===============================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
For the fiscal year ended December 31, 2000
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)
580 WestLake Park Blvd., Suite 1300
Houston, Texas 77079
(Address of principal executive offices including Zip Code)
(281) 584-5500
(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]
The aggregate market value of the voting stock held by non-affiliates of
registrant is indeterminable, as there is no established public trading market
for the registrant's common stock.
As of March 25 2001, there were 1,380 shares of the registrant's common
stock outstanding.
================================================================================
TABLE OF CONTENTS
Item Page
PART I 3
ITEMS 1. AND 2. BUSINESS AND PROPERTIES 3
(a) Overview 3
(b) Competitive Strengths and Business Strategy 5
(c) Reserves 6
(d) Oil and Gas Properties 7
(e) Production 10
(f) Productive Wells 11
(g) Acreage 11
(h) Drilling Activity 11
(i) Marketing, Customers and Hedging Activities 12
(j) Competition 13
(k) Royalty Relief 13
(l) Regulation 14
(m) Employees 16
ITEM 3. LEGAL PROCEEDINGS 16
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 16
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS 16
ITEM 6. SELECTED FINANCIAL DATA 16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 17
(a) Introduction 17
(b) General 18
(c) Results of Operations 19
(d) Liquidity and Capital Resources 21
(e) Recent Accounting Pronouncements 24
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 24
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 25
INDEPENDENT AUDITORS' REPORT 26
LIABILITIES AND STOCKHOLDER'S EQUITY 27
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 42
PART III 43
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 43
ITEM 11. EXECUTIVE COMPENSATION 45
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 49
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 51
PART IV 53
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 53
GLOSSARY 56
2
PART I
In addition to historical information, this Annual Report on Form 10-K
contains statements regarding future financial performance and results and other
statements which are not historical facts. These constitute forward-looking
statements which are subject to risks and uncertainties that could cause the
Company's actual results to differ materially. Such risks include, but are not
limited to, oil and gas price volatility, results of future drilling,
availability of drilling rigs, availability of capital resources for drilling
and completion activities, future production and costs and other factors. Some
of the more important factors that could cause or contribute to such differences
include those discussed in Items 1 and 2 "Business and Properties" and Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in this report.
Items 1. and 2. Business and Properties
Certain technical terms used in these Items are described or defined in the
Glossary presented on page 56 of this report.
(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. Our increasing
focus on Gulf water depths greater than 600 feet, or the deepwater, since the
early 1990s has made us one of the most experienced independent operators in the
deepwater Gulf. We have been an active explorer in the Gulf Coast area since the
mid-1980s, when we operated as Hardy Oil & Gas USA Inc., and have increased our
production and reserve base through the exploitation and development of
internally generated prospects, which we refer to as growth "through the
drillbit." Members of our senior management team, most of whom have worked
together for over 15 years, and an affiliate of Enron North America Corp. led a
buyout of Mariner from Hardy Oil & Gas, plc in April 1996.
Since beginning deepwater operations in 1994, we have:
o operated nine successful field development projects in water depths of 400
feet to 5,600 feet;
o developed three deepwater exploitation projects acquired from major oil
companies, including our Pluto project, with a fourth deepwater
exploitation project, King Kong, which was acquired from Shell Oil Company
in 2000 in progress;
o discovered eight new fields in 16 deepwater Gulf exploration tests;
o acquired 67 deepwater Gulf lease blocks, most of which qualify for relief
of royalty payment obligations; and
o built an inventory of 14 exploration prospects as of December 31, 2000,
including 13 prospects in the deepwater Gulf.
Ryder Scott Company estimated that we had proved reserves of 203.6 Bcfe as
of December 31, 2000, the highest level in our history, of which 63% were
natural gas and 37% were oil and condensate. Proved reserves included net
reserve additions of 63.6 Bcfe, representing 175% of 2000's company record
production of 36.3 Bcfe. Year 2000 additions included first proved reserve
bookings from the Aconcagua and Devils Tower discoveries and proved reserves
associated with the Company's acquired interest in the King Kong exploitation
project.
We expect our production for 2001 to be level or slightly higher than
2000's average rate of 99 MMcfe per day, with production from the Black Widow
project expected to offset anticipated production declines in the Company's
other fields. With first production from the Mariner-operated King Kong
Deepwater Gulf project scheduled for late fourth quarter 2001, our year-end 2001
production rate is expected to rise sharply compared to the production rate of
109 MMcfe per day at the end of 2000. In 2001, we expect to drill seven to ten
exploratory wells in the deepwater Gulf, with partners paying Mariner's share of
the cost for at least one of the wells. We also plan to increase our 3-D seismic
database and leasehold position in the deepwater Gulf. Development activities in
2001 include the completion of our King Kong deepwater Gulf exploitation
project, development of the Aconcagua discovery and several development wells in
currently-producing fields.
3
We anticipate capital expenditures for 2001, net of proceeds from property
conveyances, to be approximately $140 million for leasehold acquisition,
exploration drilling and development projects, compared to our 2000 capital
expenditures of approximately $79.1 million, net of proceeds from property
conveyances of $29.0 million. We expect to fund our capital expenditures by a
combination of internally generated cash flow, proceeds from property
conveyances, including the recently-announced sale of our remaining interest in
the Devils Tower development project, and borrowings against our Revolving
Credit Facility.
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,
2000. 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. Year-end oil and gas prices 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 ended December 31,
(dollars in millions unless otherwise indicated)
2000 1999 1998 1997 1996(3)
---- ---- ---- ---- --------
Proved reserves:
Oil (MMbbls) ......................................................... 12.4 9.9 9.4 6.6 5.3
Natural gas (Bcf) .................................................... 129.3 118.8 128.9 121.4 92.3
Natural gas equivalent (Bcfe) ........................................ 203.6 178.4 185.1 161.2 124.0
Present value of estimated future net revenues (1) ...................... $ 1,043.2 $ 211.2 $ 147.6 $ 176.5 $ 303.4
Annual reserve replacement ratio (2) ................................... 1.7 1.3 2.0 2.6 1.2
Capital expenditures and disposal data:
Capital costs incurred ............................................... $ 108.1 $ 81.5 $ 141.9 $ 68.9 $ 46.6
Proceeds from property conveyances ................................... ($ 29.0) ($ 19.8) -- -- ($ 7.5)
Capital costs net of proceeds from property conveyances............... $ 78.5 $ 61.7 $ 141.9 $ 39.1 $ 68.9
Percentage of net capital costs attributable to:
Lease acquisition ................................................. 10.5% 12.8% 30.4% 36.0% 30.7%
Exploratory drilling, geological and geophysical................... 19.6% 16.6% 25.1% 39.7% 48.7%
Development and other ............................................. 69.9% 70.6% 44.5% 24.3% 20.6%
Production:
Oil (MMbls) .......................................................... 1.8 0.6 0.8 1.0 0.8
Natural gas (Bcf) .................................................... 25.7 21.1 19.5 18.0 20.4
Natural gas equivalents (Bcfe) ....................................... 36.3 24.9 24.2 23.9 24.9
Average realized sales price per unit (excluding the effects of hedging):
Oil ($/Bbl) .......................................................... $ 29.53 $ 17.53 $ 12.99 $ 19.18 $ 20.65
Natural gas ($/Mcf) .................................................. 4.07 2.48 2.33 2.77 2.57
Gas equivalent ($/Mcfe) .............................................. 4.32 2.58 2.30 2.87 2.72
Average realized sales price per unit (including the effects of hedging):
Oil ($/Bbl) .......................................................... $ 21.54 $ 14.11 $ 12.99 $ 18.55 $ 18.10
Natural gas ($/Mcf) .................................................. 3.24 2.16 2.45 2.55 2.39
Gas equivalent ($/Mcfe) .............................................. 3.34 2.19 2.40 2.68 2.50
Expenses ($/Mcfe):
Lease operating ...................................................... 0.47 0.46 0.41 0.39 0.36
Transportation ....................................................... 0.22 0.08 0.05 0.05 0.08
General and administrative, net ...................................... 0.18 0.22 0.20 0.13 0.13
4
(1) Discounted at an annual rate of 10%. See "Glossary" included elsewhere in
this 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 an Mcfe basis for the
year by actual production on an Mcfe basis for such year.
(3) In an acquisition effective April 1, 1996 for accounting purposes, Mariner
Holdings, Inc. acquired all the capital stock of the Company from Hardy
Holdings Inc. as part of a management-led buyout. In connection with the
acquisition, substantial intercompany indebtedness and receivables and
third-party indebtedness of the Company were eliminated. The acquisition
was accounted for using the purchase method of accounting, and Mariner
Holdings' cost of acquiring the Company was allocated to the assets and
liabilities of the Company based on estimated fair values. As a result, the
Company's financial position and operating results subsequent to the
acquisition reflect a new basis of accounting and are not comparable to
prior periods. "Predecessor Company" refers to Mariner Energy, Inc.
(formerly named "Hardy Oil & Gas USA Inc.") prior to the effective date of
the acquisition.
(b) Competitive Strengths and Business Strategy
Competitive Strengths
We have several competitive strengths that we believe will allow us to
compete successfully in oil and natural gas exploration, production and
development activities in the Gulf:
Early Entry Into the Deepwater Gulf. We began focusing in the deepwater
Gulf in 1994 as one of the first independent oil and natural gas companies to
recognize the opportunity for acquiring smaller deepwater discoveries not
meeting a large company's field size threshold and for partnering with major oil
companies to develop these discoveries. We believe our six years in the
deepwater Gulf have provided us with the geophysical and geological skills,
operating expertise and relationships necessary to operate successfully in the
deepwater. Our deepwater Gulf expertise includes:
o a strong understanding of the geology and geophysics of the deepwater Gulf;
o familiarity with challenges peculiar to operating in the deepwater Gulf;
and
o relationships with vendors, major oil companies and other partners having
complementary skills and knowledge of the area.
Substantial Acreage, Seismic Data and Prospect Inventory. Our Gulf
leasehold inventory as of December 31, 2000, consisted of 100 lease blocks,
including 67 in the deepwater. Our prospect inventory includes 15 exploration
prospects, 14 of which are in the deepwater Gulf. We expect to drill seven to
ten of our deepwater exploration prospects by the end of 2001. Our seismic
database includes 3-D seismic that covers approximately 8,200 square miles of
the Gulf and modern 2-D seismic that covers more than 250,000 miles of the
deepwater Gulf. We internally generate substantially all of our exploration and
exploitation prospects using 3-D seismic data.
Experienced Operations and Technical Staff and Management. Our 13
geoscientists average more than 20 years of experience in the exploration and
production business, including extensive experience in the deepwater Gulf and
with major oil companies. Our 6 deepwater operations managers average over 25
years of experience with major oil companies and large independents around the
world. Most of our senior management team participated in our acquisition from
Hardy and have worked together for over 15 years. Management and other key
personnel currently own approximately 4% of the common shares of our parent
company and have options that, if exercised, would increase their ownership to
17%. We believe that management's ownership aligns its interests with those of
other shareholders.
Strategy
Our business strategy is to increase reserves, production and cash flow by
emphasizing growth through the drillbit in the deepwater Gulf; the use of subsea
technology to develop mid-sized fields that are either acquired from major oil
companies or discovered via low-cost exploration. Our strategy consists of the
following elements:
o Focus on the Deepwater Gulf. Our early entry into the deepwater Gulf in
1994 has allowed us to develop the geophysical and geological skills,
operating expertise and relationships with partners necessary to operate
successfully in the deepwater. With our current prospect and seismic
inventory and many more deepwater Gulf lease blocks expected to become
available via lease sales and farmouts from existing leaseholders, we
believe we are well-positioned to increase our deepwater Gulf activity and
to continue to generate and exploit economically attractive prospects.
5
o Pursue a Balanced Portfolio Approach to our Drilling Program. We target six
to ten new prospects each year, with a strong deepwater Gulf emphasis. The
program is designed to provide reserve replacement and production growth
through low-risk deepwater exploitation projects and opportunities for
substantial growth through moderate-risk exploration prospects that can
significantly increase our reserve base.
o Internally Generate Most of Our Prospects. By internally generating most of
our prospects, we believe we have better control over the quality of the
prospects in which we participate, thereby increasing our chances for
commercial success. Almost all of our inventory of exploration prospects
were internally generated by our staff of geoscientists, which has
extensive experience in the deepwater Gulf. Through our technical staff's
understanding of the geology and geophysics of the deepwater Gulf and our
inventory of leasehold blocks and seismic data, we intend to continue to
generate the majority of our prospects internally.
o Manage Deepwater Risks. We intend to reduce our deepwater risks by
continuing to:
o target prospects with relatively low gross drilling costs ranging from
$5 million to $20 million;
o use 3-D seismic technology to identify direct hydrocarbon indicators
and to lessen the risk of dry holes; and
o limit the financial exposure of our deepwater prospect portfolio by:
o selling a portion of our working interests in our deepwater projects
to industry partners, typically on a promoted basis where all or a
portion of our exploratory costs are paid by partners;
o generally maintaining a 25% to 50% interest during the appraisal phase
of a successful exploratory project; and
o reducing our interest in the development phase of a project when
appropriate, considering other opportunities in our investment
portfolio, the need to avoid becoming overly concentrated in a few
projects and the availability of capital.
o Apply Our Deepwater Operational Expertise. Our deepwater operations
managers average over 25 years of experience with major oil companies and
large independents around the world. By operating most of our deepwater
projects, we intend to apply the experience of our staff to continue to:
o maintain efficient drilling performance;
o shorten project cycle times;
o reduce operational risks and life of project finding and development
costs; and
o innovatively use proven subsea production technology and develop low
cost, mobile floating production facilities.
(c) Reserves
The following table sets forth certain information with respect to our
proved reserves by geographic area as of December 31, 2000. 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, 2000 is based upon a reserve report prepared by the independent
petroleum consulting firm of Ryder Scott Company. 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 9 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.
6
As of December 31, 2000
---------------------------------------------------------
Present Value of
Estimated Future
Proved Reserve Quantities Net Revenues (1)
Oil Natural Gas Total Dollars in millions
Geographic Area (MMBbls) (Bcf) (Bcfe) Developed Undeveloped Total
Deepwater Gulf .......................... 7.7 87.5 133.7 $ 391.5 $ 371.7 $ 763.2
Gulf Shallow Water and Gulf Coast Onshore 0.3 18.5 20.2 138.1 11.8 149.9
Permian Basin ........................... 4.4 23.3 49.7 62.5 67.6 130.1
--- ---- ---- ---- ---- -----
Total ................................... 12.4 129.3 203.6 592.1 451.1 1,043.2
==== ===== ===== ===== ===== =======
Proved Developed Reserves ............... 5.5 61.6 94.6 $ 592.1
=== ==== ==== =====
(1) Discounted (at 10%) present value as of December 31, 2000 (year-end prices
held constant excluding hedging activities).
Our estimates of proved reserves set forth in the foregoing table do not
differ materially from those filed by us with other federal agencies.
(d) Oil and Gas Properties
(i) Significant Properties with Proved Reserves as of December 31, 2000
We own oil and gas properties, both producing and for future exploration
and development, onshore in Texas and offshore in the Gulf, primarily in federal
waters. Our nine largest producing properties, as shown in the following table,
accounted for approximately 93% of the Company's proved reserves as of December
31, 2000.
Date Net
Mariner Approximate Production Proved
Working Water Producing Commenced/ Reserves
Operator Interest Depth (Feet) Wells Expected (Bcfe)
Deepwater Gulf:
Mississippi Canyon 773 (Devils Tower (1) Dominion 20% 5,600 -- First quarter 2003 28.0
Green Canyon 472 (King Kong)............ Mariner 50% 3,900 -- Fourth quarter 2001 25.5
Mississippi Canyon 718 (Pluto).......... Mariner 51% 2,710 1 December 1999 21.5
Mississippi Canyon 305 (Aconcagua)...... Elf 25% 7,100 -- Fourth quarter 2002 19.2
Ewing Bank 966 (Black Widow)............ Mariner 69% 1,850 1 October 2000 18.9
Garden Banks 73 (Apia).................. Mariner 100% 700 1 April 2000 11.6
Garden Banks 367 (Dulcimer)............. Mariner 41.7% 1,100 1 April 1999 5.4
Gulf Shallow Water and Gulf Coast
Onshore:
Brazos A-105........................... Spirit Energy 12.5% 192 5 January 1993 8.8
Permian Basin of West Texas:
Spraberry Aldwell Unit(2).............. Mariner 70.3% Onshore 82 1949 49.7
Other Properties......................... -- -- -- -- -- 15.0
-----
Total Proved Reserves.................... 203.6
=====
----------
(1) Our working interest in Devils Tower was sold to a subsidiary of Dominion
in March 2001.
(2) We operate the unit and own working interests in individual wells ranging
from approximately 33% to 84%.
Following is additional informati on regarding the properties in the table
shown above.
7
Principal Oil and Natural Gas Properties
Deepwater Gulf of Mexico
Mississippi Canyon 773 (D evils Tower). We generated the Devils Tower
prospect and acquired it in the Ma rch 1998 federal lease sale. The prospect is
located approximately 140 miles so utheast of New Orleans in 5,600 feet of
water. During the fourth quarter of 1999, we drilled a successful exploration
well on the prospect, encountering multiple hydrocarbon bearing zones. Casing
was run in the well and the well was temporarily suspended. Our share of the
drilling cost for the exploration well was paid by our partners in the prospect.
In May 2000, we sold a 30% working interest in the project to one of our
partners, Dominion Exploration & Production, Inc., who subsequently became the
operator, and we retained a 20% working interest. During the second quarter of
2000, a successful appraisal well was drilled, followed immediately by a
successful sidetrack of the appraisal well. Development activities are in
progress, with first production anticipated for early 2003. In the first quarter
of 2001, we sold our remaining 20% working interest to Dominion Exploration &
Production, Inc. to better manage financial and operational risk, to obtain an
acceptable return without holding the investment through depletion and to
re-deploy capital to other projects in our deepwater Gulf niche.
Green Canyon 472 (King Kong) In July 2000,we entered into an agreement to
acquire Shell Exploration and Production Company's 50% working interest in the
"King Kong" Deepwater Gulf of Mexico development project. The project is located
in approximately 3,900 feet of water in Green Canyon Blocks 472, 473 and 517,
approximately 150 miles southeast of New Orleans. We purchased Shell's interest
for an undisclosed amount of cash and overriding royalty interest in the field,
and have been named operator for development of the project. Agip Petroleum Co.
Inc., as a successor to British Borneo, owns the remaining 50% working interest.
We intend to develop gas reserves from two separate reservoirs discovered by
three exploration wells that were previously drilled in the project. The initial
development plan calls for completing a previously-drilled well and drilling an
additional development well, with both subsea wells tied back 16 miles to the
Allegheny mini-TLP operated by Agip. We also plan to drill our "Yosemite"
exploration prospect located adjacent to King Kong in Green Canyon Block during
2001. If successful, we expect Yosemite to be jointly developed with King Kong.
We anticipate production from the project to commence by late 2001. The King
Kong development project is located in the same area of Green Canyon where we
have assembled several other exploration prospects, including Yosemite,
providing us with the opportunity to capitalize on synergies for the development
of any discoveries. The field had estimated net proved reserves of 25.5 Bcfe as
of December 31, 2000.
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. 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 deepwater Gulf approximately 150
miles southeast of New Orleans, Louisiana at a water depth of 2,700 feet and a
flow line tied back approximately 29 miles to a production platform on the
shelf. Production began on December 29, 1999 and through December 31, 2000 the
field produced 11.5 Bcfe net to us. As of December 31, 2000, the field had
estimated net proved reserves of 21.5 Bcfe, 75% of which was natural gas.
Mississippi Canyon 305 (Aconcagua). We generated the Aconcagua prospect and
acquired it at a federal offshore Gulf lease sale in March 1998. We hold a 25%
working interest in the block. During the first quarter of 1999, the operator,
Elf Exploration Inc., drilled a successful exploration well on the prospect, on
which our share of the drilling cost was paid by one of our partners. The well
logged multiple pay sands, which are geological formations where deposits of oil
or gas are found in commercial quantities, and we encountered additional sands
with productive potential. The well is located 40 miles from the shelf edge in
7,100 feet of water approximately 150 miles southeast of New Orleans. Elf
Exploration Inc. drilled a successful appraisal well in March 2000, encountering
over 250 net feet of gas pay and confirming that reservoirs found in the
discovery well extend approximately two miles to the northeast. Aconcagua is
included in the Canyon Express joint subsea development project, which will
gather production from three deepwater natural gas fields and transport it over
47 miles to a new platform to be built by Williams Field Services - Gulf Coast
Company, L.P., at a location in shallow water on the outercontinental shelf. We
anticipate that production will commence in the fourth quarter of 2002. The
field had estimated net proved reserves of 19.2 Bcfe at December 31, 2000.
8
Ewing Bank 966 (Black Widow). We generated the Black Widow prospect and
acquired it at a federal offshore Gulf lease sale in March 1997. We operate and
have a 69% working interest in this project, which is located in the deepwater
Gulf approximately 130 miles south of New Orleans, Louisiana at a water depth of
approximately 1,850 feet. In early 1998, we drilled a successful exploration
well on the prospect. We commenced production in the fourth quarter of 2000 via
subsea tieback to an existing platform and the field has produced through
December 31, 2000 2.1 Bcfe net to us. Estimated net proved reserves from Black
Widow were approximately 18.9 Bcfe, 85% of which was oil, as of December 31,
2000.
Garden Banks 73 (Apia). We generated the Apia prospect and acquired it in a
federal offshore lease sale in August 1998. We operate and own a 100% working
interest in this project which is located offshore Louisiana in a water depth of
approximately 700 feet. In September 1999 we drilled a successful exploration
well which encountered 102 net feet gas pay in a single zone. The field was
developed by the single subsea well tied back to a host platform approximately
three miles from the well. Production began on April 29, 2000 and through
December 31, 2000 it has produced 5.9 Bcfe net to us. The field had estimated
net proved reserves of 11.6 Bcfe, all of which was natural gas, as of December
31, 2000.
Garden Banks 367 (Dulcimer). We generated the Dulcimer prospect and
acquired it at a federal offshore Gulf lease sale in September 1996. The well is
located in the deepwater Gulf approximately 170 miles south of Lake Charles,
Louisiana at a water depth of approximately 1,100 feet. We operate and have a
42% working interest in the property. In late 1997, we drilled a successful
exploration well in two productive intervals between 9,900 feet and 10,500 feet.
The well commenced production in April 1999, after tieback to a production
platform located approximately 14 miles from the well. In May 2000, Dulcimer
began to produce lower gas rates in conjunction with the onset of
reservoir-related water production. To improve performance we drilled for
additional reserves in the existing well bore as well as sidetracking the well
to an updip location in this fault block in February 2001. Through December 31,
2000, the field had produced 7.5 Bcfe net to us. The field had estimated net
proved reserves of 5.4 Bcfe, all of which was natural gas, as of December 31,
2000.
Gulf Shallow Water and Gulf Coast Onshore
Brazos A-105. We generated the Brazos A-105 prospect and own a 12.5%
working interest in this Spirit Energy-operated property, which commenced
production in January 1993. Five wells exploit a single reservoir. No additional
wells are currently anticipated. The field has produced 25.1 Bcfe net to us from
its inception through December 31, 2000. The field had estimated remaining net
proved reserves of 8.8 Bcfe as of December 31, 2000, 99% of which was 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, 72 infill wells have been drilled
resulting in 71 productive wells. Currently there are a total of 82 producing
wells in the unit. Depending on, among other things, the future prices of oil
and natural gas, we may drill 20 to 40 additional infill wells, bringing proved
undeveloped reserves into production, in the next two to four years at a
projected cost of approximately $340,000 to $400,000 per well. We estimate that
the field's remaining net proved reserves as of December 31, 2000 was 49.7 Bcfe.
We believe that the field's potential for continued economic oil production
exceeds 40 years.
9
(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
therefrom to activities that we believe have a higher potential financial
return. No property dispositions of producing properties were made during 2000.
In 2000 and 2001, we sold interests in a discovered field for which production
had not yet commenced.
(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.
(e) 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 ended December 31,
--------------------------
2000 1999 1998
----- ----- -----
Production:
Oil (MMbbls) .................................... 1.8 0.6 0.8
Natural gas (Bcf) ............................... 25.7 21.1 19.5
Gas equivalent (Bcfe) ........................... 36.3 24.9 24.2
Average sales prices excluding effects of hedging:
Oil ($/Bbl) .....................................$ 29.53 $ 17.53 $ 12.99
Natural gas ($/Mcf) ............................. 4.07 2.48 2.33
Gas equivalent ($/Mcfe) ......................... 4.32 2.58 2.30
Average sales prices including effects of hedging:
Oil ($/Bbl) .....................................$ 21.54 $ 14.11 $ 12.99
Natural gas ($/Mcf) ............................. 3.24 2.16 2.45
Gas equivalent ($/Mcfe) ......................... 3.34 2.19 2.40
Expenses ($/Mcfe):
Lease operating ................................. 0.47 0.46 0.41
Transportation .................................. 0.22 0.08 0.05
General and administrative, net (1) ............. 0.18 0.22 0.20
Depreciation, depletion and amortization (2)..... 1.57 1.29 1.40
Cash margin ($/Mcfe) (3)............................ 2.26 1.18 1.47
(1) Net of overhead reimbursements received from other working interest
owners and amounts capitalized under the full cost accounting method.
(2) Excludes impairment of oil & gas properties of $50.8 million for the
year ended December 31, 1998. No impairment was necessary for either
of the years ended December 31, 1999 and 2000.
10
(3) Average equivalent gas sales price (including the effects of hedging),
minus lease operating and gross general and administrative expenses.
(f) 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, 2000:
Total Productive
Wells
Gross Net
Oil...................... 87 53.2
Gas...................... 52 9.7
-- ---
Total............... 139 62.9
=== ====
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.
(g) Acreage
The following table sets forth certain information with respect to the
developed and undeveloped acreage as of December 31, 2000.
Developed Acres (1) Undeveloped Acres (2)
------------------- ------------------
Gross Net Gross Net
------- ------ ------- -------
Texas (Onshore)................ 19,067 12,604 747 440
All other states (Onshore)..... 671 212 574 126
Offshore....................... 229,289 64,987 280,940 149,642
------- ------ ------- -------
Total..................... 249,027 77,803 282,261 150,208
======= ====== ======= =======
(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.
(h) Drilling Activity
Certain information with regard to our drilling activity during the years
ended December 31, 2000, 1999 and 1998 is set forth below.
11
Year Ended December 31,
---------------------------------------------
2000 1999 1998
----- ----- ----
Gross Net Gross Net Gross Net
Exploratory wells:
Producing................ 1 0.40 3 1.75 3 1.10
Dry...................... 3 2.08 2 0.50 5 1.54
- ---- - ---- - ----
Total................ 4 2.48 5 2.25 8 2.64
= ==== = ==== = ====
Development wells:
Producing................ 2 0.45 8 1.61 19 8.61
Dry...................... - - - - 3 1.13
- ---- - ---- - ----
Total................ 2 0.45 8 1.61 22 9.74
= ==== = ==== == ====
Total wells:
Producing................ 3 0.85 11 3.36 22 9.71
Dry...................... 3 2.08 2 0.50 8 2.67
- ---- - ---- - ----
Total................ 6 2.93 13 3.86 30 12.38
= ==== == ==== == =====
(i) Marketing, Customers and Hedging Activities
We market substantially all oil and gas production from properties we
operate and from properties operated by others where our interest is
significant. The majority 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 as to the sale of such gas and the processing thereof
which we believe to be competitive. Similarly, we have a gas processing
agreement on our gas production from Sandy Lake which we believe has the effect
of pricing our gas production favorably compared to market prices at that
location. The following table lists customers accounting for more than 10% of
our total revenues for the year indicated (a "-" indicates that revenues from
the customer accounted for less than 10% of our total revenues for that year).
Percentage of total revenues
For the year ended December 31,
--------------------------------
Customer 2000 1999 1998
-------- ---- ---- ----
Enron North America and affiliates
(An affiliate of the Company) .............. 49% 26% 15%
Transco Energy Marketing Company .............. -- 21% 16%
Duke Energy ................................... 16% 13% 29%
Genesis Crude Oil LP .......................... -- -- 10%
Due to the nature of the markets for oil and natural gas, we do not believe
that the loss of any one of these customers would have a material adverse effect
on our financial condition or results of operations.
We have utilized hedging transactions with respect to a portion of our oil
and gas production to reduce our exposure to price fluctuations and to achieve a
more predictable cash flow. We do not engage in hedging activities for
speculative purposes. We customarily conduct our hedging strategy through the
use of swap arrangements that establish an index-related price above which we
pay the hedging partner and below which we are paid by the hedging partner.
During 2000, approximately 71% of our equivalent production was subject to hedge
positions.
12
The following table sets forth our open hedge positions as of December 31,
2000.
Price
Notional ----------------------
Time Period Quantities Floor Ceiling Fixed Fair Value
----------- ---------- ----- ------- ----- ----------
in millions)
Natural Gas (MMBtu)
January 1 - September 30, 2001
Collar purchased 4,216 $3.50 $4.92 (8.5)
Put option purchased 4,216 $3.50 --
Fixed price swap purchased 3,376 $2.18 (18.0)
October 1 - December 31, 2001
Fixed price swap purcahsed 774 2.18 (2.5)
January 1 - December 31, 2002
Fixed price swap purchased 1,831 2.18 (4.3)
------
Total ($33.3)
=======
Hedging arrangements for 2001 and 2002 cover approximately 36% and 4% of
our anticipated equivalent production, respectively. Hedging arrangements may
expose us to the risk of financial loss in certain circumstances, including
instances where our production, which is in effect hedged, is less than expected
or where there is a sudden, unexpected event materially impacting prices. Our
Revolving Credit Facility (see Note 3 of the financial statements) places
certain restrictions on our use of hedging. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Changes in Prices and
Hedging Activities".
(j) 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 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.
(k) 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 State 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.
13
The impact of royalty relief is significant, as normal royalties for leases
in water depths of 400 meters or less is 16.7% and normal royalties for leases
in water depths greater than 400 meters is 12.5%. Royalty relief can
substantially improve the economics of projects in deep water. We have acquired
50 new deepwater leases that are qualified for royalty relief and have received
royalty relief on the four lease blocks comprising the Pluto project. However,
in the event that prices exceed certain prescribed thresholds royalty relief is
suspended. In 2000 natural gas prices exceeded these thresholds and we are
required to pay royalties on the Pluto project for the year.
(l) Regulation
Our operations are subject to extensive and continually changing regulation
because legislation affecting the oil and natural gas industry is under constant
review for amendment and expansion. Many departments and agencies, both federal
and state, are authorized by statute to issue and have issued rules and
regulations binding on the oil and natural gas industry and its individual
participants. The failure to comply with 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. However, we do not believe that it is affected in a significantly
different manner by these regulations than are our competitors in the oil and
natural gas industry.
(i) Transportation and Sale of Natural Gas
The FERC 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 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 to limit the number of wells or
the locations at which we can drill. Moreover, each state generally imposes a
production or severance tax with respect to production and sale of crude oil,
natural gas and gas liquids within its jurisdiction.
14
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 plans and our development and production plans
for these leases. The MMS regulations also establish construction requirements
for production facilities located on our federal offshore leases and govern the
plugging and abandonment of wells and the removal of production facilities from
these leases. Under certain circumstances, the MMS could require us to suspend
or terminate our operations on a federal lease.
In addition, a portion of our Sandy Lake Properties are located within the
boundaries of the Big Thicket National Preserve (the "BTNP"), which is under the
jurisdiction of the United States National Park Service (the "NPS"). Our
operations within the BTNP must comply with regulations of the NPS. In general,
these regulations require us to obtain NPS approval of a plan of operations for
any activity within the BTNP or to demonstrate that a waiver of a plan of
operations is appropriate. Compliance with these regulations increases our cost
of operations and may delay the commencement of specific operations.
(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.
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.
15
Clean Water Act. The Federal Water Pollution Control Act of 1972, as
amended (the "Clean Water Act"), imposes restrictions and controls on the
discharge of produced waters and other oil and gas wastes into navigable waters.
These controls have become more stringent over the years, and it is possible
that additional restrictions will be imposed in the future. Permits must be
obtained to discharge pollutants into state and federal waters. Certain state
regulations and the general permits issued under the Federal National Pollutant
Discharge Elimination System program prohibit the discharge of produced waters
and sand, drilling fluids, drill cuttings and certain other substances related
to the oil and gas industry into certain coastal and offshore water. The Clean
Water Act provides for civil, criminal and administrative penalties for
unauthorized discharges for oil and other hazardous substances and imposes
liability on parties responsible for those discharges for the costs of cleaning
up any environmental damage caused by the release and for natural resource
damages resulting from the release. Comparable state statutes impose liabilities
and authorize penalties in the case of an unauthorized discharge of petroleum or
its derivatives, or other hazardous substances, into state waters. We believe
that our operations comply in all material respects with the requirements of the
Clean Water Act and state statutes enacted to control water pollution.
Resources Conservation Recovery Act. The Resource Conservation Recovery Act
("RCRA") is the principle federal statute governing the treatment, storage and
disposal of hazardous wastes. RCRA imposes stringent operating requirements, and
liability for failure to meet such requirements, on a person who is either a
"generator" or "transporter" of hazardous waste or an "owner" or "operator" of a
hazardous waste treatment, storage or disposal facility. At present, RCRA
includes a statutory exemption that allows most crude oil and natural gas
exploration and production waste to be classified as nonhazardous waste. A
similar exemption is contained in many of the state counterparts to RCRA. As a
result, we are not required to comply with a substantial portion of RCRA's
requirements because our operations generate minimal quantities of hazardous
wastes. At various times in the past, proposals have been made to amend RCRA to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste. Repeal or modification of
the exemption by administrative, legislative or judicial process, or
modification of similar exemptions in applicable state statutes, would increase
the volume of hazardous waste we are required to manage and dispose of and would
cause us to incur increased operating expenses.
(m) Employees
As of December 31, 2000, we had 81 full-time employees. Our employees are
not represented by any labor union. We consider relations with our employees to
be satisfactory. We have never experienced a work stoppage or strike.
Item 3. Legal Proceedings
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.
Item 4. Submission of Matters to a Vote of Security Holders
None.
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.
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.
16
Predecessor
Company
(All amounts in millions) (1)
----------
Nine Three
Year Ended December 31, Months Months
--------------------------------- Ended Ended
Statement of Operations Data: 2000 1999 1998 1997 12/31/96 03/31/96
-------- ------ ------ ------ -------- ----------
Total revenues ..........................$ 121.1 $ 54.5 $ 58.0 $ 64.1 $ 48.4 $ 13.8
Lease operating expenses ................ 17.2 11.5 9.9 9.4 6.5 2.4
Transportation .......................... 7.8 2.0 1.3 1.3 1.3 0.5
Depreciation, depletion and amortization. 56.8 32.1 33.8 31.7 24.8 6.3
Impairment of oil and gas properties .... -- -- 50.8 28.5 22.5 --
Provision for litigation ................ -- -- 2.8 -- -- --
General and administrative expenses ..... 6.5 5.4 4.8 3.2 2.4 0.7
-------- ------ ------ ------ ------ ------
Operating income (loss) .............. 32.8 3.5 (45.4) (10.0) (9.1) 3.9
Interest income ......................... 0.1 -- 0.3 0.5 0.5 2.2
Interest expense ........................ (11.0) (13.5) (13.3) (10.6) (7.7) (3.4)
Write-off of bridge loan fees ........... -- -- -- -- (2.4) --
-------- ------ ------ ------ ------ ------
Income (loss) before income taxes..... 21.9 (10.0) (58.4) (20.2) (18.7) 2.7
Provision for income taxes............... - - - - - -
-------- ------ ------ ------ ------ ------
Net income (loss)................... $21.9 ($10.0) ($58.4) ($20.2) ($18.7) $2.7
======== ====== ====== ====== ====== ======
Capital Expenditure and Disposal Data:
Exploration, incl. leasehold/seismic..... $ 46.7 $ 24.0 $ 78.8 $ 49.0 $ 31.9 $ 4.9
Development and other ................... 61.4 57.5 63.1 19.9 7.0 2.8
Proceeds from property conveyances ...... (29.0) (19.8) -- -- (7.5) --
--------- ------ ------ ------ ------ ------
Total capital expenditures
net of proceeds from
property conveyances ............... $ 79.1 $ 61.7 $141.9 $ 68.9 $ 31.4 $ 7.5
======== ====== ====== ====== ====== ======
Balance Sheet Data (at end of period):
Oil and gas properties, net, at full cost $287.8 $263.6 $233.3 $175.7 $166.6 $127.1
Long-term receivable from affiliates .... -- -- -- -- -- 104.0
Total assets ............................ 335.4 297.5 262.3 212.6 196.8 254.3
Long-term debt, less current maturities . 129.7 167.3 124.6 113.6 99.5 162.5
Stockholder's equity .................... 141.9 65.0 27.5 57.2 77.1 71.9
(1) - In an acquisition effective April 1, 1996 for accounting purposes,
Mariner Holdings, Inc. acquired all the capital stock of the company from
Hardy Holdings Inc. as part of a management-led buyout. In connection with
the acquisition, substantial intercompany indebtedness and receivables and
third-party indebtedness of the Company were eliminated. The acquisition
was accounted for using the purchase method of accounting, and Mariner
Holdings' cost of acquiring the Company was allocated to the assets and
liabilities of the Company based on estimated fair values. As a result, the
Company's financial position and operating results subsequent to the
acquisition reflect a new basis of accounting and are not comparable to
prior periods. "Predecessor Company" refers to Mariner Energy, Inc.
(formerly named "Hardy Oil & Gas USA Inc.") prior to the effective date of
the acquisition.
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, 1998 and ended December 31, 2000. This discussion
should be read in conjunction with the information contained in the financial
statements included elsewhere in this annual 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, it can give no assurance that such expectations will prove to have
been correct.
17
(b) General
We are an independent oil and natural gas exploration, development and
production company with principal operations in the Gulf and along the U.S. Gulf
Coast. Our strategy is to profitably increase reserves, production and cash flow
primarily through the drillbit with a heavy emphasis on the deepwater Gulf.
During 2000 we:
o drilled four exploratory wells, with one success, in the deepwater
Gulf of Mexico, making us eight of sixteen in deepwater Gulf
exploratory test wells drilled since the acquisition from Hardy;
o drilled successful appraisal wells on our Aconcagua and Devils Tower
prospects;
o commenced production from two significant deepwater projects; Apia in
April 2000 and Black Widow in October 2000, which, when combined with
first production from Pluto in late 1999, resulted in the highest
level of production in our history;
o acquired from Shell Oil Company a 50% interest in the King Kong
deepwater Gulf exploitation project;
o sold a portion of our Devils Tower discovery to one of our partners in
the project, reducing our working interest from 50% to 20%, the
remainder of which was sold to the same partner in the first quarter
of 2001 to better manage financial and operational risk;
o added proved reserves of 63.6 Bcfe, which were approximately 175% of
our 2000 production of 36.3 Bcfe, including first proved reserve
bookings from the Aconcagua and Devils Tower discoveries and from the
King Kong exploitation project, resulting in the highest level of
proved reserves in our history;
o completed the settlement of a drilling rig commitment dispute,
securing access to a rig capable of drilling many of the prospects in
our deepwater Gulf inventory.
We expect capital expenditures for 2001, net of proceeds from property
conveyances, to be approximately $140 million, which we intend to use to
explore, develop and continue to build our prospect inventory. We expect to fund
our capital expenditures by a combination of internally generated cash flow,
proceeds from property conveyances and borrowings against our Revolving Credit
Facility.
Our revenue, profitability, access to capital and future rate of growth are
heavily influenced by the price we receive for our production. The markets for
oil, natural gas and natural gas liquids have been historically volatile and may
continue to be volatile in the future. We enter into hedging transactions for
our oil and natural gas production and intend to continue doing so. These
transactions may limit our potential gains if oil and natural gas prices were to
rise substantially over the price established by the hedges. These hedges also
may expose us to the risk of financial loss in some instances, including
possible production shortfalls and unexpected price changes.
Competition, both from other sources of energy such as electricity and from
within the industry, also affects our performance. Many of our larger
competitors possess and employ financial and personnel resources substantially
greater than those available to us, which can be particularly important in
deepwater Gulf activities. These companies may be able to pay more than we can
for productive oil and natural gas properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of properties and
prospects.
18
We use the full cost method of accounting for our investments in oil and
natural gas properties. Under this methodology, all costs of exploration,
development and acquisition of oil and natural gas reserves are capitalized into
a "full cost pool" as incurred and properties in the pool are depleted and
charged to operations using the unit-of-production method based on a ratio of
current production to total proved oil and natural gas reserves. To the extent
that capitalized costs less deferred applicable taxes exceed the present value,
using a 10% discount rate, of estimated future net cash flows from proved oil
and natural gas reserves and the lower of cost or fair market value of unproved
properties, the excess costs are charged to operations. Capitalized costs are
net of accumulated depreciation, depletion and amortization. If a writedown were
required, it would result in a charge to earnings but would not have an impact
on cash flows.
Our results of operations may vary significantly from year to year based on
the factors discussed above and on other factors such as exploratory and
development drilling success, curtailments of production due to workover and
recompletion activities and the timing and amount of reimbursement for overhead
costs we receive from co-owners. Therefore, the results of any one year may not
be indicative of future results.
(c) 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 ended December 31,
--------------------------------
2000 1999 1998
----- ----- -----
Production:
Oil (MMbbls)............................ 1.8 0.6 0.8
Natural gas (Bcf)....................... 25.7 21.1 19.5
Gas equivalent (Bcfe)................... 36.3 24.9 24.2
Average sales prices excluding effects of hedging:
Oil ($/Bbl)............................. $ 29.53 $ 17.53 $ 12.99
Natural gas ($/Mcf)..................... 4.07 2.48 2.33
Gas equivalent ($/Mcfe)................. 4.32 2.58 2.30
Average sales prices including effects of hedging:
Oil ($/Bbl)............................. $ 21.54 $ 14.11 $ 12.99
Natural gas ($/Mcf)..................... 3.24 2.16 2.45
Gas equivalent ($/Mcfe)................. 3.34 2.19 2.40
Expenses ($/Mcfe):
Lease operating......................... 0.47 0.46 0.41
Transportation.......................... 0.22 0.08 0.05
General and administrative, net......... 0.18 0.22 0.20
Depreciation, depletion and amortization
(excluding impairments)................. 1.57 1.29 1.40
(i) 2000 compared to 1999
Net production increased during 2000 to 36.3 billion cubic feet of natural
gas equivalent (Bcfe) from 24.9 Bcfe in 1999, a 46% improvement. Production from
the Pluto, Apia and Black Widow projects, all located in the Deepwater Gulf of
Mexico and commissioned during 2000, more than offset production declines in the
Company's other fields, primarily the Sandy Lake field, located onshore, and the
Dulcimer and Rembrandt fields, located offshore.
Hedging activities in 2000 decreased our average realized natural gas price
received by $0.83 per Mcf and revenues by $21.4 million, compared with a
decrease of $0.32 per Mcf and revenues of $6.7 million in 1999. Our hedging
activities with respect to crude oil during 2000 reduced the average sales price
received by $7.97 per Bbl and revenues by $14.1 million compared with a decrease
of $3.42 per Bbl and revenues of $2.2 million.
Oil and gas revenues increased 122% to $121.1 million for 2000 from $54.5
million for 1999, due to a 53% increase in realized prices to $3.34 per Mcfe in
2000 from $2.19 per Mcfe in 1999.
19
Lease operating expenses increased 50% to $17.2 million for 2000 from $11.5
million for 1999 due to the higher offshore production discussed above.
Transportation expenses increased 290% to $7.8 million for 2000 from $2.0
million for 1999. The increase was attributable to the full years transportation
expense on Pluto.
Depreciation, depletion, and amortization expense increased 77% to $56.8
million for 2000 from $32.1 million for 1999 as a result of the increase in the
unit-of-production depreciation, depletion and amortization rate to $1.57 per
Mcfe from $1.29 per Mcfe. This increase was in addition to increased
depreciation, depletion and amortization as a result of the increased production
mentioned above.
General and administrative expenses, which are net of overhead
reimbursements we received from other working interest owners, increased 22% to
$6.6 million for 2000 from $5.4 million for 1999 due to increased
personnel-related costs in 2000 required for us to pursue our deepwater Gulf
exploration and development plan.
Interest expense for 2000 decreased 19% to $11.0 million from $13.5 million
for 1999, primarily due to capital contributions by the sale of common stock to
our Parent which were used to reduce debt.
Income (loss) before income taxes increased to a net income of $21.9
million for 2000 from a loss of $10.0 million in 1999. Primarily as a result of
increased revenue and increased expenses discussed above.
(ii) 1999 compared to 1998
Net production increased 3% to 24.9 Bcfe for 1999 from 24.2 Bcfe for 1998.
Production from our offshore Gulf properties increased to 18.2 Bcfe in 1999 from
13.1 Bcfe in 1998, as a result of production commencing from a new well in the
Dulcimer field located in Garden Banks block 367 and two new wells in the
Rembrandt field located in Galveston block 151. This increase was offset by less
than expected production from our Sandy Lake field onshore Texas.
Hedging activities in 1999 decreased our average realized natural gas price
received by $0.32 per Mcf and revenues by $6.7 million, compared with an
increase of $0.12 per Mcf and revenues of $2.3 million in 1998. Our hedging
activities with respect to crude oil during 1999 reduced the average sales price
received by $3.42 per Bbl and revenues by $2.2 million. There were no oil hedges
in 1998.
Oil and gas revenues decreased 6% to $54.5 million for 1999 from $58.0
million for 1998, due to a 9% decrease in realized prices to $2.19 per Mcfe in
1999 from $2.40 per Mcfe in 1998.
Lease operating expenses increased 16% to $11.5 million for 1999 from $9.9
million for 1998 due to the higher offshore production discussed above and well
workovers on three offshore wells and two wells in our Sandy Lake field.
Transportation expenses increased 54% to $2.0 million for 1999 from $1.3
million for 1998. The increase was attributable to the addition of additional
production on offshore properties that are subject to transportation tarriffs.
Depreciation, depletion, and amortization expense decreased 5% to $32.1
million for 1999 from $33.8 million for 1998 as a result of the decrease in the
unit-of-production depreciation, depletion and amortization rate to $1.29 per
Mcfe from $1.40 per Mcfe. This decrease was offset in part by a 3% increase in
equivalent volumes produced. The lower rate for 1999 was primarily due to the
$50.8 million non-cash full cost ceiling test impairment recorded in 1998. No
impairment was necessary for 1999.
General and administrative expenses, which are net of overhead
reimbursements we received from other working interest owners, increased 14% to
$5.4 million for 1999 from $4.7 million for 1998 due to increased
personnel-related costs in 1999 required for us to pursue our deepwater Gulf
exploration and development plan.
Interest expense for 1999 increased 1% to $13.5 million from $13.4 million
for 1998.
20
Income (loss) before income taxes decreased to a loss of $10.0 million for
1999 from a loss of $58.4 million in 1998 as a result of a $50.8 million full
cost ceiling test impairment, offset in part by oil and gas revenue decreases
and increased expenses discussed above.
(d) Liquidity and Capital Resources
(i) Cash Flows
As of December 31, 2000, we had a working capital deficit of approximately
$15.4 million, compared to a working capital deficit of $32.3 million at
December 31, 1999. The reduction in the working capital deficit was primarily a
result of a $55.0 million cash equity contribution by the sale of common stock
to our Parent, which was used to reduce accounts payable, accrued liabilities
and affiliate debt as well as provide funds for capital expenditures. We expect
our 2001 capital expenditures, excluding capitalized general and administrative,
interest costs and proceeds from property conveyances, to be approximately $140
million, which would exceed cash flow from operations. However, we believe there
will be adequate cash flow due to increased commodity prices and proceeds from
property conveyances in order for us to fund our remaining planned activities in
2001. There can be no assurance that our access to capital will be sufficient to
meet our needs for capital. As such, we may be required to reduce our planned
capital expenditures and forego planned exploratory drilling.
We had a net cash inflow of $2.3 million in 2000, compared to a net cash
inflow of $0.1 million in 1999 and a net cash outflow of $9.1 million in 1998. A
discussion of the major components of cash flows for these years follows.
2000 1999 1998
------ ------ ------
Cash flows provided
by operating activities (in millions)....... $ 63.9 $ 24.4 $ 39.6
Cash flows provided by operating activities in 2000 increased by $39.5
million compared to 1999 due to increased oil and gas prices, production lease
operating and general and administrative expenses. Cash flows from operating
activities in 1999 decreased by $15.2 million from 1998 primarily due to
decreased oil and gas prices.
2000 1999 1998
------ ------ ------
Cash flows used in investing
activities (in millions).................. $ 79.1 $ 61.8 $141.9
Cash flows used in investing activities in 2000 increased by $17.3 million
compared to 1999 due to increased capital expenditures offset by $29.0 million
in proceeds from property conveyances. Cash flows used in investing activities
in 1999 decreased by $80.1 million compared to 1998 due to decreased capital
expenditures and the receipt of proceeds from property conveyances.
2000 1999 1998
------ ------ ------
Cash flows provided by financing
activities (in millions)................ $ 17.4 $ 37.5 $ 93.2
Cash flows provided by financing activities in 2000 decreased by $20.1
million compared to 1999 due to a $37.6 million net reduction in borrowings
against our Revolving Credit Facility and our Affiliate Credit Facility as
compared to a $14.2 million increase in borrowings against that facility for the
previous year. In addition, capital contributions by the sale of stock to Parent
increased by $31.7 million. Cash flows provided by financing activities in 1999
decreased by $55.7 million as compared to 1998 due to a net reduction in
borrowings of $50.2 million from borrowings against our various credit
facilities.
(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 through the use of
commodity futures, options and swap agreements. While the use of these hedging
arrangements limits the downside risk of adverse price movements, it also limits
future gains from favorable movements.
21
The following table sets forth the increase or decrease in our oil and gas
sales as a result of hedging transactions and the effects of hedging
transactions on prices during the periods indicated.
Year Ended December 31,
-------------------------
2000 1999 1998
------- ------ ------
Increase (decrease) in natural gas sales (in millions) ................ $ (21.4) $ (6.7) $ 2.3
Increase (decrease) in oil sales (in millions) ........................ (14.1) (2.2) --
Effect of hedging transactions on average gas sales price (per Mcf).... (0.83) (0.32) 0.12
Effect of hedging transactions on average oil sales price (per Bbl).... (7.97) (3.42) --
Hedging arrangements for 2000 covered approximately 71% of our equivalent
production for the year. Hedging arrangements for 2001 and 2002 cover
approximately 36% and 4% of our anticipated equivalent production, respectively.
The following table sets forth our open hedge positions as of December 31,
2000.
Price
Notional ---------------------
Time Period Quantities Floor Ceiling Fixed Fair Value
----- ------- ----- (in millions)
Natural Gas (MMBtu)
January 1 - September 30, 2001
Collar purchased 4,216 $3.50 $4.92 (8.5)
Put option purchased 4,216 $3.50 --
Fixed price swap purchased 3,376 $2.18 (18.0)
October 1 - December 31, 2001
Fixed price swap purchased 774 2.18 (2.5)
January 1 - December 31, 2002
Fixed price swap purchased 1,831 2.18 (4.3)
-------
Total ($33.3)
=======
The fair value for our hedging instruments was determined based on brokers'
forward price quotes and NYMEX forward price quotes as of December 31, 2000. As
of December 31, 2000, a commodity price increase of 10% would have resulted in
an unfavorable change in the fair value of our hedging instruments of $6.8
million and a commodity price decrease of 10% would have resulted in a favorable
change in the fair value of our hedging instruments of $6.6 million.
Our senior subordinated notes have a fixed rate and, therefore, do not
expose us to risk of earnings loss due to changes in market interest rates.
However, we are subject to interest rate risk under our Revolving Credit
Facility and our short-term credit facility with ENA. For example a 100 basis
point increase in the London Interbank Offered Rate would have increased our
2000 interest expense by $0.4 million. The carrying value of our Revolving
Credit Facility approximates market since these instruments have floating
interest rates. The market value of the senior subordinated notes was
approximately $91.0 million based on borrowing rates available at December 31,
2000.
22
(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, 2000.
Year Ended December 31,
2000 1999 1998
---- ---- ----
Capital expenditures (in millions):
Leasehold acquisition-- unproved properties... $ 1.7 $ 3.0 $ 43.1
Leasehold acquisition-- proved properties..... - - -
Oil and natural gas exploration............... 16.0 13.5 35.7
Oil and natural gas development and other..... 61.4 45.2 63.1
----- ----- ------
Total capital expenditures, net of proceeds from
property conveyances.......................... $79.1 $61.7 $ 141.9
===== ===== =======
Our capital expenditures for 2000 were $79.1 million, excluding the $29.0
million of proceeds from property conveyances, which was $17.4 million more than
1999. The increase was primarily a result of higher leasehold acquisition,
geological and geophysical, exploratory drilling and development costs as we
operated with increased access to capital. Before property conveyances, our 2000
capital expenditures included $32.3 million for exploration activities, $63.6
million for development activities and $11.7 million of capitalized indirect
costs.
Our total capital expenditures for 1999 were $61.7 million, excluding $19.8
million in proceeds from property conveyances, which was $80.2 million less than
1998. The decrease was due primarily to lower leasehold acquisition, geological
and geophysical, exploratory and development costs as we operated with reduced
access to capital.
Our approved capital expenditure budget for 2001 is approximately $140
million after estimated proceeds from property conveyances and before indirect
costs. Our budget includes approximately $70 million for exploration activities
and $70 million for development activities. A very active Deepwater Gulf
exploration program is underway, with funds budgeted to drill seven to ten
wells. The exploration budget also anticipates additions to our Deepwater 3-D
seismic database and our Deepwater leasehold position. The development budget
includes funds for completion of our King Kong Deepwater Gulf exploitation
project, development of the Aconcagua discovery and several development wells in
currently-producing fields.
Our long-term debt outstanding as of December 31, 2000 was approximately
$129.7 million, including $99.7 million of senior subordinated notes and $30.0
million drawn on our Revolving Credit Facility. Following our semi-annual
borrowing base redetermination completed in October 2000, our borrowing base
under the Revolving Credit Facility was reaffirmed at $70 million.
Our Revolving Credit Facility and the senior subordinated notes contain
various restrictive covenants that, among other things, restrict the payment of
dividends, limit the amount of debt 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. In
addition, restrictions in the Revolving Credit Facility and the senior
subordinated notes effectively restrict us from using our assets or cash flow to
satisfy interest or principal payments for our parent's credit facility with
Enron.
In March and May of 2000, we received cash equity contributions by the sale
of common stock to our Parent of $30 million and $25 million, respectively. The
March equity contribution was used to reduce accounts payable and accrued
liabilities, and the May equity contribution was used to repay our $25 million
Senior Credit Facility with ENA. These equity contributions were made with
proceeds from the Mariner Energy LLC three-year $112 million term loan with ENA.
Due to certain restrictions with our Indenture and Revolving Credit Agreement,
neither cash flows from operations nor from asset sales would be available to
repay any portion of this term loan.
23
We expect to fund our activities for 2001 through a combination of cash
flow from operations, borrowings under our Revolving Credit Facility, 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. We cannot assure you that anticipated growth will be realized,
that our business will generate sufficient cash flow from operations or that
future borrowings or equity capital will be available in an amount sufficient to
enable us to service our indebtedness or make necessary capital expenditures. In
addition, depending on the levels of our cash flow and capital expenditures, we
may need to refinance a portion of the principal amount of our senior
subordinated debt at or prior to maturity. However, we cannot assure you that we
would be able to obtain financing on acceptable terms to complete a refinancing.
(e) Recent Accounting Pronouncements
Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities, is effective for all fiscal years
beginning after June 15, 2000. SFAS 133, as amended and interpreted, establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
All derivatives, whether designated in hedging relationships or not, will be
required to be recorded on the balance sheet at fair value. If the derivative is
designated in a fair-value hedge, the changes in the fair value of the
derivative and the hedged item will be recognized in earnings. If the derivative
is designated in a cash-flow hedge, changes in the fair value of the derivative
will be recorded in other comprehensive incomes (OCI) and will be recognized in
the income statement when the hedged item affects earnings. SFAS 133 defines new
requirements for designation and documentation of hedging relationships as well
as ongoing effectiveness assessments in order to use hedge accounting. For a
derivative that does not qualify as a hedge, changes in fair value will be
recognized in earnings.
The Company expects that at January 1, 2001, it will record $33.3 million
charge in OCI as a cumulative transition adjustment for derivatives designated
in cash flow-type hedges prior to adopting SFAS 133. The Company does not expect
to record a cumulative transition adjustment to earnings relating to derivatives
not designated as hedges prior to the adoption of SFAS 133.
The Company adopted the provisions of Staff Accounting Bulletin ("SAB") No.
101 issued by the staff of the Securities and Exchange Commission. The impact of
adopting SAB No. 101 was not material to the Company.
In the fourth quarter of 2000, the Company adopted Emerging Issues Task
Force Issue No. 00-10 ("EITF No. 00-10") Accounting for Shipping and Handling
Fees and Costs. EITF No. 00-10 addresses how shipping and handling fees should
be classified in the income statement. As a result of EITF No. 00-10, the
Company has reclassified transportation expenses from oil and gas revenues to a
separate line item. The amounts reclassified for the years ended December 31,
2000, 1999 and 1998 were $7.8 million, $2.0 million and $1.3 million,
respectively.
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.
24
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
PAGE
Independent Auditors' Report............................................................ 26
Balance Sheets at December 31, 2000 and 1999............................................ 27
Statements of Operations for the years ended December 31, 2000, 1999 and 1998........... 28
Statements of Stockholder's Equity for the years ended December 31, 2000, 1999 and 1998. 29
Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998........... 30
Notes to Financial Statements........................................................... 31
25
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, 2000 and 1999 and the related statements of
operations, stockholder's equity and cash flows for each of the three years in
the period ended December 31, 2000. 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, 2000 and 1999, and the results of its operations and cash flows for
each of the three years in the period ended December 31, 2000, in conformity
with accounting principles general accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Houston, Texas
April 2, 2001
26
MARINER ENERGY, INC.
BALANCE SHEETS
(in thousands, except share data)
December 31, December 31,
2000 1999
------------- -------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2,389 $ 123
Receivables 33,534 23,683
Prepaid expenses and other 5,991 4,891
------------- -------------
Total current assets 41,914 28,697
------------- -------------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at full cost:
Proved 478,596 379,301
Unproved, not subject to amortization 61,068 81,897
------------- -------------
Total 539,664 461,198
Other property and equipment 4,592 3,982
Accumulated depreciation, depletion and amortization (254,396) (199,233)
------------- -------------
Total property and equipment, net 289,860 265,947
------------- -------------
OTHER ASSETS, NET OF AMORTIZATION 3,653 2,868
------------- -------------
TOTAL ASSETS $335,427 $297,512
============= =============
LIABILITIES AND STOCKHOLDER'S EQUITY
------------------------------------
CURRENT LIABILITIES:
Accounts payable $ 37,600 $ 45,058
Accrued liabilities 15,144 10,600
Accrued interest 4,522 5,329
------------- -------------
Total current liabilities 57,266 60,987
------------- -------------
OTHER LIABILITIES 6,552 4,226
LONG-TERM DEBT:
Senior Subordinated notes 99,722 99,673
Revolving Credit Facility 30,000 42,600
Affiliate Credit Facility - 25,000
------------- -------------
Total long-term debt 129,722 167,273
------------- -------------
STOCKHOLDER'S EQUITY:
Common stock, $1 par value;
2,000 and 1,000 shares authorized,
1,380 and 1,378 issued and outstanding,
at December 31, 2000 and December 31, 1999,
respectively 1 1
Additional paid-in-capital 227,318 172,318
Accumulated deficit (85,432) (107,293)
------------- -------------
Total stockholder's equity 141,887 65,026
------------- -------------
TOTAL LIABILITIES and STOCKHOLDER'S EQUITY $335,427 $297,512
============= =============
The accompanying notes are an integral part of these financial statements
27
MARINER ENERGY, INC.
STATEMENTS OF OPERATIONS
(in thousands)
Year Ended December 31,
------------------------------------
2000 1999 1998
--------- --------- ---------
REVENUES:
Oil sales $37,959 $8,888 $10,211
Gas sales 83,191 45,597 47,804
--------- --------- ---------
Total revenues 121,150 54,485 58,015
--------- --------- ---------
COSTS AND EXPENSES:
Lease operating expense 17,192 11,453 9,858
Transportation expense 7,789 2,017 1,325
Depreciation, depletion and amortization 56,846 32,121 33,833
Impairment of oil and gas properties - - 50,800
Provisions for ligitation - - 2,800
General and administrative expense 6,549 5,396 4,749
--------- --------- ---------
Total costs and expenses 88,376 50,987 103,365
--------- --------- ---------
OPERATING INCOME 32,774 3,498 (45,350)
INTEREST:
Income 124 36 313
Expense (11,037) (13,504) (13,384)
--------- --------- ---------
INCOME (LOSS) BEFORE TAXES 21,861 (9,970) (58,421)
PROVISION FOR INCOME TAXES - - -
--------- --------- ---------
NET INCOME (LOSS) $21,861 $(9,970) $(58,421)
========= ========= =========
The accompanying notes are an integral part of these financial statements
28
MARINER ENERGY, INC.
STATEMENTS OF STOCKHOLDER'S EQUITY
(in thousands, except number of shares)
Additional Total
Common Stock Paid-in Accumulated Stockholder's
Shares Amount Capital Deficit Equity
-------- ------ -------- -------- ----------
Balance at December 31, 1997 . 1,000 $ 1 $ 96,075 $(38,902) $ 57,174
Capital contribution
-- proceeds from the sale of
common stock of Parent -- 28,781 -- 28,781
Net loss ................... -- -- -- (58,421) (58,421)
-------- --- -------- -------- --------
Balance at December 31, 1998 . 1,000 1 124,856 (97,323) 27,534
Capital contribution ....... 378 -- 47,462 -- 47,462
Net loss ................... -- -- -- (9,970) (9,970)
-------- --- -------- -------- --------
Balance at December 31, 1999 . 1,378 1 172,318 (107,293) 65,026
======== === ======== ======== ========
Capital contribution ....... 2 -- 55,000 -- 55,000
Net income ................. 21,861 21,861
-------- --- -------- -------- --------
Balance at December 31, 2000 . 1,380 $ 1 $227,318 $(85,432) $141,887
======== === ======== ======== ========
The accompanying notes are an integral part of these financial statements
29
MARINER ENERGY, INC.
STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended
December 31,
--------------------------------------------
2000 1999 1998
------------ ------------- ------------
OPERATING ACTIVITIES:
Net income (loss) $21,861 $(9,970) $(58,421)
Adjustments to reconcile net loss to
net cash provided by operating activities:
Depreciation, depletion and amortization 57,538 32,838 33,762
Impairment of oil and gas properties - - 50,800
Provisions for litigation - - 2,800
Changes in operating assets and liabilities:
Receivables (9,851) (8,119) 2,578
Other current assets (1,100) 2,343 (3,606)
Other assets (785) 265 379
Accounts payable and accrued liabilities (3,721) 7,027 11,253
------------ ------------- ------------
Net cash provided by operating activities 63,942 24,384 39,545
------------ ------------- ------------
INVESTING ACTIVITIES:
Additions to oil and gas properties (107,468) (80,823) (140,777)
Proceeds from property conveyances 29,002 19,758 -
Additions to other property and equipment (610) (682) (1,078)
------------ ------------- ------------
Net cash used in investing activities (79,076) (61,747) (141,855)
------------ ------------- ------------
FINANCING ACTIVITIES:
Proceeds from (repayment of) revolving credit
facility (12,600) (10,800) 39,400
Capital contributed by sale of stock to parent 55,000 23,284 28,781
Proceeds from (payments to) the affiliate credit
facility (25,000) 25,000 25,000
------------ ------------- ------------
Net cash provided by financing activities 17,400 37,484 93,181
------------ ------------- ------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 2,266 121 (9,129)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 123 2 9,131
------------ ------------- ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 2,389 $ 123 $ 2
============ ============= ============
The accompanying notes are an integral part of these financial statements
30
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS For the Years Ended
December 31, 2000, 1999 and 1998
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
public company incorporated in the United Kingdom. Pursuant to a stock purchase
agreement dated April 1, 1996, Joint Energy Development Investments Limited
Partnership ("JEDI"), which is an affiliate of Enron Capital & Trade Resources
Corp. as of September 1, 1999 known as Enron North America Corp. ("ENA"),
together with members of management of the 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"). As a result of the sale of
Hardy Oil & Gas USA Inc.'s common stock, the name 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 owns 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. The net carrying value of proved oil and gas
properties is limited to an estimate of the future net revenues (discounted at
10%) from proved oil and gas reserves based on period-end prices and costs plus
the lower of cost or estimated fair value of unproved properties. As a result of
this limitation, permanent impairments of oil and gas properties of
approximately $50,800,000 was recorded during 1998. No writedown was necessary
in 2000 or 1999.
The costs of unproved properties are excluded from amortization using the
full-cost method of accounting. These costs are assessed quarterly for possible
impairments or reduction in value based on geological and geophysical data. If a
reduction in value has occurred, costs being amortized are increased. The
majority of the costs will be evaluated over the next three years.
Other Property and Equipment -- Depreciation of other property and
equipment is provided on a straight-line basis over their estimated useful lives
which range from five to seven years.
Deferred Loan Costs -- Deferred loan costs, which are included in other
assets, are stated at cost and amortized straight-line over their estimated
useful lives, not to exceed the life of the related debt.
Income Taxes -- The Company's taxable income is included in a consolidated
United States income tax return with Mariner Holdings Inc. 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.
31
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 $3,885,000, $3,028,000 and $1,702,000 for the years ended December
31, 2000, 1999 and 1998, respectively.
Accrual for Future Abandonment Costs -- Provision is made for abandonment
costs calculated on a unit-of-production basis, representing the Company's
estimated liability at current prices for costs which may be incurred in the
removal and abandonment of production facilities at the end of the producing
life of each property.
Hedging Program -- The Company utilizes derivative instruments in the form
of natural gas and crude oil price swap and price collar agreements in order to
manage price risk associated with future crude oil and natural gas production
and fixed-price crude oil and natural gas purchase and sale commitments. Such
agreements are accounted for as hedges using the deferral method of accounting.
Gains and losses resulting from these transactions are deferred, as appropriate,
until recognized as operating income in the Company's Statement of Operations as
the physical production required by the contracts is delivered.
The net cash flows related to any recognized gains or losses associated
with these hedges are reported as cash flows from operations. If the hedge is
terminated prior to expected maturity, gains or losses are deferred and included
in income in the same period as the physical production required by the
contracts is delivered.
The conditions to be met for a derivative instrument to qualify as a hedge
are the following: (i) the item to be hedged exposes the Company to price risk;
(ii) the derivative reduces the risk exposure and is designated as a hedge at
the time the derivative contract is entered into; and (iii) at the inception of
the hedge and throughout the hedge period there is a high correlation of changes
in the market value of the derivative instrument and the fair value of the
underlying item being hedged.
When the designated item associated with a derivative instrument matures,
is sold, extinguished or terminated, derivative gains or losses are recognized
as part of the gain or loss on sale or settlement of the underlying item. When a
derivative instrument is associated with an anticipated transaction that is no
longer expected to occur or if correlation no longer exists, the gain or loss on
the derivative is recognized in income to the extent the future results have not
been offset by the effects of price or interest rate changes on the hedged item
since the inception of the hedge.
Revenue Recognition -- The Company recognizes oil and gas revenue from its
interests in producing wells as oil and gas from those wells is produced and
sold. Oil and gas sold is not significantly different from the Company's share
of production.
Financial Instruments -- The Company's financial instruments consist of
cash and cash equivalents, receivables, payables, and debt. At December 31, 2000
and 1999, the estimated fair value of the Company's Senior Subordinated Notes
was approximately $91,000,000 and $92,000,000, respectively. The estimated fair
value was determined based on borrowing rates available at December 31, 2000 and
1999, respectively, for debt with similar terms and maturities. The carrying
amount of the Company's other instruments noted above approximate fair value.
Use of Estimates in the Preparation of Financial Statements -- The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amount of revenues and expenses during the reporting period. Actual
results could differ from these estimates.
32
Major Customers -- 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. During the year ended December 31, 1999, sales of oil and gas to
three purchasers, including an affiliate, accounted for 26%, 21% and 13% of
total revenues. During the year ended December 31, 1998, sales of oil and gas to
four purchasers accounted for 29%, 16%, 15% and 10% of total revenues.
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 years
financial statements to conform to the current year presentation.
Recent Accounting Pronouncements -- Statement of Financial Accounting
Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging
Activities, is effective for all fiscal years beginning after June 15, 2000.
SFAS 133, as amended and interpreted, establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. All derivatives,
whether designated in hedging relationships or not, will be required to be
recorded on the balance sheet at fair value. If the derivative is designated in
a fair-value hedge, the changes in the fair value of the derivative and the
hedged item will be recognized in earnings. If the derivative is designated in a
cash-flow hedge, changes in the fair value of the derivative will be recorded in
other comprehensive incomes (OCI) and will be recognized in the income statement
when the hedged item affects earnings. SFAS 133 defines new requirements for
designation and documentation of hedging relationships as well as ongoing
effectiveness assessments in order to use hedge accounting. For a derivative
that does not qualify as a hedge, changes in fair value will be recognized in
earnings.
The Company expects that at January 1, 2001, it will record $33.3 million
charge in OCI as a cumulative transition adjustment for derivatives designated
in cash flow-type hedges prior to adopting SFAS 133. The Company does not expect
to record a cumulative transition adjustment to earnings relating to derivatives
not designated as hedges prior to the adoption of SFAS 133.
The Company adopted the provisions of Staff Accounting Bulletin ("SAB") No.
101 issued by the staff of the Securities and Exchange Commission. The impact of
adopting SAB No. 101 was not material to the Company.
In the fourth quarter of 2000, the Company adopted Emerging Issues Task
Force Issue No. 00-10 ("EITF No. 00-10") Accounting for Shipping and Handling
Fees and Costs. EITF No. 00-10 addresses how shipping and handling fees should
be classified in the income statement. As a result of EITF No. 00-10, the
Company has reclassified transportation expenses from oil and gas revenues to a
separate line item. The amounts reclassified for the years ended December 31,
2000, 1999 and 1998 were $7.8 million, $2.0 million and $1.3 million,
respectively.
2. RELATED-PARTY TRANSACTIONS
Sales to Affiliates -- For the years ending December 31, 2000, 1999 and
1998, sales to affiliates were approximately $73.4 million, $16.2 million and
$8.9 million, respectively.
Receivables from Affiliates - At December 31, 2000 and 1999, receivables
from affiliates were $993,533 and $76,100, respectively.
Affiliate Transactions Subsequent to the Acquisition -- Enron
Corp.("Enron") is the parent of ENA, and an affiliate of Enron and ENA is the
general partner of JEDI. Accordingly, Enron may be deemed to control JEDI,
Mariner Energy LLC, Mariner Holdings and the Company. In addition, eight of the
Company's directors are officers of Enron or affiliates of Enron. Enron and
certain of its subsidiaries and other affiliates collectively participate in
many phases of the oil and natural gas industry and are, therefore, competitors
of the Company. In addition, ENA and JEDI have provided, and may in the future
provide, and ENA Securities Limited Partnership has assisted, and may in the
future assist, in arranging financing to non-affiliated participants in the oil
and natural gas industry who are or may become competitors of the Company.
Because of these various conflicting interests, ENA, the Company, JEDI and the
members of the Company's management who are also 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.
33
Transportation Contract - In 1999 the Company constructed a 29 mile
flowline from a third party platform to the Mississippi Canyon 718 subsea well.
After commissioning, MEGS LLC, an Enron affiliate, purchased the flowline from
the Company and its joint interest partners. The Company received $8.8 million
in cash proceeds which were offset against the cost of constructing the
flowline. No gain or loss was recognized. In addition the Company entered into a
firm transportation contract at a rate of $0.26 per MMbtu with MEGS LLC to
transport its share of 86 Bcf of natural gas from the commencement of production
through March 2009. For the year ending December 31, 2000 the Company paid $4.3
million on this contract. The Company's working interest at December 31, 2000
was 51%.
The Company expects that from time to time it will engage 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,
engaging in hydrocarbon price hedging arrangements and entering into other oil
and gas related or financial transactions. For example, the Company has entered
into several agreements with Enron or affiliates of Enron for the purpose of
hedging oil and natural gas prices on the Company's future production. Certain
of the Company's debt instruments restrict the Company's ability to engage in
transactions with its affiliates, but those restrictions are subject to
significant exceptions. The Company believes that its current agreements with
Enron 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 contained in an agreement with a third party.
3. 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 provides for a maximum $150 million revolving
credit loan. The available borrowing base under the Revolving Credit Facility is
currently $70 million and is subject to periodic redetermination. The Revolving
Credit Facility has an outstanding balance of $30.0 million at December 31,
2000. On June 28, 1999, the Revolving Credit Facility was amended to extend the
maturity date from October 1, 1999 to October 1, 2002 and to pledge certain
Mariner interests to secure the Revolving Credit Facility.
Borrowings under the Revolving Credit Facility bear interest, at the option
of the Company, at either (i) LIBOR plus 0.75% to 1.25% (depending upon the
level of utilization of the Borrowing Base) or (ii) the higher of (a) the
agent's prime rate or (b) the federal funds rate plus 0.5%. The effective
interest rate at December 31, 2000 was 8.49%. The Company incurs a quarterly
commitment fee ranging from 0.25% to 0.375% per annum on the average unused
portion of the Borrowing Base, depending upon the level of utilization.
The Revolving Credit Facility, as amended, contains various restrictive
covenants which, among other things, restrict the payment of dividends, limit
the amount of debt the Company may incur, limit the Company's ability to make
certain loans and investments, limit the Company's ability to enter into certain
hedge transactions and provide that the Company must maintain specified
relationships between cash flow and fixed charges and cash flow and interest on
indebtedness. As of December 31, 2000, the Company was in compliance with all
such requirements.
Affiliate Credit Facility -- In April 1999, the Company established a $25
million borrowing-based short-term credit facility with ENA to obtain funds
needed to execute the Company's 1999 capital expenditure program and for
short-term working capital needs. The facility accrued interest at an annual
rate of LIBOR plus 2.5% and required a structuring fee of 1% of the committed
amount. The effective interest rate for the year ended December 31, 2000 and
1999 was 8.52% and 8.69%, respectively. The facility matured on May 1, 2000 and
was repaid from a capital contribution from the Company's parent. Accordingly,
the facility was classified as long-term debt as of December 31, 1999.
34
10 1/2% Senior Subordinated Notes -- On August 14, 1996 the Company
completed the sale of $100 million principal amount of 10 1/2% Senior
Subordinated Notes Due 2006, (the "Notes"). The proceeds of the Notes were used
by the Company to (i) pay a dividend to Mariner Holdings, which used the
dividend to fully repay a bridge loan from JEDI incurred in the Acquisition, and
(ii) repay the Revolving Credit Facility. The Notes bear interest at 10 1/2%
payable semiannually in arrears on February 1 and August 1 of each year. The
Notes are unsecured obligations of the Company, and are subordinated in right of
payment to all senior debt (as defined in the indenture governing the Notes) of
the Company, including indebtedness under the Revolving Credit Facility.
The indenture pursuant to which the Notes are issued contains certain
covenants that, among other things, limit the ability of the Company to incur
additional indebtedness, pay dividends, redeem capital stock, make investments,
enter into transactions with affiliates, sell assets and engage in mergers and
consolidations. As of December 31, 2000, 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, 2000, 1999 and
1998 was $15.3, $15.1 million and $15.7 million, respectively.
4. 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 will not be less than the fair market value of the shares at the
date of grant. The maximum number of shares of Mariner Holdings common shares
that may be issued under the Plan was 142,800. In June 1998, the Plan was
amended to increase the number of eligible shares to be issued to 202,800. In
September 1998, concurrent with the exchange of each common share of Mariner
Holdings for twelve common shares of Mariner Energy LLC, the 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 2,433,600.
During the years ended December 31, 2000, 1999 and 1998, the Mariner Energy
LLC granted stock options ("Options") of 39,144, 215,748 and 329,172,
respectively. No options have been exercised, however, 66,828 options have been
canceled during the three year period. At December 31, 2000, options to purchase
2,200,620 shares had been issued at an exercise price ranging from $8.33 to
$14.58 per share. These Options generally become exercisable as to one-fifth to
one-third on each of the first three or five anniversaries of the date of grant.
The Options expire from seven years to ten years after the date of grant.
The Company applies APB Opinion 25 and related interpretations in
accounting for the Plan. Accordingly, no compensation cost has been recognized
for the Plan. Had compensation cost for the 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,
2000 would have been reduced by $422,000 to $21,439,000 and the net loss for the
years ending 1999 and 1998 would have decreased $428,000 and $357,000,
respectively. The effects of applying SFAS No. 123 in this pro forma disclosure
are not indicative of future amounts. The fair value of each option grant is
estimated on the date of grant using a present value calculation, risk free
interest of 6.46% for the year ending December 31, 2000 and 6.46% for the years
ending December 31, 1999 and 1998. Stock options available for future grant
amounted to 232,980 shares at December 31, 2000. Exercisable stock options
amounted to 1,625,582 shares at December 31, 2000.
35
Capital Contribution -- In March and May of 2000, we received cash equity
contributions by the sale of common stock to our Parent of $30 million and $25
million, respectively. The March equity contribution was used to reduce accounts
payable and accrued liabilities, and the May equity contribution was used to
repay the Affiliate Credit Facility with ENA. These equity contributions were
made with proceeds from the Mariner Energy LLC three-year $112 million term loan
with ENA. Due to certain restrictions with our Indenture and Revolving Credit
Agreement, neither cash flows from operations nor from asset sales would be
available to repay any portion of this term loan.
5. EMPLOYEE BENEFIT AND ROYALTY PLANS
Employee Capital Accumulation Plan -- The Company provides all full-time
employees participation in the Employee Capital Accumulation Plan (the "Plan")
which is comprised of a contributory 401(k) savings plan and a discretionary
profit sharing plan. Under the 401(k) feature, the Company, at its sole
discretion, may contribute an employer-matching contribution equal to a
percentage not to exceed 50% of each eligible participant's matched salary
reduction contribution as defined by the Plan. Under the discretionary profit
sharing contribution feature of the Plan, the Company's contribution, if any,
shall be determined annually and shall be 4% of the lesser of the Company's
operating income or total employee compensation and shall be allocated to each
eligible participant pro rata to his or her compensation. During 2000, 1999 and
1998, the Company contributed $251,017, $180,000 and $182,000, 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, 2000, 1999 and 1998 were $2.9 million, $1.0
million and $1.0 million, respectively.
6. COMMITMENTS AND CONTINGENCIES
Minimum Future Lease Payments -- The Company leases certain office
facilities and other equipment under long-term operating lease arrangements.
Minimum rental obligations under the Company's operating leases in effect at
December 31, 2000 are as follows (in thousands):
2001............................. 1,345
2002............................. 1,346
2003............................. 654
2004............................. 110
-----
Total.......................$3,455
======
Rental expense, before capitalization, was approximately $1,228,000,
$1,170,000 and $1,000,000 for the years ended December 31, 2000, 1999 and 1998,
respectively.
Hedging Program -- The Company conducts a hedging program with respect to
its sales of crude oil and natural gas using various instruments whereby monthly
settlements are based on the differences between the price or range of prices
specified in the instruments and the settlement price of certain crude oil and
natural gas futures contracts quoted on the open market. The instruments
utilized by the Company differ from futures contracts in that there is no
contractual obligation which requires or allows for the future delivery of the
product.
36
The following table sets forth the results of hedging transactions during
the periods indicated:
Year Ended December 31,
2000 1999 1998
-------- -------- -------
Natural gas quantity hedged (Mmbtu) ................ 19,569 18,818 9,800
Increase (decrease) in natural gas sales (thousands) ($21,364) ($ 6,741) $ 2,337
Crude oil quantity hedged (MBbls) .................. 1,059 389 --
Increase (decrease) in crude oil sales (thousands) . ($14,053) ($ 2,152) --
The following tables set forth the Company's position as of December 31,
2000.
Price
Notional ---------------------
Time Period Quantities Floor Ceiling Fixed Fair Value
----------- ---------- ----- ------- ----- ----------
(in millions)
Natural Gas (MMBtu)
January 1 - September 30, 2001
Collar purchased 4,216 $3.50 $4.92 (8.5)
Put option purchased 4,216 $3.50 --
Fixed price swap purchased 3,376 $2.18 (18.0)
October 1 - December 31, 2001
Fixed price swap purchased 774 2.18 (2.5)
January 1 - December 31, 2002
Fixed price swap purchased 1,831 2.18 (4.3)
--------
Total ($33.3)
========
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.
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.
37
7. INCOME TAXES
The following table sets forth a reconciliation of the statutory federal
income tax with the income tax provision (in thousands):
2000 1999 1998
-------------------- --------------------- ---------------------
$ % $ % $ %
----------- -------- ------------ -------- ------------ --------
Income (loss) before income taxes 21,861 -- (9,970) -- (58,421) --
Income tax expense (benefit)
computed at statutory rates.... 7,651 35 (3,490) (35) (20,447) (35)
Change in valuation allowance.. (8,074) (34) 2,330 23 18,804 32
Other.......................... (423) (1) 1,160 12 1,643 3
----------- -------- ------------ -------- ------------ --------
Tax Expense.................... -- -- -- -- -- --
=========== ======== ============ ======== ============ ========
No federal income taxes were paid by the Company during the years ended
December 31, 2000, 1999 or 1998.
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):
2000 1999 1998
--------- -------- --------
Deferred tax assets:
Net operating loss carry forwards ....................... $ 44,939 $ 43,401 $ 34,771
Valuation allowance ..................................... (28,056) (36,130) (33,800)
--------- -------- --------
Total net deferred tax assets ........................... 16,883 7,271 971
Deferred tax liabilities --
Differences between book and tax bases of properties (16,883) (7,271) (971)
--------- -------- --------
Total net deferred taxes ...................... $ -- $ -- $ --
========= ======== ========
As of December 31, 2000, the Company has a cumulative net operating loss
carryforward ("NOL") for federal income tax purposes of approximately $128
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.
38
8. OIL AND GAS PRODUCING ACTIVITIES and CAPITALIZED COSTS
The results of operations from the Company's oil and gas producing
activities were as follows (in thousands):
Year ended Year ended Year ended
December 31, December 31, December 31,
2000 1999 1998
------------- -------------- ------------
Oil and gas sales................... $121,150 $54,485 $58,015
Production costs.................... (17,192) (11,453) (9,858)
Transportation...................... (7,789) (2,017) (1,325)
Depreciation, depletion and (56,846) (32,121) (33,833)
amortization........................
Impairment of oil and gas properties -- -- (50,800)
------------- -------------- ------------
Results of operations........... $ 39,323 $8,894 $(37,801)
============= ============== ============
Costs incurred in property acquisition, exploration and development
activities were as follows (in thousands, except per equivalent mcf amounts):
Year ended Year ended Year ended
December 31, December 31, December 31,
2000(1) 1999(1) 1998
--------- -------- --------
Property acquisition costs
Unproved properties.......... $1,724 $2,982 $43,143
Exploration costs................. 16,005 13,522 35,674
Development costs................. 60,738 44,561 61,960
--------- --------- ---------
Total costs, net of proceeds from
property conveyances........... $78,467 $61,065 $140,777
========= ========= =========
Depreciation, depletion and amortization
rate per equivalent Mcf before impairment $1.57 $1.29 $1.40
(1) Property acquisition costs, exploration costs and development costs are
net of proceeds from property conveyances of $9.6 million, $5.0 million, $14.4
million and $7.5 million, $0 and $12.3 for the years ending December 31, 2000
and 1999, respectively.
The Company capitalizes internal costs associated with exploration
activities in progress. These capitalized costs were approximately $11,625,000,
$9,440,000 and $6,386,000 for the years ended December 31, 2000, 1999 and 1998,
respectively.
The following table summarizes costs related to unevaluated properties
which have been excluded from amounts subject to amortization at December 31,
2000. 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.
39
Cost Incurred During the Total at
Year Ended December 31, December 31,
2000 1999 1998 2000
--------- -------- -------- --------
Property
Acquisition costs $5,652 $8,802 $42,815 $57,269
Exploration costs 3,143 646 10 3,799
--------- -------- -------- --------
Total....... $8,795 $9,448 $42,825 $61,068
========= ======== ======== ========
Approximately 99% of excluded costs at December 31, 2000 relate to
activities in the Deepwater Gulf of Mexico and the remaining 1% relates to
activities in the Gulf of Mexico shallow waters and onshore areas near the Gulf.
9. 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, 2000 were reserves expected to be
recovered from wells for which certain drilling and completion operations had
occurred as of that date, but for which significant future capital expenditures
were required to bring the wells into commercial production.
Reserve estimates are inherently imprecise and may change as additional
information becomes available. Furthermore, estimates of oil and gas reserves,
of necessity, are projections based on engineering data, and there are
uncertainties inherent in the interpretation of such data as well as in the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured
exactly, and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
Accordingly, estimates of the economically recoverable quantities of oil and
natural gas attributable to any particular group of properties, classifications
of such reserves based on risk of recovery and estimates of the future net cash
flows expected therefrom prepared by different engineers or by the same
engineers at different times may vary substantially. There also can be no
assurance that the reserves set forth herein will ultimately be produced or that
the proved undeveloped reserves set forth herein will be developed within the
periods anticipated. It is likely that variances from the estimates will be
material. In addition, the estimates of future net revenues from proved reserves
of the Company and the present value thereof are based upon certain assumptions
about future production levels, prices and costs that may not be correct when
judged against actual subsequent experience. The Company emphasizes with respect
to the estimates prepared by 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.
40
Estimated Quantities of Proved Reserves
(in thousands)
Natural Gas
Equivalent
Oil (Bbl) Gas (Mcf) (Mcfe)
------ -------- -----------
December 31, 1997 .................................. 6,630 121,366 161,146
Revisions of previous estimates .................. (836) (410) (5,426)
Extensions, discoveries and other additions ...... 4,351 27,416 53,522
Production ....................................... (786) (19,477) (24,193)
------ ------- -------
December 31, 1998 .................................. 9,359 128,895 185,049
------ ------- -------
Revisions of previous estimates .................. 715 (5,098) (808)
Extensions, discoveries and other additions ...... 1,225 24,972 32,322
Sale of reserves in place ........................ (742) (8,856) (13,308)
Production ....................................... (630) (21,123) (24,903)
------ ------- -------
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
Sales 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 .................................. 12,387 129,256 203,638
====== ======= =======
Estimated Quantities of Proved Developed Reserves
(in thousands)
Natural Gas
Equivalent
Oil (Bbl) Gas (Mcf) (Mcfe)
--------- --------- ---------
December 31, 1998 2,886 86,024 103,340
December 31, 1999 3,799 82,760 105,554
December 31, 2000 5,540 61,623 94,863
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.
41
Standardized Measure of Discounted Future Net Cash Flows
(in thousands)
Year ended December 31,
2000 1999 1998
--------- -------- ---------
Future cash inflows .................................... $ 1,758,734 $ 490,239 $ 383,490
Future production costs ................................ (161,617) (122,681) (103,400)
Future development costs ............................... (162,277) (70,774) (81,090)
Future income taxes .................................... (372,059) -- --
--------- -------- --------
Future net cash flows .................................. 1,062,781 296,784 199,000
--------- -------- --------
Discount of future net cash flows at 10% per annum ..... (290,075) (85,558) (51,371)
--------- -------- --------
Standardized measure of discounted future net cash flows $ 772,705 $ 211,226 $ 147,629
========= ======== ========
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, 2000, 1999 and 1998, used in the
above table, were $26.36, $23.85 and $10.36 per Bbl, respectively, and $11.32,
$2.23 and $2.22 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 ended December 31,
----------------------------------------
2000 1999 1998
----------- ---------- ----------
Sales and transfers of oil and gas
produced, net of production costs ............ $ (96,169) $(41,015) $(46,832)
Net changes in prices and production costs ... 503,871 77,532 (67,815)
Extensions and discoveries, net of
future development and production costs ...... 214,022 33,357 23,730
Development costs during period and
net change in development costs .............. 39,736 (3,661) 30,799
Revision of previous quantity estimates ...... (13,365) (984) (6,846)
Purchases of reserves in place ............... 157,657 -- --
Sales of reserves in place ................... (2,584) (15,535) --
Net change in income taxes ................... (270,510) -- 27,193
Accretion of discount before income taxes .... 29,678 19,900 20,365
Changes in production rates (timing) and other (857) (5,997) (9,424)
----------- ---------- ---------
$ 561,479 $ 63,597 $ (28,830)
Net change =========== ========== =========
Item 9. Changes In and Disagreements With Accountants On Accounting and
Financial Disclosure
None
42
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 15, 2001. 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
Robert E. Henderson 48 Chairman of the Board, President and Chief Executive Officer
Richard R. Clark 45 Executive Vice President and Director
L. V. "Bud" McGuire 58 Senior Vice President of Operations and Director
Michael W. Strickler 45 Senior Vice President of Exploration and Director
Frank A. Pici 45 Vice President of Finance and Chief Financial Officer
Gregory K. Harless 51 Vice President of Oil and Gas Marketing
W. Hunt Hodge 45 Vice President of Administration
Tom E. Young 42 Vice President of Business Development
Kelly D. Zelikovitz 42 General Counsel and Secretary
David S. Huber 50 Consultant and Director of Deepwater Development
Raymond M. Bowen 45 Director
Richard B. Buy 48 Director
Timothy J. Detmering 42 Director
Jeffrey M. Donahue, Jr. 38 Director
Craig A. Fox 45 Director
Mark E. Haedicke 45 Director
Jesus G. Melendrez 41 Director
Jeffrey B. Sherrick 46 Director
Mr. Henderson has been our Chairman of the Board since May 1996, President
and Chief Executive Officer since 1987 and a director since 1985. Mr. Henderson
served as a director of London-based Hardy Plc, our former parent company,
between 1989 and 1996. From 1984 to 1987, he served us or predecessors as Vice
President of Finance and Chief Financial Officer. From 1976 to 1984, he held
various positions with ENSTAR Corporation, including Treasurer of ENSTAR
Petroleum, which operated in the U.S. and Indonesia.
Mr. Clark has served us in various engineering and operations activities
since 1984 and has been Executive Vice President since May 1998. He served as
Senior Vice President of Production from 1991 until May 1998 and has served as a
director since 1988. Prior to joining us he worked as a Production Engineer in
the Offshore Production Group of Shell Oil Company.
Mr. McGuire joined us in June 1998 as Senior Vice President-Operations.
Prior to joining us, Mr. McGuire was Vice President-Operations for Enron Oil &
Gas International, Inc. Before joining EOGI, he served five years with
Kerr-McGee Corporation as Senior Vice President over worldwide production
operations. His experience prior to Kerr-McGee included Hamilton Oil Corporation
from 1981 to 1991, where he served as Operations Manager then as Vice President
of Operations for Hamilton in the North Sea. He began his career in 1966 with
Conoco.
Mr. Strickler joined us in 1984 and has served since such time in our
geological and exploration activities. He has served as Senior Vice President of
Exploration since 1991 and a director since 1989. Prior to joining us, Mr.
Strickler worked for several independent oil companies as an exploration
geologist, generating and evaluating exploration plays in the Gulf Coast, Mid
Continent, Rocky Mountains, West Texas and several overseas basins.
Mr. Pici became Vice President of Finance and Chief Financial Officer in
December 1996. Prior to joining us, Mr. Pici was employed by Cabot Oil & Gas
Corporation holding several positions since 1989, including Corporate
Controller. Prior to joining Cabot Oil & Gas, he was Controller of a
privately-held independent oil & gas company, and he began his career with
Coopers & Lybrand. He is a Certified Public Accountant.
43
Mr. Harless has served as Vice President of Oil and Gas Marketing since
1990. Prior to joining us in 1988, he was Vice President of Marketing and
Regulatory Affairs of Enron Oil and Gas Company and District Operating Manager
with Coastal States Oil & Gas.
Mr. Hodge has served as Vice President of Administration since 1991. Prior
to joining us in 1985, he was Purchasing Manager of Santa Fe Minerals Company.
Mr. Young has served as Vice President of Business Development since
January 2001. Mr. Young also served as our Vice President of Land from November
1998 to January 2001, and as Manager of Land for the Central Gulf and as a
landman since joining us in 1985. Prior to joining us, Mr. Young served as a
landman for TXO Production Corp.
Ms. Zelikovitz has been our General Counsel and Secretary since August
2000. She is in private practice and has a contractual relationship with us.
Prior to May 1998, she held various legal and management positions with Mobil
Oil Corporation, Greenhill Petroleum Corporation, Union Texas Petroleum
Corporation, and with a Houston-based law firm.
Mr. Huber, a consultant, began his association with us in 1991 as a
deepwater project management consultant and is presently our Director of
Deepwater Developments. 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. Bowen has served as a director since January 2000. He is currently
Managing Director of ENA and Co-Head of the Commercial Transactions Group and
has held various management positions with ENA since 1996. Prior to joining ENA,
Mr. Bowen was a Vice President and Senior Banker in Citicorp's Petroleum, Metals
and Mining Department in Houston.
Mr. Buy has served as a director since January 1998. Since 1994 he has been
an employee of ENA or its affiliates, currently serving as Senior Vice President
and Chief Risk Officer of Enron Corp. Prior to joining Enron, Mr. Buy was a Vice
President at Bankers Trust in the Energy Group.
Mr. Detmering has served as a director since March 2001. Since 1994 he has
been an employee of ENA or its affiliates, currently serving as a Managing
Director of Corporate Development. Prior to joining Enron, Mr. Detmering was an
Engineer with ARCO Oil & Gas Co. and an Investment Banker with Wasserstein
Perella and Co.
Mr. Donahue has served as a director since August 2000. He joined Enron in
April 1998 as Vice President responsible for Corporate Development of ENA. Prior
to joining ENA, Mr. Donahue was an investment banker focusing on the energy
industry at UBS Securities, CS First Boston and Kidder Peabody. He was also a
management consultant with McKinsey & Company and an economic policy consultant
at ICF Incorporated.
Mr. Fox has served as a director since March 2001. He is currently Vice
President and Technical Manager for Enron 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. Haedicke has served as a director since October 1998. He is currently
Managing Director, Legal, of ENA. Mr. Haedicke also serves on the board of
directors of the International Swaps and Derivatives Association, Inc. and he
holds a seat on the New York Mercantile Exchange. He has been associated with
ENA since its inception in 1990.
Mr. Melendrez is a Vice President of ENA and is responsible for the
execution and structuring of upstream transactions. Prior to joining ENA in
1999, Mr. Melendrez was Sr. Vice President of Enserch Energy Services, Inc. He
has held financial positions with several Enron affiliates since the early
1990's which involved loan restructuring and power marketing.
44
Mr. Sherrick has served as a director since January 2000. He is currently
the President and Chief Executive Officer of Enron Global Exploration &
Production Inc. and has held various management positions with Enron Oil & Gas
Company, or one of its affiliates, since 1993.
The Shareholders' Agreement requires that the Board of Directors include at
least three nominees of the Management Stockholders. Currently, those three
representatives are Messrs. Henderson, Clark and Strickler. The remaining board
members are to include nominees of JEDI. See "Certain Relationships and Related
Transactionson page 51.
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, 2000. These individuals are
sometimes referred to as the "named executive officers".
Annual Compensation Current Year
------------------------- Compensation
Under our
Other Annual Overriding Royalty All Other
Name and Principal Position Salary Compensation(1) Program(2) Compensation(3)
-------- ------------ ------- ---------------
Robert E. Henderson ......... 2000 $295,000 $ 3,680 $ 8,690 $ 270
President and ............... 1999 285,000 6,400 5,438 396
Chief Executive Officer .. 1998 285,000 4,800 1,292 522
Richard R. Clark ............ 2000 235,000 3,680 5,596 210
Executive Vice President .... 1999 225,000 6,400 3,508 243
of Production ............ 1998 225,000 4,800 821 306
Michael W. Strickler ........ 2000 198,000 3,680 5,596 188
Senior Vice President ....... 1999 190,000 6,400 3,508 243
of Exploration ........... 1998 182,000 4,800 821 306
L. V. "Bud" McGuire (4) ..... 2000 198,000 3,680 0 114,774
Senior Vice President ....... 1999 190,000 4,433 0 44,573
of Operations ........... 1998 110,834 0 0 788
Frank A. Pici ............... 2000 167,000 3,680 3,440 180
Vice President of Finance ... 1999 160,000 6,400 2,043 243
and Chief Financial Officer . 1998 160,000 4,380 356 306
(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 2000, 1999 or 1998.
(3) Amounts shown reflect insurance premiums paid by us with respect to
term life insurance for the benefit of the named executive officers and any
performance bonuses paid during the year.
(4) Mr. McGuire joined us in June 1998 and is eligible for guideline
bonuses under our incentive compensation plan. He does not participate in the
Overriding Royalty Program.
45
Options
Mariner Energy LLC granted 0 and 48,624 options to purchase common shares
to Mr. McGuire in 2000 and 1999, respectively. None of the named executive
officers exercised stock options in 2000. The following table shows the number
and value of options owned by our named executive officers at December 31, 2000.
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, 2000
Exercisable Unexercisable
Robert E. Henderson......... 190,896 47,724
Richard R. Clark............ 134,342 33,586
L. V. "Bud" McGuire......... 85,116 72,948
Michael W. Strickler........ 134,342 33,586
Frank A. Pici............... 43,848 29,232
Share Option Plan
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 us and our shareholders. A total
of 2,433,600 common shares may be issued under options granted under the 1996
plan, subject to adjustment for any share split, share dividend or other change
in the common shares or our capital structure. Options to purchase 2,200,620
common shares are outstanding under the 1996 plan, 1,625,582 of which are
currently exercisable. The exercise price for outstanding options to purchase an
aggregate of 1,683,386 shares under the 1996 plan is $8.33 per share, and the
exercise price for options to purchase the remaining outstanding aggregate of
517,234 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
We and each of the named executive officers are parties to employment
agreements that expire on September 30, 2002. Following the expiration date of
an employment agreement or the expiration of any extended term, the employment
agreements extend for six months, unless notice of termination is given by
either us or the named executive officer at least six months before the end of
the initial term or extended term, as applicable.
Under the employment agreements, the current annual salaries are $295,000
for Mr. Henderson, $235,000 for Mr. Clark, $198,000 for Mr. Strickler, $198,000
for Mr. McGuire and $167,000 for Mr. Pici. Our board of directors may in its
discretion increase their salaries.
46
The named executive officers are entitled to participate in any medical,
dental, life and accidental death and dismemberment insurance programs and
retirement, pension, deferred compensation and other benefit programs instituted
by us from time to time. The employees are also entitled to vacation,
reimbursement of specified expenses and, depending on the employment agreement,
an automobile allowance and reimbursement for expenses related to the use of
that vehicle. As incentive compensation, the named executive officers, except
for Mr. McGuire, are entitled to receive overriding royalty interests in some
oil and gas prospects that we have acquired under our overriding royalty
program. Mr. McGuire is entitled to receive annual cash bonuses and incentive
stock option awards under an incentive compensation plan separate from other
named executive officers.
If we terminate a named executive officer's employment agreement without
cause, if the named executive officer terminates his employment contract for
good reason, or if we give notice of termination on the expiration of his term
of employment, then the named executive officer will be entitled to, among other
things:
o the value of his salary and other benefits through the end of the
initial term or any extended term of the employment agreement;
o a lump sum cash payment equal to 12 months salary in the case of Mr.
Henderson, nine months salary in the case of Messrs. Clark, Strickler
and McGuire and six months salary in the case of Mr. Pici plus, in the
case of Mr. McGuire, an amount equal to 40% of nine months salary;
o a lump sum cash payment equal to all earned and unused vacation time
for the previous year and the then current year;
o an assignment of his vested interests under our overriding royalty
program, if eligible; and
o in the case of Mr. McGuire, a lump sum payment equal to any unpaid
bonus from prior years under our incentive compensation plan, plus, in
lieu of any bonus for subsequent years, an amount equal to 40% of his
base salary through the end of the remaining term of his employment
agreement.
If a named executive officer's employment agreement is terminated by the
named executive officer without good reason, the named executive officer gives
notice of termination on the expiration of his term of employment or if we
consent to a request by the named executive officer to terminate his employment
agreement before the expiration of his term, he will be entitled to:
o the value of his salary and benefits through the date that his
employment agreement is terminated;
o a lump sum cash payment equal to all earned and unused vacation time
for the previous year and the then current year;
o an assignment of his vested interests in our overriding royalty
program through the date of termination, if eligible; and
o in the case of Mr. McGuire, a lump sum payment equal to any unpaid
bonus from prior years under our incentive compensation plan, plus, in
lieu of any bonus for subsequent years, an amount equal to 40% of his
base salary through the end of the remaining term of his employment
agreement.
If a named executive officer's employment agreement is terminated by us for
cause, we will have no obligation to that employee other than to:
o pay his salary through the day of termination;
o pay him the value of his benefits under the employment agreement
through the month of termination; and
o assign to him his vested interests in our overriding royalty program
through the date of termination, if eligible.
47
To the extent any amounts paid under an employment agreement are subject to
the "golden parachutes" excise tax, those amounts are grossed-up to cover the
excise tax and any applicable taxes on the gross-up amount.
Each named executive officer has agreed that during the term of his
employment agreement, and, if the named executive officer's employment agreement
is terminated by us for cause or terminated by the named executive officer other
than for good reason, for 12 months after the term expires in the case of
Messrs. Henderson, Clark, Strickler and McGuire and six months after the term
expires in the case of Mr. Pici, he will not compete with us for business or
hire away our employees.
For purposes of the employment agreements with the named executive
officers, "good reason" means:
o The assignment to the employee of any duties materially inconsistent
with the employee's position, authority, duties or responsibilities
with us or any other action that results in a material diminution in,
or interference with, such position, authority, duties or
responsibilities, if the assignment or action is not cured within 30
days after the employee has provided us with written notice;
o The failure to continue to provide the employee with office space,
related facilities and support personnel (a) that are commensurate
with the employee's responsibilities to, and position with, us and not
materially dissimilar to the office space, related facilities and
support personnel provided to our other employees having comparable
responsibilities or (b) that are physically located at our principal
executive offices, if that failure is not cured within 30 days after
the employee has provided us with written notice;
o Any (a) reduction in the employee's monthly salary, (b) reduction in,
discontinuance of, or failure to allow or continue to allow the
employee's participation in, our incentive compensation program, or
(c) reduction in, or failure to allow or continue the employee's
participation in, any employee benefit plan in which the employee is
participating or is eligible to participate before the reduction or
failure, and that reduction, discontinuance or failure is not cured
within 30 days after the employee has provided us with written notice;
o The relocation of the employee's or our principal office and principal
place of the employee's performance of his duties and responsibilities
to a location more than 50 miles outside of the central business
district of Houston, Texas; or
o A breach of any material provision of the employment agreement that is
not cured within 30 days after the employee has provided us with
written notice.
Change of Control Agreements
We have issued each of the named executive officers' change of control
agreements. Under these agreements, if a change of control occurs and the named
executive officer's employment is terminated without cause or for good reason
within 18 months of the change of control, Messrs. Henderson, Clark, McGuire,
Pici and Strickler are entitled to receive, if the change in control is due to
an acquisition of us by another company, three and one-half times their base
salary and targeted annual incentive bonus, if applicable. The severance payment
will be calculated assuming we satisfy the applicable base target for a
particular year for the targeted annual incentive bonus. The ultimate payment
due under the change of control agreements will be the greater of the payment
calculated under the change of control agreements or the compensation due for
the remaining balance under the employment agreements. To the extent any amounts
paid under the change in control agreemens are subject to the "golden
parachutes" excise tax, those amounts are grossed-up to cover the excise tax and
any applicable taxes on the gross-up amount.
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.
48
The overriding royalty interest percentage of our working interest to which
each named executive officer is entitled for the period before well payout is
one-fourth of the overriding royalty interest percentage for the period after
well payout. These percentages currently range from 0.09375% to 0.23250% before
payout and from 0.37500% to 0.93000% after payout for the named executive
officers.
If all or a portion of our working interest in a prospect is sold or farmed
out to unaffiliated third parties and we determine in good faith that our
interest will not be marketable on satisfactory terms if marketed subject to the
named executive officer's overriding royalty interest affecting the prospect, we
may adjust the named executive officer's overriding royalty interest in the
prospect. These adjustments are determined by a committee designated by our
board of directors, at least half of the members of which are individuals who
have been granted an overriding royalty interest by us. Some committee decisions
require the approval of our board of directors. These adjustments apply only to
the portion of our working interest sold or farmed out to a third party and do
not affect the named executive officer's overriding royalty interest in the
portion of a prospect retained by us.
We may also elect, within 60 days after the end of our fiscal year, to
reduce a named executive officer's overriding royalty interest in prospects that
we acquired during the fiscal year. We must base these reductions on the levels
of exploration and development costs related to these prospects actually
incurred during the fiscal year. With respect to certain deepwater prospects, we
also may elect, in our sole discretion, to make other reductions and adjustments
to the employee's overriding royalty interest based on estimated exploration
levels and development costs to be incurred in connection with these deepwater
prospects. We retain a right of first refusal to purchase any overriding royalty
interest assigned to a named executive officer. This right applies to any
third-party offer received by the named executive officer during or within one
year after the named executive officer's employment is terminated.
The following table shows distributions received during the applicable year
by the named executive officers who are participants in the plan, some of which
were paid by third parties, from overriding royalty interests we granted to the
officers during the last 15 years.
Aggregate Cash Amounts Received
from Previously Assigned Overriding
Royalty Interests(1)
------------------------------------
Name 2000 1999 1998
---------------- ---- ---- ----
Robert E. Henderson........ $502,155 $227,054 $354,857
Richard R. Clark........... 301,702 137,774 218,077
Michael W. Strickler....... 298,452 131,103 212,803
Frank A. Pici.............. 70,399 1,093 0
----------
(1) For information on the value conveyed and distributions received, if
any, during the applicable year attributable to overriding royalty
interests assigned to the named executive officer during the
applicable year, see the table under "Summary Compensation Table".
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 1, 2001, there were 13,928,308 common shares of Mariner Energy LLC
outstanding.
49
Amount and
Name and Address Nature of Percent
Title of Class of Benefical Owner Beneficial Owner of Class
-------------- ------------------ ---------------- --------
Common Stock of Joint Energy Development 13,334,186 95.7%
Mariner Energy LLC Investments Limited Partnership (1)
1400 Smith Street
Houston, TX 77002
(1) 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 1, 2000, with
respect common shares of Mariner Energy LLC beneficially owned by each of our
directors, our 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.
Directors, Key Consultant and Amount and Nature of Percent
Named Executive Officers Beneficial Ownership of Class
(1)
Robert E. Henderson............... 84,840 *
Richard R. Clark.................. 61,440 *
L. V. "Bud" McGuire............... 6,120 *
Michael W. Strickler.............. 61,440 *
Frank A. Pici..................... 20,472 *
David S. Huber.................... 61,440 *
Raymond M. Bowen.................. 0 *
Richard B. Buy.................... 0 *
Timothy J. Detmering.............. 0 *
Jeffrey M. Donahue, Jr............ 0 *
Craig A. Fox...................... 0 *
Mark E. Haedicke.................. 0 *
Jesus Melendrez................... 0 *
Jeffrey B. Sherrick............... 0 *
All directors and executive officers and
key consultant as a group (17 persons) 347,508 2.49%
* 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.
50
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 Affiliates
Enron is the parent of ENA, and an affiliate of Enron and ENA is the
general partner of JEDI. Accordingly, Enron may be deemed to control JEDI and
us. See "Ownership of Securities". In addition, eight of the Company's directors
are officers of Enron or of affiliates of Enron: Mr. Bowen is a Managing
Director of ENA, Mr. Buy is Senior Vice President and Chief Risk Officer of
Enron Corp., Mr. Detmering isa Managing Director of ENA, Mr. Donahue is a Vice
President of ENA, Mr. Fox is a Vice President for Enron Capital Resources, Mr.
Haedicke is a Managing Director of ENA, Mr. Melendrez is a Vice President of
ENA, and Mr. Sherrick is President and Chief Executive Officer of Enron Global
Exploration and Production, Inc.
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, and may in the future
assist, in arranging financing to non-affiliated participants in the oil and
natural gas industry who are or may become competitors of 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.
Under the Revolving Credit Facility, Mariner has covenanted that it will
not engage in any transaction with any of its affiliates (including Enron, ENA,
JEDI and affiliates of such entities) providing for the rendering of services or
sale of property unless such transaction is as favorable to such party as could
be obtained in an arm's-length transaction with an unaffiliated party in
accordance with prevailing industry customs and practices. The Revolving Credit
Facility excludes from this covenant (i) any transaction permitted by the
Shareholders' Agreement, (ii) the grant of options to purchase or sales of
equity securities to directors, officers, employees and consultants of Mariner
and (iii) the assignment of any overriding royalty interest pursuant to an
employee incentive compensation plan.
The Indenture, dated as of August 1, 1996, between Mariner and United
States Trust Company of New York (the "Indenture"), under which the Senior
Subordinated Notes were issued, contains similar restrictions. Under the
Indenture, Mariner Energy, Inc. has covenanted not to engage in any transaction
with an affiliate unless the terms of that transaction are no less favorable to
Mariner than could be obtained in an arm's-length transaction with a
nonaffiliate. Further, if such transaction involves more than $1 million, it
must be approved in writing by a majority of Mariner's disinterested directors,
and if such a transaction involves more than $5 million, it must be determined
by a nationally recognized banking firm to be fair, from a financial standpoint,
to Mariner. However, this covenant is subject to several significant exceptions,
including, among others, (i) certain industry-related agreements made in the
ordinary course of business where such agreements are approved by a majority of
Mariner's disinterested directors as being the most favorable of several bids or
proposals, (ii) transactions under employment agreements or compensation plans
entered into in the ordinary course of business and consistent with industry
practice and (iii) certain prior transactions. Mariner expects that from time to
time it will engage 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, engaging in hydrocarbon price hedging
arrangements and entering into other oil and gas related or financial
transactions. For example, Mariner has entered into several agreements with
Enron or affiliates of Enron for the purpose of hedging oil and natural gas
prices on Mariner's future production. Mariner believes that its current
agreements with Enron and its affiliates are, and anticipates that, but can
provide no assurances that, any future agreements with Enron and its affiliates
will be, on terms no less favorable to Mariner than would be contained in an
agreement with a third party.
51
Mariner Energy LLC Credit Facility with ENA
Our parent established the ENA Credit Facility to provide us with
additional capital. The ENA Credit Facility provides for unsecured, subordinated
loans to our parent up to $50 million, bearing interest at LIBOR plus 4.5%,
payable monthly. In addition, upon any draw against the facility, our parent
must pay a structuring fee equal to 4% of the principal amount of the borrowing.
This agreement is expected to be repaid in full at maturity on April 30, 2000
through a capital contribution from our parent.
Affiliate Credit Facility
In April 1999, the Company established a $25 million borrowing-based
short-term credit facility with ENA to obtain funds needed to execute the
Company's 1999 capital expenditure program and for short-term working capital
needs. The facility accrued interest at an annual rate of LIBOR plus 2.5% and
required a structuring fee of 1% of the committed amount. The effective interest
rate for the year ended December 31, 2000 and 1999 was 8.52% and 8.69%,
respectively. The facility matured on May 1, 2000 and was repaid from a capital
contribution from the Company's parent. Accordingly, the facility was classified
as long-term debt as of December 31, 1999.
Capital Contribution
In March and May of 2000, we received cash equity contributions by the sale
of common stock to our Parent of $30 million and $25 million, respectively. The
March equity contribution was used to reduce accounts payable and accrued
liabilities, and the May equity contribution was used to repay the Affiliate
Credit Facility with ENA. These equity contributions were made with proceeds
from the Mariner Energy LLC three-year $112 million term loan with ENA. Due to
certain restrictions with our Indenture and Revolving Credit Agreement, neither
cash flows from operations nor from asset sales would be available to repay any
portion of this term loan.
Firm Transportation Contract
In 1999 we constructed a 29 mile flowline from a third party platform to
the Mississippi Canyon 718 subsea well. After commissioning the flowline, MEGS
LLC, an Enron affiliate, purchased the flowline from us and our joint interest
partners. We received $8.8 million in cash proceeds which were offset against
the cost of constructing the flowline. No gain or loss was recognized. In
addition, we entered into a firm transportation contract with MEGS LLC at a rate
of $0.26 per Mcf to transport our share of 86 Bcf of natural gas from the
commencement of production through March 2009. For the year ending December 31,
2000 the Company paid $4.3 million on this contract. Our working interest
increased from 37% to 51% after the project reached payout in the third quarter
of 2000.
52
PART IV
Item 14. 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.
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.).
53
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.).
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.
10.4(a)+Amended and Restated Employment Agreement, dated June 27,
1996, between the Registrant and Robert E. Henderson.
10.5(a)+Amended and Restated Employment Agreement, dated June 27,
1996, between the Registrant and Richard R. Clark.
10.6(a)+Amended and Restated Employment Agreement, dated June 27,
1996, between the Registrant and Michael W. Strickler.
10.7*+ Amended and Restated Employment Agreement, dated January 1,
1997, between the Registrant and Tom E. Young.
10.8*+ Amended and Restated Employment Agreement, dated December 27,
1998, between the Registrant and Gregory K. Harless.
10.9*+ Amended and Restated Employment Agreement, dated December 27,
1998, between the Registrant and W. Hunt Hodge.
10.10(a)+ Amended and Restated Consulting Services Agreement, dated
June 27, 1996, between the Registrant and David S. Huber.
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.
10.17*+ Amended and Restated Employment Agreement, dated as of
December 1, 1998, between the Registrant and Frank A. Pici.
10.18*+ Amended and Restated Employment Agreement, dated as of June 1,
1998, between the Registrant and L.V. Bud McGuire.
10.19(e)Third Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc. and
Richard R. Clark.
54
10.20(e)Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc. and
Gregory K. Harless.
10.21(e)Third Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc. and
Robert E. Henderson.
10.22(e)Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc. and
William Hunt Hodge.
10.23(e)First Amendment to Amended and Restated Consulting Services
Agreement, effective as of October 1, 1999, between Mariner Energy,
Inc. and David S. Huber.
10.24(e)First Amendment to Employment Agreement, effective as of
October 1, 1999, between Mariner Energy, Inc. and L.V. McGuire.
10.25(e)Third Amendment to Employment Agreement, effective as of
October 1, 1999, between Mariner Energy, Inc. and Frank A. Pici.
10.26(e)Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc. and
Michael W. Strickler.
10.27(e)First Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc. and
Thomas E. Young.
10.28(g)Gas Gathering Agreement, dated December 29, 1999 between MEGS,
LLC and Mariner Energy, Inc. and Burlington Resources, Inc.
10.29(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.
23.1** Consent of Ryder Scott Company.
23.2** Ryder Scott Company Letter of Estimated Proved Reserves dated
February 23, 2001
27.1** Financial Data Schedule.
(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, 1999, June
30, 1999 or September 30, 1999 quarterly filings on Form 10-Q.
(g) Incorporated by reference to the Mariner Energy Inc. December 31, 2000
annual filing on form 10-K
(b) Reports on Form 8-K:
The Company filed no reports on Form 8-K during the quarter ended December
31, 2000.
55
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".
56
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet of natural gas equivalent (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.
57
"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.
"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.
58
SIGNATURES
The registrant has duly caused this report to be signed on its behalf by
the undersigned, hereunto duly authorized.
April 2, 2000
MARINER ENERGY, INC.
by:/s/ Robert E. Henderson
-----------------------
Robert E. Henderson,
Chairman of the Board, President and Chief Executive Officer
This report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title
-------------------------------------------------------------------------------
Date
-------
Signature Title Date
/s/ ROBERT E. HENDERSON Chairman of the Board, April 2, 2001
--------------------------- President and Chief
Robert E. Henderson Executive Officer
(Principal Executive
Officer)
Vice President of Finance April 2, 2001
/s/ FRANK A. PICI and Chief-Financial
--------------------------- Officer (Principal Financial
Frank A. Pici Officer and Principal
Accounting Officer)
/s/ L. V. MCGUIRE Senior Vice President of April 2, 2001
--------------------------- Operations and Director
L. V. McGuire
/s/ RICHARD R. CLARK Executive Vice President April 2, 2001
--------------------------- and Director
Richard R. Clark
/s/ MICHAEL W. STRICKLER Senior Vice President of April 2, 2001
--------------------------- Exploration and Director
Michael W. Strickler
/s/ RAYMOND M. BOWEN Director April 2, 2001
---------------------------
Raymond M. Bowen
/s/ RICHARD B.BUY Director April 2, 2001
---------------------------
Richard B. Buy
/s/ TIMOTHY J. DETMERING Director April 2, 2001
---------------------------
Timothy J. Detmering
/s/ JEFFREY M. DONAHUE, JR. Director April 2, 2001
---------------------------
Jeffrey M. Donahue, Jr.
/s/ CRAIG A. FOX Director April 2, 2001
---------------------------
Craig A. Fox
/s/ MARK E. HAEDICKE Director April 2, 2001
---------------------------
Mark E. Haedicke
/s/ JESUS G. MELEDREZ Director April 2, 2001
---------------------------
Jesus G. Melendrez
/s/ JEFFREY B. SHERRICK Director April 2, 2001
---------------------------
Jeffrey B. Sherrick
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.