------------------------------------------
2002 2001 2000
---------------------- --------------------- --------------------
$ % $ % $ %
---------- ---------- ---------- --------- ---------- --------
Income before income taxes............... 29,993 -- 12,393 -- 21,861 --
Income tax expense (benefit) computed at
statutory rates....................... 10,498 35 4,338 35 7,651 35
Change in valuation allowance............ (11,507) (38) (4,544) (37) (8,742) (40)
Other.................................... 1,009 3 206 2 1,091 5
------- ---- ------- ---- ------ ----
Tax Expense.............................. -- -- -- -- -- --
======= ==== ======= ==== ====== ====
No federal income taxes were paid by the Company during the years ended
December 31, 2002, 2001 and 2000.
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):
63
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
YEAR ENDING DECEMBER 31,
---------------------------------------------
2002 2001 2000
------------ ------------- ------------
DEFERRED TAX ASSETS:
Net operating loss carry forwards............................. $ 21,025 $ 21,618 $ 43,142
Differences between book and tax basis of receivables......... 3,160 10,335 --
Valuation allowance........................................... (7,090) (18,597) (23,141)
--------- -------- ---------
Total net deferred tax assets.......................... 17,095 13,356 20,001
DEFERRED TAX LIABILITIES:
Differences between book and tax basis of properties.......... (17,095) (13,356) ( 20,001)
--------- -------- ---------
Total net deferred taxes............................... -- -- --
========= ======== =========
As of December 31, 2002, the Company had a cumulative net operating
loss carryforward ("NOL") for federal income tax purposes of approximately $60.1
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.
10. OIL AND GAS PRODUCING ACTIVITIES AND CAPITALIZED COSTS
The results of operations from the Company's oil and gas producing
activities were as follows (in thousands):
YEAR ENDING DECEMBER 31,
--------------------------------------------
2002 2001 2000
----------- ------------ ------------
Oil and gas sales................................ $ 158,228 $ 155,000 $121,150
Production costs................................. 26,076 (20,063) (17,192)
Transportation................................... 10,480 (12,011) (7,789)
Depreciation, depletion and amortization......... 70,821 (63,503) (56,846)
--------- --------- --------
Results of operations........................ $ 50,851 $ 59,423 $ 39,323
========= ========= ========
64
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Costs incurred in property acquisition, exploration and development
activities were as follows (in thousands, except per equivalent mcf amounts):
YEAR ENDING DECEMBER 31,
---------------------------------------------
2002 2001 2000
---------- ------------- -----------
Property acquisition costs
Unproved properties $ -- $ 8,721 $ 14,000
Exploration costs 40,358 57,665 17,192
Development costs 65,002 96,999 76,276
Proceeds from property conveyances......................... (52,329) (90,500) (29,002)
-------- -------- --------
Total costs, net of proceeds from property conveyances. $ 53,031 $ 72,885 $ 78,466
======== ======== ========
Depreciation, depletion and amortization rate per
equivalent Mcf before impairment........................... $ 1.78 $ 1.73 $ 1.57
The Company capitalizes internal costs associated with exploration
activities in progress. These capitalized costs were approximately $1,022,000,
$10,508,000 and $11,625,000 for the years ended December 31, 2002, 2001 and
2000, respectively.
The following table summarizes costs related to unevaluated properties
which have been excluded from amounts subject to amortization at December 31,
2002. 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.
COST INCURRED DURING THE YEAR
ENDED DECEMBER 31,
--------------------------------------- TOTAL AT
2002 2001 2000 PRIOR DECEMBER 31, 2002
------------ ---------- ----------- ----------- -----------------------------
Property acquisition costs...... $ 16,289 $ 8,912 $ 2,527 $ 9,672 $ 37,400
Exploration costs............... 1,834 5,380 -- 16 7,230
-------- ------- ------- ------- --------
Total ........................ 18,123 $14,292 $ 2,527 $ 9,688 $ 44,630
======== ======= ======= ======= ========
All of the excluded costs at December 31, 2002 relate to activities in
the Gulf of Mexico.
11. 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, 2002 were reserves expected to be
recovered from wells for which certain drilling and completion operations had
occurred as of that date, (See "Note 4. Recent Events" regarding sale of our
remaining working interest in the Falcon project subsequent to December 31,
2002) 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
65
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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 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
(IN THOUSANDS)
NATURAL GAS
OIL NATURAL GAS EQUIVALENT
(BBL) (MCF) (MCFE)
----------- ------------- ------------------
DECEMBER 31, 1999 9,927 118,790 178,352
------ ------- -------
Revisions of previous estimates.................. 324 (13,255) (11,311)
Extensions, discoveries and other additions...... 4,123 24,649 49,387
Sale of reserves in place........................ (215) (673) (1,963)
Purchase of reserves in place.................... -- 25,455 25,455
Production....................................... (1,762) (25,710) (36,282)
------ ------- -------
DECEMBER 31, 2000 12,387 129,256 203,578
------ ------- -------
Revisions of previous estimates.................. 2,079 (8,240) 4,236
Extensions, discoveries and other additions...... 2,736 96,711 113,127
Sale of reserves in place........................ (4,123) (22,470) (47,208)
Production....................................... (2,978) (18,796) (36,664)
------ ------- -------
DECEMBER 31, 2001 10,101 176,461 237,067
------ ------- -------
Revisions of previous estimates.................. 541 5,523 8,769
Extensions, discoveries and other additions...... 2,108 18,791 31,439
Sale of reserves in place........................ (35) (35,088) (35,298)
Production....................................... (1,697) (29,632) (39,814)
------ ------- -------
DECEMBER 31, 2002 11,018 136,055 202,163
====== ======= =======
66
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
ESTIMATED QUANTITIES OF PROVED DEVELOPED RESERVES
(IN THOUSANDS)
NATURAL GAS
OIL NATURAL GAS EQUIVALENT
(BBL) (MCF) (MCFE)
--------- ----------------- -----------------
December 31, 2000............................. 5,540 61,623 94,863
December 31, 2001............................. 4,675 44,040 72,090
December 31, 2002............................. 3,609 64,586 86,240
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.
67
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(IN THOUSANDS)
YEAR ENDING DECEMBER 31,
------------------------------------------------
2002 2001 2000
-------------- -------------- ------------
Future cash inflows......................................... $ 992,700 $ 615,131 $1,758,734
Future production costs..................................... (154,661) (149,636) (161,617)
Future development costs.................................... (110,474) (145,243) (162,277)
Future income taxes......................................... (72,648) -- (372,059)
--------- --------- ----------
Future net cash flows....................................... 654,917 320,252 1,062,781
--------- --------- ----------
Discount of future net cash flows at 10% per annum.......... (191,345) (88,224) (290,075)
--------- --------- ----------
Standardized measure of discounted future net flows......... 463,572 $ 232,028 $ 772,705
========= ========= ==========
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
weighted average prices of oil and gas at December 31, 2002, 2001 and 2000, used
in the above table, were $29.34, $16.40 and $26.36 per Bbl, respectively, and
$5.09, $2.60 and $11.32 per Mcf, respectively, and do not include the effect of
hedging contracts in place at period end.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands):
YEAR ENDING DECEMBER 31,
-----------------------------------------------
2002 2001 2000
-------------- ------------ -------------
Sales and transfers of oil and gas produced,
net of production costs................... (125,610) $(122,053) $(96,169)
Net changes in prices and production costs... 331,085 (661,871) 503,871
Extensions and discoveries, net of future
development and production costs.......... 50,085 130,512 214,022
Development costs during period and net change
in development costs...................... 28,474 40,674 39,736
Revision of previous quantity estimates...... 7,480 (106,813) (13,365)
Purchases of reserves in place............... -- 157,657
Sales of reserves in place................... (25,887) (172,072) (2,584)
Net change in income taxes................... (51,423) 270,510 (270,510)
Accretion of discount before income taxes.... 29,488 104,320 29,678
Changes in production rates (timing) and
other..................................... (12,148) (23,884) (857)
--------- --------- --------
Net change................................... $ 231,544 $(540,677) $561,479
========= ========= ========
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
68
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below are the names, ages and positions of our executive
officers and directors and a key consultant as of March 4, 2003. All directors
are elected for a term of one year and serve until their successors are elected
and qualified. All executive officers hold office until their successors are
elected and qualified.
Name Age Position with the Company
---- --- -------------------------
Scott D. Josey 45 Chairman of the Board and Chief Executive Officer
Judd Hansen 47 Vice President
David S. Huber 52 Consultant and Sr. Vice President
Cory L. Loegering 47 Vice President - Deepwater Operations
Dalton F. Polasek 51 Sr. Vice President
Mike C. van den Bold 40 Vice President - Development
Michael A. Wichterich 35 Vice President - Finance & Administration
Raymond M. Bowen, Jr. 43 Director
Craig A. Fox 47 Director
Michael S. McConnell 43 Director
Jesus G. Melendrez 43 Director
Greg F. Piper 40 Director
Mr. Josey is the Chairman of the Board and Chief Executive Officer of
Mariner Energy, Inc. From 2000 to 2002, Mr. Josey served as Vice President and
Co-Manager of Enron Energy Capital Resources, which provided debt, mezzanine,
and equity capital to energy companies. From 1995 to 2000, Mr. Josey was the
managing partner of Sagestone Capital, which provided investment-banking
services to the oil and gas industry and portfolio management services to
Commonfund Capital, a fund of funds for endowments and foundations. From 1993 to
1995, Mr. Josey was a Director with Enron Capital & Trade Resources Corp. in its
energy investment group. From 1982 to 1993, Mr. Josey was with Texas Oil and Gas
Corp., where he worked in all phases of its drilling, production, pipeline,
corporate planning and commercial activities. Mr. Josey is a member of the
Society of Petroleum Engineers and the Independent Producers Association of
America. Mr. Josey received his BS in mechanical engineering from Texas A&M
University, his MBA from the University of Texas, and his MS in petroleum
engineering from the University of Houston.
Mr. Hansen has served as Vice President of Mariner Energy, Inc. since
September 2002. Mr. Hansen has served as Manager of Drilling and Operations of
Aeon Exploration Company since its inception in 2001. He was employed as
Operations Manager, Gulf Coast Division for Basin Exploration, Inc. from
November 1997 until it was merged with Stone Energy in February 2001. From 1991
to 1997, he was employed in various engineering positions at Greenhill Petroleum
Corporation, including Senior Production Engineer and Workover/Completion
Superintendent. He began his career in 1978 as a Drilling Engineer for Shell Oil
Company.
Mr. Huber, a consultant, began his association with us in 1991 as a
deepwater project management consultant and is presently a Sr. Vice President
over the Deepwater department. Prior to 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. Loegering has been our Vice President of Deepwater Operations since
August 2002. He has been active in exploration and production in the Gulf of
Mexico since 1977. Cory began with Conoco in 1977 in the construction,
production and reservoir departments. In 1982 he joined Tenneco and held the
position of reservoir engineering supervisor and was later moved to a position
of senior engineer in the economic, planning and analysis group. He joined Hardy
Oil and Gas, now Mariner, in 1990. In 1992, Cory became active in deepwater with
the formulation and implementation of Mariner's objective to become a deepwater
operator. Cory holds a BS degree in Civil Engineering from Montana State
University.
69
Mr. Polasek has been Sr. Vice President of Mariner Energy, Inc. since
September 2002. Mr. Polasek has served as Vice President and Principal of Aeon
Exploration Company since its inception in 2001. He served as Vice President of
Gulf Coast Engineering for Basin Exploration, Inc. from 1996 until it was merged
with Stone Energy in February 2001. From 1994 to 1996, he was employed by SMR
Energy Income Funds as Vice President of Engineering. From 1991 to 1994, Mr.
Polasek served as the director of Gulf Coast Acquisitions/Engineering for
General Atlantic Resources. Prior to joining GA Resources, Mr. Polasek served as
manager of planning and business development for Mark Producing Company from
1983 to 1991. He began his career in 1975 as a reservoir engineer for Amoco
Production Company. Mr. Polasek is a Registered Professional Engineer in Texas
and a member of the Independent Producers Association of America, the American
Association of Drilling Engineers and the American Petroleum Institute.
Mr. van den Bold has been our Vice President of Development since
October 2001. Prior to obtaining his position, he was a Senior Development
Geologist. He was previously employed at British Borneo and British Petroleum
from 1986 through 2000 in various exploration and development positions. He
received his BS and MS degrees in geology from the Louisiana State University.
Mr. Wichterich has been our Vice President of Finance and
Administration since September 2001. Prior to obtaining this position he was the
Company's Corporate Controller from 1998 through August 2001. He was previously
employed at PricewaterhouseCoopers from 1989 through 1998 with ending title of
Senior Manager.
Mr. Bowen has served as a director since January 2000. He is currently
Executive Vice President and Chief Financial Officer of ENA and has held various
management positions with ENA since 1996. Prior to joining ENA, Mr. Bowen was a
Vice President and Senior Banker in Citicorp's Petroleum, Metals and Mining
Department in Houston.
Mr. Fox is currently Senior Vice President and Senior Engineer at the
Royal Bank of Scotland; prior to this position he was Vice President and
Technical Manager for Enron Energy Capital Resources. Mr. Fox received his
bachelor's of science degree in mechanical engineering from Texas A&M University
in 1977. He was employed with Houston Oil & Minerals, Tenneco Oil Company, and
Sandefer Oil & Gas as a reservoir and production engineer for 15 years before
joining Enron Finance Corp. in 1992 as a Senior Reservoir Engineer. He became a
Vice President in the engineering group supporting producer finance in 1995.
Mr. McConnell is Chairman and Chief Executive Officer of the Enron
Generation and Production Group, which is responsible for unregulated businesses
in North America. He also serves on the Executive Committee of Enron Corp. Mr.
McConnell graduated from the University of Oklahoma in 1982 with a BBA in
Petroleum Land Management with an emphasis on Law. He is a member of the Price
Business School Board of Advisors for the University of Oklahoma and is
currently serving on several Boards of Directors.
Mr. Melendrez is a Vice President of ENA and is responsible for the
execution and structuring of upstream transactions. Prior to joining ENA in
1999, Mr. Melendrez was Sr. Vice President of Enserch Energy Services, Inc. He
has held financial positions with several Enron affiliates since the early
1990's that involved loan restructuring and power marketing.
Mr. Piper is Managing Director of Enron North America and President and
Chief Operating Officer of the Generation and Production Group. Prior to his
current position, Mr. Piper was Managing Director and Chief Information Officer
of Enron Corp. Mr. Piper graduated from the Colorado School of Mines in 1986
with a Bachelor of Science degree in Petroleum Engineering and graduated from
the University of Texas in 1997 with a Masters in Business Administration.
The Shareholders' Agreement requires that the Board of Directors
include at least three nominees of the Management Stockholders. The remaining
board members are to include nominees of JEDI. See "Certain Relationships and
Related Transactions on page 72.
70
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth the annual compensation for Mariner's
Chief Executive Officer and the four other most highly compensated executive
officers for the three fiscal years ended December 31, 2002, two of which were
no longer with the Company at year end. These individuals are sometimes referred
to as the "named executive officers".
CURRENT YEAR
COMPENSATION UNDER
ANNUAL OTHER ANNUAL OUR OVERRIDING ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY COMPENSATION (1) ROYALTY PROGRAM (2) COMPENSATION (3)
------------------------------- ------ ------- --------------- ------------------ ---------------
Scott D. Josey 2002 90,909 1,825 0 306,452
Chairman of the Board & 2001 0 0 0 112,500
Chief Executive Officer 2000 0 0 0 0
Dave Huber 2002 0 0 1,120 283,407
Sr. Vice President, Deepwater 2001 0 0 6,276 295,788
2000 0 0 5,003 257,462
Mike Wichterich 2002 152,500 11,317 0 83,906
Vice President of Finance 2001 127,797 8,773 0 36,144
And Administration 2000 111,250 5,320 0 25,144
Mike van den Bold 2002 152,500 10,228 0 83,925
Vice President Exploration 2001 131,125 5,616 0 13,662
2000 59,000 750 0 81
Cory Loegering 2002 145,200 9,221 462 72,053
Vice President Deepwater 2001 128,999 4,992 2,641 270
2000 123,600 2,760 2,063 232
Kelly Zelikovitz 2002 0 0 0 428,084
Corporate Secretary and General 2001 0 0 0 408,481
Counsel 2000 0 0 0 218,815
Richard Clark 2002 46,873 0 1,232 334,223
Senior Vice President 2001 250,000 6,800 7,043 270
2000 235,000 3,680 5,596 210
(1) Amounts shown reflect our contribution under the discretionary
profit sharing feature of its Employee Capital Accumulation Plan. See "--401(k)
Plan". For each of the named executive officers, the aggregate amount of
perquisites and other personal benefits did not exceed the lesser of $50,000 or
10% of the officer's total annual salary and bonus and information with respect
thereto is not included.
(2) These amounts include the value conveyed 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 2002, 2001 or 2000.
(3) Amounts shown reflect insurance premiums paid by us with respect to
term life insurance for the benefit of the named executive officers and any
performance bonuses, severance payments and contract fees paid during the year.
In addition for Mr. Josey, the amounts also incurred payable to Enron North
America under a Services Agreement . Mr. Josey, in 2002, became an employee of
Mariner and is no longer working through the Services Agreement.
71
OPTIONS
None of the named executive officers exercised stock options in 2002.
The following table shows the number and value of options owned by our named
executive officers at December 31, 2002. All of the options described in the
table below have been issued under the Mariner Energy LLC 1996 Stock Option
Plan.
NUMBER OF
COMMON SHARES
UNDERLYING
UNEXERCISED OPTIONS AT
DECEMBER 31, 2001
-----------------
EXERCISABLE UNEXERCISABLE
----------- -------------
Dave Huber......................... 17,136 0
Mike Wichterich.................... 20,568 0
Mike van den Bold.................. 8,232 0
Cory Loegering..................... 48,456 0
Richard Clark...................... 167,928 0
Under the Mariner Energy LLC 1996 Stock Option Plan, a committee of the 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 our shareholders and us. 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 1,926,468
common shares are outstanding under the 1996 plan, 1,926,468 of which are
currently exercisable. The exercise price for outstanding options to purchase an
aggregate of 1,574,244 shares under the 1996 plan is $8.33 per share, and the
exercise price for options to purchase the remaining outstanding aggregate of
352,224 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, the board
of directors of Mariner Energy LLC is authorized to amend, alter or terminate
the 1996 plan.
EMPLOYMENT AGREEMENTS AND OTHER ARRANGEMENTS
All named executive officers are either employees at will with no
employment contracts or contractors with contract cancellable upon 30 days
notice, who became employees at will before March 4, 2002. Prior to becoming an
employee Mr. Josey and Mr. Keel performed services under a Service Agreement
with ENA at $25,000 per month. Mr. Josey became an employee at will in September
2002. Ms. Zelikovitz and Mr. Huber were performing their services under month to
month cancellable contracts. Ms. Zelikovitz resigned her position in December
2002.
The named executive officers are entitled to participate in any
medical, dental, life and accidental death and dismemberment insurance programs
and retirement, pension, ERISA severance, deferred compensation and other
benefit programs instituted by us from time to time. The employees are also
entitled to vacation, reimbursement of specified expenses. Mr. Huber, Mr.
Wichterich, Mr. Loegering and Mr. van den Bold each have retention agreements
which provide for the payments of $30,000, $25,000, $25,000 and $25,000,
respectively, to be paid on June 23, 2003. Mr. Josey is currently in negotiating
with the compensation committee to establish a retention agreement. The terms
and conditions of this agreement have not been established.
If we terminate a named executive officer's or any other employee
without cause, the named executive officer or employee will be entitled to,
among other things the higher of:
72
a. One week of pay for every $10,000 increment in base salary, rounded up
to the next $10,000 increment
b. One week of pay for every year of service rounded up to the next whole
year
c. An equal amount of the combined a. and b. above upon the signing of a
release of liability, or;
d. Any amounts owned under the our employee retention plan.
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
OVERRIDING ROYALTY PROGRAM
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. 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 .051562 % to .137500 %
before payout and from .206250 % to .550000 % after payout for the named
executive officers.
If we propose to sell or farm out all or a portion of our working
interest in a prospect to an unaffiliated third party 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.
73
The following table shows distributions received during the applicable
year by the named executive officers who are participants in the plan from
overriding royalty interests we granted to the officers during the last 15
years.
AGGREGATE CASH AMOUNTS RECEIVED
FROM PREVIOUSLY ASSIGNED
OVERRIDING
ROYALTY INTERESTS(1)
----------------------------------
NAME 2001 2001 2000
------------------- ---- ---- ----
Richard Clark................... $333,429 $544,237 $260,577
Dave Huber...................... 262,084 409,895 128,659
Cory Loegering.................. 119,191 189,063 79,596
----------------
(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". The above
amounts only include payments made by the Company. Certain participants
also receive overrides from third parties.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Mariner is an indirect wholly owned subsidiary of Mariner Energy LLC.
The following table sets forth the name and address of the only shareholder of
Mariner Energy LLC that is known by the Company to beneficially own more than 5%
of the outstanding common shares of Mariner Energy LLC, the number of shares
beneficially owned by such shareholder, and the percentage of outstanding shares
of common shares of Mariner Energy LLC so owned, as of March 1, 1999. As of
March 4, 2003, there were 13,928,308 common shares of Mariner Energy LLC
outstanding.
NAME AND ADDRESS NATURE OF AMOUNT AND
TITLE OF CLASS OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP PERCENT OF CLASS
-------------- ------------------- -------------------- ----------------
Common Stock of Joint Energy Development 13,334,186 95.7%
Mariner Energy LLC Investments Limited Partnership (1)
1400 Smith Street
Houston, Texas 77002
JEDI primarily invests in and manages certain natural gas and energy
related assets. JEDI'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 ENA,
which is a wholly-owned subsidiary of Enron Corp. The general partner of JEDI
exercises sole voting and investment power with respect to such shares.
The table appearing below sets forth information as of March 4, 2003,
with respect common shares of Mariner Energy LLC beneficially owned by each of
our directors, the named officers listed in the compensation table, a key
consultant and all directors and executive officers and such key consultant as a
group, and the percentage of outstanding common shares of Mariner Energy LLC so
owned by each.
74
AMOUNT AND NATURE
DIRECTORS, KEY CONSULTANT AND OF BENEFICIAL PERCENT
NAMED EXECUTIVE OFFICERS OWNERSHIP (1) OF CLASS
------------------------ ------------- --------
David S. Huber........................... 61,440 *
Cory Loegering........................... 17,172 *
All directors and executive and
----------------- --------
consultant as a group (2 persons)...... 78,612 *
----------------- --------
* Less than one percent.
(1) All shares are owned directly by the named person and such person has
sole voting and investment power with respect to such shares.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
THE ACQUISITION, THE SHAREHOLDERS' AGREEMENT AND RELATED MATTERS
Mariner Energy LLC, JEDI and each other shareholder of Mariner are
parties to the Amended and Restated Shareholders' Agreement (as amended, the
"Shareholders' Agreement").
Mariner Energy LLC has agreed to reimburse each Management Shareholder
who paid for equity in Mariner's predecessor by assignment of overriding royalty
interests for any additional taxes and related costs incurred by such Management
Shareholder to the extent, if any, that the transfer of the overriding royalty
interests does not qualify as a tax-free exchange under federal tax laws.
Enron 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 Mariner. In addition, ENA, JEDI and other affiliates of
ENA have provided, and may in the future provide, and ECT Securities Limited
Partnership, another affiliate of Enron, has assisted in arranging financing to
non-affiliated participants in the oil and natural gas industry who are or may
become competitors of Mariner. Because of these various possible conflicting
interests, the Shareholders' Agreement includes provisions designed to clarify
that generally Enron and its affiliates have no duty to make business
opportunities available to Mariner and no duty to refrain from conducting
activities that may be competitive with us.
Under the terms of the Shareholders' Agreement, Enron and its
affiliates (which include, without limitation, ENA and JEDI) are specifically
permitted to compete with Mariner, and neither Enron nor any of its affiliates
has any obligation to bring any business opportunity to Mariner.
ENRON BANKRUPTCY - Commencing on December 2, 2001, Enron Corp.
("Enron") and certain of its affiliates, including Enron North America Corp.
("ENA"), filed voluntary petitions for bankruptcy protection. We have been
informed that of our various direct or indirect owners, only Enron and ENA are
debtors in the bankruptcy. We do not know at this time if any other owners will
seek bankruptcy protection or what effect, if any, this may have on the
ownership of Mariner Energy LLC which owns 100% of Mariner Holdings, Inc. (our
direct parent) or on Joint Energy Development Investments Limited Partnership
("JEDI"), which owns approximately 96% of the issued and outstanding equity of
Mariner Energy LLC. Enron is the parent of ENA, and an affiliate of ENA is the
general partner of JEDI. JEDI is 100% owned by Enron and affiliates of ENA.
Accordingly, Enron may be deemed to control JEDI, Mariner Energy LLC, Mariner
Holdings and us. Additionally, five of the Company's directors are officers of
Enron or affiliates of Enron. Because of these various potentially conflicting
interests, ENA, the Company, JEDI and the minority shareholders of Mariner
Energy LLC have entered into an agreement that is intended to make clear that
Enron and its affiliates have no duty to make business opportunities available
to the Company.
Mariner Energy LLC's only asset is 100% of the common stock of Mariner
Holdings, Inc., our direct parent. The only asset of Mariner Holdings is 100% of
the common shares of Mariner.
75
Management cannot predict with certainty what impact Enron's bankruptcy
may have on us. However, it does believe that our assets and liabilities will
not become part of the Enron estate in bankruptcy. Although JEDI owns 96% of
Mariner Energy LLC's common shares, we, as a separate corporation own or lease
the assets used in its business and our management, separate from Enron, is
responsible for our day-to-day operations. Contractual provisions restrict Enron
access to our assets. We maintain our own accounting system as well as separate
debt ratings. We maintain our own separate and complete cash management system
and finance its operations separately from Enron, on both a short-term and
long-term basis. We file a consolidated tax return with Mariner Energy LLC.
Notwithstanding the above, we may have potential exposure to certain
liabilities and asset impairments as a result of Enron's bankruptcy. Portions
following Enron-related disclosures are based on discussions with Enron's legal
advisors and management, including members of our Board of Directors. Although
our management has implemented with Enron's legal advisor and management a
systematic method of identifying Enron matters which may have a material impact
on us, management cannot provide any assurance as the completeness or accuracy
of the information provided by or on behalf of Enron.
ORGANIZATION AND OWNERSHIP OF THE COMPANY - Through March 31, 1996, Hardy Oil &
Gas USA Inc. (the "Predecessor Company") was a wholly-owned subsidiary of Hardy
Holdings Inc., which is a wholly-owned subsidiary of Hardy Oil & Gas Plc ("Hardy
Plc"), a company incorporated in the United Kingdom. Pursuant to a stock
purchase agreement dated April 1, 1996, JEDI and ENA, together with members of
management of the Predecessor Company, formed Mariner Holdings, Inc. ("Mariner
Holdings"). Mariner Holdings then purchased from Hardy Holdings Inc. all of the
issued and outstanding stock of the Predecessor Company for a purchase price of
approximately $185.5 million (the "Acquisition"). After the Acquisition, the
name of the Predecessor Company was changed to Mariner Energy, Inc. In October
1998, JEDI and other shareholders exchanged all of their common shares of
Mariner Holdings, the Company's direct parent, for an equivalent ownership
percentage in common shares of Mariner Energy LLC. Mariner Energy LLC owns 100%
of Mariner Holdings.
76
The following chart represents our current ownership structure and affiliation
with Enron entities.
------------------ ------------------
Enron North ____________________100%__________________ Enron Corp.
America Corp. _____ ------------------
------------------ | |
| | |
| | |
| | |
| | ------------------ |
| |________ JILP-LP, Inc. |
| ------------------ |
| | |
| | (Asset Specific) |
| | |
| ------------------ |
| Ponderosa |
| Assets LP LP
| ------------------ |
| | |
| | (Limited Partnership) |
| | |
------------------ ------------------ |
Enron Capital _____GP______ Enron Capital |
Corp. ________ Management LP |
------------------ | ------------------ |
| | |
| GP |
| | |
------------------ | ------------------ |
Enron Capital _____| Joint Energy |
Management, LLC ____SLP______ Development ___________________|
------------------ Investments (JEDI)
------------------
|
96%
|
------------------ ------------------
Mariner _____4%_____ Employees and
Energy, LLC Former Employees
------------------ ------------------
|
100%
|
------------------
Mariner
Holdings, Inc.
------------------
|
100%
|
------------------
Mariner
Energy, Inc.
------------------
Subsequent to the Acquisition, Mariner Energy LLC, Mariner Holdings and
Mariner have each entered into various financing and operating transactions with
affiliates. In addition the Company may have from time to time engaged in
various commercial transactions and have various commercial relationships with
Enron and certain affiliates of Enron, such as holding and exploring, exploiting
and developing joint working interests in particular prospects and properties
and entering into other oil and gas related or financial transactions. Certain
of the Company's third-party debt instruments and arrangements 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 and its affiliates are, and anticipates that
any future agreements with Enron and its affiliates will be, on terms no less
favorable to the Company than would be obtained in an agreement with a third
party. Below is a summary of key transactions between the Company and affiliate
entities.
77
MARINER ENERGY LLC
ENA Affiliate Term Loan - In March 2000, Mariner Energy LLC established
an unsecured term loan with ENA to repay amounts outstanding under various
affiliate credit facilities at Mariner Energy LLC and Mariner and to provide
additional working capital. The additional working capital of $55 million was
contributed to Mariner in 2000. The loan bears interest at 15%, which interest
accrues and is added to the loan principal. Repayment of the balance of loan
principal and accrued interest, which was approximately $164.4 million as of
December 31, 2002, is due March 20, 2004. In conjunction with the loan
agreement, two five-year warrants were issued to ENA providing the right to
purchase up to 900,000 of common shares of Mariner Energy LLC for $0.01 per
share.
Covenants in Mariner's Senior Subordinated Notes restrict the funds of
Mariner that can be distributed to Mariner Energy LLC. Accordingly, Mariner
Energy LLC is restricted in its ability to repay the unsecured Term Loan or to
distribute earnings to its shareholders. In the event Mariner Energy LLC is
unable to restructure or extend the maturity of its obligations prior to March
2004 it would either default under the Term Loan or be forced to sell its
interest in Mariner or cause Mariner to sell a substantial portion of its assets
to repay any outstanding Senior Subordinated Notes so that it could distribute
any remaining cash proceeds to Mariner Energy LLC to be used to repay the Term
Loan.
We have been informed by Enron's legal advisors and management that the
Term Loan and warrants were transferred from ENA to an ENA affiliate, which
affiliate is part of a finance structure formed by ENA. Because debt obligations
of the finance structure are in default and ENA therefore does not have complete
control over decisions made by the ENA affiliate, it may be difficult for
Mariner Energy LLC to obtain any consents, waivers or amendments needed from the
ENA affiliate in connection with the Term Loan or the warrants.
MARINER HOLDINGS, INC.
1998 Equity Investment - In June 1998, Mariner Holdings issued
additional equity to its existing shareholders, including JEDI, for
approximately $14.58 per share, for a net investment of $28.8 million, all of
which was contributed to Mariner. Mariner Holdings 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 Limited Partnership.
MARINER ENERGY, INC.
Oil and Gas Production Sales to ENA or Affiliates - During the three
years ending December 31, 2002, 2001 and 2000, sales of oil and gas production
to ENA or affiliates were $56.4million, $50.2 million and $73.4 million,
respectively. These sales were generally made on 1 to 3 month contracts. At the
time ENA filed its petition for bankruptcy protection, the Company immediately
ceased selling its physical production to ENA, however, we continued to sell our
production to Bridgeline which ENA owned a minority interest. All amounts sold
to this party have been collected. As of December 31, 2002, we had an
outstanding receivable for $3 million from ENA. This amount was not paid as
scheduled and is still outstanding. Mariner has submitted a proof of claim to
the bankruptcy court for amounts owed to it by ENA. The Company has estimated
100% of this balance is uncollectible and has recorded a full allowance and
related expense.
78
Management Activities - We engage in price risk management activities
from time to time. These activities are intended to manage our exposure to
fluctuations in commodity prices for natural gas and crude oil. We primarily
utilize price swaps and costless collars as a means to manage such risk.
Historically, all of our hedging contracts were with ENA. As a result of ENA's
bankruptcy, the contracts are currently in default. The November 2001 through
April 30, 2002 settlements for oil and gas have not been collected. In addition,
on May 14, 2002, we elected under its Master Service Agreement with ENA to
terminate all open contracts. The effect of this termination is to fix the
nominal value on all remaining contracts on May 14, 2002. Subsequent to this
termination, the value of all oil and natural gas unpaid hedge contracts was
$7.7 million. We have estimated 100% of this balance is uncollectible and has
recorded a full allowance. We have submitted a proof of claims to the bankruptcy
court for amounts owed under this agreement. In accordance with Statement of
Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 137 and No. 138, we
have de-designated our contracts effective December 2, 2001 and are recognizing
all market value changes subsequent to such de-designation in our earnings. The
value recorded up to the time of de-designation and included in Accumulated
Other Comprehensive Income ("AOCI"), will reverse out of AOCI and into earnings
as the original corresponding production, as hedged by the contracts, is
produced. For the year ending December 31, 2002 approximately $23.2 million has
reversed out to earnings. As of December 31, 2002, $2.6 million remained in AOCI
to be reversed out to earnings.
The following table sets forth the results of hedging transactions
during the periods indicated that were made with ENA (all amounts shown are
non-cash items):
YEAR ENDING DECEMBER 31,
-----------------------------
2002 2001 2000
------- -------- --------
Natural gas quantity hedged (Mmbtu).......................... 18,090 17,733 19,569
Increase (decrease) in natural gas sales (thousands)......... $20,413 $ (5,523) $(21,364)
Crude oil quantity hedged (MBbls)............................ 446 752 1,059
Increase (decrease) in crude oil sales (thousands)........... $ 2,787 $ 2,393 $(14,053)
79
Supplemental Affiliate Data - provided below is a supplemental balance sheet and
income statement for affiliate entities:
DECEMBER 31, 2002 DECEMBER 31, 2001
----------------- -----------------
AMOUNTS AMOUNTS
BALANCE SHEET DATA (IN MILLIONS) (IN MILLIONS)
------------------ TOTAL TOTAL
----------- -----------
RELATED PARTY RECEIVABLE:
Derivative Asset $ -- $ 2.5 $ --
Settled Hedge Receivable -- 0.4 --
Oil and Gas Receivable 8.2 8.2 0.3 3.2
ACCRUED LIABILITIES:
Transportation Contract -- -- 0.9 --
Service Agreement 0.6 0.6 0.3 1.2
STOCKHOLDER'S EQUITY:
--------------------
Common Stock $ .001 -- $ .001 --
Additional Paid in Capital $ 227.3 $227.3
Accumulated other Comprehensive Income $ 2.3 $229.6 $ 25.8 $253.1
YEAR ENDED
DECEMBER 31
---------------------------
INCOME STATEMENT DATA
2002 2001
----------- ------------
Oil and Gas Sales $ 56.4 $ 50.2
General and Administrative Expenses 0.4 0.2
Transportation Expenses 2.7 4.2
Unrealized loss and other non-cash 3.2 29.5
derivative instrument adjustments
As a result of the Enron and ENA bankruptcies, among other
implications, we may not be able to obtain credit from banks or trade vendors or
enter into hedging arrangements on acceptable terms. To date, our operations
have not been materially affected by the bankruptcies; however, our ability to
enter into certain transactions including purchase or sale arrangements and to
conduct significant capital programs may be affected in the future Oil and gas
sales and the related accounts receivable for the year ending December 31, 2002
relate to sales made to a minority owed affiliate of Enron.
CONTROLLED GROUP LIABILITY
On November 12, 2002, Enron's legal advisors and management informed us
that we may be an Enron Corp. Controlled Group Member as defined under the
Employee Retirement Income Security Act of 1974 ("ERISA") due to Enron's
indirect ownership interest in Mariner Energy LLC. Enron management has not made
a final determination if we are in fact a Controlled Group Member. Because of
numerous ownership issues within the Enron Group, we are unable to make our own
determination as to whether we agree or disagree that we are a Controlled Group
Member. In the event we are a Controlled Group Member, we may have potential
liability for certain employee benefit plan obligations of Enron discussed
below.
Pension Plans - Applicable federal law authorizes the Pension Benefit
Guaranty Corporation ("PBGC") to institute proceedings in federal district court
for the termination of a pension plan if it determines the plan has failed to
comply with minimum funding standards, the plan is or will be unable to pay
benefits when due, or the failure to terminate the plan may reasonably be
expected to unreasonably increase the possible long-run loss to the PBGC.
Federal law also authorizes the sponsor of a pension plan to terminate the plan
at a time when the plan is underfunded, subject to PBGC or court approval.
80
Based on discussions with Enron management, it is our management's
understanding that, as of December 31, 2001 the assets of Enron's pension plan
(the "Enron Plan") were less than the present value of all accrued benefits by
approximately $52 million on a SFAS No. 87 basis and approximately $182 million
on a plan termination basis. Further, Enron's management has informed Mariner
management that the PBGC has filed claims in the Enron bankruptcy cases. The
claims are duplicative in nature, representing unliquidated claims for PBGC
insurance premiums (the "Premium Claims") and unliquidated claims for due but
unpaid minimum funding contributions (the "Contribution Claims") under the
Internal Revenue Code of 1986, as amended (the "Tax Code") 29 U.S.C.Sections
412(a) and 1082 and claims for unfunded benefit liabilities (the "UBL" Claims").
Enron and the relevant sponsors of the defined benefit plans are current on
their PBGC premiums and their contributions to the pension plans. Therefore,
Enron has valued the Premium Claims and the Contribution Claims at $0. The total
amount of the UBL Claims is $305.5 million (including $271 million for the Enron
Plan). In addition Enron Management has informed Mariner Management that the
PBGC has informally alleged in pleadings filed with the bankruptcy court that
the UBL Claim related to the Enron Plan could increase by as much as 100%. PBGC
has provided no support (statutory or otherwise) for this assertion and Enron
Management disputes the validity of any such claim. Because the Enron Plan is
under funded and Enron is in bankruptcy, in certain circumstances the Enron Plan
may be terminated and taken control of by the PBGC upon approval of a Federal
District Court.
Mariner's employees have not been participants in the Enron Plan.
However, upon termination of a pension plan, all of the members of the
controlled group of the plan sponsor become jointly and severally liable for the
plan are under funding. The PBGC can demand payment from one or more of the
members of the controlled group. If payment is not made, a lien in favor of the
PBGC automatically arises against all of the assets of that member of the
controlled group. The amount of the lien is equal to the lesser of the
underfunding or 30% of the aggregate net worth of all of the Controlled Group
members. In addition, if the sponsor of a pension plan does not timely satisfy
its minimum funding obligation to the pension plan, once the aggregate missed
amounts exceed $1 million, a lien in favor of the plan in the amount of the
missed funding automatically arises against the assets of every member of the
Controlled Group. In either case, the PBGC may file to perfect the lien and
attempt to enforce it against the assets of members of the Enron controlled
group. Mariner has been informed by Enron that Enron's management believes that
the lien would be subordinate to prior perfected liens on the assets of the
member of the controlled group. Based on discussions with Enron's management,
Mariner's management understands that Enron has made all required contributions
to date through October 15, 2002. Enron's management has advised us that it
intends to make its next contribution, due in the first quarter of 2003.
Management cannot predict the outcome of the above matters or estimate
any potential loss. In addition, if the PBGC did look solely to Mariner to pay
any amount with respect to the Enron Plan, Mariner would exercise all legal
rights, available to it to defend against such a demand and to recover any
contributions from the other solvent members of the Controlled Group. No
reserves have been established by Mariner for any amounts related to this issue.
Mariner has also been informed by Enron management that Enron has
contacted the PBGC as well as Unsecured Creditors Committee regarding their
intention to terminate the Enron Plan, subject to approval by such parties, the
bankruptcy court and authorization to fully fund the Enron Plan in accordance
with its terms. If approved Enron would fully fund the Enron Plan in accordance
with the terms, the plan could be terminated without any liability to Mariner.
Enron has also stated that it believes it has the necessary funds to consummate
such a termination. In addition to the extent that entities in the Controlled
Group are sold prior to termination of the Plan, proceeds of the sale of such
entities may be available to satisfy this liability. Enron estimates proceeds
from such sale of Enron Control Group entities would far exceed any plan
obligations.
Retiree Health Benefits - Under COBRA, if certain retirees of Enron
lose coverage under Enron's group health plan due to Enron's bankruptcy
proceedings, they would be entitled to elect continuation of their health
coverage in a group plan maintained by Enron or a member of its Controlled
Group. Mariner's employees have not participated in this plan. Mariner
management understands, based on discussions with Enron management, that Enron
had provided a plan for retiree health insurance and that the actuarial
liability for such coverage was approximately $70 million as of December 31,
2001. Management further understands that to meet its obligation, Enron, at
December 31, 2001, had set aside approximately $34 million of assets in a VEBA
trust, which may be protected under ERISA from Enron's creditors, leaving an
unfunded liability of approximately $36 million.
81
In the event that Enron terminates its retiree group health plan, the
retirees must be provided the opportunity to purchase continuing coverage from
Enron's group health plan, if any, or the most appropriate existing group health
plan of another member of the Enron controlled group. Retirees electing to
purchase COBRA coverage would be provided the same coverage that is provided to
similarly situated retirees under the appropriate existing plan. Retirees
electing to purchase COBRA coverage would be required to pay for the coverage,
up to an amount not to exceed 102% of the cost of coverage for similarly
situated beneficiaries. Retirees are not required to purchase coverage under
COBRA. Retirees may, instead, shop for coverage from third party sources and
determine which is the least expensive coverage.
Management cannot predict the outcome of the above matter or estimate
any potential loss. However, management believes that in the event Enron
terminates coverage, any liability to Mariner associated with the number of
retirees that choose to remain under Enron's retiree health plan will not be
material. No reserves have been established by Mariner for any amounts related
to this issue.
SALE OF ENRON INTEREST IN MARINER
On May 3, 2002, Enron presented to its Unsecured Creditors' Committee a
proposal under which certain of Enron's core energy assets, including JEDI's
ownership of Mariner Energy LLC, would be separated from Enron's bankruptcy
estate and operated prospectively as a new integrated power and pipeline
company.
On August 27, 2002, Enron announced that it had commenced a formal
sales process for its interests in certain major assets, including JEDI's
ownership of Mariner Energy LLC. In its announcement, Enron indicated that it
was extending invitations to visit electronic data rooms containing information
on 12 of its most valuable businesses, including Mariner, to a broad universe of
potential bidders with whom Enron had executed confidentiality agreements.
Enron has announced its intent to move forward with the sale of four
companies, however, it continues to evaluate its alternatives with regard to
Mariner. Management is unable to give assurances that the Company will be or not
be sold in the near future and there can be no assurance as to whether JEDI's
ownership of Mariner Energy LLC will be sold in the future.
ITEM 14. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures. The Company's
Chief Executive Officer and Vice President of Finance & Administration have
evaluated the effectiveness of the Company's disclosure controls and procedures
(as such term is defined in Rules 13a-14(c) and 15d-14(c) under the Securities
Exchange Act of 1934, as amended (the "Exchange Act")) as of a date within 90
days prior to the filing date of this annual report (the "Evaluation Date").
Based on such evaluation, such officers have concluded that, as of the
Evaluation Date, the Company's disclosure controls and procedures are effective
in alerting them on a timely basis to material information relating to the
Company required to be included in the Company's reports filed or submitted
under the Exchange Act. Although the Company's Chief Executive Officer and Vice
President - Finance & Administration have concluded that the disclosure controls
and procedures are effective, disclosures relating to Enron and the effects of
its bankruptcy on Mariner were provided by Enron's management and its legal
advisors. The Chief Executive Officer and Vice President - Finance &
Administration rely on the information they provide for disclosure purposes.
(b) Changes in Internal Controls. Since the Evaluation Date, there have
not been any significant changes in the Company's internal controls or in other
factors that could significantly affect such controls.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) DOCUMENTS INCLUDED IN THIS REPORT:
1. FINANCIAL STATEMENTS and 2. FINANCIAL STATEMENT SCHEDULES
These documents are listed in the Index to Financial Statements in Item
8 hereof.
82
3. EXHIBITS
Exhibits designated by the symbol * have been previously filed on prior
years Form 10-K. All exhibits not so designated are incorporated by
reference to a prior filing as indicated.
Exhibits designed by the symbol ** are filed with this Annual Report on
Form 10-K.
Exhibits designated by the symbol " are management contracts or
compensatory plans or arrangements that are required to be filed with
this report pursuant to this Item 14.
The Company undertakes to furnish to any stockholder so requesting a
copy of any of the following exhibits upon payment to the Company of
the reasonable costs incurred by Company in furnishing any such
exhibit.
3.1* Amended and Restated Certificate of Incorporation of
the Registrant, as amended.
3.2* Bylaws of Registrant, as amended.
4.1(a) Indenture, dated as of August 1, 1996, between the
Registrant and United States Trust Company of New
York, as Trustee.
4.2(d) First Amendment to Indenture, dated as of January 31,
1998, between the Registrant and United States Trust
Company of New York, as Trustee.
4.3(a) Note, dated August 12, 1996, in the principal amount
of up to $45,000,000, made by the Registrant in favor
of Nations Bank of Texas, N.A.
4.4(a) Note, dated August 12, 1996, in the principal amount
of up to $45,000,000, made by the Registrant in favor
of Toronto Dominion (Texas), Inc.
4.5(a) Note, dated August 12, 1996, in the principal amount
of up to $30,000,000, made by the Registrant in favor
of The Bank of Nova Scotia.
4.6(a) Note, dated 12, 1996, in the principal amount of up
to $30,000.000, made by the Registrant in favor of
ABN AMRO Bank, N.V., Houston Agency.
4.7(a) Form of the Registrant's 10 1/2% Senior Subordinated
Note Due 2006, Series B.
4.8* Credit and Subordination Agreement dated as of
September 2, 1998 between Mariner Holdings, Inc. and
Enron Capital & Trade Resources Corp.
4.9(f) 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.
4.10(f) 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.).
4.11(f) Revolving Credit Agreement dated as of April 15,
1999, between Mariner Energy, Inc. and Enron North
America Corp. (formerly Enron Capital & Trade
Resources Corp.).
4.12(g) Term Loan Agreement, dated March 21, 2000, between
Mariner Energy LLC and Enron North America Corp.
4.12(h) First Amendment to Term Loan Agreement between
Mariner Energy LLC and ECTMI Trutta Holdings LP dated
September 6, 2002
10.1* Amended and Restated Shareholders' Agreement, dated
October 12, 1998, among Mariner Energy LLC, Enron
Capital & Trade Resources Corp., Mariner Holdings,
Inc., Joint Energy Development Investments Limited
Partnership and the other shareholders of Mariner
Energy LLC.
10.2* Gas Gathering Agreement, dated December 29, 1999,
between MEGS LLC, Mariner Energy, Inc. and Burlington
Resources.
83
10.3(f) Amended and Restated Credit Agreement, dated June 28,
1999, between Mariner Energy and Bank of America,
N.A.
10.10** Retention Agreement between Mariner Energy Inc. and
Dave Huber dated September 27, 2003.
10.11(a)[] Mariner Holdings, Inc. 1996 Stock Option Plan
(assumed by Mariner Energy LLC).
10.12(a)[] Form of Incentive Stock Option Agreement (pursuant
to the Mariner Holdings, Inc. 1996 Stock Option Plan,
assumed by Mariner Energy LLC).
10.13** List of executive officers who are parties to an
Incentive Stock Option Agreement.
10.14(a)[] Form of Nonstatutory Stock Option Agreement
(pursuant to the Mariner Holdings, Inc. 1996 Stock
Option Plan, assumed by Mariner Energy LLC).
10.15** List of executive officers who are parties to a
Nonstatutory Stock Option Agreement.
10.16(a)[] Nonstatutory Stock Option Agreement, dated June 27,
1996, between the Registrant and David S. Huber.
10.23** Retention Agreement between Mariner Energy Inc. and
Mike Wichterich dated September 27, 2003.
10.28(g) First Amendment to Amended and Restated Credit
Agreement, dated December 31, 1999 by and among
Mariner Energy, Inc., Bank of America, N.A., Toronto
Dominion (Texas), Inc., Bank of Nova Scotia, and
ABN-AMRO Bank, N.V.
10.29(g)[] Second Amendment to Amended and Restated Consulting
Services Agreement, effective as of January 1, 2000,
between Mariner Energy, Inc. and David S. Huber.
10.30(g)[] Third Amendment to Amended and Restated Consulting
Services Agreement, effective as of March 4, 2002,
between Mariner Energy, Inc. and David S. Huber.
10.31** Retention Agreement between Mariner Energy Inc. and
Mike van den Bold dated September 27, 2003.
10.32** Retention Agreement between Mariner Energy Inc. and
Cory Loegering dated September 27, 2003.
10.39(g) Corporate Services Agreement, dated August 23, 2001,
between the Mariner Energy, Inc. and Enron North
America Corp.
23.1** Consent of Ryder Scott Company.
23.2** Ryder Scott Company Letter of Estimated Proved
Reserves dated March 6, 2002.
99.1 Certificate of Chairman of Board and Chief Executive
Officer
99.2 Certificate of Vice President of Finance and
Administration
(a) Incorporated by reference to the Company's Registration
Statement on Form S-4 (Registration No. 333-12707), filed
September 25, 1996.
(b) Incorporated by reference to Amendment No. 1 to the Company's
Registration Statement on Form S-4 (Registration No.
333-12707), filed December 6, 1996.
(c) Incorporated by reference to Amendment No. 2 to the Company's
Registration Statement on Form S-4 (Registration No.
333-12707), filed December 19, 1996.
(d) Incorporated by reference to the Company's Annual Report on
Form 10-K for the year ended December 31, 1996 (Registration
No. 333-12707) filed March 31, 1997.
(e) Incorporated by reference to the Mariner Energy LLC November
4, 1999 filing on Forms S-1 (Registration No. 333-87287).
84
(f) Incorporated by reference to the Mariner Energy, Inc. March
31, 2001, June 30, 2001 or September 30, 2001 quarterly
filings on Form 10-Q.
(g) Incorporated by reference to the Mariner Energy Inc. December
31, 2001 annual filing on form 10-K.
(h) Incorporated by reference to the Mariner Energy, Inc. March
31, 2002, June 30, 2002 or September 30, 2002 quarterly
filings on Form 10-Q.
(b) REPORTS ON FORM 8-K:
The Company filed no reports on Form 8-K during the quarter ended
December 31, 2002.
85
GLOSSARY
The terms defined in this glossary are used throughout this annual
report.
Bbl. One stock tank barrel, or 42 U.S. Gallons liquid volume, used
herein 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).
"behind the pipe" Hydrocarbons in a potentially producing horizon
penetrated by a well bore the production of which has been postponed pending the
production of hydrocarbons from another formation penetrated by the well bore.
These hydrocarbons are classified as proved but non-producing reserves.
2-D. (Two-Dimensional Seismic) -- Geophysical data that depicts the
subsurface strata in two dimensions.
3-D. (Three-Dimensional Seismic) -- 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 can be
achieved using 2-D seismic.
"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. The Company uses the word to refer to
Deepwater wells which 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 the Company
distinguishes its development wells on its own properties from such exploitation
wells.
"exploratory well" A well drilled in unproven or semi-proven territory
for the purpose of ascertaining the presence underground of a commercial
petroleum deposit and which can be contrasted with a "development well".
"farm-in" A term used to describe the action taken by the person to
whom a transfer of an interest in a leasehold in an oil and gas property is made
pursuant to a farmout agreement.
"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 who is
not desirous of drilling at the time agrees to assign the leasehold interest, or
some portion of it, to another operator who is desirous of drilling the tract.
The assignor in such a transaction 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,
drilling or completion expenses or other "finding costs".
86
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
MMBls. One million barrels of crude oil or other liquid hydrocarbons
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).
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).
NYMEX. New York Mercantile Exchange.
"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 Securities and Exchange
Commission practice, to determine their "present value". The present value is
shown to indicate the effect of time on the value of the revenue stream and
should not be construed as being the fair market value of the properties.
Estimates of future net revenues are made using oil and natural gas prices and
operating costs at the date indicated and held constant for the life of the
reserves.
"producing well" or "productive well" A well that is producing oil or
natural gas or that is capable of production without further capital
expenditure.
"proved developed reserves" Proved developed reserves are those
quantities of crude oil, natural gas and natural gas liquids that, upon analysis
of geological and engineering data, are expected with reasonable certainty to be
recoverable in the future from known oil and natural gas reservoirs under
existing economic and operating conditions. This classification includes: (a)
proved developed producing reserves, which are those expected to be recovered
from currently producing zones under continuation of present operating methods;
and (b) proved developed non-producing reserves, which consist of (i) reserves
from wells 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 (ii) reserves currently behind the pipe in existing wells which are expected
to be productive due to both the well log characteristics and analogous
production in the immediate vicinity of the well.
"proved reserves" The estimated quantities of crude oil, natural gas
and other hydrocarbon liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
"proved undeveloped 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 of the proceeds from the sale thereof. Such an interest
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.
87
"unitized" or "unitization" Terms used to denominate the joint
operation of all or some portion of a producing reservoir, particularly where
there is separate ownership of portions of the rights in a common producing
pool, in order to carry on certain production techniques, maximize reservoir
production and serve conservation interests economically.
"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 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.
88
SIGNATURES
The registrant has duly caused this report to be signed on its behalf
by the undersigned, hereunto duly authorized.
April 16, 2003
MARINER ENERGY, INC.
by: /s/ Scott D. Josey
------------------
Scott D. Josey,
Chairman of the Board & Chief Executive Officer
This report has been signed below by the following persons on behalf of
the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Scott D. Josey Chairman of the Board April 15, 2003
--------------------------------
Scott D. Josey
/s/ Judd Hansen Vice President April 15, 2003
--------------------------------
Judd Hansen
/s/ David S. Huber Sr. Vice President April 15, 2003
--------------------------------
David S. Huber
/s/ Cory L. Loegering Vice President - Deepwater Operations April 15, 2003
--------------------------------
Cory L. Loegering
/s/ Dalton F. Polasek Sr. Vice President April 15, 2003
--------------------------------
Dalton F. Polasek
/s/ Mike C. van den Bold Vice President - Development April 15, 2003
--------------------------------
Mike C. van den Bold
/s/ Michael A. Wichterich Vice President - Finance & Administration April 15, 2003
--------------------------------
Michael A. Wichterich
/s/ Raymond M. Bowen, Jr. Director April 15, 2003
--------------------------------
Raymond M. Bowen, Jr.
/s/ Craig A. Fox Director April 15, 2003
--------------------------------
Craig A. Fox
/s/ Michael S. McConnell Director April 15, 2003
--------------------------------
Michael S. McConnell
/s/ Jesus G. Melendrez Director April 15, 2003
--------------------------------
Jesus G. Melendrez
/s/ Greg F. Piper Director April 15, 2003
--------------------------------
Greg F. Piper
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT
No annual report covering the Registrant's last fiscal year or proxy
statement, form of proxy or other proxy soliciting material with respect to any
annual or other meeting of security holders has been sent to the Company's
security holders.
CERTIFICATION OF
CHAIRMAN OF THE BOARD / CEO
I, Scott D. Josey, certify that:
1. I have reviewed this annual report on Form 10-K of Mariner Energy, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date.;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: April 15, 2003
/s/ Scott D. Josey
--------------------------------
Scott D. Josey
Chairman of the Board / CEO
CERTIFICATION OF
VICE PRESIDENT - FINANCE & ADMINISTRATION
I, Michael A. Wichterich, certify that:
1. I have reviewed this annual report on Form 10-K of Mariner Energy, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report.;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report.;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date.
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: April 15, 2003
/s/ Michael A. Wichterich
--------------------------------
Michael A. Wichterich
Vice President - Finance & Administration
EXHIBIT INDEX
3.1* Amended and Restated Certificate of Incorporation of
the Registrant, as amended.
3.2* Bylaws of Registrant, as amended.
4.1(a) Indenture, dated as of August 1, 1996, between the
Registrant and United States Trust Company of New
York, as Trustee.
4.2(d) First Amendment to Indenture, dated as of January 31,
1998, between the Registrant and United States Trust
Company of New York, as Trustee.
4.3(a) Note, dated August 12, 1996, in the principal amount
of up to $45,000,000, made by the Registrant in favor
of Nations Bank of Texas, N.A.
4.4(a) Note, dated August 12, 1996, in the principal amount
of up to $45,000,000, made by the Registrant in favor
of Toronto Dominion (Texas), Inc.
4.5(a) Note, dated August 12, 1996, in the principal amount
of up to $30,000,000, made by the Registrant in favor
of The Bank of Nova Scotia.
4.6(a) Note, dated 12, 1996, in the principal amount of up
to $30,000.000, made by the Registrant in favor of
ABN AMRO Bank, N.V., Houston Agency.
4.7(a) Form of the Registrant's 10 1/2% Senior Subordinated
Note Due 2006, Series B.
4.8* Credit and Subordination Agreement dated as of
September 2, 1998 between Mariner Holdings, Inc. and
Enron Capital & Trade Resources Corp.
4.9(f) 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.
4.10(f) 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.).
4.11(f) Revolving Credit Agreement dated as of April 15,
1999, between Mariner Energy, Inc. and Enron North
America Corp. (formerly Enron Capital & Trade
Resources Corp.).
4.12(g) Term Loan Agreement, dated March 21, 2000, between
Mariner Energy LLC and Enron North America Corp.
4.12(h) First Amendment to Term Loan Agreement between
Mariner Energy LLC and ECTMI Trutta Holdings LP dated
September 6, 2002
10.1* Amended and Restated Shareholders' Agreement, dated
October 12, 1998, among Mariner Energy LLC, Enron
Capital & Trade Resources Corp., Mariner Holdings,
Inc., Joint Energy Development Investments Limited
Partnership and the other shareholders of Mariner
Energy LLC.
10.2* Gas Gathering Agreement, dated December 29, 1999,
between MEGS LLC, Mariner Energy, Inc. and Burlington
Resources.
10.3(f) Amended and Restated Credit Agreement, dated June 28,
1999, between Mariner Energy and Bank of America,
N.A.
10.10** Retention Agreement between Mariner Energy Inc. and
Dave Huber dated September 27, 2003.
10.11(a)[] Mariner Holdings, Inc. 1996 Stock Option Plan
(assumed by Mariner Energy LLC).
10.12(a)[] Form of Incentive Stock Option Agreement (pursuant
to the Mariner Holdings, Inc. 1996 Stock Option Plan,
assumed by Mariner Energy LLC).
10.13** List of executive officers who are parties to an
Incentive Stock Option Agreement.
10.14(a)[] Form of Nonstatutory Stock Option Agreement
(pursuant to the Mariner Holdings, Inc. 1996 Stock
Option Plan, assumed by Mariner Energy LLC).
10.15** List of executive officers who are parties to a
Nonstatutory Stock Option Agreement.
10.16(a)[] Nonstatutory Stock Option Agreement, dated June 27,
1996, between the Registrant and David S. Huber.
10.23** Retention Agreement between Mariner Energy Inc. and
Mike Wichterich dated September 27, 2003.
10.28(g) First Amendment to Amended and Restated Credit
Agreement, dated December 31, 1999 by and among
Mariner Energy, Inc., Bank of America, N.A., Toronto
Dominion (Texas), Inc., Bank of Nova Scotia, and
ABN-AMRO Bank, N.V.
10.29(g)[] Second Amendment to Amended and Restated Consulting
Services Agreement, effective as of January 1, 2000,
between Mariner Energy, Inc. and David S. Huber.
10.30(g)[] Third Amendment to Amended and Restated Consulting
Services Agreement, effective as of March 4, 2002,
between Mariner Energy, Inc. and David S. Huber.
10.31** Retention Agreement between Mariner Energy Inc. and
Mike van den Bold dated September 27, 2003.
10.32** Retention Agreement between Mariner Energy Inc. and
Cory Loegering dated September 27, 2003.
10.39(g) Corporate Services Agreement, dated August 23, 2001,
between the Mariner Energy, Inc. and Enron North
America Corp.
23.1** Consent of Ryder Scott Company.
23.2** Ryder Scott Company Letter of Estimated Proved
Reserves dated March 6, 2002.
99.1 Certificate of Chairman of Board and Chief Executive
Officer
99.2 Certificate of Vice President of Finance and
Administration
(a) Incorporated by reference to the Company's Registration
Statement on Form S-4 (Registration No. 333-12707), filed
September 25, 1996.
(b) Incorporated by reference to Amendment No. 1 to the Company's
Registration Statement on Form S-4 (Registration No.
333-12707), filed December 6, 1996.
(c) Incorporated by reference to Amendment No. 2 to the Company's
Registration Statement on Form S-4 (Registration No.
333-12707), filed December 19, 1996.
(d) Incorporated by reference to the Company's Annual Report on
Form 10-K for the year ended December 31, 1996 (Registration
No. 333-12707) filed March 31, 1997.
(e) Incorporated by reference to the Mariner Energy LLC November
4, 1999 filing on Forms S-1 (Registration No. 333-87287).
(f) Incorporated by reference to the Mariner Energy, Inc. March
31, 2001, June 30, 2001 or September 30, 2001 quarterly
filings on Form 10-Q.
(g) Incorporated by reference to the Mariner Energy Inc. December
31, 2001 annual filing on form 10-K.
(h) Incorporated by reference to the Mariner Energy, Inc. March
31, 2002, June 30, 2002 or September 30, 2002 quarterly
filings on Form 10-Q.