1
- -------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
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 27, 1999, there were 1,378 shares of the registrant's
common stock outstanding.
- -------------------------------------------------------------------------------
2
TABLE OF CONTENTS
Item Page
- ------------------------------------------------------------------------------------------------------------------
PART I
1.and 2. Business and Properties
(a) Overview ....................................................................... 1
(b) Business Strategy .............................................................. 3
(c) Reserves ....................................................................... 4
(d) Oil and Gas Properties ......................................................... 5
(e) Production ...................................................................... 8
(f) Productive Wells ............................................................... 8
(g) Acreage ........................................................................ 9
(h) Drilling Activity................................................................ 9
(i) Marketing, Customers and Hedging Activities ................................... 10
(j) Competition ................................................................... 11
(k) Regulation .................................................................... 11
(l) Employees....................................................................... 12
3. Legal Proceedings............................................................................... 12
4. Submission of Matters to a Vote of Security Holders............................................. 12
PART II
5. Market for Registrant's Common Equity and Related Stockholder Matters........................... 13
6. Selected Financial Data......................................................................... 13
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
(a) Introduction ....................................................................... 14
(b) General............................................................................. 14
(c) Results of Operations............................................................... 15
(d) Liquidity and Capital Resources..................................................... 17
(e) Year 2000 Issues..................................................................... 20
(f) Market Risk Disclosure............................................................... 21
8. Financial Statements and Supplementary Data..................................................... 22
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure......................................................................42
PART III
10. Directors and Executive Officers of the Registrant.............................................. 42
11. Executive Compensation.......................................................................... 44
12. Security Ownership of Certain Beneficial Owners and Management.................................. 45
13. Certain Relationships and Related Party Transactions............................................ 46
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K................................. 49
Glossary........................................................................................ 51
3
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, 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 51 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 three geographical areas of the United States; the shallow water
or "shelf" (water depths less than 600 feet) of the Gulf of Mexico ("Gulf") and
onshore areas near the Gulf; the "Deepwater" Gulf (water depths greater than
600 feet); and the Permian Basin of West Texas. Most of the Company's senior
managers have been with the Company since 1984 and have over 20 years
experience in the oil and natural gas exploration and production business. The
Company has been an active explorer in the Gulf Coast area since the mid-
1980s, when it operated as Hardy Oil & Gas USA Inc., and has grown its
production and reserve base through the drillbit. Mariner's increasing focus on
the Gulf in water depths greater than 600 feet since the early 1990's has made
it one of the most experienced independent operators in the Deepwater Gulf,
where it has operated six subsea development projects.
Management of the Company and an affiliate of Enron Capital & Trade
Resources Corp. ("ECT") acquired the Company from Hardy Oil & Gas, plc
effective April 1, 1996 ("the Acquisition"). From the Acquisition effective
date though December 31, 1998, the Company boosted its reserve base
approximately 56%, increasingly emphasizing Deepwater Gulf exploration along
with its well-established Deepwater Gulf exploitation activities. The Company's
Deepwater Gulf drilling program has resulted in four new field discoveries in
eight exploration wells drilled since the Acquisition. Mariner operates three
of these four discoveries. First production from two of these discoveries
commenced in 1998 and the Company expects first production from the other two
in 1999 or 2000. Subsequent to year-end the Company had another Deepwater
discovery which may be the most significant discovery for the Company to date,
pending successful appraisal drilling.
Since the Acquisition, the Company has more than tripled its inventory
of Deepwater Gulf lease blocks through federal lease sales in which new
Deepwater leases include royalty relief benefits. In 1998, Mariner acquired 20
Deepwater Gulf lease blocks through federal lease sales and farm-in
arrangements, which blocks the Company believes add significant potential for
reserve and production growth. As of December 31, 1998, Mariner had 128 blocks
in the Gulf of Mexico, including 66 in the Deepwater Gulf, and held an
inventory of 22 drillable exploration prospects, including 16 in the Deepwater
Gulf, which it expects to drill over the next two to three years. In March
1999, the Company was the apparent high bidder at a federal lease sale on three
blocks in water depths of 4,000 to 5,000 feet. Management believes all of these
blocks encompass drillable prospects.
As of December 31, 1998, the Company had proved reserves of 185.1
Bcfe, of which 70% was natural gas and 30% was oil and condensate. Also, the
Company held a total undeveloped leasehold inventory of approximately 216,000
net acres, including 87 undeveloped Gulf blocks, and held under license or
other arrangement approximately 8,200 square miles of 3-D seismic data and
approximately 241,000 linear miles of 2-D seismic data.
From June 1, 1989 (when the Company began to focus its efforts on the
Gulf) through December 31, 1998, the Company drilled 287 gross (95.6 net)
wells, including 97 gross (31.2 net) exploration and Deepwater exploitation
wells. Of these wells, 32 were completed (26 in Gulf shallow water or onshore
and 6 in Gulf Deepwater), representing a 33%
1
4
success rate on its exploration and Deepwater exploitation activities. During
the same period, the Company completed approximately 92% of its development
wells.
From January 1, 1994 through December 31, 1998, the Company increased
its annual average daily production by 41% to approximately 66 Mmcfe per day.
During the same period the Company replaced 170% of its annual production
through the drill bit, primarily on Company-generated drilling prospects. To
partially fund the drilling program, the Company sold some properties. Net of
disposals, proved reserves have increased 45% over the period.
The following table sets forth certain summary information with
respect to the Company's oil and gas activities and results during the five
years ended December 31, 1998. 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 for each year, held
constant throughout the projected reserve life. 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,
(in thousands unless otherwise indicated)
-------------------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
Proved reserves:
Oil (Mbbls).......................................... 9,359 6,630 5,280 6,669 6,900
Natural gas (Mmcf)................................... 128,895 121,366 92,284 98,330 100,645
Natural gas equivalent (Mmcfe)....................... 185,049 161,148 123,964 138,344 142,045
Present value of estimated future net revenues (1)...... $ 147,629 $ 183,829 $ 303,363 $ 173,421 $ 95,318
Annual reserve replacement ratio (2)................... 2.0 2.6 1.2 1.2 2.0
Capital expenditures:
Capital costs incurred............................... $ 141,855 $ 68,868 $ 46,625 $ 41,772 $ 36,923
Percentage attributable to:
Lease acquisition................................. 30.4% 36.0% 30.7% 11.0% 6.8%
Exploratory drilling, geological and geophysical.. 25.1% 39.7% 48.7% 58.2% 48.5%
Development and other............................. 44.5% 24.3% 20.6% 30.8% 44.7%
Proceeds from property sales......................... -- -- $ 7,528 $ 20,688 $ 3,480
Production:
Oil (Mbbls).......................................... 786 977 750 424 459
Natural gas (Mmcf)................................... 19,477 18,004 20,429 13,770 14,362
Natural gas equivalents (Mmcfe)...................... 24,193 23,866 24,929 16,314 17,116
Average realized sales price per unit
(including the effects of hedging):
Oil (per Bbl)........................................ $ 12.80 $ 18.48 $ 18.04 $ 17.10 $ 15.83
Natural gas (per Mcf)................................ 2.39 2.48 2.29 1.83 1.92
Gas equivalent (per Mcfe)............................ 2.34 2.63 2.42 1.99 2.04
Expenses per Mcfe:
Lease operating...................................... 0.41 0.39 0.36 0.39 0.36
General and administrative, net...................... 0.20 0.13 0.13 0.12 0.11
(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.
2
5
(b) BUSINESS STRATEGY
Mariner's strategy is to increase reserves, production and cash flow
in a cost effective manner primarily "through the drill bit" -- emphasizing
growth through exploration, exploitation and development of internally
generated prospects, with heavy emphasis on the Deepwater Gulf. Approximately
90% by value of Mariner's proved reserves as of December 31, 1998 was
attributable to fields developed from internally generated prospects. The
Company prefers to operate the wells in which it participates.
The Company pursues a portfolio approach to its drilling program,
balancing risk and potential reward and currently targeting 5 to 10 new
projects per year. This program is designed to supply predictable reserve
replacement and production growth through lower risk Deepwater Gulf
exploitation and substantial growth through a moderate risk exploration
component where individual prospects can significantly increase the reserve
base. Mariner currently targets capital allocation for exploration and
exploitation efforts as follows:
Portfolio Component Capital allocation Target
------------------- -------------------------
Deepwater Gulf Exploration 55-70%
Deepwater Gulf Exploitation 20-30%
Shelf/Onshore Gulf Exploration 5-15%
The Company focuses on the Deepwater Gulf because of (i) the potential
for discovery of large hydrocarbon deposits, (ii) relatively favorable
reservoir characteristics, (iii) the prevalence of 3-D seismic direct
hydrocarbon indicators, (iv) the relatively under-explored nature of the
region, (v) recent advances in Deepwater production technology that reduce
development costs and expedite production and (vi) the favorable operating
margins resulting from generally favorable prices for Gulf production and lower
operating costs per unit. These lower operating costs per unit are attributed
to prolific wells, concentration of labor and equipment, absence of severance
and ad valorem taxes and generally lower royalties.
Deepwater Gulf Exploitation. Six years ago Mariner was one of the
first to recognize the opportunity to partner with major oil companies to
develop smaller Deepwater discoveries which do not meet a large company's
field-size threshold. The Company's initial Deepwater activities were
exploitation projects involving subsea tiebacks of natural gas wells to
existing platforms in water depths of 1,000 feet or less. After developing
significant experience managing these projects, Mariner added more challenging
natural gas projects in deeper water and oil subsea tieback projects. The
Company operated two subsea tieback exploitation projects in the Deepwater Gulf
in 1995 and 1996 and was recognized for its deepwater expertise by Hart
Publications, which awarded its 1996 "Best in Gulf" Award for the Company's
"Shasta" project. During 1997 and 1998, the Company acquired a 97% working
interest in and operatorship of the planned "Pluto" exploitation subsea tieback
project located in 2,800 feet of water on Mississippi Canyon block 718.
Deepwater Gulf Exploration. Mariner expanded its Deepwater Gulf
program in 1996 to include moderate risk exploratory drilling for small to
mid-sized targets where its subsea expertise, coupled with the benefits of
royalty relief on new leases, provide an opportunity for attractive economic
returns. From the Acquisition through December 31, 1998, the Company has
discovered four new fields in eight Deepwater Gulf exploratory test wells
drilled. These four discoveries have been or are in the process of being
developed with subsea tieback production systems. In 1997, Mariner further
expanded its Deepwater Gulf program to selectively pursue larger exploratory
targets which, if successful, may require the installation of dedicated
floating production systems. The Company believes that these prospects offer
significant reserve and production potential. In March 1999, the Company
announced a significant discovery on one of these prospects located in
approximately 7,100 feet of water offshore Louisiana in Mississippi Canyon
block 305, on which appraisal drilling is expected to be undertaken during
1999. To support its Deepwater exploration strategy, Mariner acquired 28 total
Deepwater Gulf blocks in 1996 and 1997, 20 Deepwater Gulf blocks in 1998 and
three Deepwater Gulf blocks in the March 1999 lease sale.
Shelf/Onshore Gulf Exploration. Mariner's strategy in the Gulf shallow
water and near onshore fields is to focus on certain prospects in areas where
it has been successful in obtaining attractive rates of return. Since the
Acquisition, the Company has made five exploratory discoveries in the
Shelf/Onshore Gulf area, three of which the Company generated internally.
Mariner also devotes a small portion of its capital resources to relatively low
risk development infill drilling operations in the Spraberry Trend of the
Permian Basin of West Texas, which continues to be important to its internal
growth strategy by providing a consistent source of cash flow for use in other
activities.
3
6
Mariner believes that the following competitive strengths distinguish
the Company from other independent oil and gas companies. These advantages are
responsible to a significant extent for the success of the Company's
exploration and exploitation efforts in recent years.
Early Entry Into Deepwater Gulf. Mariner established operations in the
Deepwater Gulf in 1992 as one of the first independent oil and natural gas
companies in the deepwater. After six years of managing projects in the
Deepwater Gulf, the Company believes it has a competitive operating advantage
in the area. This competitive advantage consists of a strong understanding of
the geology and geophysics of the Deepwater Gulf, familiarity with challenges
peculiar to operating in the Deepwater Gulf and relationships with vendors,
major oil companies and other partners having complementary skills and
knowledge of the area.
Experienced Geoscience Staff. The Company's skilled technical staff of
twelve geoscientists averages over 20 years experience, including extensive
experience in the Deepwater Gulf and with major oil companies. This staff
applies state-of-the-art technology to minimize exploration risk and maximize
returns. Substantially all of the Company's exploration and exploitation
prospects are generated using 3-D seismic data.
Exploration Prospect Inventory. Mariner had an inventory of 22
drillable exploration prospects as of December 31, 1998 (including 16 in the
Deepwater Gulf), which it expects to drill over the next two to three years.
Pursuant to arrangements with partners on three of the prospects it was awarded
in 1998, Mariner's share of exploration drilling costs on these prospects,
estimated to be approximately $16 million, will be paid by its partners. The
Company holds 87 undeveloped blocks and approximately 8,200 square miles of 3-D
seismic under license or other arrangements to facilitate prospect generation.
With 128 blocks on the Gulf of Mexico, including 66 in the Deepwater Gulf and
numerous Deepwater Gulf lease blocks scheduled to become available over the
next several years, Mariner believes that it is positioned to increase its
lease and prospect holdings.
Access to Deepwater Drilling Rig. The Company executed a letter of
intent in February 1998 regarding the provision of a Deepwater drilling rig to
Mariner and another company on an equally shared basis for five years beginning
late 1999 or early 2000. The Company is currently in discussions with the owner
of the rig to determine if a mutually acceptable drilling contract can be
negotiated.
Deepwater Operating Ability. The Company has made a substantial
investment in obtaining experienced Deepwater drilling and project management
personnel. Key management positions have been filled with individuals who
average over 20 years of subsea experience in the North Sea and the Deepwater
Gulf. This investment gives the Company the ability to execute Deepwater
projects beyond the scope of most independents.
Experienced Management with Significant Equity Incentives. The
management team has considerable expertise in the oil and gas industry and
significant experience working with the Company. All present key employees of,
and consultants to, the Company are either (i) eligible to participate in an
incentive program that provides overriding royalty interests in successful
projects or (ii) participate in a Stock Option Plan. The Company believes this
program strongly aligns management's and investors' interests. In addition, the
Company believes this program is a significant reason why it has been able to
retain the services of its senior management team, most of whom have been
working together at the Company for over 10 years. Certain members of
management and other key personnel of the Company have purchased approximately
4% of the common stock of Mariner Holdings and have acquired or received
options to purchase an additional 12% of the common stock of Mariner Holdings.
These shares and options were converted to Mariner Energy LLC shares and
options in 1998.
(c) RESERVES
The following table sets forth certain information with respect to the
Company's proved reserves by geographic area as of December 31, 1998. Reserve
volumes and values were determined under the method prescribed by the
Securities and Exchange Commission which requires the application of year-end
prices for each year, held constant throughout the projected reserve life. The
reserve information as of December 31, 1998 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 10 to the Financial Statements
of the Company 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 of the Company.
4
7
As of December 31, 1998
---------------------------------------------------------------------------
Present Value of
Proved Reserve Quantities Estimated Future Net Revenues (1)
---------------------------------- -------------------------------------
Oil Natural Gas Total Developed Undeveloped Total
Geographic Area (MBbls) (MMcf) (MMcfe) ($000) ($000) ($000)
- --------------- ------- ------ ------- -------- ------- --------
Deepwater Gulf.................... 4,183 60,851 85,949 $ 41,208 $21,821 $ 63,029
Gulf of Mexico Shelf and
Gulf Coast Onshore.......... 1,105 46,659 53,289 70,315 40 70,355
Permian Basin..................... 4,071 21,385 45,811 9,401 4,844 14,245
----- ------- ------- -------- ------- --------
Total....................... 9,359 128,895 185,049 $120,924 $26,705 $147,629
===== ======= ======= ======== ======= ========
Proved Developed Reserves......... 2,886 86,024 103,340 $120,924
===== ====== ======= ========
(1) Discounted (at 10%) present value as of December 31, 1998 (year-end prices
held constant).
The Company's estimates of proved reserves set forth in the foregoing
table do not differ materially from those filed by the Company with other
federal agencies.
(d) OIL AND GAS PROPERTIES
(i) SIGNIFICANT PRODUCING PROPERTIES
The Company owns oil and gas properties, both producing and for future
exploration and development, onshore in Texas and offshore in the Gulf,
primarily in federal waters. The Company's seven largest producing properties,
as shown in the following table, accounted for approximately 52% of the
Company's proved reserves as of December 31, 1998.
As of December 31, 1998
----------------------------------------------------------
Mariner Ownership Producing Net Average Net Proved
Working Net Revenue Wells Daily Production Reserves
Interest Interest (gross) Oil (Bbls) Gas (Mmcf) (Mmcfe)
-------- -------- -------- ---------- ---------- ---------
Deepwater Gulf:
Green Canyon 136 25.0% 21.5% 2 13 5.1 3,409
Garden Banks 240 33.0% 26.9% 1 42 5.0 6,910
Gulf Shallow Water and
Near Onshore Areas:
Sandy Lake 48.3% 36.0% 5 715 16.3 14,544
Brazos A-105 12.5% 9.9% 5 11 7.2 13,594
Galveston 151 33.3% 26.7% 3 843 12.0 7,405
Matagorda Island 683/703 25.0% 20.1% 4 1 32.1 4,257
Permian Basin of West Texas:
Spraberry Aldwell Unit 70.3% 54.4% 82 501 2.1 45,811
-------
Totals - Principal Producing Properties 95,930
=======
Following is additional information regarding the properties in the table shown
above.
5
8
Deepwater Gulf
GREEN CANYON 136 ("SHASTA"). Shasta was generated by the Company,
acquired through a farmout transaction with Texaco and achieved initial
production in 1995. The 5,760 acre block is located offshore Louisiana in water
depths of approximately 840 to 1,040 feet. The Company operated the property to
the date of first production when Texaco became the operator. Two producing
wells have been drilled, and no additional drilling is currently planned. Green
Canyon 136 is tied back, by a specially laid subsea pipeline and connecting
system, to a production platform operated by Texaco approximately 10 miles from
the well sites, and its production is commingled and marketed with Texaco's
production. The field has an estimated remaining life of three years.
GARDEN BANKS 240 ("MUSTIQUE"). Mustique was generated by the Company,
acquired through a swap transaction with Shell Oil Company and achieved initial
production in January 1996. The 5,760 acre block is located offshore Louisiana
at a water depth of approximately 830 feet. The Company is the operator of the
property. One producing well has been drilled and no additional drilling is
currently planned. Garden Banks 240 is tied back by a subsea pipeline and
connecting system to a production platform operated by Chevron approximately 12
miles from the well site, where its production is commingled and marketed with
Chevron's production. The field has an estimated remaining life of five years.
Gulf Shallow Water and Near Onshore Areas
SANDY LAKE. The Sandy Lake property, located onshore in the Pine
Island Bayou Field of the Texas Gulf Coast, was generated by the Company and
achieved initial production in 1994. The majority of the 4,870 acre property is
located within the city limits of Beaumont, Texas. The Company is the operator
of the property. Currently there are five producing wells in the field, and the
Company is in the process of acquiring a 3D seismic survey to determine
additional drilling potential in the area. The current field production has an
estimated remaining life of three years.
BRAZOS A-105. Brazos A-105 was generated by the Company and achieved
initial production in 1993. The 4,320 acre block is located offshore Texas at a
water depth of approximately 190 feet. Union Oil Company of California is the
operator of the property and has drilled five producing wells thus far. No
additional drilling is currently planned. The field has an estimated remaining
life of nine years.
GALVESTON 151 ("REMBRANDT"). Rembrandt was generated by the Company
and achieved initial production in 1997. During 1998, Mariner drilled two
additional successful wells in adjacent fault blocks, significantly increasing
field production and proved reserves from the field. The 4,800 acre block is
located offshore Texas in less than 50 feet of water. Mariner is the operator
of the block. Additional drilling potential is currently under evaluation. The
reserves developed to date have a remaining life of approximately four years.
MATAGORDA ISLAND 683/703. Matagorda Island blocks 683 and 703 were
acquired by the Company as part of a bid group and commenced production in
1993. The two 5,760 acre blocks are located offshore Texas at a water depth of
approximately 125 feet. Vastar Resources, Inc. is the operator of the property.
Four producing wells have been drilled, and no additional drilling is currently
planned. The field has an estimated remaining economic life of six years.
The Permian Basin of West Texas
SPRABERRY ALDWELL UNIT. In 1985, the Company acquired its interest in
the Aldwell Unit property, which has been producing since 1949. The 15,776 acre
fieldwide unit is located within the Spraberry Trend and produces from the
unitized Spraberry Formation and non-unitized Dean Formation in Reagan County
in West Texas. The Company is the operator of the property, and its working
interest in individual wells ranges from 33% to 84% approximately. An infill
well drilling program was implemented in 1997, and, to date, 70 wells have been
drilled, all of which are currently producing. The drilling of additional
infill wells is planned as market conditions allow. The estimated remaining
life of the field is more than 45 years.
6
9
(ii) OTHER SIGNIFICANT PROPERTIES
In addition to the producing properties described above, the Company
also owns interests in three other properties which, while not producing at
December 31, 1998, represent a significant portion of proved reserves as of
that date. Those properties are described below.
GARDEN BANKS 367 ("DULCIMER"). Dulcimer was generated by the Company
and acquired at a federal offshore Gulf of Mexico lease sale in September 1996.
In late 1997, a successful exploration well was drilled on this 5,760 acre
block located offshore Louisiana at a water depth of approximately 1,100 feet.
The Company is the operator of the property and has a 41.7% working interest
and a 40.7% net revenue interest. No additional drilling is currently planned.
Dulcimer is expected to commence production in the second quarter of 1999,
after being tied back by a subsea pipeline and connecting system to a
production platform located approximately 14 miles from the well site. The
field has an estimated life of approximately seven years after the start of
production. Net proved reserves of 16.2 Bcfe, 97% natural gas, were included by
the Company at December 31, 1998.
MISSISSIPPI CANYON 673, 674, 717 AND 718 ("PLUTO"). During 1998, the
Company increased its working interest in this deepwater exploitation project
to 97% through a transaction with Chevron USA. The Company is operator of the
prospect, located offshore Louisiana in water depths exceeding 2,800 feet, and
has filed for Deepwater royalty relief with the Mineral Management Service. Two
exploration and appraisal wells had been drilled in this project prior to the
Company's ownership, which wells encountered a high-quality, gas condensate
reservoir. Drilling of one or two additional production wells and the
installation of a 30 mile flow line/umbilical system to a host platform on the
shelf will be necessary to fully develop the discovery. Drilling of the first
additional well is expected to commence in mid-1999 with concurrent
infrastructure installation, and first production is planned for the fourth
quarter of 1999. Ultimately, the Company expects to own a working interest in
the project between 33% and 75%. The field has an estimated life of
approximately eight years after the start of production, and net proved
reserves of 39.7 Bcfe (70% natural gas), reflecting a 75% working interest,
were included by the Company's estimate of proved reserves at December 31,
1998.
EWING BANK 966 ("BLACK WIDOW"). Mariner generated the Black Widow
deepwater prospect and acquired it at a federal offshore Gulf of Mexico lease
sale in March 1997. Mariner operates and has a 45% working interest in this
project, which is located offshore Louisiana at a water depth of approximately
1,900 feet. In early 1998, a successful exploration well was drilled on the
prospect. Mariner expects the well to commence production in 2000 via subsea
tieback to an existing platform. The Company estimates its net proved reserves
from the Black Widow at December 31, 1998, to be approximately 14 Bcfe, 82% of
which is oil.
(iii) SIGNIFICANT RECENT DEVELOPMENT
MISSISSIPPI CANYON 305 ("ACONCAGUA"). Aconcagua was generated by the
Company and acquired at a federal offshore Gulf of Mexico Lease Sale in March
1998. In March 1999, the Company announced an exploratory discovery on this
block, located in approximately 7,100 feet of water offshore Louisiana which
logged multiple pay sands and encountered additional sands with productive
potential. Appraisal and development plans for this significant discovery are
currently being prepared to quantify reserve estimates and to ensure an
appropriate development scenario. Drilling of the first appraisal well is
anticipated for the third or fourth quarter of 1999. The Company holds a
non-operating 25% working interest in the block.
(iv) DISPOSITION OF PROPERTIES
The Company periodically evaluates and, when appropriate, sells
certain of its producing properties that it considers to be marginally
profitable or outside of its areas of concentration. Such sales enable the
Company to maintain financial flexibility, reduce overhead and redeploy the
proceeds therefrom to activities that the Company believes have a higher
potential financial return. No property dispositions were made by the Company
during 1998.
(v) TITLE TO PROPERTIES
The Company's 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. The Company
does not believe that any of these burdens materially interferes with the use
of such properties in the operation of its business.
The Company believes that it has satisfactory title to or rights in
all of its 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
7
10
properties. Title investigation is made, and title opinions of local counsel
are generally obtained, only before commencement of drilling operations. The
Company believes 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 the Company's properties, average
sales price received and expenses per unit of production during the periods
indicated.
Year ended December 31,
--------------------------------------------------------------
1998 1997 1996
------ ------ ----
Production:
Oil (Mbbls)......................................... 786 977 750
Natural gas (Mmcf).................................. 19,477 18,004 20,429
Gas equivalent (per Mcfe)........................... 24,193 23,866 24,929
Average sales prices including effects of hedging:
Oil (per Bbl)....................................... $ 12.80 $ 18.48 $ 18.04
Natural gas (per Mcf)............................... 2.39 2.48 2.29
Gas equivalent (per Mcfe)........................... 2.34 2.63 2.42
Expenses (per Mcfe):
Lease operating..................................... .41 .39 .36
General and administrative, net (1)................. .20 .13 .13
Depreciation, depletion and amortization (2)........ 1.40 1.33 1.25
Cash margin per Mcfe (3)............................... 1.47 1.92 1.77
(1) Net of overhead reimbursements received by the Company from other
working interest owners and amounts capitalized under the full cost accounting
method.
(2) Excludes impairment of oil & gas properties
(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 the Company owned a working interest at December 31, 1998:
Total Productive Wells
------------------------
Gross Net
------- -----
Oil.............................. 92 65.5
Gas.............................. 99 17.5
--- ----
Total....................... 191 83.0
=== ====
Productive wells consist of producing wells and wells capable of
production, including gas wells awaiting pipeline connections. The Company has
six wells that are completed in more than one producing horizon; those wells
have been counted as single wells.
8
11
(g) ACREAGE
The following table sets forth certain information with respect to the
developed and undeveloped acreage of the Company as of December 31, 1998.
Developed Acres (1) Undeveloped Acres (2)
---------------------- ----------------------
Gross Net Gross Net
------- ------- ------- -------
Texas (Onshore).............................. 21,128 13,899 5,467 2,412
All other states (Onshore)................... 671 212 644 196
Offshore..................................... 211,391 60,414 435,167 213,614
------- ------- ------- -------
Total................................... 233,190 74,525 441,278 216,222
======= ====== ======= =======
(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 the Company's drilling activity
during the years ended December 31, 1998, 1997 and 1996 is set forth below.
Year Ended December 31,
----------------------------------------------------------------------
1998 1997 1996
------------------- ------------------- ------------------
Gross Net Gross Net Gross Net
----- ----- ----- ------ ----- -----
Exploratory wells:
Producing........................ 3 1.10 4 1.37 3 0.78
Dry.............................. 5 1.54 7 1.60 4 1.40
---- ----- ---- ----- ---- -----
Total........................ 8 2.64 11 2.97 7 2.18
==== ===== ==== ===== ==== =====
Development wells:
Producing........................ 19 8.61 11 5.27 5 1.73
Dry.............................. 3 1.13 - - - -
---- ----- ---- ----- ---- -----
Total........................ 22 9.74 11 5.27 5 1.73
==== ===== ==== ===== ==== =====
Total wells:
Producing........................ 22 9.71 15 6.64 8 2.51
Dry.............................. 8 2.67 7 1.60 4 1.40
---- ----- ---- ----- ---- -----
Total........................ 30 12.38 22 8.24 12 3.91
==== ===== ==== ===== ==== =====
9
12
(i) MARKETING, CUSTOMERS AND HEDGING ACTIVITIES
The Company markets substantially all oil and gas production from
Company-operated properties and from properties operated by others where
Mariner's interest is significant. The majority of the Company's 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, the Company has a long-term agreement
as to the sale of such gas and the processing thereof which the Company believes
to be competitive. Similarly, the Company has a gas processing agreement on its
gas production from Sandy Lake which the Company believes has the effect of
pricing its gas production favorably compared to market prices at that location.
The following table lists customers accounting for more than 10% of the
Company's total revenues for the year indicated (a "-" indicates that revenues
from the customer accounted for less than 10% of the Company's total revenues
for that year).
Percentage of total revenues
For the year ended December 31
----------------------------------------------
Customer 1998 1997 1996
-------- --------- ----------- -----------
PanEnergy Marketing Co. 29% 19% -
Transco Energy Marketing Company 16% 14% 15%
Enron Capital & Trade Resources Corp.
(An affiliate) 15% 18% -
Genesis Crude Oil LP (formerly
Howell Crude Oil Company) 10% 19% 13%
Texaco Natural Gas, Inc. - - 13%
Seneca Resources Corporation - - 10%
Due to the nature of the markets for oil and natural gas, the Company
does not believe that the loss of any one of these customers would have a
material adverse effect on the Company's financial condition or results of
operations.
Historically, demand for natural gas has been seasonal in nature, with
peak demand and typically higher prices occurring during the colder winter
months.
From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to reduce its exposure to
price fluctuations and to achieve a more predictable cash flow. The Company
does not engage in hedging activities for speculative purposes. The Company
customarily conducts its hedging strategy through the use of swap arrangements
that establish an index-related price above which the Company pays the hedging
partner and below which the Company is paid by the hedging partner. During
1998, approximately 40% of the Company's equivalent production was subject to
hedge positions, and the Company did not have any open positions at December
31, 1998. Subsequent to December 31, 1998, the Company entered into a commodity
price hedging contract under a costless collar covering 60,000 Mmbtu per day of
natural gas production with a floor price of $1.85 per Mmbtu and a ceiling
price of $2.05 per Mmbtu for the period beginning April 1, 1999 to October 31,
1999. This agreement can be extended for the same daily volume through March
2000 for a floor price of $2.00 per Mmbtu and a ceiling of $2.70 per Mmbtu at
the option of the counterparty to the transaction. Subsequent to December 31,
1998, the Company entered into a long-term hedging agreement for a three-year
period from November 1, 1999 through October 31, 2002. Average volumes hedged
by year are approximately 44,000, 30,000, 12,000 and 6,000 Mmbtu per day for
1999, 2000, 2001, and 2002, respectively, at a price of $2.18 per Mmbtu. In
April 1999, the Company entered into a hedging agreement covering 600 barrels
of oil per day for the period May 1, 1999 through December 31, 1999 at a price
of $16.32 per Bbl. Hedging arrangements for 1999 cover approximately 53% of the
Company's anticipated equivalent production for the year. Hedging arrangements
for 2000, 2001 and 2002 cover approximately 30%, 10% and 3% of the Company's
anticipated equivalent production, respectively. Hedging arrangements may
expose the Company to the risk of financial loss in certain circumstances,
including instances where the Company's production, which is in effect hedged,
is less than expected or where there is a sudden, unexpected event materially
impacting prices. The Company's Revolving Credit Facility (see note 4 of the
financial statements) places certain restrictions on the Company's use of
hedging. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Changes in Prices and Hedging Activities".
10
13
(j) COMPETITION
The Company believes that the locations of its leasehold acreage, its
exploration, drilling and production capabilities, and the experience of its
management generally enable it to compete effectively. However, the Company's
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 the Company's larger competitors possess and employ financial
and personnel resources substantially greater than those available to the
Company. 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 the Company's
financial or personnel resources permit. The Company's ability to acquire
additional prospects and to discover reserves in the future is dependent upon
its 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) REGULATION
The Company's 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 the Company's cost of doing business and,
consequently, affects its profitability. However, the Company does not believe
that it is affected in a significantly different manner by these regulations
than are its 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 the
Company and the revenues received by the Company 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. FERC proposes to revise its regulations to require all
available short term capacity (including capacity released by shippers holding
firm entitlements) to be allocated through an auction process. FERC also
proposes to require pipelines to offer additional services under open access
principles, such as "park and loan" 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. Among other
things, FERC is seeking input on retention of cost-based rate regulation for
long term transportation services, potential changes in the manner in which
rates are designed and the use of index driven or incentive rates for pipelines.
The July 29, 1998 Notice of Inquiry may lead to a subsequent Notice of Proposed
Rulemaking to further revised FERC's regulations.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any such
proposals might become effective or their effect, if any, on the Company's
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 the
Company owns and operates 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 the Company can produce from its wells and to limit the number of
wells or the locations at which the
11
14
Company 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.
(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 the Company's operations and costs.
In particular, the Company's exploration, development and production operations,
its activities in connection with storage and transportation of crude oil and
other liquid hydrocarbons and its 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 the Company's 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, the Company may generate waste that may fall within CERCLA's
definition of a "hazardous substance". The Company 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.
The Company currently owns or leases, and has 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 the Company has 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 the Company 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
the Company's control. These properties and wastes disposed thereon may be
subject to CERCLA and analogous state laws. Under such laws, the Company 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.
(l) EMPLOYEES
As of December 31, 1998, the Company had 71 full-time employees. The
Company's employees are not represented by any labor union. The Company
considers relations with its employees to be satisfactory. The Company has never
experienced a work stoppage or strike.
ITEM 3. LEGAL PROCEEDINGS
In December, 1996, ETOCO, Inc., which owns a 20% interest in one
producing well operated by the Company, filed a lawsuit against the Company in
the district court of Hardin County, Texas, alleging damage due to the Company's
refusal to drill an additional well. In April 1998, after a trial on the merits,
a jury awarded ETOCO $2.38 million in damages. In August, the court awarded
ETOCO $0.5 million in attorneys' fees. On February 8, 1999, the claim was
settled for an amount previously provided by the Company.
The Company, in the ordinary course of business, is a claimant and/or
a defendant in various other legal proceedings, including proceedings as to
which it has insurance coverage, in which its exposure, individually and in the
aggregate, is not considered material to the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
15
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
There is no established public trading market for the Company's common
stock, its 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 of the Company for the
periods indicated.
Predecessor Company (1)
-------------------------------------
(ALL AMOUNTS IN THOUSANDS) 3 Mos. 9 Mos. Year Year
Years Ended December 31, Ended Ended Ended Ended
-----------------------
1994 1995 3/31/96 12/31/96 12/31/97 12/31/98
---------- ---------- ---------- ---------- ---------- ----------
STATEMENT OF OPERATIONS DATA:
Total revenues $ 34,861 $ 32,386 $ 13,309 $ 47,079 $ 62,771 $ 56,690
Lease operating expenses 6,123 6,408 2,403 6,495 9,376 9,858
Depreciation, depletion and amortization 16,221 15,635 6,309 24,747 31,719 33,833
Impairment of oil and gas properties 6,257 -- -- 22,500 28,514 50,800
Provision for litigation -- -- -- -- -- 2,800
General and administrative expenses 1,830 2,028 712 2,406 3,195 4,749
---------- ---------- ---------- ---------- ---------- ----------
Operating income (loss) 4,430 8,315 3,885 (9,069) (10,033) (45,350)
Interest income 1,084 9,255 2,167 515 467 313
Interest expense (8,125) (12,772) (3,391) (7,746) (10,644) (13,384)
Write-off of bridge loan fees -- -- -- (2,392) -- --
---------- ---------- ---------- ---------- ---------- ----------
Income (loss) before income taxes (2,611) 4,798 2,661 (18,692) (20,210) (58,421)
Provision for income taxes -- 338 -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Net income (loss) $ (2,611) $ 4,460 $ 2,661 $ (18,692) $ (20,210) $ (58,421)
========== ========== ========== ========== ========== ==========
CAPITAL EXPENDITURE AND DISPOSAL DATA:
Exploration, incl. leasehold/seismic $ 19,016 $ 17,460 $ 4,926 $ 31,885 $ 48,933 $ 78,817
Development and other 17,907 24,312 2,545 7,043 19,935 63,038
---------- ---------- ---------- ---------- ---------- ----------
Total capital expenditures $ 36,923 $ 41,772 $ 7,471 $ 38,928 $ 68,868 $ 141,855
========== ========== ========== ========== ========== ==========
Proceeds from disposals $ 3,480 $ 20,688 -- $ 7,528 -- --
========== ========== ========== ========== ========== ==========
BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net, at full cost $ 120,135 $ 125,817 $ 127,095 $ 166,619 $ 175,668 $ 233,327
Long-term receivable from affiliates 4,000 106,000 104,000 -- -- --
Total assets 138,202 250,726 254,301 196,749 212,577 262,342
Long-term debt, less current maturities 105,500 162,500 162,500 99,525 113,574 124,624
Stockholder's equity 18,798 69,258 71,919 77,053 57,174 27,534
(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.
13
16
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
the Company's financial position and results of operations for each of the three
years in the period that began January 1, 1996 and ended December 31, 1998. This
discussion should be read in conjunction with the information contained in the
financial statements of the Company 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 the Company's financial position, business strategy, plans
and objectives of management of the Company for future operations and industry
conditions, are forward-looking statements. Although the Company believes 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.
(b) GENERAL
A key component of the Company's strategy is growth "through the drill
bit", with heavy emphasis on the exploration, exploitation and development
spending on projects in the Deepwater Gulf. This strategy is supported by a
capital expenditures plan which is expected to decrease in 1999 due to a
constrained capital environment and increase thereafter due to development
opportunities, subject to capital availability. The Company expects that a
combination of internally generated cash flows, borrowings against the Company's
Revolving Credit Facility and a short-term credit facility with an affiliate and
equity capital contributions will provide the capital resources to support the
Company's capital expenditure plan.
During 1998, the Company achieved the following in pursuit of its
growth strategy:
o Added proved reserves of 48 Bcfe, primarily as a result of
drilling three successful exploratory wells, including 1 in
the Deepwater Gulf, and acquiring an additional 30% working
interest in the "Pluto" Deepwater Gulf exploitation project
(see page 7 for additional information regarding the "Pluto"
project).
o Increased its prospect inventory, adding 20 new blocks in the
Gulf of Mexico for a total of 87 undeveloped blocks, including
47 blocks in the Deepwater Gulf covering 22 prospects.
Included in the new prospects added during 1998 were six large
prospects, success on any one of which the Company believes
would significantly increase the proved reserves and value of
the Company. As a result of arrangements made with industry
partners, most of the Company's share of exploratory drilling
costs for three of these large prospects, two of which the
Company anticipates will be drilled in 1999 and one in 2000,
will be paid by these partners.
A key to the Company's growth strategy is the availability of capital.
During 1998, the Company's capital expenditures of $141.9 million were funded by
internally generated cash flow, borrowing against the Revolving Credit Facility
and equity contributions from existing shareholders. Access to additional debt
or equity capital has proven difficult for independent oil and gas companies in
general and for the Company. Accordingly, in 1999 the Company is pursuing a
flexible capital expenditures plan and expects capital expenditures to be in the
$40 to $60 million range, depending on changes in the amount of internally
generated cash and access to other sources of capital during the year.
The Company expects to fund its 1999 activities with a combination of
cash flow from operations, borrowings against its Revolving Credit Facility and
a short-term credit facility with an affiliate, and equity contributions from
its parent company. In support of this plan, a credit facility between Mariner's
parent company, Mariner Energy LLC, and Enron Capital & Trade Resources Corp.
was increased from $25 million to $50 million in early 1999. The maturity of
this facility was subsequently extended from April 30, 1999 to April 30, 2000.
This additional capital, net of related fees and interest, was contributed to
Mariner. In April 1999, a $25 million short-term credit facility, maturing
December 31, 1999, was established between the Company and Enron Capital & Trade
Resources Corp. to fund Mariner's capital needs for the remainder of 1999.
Including this additional capital, the Company believes its capital resources
will be sufficient to meet its capital requirements for 1999. However, there can
be no assurances that the Company's access to capital will be sufficient to meet
its needs for capital.
The Company's revenue, profitability, access to capital and future rate
of growth are heavily influenced by prevailing prices for natural gas, oil and
condensate, which prices are dependent upon numerous factors beyond the
Company's control, such as economic, political and regulatory developments.
Energy market prices have been extremely volatile in recent years. The Company
expects this volatility to continue. While the Company uses hedging transactions
from time
14
17
to time to reduce its exposure to price fluctuations, a substantial extended
decline in oil and gas prices could have a material adverse effect on the
Company's financial position, results of operations, future exploration and
development plans and access to capital. Since December 31, 1998, oil prices
have increased. However, natural gas prices had decreased significantly over the
same period of time.
The Company uses the full cost method of accounting for its 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 (net of accumulated depreciation, depletion,
and amortization) 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. If a writedown were
required, it would result in a charge to earnings but would not have an impact
on cash flows. In 1998, the Company recorded a writedown of $50.8 million as a
result of the above described requirements. Decreased natural gas prices since
December 31, 1998 could require an additional writedown in 1999.
Another significant factor affecting the Company will be competition,
both from other sources of energy such as electricity, and from within the
industry. Many of the Company's larger competitors possess and employ financial
and personnel resources substantially greater than those available to Mariner,
which can be particularly important in Deepwater Gulf activities. 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 the Company's resources permit.
The Company's results of operations may vary significantly from year to
year based upon the factors discussed above and by 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 received by the Company from its 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,
----------------------------------------
1998 1997 1996
---------- ---------- ----------
Production:
Oil (Mbbls) ................................... 786 977 750
Natural gas (Mmcf) ............................ 19,477 18,004 20,429
Gas equivalent (Mmcfe) ........................ 24,193 23,866 24,929
Average sales prices including effects of hedging:
Oil (per Bbl) ................................. $ 12.80 $ 18.48 $ 18.04
Natural gas (per Mcf) ......................... 2.39 2.48 2.29
Gas equivalent (per Mcfe) ..................... 2.34 2.63 2.42
Expenses (per Mcfe):
Lease operating ............................... .41 .39 .36
General and administrative, net ............... .20 .13 .13
Depreciation, depletion and amortization
(excluding impairments) .................... 1.40 1.33 1.25
15
18
(i) 1998 COMPARED TO 1997
NET PRODUCTION increased 1% to 24.2 Bcfe in 1998 from 23.9 Bcfe in
1997. Natural gas production increased by 1.4 Bcf, or 8%, to 19.5 Bcf from 18.0
Bcf. Gas production from offshore properties decreased 0.3 Bcf or 3%, primarily
due to the natural production decline offset by the addition of two offshore
properties, while gas production from onshore properties increased 1.8 Bcf or
32%. The Company expects net production to increase by over 20% in 1999 compared
to 1998, as the result of the commencement of production from several 1996 and
1997 discoveries.
OIL AND GAS REVENUES for 1998 decreased by $6.1 million, or 10%,
compared to 1997 primarily due to decreased oil and gas sales prices partially
offset by the production increase described above. The average realized sales
price of natural gas decreased 4%, to $2.39 per Mcf in 1998 from $2.48 per Mcf
in 1997, while the average realized oil sales price decreased by 31% to $12.80
per Bbl in 1998 from $18.48 per Bbl in 1997.
HEDGING ACTIVITIES of the Company in 1998, with respect to the average
realized natural gas sales price received, increased by $0.12 per Mcf and
revenues by $2.3 million. In 1997, the Company's natural gas hedging activities
decreased the average realized natural gas sales price received by $0.22 per mcf
and revenues by $3.9 million. There were no hedging activities for oil in 1998.
The Company's hedging activities with respect to crude oil during 1997 reduced
the average sales price received by $0.63 per Bbl and revenues by $0.6 million.
During 1998, approximately 40% of the Company's equivalent production was
subject to hedge positions compared to 60% in 1997. See "Changes in Prices and
Hedging Activities" below for a summary of 1999 hedging positions as of the date
of this annual report.
LEASE OPERATING EXPENSES increased 5% to $9.9 million for 1998 from
$9.4 million for 1997. Lease operating expense per Mcfe increased to $0.41 per
Mcfe for 1998 from $0.39 per Mcfe for 1997, due primarily to higher fixed costs
associated with offshore properties.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE (DD&A) increased 7% to
$33.8 million for 1998, from $31.7 million for 1997, as a result of a 5%
increase in the unit-of-production depreciation, depletion and amortization rate
to $1.40 per Mcfe from $1.33 per Mcfe, due primarily to increased drilling and
completion costs, and a 1% increase in equivalent volumes produced.
IMPAIRMENT OF OIL AND GAS PROPERTIES of $50.8 million was recorded in
the fourth quarter of 1998 for a non-cash full cost ceiling test impairment
using prices in effect at December 31, 1998. During the first quarter of 1997, a
$28.5 million non-cash full cost ceiling writedown was also recorded due to low
commodity prices in effect as of the end of that period.
GENERAL AND ADMINISTRATIVE EXPENSES, which are net of overhead
reimbursements received by the Company from other working interest owners on
properties operated by the Company, increased 49% to $4.7 million in 1998, up
from $3.2 million in 1997, due primarily to higher employment levels to build
the necessary expertise for Deepwater Gulf projects and related office costs in
1998. General and administrative expense increased $0.07 per Mcfe from 1997 to
1998. In addition, during 1998 the Company recognized a one-time charge of $2.8
million relating to litigation expense.
INTEREST EXPENSE increased 26% to $13.4 million for 1998, from $10.6
million for 1997, due primarily to the 47% increase in average outstanding debt
to $151.4 million in 1998, from $103.2 million in 1997, which was partially
offset by a 10.1% decrease in the average interest rate paid on outstanding debt
to 9.33%, from 10.38%.
INCOME (LOSS) BEFORE INCOME TAXES decreased to a loss of $58.4 million
for 1998, from a loss of $20.2 million loss for 1997, as a result of the factors
described above.
(ii) 1997 COMPARED TO 1996
NET PRODUCTION decreased 4% to 23.9 Bcfe in 1997 from 24.9 Bcfe in
1996. Natural gas production decreased by 2.4 Bcf, or 12%, to 18.0 Bcf from 20.4
Bcf. Gas production from offshore properties decreased 3.8 Bcf or 23%, primarily
due to natural production decline, while gas production from onshore properties
increased 1.4 Bcf or 34%, due to the capacity expansion of the Sandy Lake
Central facility, which became operational in the first quarter of 1997. Oil and
condensate production increased by 227 Mbbls to 977 Mbbls from 750 Mbbls, also
due primarily to the expansion of the Sandy Lake Central facility, offset in
part by a decrease in other onshore oil production resulting from the sale of
non-core Permian Basin properties in early 1996.
OIL AND GAS REVENUES for 1997 increased by $2.4 million, or 4%,
compared to 1996. The increase was primarily the result of increased oil and gas
sales prices, offset in part by the production decrease described above. The
average
16
19
realized sales price of natural gas increased 8%, to $2.48 per Mcf in 1997 from
$2.29 per Mcf in 1996, while the realized oil sales price increased by 2% to
$18.48 per Bbl in 1997 from $18.04 per Bbl in 1996.
HEDGING ACTIVITIES for 1997 reduced the average realized natural gas
sales price received by $0.22 per Mcf and revenues by $3.9 million. In 1996,
natural gas hedging activities decreased the average realized sales price
received by $0.18 per mcf and revenues by $3.7 million. Hedging activities of
crude oil during 1997 reduced the average sales price received by $0.63 per Bbl
and revenues by $0.6 million, compared with a reduction in the average realized
sales price of $2.55 per Bbl and revenues of $1.9 million during 1996. During
1997, approximately 60% of the Company's equivalent production was subject to
hedge positions compared to 64% in 1996. See "Changes in Prices and Hedging
Activities" below for a summary of 1998 hedging positions as of the date of this
annual report.
LEASE OPERATING EXPENSES increased 6% to $9.4 million for 1997, from
$8.9 million for 1996. Lease operating expense per Mcfe increased to $0.39 for
1997 from $0.36 for 1996, due primarily to relatively fixed operating expenses
spread over reduced production volumes.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE (DD&A) increased 2% to
$31.7 million for 1997, from $31.1 million for 1996, as a result of a 6%
increase in the unit-of-production depreciation, depletion and amortization rate
to $1.33 per Mcfe from $1.25 per Mcfe, due primarily to increased drilling and
completion costs, partially offset by a 4% reduction in equivalent volumes
produced.
IMPAIRMENT OF OIL AND GAS PROPERTIES of $28.5 million was recorded in
the first quarter of 1997 for a non-cash full cost ceiling test impairment using
prices in effect at March 31, 1997. Price increases subsequent to March 31, 1997
were sufficient to avoid the impairment charge, but given the unpredictable
volatility of future prices, the Company elected to record the charge in order
to more conservatively state the book value of its assets. During the second
quarter of 1996, a $22.5 million full cost ceiling writedown was recorded in
conjunction with Mariner Holdings' acquisition of the Company.
GENERAL AND ADMINISTRATIVE EXPENSES, which are net of overhead
reimbursements received by the Company from other working interest owners on
properties operated by the Company, increased 3% to $3.2 million in 1997, up
from $3.1 million in 1996, due primarily to higher employment and office costs
in 1997 which were almost entirely offset by increased overhead reimbursements
during 1997. Accordingly, there was no change in general and administrative
expense per Mcfe of $0.13 for both 1997 and 1996.
INTEREST EXPENSE decreased 5% to $10.6 million for 1997, from $11.1
million for 1996, due primarily to the 9% decrease in average outstanding debt
to $103.2 million in 1997, from $113.2 million in 1996, which decrease was
partially offset by a 7% increase in the average interest rate paid on
outstanding debt to 10.38%, from 9.68%. During 1996, the Company wrote off $2.4
million of loan fees related to debt incurred in connection with the Company's
management-led buyout in the second quarter of 1996. Interest income also
decreased 83% to $0.5 million for 1997, from $2.7 million for 1996, due
primarily to the retirement of receivables from affiliates resulting from the
acquisition by Mariner Holdings of the stock of the Company.
INCOME (LOSS) BEFORE INCOME TAXES decreased to a loss of $20.2 million
for 1997, from a $16.0 million loss for 1996, as a result of the factors
described above.
(d) LIQUIDITY AND CAPITAL RESOURCES
(i) CASH FLOWS
Liquidity is a company's ability to generate cash to meet its needs for
cash. As of December 31, 1998, the Company had a working capital deficit of
approximately $84.1 million, compared with a working capital deficit of $8.6
million as of December 31, 1997. The increased working capital deficit was
primarily a result of the classification of the Company's Revolving Credit
Facility as a current liability, which had a balance of $53.4 million at
December 31, 1998 and which matures October 1, 1999. The Company expects that
this facility will be extended, which extension would result in a
reclassification of the balance due thereunder to long-term debt. However, there
can be no assurance to that effect. The working capital deficit also was
increased as a result of increased accounts payable at year-end compared to the
prior year due to a higher level of drilling and completion activity. In
addition, the Company will require a significant amount of capital to develop
its properties in order to achieve higher levels of production and cash flow. To
obtain the necessary funds to reduce the working capital deficit and continue
its planned capital expenditure program, in April 1999, the
17
20
Company established a $25 million short-term credit facility with Enron Capital
& Trade Resources Corp. There can be no assurances, however, that the Company's
access to capital will be sufficient to meets its needs for capital.
Primary sources of cash during the three year period ended December 31,
1998 were funds generated from operations, proceeds from the sale of oil and gas
properties, proceeds from the issuance of notes, bank borrowings and capital
contributions by the Company's former and present parent companies. Primary uses
of cash for the same period were funds used in exploration and production
activities, repayment of notes and bank debt, and the purchase of Hardy Oil &
Gas USA, Inc.
The Company had a net cash outflow of $9.1 million in 1998, compared to
a net cash outflow of $1.7 million in 1997 and a net cash inflow of $10.8
million in 1996. A discussion of the major components of cash flows for these
years follows.
1998 1997 1996
------ ------ ------
Cash flows provided by operating activities (in millions)....... $ 39.6 $ 52.9 $ 44.3
Cash flows provided by operating activities in 1998 decreased by $13.3
million compared to 1997 primarily due to decreased oil and gas prices. Cash
flows from operating activities in 1997 increased by $8.6 million from 1996
primarily due to increased oil and gas prices and changes in working capital.
1998 1997 1996
------ ------ -------
Cash flows used in investing activities (in millions)............. $ 141.9 $ 68.9 $ 221.8
Cash flows used in investing activities in 1998 increased by $73
million compared to 1997 primarily due to increased capital expenditures to
acquire leasehold inventory. Cash flows used in investing activities in 1997
decreased by $152.9 million compared to 1996 primarily because in 1996, cash
was used to fund the acquisition of Hardy Oil & Gas USA, Inc. for $184.7
million. This decrease was partially offset by an increase of $22.6 million for
capital expenditures for oil and gas properties in 1997 over 1996 and $7.5
million lower proceeds from the sale of oil and gas properties in 1997 from
1996.
1998 1997 1996
------- ------- -------
Cash flows provided by financing activities (in millions)....... $ 93.2 $ 14.3 $ 188.3
Cash flows provided by financing activities in 1998 increased by $78.9
million as compared to 1997 due to the Company receiving approximately $28.8
million in equity contributions and $64.4 million from its revolving credit
facilities. Cash flows provided by financing activities in 1997 decreased by
$174.0 million compared to 1996 primarily because in 1996, cash was provided by
$92.2 million of equity contributed by the Company's shareholders and the
issuance of $99.5 million of senior subordinated notes, offset in part by
proceeds of borrowings from the revolving credit facility in 1997 of $14.0
million.
(ii) CHANGES IN PRICES AND HEDGING ACTIVITIES
The energy markets have historically been very volatile, and there can
be no assurance that oil and gas prices will not be subject to wide fluctuations
in the future. In an effort to reduce the effects of the volatility of the price
of oil and natural gas on the Company's 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.
The following table sets forth the increase (decrease) in the Company's
oil and gas sales as a result of hedging transactions and the effects of hedging
transactions on prices during the periods indicated.
18
21
Year Ended December 31
--------------------------------
1998 1997 1996
------- -------- --------
Increase (decrease) in natural gas sales (in thousands)......... $ 2,337 $(3,931) $(3,701)
Increase (decrease) in oil sales (in thousands)................. -- (614) (1,912)
Effect of hedging transactions on average gas sales price
(per Mcf)................................................. 0.12 (0.22) (0.18)
Effect of hedging transactions on average oil sales price
(per Bbl)................................................. -- (0.63) (2.55)
Subsequent to December 31, 1998, the Company entered into a commodity
price hedging contract under a costless collar covering 60,000 Mmbtu per day of
natural gas production with a floor price of $1.85 per Mmbtu and a ceiling price
of $2.05 per Mmbtu for the period beginning April 1, 1999 to October 31, 1999.
This agreement can be extended for the same daily volume through March 2000 for
a floor price of $2.00 per Mmbtu and a ceiling of $2.70 per Mmbtu at the option
of the counterparty to the transaction. Subsequent to December 31, 1998, the
Company entered into a long-term hedging agreement for a three-year period from
November 1, 1999 through October 31, 2002. Average volumes hedged by year are
approximately 44,000, 30,000, 12,000 and 6,000 Mmbtu per day for 1999, 2000,
2001, and 2002, respectively, at a price of $2.18 per Mmbtu. In April 1999, the
Company entered into a hedging agreement covering 600 barrels of oil per day for
the period May 1, 1999 through December 31, 1999 at a price of $16.32 per Bbl.
Hedging arrangements for 1999 cover approximately 53% of the Company's
anticipated equivalent production for the year. Hedging arrangements for 2000,
2001 and 2002 cover approximately 30%, 10% and 3% of the Company's anticipated
equivalent production, respectively.
(iii) CAPITAL EXPENDITURES AND CAPITAL RESOURCES
The following table presents major components of capital and
exploration expenditures for each of the three years ended December 31,
respectively.
1998 1997 1996
-------- -------- --------
Capital Expenditures (in millions):
Leasehold acquisition-unproved properties $ 43.1 $ 21.6 $ 14.3
Leasehold acquisition-proved properties -- 3.2 --
Oil and gas exploration 35.7 27.4 22.7
Oil and gas development and other 63.1 16.7 9.6
-------- -------- --------
Total capital expenditures $ 141.9 $ 68.9 $ 46.6
======== ======== ========
Total capital expenditures for 1998 were $73.0 million more than 1997.
The increase was due primarily to (1) the Company's continued focus on building
and evaluating its exploration and exploitation prospect inventory, as evidenced
by the increase in both leasehold acquisition of unproved properties and oil and
gas exploration and (2) increased development-related spending, both to acquire
additional interests in existing proved properties and to develop successful
exploratory prospects.
The Company's board of directors has approved a flexible 1999 capital
expenditures budget of $40 to $60 million depending on the availability of
capital. This budget represents a significant decrease from capital expenditures
of $141.9 million in 1998. The goal of this flexible plan is to maximize the
opportunity for growth in proved reserves and related value while conserving
cash. Focal points of this expenditure plan are to:
o Bring development projects on production to increase
production and cash flow, including the Dulcimer exploration
success and the Pluto exploitation project, both in the
Deepwater Gulf.
o Extend and enlarge the Company's successful Sandy Lake field.
o Evaluate five to six exploration projects while exposing
minimal Company capital, including two large Deepwater
prospects on which the Company's share of exploratory drilling
costs are covered by industry partners.
o Appraise the early 1999 Deepwater Gulf exploratory discovery
at Mississippi Canyon block 305 in which Mariner has a 25%
working interest.
o Acquire several new high quality prospects in the Deepwater
Gulf via participation in 1999 lease sales.
To increase the probability of achieving this plan, the Company
anticipates using other steps to generate access to additional capital as may be
needed, such as selling a package of part of its drilling prospects and/or
reducing the Company's share of other successful projects such as Pluto.
19
22
Capital spending plans will be re-evaluated throughout the year. Actual
levels of capital expenditures may vary significantly due to a variety of
factors, including drilling results, oil and gas prices, industry conditions
including drilling rig availability, future acquisitions and availability of
capital. The planned levels of capital expenditures could be reduced if the
Company experiences lower than anticipated net cash from operations or other
liquidity needs or could be increased if the Company experiences increased cash
flow or access to additional sources of capital. Though the 1999 capital
expenditures plan does not include any acquisitions, the Company expects to
pursue acquisition opportunities selectively looking for proved reserves where
it believes significant operating improvement or exploration potential exists,
provided it has access to capital.
On March 17, 1999, the Company participated in a federal offshore Gulf
of Mexico lease sale in which it was the apparent high bidder on three blocks in
the Deepwater Gulf. Upon award of the leases, the Company would have a 100%
working interest in two blocks and a 50% working interest in the third block.
The anticipated net cost to the Company for these blocks is approximately $9
million.
The Company has used its Revolving Credit Facility with a group of
banks led by Bank of America (see Note 4 to the Financial Statements) to fund a
portion of its expenditures. The Revolving Credit Facility, which provides for a
maximum $150 million revolving credit loan, had a borrowing base of $60.0
million as of December 31, 1998, and $53.4 million of debt was outstanding as of
that date. The borrowing base is subject to semi-annual redetermination as of
June 30 and December 31 of each year, and one additional redetermination per
year may be requested by either the Bank Group or the Company. In April 1999,
the Company pledged certain mineral interests to secure the Revolving Credit
Facility. The borrowing under the Revolving Credit Facility matures on
October 1, 1999. The semi-annual borrowing base redetermination as of
December 31, 1998 was in progress as of the date of this annual report. While
the Company expects to extend this Facility on a long-term basis at its
current level, there can be no assurance that either the borrowing base will
remain unchanged or that the facility will be extended on a long-term basis.
In April 1999, the Company established a $25 million borrowing-based,
short-term credit facility with Enron Capital & Trade Resources Corp. to obtain
funds needed to execute the Company's 1999 capital expenditure program and for
short-term working capital needs. This facility will mature on December 31, 1999
and is expected to be repaid from internally-generated cash flows.
Equity capital has been a significant source of capital for the
Company. In June 1998, the Company's parent Mariner Holdings, Inc., reached an
agreement in which management shareholders and an affiliate of Enron Corp.
agreed to contribute approximately $28.8 million of net equity capital, which
capital was used to supplement funding of the Company's 1998 capital
expenditure plan. In September 1998, Mariner's parent company entered into a
$25 million credit facility with Enron Capital & Trade Resources Corp. Proceeds
from that credit facility, net of related transaction fees and interest, were
provided to the Company in the form of an equity contribution. At December 31,
1998 the Company used push down accounting treatment and reported this
contribution as debt. Subsequent to December 31, 1998, this facility was
increased to $50 million and the Company has reclassified the entire net
proceeds to equity contribution. See further discussion of this transaction
under Item 13. "Certain Relationships and Related Transactions".
The Company expects to fund its 1999 activities with a combination of
cash flow from operations, borrowings against its Revolving Credit Facility and
a short-term credit facility with an affiliate, and equity contributions from
its parent company. However, there can be no assurance that the Company will
realize its anticipated growth, that the Company's business will generate
sufficient cash flow from operations or that future borrowings or equity capital
will be available in an amount sufficient to enable the Company to service its
indebtedness or make necessary capital expenditures.
(e) YEAR 2000 ISSUES
Year 2000 issues result from the inability of computer programs or
computerized equipment to accurately calculate, store or use a date subsequent
to December 31, 1999. The erroneous date can be interpreted in a number of
different ways; typically the year 2000 is represented as the year 1900. This
could result in a system failure or miscalculations causing disruptions of
operations, including, among other things, a temporary inability to process
transactions, send invoices or engage in similar normal business transactions.
The Company has reviewed the majority of its primary Information
Technology ("IT") systems with the vendors from which the systems were purchased
and believes these systems were Year 2000 compliant as of December 31, 1998. The
Company is also reviewing its non-IT systems (such as technology embedded within
its operational equipment) and any material third-party relationships for Year
2000 problems that could affect the Company's operations. A consulting firm has
been engaged to assist in this effort. The Company expects to complete this
review by mid-1999. The Company believes the potential impact, if any, of these
IT, non-IT or third-party systems not being Year 2000 compliant should not
20
23
materially impact the Company's ability to continue exploration, drilling,
production and sales activities. Based on reviews conducted to date and other
preliminary information, costs of addressing potential problems are not expected
to have a material adverse impact on the Company's financial position, results
of operations, or cash flow in future periods. Cost to date has been immaterial.
The Company relies on other producers and transmission companies to
conduct its basic operations. Should any third party with which the Company has
a material relationship fail, the impact could be a significant challenge to the
Company's ability to perform its basic operations. Examples of such changes are
an inability to transport production to market or an inability to continue
drilling activities. As part of the above-mentioned review, the Company will
address the most reasonably likely worst-case Year 2000 scenarios and potential
costs. The Company will also develop a Year 2000 contingency plan for unknown
events. The Company is scheduled to have these plans completed by June 1999.
Statements in this section are intended to be and are hereby designated
"Year 2000 Readiness Disclosure" within the meaning of the Year 2000 Information
and Readiness Disclosure Act.
(f) MARKET RISK DISCLOSURE
See Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - (d) (ii) Changes in Prices and Hedging Activities.
21
24
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements
PAGE
----
Independent Auditors' Report.............................................................................23
Balance Sheets at December 31, 1998 and 1997 (Mariner Energy, Inc.)......................................24
Statements of Operations for the years ended December 31, 1998 and
1997, the nine months ended December 31, 1996 (Mariner Energy,
Inc.), and the three months ended March 31, 1996 (Predecessor Company).............................25
Statements of Stockholder's Equity for the year ended December 31, 1998 and 1997,
the nine months ended December 31, 1996 (Mariner Energy, Inc.), and the three
months ended March 31, 1996 (Predecessor Company)..................................................26
Statements of Cash Flows for the year ended December 31, 1998 and 1997,
the nine months ended December 31, 1996 (Mariner Energy, Inc.),
and the three months ended March 31, 1996 (Predecessor Company)....................................27
Notes to Financial Statements............................................................................28
22
25
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholder
Mariner Energy, Inc.
Houston, Texas
We have audited the accompanying financial statements of Mariner Energy, Inc.
(the "Company"), formerly Hardy Oil & Gas USA Inc. (the"Predecessor Company"),
as listed in the Index to Financial Statements in Item 8. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Mariner Energy, Inc. as of
December 31, 1998 and 1997, and the results of its operations and cash flows for
the years ended December 31, 1998 and 1997, the nine months ended December 31,
1996, and the three months ended March 31, 1996, in conformity with generally
accepted accounting principles.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Houston, Texas
April 14, 1999
23
26
MARINER ENERGY, INC.
BALANCE SHEETS
(IN THOUSANDS)
December 31, December 31,
1998 1997
------------ ------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2 $ 9,131
Receivables 16,007 18,585
Prepaid expenses and other 7,234 3,628
------------ ------------
Total current assets 23,243 31,344
------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at full cost:
Proved 316,056 222,829
Unproved, not subject to amortization 84,076 36,526
------------ ------------
Total 400,132 259,355
Other property and equipment 3,300 2,222
Accumulated depreciation, depletion and amortization (167,846) (84,236)
------------ ------------
Total property and equipment, net 235,586 177,341
------------ ------------
OTHER ASSETS, Net of Amortization 3,513 3,892
------------ ------------
TOTAL ASSETS $ 262,342 $ 212,577
============ ============
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES:
Accounts payable $ 20,375 $ 5,556
Accrued liabilities 29,082 29,908
Accrued interest 4,503 4,443
Revolving credit facility 53,400 --
------------ ------------
Total current liabilities 107,360 39,907
------------ ------------
ACCRUAL FOR FUTURE ABANDONMENT COSTS 2,824 1,922
LONG-TERM DEBT:
Subordinated notes 99,624 99,574
Revolving credit facility -- 14,000
Affiliated credit facility 25,000 --
------------ ------------
Total long-term debt 124,624 113,574
------------ ------------
COMMITMENTS AND CONTINGENCIES (Note 7)
STOCKHOLDER'S EQUITY:
Common stock, $1 par value; 1,000 shares authorized,
1,000 shares were issued and outstanding 1 1
Additional paid-in-capital 124,856 96,075
Accumulated deficit (97,323) (38,902)
------------ ------------
Total stockholder's equity 27,534 57,174
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 262,342 $ 212,577
============ ============
The accompanying notes are an integral part of these financial statements
24
27
MARINER ENERGY, INC.
STATEMENTS OF OPERATIONS
(IN THOUSANDS)
Predecessor
Company
------------
Year Year Nine Months Three Months
Ended Ended Ended Ended
December 31, December 31, December 31, March 31,
1998 1997 1996 1996
------------ ------------ ------------ ------------
REVENUES:
Oil sales $ 10,066 $ 18,061 $ 9,897 $ 3,632
Gas sales 46,624 44,710 37,182 9,677
---------- ---------- ---------- ----------
Total revenues 56,690 62,771 47,079 13,309
---------- ---------- ---------- ----------
COSTS AND EXPENSES:
Lease operating expenses 9,858 9,376 6,495 2,403
Depreciation, depletion and amortization 33,833 31,719 24,747 6,309
Impairment of oil and gas properties 50,800 28,514 22,500 --
Provision for litigation 2,800 -- -- --
General and administrative expenses 4,749 3,195 2,406 712
---------- ---------- ---------- ----------
Total costs and expenses 102,040 72,804 56,148 9,424
---------- ---------- ---------- ----------
OPERATING INCOME (LOSS) (45,350) (10,033) (9,069) 3,885
INTEREST:
Related party income -- -- -- 57
Other income 313 467 515 2,110
Related party expense (993) -- -- (381)
Other expense (12,391) (10,644) (7,746) (3,010)
Write-off of Bridge Loan fees -- -- (2,392) --
---------- ---------- ---------- ----------
INCOME (LOSS) BEFORE INCOME TAXES (58,421) (20,210) (18,692) 2,661
PROVISION FOR INCOME TAXES -- -- -- --
---------- ---------- ---------- ----------
NET INCOME (LOSS) $ (58,421) $ (20,210) $ (18,692) $ 2,661
========== ========== ========== ==========
The accompanying notes are an integral part of these financial statements
25
28
MARINER ENERGY, INC.
STATEMENTS OF STOCKHOLDER'S EQUITY
(IN THOUSANDS, EXCEPT NUMBER OF SHARES)
COMMON STOCK ADDITIONAL TOTAL
------------------------- PAID-IN ACCUMULATED STOCKHOLDER'S
SHARES AMOUNT CAPITAL DEFICIT EQUITY
---------- ---------- ---------- ----------- -------------
PREDECESSOR COMPANY:
Balance at December 31, 1995 1,000 $ 1 $ 81,094 $ (11,837) $ 69,258
Net income -- -- -- 2,661 2,661
---------- ---------- ---------- ---------- ----------
Balance at March 31, 1996 1,000 1 81,094 (9,176) 71,919
POST ACQUISITION:
Adjustments due to Acquisition -- -- 14,650 9,176 23,826
Net loss -- -- -- (18,692) (18,692)
---------- ---------- ---------- ---------- ----------
Balance at December 31, 1996 1,000 1 95,744 (18,692) 77,053
Capital contribution -- -- 331 -- 331
Net loss -- -- -- (20,210) (20,210)
---------- ---------- ---------- ---------- ----------
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
========== ========== ========== ========== ==========
The accompanying notes are an integral part of these financial statements
26
29
MARINER ENERGY, INC.
STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
Predecessor
Company
------------
Year Year Nine Months Three Months
Ended Ended Ended Ended
December 31, December 31, December 31, March 31,
1998 1997 1996 1996
---------- ---------- ---------- ----------
OPERATING ACTIVITIES:
Net income (loss) $ (58,421) $ (20,210) $ (18,692) $ 2,661
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization 33,762 32,588 27,706 6,437
Impairment of oil and gas properties 50,800 28,514 22,500 --
Provision for litigation 2,800 -- -- --
Imputed interest -- -- 1,322 --
Changes in operating assets and liabilities:
Receivables 2,578 (5,014) (769) (1,873)
Receivables from affiliates -- -- -- (2,109)
Other current assets (3,606) (3,210) (317) (307)
Other assets 379 (483) -- --
Accounts payable and accrued liabilities 11,253 20,693 6,955 832
Payables to affiliates -- -- -- (11)
---------- ---------- ---------- ----------
Net cash provided by operating activities 39,545 52,878 38,705 5,630
---------- ---------- ---------- ----------
INVESTING ACTIVITIES:
Purchase of Predecessor Company, net of cash of $5,438 -- -- (184,742) --
Additions to oil and gas properties (140,777) (68,317) (38,236) (7,495)
Additions to other property and equipment (1,078) (551) (741) (153)
Proceeds from sale of oil and gas properties -- -- 7,528 --
Issuance of long-term receivable to affiliates -- -- -- (1,000)
Repayment of long-term receivable from affiliates -- -- -- 3,000
---------- ---------- ---------- ----------
Net cash used in investing activities (141,855) (68,868) (216,191) (5,648)
---------- ---------- ---------- ----------
FINANCING ACTIVITIES:
Principal payments on long-term debt -- -- (92,000) --
Principal payments on revolving credit facility -- -- (50,000) --
Payments of debt issue costs -- (29) (3,961) --
Proceeds from Subordinated notes -- -- 99,506 --
Proceeds from long-term debt -- -- 92,000 --
Proceeds from revolving credit facility, net 39,400 14,000 50,000 --
Proceeds from affiliate credit facility 25,000 -- -- --
Additional capital contributed by Parent -- -- 92,150 --
Proceeds from sale of common stock of parent 28,781 331 610 --
---------- ---------- ---------- ----------
Net cash provided by financing activities 93,181 14,302 188,305 --
---------- ---------- ---------- ----------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (9,129) (1,688) 10,819 (18)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 9,131 10,819 -- 5,456
---------- ---------- ---------- ----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 2 $ 9,131 $ 10,819 $ 5,438
========== ========== ========== ==========
The accompanying notes are an integral part of these financial statements
27
30
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION -- For the three months ended 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. ("ECT"), 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").
See Notes 2 and 3. As a result of the sale of Hardy Oil & Gas USA Inc.'s common
stock, the Predecessor Company changed its name to Mariner Energy, Inc. (the
"Company"). Additionally, ECT and Mariner Holdings entered into agreements with
certain members of the Predecessor Company's management providing for a
continued role of management in the Company after the Acquisition. 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 the Company, JEDI and other
shareholders exchanged all of their common shares of Mariner Holdings for common
shares of Mariner Energy LLC. As of December 31, 1998 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, $28,514,000 and $22,500,000 were recorded during
1998, 1997 and 1996, respectively. Subsequent to year-end, natural gas prices
have declined. This decline could result in an additional writedown in 1999.
Unproved properties are reviewed for impairment quarterly.
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 Predecessor Company's taxable income was and the
Company's taxable income is included in a consolidated United States income tax
return with Hardy Holdings Inc. and Mariner Holdings Inc., respectively. The
intercompany tax allocation policy provides that each member of the consolidated
group compute a provision for income taxes on a separate return basis. The
Company records its income taxes using an asset and liability approach which
results in the recognition of deferred tax assets and liabilities for the
expected future tax consequences of temporary differences between the book
carrying amounts and the tax bases of assets and liabilities (see Note 8).
28
31
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
CAPITALIZED INTEREST COSTS -- The Company capitalizes interest based on
the cost of major development projects which are excluded from current
depreciation, depletion, and amortization calculations. Capitalized interest
costs were approximately $1,702,000, $729,000 and $449,000 for the years ended
December 31, 1998, 1997 and 1996, 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 and included in other assets or accrued liabilities, as appropriate,
until recognized as operating income in the Company's Consolidated Statement of
Operations as the physical production required by the contracts is delivered.
The net cash flows related to any recognized gains or losses associated
with these hedges are reported as cash flows from operations. If the hedge is
terminated prior to expected maturity, gains or losses are deferred and included
in income in the same period as the physical production required by the
contracts is delivered.
The conditions to be met for a derivative instrument to qualify as a
hedge are the following: (i) the item to be hedged exposes the Company to price
risk; (ii) the derivative reduces the risk exposure and is designated as a hedge
at the time the derivative contract is entered into; and (iii) at the inception
of the hedge and throughout the hedge period there is a high correlation of
changes in the market value of the derivative instrument and the fair value of
the underlying item being hedged.
When the designated item associated with a derivative instrument
matures, is sold, extinguished or terminated, derivative gains or losses are
recognized as part of the gain or loss on sale or settlement of the underlying
item. When a derivative instrument is associated with an anticipated transaction
that is no longer expected to occur or if correlation no longer exists, the gain
or loss on the derivative is recognized in income to the extent the future
results have not been offset by the effects of price or interest rate changes on
the hedged item since the inception of the hedge.
REVENUE RECOGNITION -- The Company recognizes oil and gas revenue from
its interests in producing wells as oil and gas from those wells is produced and
sold. Oil and gas sold is not significantly different from the Company's share
of production.
FINANCIAL INSTRUMENTS -- The Company's financial instruments consist of
cash and cash equivalents, receivables, payables, and debt. At December 31, 1998
and 1997, the estimated fair value of the Company's Senior Subordinated Notes
was approximately $100,000,000. The estimated fair value was determined based on
borrowing rates available at December 31, 1998 and 1997, respectively, for debt
with similar terms and maturities. The carrying amount of the Company's other
financial instruments approximates 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.
MAJOR CUSTOMERS -- During the year ended December 31, 1998, sales of
oil and gas to four purchasers, including an affiliate, accounted for 29%, 16%,
15% and 10% of total revenues. During the year ended December 31, 1997, sales of
oil and gas to four purchasers accounted for 19%, 19%, 18% and 14% of total
revenues. During the year ended December 31, 1996, sales of oil and gas to four
purchasers accounted for 15%, 13%, 13% and 10% of total revenues.
29
32
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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.
2. THE ACQUISITION
Effective April 1, 1996, Mariner Holdings, Inc. acquired all the
capital stock of the Company from Hardy Holdings Inc. for an aggregate purchase
price of approximately $185.5 million, including $14.5 for net working capital.
In connection with the Acquisition, substantial intercompany indebtedness and
receivables and third-party indebtedness of the Company were eliminated.
The sources and uses of funds related to financing the Acquisition (See
Note 1) were as follows:
Sources of Funds
(in millions)
Bridge loan provided by JEDI(1)....................................................... $ 92.0
Common stock purchased by JEDI(2)..................................................... 95.0
Working capital provided by the Company............................................... 6.0
------
Total........................................................................... $193.0
======
Uses of Funds
(in millions)
Acquisition purchase price............................................................. $185.5
Acquisition costs and other expenses(3)................................................ 7.5
------
Total............................................................................ $193.0
======
(1) The JEDI Bridge Loan (see Note 4) was incurred by Mariner
Holdings to fund a portion of the consideration paid in the
Acquisition, which has been pushed down for accounting purposes
to the Company.
(2) As contemplated in connection with the Acquisition and shortly
after the consummation thereof, certain members of the Company's
management purchased approximately 4% of the capital stock of
Mariner Holdings (and thereby acquired beneficial ownership of
approximately 4% of the capital stock of the Company) for an
aggregated consideration valued at approximately $3.6 million.
Such consideration consisted of approximately $0.6 million in
cash and approximately $3.0 million of overriding royalty
interests, which amounts are not included in the above sources
and uses of funds related to the Acquisition.
(3) Includes $2.9 million of fees and expenses paid to JEDI
associated with the purchase of the common stock by JEDI, $2.6
million of expenses paid to JEDI associated with the
implementation of the JEDI Bridge Loan and $2.0 million of other
transaction fees and expenses (See Note 4).
The Acquisition was accounted for using the purchase method of
accounting. As such, JEDI's cost to acquire the Company, including transaction
costs, have been allocated to the assets and liabilities acquired based on
estimated fair values. As a result, the Company's financial position and
operating results subsequent to the date of the Acquisition reflect a new basis
of accounting and are not comparable to prior periods. In addition, $1.3 million
of interest was imputed for the period from April 1, 1996 to the date of
closing.
30
33
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
The allocation of JEDI's purchase price to the assets and liabilities
of the Company resulted in a significant increase in the carrying value of the
Company's oil and gas properties. Under the full cost method of accounting, the
carrying value of oil and gas properties is generally not permitted to exceed
the sum of the present value (10% discount rate) of estimated future net cash
flows from proved reserves, based on current prices and costs, plus the lower of
cost or estimated fair value of unproved properties (the "cost center ceiling").
Based upon the allocation of JEDI's purchase price, estimated proved reserves
and product prices in effect at the date of the Acquisition, the purchase price
allocated to oil and gas properties was in excess of the cost center ceiling by
approximately $22.5 million. The resulting writedown was a non-cash charge and
was included in the results of operations for the nine months ended December 31,
1996.
The allocation of the purchase price (including fees and expenses) is
summarized as follows (in millions of dollars):
Current assets.................................... $ 18.3
Property and equipment............................ 181.4
Other noncurrent assets........................... 2.6
Liabilities assumed............................... (12.2)
------
Total....................................... $190.1
======
The following unaudited pro forma financial data have been prepared
assuming that the Acquisition and the related financing were consummated on
January 1, 1995. Amounts are in thousands:
Year Ended December 31,
-----------------------
1996
-------
Revenues...................... $62,300
Net income (loss)............ $ 6,511
3. RELATED-PARTY TRANSACTIONS
RECEIVABLES FROM AFFILIATES -- Prior to the management buyout, the
Company had four lending facilities with Hardy plc. These facilities earned
interest income of approximately $2,110,000 for the three month period ending
March 31, 1996.
DEBT TO AFFILIATE -- Prior to the management buyout, the Company had
one loan facility outstanding with Hardy plc. The Company incurred approximately
$381,000 of interest expense relating to this debt for the three month period
ending March 31, 1996.
SALES TO AFFILIATES -- For the years ending December 31, 1998, 1997 and
1996, sales to affiliates were approximately $8.9 million, $13.0 million and
$29,000, respectively.
GENERAL AND ADMINISTRATIVE EXPENSES -- Prior to April 1, 1996, the
Company paid an affiliate for various administrative support services. Included
in general and administrative expenses was approximately $29,000 for the three
months ended March 31, 1996, for such services. In management's opinion, such
allocated expenses reasonably represented expenses incurred by the affiliate on
behalf of the Company.
AFFILIATE TRANSACTIONS SUBSEQUENT TO THE ACQUISITION -- Enron
Corp. ("Enron") is the parent of ECT, and an affiliate of Enron and ECT is the
general partner of JEDI. Accordingly, Enron may be deemed to control JEDI,
Mariner Holdings and the Company. In addition, six 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
31
34
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
industry and are, therefore, competitors of the Company. In addition, ECT and
JEDI have provided, and may in the future provide, and ECT 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, ECT, 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.
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, there are several
prospects in which both an affiliate of Enron and the Company have working
interests. Such interests were acquired in the ordinary course of business
pursuant to bids, joint or otherwise. Any wells drilled will be subject to joint
operating agreements relating to exploration and possible production and will be
subject to customary business terms. Furthermore, the Company has entered into
several agreements with Enron 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
transaction 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.
4. LONG-TERM DEBT
JEDI BRIDGE LOAN -- In connection with the Acquisition, JEDI and
Mariner Holdings entered into a Credit, Subordination and Further Assurances
Agreement dated May 16, 1996, pursuant to which JEDI provided a loan commitment
to Mariner Holdings of $105 million. Under this commitment Mariner Holdings
borrowed $92 million (the "JEDI Bridge Loan") to partially fund the Acquisition.
The JEDI Bridge Loan bore interest at 6% above LIBOR. The JEDI Bridge Loan was
repaid with proceeds from dividends paid by the Company to Mariner Holdings; the
Company used proceeds of $50 million from borrowings under the Revolving Credit
Facility (see below) and $42 million from the issuance of the 10 1/2% Senior
Subordinated Notes (see below) to pay such dividends. As a result of the
repayments, the JEDI Bridge Loan was terminated. In connection with the $92
million repayment, $2.4 million of the JEDI Bridge Loan debt fees were written
off during the nine months ended December 31, 1996.
REVOLVING CREDIT FACILITY -- On June 28, 1996, the Company entered into
an unsecured revolving credit facility (the "Revolving Credit Facility") with
Bank of America as agent for a group of lenders (the "Lenders"). On that date,
the Company borrowed $50 million under the Revolving Credit Facility and used
the proceeds to pay a dividend to Mariner Holdings, which was used by Mariner
Holdings to partially repay the JEDI Bridge Loan. During August 1996, the
outstanding balances of both the Revolving Credit Facility and the JEDI Bridge
Loan were repaid with the proceeds from the issuance of the Company's 10 1/2%
Senior Subordinated Notes.
The Revolving Credit Facility provides for a maximum $150 million
revolving credit loan which matures on October 1, 1999. The borrowing base under
the Revolving Credit Facility is currently $60 million and is subject to
periodic redetermination. The Revolving Credit Facility, with an outstanding
balance of $53.4 million at December 31, 1998, is classified as a current
liability. The October 1, 1999 maturity date on this liability is expected to be
extended in excess of one year as part of its semi-annual redetermination and
would be reclassified to a non-current liability at that time. In April 1999,
the Company pledged certain mineral 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 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.
32
35
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
The Revolving Credit Facility 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, 1998, the Company was in compliance with all such
requirements.
AFFILIATE CREDIT FACILITY -- Mariner Holdings., the Company's parent
and later assigned to Mariner Energy LLC, entered into an agreement with Enron
Capital & Trade Resources Corp. to provide a $25 million unsecured, subordinated
credit facility (the "Facility"), the funds from which were contributed to the
Company. The Facility accrues interest at an annual rate of LIBOR plus 2.5% and
requires a structuring fee of 4% of the borrowed amount. The Facility requires
that a portion of the proceeds of any private or public equity or debt offering
by the Company's parent be applied to repay amounts outstanding under the
Facility. The terms of the Facility required that if financing did not become
available by March 1, 1999, up to $25 million of the Facility would be converted
to equity. Interest expense recorded as a result of this Facility for the year
ended December 31, 1998, was approximately $993,000. As of December 31, 1998 the
Company had applied push down accounting treatment and reported the Mariner
Energy LLC debt as a liability of the Company. Subsequent to December 31, 1998,
the Facility was amended to (i) increase the size of the Facility to $50
million, (ii) extend the maturity to April 30, 2000, (iii) accrue interest at an
annual rate of LIBOR plus 4.5%, and (iv) provide for an optional conversion to
equity of Mariner Energy LLC by ECT.
SHORT-TERM CREDIT FACILITY WITH ECT -- In April 1999, the Company
established a $25 million short-term credit facility with Enron Capital & Trade
Resources Corp. to obtain funds needed to execute the Company's 1999 capital
expenditure program and for short-term working capital needs. The borrowing base
under the short-term credit facility is currently $25 million and is subject to
periodic redetermination. The facility accrues interest at an annual rate of
LIBOR plus 2.5% and requires a structuring fee of 1% of the committed amount.
The facility will mature on December 31, 1999 and is expected to be repaid from
internally-generated cash flows.
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 the JEDI Bridge Loan incurred in the Acquisition, and
(ii) repay the Revolving Credit Facility. The Notes bear interest at 10 1/2%
payable semiannually in arrears on February 1 and August 1 of each year. The
Notes are unsecured obligations of the Company, and are subordinated in right of
payment to all senior debt (as defined in the indenture governing the Notes) of
the Company, including indebtedness under the Revolving Credit Facility.
The indenture pursuant to which the Notes are issued contains certain
covenants that, among other things, limit the ability of 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, 1998, the Company was in compliance with all
such requirements.
The Notes are redeemable at the option of the Company, in whole or in
part, at any time on or after August 1, 2001, initially at 105.25% of their
principal amount, plus accrued interest, declining ratably to 100% of their
principal amount, plus accrued interest, on or after August 1, 2003. In
addition, at the option of the Company, at any time prior to August 1, 1999, up
to an aggregate of 35% of the original principal amount of the Notes may be
redeemable from the net proceeds of one or more public equity offerings, at
110.5% of their principal amount, plus accrued interest, provided that any such
redemption shall occur within 60 days of the date of the closing of such public
equity offering.
In the event of a change of control of the Company (as defined in the
indenture pursuant to which the Notes are issued), each holder of the Notes (the
"Holder") will have the right to require the Company to repurchase all or any
portion of such Holder's Notes at a purchase price equal to 101% of the
principal amount thereof, plus accrued interest.
As required in the indenture, in January 1997 the Company exchanged all
of the Notes for Series B notes with substantially the same terms as to
principal amount, interest rate, maturity and redemption rights. If the exchange
offer had not been consummated, the interest rate on the Notes would have
increased by 0.5% per annum.
33
36
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
5. 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 maximum number of
shares of common shares that can be issued under the Plan was 2,433,600.
At December 31, 1998, options (the "Options") to purchase 2,011,188
shares had been granted at exercise prices ranging from $8.33 to $14.58 per
share. The Options generally become exercisable as to one-fifth to one-third on
each of the first three or five anniversaries of the date of grant. The Options
expire from seven years to ten years after the date of grant.
The Company applies APB Opinion 25 and related interpretations in
accounting for the Plan. Accordingly, no compensation cost has been recognized
for the Plan. Had compensation cost for the Company's Plan been determined based
on the fair value at the grant date for awards under the Plan consistent with
the method of Financial Accounting Standards Board Statement 123 ("FAS 123"),
the Company's net loss for the year ended December 31, 1998, 1997 and for the
nine months ended December 31, 1996 would have increased $912,000, $777,000 and
$356,000, respectively to $59,333,000, $20,987,000 and $19,048,000 respectively.
The effects of applying FAS 123 in this pro forma disclosure are not indicative
of future amounts. The fair value of each option grant is estimated on the date
of grant using a present value calculation, risk free interest of 4.6%, no
dividends and expected life of 5 years. Stock options available for future grant
amounted to 422,412 shares at December 31, 1998. Exercisable stock options
amounted to 644,292 shares at December 31, 1998.
EQUITY INVESTMENT -- In June 1998, Mariner Holdings reached an
agreement with management shareholders and an affiliate of Enron to purchase
common shares of approximately $28.8 million of net equity capital, which was
used to supplement funding of the Company's 1998 capital expenditure plan.
6. EMPLOYEE BENEFIT AND ROYALTY PLANS
EMPLOYEE CAPITAL ACCUMULATION PLAN -- The Company provides all
full-time employees participation in the Employee Capital Accumulation Plan (the
"Plan") which is comprised of a contributory 401(k) savings plan and a
discretionary profit sharing plan. Under the 401(k) feature, the Company, at its
sole discretion, may contribute an employer-matching contribution equal to a
percentage not to exceed 50% of each eligible participant's matched salary
reduction contribution as defined by the Plan. Under the 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 1998, 1997 and
1996, the Company contributed $182,000, $200,000, and $165,000, 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.
34
37
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
7. COMMITMENTS AND CONTINGENCIES
MINIMUM FUTURE LEASE PAYMENTS -- The Company leases certain office
facilities and other equipment under long-term operating lease arrangements.
Minimum rental obligations under the Company's operating leases in effect at
December 31, 1998 are as follows (in thousands):
1999.................................... $ 1,112
2000.................................... 1,046
2001.................................... 1,073
2002.................................... 1,082
2003.................................... 454
Total............................. $ 4,767
Rental expense, before capitalization, was approximately $1,000,000,
$544,000, and $427,000 for the years ended December 31, 1998, 1997 and 1996,
respectively.
HEDGING PROGRAM -- The Company conducts a hedging program with respect
to its sales of crude oil and natural gas using various instruments whereby
monthly settlements are based on the differences between the price or range of
prices specified in the instruments and the settlement price of certain crude
oil and natural gas futures contracts quoted on the open market. The instruments
utilized by the Company differ from futures contracts in that there is no
contractual obligation which requires or allows for the future delivery of the
product.
The following table sets forth the results of hedging transactions
during the periods indicated:
Year Ended December 31,
-----------------------------------------------
1998 1997 1996
------------ ------------ ------------
Natural gas quantity hedged (Mmbtu) ......... 9,800,000 13,573,500 13,482,900
Increase (decrease) in natural gas sales .... $ 2,337,000 $ (3,931,000) $ (3,701,000)
Crude oil quantity hedged (Bbls) ............ 0 118,000 428,000
Increase (decrease) in crude oil sales ...... $ 0 $ (614,000) $ (1,912,000)
35
38
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Subsequent to year-end, the Company entered into a costless natural gas
collar with an affiliate from April to October 1999 with an extension at the
collar parties' option to extend the collar at a higher price through March
2000. In addition, in March, the Company entered into a three-year gas swap with
an affiliate. The following tables set forth the Company's position as of March
15, 1999.
Average
Daily
Volume
Type Location Time Period (Mmmbtu) Floor Ceiling Fixed Price
---- -------- ----------- -------- ----- ------- -----------
Collar Henry Hub April 1 - October 31, 1999 60 $1.85 $2.05 -
Swap Henry Hub November 1 - December 31, 1999 44 - - $2.18
Swap Henry Hub January 1 - December 31, 2000 30 - - $2.18
Swap Henry Hub January 1 - December 31, 2001 12 - - $2.18
Swap Henry Hub January 1 - October 31, 2002 6 - - $2.18
DEEPWATER RIG -- The Company executed a letter of intent in February
1998 regarding the provision of a Deepwater rig to Mariner and another company
on an equally shared basis for five years beginning in late 1999 or early 2000.
The Company is currently in discussions with the owner of the rig to determine
if a mutually acceptable drilling contract can be negotiated.
LITIGATION -- In December, 1996, ETOCO, Inc., which owns a 20% interest
in one producing well operated by the Company, filed a lawsuit against the
Company in the district court of Hardin County, Texas, alleging damage due to
the Company's refusal to drill an additional well. In April 1998, after a trial
on the merits, a jury awarded ETOCO $2.38 million in damages. In August, the
court awarded ETOCO $0.5 million in attorneys' fees. On February 8, 1999, the
case was settled.
8. INCOME TAXES
The following table sets forth a reconciliation of the statutory
federal income tax with the income tax provision (in thousands):
Predecessor
Company
Year Ended Year Ended ------------------
December 31 December 31 9 Months Ended 3 Months Ended
1998 1997 12/31/96 3/ 31/96
------------------ ------------------ ------------------ ------------------
$ % $ % $ % $ %
------- ------- ------- ------- ------- ------- ------- -------
Income (loss) before income
taxes........................... (58,421) -- (20,210) -- (18,692) -- 2,661 --
Income tax expense (benefit)
computed at statutory rates .... (20,447) (35) (7,074) (35) (6,542) (35) 931 35
Change in valuation allowance .. 18,804 32 6,871 34 8,125 43 (3,597) (135)
Other .......................... 1,643 3 203 1 (1,583) (8) 2,666 100
------- ------- ------- ------- ------- ------- ------- -------
Tax Expense .................... -- -- -- -- -- -- -- --
======= ======= ======= ======= ======= ======= ======= =======
36
39
No federal income taxes were paid by the Company during the years ended
December 31, 1998, December 31, 1997, or the nine months ending December 31,
1996 or the three months ending March 31, 1996.
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):
1998 1997 1996
---------- ---------- ----------
Deferred tax assets:
Net operating loss carry forwards ....................... $ 34,471 $ 10,410 $ 6,323
Differences between book and tax bases of properties .... -- 4,586 1,802
---------- ---------- ----------
34,771 14,996 8,125
Valuation allowance .......................................... (33,800) (14,996) (8,125)
---------- ---------- ----------
Total net deferred tax assets ................................ 971 -- --
Deferred tax liabilities --
Differences between book and tax bases of properties .... (971) -- --
Total net deferred taxes ........................... $ -- $ -- $ --
========== ========== ==========
As of December 31, 1998, the Company has a cumulative net operating
loss carryforward ("NOL") for federal income tax purposes of approximately $98
million, which begins to expire in the year 2012. A valuation allowance is
recorded against tax assets which are not likely to be realized. Because of the
uncertain nature of their ultimate realization, as well as past performance and
the NOL expiration date, the Company has established a valuation allowance
against this NOL carryforward benefit and for all net deferred tax assets in
excess of net deferred tax liabilities.
9. OIL AND GAS PRODUCING ACTIVITIES AND CAPITALIZED COSTS
The results of operations from the Company's oil and gas producing
activities were as follows (in thousands):
Predecessor
Company
------------
Year ended Year ended Nine months Three months
December December ended December ended March
31, 1998 31, 1997 31, 1996 31, 1996
---------- ---------- ---------- ----------
Oil and gas sales ........................... $ 56,690 $ 62,771 $ 47,079 $ 13,309
Production costs ............................ (9,858) (9,376) (6,495) (2,403)
Depreciation, depletion and amortization .... (33,833) (31,719) (24,747) (6,309)
Impairment of oil and gas properties ........ (50,800) (28,514) (22,500) --
Income tax expense .......................... -- -- -- --
---------- ---------- ---------- ----------
Results of operations ................... $ (37,801) $ (6,838) $ (6,663) $ 4,597
========== ========== ========== ==========
37
40
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Costs incurred in property acquisition, exploration and development
activities were as follows (in thousands, except per equivalent mcf amounts):
Predecessor
Company
------------
Year ended Year ended Nine months Three months
December 31, December 31, ended December ended March
1998 1997 31, 1996 31, 1996
---------- ---------- ---------- ----------
Property acquisition costs
Unproved properties .................... $ 43,143 $ 21,569 $ 13,477 $ 949
Proved properties ...................... -- 3,250 -- --
Exploration costs ........................... 35,674 27,364 18,627 3,903
Development costs ........................... 61,960 16,134 6,132 2,643
---------- ---------- ---------- ----------
Total costs ............................. $ 140,777 $ 68,317 $ 38,236 $ 7,495
========== ========== ========== ==========
Depreciation, depletion and amortization
rate per equivalent Mcf before impairment ... $ 1.40 $ 1.33 $ 1.33 $ 1.00
The Company capitalizes internal costs associated with exploration
activities. These capitalized costs were approximately $6,386,000, $4,418,000
and $4,362,000, for the years ended December 31, 1998, 1997 and 1996,
respectively.
The following table summarizes costs related to unevaluated properties
which have been excluded from amounts subject to amortization at December 31,
1998. The Company regularly evaluates these costs to determine whether
impairment has occurred. The majority of these costs are expected to be
evaluated and included in the amortization base within three years.
Predecessor Company
------------------------------------
Nine months Three months
Year ended Year ended ended ended Total at
December 31, December 31, December 31, March 31, Prior December 31,
1998 1997 1996 1996 Years 1998
-------- -------- -------- -------- -------- --------
Property
Acquisition costs ..... $ 53,936 $ 19,509 $ 7,949 $ 24 $ 1,628 $ 83,046
Exploration costs ...... 1,030 -- -- -- -- 1,030
-------- -------- -------- -------- -------- --------
Total .............. $ 54,966 $ 19,509 $ 7,949 $ 24 $ 1,628 $ 84,076
======== ======== ======== ======== ======== ========
Approximately 95% of excluded costs at December 31, 1998 relate to
activities in the Deepwater Gulf of Mexico and the remaining 5% relates to
activities in the Gulf of Mexico shallow waters and onshore areas near the Gulf.
38
41
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
10. SUPPLEMENTAL OIL AND GAS RESERVE AND STANDARDIZED MEASURE INFORMATION
(UNAUDITED)
Estimated proved net recoverable reserves as shown below include only
those quantities that are expected to be commercially recoverable at prices and
costs in effect at the balance sheet dates under existing regulatory practices
and with conventional equipment and operating methods. Proved developed reserves
represent only those reserves expected to be recovered through existing wells.
Proved undeveloped reserves include those reserves expected to be recovered from
new wells on undrilled acreage or from existing wells on which a relatively
major expenditure is required for recompletion. Also included in the Company's
proved undeveloped reserves as of December 31, 1998 were reserves expected to be
recovered 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.
39
42
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Estimated Quantities of Proved Reserves
(in thousands)
Oil (Bbl) Gas (Mcf)
----------- ----------
December 31, 1995 6,669 98,330
Revisions of previous estimates 3 (518)
Extensions, discoveries and other additions 1,168 24,326
Sales of reserves in place (1,810) (9,425)
Production (750) (20,429)
----------- ----------
December 31, 1996 5,280 92,284
Revisions of previous estimates 210 (1,817)
Extensions, discoveries and other additions 2,062 46,166
Purchase of reserves in place 55 2,737
Production (977) (18,004)
----------- ----------
December 31, 1997 6,630 121,366
Revisions of previous estimates (836) (410)
Extensions, discoveries and other additions 4,351 27,416
Production (786) (19,477)
----------- ----------
December 31, 1998 9,359 128,895
=========== ==========
Estimated Quantities of Proved Developed Reserves
(in thousands)
Oil (Bbl) Gas (Mcf)
----------- ----------
December 31, 1996 3,456 83,529
December 31, 1997 3,486 76,343
December 31, 1998 2,886 86,024
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.
40
43
MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Standardized Measure of Discounted Future Net Cash Flows
(in thousands)
Year ended December 31,
------------------------------------------
1998 1997 1996
---------- ---------- ----------
Future cash inflows ........................................ $ 383,490 $ 447,681 $ 548,451
Future production costs .................................... (103,400) (109,405) (103,777)
Future development costs ................................... (81,090) (73,568) (20,413)
Future income taxes ........................................ -- (35,346) (90,971)
---------- ---------- ----------
Future net cash flows ...................................... 199,000 229,362 333,290
Discount of future net cash flows at 10% per annum ......... (51,371) (52,903) (78,914)
---------- ---------- ----------
Standardized measure of discounted future net cash flows ... $ 147,629 $ 176,459 $ 254,376
========== ========== ==========
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, 1998, 1997 and 1996, used
in the above table, were $10.36, $16.43 and $25.16 per Bbl, respectively, and
$2.22, $2.79 and $4.50 per Mcf, respectively.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands):
Year ended December 31,
------------------------------------------
1998 1997 1996
---------- ---------- ----------
Sales and transfers of oil and gas produced,
net of production costs ..................... $ (46,832) $ (53,395) $ (51,505)
Net changes in prices and production costs ....... (67,815) (132,658) 120,843
Extensions and discoveries, net of future
development and production costs ............ 23,730 42,717 62,551
Development costs during period and net
change in development costs ................. 30,799 4,188 --
Revision of previous quantity estimates .......... (6,846) (730) (1,293)
Purchases of reserves in place ................... -- 6,071 --
Sales of reserves in place ....................... -- -- (10,813)
Net change in income taxes ....................... 27,193 29,619 (36,082)
Accretion of discount before income taxes ........ 20,365 30,336 17,342
Changes in production rates (timing) and
other ....................................... (9,424) (4,065) (7,182)
---------- ---------- ----------
Net change ....................................... $ (28,830) $ (77,917) $ 93,861
========== ========== ==========
41
44
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below are the names, ages and positions of the
executive officers and directors of the Company and a key consultant to the
Company as of March 1, 1999. All directors are elected for a term of one year
and serve until their successors are elected and qualified. All executive
officers hold office until their successors are elected and qualified.
Name Age Position with the Company
---- --- -------------------------
Robert E. Henderson 46 Chairman of the Board, President and Chief Executive Officer
Richard R. Clark 43 Executive Vice President and Director
L. V. "Bud" McGuire 55 Senior Vice President of Operations
Michael W. Strickler 43 Senior Vice President of Exploration and Director
Frank A. Pici 43 Vice President of Finance and Chief Financial Officer
Gregory K. Harless 49 Vice President of Oil and Gas Marketing
W. Hunt Hodge 43 Vice President of Administration
Tom E. Young 40 Vice President of Land
Christopher E. Lindsey 32 General Counsel and Secretary
David S. Huber 48 Consultant and Director of Deepwater Development
Richard B. Buy 47 Director
Mark E. Haedicke 44 Director
Stephen R. Horn 41 Director
Jeffrey McMahon 37 Director
Jere C. Overdyke, Jr. 47 Director
Frank Stabler 46 Director
Mr. Henderson has been Chairman of the Board of the Company 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, the
Company's former parent company, between 1989 and 1996. From 1984 to 1987, he
served the Company 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 the Company 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 the Company he worked as a
Production Engineer in the Offshore Production Group of Shell Oil Company.
Mr. McGuire joined the Company in June 1998 as Senior Vice
President-Operations. Prior to joining the Company, 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
Deepwater 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 the Company in 1984 and has served the Company
since such time in its geological and exploration activities. He has served as
Senior Vice President of Exploration of the Company since 1991 and a director
since 1989. Prior to joining the Company, 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.
42
45
Mr. Pici became Vice President of Finance and Chief Financial Officer
in December 1996. Prior to joining the Company, 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 an
independent oil & gas company in Pittsburgh, and he began his career with
Coopers & Lybrand. He's a Certified Public Accountant.
Mr. Harless has served as Vice President of Oil and Gas Marketing of
the Company since 1990. Prior to joining the Company 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 of the Company
since 1991. Prior to joining the Company in 1985, he was Purchasing Manager of
Santa Fe Minerals Company.
Mr. Young has served as Vice President of Land since November 1998.
Prior to his current position, Mr. Young served Mariner as Manager of Land for
the Central Gulf for approximately 10 years. Prior to joining Mariner in 1985,
Mr. Young served as a landman for TXO Production Corp.
Mr. Lindsey, General Counsel, joined the Company in August 1998. Prior
to joining the Company, Mr. Lindsey was associated with Bracewell & Patterson,
L.L.P. for five years.
Mr. Huber, a consultant to the Company, began his association with the
Company in 1991 as a deepwater project management consultant and is presently
Mariner's Director of Deepwater Developments. Prior to joining Mariner, Mr.
Huber was employed by Hamilton Oil Corporation in the North Sea from 1981 to
1991, holding positions of production manager, planning and economics manager,
and engineering manager. He was the deepwater drilling engineering supervisor
for Esso Exploration, Inc. from 1974 to 1980.
Mr. Buy has served as a director since January 1998. Since 1994 he has
been an employee of ECT or its affiliates, currently serving as Senior Vice
President and Chief Risk Officer of Enron Corp. Prior to joining ECT Mr. Buy was
a Vice President at Bankers Trust in the Energy Group.
Mr. Haedicke has served as a director since October 1998. He is
currently Managing Director, Legal, of ECT. 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 ECT since its inception in 1990.
Mr. Horn has served as a director since November 1998. Since 1996, he
has been as employee and Vice President, Equity Investments, of ECT. Prior to
joining ECT, Mr. Horn was a principal in Yellowstone Energy Partners, a private
equity investing firm in Houston, Texas.
Mr. McMahon has served as a director since September 1998. Since 1994,
he has been an employee of Enron, or its affiliates, currently serving as Senior
Vice President, Finance and Corporate Treasurer of Enron. Prior to joining
Enron, Mr. McMahon served as Senior Vice President and Chief Financial Officer
of MG Natural Gas Corp., a medium-sized natural gas marketing and finance
company in Houston, Texas.
Mr. Overdyke has served as a director since May 1996. Since 1991 he has
been an employee of ECT or one of its affiliates, currently serving as
President, ECT North America, Merchant Finance. Mr. Overdyke has over 20 years
of experience in the energy sector and has held various financial and management
positions with public and private independent exploration and production
companies.
Mr. Stabler has served as a director since May 1996. He is currently a
Managing Director of Enron International, Inc. and has held positions with ECT
since 1992. From 1989 to 1992, Mr. Stabler served as Manager of Investor
Services for American Exploration Company.
The Shareholders' Agreement requires that the Board of Directors of the
Company 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 Transactions -- The Acquisition, the
Shareholders' Agreement and Related Matters" on page 46.
43
46
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth the annual compensation for the
Company's Chief Executive Officer and the four other most highly compensated
executive officers for the three fiscal years ended December 31, 1998, and
includes two additional persons who were not executive officers as of December
31, 1998. These individuals are sometimes referred to as the "named executive
officers".
Long-Term
Annual Compensation Compensation
-------------------------------------- Received from
Other Annual Overriding Royalty All Other
Name and Principal Position Salary Compensation(1) Program(2) Compensation(3)
- ------------------------------- -------------- ------------------- --------------------- -----------------
Robert E. Henderson 1998 $285,000 $4,800 $354,857 $ 522
President and 1997 255,000 6,000 394,136 315
Chief Executive Officer 1996 236,000 6,000 421,311 306
Richard R. Clark 1998 225,000 4,800 218,077 306
Executive Vice President 1997 185,000 6,000 237,982 306
of Production 1996 166,500 6,000 247,971 306
Michael W. Strickler 1998 182,000 4,800 212,803 306
Senior Vice President 1997 165,000 6,000 234,603 306
of Exploration 1996 150,000 5,880 258,731 306
Frank A. Pici (6) 1998 160,000 4,380 0 306
Vice President of Finance and 1997 146,000 2,747 0 306
Chief Financial Officer 1996 12,167 0 0 26
Gregory K. Harless 1998 143,000 3,813 70,541 522
Vice President of Oil & Gas 1997 127,100 4,911 81,725 522
Marketing 1996 121,000 4,760 86,383 522
Clinton D. Smith (4) 1998 111,993 4,221 N/A (5) 183,229
Formerly Vice President of 1997 140,700 5,367 60,449 306
Operations 1996 131,500 5,154 96,447 306
James M. Fitzpatrick (4) 1998 107,269 3,720 N/A (5) 151,227
Formerly Vice President of 1997 124,000 4,762 N/A (5) 522
Land & Legal 1996 120,000 4,390 N/A (5) 522
(1) Amounts shown reflect the Company's contribution under the
discretionary profit sharing feature of its Employee Capital Accumulation Plan.
See "-- 401(k) Plan" (for a short plan year of nine months). 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) Does not include amounts received as a result of sales of
overriding royalty interests by individuals, normally in connection with sales
of properties by the Company. No such sales were made in 1998, 1997 or 1996.
(3) Amounts shown reflect insurance premiums paid by the Company with
respect to term life insurance for the benefit of the named executive officers.
(4) Mr. Smith left the Company in September 1998, and Mr. Fitzpatrick
left the Company in October 1998. The "All Other Compensation" column reflects
both insurance premium paid by the Company with respect to term life insurance
and severance benefits pursuant to their Employment Agreements.
(5) Information is not available to the Company.
(6) Mr. Pici joined the Company in December 1996.
EMPLOYMENT AGREEMENTS
The Company and each of the named executive officers have entered into
employment agreements (each, an "Employment Agreement" and collectively, the
"Employment Agreements") for initial terms of five years in the case of Messrs.
Henderson, Clark and Strickler, and one year in the case of Mr. Pici and three
years in the case of Mr. Harless.
44
47
The terms for Messrs. Pici and Harless were recently extended for one and
one-half years. The Employment Agreements then extend for six months in the case
of Messrs. Henderson, Clark, Strickler and Pici, and three months in the case of
Mr. Harless, unless notice of termination is given by either the Company or the
named executive officer at least three or six months before the end of the term.
Under the Employment Agreements, the current annual salaries are $285,000,
$225,000, $190,000, $160,000, and $143,000 for Messrs. Henderson, Clark,
Strickler, Pici and Harless, respectively, which the Company may in its
discretion increase. The named executive officers are eligible for participation
in any medical, dental, life and accidental death and dismemberment insurance
programs and retirement, pension, deferred compensation and other benefit
programs instituted by the Company from time to time. The employees are also
entitled to vacation, reimbursement of certain expenses and, depending upon the
Employment Agreement, either an automobile allowance or a leased vehicle of the
Company's choice and reimbursement for expenses related to the use of that
leased vehicle. As incentive compensation, the named executive officers are
entitled to overriding royalty interests in certain oil and gas prospects
acquired by the Company. See "Overriding Royalty Program".
If a named executive officer's Employment Agreement is terminated by
the Company, with or without Cause (as defined in each Employment Agreement) or
by the named executive officer for Good Reason (as defined in each Employment
Agreement), the named executive officer will be entitled to, among other things,
(i) his or her salary and other benefits through the end of the initial term or
extended term of the Employment Agreement (to be paid in a lump sum cash payment
in the case of termination by the Company without Cause or termination by the
named executive officer for Good Reason), (ii) a lump sum cash payment equal to
six, nine or 12 months' salary, depending upon the Employment Agreement (12
months in the case of Mr. Henderson, nine months in the case of Messrs. Clark
and Strickler, and six months in the case of Messrs. Pici and Harless), (iii) a
lump sum cash payment equal to all vacation time carried forward from a previous
year and all earned and unused vacation time for the then current year and (iv)
an assignment of vested overriding royalty interests. See "-- Overriding Royalty
Interests". If a named executive officer's Employment Agreement is terminated by
the named executive officer without Good Reason or by the Company for cause, he
will be entitled to the amounts specified in the preceding sentence except that
he will not be entitled to the lump sum cash payment described in clause (ii).
Any amounts paid on termination of an Employment Agreement will be grossed-up to
cover any applicable taxes.
Each named executive officer has agreed that during the term of his
Employment Agreement, and for 12 months thereafter in the case of Messrs.
Henderson, Clark and Strickler and six months thereafter in the case of Messrs.
Pici and Harless, if the named executive officer's Employment Agreement is
terminated by the Company for Cause or by the named executive officer other than
for Good Reason, he will not compete with the Company for business or hire away
the Company's employees.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The Company 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, 1999, there were 13,928,304 common shares of Mariner Energy LLC
outstanding.
Amount and
Name and Address Nature of Percent
Title of Class of Beneficial Owner Beneficial Ownership of Class
-------------- ------------------- -------------------- ----------
Common Stock of Joint Energy Development 13,334,184 95.7%
Mariner Energy LLC Investments Limited Partnership(1)
1400 Smith Street
Houston, Texas 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
ECT. 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, 1999,
with respect common shares of Mariner Energy LLC beneficially owned by each of
the Company's directors, the Company's named officers, a key consultant
45
48
of the Company 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 (1) of Class
------------------------------ ------------------------ --------
Robert E. Henderson......................... 84,840 *
Richard R. Clark............................ 61,440 *
L. V. "Bud" McGuire......................... 6,000 *
Michael W. Strickler........................ 61,440 *
Frank A. Pici............................... 20,472 *
Gregory K. Harless.......................... 13,200 *
David S. Huber.............................. 61,440 *
Richard B. Buy.............................. 0 *
Mark E. Haedicke............................ 0 *
Stephen R. Horn............................. 0 *
Jeffrey McMahon............................. 0 *
Jere C. Overdyke, Jr........................ 0 *
Frank Stabler............................... 0 *
All directors and executive officers and
key consultant as a group (15 persons).... 308,832 2.22%
* Less than one percent.
(1) All shares are owned directly by the named person and such person
has sole voting and investment power with respect to such shares.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
THE ACQUISITION, THE SHAREHOLDERS' AGREEMENT AND RELATED MATTERS
Mariner, JEDI and each other shareholder of Mariner are parties to the
Amended and Restated Shareholders' Agreement (as amended, the "Shareholders'
Agreement").
Mariner 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 ECT, and an affiliate of Enron and ECT is the
general partner of JEDI. Accordingly, Enron may be deemed to control JEDI and
the Company. See "Ownership of Securities". In addition, six of the Company's
directors are officers of Enron or of affiliates of Enron: Mr. Buy is Senior
Vice President and Chief Risk Officer of Enron Corp., Mr. Haedicke is a
Managing Director of ECT, Mr. McMahon is Vice President, Finance and the
Corporate Treasurer for Enron, Mr. Horn is a Vice President of ECT, Mr. Overdyke
is the President of ECT N.A., Merchant Finance, and Mr. Stabler is a Managing
Director of Enron International, 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, ECT, JEDI and other affiliates of
ECT 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
46
49
are or may become competitors of Mariner. Because of these various possible
conflicting interests, the Company 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 the Company.
Under the terms of the Company Agreement, Enron and its affiliates
(which include, without limitation, ECT and JEDI) are specifically permitted to
compete with the Company, and neither Enron nor any of its affiliates has any
obligation to bring any business opportunity to the Company.
Under the Revolving Credit Facility, the Company has covenanted that it
will not engage in any transaction with any of its affiliates (including Enron,
ECT, 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 the Company 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 Energy, Inc.
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
the Company 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 Energy, Inc.'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 Energy, Inc. 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 Energy, Inc.'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.
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, there are several
prospects in which both an affiliate of Enron and the Company have working
interests. Such interests were acquired in the ordinary course of business
pursuant to bids, joint or otherwise. Any wells drilled will be subject to joint
operating agreements relating to exploration and possible production and will be
subject to customary business terms. Furthermore, the Company has entered into
several agreements with Enron or affiliates of Enron for the purpose of hedging
oil and natural gas prices on the Company's future production. The Company
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 the Company than
would be contained in an agreement with a third party.
Pursuant to a Participation Agreement dated as of May 16, 1996 (the
"Participation Agreement") by and between Hardy plc and Mariner Holdings, Hardy
plc has an option to purchase participation rights in certain prospects
generated by the Company until May 16, 1999. This option entitles Hardy plc to
acquire up to 25% of any leasehold or working interest the Company holds in any
exploitation prospect that (i) is located in the Gulf, (ii) the Company, in its
reasonable judgement, plans to develop, (iii) the Company reasonably expects to
exploit using a floating production facility or a subsea tieback system that
will require estimated gross capital expenditures in excess of $150.0 million
and (iv) is generated by the Company and is expected to be operated by the
Company. The Company is required to provide notice to Hardy plc within ten days
of acquiring an interest, or a contractual right to acquire an interest, in such
a prospect. Hardy plc must exercise its option with respect to such prospect
within ten days of receiving such notice from the Company. If Hardy plc
exercises its participation right as to any prospect, it must pay the Company a
ratable portion of the Company's costs and expenses in generating and acquiring
the prospect, including a ratable portion of a $250,000 prospect fee. In
addition to the interest in the prospect it acquires from the Company, Hardy plc
would then have the right to copy any geological and geophysical data owned by
the Company and pertaining to the prospect in which it is participating, unless
the Company is restricted from doing so by another agreement.
47
50
1998 EQUITY INVESTMENT
In June 1998, Mariner Holdings issued additional equity to its existing
shareholders, including JEDI, for approximately $14.58 per share, for an
aggregate investment of $30.0 million (the "1998 Equity Investment"). The
Company paid approximately $1.2 million as a structuring fee, on a pro rata
basis, to existing shareholders participating in this transaction. Approximately
$1.0 million of this fee was paid to ECT Securities Corp., an affiliate of JEDI.
ECT CREDIT FACILITY
In August 1998, the Company's parent established the ECT Credit
Facility to provide the Company with additional capital. The ECT Credit Facility
provides for unsecured, subordinated loans up to $25 million, bearing interest
at LIBOR plus 2.5%, payable monthly. In addition, upon any draw against the
facility, the Company's parent must pay ECT Securities Limited Partnership a
structuring fee equal to 4% of the principal amount of the borrowing. This
agreement was due to mature on March 1, 1999 and if not repaid will be converted
to common shares. Subsequent to December 31, 1998, the Facility was amended to
(i) increase the size of the Facility to $50 million, (ii) extend the maturity
to April 30, 2000, (iii) accrue interest at an annual rate of LIBOR plus 4.5%,
and (iv) provide for an optional conversion to equity of Mariner Energy LLC by
ECT.
SHORT-TERM CREDIT FACILITY WITH ECT
In April 1999, the Company established a $25 million borrowing-based,
short-term credit facility with Enron Capital & Trade Resources Corp. to obtain
funds needed to execute the Company's 1999 capital expenditure program and for
short-term working capital needs. This facility will mature on December 31,
1999. The Company paid ECT Securities Limited Partnership a structuring fee
equal to 1% of the commitment.
48
51
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 * are filed with this Annual Report
on Form 10-K. All exhibits not so designated are incorporated by
reference to a prior filing as indicated.
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) Credit Agreement, dated June 28, 1996, among the Registrant,
Nations Bank of Texas, N.A., as Agent, and the financial
institutions listed on schedule 1 thereto, as amended by First
Amendment to Credit Agreement, dated August 12, 1996, among
the Registrant, Nations Bank of Texas, N.A., as Agent, Toronto
Dominion (Texas), Inc., as Co-agent, and the financial
institutions listed on schedule 1 thereto.
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 Nations Bank
of Texas, N.A.
4.5(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.
4.6(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.
4.7(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.
4.8(a) Form of the Registrant's 10 1/2% Senior Subordinated Note Due
2006, Series B.
4.9* Credit and Subordination Agreement dated as of September 2,
1998 between Mariner Holdings, Inc. and Enron Capital & Trade
Resources Corp.
10.2(a) Participation Agreement, dated as of May 16, 1996, between
Hardy Oil & Gas plc. and Mariner Holdings, Inc.
10.3* 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.
49
52
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(a)+ 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*+ Employment Agreement, dated August 1, 1998, between the
Registrant and Chris E. Lindsey.
10.11(a)+Amended and Restated Consulting Services Agreement, dated June
27, 1996, between the Registrant and David S. Huber.
10.12(a)+Mariner Holdings, Inc. 1996 Stock Option Plan (assumed by
Mariner Energy LLC).
10.13(a)+Form of Incentive Stock Option Agreement (pursuant to the
Mariner Holdings, Inc. 1996 Stock Option Plan, assumed by
Mariner Energy LLC).
10.14* List of executive officers who are parties to an Incentive
Stock Option Agreement.
10.15(a)+Form of Nonstatutory Stock Option Agreement (pursuant to the
Mariner Holdings, Inc. 1996 Stock Option Plan, assumed by
Mariner Energy LLC).
10.16* List of executive officers who are parties to a Nonstatutory
Stock Option Agreement.
10.17(a)+Nonstatutory Stock Option Agreement, dated June 27, 1996,
between the Registrant and David S. Huber.
10.19(d) Amended and Restated Employment Agreement, dated as of
December 1, 1998, between the Registrant and Frank A. Pici.
10.20*+ Amended and Restated Employment Agreement, dated as of June 1,
1998, between the Registrant and L.V. Bud McGuire.
23.1* Consent of Ryder Scott Company.
23.2* Ryder Scott Company Letter of Estimated Proved Reserves dated
March 29, 1999
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.
50
53
(b) REPORTS ON FORM 8-K:
The Company filed no reports on Form 8-K during the quarter ended
December 31, 1998.
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
51
54
valorem taxes and other expenses incidental to production, but not including
lease acquisition, drilling or completion expenses or other "finding costs".
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.
52
55
"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.
53
56
SIGNATURES
The registrant has duly caused this report to be signed on its behalf
by the undersigned, hereunto duly authorized.
April 15, 1999
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
- --------- ----- ----
/s/ Robert E. Henderson Chairman of the Board, President and April 15, 1999
- ------------------------------------ Chief Executive Officer
Robert E. Henderson (Principal Executive Officer)
/s/ Frank A. Pici Vice President of Finance and April 15, 1999
- ------------------------------------ Chief Financial Officer
Frank A. Pici (Principal Financial Officer and
Principal Accounting Officer)
/s/ Richard R. Clark Executive Vice President April 15, 1999
- ------------------------------------
Richard R. Clark
/s/ Michael W. Strickler Senior Vice President of Exploration April 15, 1999
- ------------------------------------ and Director
Michael W. Strickler
/s/ Richard B. Buy Director April 15, 1999
- ------------------------------------
Richard B. Buy
/s/ Mark E. Haedicke Director April 15, 1999
- ------------------------------------
Mark E. Haedicke
/s/ Stephen R. Horn Director April 15, 1999
- ------------------------------------
Stephen R. Horn
/s/ Jeffery D. McMahon Director April 15, 1999
- ------------------------------------
Jeffery D. McMahon
/s/ Jere C. Overdyke, Jr. Director April 15, 1999
- ------------------------------------
Jere C. Overdyke, Jr.
/s/ Frank Stabler Director April 15, 1999
- ------------------------------------
Frank Stabler
57
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.
58
INDEX TO EXHIBITS
Exhibit
Number Description
------- -----------
Exhibits designated by the symbol * are filed with this Annual Report
on Form 10-K. All exhibits not so designated are incorporated by
reference to a prior filing as indicated.
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) Credit Agreement, dated June 28, 1996, among the Registrant,
Nations Bank of Texas, N.A., as Agent, and the financial
institutions listed on schedule 1 thereto, as amended by First
Amendment to Credit Agreement, dated August 12, 1996, among
the Registrant, Nations Bank of Texas, N.A., as Agent, Toronto
Dominion (Texas), Inc., as Co-agent, and the financial
institutions listed on schedule 1 thereto.
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 Nations Bank
of Texas, N.A.
4.5(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.
4.6(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.
4.7(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.
4.8(a) Form of the Registrant's 10 1/2% Senior Subordinated Note Due
2006, Series B.
4.9* Credit and Subordination Agreement dated as of September 2,
1998 between Mariner Holdings, Inc. and Enron Capital & Trade
Resources Corp.
10.2(a) Participation Agreement, dated as of May 16, 1996, between
Hardy Oil & Gas plc. and Mariner Holdings, Inc.
10.3* 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.
59
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(a)+ 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*+ Employment Agreement, dated August 1, 1998, between the
Registrant and Chris E. Lindsey.
10.11(a)+Amended and Restated Consulting Services Agreement, dated June
27, 1996, between the Registrant and David S. Huber.
10.12(a)+Mariner Holdings, Inc. 1996 Stock Option Plan (assumed by
Mariner Energy LLC).
10.13(a)+Form of Incentive Stock Option Agreement (pursuant to the
Mariner Holdings, Inc. 1996 Stock Option Plan, assumed by
Mariner Energy LLC).
10.14* List of executive officers who are parties to an Incentive
Stock Option Agreement.
10.15(a)+Form of Nonstatutory Stock Option Agreement (pursuant to the
Mariner Holdings, Inc. 1996 Stock Option Plan, assumed by
Mariner Energy LLC).
10.16* List of executive officers who are parties to a Nonstatutory
Stock Option Agreement.
10.17(a)+Nonstatutory Stock Option Agreement, dated June 27, 1996,
between the Registrant and David S. Huber.
10.19(d) Amended and Restated Employment Agreement, dated as of
December 1, 1998, between the Registrant and Frank A. Pici.
10.20*+ Amended and Restated Employment Agreement, dated as of June 1,
1998, between the Registrant and L.V. Bud McGuire.
23.1* Consent of Ryder Scott Company.
23.2* Ryder Scott Company Letter of Estimated Proved Reserves dated
March 29, 1999
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.