e424b3
Filed pursuant to Rule 424(b)(3)
Registration No. 333-124858
PROSPECTUS
33,348,130 Shares
Common Stock
This prospectus relates to up to 33,348,130 shares of the
common stock of Mariner Energy, Inc., which may be offered for
sale by the selling stockholders named in this prospectus. The
selling stockholders acquired the shares of common stock offered
by this prospectus in private equity placements. We are
registering the offer and sale of the shares of common stock to
satisfy registration rights we have granted.
We are not selling any shares of common stock under this
prospectus and will not receive any proceeds from the sale of
common stock by the selling stockholders. The shares of common
stock to which this prospectus relates may be offered and sold
from time to time directly from the selling stockholders or
alternatively through underwriters or broker-dealers or agents.
The shares of common stock may be sold in one or more
transactions, at fixed prices, at prevailing market prices at
the time of sale or at negotiated prices. Because all of the
shares being offered under this prospectus are being offered by
selling stockholders, we cannot currently determine the price or
prices at which our shares of common stock may be sold under
this prospectus. Prior to the date of this prospectus, we are
aware that some of our shares of common stock have been sold in
private resale transactions. We understand those sales have been
reported to the
PORTAL®
Market. To our knowledge, the most recent price at which shares
were resold was $20.50 per share on February 7, 2006.
Future prices will likely vary from that price and these sales
may not be indicative of prices at which our common stock will
trade. Until our shares of common stock are listed on the New
York Stock Exchange, we expect that the selling stockholders
will sell their shares at prices between $19.50 and $21.50, if
any shares are sold. Please read Plan of
Distribution.
Prior to this offering, there has been no public market for our
common stock. Our common stock has been approved for listing on
the New York Stock Exchange, subject to the completion of our
proposed merger with Forest Energy Resources, Inc.
Investing in our common stock involves risks. You should read
the section entitled Risk Factors beginning on
page 24 for a discussion of certain risk factors that you
should consider before investing in our common stock.
You should rely only on the information contained in this
prospectus or any prospectus supplement or amendment. We have
not authorized anyone to provide you with different information.
We are not making an offer of these securities in any state
where the offer is not permitted.
Neither the Securities and Exchange Commission (the
SEC) nor any state securities commission has
approved or disapproved of these securities or determined
whether this prospectus is truthful or complete. Any
representation to the contrary is a criminal offense.
The date of this prospectus is February 10, 2006.
TABLE OF CONTENTS
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F-1 |
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A-1 |
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WHERE YOU CAN FIND INFORMATION
We have filed with the SEC, under the Securities Act of 1933, as
amended (the Securities Act), a registration
statement on
Form S-1 with
respect to the common stock offered by this prospectus. This
prospectus, which constitutes part of the registration
statement, does not contain all the information set forth in the
registration statement or the exhibits and schedules which are
part of the registration statement, portions of which are
omitted as permitted by the rules and regulations of the SEC.
Statements made in this prospectus regarding the contents of any
contract or other documents are summaries of the material terms
of the contract or document. With respect to each contract or
document filed as an exhibit
(i)
to the registration statement, reference is made to the
corresponding exhibit. For further information pertaining to us
and to the common stock offered by this prospectus, reference is
made to the registration statement, including the exhibits and
schedules thereto, copies of which may be inspected without
charge at the public reference facilities of the SEC at
100 F Street, N.E., Washington, D.C. 20549. Copies of
all or any portion of the registration statement may be obtained
from the SEC at prescribed rates. Information on the public
reference facilities may be obtained by calling the SEC at
1-800-SEC-0330. In
addition, the SEC maintains a web site that contains reports,
proxy and information statements and other information that is
filed electronically with the SEC. The web site can be accessed
at www.sec.gov.
Upon completion of this offering, we will be required to comply
with the informational requirements of the Securities Exchange
Act of 1934, as amended (the Exchange Act), and,
accordingly, will file current reports on
Form 8-K,
quarterly reports on
Form 10-Q, annual
reports on
Form 10-K, proxy
statements and other information with the SEC. Those reports,
proxy statements and other information will be available for
inspection and copying at the public reference facilities and
internet site of the SEC referred to above.
(ii)
SUMMARY
This summary highlights selected information from this
prospectus, but does not contain all information that you should
consider before investing in the shares. You should read this
entire prospectus carefully, including the Risk
Factors beginning on page 24 of this prospectus and
the financial statements included elsewhere in this prospectus.
References to Mariner, the Company,
we, us, and our refer to
Mariner Energy, Inc. The estimates of our proved reserves as of
December 31, 2002, 2003 and 2004 included in this
prospectus are based on reserve reports prepared by Ryder Scott
Company, L.P., independent petroleum engineers (Ryder
Scott). A summary of their report on our proved reserves
as of December 31, 2004 is attached to this prospectus as
Annex A. We have provided definitions for some of the
industry terms used in this prospectus in the Glossary of
Oil and Natural Gas Terms beginning on page 191 of
this prospectus.
In this prospectus:
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The terms we, us, our and
like terms, and the term Mariner, refer to Mariner
Energy, Inc.; |
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MEI Sub refers to MEI Sub, Inc.; |
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Forest refers to Forest Oil Corporation; |
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Forest Energy Resources refers to Forest Energy
Resources, Inc.; and |
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Forest Gulf of Mexico operations refers to the
offshore Gulf of Mexico operations conducted by Forest that have
been contributed to Forest Energy Resources and the shares of
which will be spun-off to Forest shareholders. |
About Mariner Energy, Inc.
Mariner Energy, Inc. is an independent oil and gas exploration,
development and production company with principal operations in
the Gulf of Mexico, both shelf and deepwater, and the Permian
Basin in West Texas. As of December 31, 2004, we had
237.5 Bcfe of estimated proved reserves, of which
approximately 64% were natural gas and 36% were oil and
condensate. As of December 31, 2004, the present value,
discounted at 10% per annum, of estimated future net
revenues from our estimated proved reserves, before income tax
(PV10), was approximately $668 million, and our
standardized measure of discounted future net cash flows
attributable to its estimated proved reserves was approximately
$494.4 million. Please see Business Estimated
Proved Reserves for a reconciliation of PV10 to the
standardized measure of discounted future net cash flows. As of
December 31, 2004, approximately 46% of our estimated
proved reserves were classified as proved developed. For the
year ended December 31, 2004, our total net production was
37.6 Bcfe. Of our estimated proved reserves, 48% are
located in the Permian Basin in West Texas, 37% in the Gulf of
Mexico deepwater and 15% on the Gulf of Mexico shelf as of
December 31, 2004. In the three-year period ended
December 31, 2004, we deployed approximately
$337 million of capital on acquisitions, exploration and
development while adding approximately 191 Bcfe of
estimated proved reserves and producing approximately
111 Bcfe.
1
Significant Properties
We own oil and gas properties, producing and non-producing,
onshore in Texas and offshore in the Gulf of Mexico, primarily
in federal waters. Our largest properties, based on the present
value of estimated future net proved reserves as of
December 31, 2004, are shown in the following table.
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Approximate | |
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Date | |
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Estimated | |
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Mariner | |
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Water | |
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Gross | |
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Production | |
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Proved | |
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Working | |
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Depth | |
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Producing | |
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Commenced/ | |
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Reserves | |
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PV10 | |
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Standardized | |
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Operator | |
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Interest | |
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(Feet) | |
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Wells(1) | |
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Expected | |
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(Bcfe) | |
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Value(2) | |
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Measure | |
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% | |
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(in $ millions) | |
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(in $ millions) | |
West Texas Permian Basin:
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Aldwell Unit
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Mariner |
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66.5 |
(3) |
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Onshore |
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185 |
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1949 |
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112.7 |
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$ |
203.8 |
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Gulf of Mexico Deepwater:
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Mississippi Canyon 296/252 (Rigel)
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Dominion |
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22.5 |
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5,200 |
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0 |
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Second Quarter 2006 |
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22.4 |
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82.9 |
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Viosca Knoll 917/961/962 (Swordfish)
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Mariner(4 |
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15.0 |
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4,700 |
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2 |
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Fourth Quarter 2005 |
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13.4 |
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59.3 |
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Green Canyon 516 (Yosemite)
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ENI |
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44.0 |
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3,900 |
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1 |
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2002 |
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15.1 |
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66.6 |
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Mississippi Canyon 718 (Pluto)(5)
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Mariner |
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51.0 |
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2,830 |
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0 |
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1999 |
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9.0 |
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31.7 |
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Green Canyon 178 (Baccarat)
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W&T |
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40.0 |
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1,400 |
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0 |
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Third Quarter 2005 |
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4.0 |
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14.3 |
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Green Canyon 472/473 (King Kong)
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ENI |
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50.0 |
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3,850 |
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2002 |
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1.2 |
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2.0 |
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Gulf of Mexico Shelf:
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Mississippi Canyon 66 (Ochre)(6)
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Mariner |
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75.0 |
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1,150 |
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0 |
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2004 |
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3.6 |
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11.7 |
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Other Properties
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43 |
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56.1 |
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195.7 |
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Total:
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231 |
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237.5 |
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$ |
668.0 |
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$ |
494.4 |
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(1) |
Wells producing or capable of producing as of December 31,
2004. |
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(2) |
Please see Business Estimated Proved Reserves
for a definition of PV10 and a reconciliation of PV10 to the
standardized measure of discounted future net cash flows. |
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(3) |
We operate the field and own working interests in individual
wells ranging from approximately 33% to 84%. |
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(4) |
Mariner served as operator until December 2005, at which time
pursuant to certain contractual arrangements, Noble Energy,
Inc., a 60% partner in the project, began serving as operator. |
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(5) |
This field was shut-in in April 2004 pending the drilling of a
new well and installation of an extension to the existing
infield flowline and umbilical. As a result, as of
December 31, 2004, 9.0 Bcfe of our net proved reserves
attributable to this project were classified as proved
undeveloped reserves. We expect production from Pluto to
recommence in the second quarter of 2006. |
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(6) |
Field has been shut in since September 2004 due to destruction
of host platform by Hurricane Ivan. |
The distribution of our proved reserves reflects our efforts
over the last three years to diversify our asset base, which in
prior years had been focused primarily in the Gulf of Mexico
deepwater. We have shifted some of our focus on deepwater
activities to increased exploration and development on the Gulf
of Mexico shelf and exploitation of our West Texas Permian Basin
properties. By allocating our resources among these three areas,
we expect to balance the risks associated with the exploration
and development of our asset base. We intend to continue to
pursue moderate-risk exploratory and development drilling
projects in the Gulf of Mexico deepwater and on the Gulf of
Mexico shelf, including select deep shelf
2
prospects, and also target low-risk infill drilling projects in
West Texas. It is our practice to generate most of our prospects
internally, but from time to time we also acquire third-party
generated prospects. We then drill to find oil and natural gas
reserves, a process that we refer to as growth through the
drill bit.
We operate and own working interests in individual wells ranging
from 33% to 84% (with an average working interest of
approximately 66.5%), in the
18,500-acre Aldwell
Unit. The field is located in the heart of the Spraberry
geologic trend southeast of Midland, Texas, and has produced oil
and gas since 1949. We began our recent redevelopment of the
Aldwell Unit by drilling eight wells in the fourth quarter of
2002, 43 wells in 2003, and 54 wells in 2004. As of
December 31, 2004, there were a total of 185 wells
producing or capable of producing in the field. Our aggregate
net capital expenditures for the 2004 drilling program in the
field were approximately $20.3 million, and we added
27 Bcfe of proved reserves, while producing 4.0 Bcfe.
During 2005, we have accelerated our development program in West
Texas. Through September 30, 2005, we had drilled 65 new
wells at our Aldwell and North Stiles Units. All of our drilling
in the Aldwell and North Stiles Units has resulted in
commercially successful wells that are expected to produce in
quantities sufficient to exceed costs of drilling and
completion. Our net production from onshore wells for the nine
months ended September 30, 2005 averaged approximately
17 MMcfe per day. We have completed construction of our own
oil and gas gathering system and compression facilities in the
Aldwell Unit. We began flowing gas production through the new
facilities on June 1, 2005. We have also entered into new
contracts with third parties to provide processing of our
natural gas and transportation of our oil produced in the unit.
The new gas arrangement also provides us with the option to sell
our gas to one of four firm or five interruptible sales
pipelines versus a single outlet under the former arrangement.
We expect these arrangements to improve the economics of
production from the Aldwell Unit.
In August 2005, but effective in October 2005, we entered into
an agreement covering approximately 33,000 acres in West
Texas, pursuant to which, upon closing, we acquired an
approximate 35% working interest in approximately 200 existing
producing wells effective November 1, 2005, and committed
to drill an additional 150 wells within a four year period,
funding $36.5 million of our partners share of
drilling costs for such
150-well drilling
program. We will obtain an assignment of an approximate 35%
working interest in the entire committed acreage upon completion
of the 150-well program.
As of September 30, 2005 we held interests in
11 fields in the Gulf of Mexico deepwater, four of which we
operate. The Gulf of Mexico deepwater accounts for 37%, or
86.7 Bcfe, of our December 31, 2004 proved reserves.
Our net production from deepwater wells for the nine months
ended September 30, 2005 averaged approximately
33 MMcfe per day (see Recent Developments below
for a discussion of the effects of hurricanes Katrina and Rita).
As of September 30, 2005, we held interests in 55 Gulf
of Mexico blocks with water depths of over 1,300 feet and
had approximately 132,000 net undeveloped acres under
lease. In 2004, we spent approximately $63.5 million net on
drilling and completion activities in the deepwater. We drilled
five exploratory wells, four of which were successful, and one
development well, which was also successful.
In 2004, four subsea tiebacks were in the development phase in
the deepwater: Mississippi Canyon 718 (Pluto), Viosca
Knoll 917 (Swordfish), Green Canyon 178 (Baccarat) and
Mississippi Canyon 296 (Rigel). These four subsea tieback
projects contain approximately 49 Bcfe of proved reserves
as of December 31, 2004. Swordfish, Baccarat and Rigel are
the results of Mariner-generated prospects. The Swordfish and
Pluto projects are operated by Mariner, and the Baccarat and
Rigel projects are operated by other working interest owners.
Currently approximately 7 MMcfe per day of production
remains shut-in awaiting repairs due to Hurricanes Katrina and
Rita, primarily associated with the Baccarat property. While we
believe physical damage to our existing platforms and facilities
was relatively minor from both hurricanes, the effects of the
storms caused damage to onshore pipeline and processing
3
facilities that resulted in a portion of our production being
temporarily shut-in, or
in the case of our Swordfish project, postponed. In addition,
Hurricane Katrina caused damage to platforms that host three of
our development projects: Pluto, Rigel, and Mississippi
Canyon 66 (Ochre). Repairs to these facilities may take up
to six months, pushing commencement of production on these
projects into 2006.
In the past two years, we have increased our drilling activities
on the Gulf of Mexico shelf. As of September 30, 2005, we
held interests in 21 fields on the Gulf of Mexico shelf,
eight of which we operate. Gulf of Mexico shelf properties
comprise 15%, or 36 Bcfe, of our proved reserves as of
December 31, 2004. Our net production from these wells for
the nine months ended September 30, 2005 averaged
approximately 32 MMcfe per day (see Recent
Developments below for a discussion of the effects of
hurricanes Katrina and Rita). As of September 30, 2005, we
held interests in 59 Gulf of Mexico shelf blocks and had
approximately 81,000 net undeveloped acres under lease.
During 2004, we spent approximately $38.3 million to drill
nine exploratory wells, three of which were successful, and two
development wells, one of which was successful, on the Gulf of
Mexico shelf.
First production from our Ewing Bank 977 (Dice) project, a
subsea tieback, and High Island 46 (Green Pepper) commenced
in January 2005. First production from our two West Cameron
333 wells (Royal Flush) commenced during February 2005.
Recent Developments
Approximately 29 Mmcfe per day of natural gas and
approximately 3,000 bbls per day of oil and condensate net
to our interest were initially
shut-in as a result of
the effects of Hurricane Katrina in August 2005. The majority of
this production was returned within two weeks of the hurricane,
and substantially all within three weeks of the hurricane.
Additionally, we are experiencing delays in startup of three of
our projects primarily as a result of Hurricane Katrina which is
anticipated to defer commencement of production to as late as
the second quarter of 2006. Approximately 60 MMcfe per day
of production net to our interest was shut-in initially as a
result of the effects of Hurricane Rita in late September 2005.
Approximately 53 MMcfe per day of production, or
approximately 90% of our pre-hurricane production, was restored
within two weeks of the hurricane. Our operated platforms appear
to have sustained minimal damage attributable to the storm.
First reports from operators of other facilities handling our
production indicated varying degrees of damage to their
facilities, the full extent of which may not be known for some
time. Although a submersible rig engaged in drilling operations
on our East Cameron Block 79 property was moved off
location by Hurricane Rita, a substitute rig was subsequently
provided, the damage to the well was repaired and drilling
recommenced in the last quarter of 2005. Other planned
operations also are delayed as a result of the effects of both
hurricanes. We cannot estimate a range of loss arising from the
hurricanes until we are able to more completely assess the
impacts on our properties and the properties of our operational
partners. Until we are able to complete all the repair work and
submit costs to our insurance underwriters for review, the full
extent of our insurance recovery and the resulting net cost to
us for Hurricanes Katrina and Rita will be unknown. For the
insurance period ending September 30, 2005, we carry a
$3.0 million annual deductible and a $.375 million
single occurrence deductible.
We entered into an agreement effective in October 2005 covering
approximately 33,000 acres in West Texas, pursuant to
which, upon closing, we acquired an approximate 35% working
interest in approximately 200 existing producing wells effective
November 1, 2005, and committed to drill an additional
150 wells within a four year period, funding
$36.5 million of our partners share of drilling costs
for such 150-well
drilling program. We will obtain an assignment of an approximate
35% working interest in the entire committed acreage upon
completion of the
150-well program.
4
The Offering
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Common stock offered by selling stockholders |
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33,348,130 shares. |
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Use of proceeds |
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We will not receive any proceeds from the sale of the shares of
common stock by the selling stockholders. |
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Listing |
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Our common stock has been approved for listing on the New York
Stock Exchange, subject to the completion of our proposed merger
with Forest Energy Resources, Inc. |
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Common stock split |
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Unless specifically indicated or the context requires otherwise,
the share and per share information of this offering gives
effect to a 21,556.61594 to 1 stock split, which was
effected on March 3, 2005. |
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Dividend Policy |
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We do not expect to pay dividends in the near future. |
Risk Factors
You should carefully consider all of the information contained
in this prospectus prior to investing in the common stock. In
particular, we urge you to carefully consider the information
under Risk Factors, beginning on page 24 of
this prospectus so that you understand the risks associated with
an investment in our company and the common stock. These risks
include the following:
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Oil and natural gas prices are volatile, and a decline in oil
and natural gas prices would affect significantly our financial
results and impede our growth. |
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Reserve estimates depend on many assumptions that may turn out
to be inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions will affect materially the
quantities and present value of our reserves. |
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Unless we replace our oil and natural gas reserves, our reserves
and production will decline. |
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Relatively short production periods or reserve life for Gulf of
Mexico properties subject us to higher reserve replacement needs
and may impair our ability to replace production during periods
of low oil and natural gas prices. |
Corporate Information
We were incorporated in August 1983 as a Delaware corporation.
We have three subsidiaries, Mariner LP LLC, a Delaware limited
liability company, Mariner Energy Texas LP, a Delaware limited
partnership, and MEI Sub, Inc., a Delaware corporation.
On March 2, 2004, Mariner was acquired by MEI Acquisitions
Holdings, LLC, an affiliate of the private equity funds,
Carlyle/ Riverstone Global Energy and Power Fund II, L.P.
and ACON Investments LLC, through a merger of Mariners
former indirect parent with MEI. Prior to the merger, we were
owned indirectly by Joint Energy Development Investments Limited
Partnership (JEDI), which was an indirect wholly
owned subsidiary of Enron Corp. As a result of the merger, we
are no longer affiliated with Enron Corp. See
Business Enron Related Matters.
In March 2005, we completed a private placement of
16,350,000 shares of our common stock to qualified
institutional buyers,
non-U.S. persons
and accredited investors. Our former sole stockholder, MEI
Acquisitions Holdings, LLC, also sold 15,102,500 shares of
our common stock in the private placement. We used the net
proceeds from the sale of 12,750,000 shares of our common
stock to purchase and retire an equal number of shares of our
common stock from our former sole stockholder. As a result,
after the private placement an affiliate of our former sole
stockholder beneficially owned 5.3% of our outstanding common
stock. See Security Ownership of Certain Beneficial Owners
and Management.
Our principal executive office is located at One Briar Lake
Plaza, Suite 2000, 2000 West Sam Houston Parkway
South, Houston, Texas 77042. Our telephone number is
(713) 954-5500.
5
Proposed Merger with Forest Energy Resources, Inc.
On September 9, 2005, we entered into a merger agreement
with Forest Oil Corporation (which we refer to as Forest),
Forest Energy Resources, Inc. (which we refer to as Forest
Energy Resources), and MEI Sub, Inc. The consummation of the
transactions contemplated by the merger agreement is subject to
several conditions, including the adoption of the merger
agreement by our stockholders. Accordingly, we cannot assure you
that the merger and related transactions will ever be
consummated. Our annual stockholder meeting, at which Mariner
stockholders will vote to adopt the merger agreement, is
scheduled to occur on March 2, 2006.
The following provides a summary of the material terms of the
transactions contemplated by the merger agreement.
Overview of the Proposed Transactions
Forest has transferred and contributed the assets and certain
liabilities associated with its offshore Gulf of Mexico
operations to Forest Energy Resources, a newly formed subsidiary
of Forest. Immediately prior to the merger, Forest will
distribute all of the outstanding shares of Forest Energy
Resources to Forest shareholders on a pro rata basis. Forest
Energy Resources will then merge with a newly formed subsidiary
of Mariner, and become a new wholly owned subsidiary of Mariner.
When the merger is complete, approximately 58% of the Mariner
common stock will be held by shareholders of Forest and
approximately 42% of Mariner common stock will be held by the
pre-merger stockholders of Mariner, each on a pro forma basis.
Following the merger, Mariner will:
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be an independent public company; |
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own both the Mariner operations and the Forest Gulf of Mexico
operations; and |
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have total assets of approximately $2.1 billion and total
debt of approximately $279.0 million on a pro forma
combined basis, assuming the spin-off and the merger occurred on
September 30, 2005. |
About Forest and Forest Energy Resources
Forest is an independent oil and gas company engaged in the
acquisition, exploration, development and production of natural
gas and liquids in North America and selected international
locations. Forest was incorporated in New York in 1924, as the
successor to a company formed in 1916, and has been a publicly
held company since 1969. Forest operates from offices located in
Denver, Colorado; Lafayette and Metairie, Louisiana; Anchorage,
Alaska; and Calgary, Alberta, Canada.
Forest Energy Resources is a wholly owned subsidiary of Forest.
Forest Energy Resources was formed in Delaware on
August 18, 2005 for the purpose of completing the spin-off
of the Forest Gulf of Mexico operations. As of December 31,
2004, the Forest Gulf of Mexico operations that have been
contributed to Forest Energy Resources had 339.7 Bcfe of
estimated proved reserves, of which approximately 79% were
natural gas and 21% were oil and condensate. As of
December 31, 2004, the PV10 of the Forest Gulf of Mexico
operations was approximately $1,222.2 million, and the
standardized measure of discounted future net cash flows
attributable to its estimated proved reserves was approximately
$925.8 million. Please see The Forest Gulf of Mexico
Operations Estimated Proved Reserves for a
reconciliation of PV10 to the standardized measure of discounted
future net cash flows. As of December 31, 2004,
approximately 76% of the Forest Gulf of Mexico operations
estimated proved reserves were classified as proved developed.
For the year ended December 31, 2004, the Forest Gulf of
Mexico operations total net production was 81.1 Bcfe.
In the three-year period ended December 31, 2004, the
Forest Gulf of Mexico operations deployed approximately
$560 million of capital on acquisitions, exploration and
development while adding approximately 182 Bcfe of
estimated proved reserves and producing approximately
215 Bcfe.
6
Transaction Structure
The following diagrams and accompanying descriptions serve to
describe generally the transactions that will take place in
connection with the spin-off and merger. For more information,
please read The Spin-off and Merger.
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1. |
Current Corporate Ownership Structure |
Forest Energy Resources is a wholly owned subsidiary of Forest.
MEI Sub is a wholly owned subsidiary of Mariner.
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2. |
The Contribution and Spin-Off |
Forest has contributed the assets and certain liabilities
associated with its Gulf of Mexico operations to Forest Energy
Resources. Forest will, immediately prior to the merger,
distribute all of the shares of Forest Energy Resources to its
shareholders on a pro rata basis.
MEI Sub will merge with and into Forest Energy Resources, with
Forest Energy Resources surviving as a wholly owned subsidiary
of Mariner. Forest Energy Resources will be renamed Mariner
Energy Resources, Inc. In conjunction with the merger, shares of
Forest Energy Resources stock will automatically be converted
into shares of Mariner stock.
7
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4. |
Corporate Ownership Structure following the Spin-Off and
Merger |
At the conclusion of the merger, Forest shareholders will own
approximately 58% of Mariner and the stockholders of Mariner who
owned shares prior to the merger will own the remaining
approximately 42% of Mariner.
What Forest and Mariner Stockholders Will Receive
If the merger is completed, each Forest shareholder will
ultimately receive shares of Mariner common stock. As a result
of the spin-off, Forest shareholders will initially receive
shares of Forest Energy Resources, which will then be converted
in the merger into the right to receive shares of Mariner. After
the merger, Forest shareholders will be entitled to receive
approximately 0.8 shares of Mariner for each Forest share
that they own. Forest shareholders will not be required to pay
for the shares of Forest Energy Resources distributed in the
spin-off transaction or the shares of Mariner issued in the
merger.
Mariner stockholders will keep the shares of Mariner common
stock they currently own, but will not receive any additional
shares in the merger.
Proposal to Amend Mariners Certificate of
Incorporation
We are proposing to amend Mariners certificate of
incorporation to increase the number of authorized shares of
stock from 90 million to 200 million, subject to
completion of the merger. Mariners certificate of
incorporation currently does not authorize a sufficient number
of shares of common stock to complete the merger. Mariner
currently is authorized to issue 70 million shares of
Mariner common stock and 20 million shares of Mariner
preferred stock. As of February 1, 2006, approximately
35.6 million shares of Mariner common stock were issued and
outstanding. Under the terms of the merger agreement, Mariner
must issue approximately 50.6 million shares (representing
approximately 0.8 shares of Mariner common stock for each
share of Forest common stock) of common stock in the merger,
which would result in approximately 86 million shares of
Mariner common stock outstanding. Therefore, the number of
authorized shares of Mariner common stock must be increased in
order to complete the merger.
Recommendation of Mariners Board of Directors
The Mariner board of directors has determined that the merger is
fair to and in the best interests of Mariner and its
stockholders, and that the merger agreement is advisable. The
Mariner board of directors has unanimously approved the merger
agreement and the other proposals and recommends that the
Mariner stockholders vote for the adoption of the
merger agreement and the other proposals. A more detailed
description of the background and reasons for the merger is set
forth under The Spin-Off and Merger beginning on
page 95.
8
When considering the recommendations of the Mariner board of
directors, you should be aware that the directors and executive
officers of Mariner have interests and arrangements that may be
different from your interests as stockholders, including:
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arrangements regarding the appointment of directors and officers
of Mariner following the merger; and |
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arrangements whereby the executive officers of Mariner will
receive a cash payment of $1,000 each in exchange for the waiver
of certain rights under their employment agreements, including
the automatic vesting or acceleration of restricted stock and
options upon the completion of the merger and the right to
receive a lump sum cash payment if the officer voluntarily
terminates employment without good reason within nine months
following the completion of the merger. |
At the close of business on February 1, 2006, directors and
executive officers of Mariner and their affiliates as a group
beneficially owned and were entitled to vote approximately
3.7 million shares of Mariner common stock (including
restricted stock subject to vesting), representing approximately
10.4% of the shares of Mariner common stock outstanding on that
date. All of the directors and executive officers of Mariner who
are entitled to vote at the annual meeting of stockholders have
indicated that they intend to vote their shares of Mariner
common stock in favor of adoption of the merger agreement.
In reaching its decision on the merger, the Mariner board of
directors considered a number of factors, including the
following among others:
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the increased size of the combined company could reduce
volatility and allow it to participate in larger scale drilling
projects and acquisition opportunities; |
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the merger would be expected to increase Mariners
estimated proved reserves and undeveloped acreage; |
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the merger could generate increased visibility in the capital
markets and trading liquidity for the combined company; |
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the merger would increase the number of Mariners producing
fields, thereby reducing Mariners dependence on a
concentrated number of properties; |
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the merger would be consummated only if approved by the holders
of a majority of the Mariner common stock; and |
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the merger is structured as a tax-free reorganization for
U.S. federal income tax purposes and, accordingly, would
not be taxable either to Mariner or its stockholders. |
The Mariner board of directors also identified and considered
some risks and potential disadvantages associated with the
merger, including, among others, the following:
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the risk that there may be difficulties in combining the
business of Mariner and the Forest Gulf of Mexico operations; |
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the risk that the potential benefits sought in the merger might
not be fully realized; |
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the risk that the proved undeveloped, probable and possible
reserves of the Forest Gulf of Mexico operations may never be
converted to proved developed reserves; and |
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the fact that, in order to preserve the tax-free treatment of
the spin-off, Mariner would be required to abide by restrictions
that could reduce its ability to engage in certain business
transactions. |
In the judgment of the Mariner board of directors, the potential
benefits of the merger outweigh the risks and the potential
disadvantages.
9
Opinion of Mariners Financial Advisor
Lehman Brothers Inc., Mariners financial advisor, has
delivered to Mariners board of directors a written opinion
that, as of September 9, 2005, based upon and subject to
the factors and assumptions set forth in the opinion, the
exchange ratio in the merger was fair from a financial point of
view to Mariner.
Directors and Officers of Mariner Following the Merger
If the merger is completed, Mariners board will consist of
seven members, five of whom will be the current directors of
Mariner, and two of whom will be mutually agreed between Mariner
and Forest prior to the completion of the merger. The Chairman
of the Mariner board will be Mr. Scott D. Josey, the
current Chairman, Chief Executive Officer and President of
Mariner. The two Mariner directors to be mutually agreed by
Forest and Mariner pursuant to the terms of the merger agreement
have not yet been designated.
The current executive officers of Mariner will remain in their
current positions following the merger.
Material United States Federal Tax Consequences of the
Merger
It is a condition to the completion of the merger that Forest,
Forest Energy Resources and Mariner receive opinions from their
respective tax counsels to the effect that the merger will
constitute a tax-free reorganization for U.S. federal
income tax purposes. As a tax-free reorganization for
U.S. federal income tax purposes, the merger will be
tax-free to the stockholders of Mariner and tax-free to the
shareholders of Forest, except for cash received in lieu of
fractional shares of Mariner for shares of Forest Energy
Resources.
We encourage you to consult your own tax advisor for a full
understanding of the tax consequences of the merger to you.
Conditions to the Completion of the Merger
The merger will be completed only if certain conditions,
including the following, are satisfied (or waived in certain
cases):
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the adoption of the merger agreement by Mariner stockholders
holding a majority of the Mariner common stock and the approval
of the proposed amendment to Mariners certificate of
incorporation; |
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the absence of legal restrictions that would prevent the
completion of the transactions; |
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the receipt by Forest, Mariner and Forest Energy Resources of an
opinion from their respective counsel to the effect that the
merger will be treated as a reorganization for federal income
tax purposes; |
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the completion of the spin-off in accordance with the
distribution agreement; |
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the receipt of material consents, approvals and authorizations
of governmental authorities; |
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the expiration or termination of any applicable waiting period
under the Hart-Scott-Rodino Act; |
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the SEC declaring effective the registration statements of
Mariner relating to the shares of Mariner common stock to be
issued in the merger and those shares held by its existing
stockholders; |
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the representations and warranties contained in the merger
agreement being materially true and correct, and the performance
in all material respects by the parties of their covenants and
other agreements in the merger agreement; |
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the approval for listing on the New York Stock Exchange or
Nasdaq of Mariners common stock; and |
10
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Mariner and Forest receiving the consents required pursuant to
their credit facilities (with Mariner or Forest Energy Resources
having entered into a new or amended credit facility sufficient
to operate the combined businesses), and Forest receiving any
consents required from its bondholders. |
On November 14, 2005, the waiting period under the
Hart-Scott-Rodino Act with respect to the merger expired. On
October 19, 2005, Forest received the consent required
pursuant to its credit facility. On February 7, 2006,
Mariners common stock was approved for listing on the New
York Stock Exchange upon the completion of the merger. As of
February 7, 2006, no other conditions to closing have been
satisfied. Mariner is currently negotiating the definitive
documents for its new credit facility, which documents also will
grant the consent required pursuant to its existing facility.
Mariner and Forest are actively working to obtain necessary
consents, approvals and authorizations from governmental
authorities, including the Minerals Management Service.
Based on its current valuation of the Forest Gulf of Mexico
operations and the current amount of distributions permitted by
the covenants contained in the indentures governing
Forests outstanding bonds, Forest believes that no
consents of its bondholders will be required for the spin-off
and the merger. If Forests belief that bondholder consents
are not necessary remains unchanged as the merger closing
approaches, it intends to waive conditions in the merger
agreement and distribution agreement related to such consents.
Neither Mariner nor Forest currently believes that any other
condition to closing is likely to be waived.
Pursuant to the terms of the merger agreement, the closing of
the merger will occur as promptly as practicable, and in no
event later than the second business day following the
satisfaction or, if permissible, waiver of the conditions to
closing set forth in the merger agreement, or at such other time
as Mariner and Forest Energy Resources mutually agree. Unless
Mariner consents otherwise, the closing will not occur earlier
than the fifth business day following the record date for the
spin-off.
Termination of the Merger Agreement
Forest and Mariner may mutually agree to terminate the merger
agreement without completing the merger. In addition, either
party may terminate the merger agreement if:
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the other party breaches its representations, warranties,
covenants or agreements under the merger agreement so as to
create a material adverse effect, and the breach has not been
cured within 30 days after notice was given of such breach; |
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the parties do not complete the merger by March 31, 2006; |
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a governmental order prohibits the merger; or |
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Mariner does not receive the required approval of its
stockholders. |
In addition, Mariner may terminate the merger agreement if it
receives a proposal to acquire Mariner that Mariners board
of directors determines in good faith to be more favorable to
Mariners stockholders than the merger. Forest may
terminate the merger agreement if Mariners board of
directors withdraws or modifies its approval of the merger to
Mariners stockholders.
Termination Fee and Expenses
Mariner must pay Forest a termination fee of $25 million
and out-of-pocket fees
and expenses of up to $5 million if Mariner terminates the
merger agreement to accept an alternative proposal that
Mariners board of directors determines in good faith to be
more favorable to Mariners stockholders than the merger.
In addition, Mariner must pay Forest a termination fee of
$25 million and reimbursement of
11
out-of-pocket fees and
expenses of up to $5 million if the merger agreement is
terminated for the other reasons set forth under The
Merger Agreement Termination Fees and Expenses on
page 130.
Financing Arrangements Relating to the Spin-Off and the
Merger
At the closing of the merger Mariner and Mariner Energy
Resources expect to enter into a new $500 million senior
secured revolving credit facility, and Mariner will enter into
an additional $40 million senior secured letter of credit
facility. The revolving credit facility will mature on the
fourth anniversary of the closing, and the letter of credit
facility will mature on the third anniversary of the closing.
The outstanding principal balance of loans under the revolving
credit facility may not exceed the borrowing base, which will be
initially set at $400 million. In addition, Forest Energy
Resources expects to enter into a new senior term loan facility
in connection with the spin-off, which facility is expected to
be repaid with borrowings under Mariners and Mariner
Energy Resources $500 million revolving credit
facility.
Ancillary Agreements
In addition to the merger agreement and the distribution
agreement, Forest, Forest Energy Resources and Mariner have
entered into a tax sharing agreement relating to the allocation
of certain tax liabilities. See Ancillary Agreements
Tax Sharing Agreement beginning on page 135. In
addition, Forest and Forest Energy Resources have entered into
an employee benefits agreement addressing certain benefits
matters for former Forest employees who become employees of
Forest Energy Resources in connection with the spin-off and the
merger. See Ancillary Agreements Employee Benefits
Agreement beginning on page 136. Finally, Forest and
Forest Energy Resources have entered into a transition services
agreement under which Forest will provide certain services to
Forest Energy Resources for a limited period of time following
the merger. See Ancillary Agreements Transition
Services Agreement beginning on page 137.
Regulatory Matters
None of the parties is aware of any other material governmental
or regulatory approval required for the completion of the
merger, other than the effectiveness of the registration
statement of which this prospectus is a part and the
effectiveness of Mariners registration statement on
Form S-4 relating
to the shares of Mariner common stock to be issued to Forest
shareholders in the merger, and compliance with applicable
antitrust law (including the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended) and the
corporate law of the State of Delaware. On November 14,
2005, the waiting period under the Hart-Scott-Rodino Act with
respect to the merger expired.
Mariner Stockholder Vote
Our annual stockholder meeting, at which Mariner stockholders
will vote to adopt the merger agreement, is scheduled to occur
on Thursday, March 2, 2006. For the merger to occur, the
holders of a majority of the outstanding Mariner common stock
must adopt the merger agreement and approve the amendment to the
certificate of incorporation. Mariner stockholders will have one
vote for each share of Mariner common stock they own. On
February 1, 2006, the record date for Mariners annual
meeting, 35,615,400 shares of Mariner common stock were
issued and outstanding and entitled to vote at the meeting. The
approval of Forest shareholders is not required for the spin-off
or the merger.
Closing of the Transactions
If the merger agreement and the proposed amendment to the
certificate of incorporation are adopted and approved by the
stockholders of Mariner, then Mariner, Forest, Forest Energy
Resources and MEI Sub expect to complete the spin-off and the
merger as soon as possible after the satisfaction (or waiver,
where permissible) of the other conditions to the spin-off and
the merger. We currently anticipate that the merger will be
completed during the first calendar quarter of 2006.
12
SUMMARY SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA
Sources of Information
The following is summary selected consolidated financial data of
Mariner and selected consolidated financial data of the Forest
Gulf of Mexico operations. We derived this information from the
audited and unaudited financial statements for Mariner and from
the audited and unaudited statements of revenues and direct
operating expenses of the Forest Gulf of Mexico operations for
the periods presented. You should read this information in
conjunction with the financial information included elsewhere in
this prospectus. See Index to Financial Statements
on page F-1 and
Unaudited Pro Forma Combined Condensed Financial
Information beginning on page 44.
How We Prepared the Unaudited Pro Forma Combined Condensed
Financial Information
The unaudited pro forma combined condensed financial information
is presented to show you how Mariner might have looked if the
Forest Gulf of Mexico operations had been an independent company
and combined with Mariner for the periods presented. We prepared
the pro forma financial information using the purchase method of
accounting, with Mariner treated as the acquiror. See The
Spin-Off and Merger Accounting Treatment beginning
on page 117.
If the Forest Gulf of Mexico operations had been an independent
company, and if Mariner and the Forest Gulf of Mexico operations
had been combined in the past, they might have performed
differently. You should not rely on the pro forma financial
information as an indication of the financial position or
results of operations that Mariner would have reported if the
spin-off and merger had taken place earlier or of the future
results that Mariner will achieve after the merger. See
Unaudited Pro Forma Combined Condensed Financial
Information beginning on page 44.
13
Summary Historical Consolidated Financial Data of Mariner
The following table shows Mariners summary historical
consolidated financial data as of and for each of the four years
ended December 31, 2003, the period from January 1,
2004 through March 2, 2004, the period from March 3,
2004 through December 31, 2004, the period from
March 3, 2004 through September 30, 2004 and the
nine-month period ended September 30, 2005. The summary
historical consolidated financial data as of and for the four
years ended December 31, 2003, the period from
January 1, 2004 through March 2, 2004 and the period
from March 3, 2004 through December 31, 2004 are
derived from Mariners audited financial statements
included herein, and the summary historical consolidated
financial data for the period from March 3, 2004 through
September 30, 2004 and the nine-month period ended
September 30, 2005 are derived from unaudited financial
statements of Mariner. You should read the following data in
connection with Managements Discussion and Analysis
of Financial Condition and Results of Operations and the
consolidated financial statements included elsewhere in this
prospectus, where there is additional disclosure regarding the
information in the following table, including pro forma
information regarding the merger. Mariners historical
results are not necessarily indicative of results to be expected
in future periods.
On March 2, 2004, Mariners former indirect parent,
Mariner Energy LLC, merged with MEI Acquisitions, LLC, an
affiliate of the private equity funds, Carlyle/ Riverstone
Global Energy and Power Fund II, L.P. and ACON Investments
LLC. The financial information contained herein is presented in
the style of Pre-2004 Merger activity (for all periods prior to
March 2, 2004) and Post-2004 Merger activity (for the
March 3, 2004 through December 31, 2004 period and the
March 3, 2004 through September 30, 2004 period) to
reflect the impact of the restatement of assets and liabilities
to fair value as required by push-down purchase
accounting at the March 2, 2004 merger date.
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Post-2004 Merger | |
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Pre-2004 Merger | |
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Period from | |
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Period from | |
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Period from | |
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March 3, | |
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January 1, | |
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Nine Months | |
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March 3, | |
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2004 | |
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2004 | |
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Ended | |
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2004 through | |
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through | |
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through | |
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Year Ended December 31, | |
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September 30, | |
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September 30, | |
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December 31, | |
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March 2, | |
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2005 | |
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2004 | |
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2004 | |
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2004 | |
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2003 | |
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2002 | |
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2001 | |
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2000 | |
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(in millions, except per share data) | |
Statement of Operations Data:
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Total revenues(1)
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$ |
151.2 |
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$ |
122.5 |
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$ |
174.4 |
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$ |
39.8 |
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$ |
142.5 |
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$ |
158.2 |
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$ |
155.0 |
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$ |
121.1 |
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Lease operating expenses
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20.2 |
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15.1 |
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21.4 |
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4.1 |
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24.7 |
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26.1 |
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20.1 |
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17.2 |
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Transportation expenses
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1.7 |
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3.7 |
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1.9 |
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1.1 |
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6.3 |
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10.5 |
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12.0 |
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7.8 |
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Depreciation, depletion and amortization
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43.4 |
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37.4 |
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54.3 |
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10.6 |
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48.3 |
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70.8 |
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63.5 |
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56.8 |
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Impairment of production equipment held for use
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0.5 |
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1.0 |
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1.0 |
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Derivative settlement
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3.2 |
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Impairment of Enron related receivables
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3.2 |
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29.5 |
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General and administrative expenses
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|
|
26.7 |
|
|
|
6.2 |
|
|
|
7.6 |
|
|
|
|
1.1 |
|
|
|
8.1 |
|
|
|
7.7 |
|
|
|
9.3 |
|
|
|
6.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
58.7 |
|
|
|
59.1 |
|
|
|
88.2 |
|
|
|
|
22.9 |
|
|
|
51.9 |
|
|
|
39.9 |
|
|
|
20.6 |
|
|
|
32.8 |
|
|
Interest income
|
|
|
0.7 |
|
|
|
0.2 |
|
|
|
0.2 |
|
|
|
|
0.1 |
|
|
|
0.8 |
|
|
|
0.4 |
|
|
|
0.7 |
|
|
|
0.1 |
|
|
Interest expense
|
|
|
(5.4 |
) |
|
|
(4.4 |
) |
|
|
(6.0 |
) |
|
|
|
|
|
|
|
(7.0 |
) |
|
|
(10.3 |
) |
|
|
(8.9 |
) |
|
|
(11.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
54.0 |
|
|
|
54.9 |
|
|
|
82.4 |
|
|
|
|
23.0 |
|
|
|
45.7 |
|
|
|
30.0 |
|
|
|
12.4 |
|
|
|
21.9 |
|
|
Provision for income taxes
|
|
|
(18.4 |
) |
|
|
(19.2 |
) |
|
|
(28.8 |
) |
|
|
|
(8.1 |
) |
|
|
(9.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting method
net of tax effects
|
|
|
35.6 |
|
|
|
35.7 |
|
|
|
53.6 |
|
|
|
|
14.9 |
|
|
|
36.3 |
|
|
|
30.0 |
|
|
|
12.4 |
|
|
|
21.9 |
|
|
Income before cumulative effect per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
1.10 |
|
|
|
1.20 |
|
|
|
1.80 |
|
|
|
|
.50 |
|
|
|
1.22 |
|
|
|
1.01 |
|
|
|
.42 |
|
|
|
.74 |
|
|
|
Diluted
|
|
|
1.07 |
|
|
|
1.20 |
|
|
|
1.80 |
|
|
|
|
.50 |
|
|
|
1.22 |
|
|
|
1.01 |
|
|
|
.42 |
|
|
|
.74 |
|
|
Cumulative effect of changes in accounting method
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
35.6 |
|
|
$ |
35.7 |
|
|
$ |
53.6 |
|
|
|
$ |
14.9 |
|
|
$ |
38.2 |
|
|
$ |
30.0 |
|
|
$ |
12.4 |
|
|
$ |
21.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
1.10 |
|
|
|
1.20 |
|
|
|
1.80 |
|
|
|
|
.50 |
|
|
|
1.29 |
|
|
|
1.01 |
|
|
|
.42 |
|
|
|
.74 |
|
|
|
Diluted
|
|
|
1.07 |
|
|
|
1.20 |
|
|
|
1.80 |
|
|
|
|
.50 |
|
|
|
1.29 |
|
|
|
1.01 |
|
|
|
.42 |
|
|
|
.74 |
|
Capital Expenditure and Disposal Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, including leasehold/seismic
|
|
$ |
23.6 |
|
|
$ |
35.7 |
|
|
$ |
40.4 |
|
|
|
$ |
7.5 |
|
|
$ |
31.6 |
|
|
$ |
40.4 |
|
|
$ |
66.3 |
|
|
$ |
46.7 |
|
|
Development and other
|
|
|
106.8 |
|
|
|
50.2 |
|
|
|
93.2 |
|
|
|
|
7.8 |
|
|
|
51.7 |
|
|
|
65.7 |
|
|
|
98.2 |
|
|
|
61.4 |
|
|
Proceeds from property conveyances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(121.6 |
) |
|
|
(52.3 |
) |
|
|
(90.5 |
) |
|
|
(29.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures net of proceeds from property
conveyances
|
|
$ |
130.4 |
|
|
$ |
85.9 |
|
|
$ |
133.6 |
|
|
|
$ |
15.3 |
|
|
$ |
(38.3 |
) |
|
$ |
53.8 |
|
|
$ |
74.0 |
|
|
$ |
79.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes effects of hedging.
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger | |
|
|
Pre-2004 Merger | |
|
|
| |
|
|
| |
|
|
|
|
|
December 31, | |
|
|
September 30, | |
|
December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
2003 | |
|
2002 | |
|
2001 | |
|
2000 | |
|
|
| |
|
| |
|
|
| |
|
| |
|
| |
|
| |
|
|
(in millions) | |
Balance Sheet Data:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net, full cost method
|
|
$ |
393.3 |
|
|
$ |
303.8 |
|
|
|
$ |
207.9 |
|
|
$ |
287.6 |
|
|
$ |
290.6 |
|
|
$ |
287.8 |
|
|
Total assets
|
|
|
502.2 |
|
|
|
376.0 |
|
|
|
|
312.1 |
|
|
|
360.2 |
|
|
|
363.9 |
|
|
|
335.4 |
|
|
Long-term debt, less current maturities
|
|
|
79.0 |
|
|
|
115.0 |
|
|
|
|
|
|
|
|
99.8 |
|
|
|
99.8 |
|
|
|
129.7 |
|
|
Stockholders equity
|
|
|
178.6 |
|
|
|
133.9 |
|
|
|
|
218.2 |
|
|
|
170.1 |
|
|
|
180.1 |
|
|
|
141.9 |
|
|
Working capital (deficit)(2)
|
|
|
(30.2 |
) |
|
|
(18.7 |
) |
|
|
|
38.3 |
|
|
|
(24.4 |
) |
|
|
(19.6 |
) |
|
|
(15.4 |
) |
|
|
(1) |
Balance sheet data as of December 31, 2004 reflects
purchase accounting adjustments to oil and gas properties, total
assets and stockholders equity resulting from the
acquisition of our former indirect parent on March 2, 2004. |
|
(2) |
Working capital (deficit) excludes current derivative assets and
liabilities, deferred tax assets and restricted cash. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger | |
|
|
Pre-2004 Merger | |
|
|
| |
|
|
| |
|
|
|
|
Period from | |
|
|
Period from | |
|
|
|
|
|
|
Period from | |
|
March 3, | |
|
|
January 1, | |
|
|
|
|
Nine Months | |
|
March 3, | |
|
2004 | |
|
|
2004 | |
|
|
|
|
Ended | |
|
2004 through | |
|
through | |
|
|
through | |
|
Year Ended December 31, | |
|
|
September 30, | |
|
September 30, | |
|
December 31, | |
|
|
March 2, | |
|
| |
|
|
2005 | |
|
2004 | |
|
2004 | |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
2001 | |
|
2000 | |
|
|
| |
|
| |
|
| |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(in millions) | |
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$ |
102.7 |
|
|
$ |
97.5 |
|
|
$ |
143.5 |
|
|
|
$ |
33.4 |
|
|
$ |
100.3 |
|
|
$ |
113.9 |
|
|
$ |
113.6 |
|
|
$ |
89.6 |
|
Net cash provided by operating activities
|
|
|
135.4 |
|
|
|
96.8 |
|
|
|
135.9 |
|
|
|
|
20.3 |
|
|
|
103.5 |
|
|
|
60.3 |
|
|
|
113.5 |
|
|
|
63.9 |
|
Net cash (used) provided by investing activities
|
|
|
(142.1 |
) |
|
|
(85.9 |
) |
|
|
(133.6 |
) |
|
|
|
(15.3 |
) |
|
|
38.3 |
|
|
|
(53.8 |
) |
|
|
(74.0 |
) |
|
|
(79.1 |
) |
Net cash (used) provided by financing activities
|
|
|
8.7 |
|
|
|
(74.9 |
) |
|
|
64.9 |
|
|
|
|
|
|
|
|
(100.0 |
) |
|
|
|
|
|
|
(30.0 |
) |
|
|
17.4 |
|
Reconciliation of Non-GAAP Measures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$ |
102.7 |
|
|
$ |
97.5 |
|
|
$ |
143.5 |
|
|
|
$ |
33.4 |
|
|
$ |
100.3 |
|
|
$ |
113.9 |
|
|
$ |
113.6 |
|
|
$ |
89.6 |
|
Changes in working capital
|
|
|
25.1 |
|
|
|
9.7 |
|
|
|
6.9 |
|
|
|
|
(13.2 |
) |
|
|
21.8 |
|
|
|
(20.4 |
) |
|
|
7.5 |
|
|
|
(15.5 |
) |
Non-cash hedge gain(2)
|
|
|
(3.6 |
) |
|
|
(5.1 |
) |
|
|
(7.9 |
) |
|
|
|
|
|
|
|
(2.0 |
) |
|
|
(23.2 |
) |
|
|
|
|
|
|
|
|
Amortization/other
|
|
|
0.9 |
|
|
|
0.5 |
|
|
|
0.8 |
|
|
|
|
|
|
|
|
|
|
|
|
(0.1 |
) |
|
|
0.6 |
|
|
|
0.7 |
|
Stock compensation expense
|
|
|
17.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense
|
|
|
(4.7 |
) |
|
|
(4.2 |
) |
|
|
(5.8 |
) |
|
|
|
0.1 |
|
|
|
(6.2 |
) |
|
|
(9.9 |
) |
|
|
(8.2 |
) |
|
|
(10.9 |
) |
Income tax expense
|
|
|
(2.6 |
) |
|
|
(1.6 |
) |
|
|
(1.6 |
) |
|
|
|
|
|
|
|
(10.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$ |
135.4 |
|
|
$ |
96.8 |
|
|
$ |
135.9 |
|
|
|
$ |
20.3 |
|
|
$ |
103.5 |
|
|
$ |
60.3 |
|
|
$ |
113.5 |
|
|
$ |
63.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
EBITDA means earnings before interest, income taxes,
depreciation, depletion and amortization. For the nine months
ended September 30, 2005, EBITDA includes
$17.6 million in non-cash stock compensation expense
related to restricted stock and stock options granted in 2005.
We believe that EBITDA is a widely accepted financial indicator
that provides additional information about our ability to meet
our future requirements for debt service, capital expenditures
and working capital, but EBITDA should not be considered in
isolation or as a substitute for net income, operating income,
net cash provided by operating activities or any other measure
of financial performance presented in |
15
|
|
|
accordance with generally accepted accounting principles or as a
measure of a companys profitability or liquidity. |
|
(2) |
In accordance with SFAS No. 133 Accounting for
Derivative Instruments and Hedging Activities, as amended
by SFAS No. 137 and No. 138, we de-designated our
contracts effective December 2, 2001 after the counterparty
(an affiliate of Enron Corp.) filed for bankruptcy and
recognized all market value changes subsequent to such
de-designation in our earnings. The value recorded up to the
time of de-designation and included in Accumulated Other
Comprehensive Income (AOCI), has reversed out of
AOCI and into earnings as the original corresponding production,
as hedged by the contracts, is produced. We have designated
subsequent hedge contracts as cash flow hedges with gains and
losses resulting from the transactions recorded at market value
in AOCI, as appropriate, until recognized as operating income in
our Statement of Operations as the physical production hedged by
the contracts is delivered. |
16
Summary Selected Consolidated Statements of Revenues and
Direct Operating Expenses of the Forest Gulf of Mexico
Operations
The summary selected financial data for the Forest Gulf of
Mexico operations for the nine months ended September 30,
2005 and 2004 and the years ended December 31, 2004, 2003
and 2002 were derived from the historical records of Forest. You
should read the following data in connection with
Managements Discussion and Analysis of Financial
Condition and Results of Operations of the Forest Gulf of Mexico
Operations and the consolidated statements of revenues and
direct operating expenses of the Forest Gulf of Mexico
operations included elsewhere in this prospectus. Complete
financial and operating information related to the Forest Gulf
of Mexico operations, including balance sheet and cash flow
information, are not presented below because the Forest Gulf of
Mexico operations were not maintained as a separate business
unit, and therefore the assets, liabilities or indirect
operating costs applicable to the operations were not segregated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended | |
|
Years Ended | |
|
|
September 30, | |
|
December 31 | |
|
|
| |
|
| |
|
|
2005 | |
|
2004 | |
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(in millions, except production data) | |
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues(1)
|
|
$ |
326.7 |
|
|
$ |
324.4 |
|
|
$ |
453.1 |
|
|
$ |
342.0 |
|
|
$ |
228.9 |
|
|
Direct Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
57.4 |
|
|
|
63.0 |
|
|
|
80.1 |
|
|
|
45.7 |
|
|
|
52.1 |
|
|
|
Transportation
|
|
|
2.5 |
|
|
|
1.4 |
|
|
|
2.2 |
|
|
|
2.7 |
|
|
|
3.8 |
|
|
|
Production taxes
|
|
|
1.9 |
|
|
|
1.2 |
|
|
|
1.5 |
|
|
|
1.5 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total direct operating expenses
|
|
|
61.8 |
|
|
|
65.6 |
|
|
|
83.8 |
|
|
|
49.9 |
|
|
|
56.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues in excess of direct operating expenses
|
|
$ |
264.9 |
|
|
$ |
258.8 |
|
|
$ |
369.3 |
|
|
$ |
292.1 |
|
|
$ |
172.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
41,442 |
|
|
|
46,036 |
|
|
|
61,684 |
|
|
|
58,785 |
|
|
|
50,566 |
|
|
Oil and condensate (MBbls)
|
|
|
1,845 |
|
|
|
2,004 |
|
|
|
2,624 |
|
|
|
2,143 |
|
|
|
1,974 |
|
|
Natural gas liquids (MBbls)
|
|
|
628 |
|
|
|
186 |
|
|
|
606 |
|
|
|
2 |
|
|
|
6 |
|
|
Total (MMcfe)
|
|
|
56,280 |
|
|
|
59,176 |
|
|
|
81,064 |
|
|
|
71,655 |
|
|
|
62,446 |
|
|
Per day (MMcfe)
|
|
|
206 |
|
|
|
216 |
|
|
|
221 |
|
|
|
196 |
|
|
|
171 |
|
Average realized sales price per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price received
|
|
$ |
7.14 |
|
|
$ |
6.02 |
|
|
$ |
6.30 |
|
|
$ |
5.41 |
|
|
$ |
3.39 |
|
|
|
Effects of hedging
|
|
|
(1.13 |
) |
|
|
(0.45 |
) |
|
|
(0.56 |
) |
|
|
(0.63 |
) |
|
|
0.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales price received
|
|
|
6.01 |
|
|
|
5.57 |
|
|
|
5.74 |
|
|
|
4.78 |
|
|
|
3.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended | |
|
Years Ended | |
|
|
September 30, | |
|
December 31 | |
|
|
| |
|
| |
|
|
2005 | |
|
2004 | |
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(in millions, except production data) | |
|
Oil ($/bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price received
|
|
$ |
51.97 |
|
|
$ |
38.13 |
|
|
$ |
40.06 |
|
|
$ |
30.19 |
|
|
$ |
24.85 |
|
|
|
Effects of hedging
|
|
|
(19.95 |
) |
|
|
(6.61 |
) |
|
|
(8.55 |
) |
|
|
(1.90 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales price received
|
|
|
32.02 |
|
|
|
31.52 |
|
|
|
31.51 |
|
|
|
28.29 |
|
|
|
24.85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas liquids ($/bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price received
|
|
$ |
29.54 |
|
|
$ |
25.40 |
|
|
$ |
27.28 |
|
|
$ |
19.00 |
|
|
$ |
12.33 |
|
Average realized sales price per Mcfe (including effects of
hedging) ($/Mcfe)
|
|
$ |
5.81 |
|
|
$ |
5.48 |
|
|
$ |
5.59 |
|
|
$ |
4.77 |
|
|
$ |
3.67 |
|
|
Production costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$ |
1.02 |
|
|
|
1.06 |
|
|
|
0.99 |
|
|
|
0.64 |
|
|
|
0.83 |
|
|
Transportation
|
|
$ |
0.04 |
|
|
|
0.02 |
|
|
|
0.03 |
|
|
|
0.04 |
|
|
|
0.06 |
|
|
Production taxes
|
|
$ |
0.03 |
|
|
|
0.02 |
|
|
|
0.02 |
|
|
|
0.02 |
|
|
|
0.02 |
|
|
|
(1) |
Includes effects of hedging. |
18
Summary Selected Unaudited Pro Forma Combined Condensed
Financial Information
The following summary selected unaudited pro forma combined
condensed financial information has been prepared to reflect the
proposed merger. This unaudited pro forma combined condensed
financial information is based on the historical financial
statements of Mariner and the historical statements of revenues
and direct operating expenses of the Forest Gulf of Mexico
operations, all of which are included in this prospectus, and
the estimates and assumptions set forth in the Notes to the
Unaudited Pro Forma Combined Condensed Financial Information
beginning on page 44. The unaudited pro forma combined
condensed operating results give effect to the merger as if it
had occurred on January 1, 2004. The unaudited pro forma
combined condensed balance sheet gives effect to the merger as
if it had occurred on September 30, 2005.
The unaudited pro forma combined condensed financial information
is for illustrative purposes only. The financial results may
have been different had the Forest Gulf of Mexico operations
been an independent company and had the companies always been
combined. You should not rely on the unaudited pro forma
combined condensed financial information as being indicative of
the historical results that would have been achieved had the
merger occurred in the past or the future financial results that
Mariner will achieve after the merger.
The merger will be accounted for using the purchase method of
accounting, with Mariner treated as the acquiror. In addition,
the purchase price allocation is preliminary and will be
finalized following the closing of the merger. The final
purchase price allocation will be determined after closing based
on the actual fair value of current assets, current liabilities,
indebtedness, long-term liabilities, proven and unproven oil and
gas properties, identifiable intangible assets and unvested
stock options that are outstanding at closing. We are continuing
to evaluate all of these items; accordingly, the final purchase
price may differ in material respects from that presented in the
unaudited pro forma combined condensed balance sheet.
|
|
|
|
|
|
|
|
|
|
|
|
As of and for the | |
|
|
|
|
Nine Months Ended | |
|
For the Year Ended | |
|
|
September 30, 2005 | |
|
December 31, 2004 | |
|
|
| |
|
| |
|
|
(in thousands, except per share | |
|
|
and proved reserve data) | |
OPERATING RESULTS:
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
477,967 |
|
|
$ |
667,326 |
|
|
Net income
|
|
$ |
71,221 |
|
|
$ |
106,298 |
|
Earnings per share
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.86 |
|
|
$ |
1.32 |
|
|
Diluted
|
|
$ |
0.85 |
|
|
$ |
1.32 |
|
Weighted average shares outstanding
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
83,075 |
|
|
|
80,385 |
|
|
Diluted
|
|
|
83,950 |
|
|
|
80,385 |
|
BALANCE SHEET DATA:
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
2,118,526 |
|
|
|
|
|
|
Total debt
|
|
$ |
279,000 |
|
|
|
|
|
|
Stockholders equity
|
|
$ |
1,152,134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, | |
|
As of December 31, | |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
ESTIMATED PROVED RESERVES:
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)*
|
|
|
29,261 |
|
|
|
25,905 |
|
|
Gas (MMcf)
|
|
|
423,352 |
|
|
|
421,741 |
|
|
Equivalent (MMcfe)
|
|
|
598,918 |
|
|
|
577,173 |
|
|
Proved developed percentage
|
|
|
63.9 |
% |
|
|
63.7 |
% |
|
|
* |
Includes 3,285.6 MBbls of natural gas liquids. |
19
Comparative Per Share Data
The following table presents historical per share data of
Mariner common stock and combined per share data of Mariner and
the Forest Gulf of Mexico operations on an unaudited pro forma
basis after giving effect to the spin-off and the merger. The
merger will be accounted for using the purchase method of
accounting, with Mariner treated as the acquiror. The combined
pro forma per share data was derived from the Unaudited Pro
Forma Combined Condensed Financial Information as presented
beginning on page 44. The assumptions related to the
preparation of the Unaudited Pro Forma Combined Condensed
Financial Information are described beginning at page 44.
The data presented below should be read in conjunction with the
historical consolidated financial statements of Mariner and the
historical statements of revenues and direct operating expenses
of the Forest Gulf of Mexico operations included elsewhere in
this prospectus.
The Mariner unaudited pro forma equivalent data was calculated
with reference to the total number of shares of Mariner common
stock expected to be outstanding after the merger, including the
shares to be issued to Forest shareholders and the
currently-outstanding shares of Mariner common stock.
The pro forma combined per share data may not be indicative of
the operating results or financial position that would have
occurred if the merger had been consummated at the beginning of
the periods indicated, and may not be indicative of future
operating results or financial position.
|
|
|
|
|
|
|
|
|
|
|
|
|
Mariner | |
|
|
| |
|
|
|
|
Combined | |
|
|
Historical | |
|
Pro Forma | |
|
|
| |
|
| |
Earnings per share
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2005(1)
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
1.10 |
|
|
$ |
0.86 |
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$ |
1.07 |
|
|
$ |
0.85 |
|
|
|
|
|
|
|
|
|
Year ended December 31, 2004(2)
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
2.30 |
|
|
$ |
1.32 |
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$ |
2.30 |
|
|
$ |
1.32 |
|
|
|
|
|
|
|
|
Book Value per shareAs of September 30, 2005(3)
|
|
$ |
5.01 |
|
|
$ |
13.36 |
|
|
|
|
|
|
|
|
Cash dividends declared per common share
|
|
$ |
|
|
|
$ |
|
|
|
|
(1) |
Mariners historical basic and diluted earnings per share
calculation for the nine months ended September 30, 2005
assumes Mariner had 32,438,240 and 33,312,831 weighted
average shares of common stock outstanding, respectively.
Mariners pro forma basic and diluted earnings per share
calculation for the nine months ended September 30, 2005
assumes Mariner had 83,075,250 and 83,949,841 weighted average
shares of common stock outstanding, respectively. |
|
(2) |
Mariners historical basic and diluted earnings per share
calculation for the year ended December 31, 2004 assumes
Mariner had 29,748,130 and 29,748,130 weighted average shares of
common stock outstanding, respectively. Mariners pro forma
basic and diluted earnings per share calculation for the year
ended December 31, 2004 assumes Mariner had 80,385,140 and
80,385,140 weighted average shares of common stock outstanding,
respectively. |
|
(3) |
Book value per share calculation assumes that Mariner had
35,615,400 shares of common stock outstanding and
86,252,410 combined pro forma shares of common stock outstanding
as of September 30, 2005. |
20
Summary Financial and Operational Data for the Year Ended
December 31, 2005
Set forth below is summary financial and operational data for
the year ended December 31, 2005 for Mariner and for the
Forest Gulf of Mexico operations. This information represents
the estimates of Mariners and Forests respective
management teams as of the date of this prospectus, but you
should be aware that this information has not been audited by
Mariners and Forests independent auditors. Neither
Mariners nor Forests independent auditors, nor any
other independent accountants, have compiled, examined or
performed any procedures with respect to the information set
forth below, nor have they expressed any opinion or any other
form of assurance on such information.
|
|
|
|
|
|
|
|
|
Year Ended | |
|
|
December 31, | |
|
|
2005 | |
|
|
| |
Statement of Operations Data:
|
|
|
|
|
|
Total revenues(1)
|
|
$ |
199.7 |
|
|
Direct operating expenses
|
|
|
32.2 |
|
|
|
|
|
|
Revenues in excess of direct operating expenses
|
|
$ |
167.5 |
|
|
|
|
|
Summary Production Data:
|
|
|
|
|
|
Production Data:
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
18,354 |
|
|
Oil (MBbls)
|
|
|
1,791 |
|
|
Total (MMcfe)
|
|
|
29,098 |
|
|
Per day (MMcfe)
|
|
|
80 |
|
Average realized sales price per unit:
|
|
|
|
|
|
Natural gas ($/Mcf):
|
|
|
|
|
|
|
Sales price received
|
|
$ |
8.33 |
|
|
|
Effects of hedging
|
|
|
(1.67 |
) |
|
|
|
|
|
|
Net sales price received
|
|
$ |
6.66 |
|
|
|
|
|
|
Oil ($/bbl):
|
|
|
|
|
|
|
Sales price received
|
|
$ |
51.66 |
|
|
|
Effects of hedging
|
|
|
(10.43 |
) |
|
|
|
|
|
|
Net sales price received
|
|
$ |
41.23 |
|
|
|
|
|
Average realized sales price per Mcfe (including effects of
hedging) ($/Mcfe)
|
|
$ |
6.74 |
|
|
|
|
|
|
|
Estimated Proved Reserves as of December 31, 2005:
|
|
|
|
|
|
Oil (MBbls)
|
|
|
21,647 |
|
|
Gas (MMcf)
|
|
|
207,686 |
|
|
Equivalent (MMcfe)
|
|
|
337,568 |
|
Estimated Daily Production Rate as of December 31, 2005:
75 MMcfe
|
|
|
|
|
|
|
(1) |
Includes effects of hedging. |
21
|
|
|
For the Forest Gulf of Mexico Operations: |
|
|
|
|
|
|
|
|
Year Ended | |
|
|
December 31, | |
|
|
2005 | |
|
|
| |
Summary Production Data:
|
|
|
|
|
|
Production Data:
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
49,120 |
|
|
Oil and condensate (MBbls)
|
|
|
2,070 |
|
|
Natural gas liquids (MBbls)
|
|
|
713 |
|
|
Total (MMcfe)
|
|
|
65,818 |
|
|
Per day (MMcfe)
|
|
|
180 |
|
|
Estimated Proved Reserves as of December 31, 2005:
|
|
|
|
|
|
Oil and condensate (MBbls)
|
|
|
9,271 |
|
|
Gas (MMcf)
|
|
|
231,142 |
|
|
Natural gas liquids (MBbls)
|
|
|
3,223 |
|
|
Equivalent (MMcfe)
|
|
|
306,105 |
|
|
Estimated Daily Production Rate as of December 31, 2005:
130 MMcfe
|
|
|
|
|
22
Comparative Stock Price and Dividends
In March 2005, Mariner completed a private placement of
16,350,000 shares of its common stock to qualified
institutional buyers,
non-U.S. persons
and accredited investors. There is no established public trading
market for the shares of Mariner common stock, and it is not
expected that a public trading market will be established until
the completion of the merger. The shares of Mariners
common stock issued to qualified institutional buyers in
connection with its March 2005 private equity placement are
eligible for the PORTAL
Market®.
Forest Energy Resources was incorporated as a wholly owned
subsidiary of Forest in August 2005. There is no established
public trading market for the shares of Forest Energy Resources
common stock.
Mariner has not paid any cash dividends on its shares of common
stock for the fiscal years 2003, 2004 or 2005, and it
anticipates that it will not pay any dividends in 2006. Forest
Energy Resources has not paid any cash dividends on its shares
of common stock for the fiscal year 2005, and it anticipates
that it will not pay any dividends in 2006. The payment of any
dividends by Mariner prior to the merger is subject to the
limitations included in the merger agreement and in its credit
facility, and following the merger the payment of dividends by
Mariner and Forest Energy Resources will be subject to
restrictions included in their credit facilities.
23
RISK FACTORS
You should consider carefully the following risk factors,
which we believe include all material risks associated with our
business, the merger, and the offering of our common stock,
together with all of the other information included in this
prospectus, before deciding to invest in our common stock.
Realization of any of the following risks could have a material
adverse effect on our business, financial condition, cash flows
and results of operations. In that case, the trading price of
our common stock could decline and you could lose all or part of
your investment.
Risks Related to our Business and to the Combined Operations
After the Merger
|
|
|
Oil and natural gas prices are volatile, and a decline in
oil and natural gas prices would reduce our revenues,
profitability and cash flow and impede our growth. |
Our revenues, profitability and cash flow depend substantially
upon the prices and demand for oil and natural gas. The markets
for these commodities are volatile and even relatively modest
drops in prices can affect significantly our financial results
and impede our growth. Oil and natural gas prices are currently
at or near historical highs and may fluctuate and decline
significantly in the near future. Prices for oil and natural gas
fluctuate in response to relatively minor changes in the supply
and demand for oil and natural gas, market uncertainty and a
variety of additional factors beyond our control, such as:
|
|
|
|
|
domestic and foreign supply of oil and natural gas; |
|
|
|
price and quantity of foreign imports; |
|
|
|
actions of the Organization of Petroleum Exporting Countries and
other state-controlled oil companies relating to oil price and
production controls; |
|
|
|
level of consumer product demand; |
|
|
|
domestic and foreign governmental regulations; |
|
|
|
political conditions in or affecting other oil-producing and
natural gas-producing countries, including the current conflicts
in the Middle East and conditions in South America and Russia; |
|
|
|
weather conditions; |
|
|
|
technological advances affecting oil and natural gas consumption; |
|
|
|
overall U.S. and global economic conditions; and |
|
|
|
price and availability of alternative fuels. |
Further, oil prices and natural gas prices do not necessarily
fluctuate in direct relationship to each other. Because
approximately 64% of our estimated proved reserves as of
December 31, 2004 (73% on a pro forma basis, including
reserves of the Forest Gulf of Mexico operations) were natural
gas reserves, our financial results are more sensitive to
movements in natural gas prices. Lower oil and natural gas
prices may not only decrease our revenues on a per unit basis
but also may reduce the amount of oil and natural gas that we
can produce economically. This may result in our having to make
substantial downward adjustments to our estimated proved
reserves and could have a material adverse effect on our
financial condition and results of operations.
|
|
|
Reserve estimates depend on many assumptions that may turn
out to be inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions will affect materially the
quantities and present value of our reserves and the reserves of
the Forest Gulf of Mexico operations, which may lower our bank
borrowing base and reduce our access to capital. |
Estimating oil and natural gas reserves is complex and
inherently imprecise. It requires interpretation of the
available technical data and making many assumptions about
future conditions, including price and other economic
conditions. In preparing estimates we and Forest project
production rates and timing of development expenditures. We and
Forest also analyze the available geological, geophysical,
production
24
and engineering data. The extent, quality and reliability of
this data can vary. This process also requires economic
assumptions about matters such as oil and natural gas prices,
drilling and operating expenses, capital expenditures, taxes and
availability of funds. Actual future production, oil and natural
gas prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable oil and natural gas
reserves most likely will vary from our and Forests
estimates, perhaps significantly. In addition, we may adjust
estimates of proved reserves to reflect production history,
results of exploration and development, prevailing oil and
natural gas prices and other factors, many of which are beyond
our control. At December 31, 2004, 54% of our proved
reserves (36% on a pro forma basis, including reserves of the
Forest Gulf of Mexico operations) were proved undeveloped.
If the interpretations or assumptions we use in arriving at our
estimates prove to be inaccurate, the amount of oil and natural
gas that we ultimately recover may differ materially from the
estimated quantities and net present value of reserves shown in
this prospectus. See BusinessEstimated Proved
Reserves for information about our oil and gas reserves
and The Forest Gulf of Mexico OperationsEstimated
Proved Reserves for more information about the oil and gas
reserves of the Forest Gulf of Mexico operations.
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In estimating future net revenues from proved reserves, we
and Forest assume that future prices and costs are fixed and
apply a fixed discount factor. If these assumptions or discount
factor are materially inaccurate, our revenues, profitability
and cash flow could be materially less than our
estimates. |
The present value of future net revenues from our proved
reserves and the proved reserves of the Forest Gulf of Mexico
operations referred to in this prospectus is not necessarily the
actual current market value of our estimated oil and natural gas
reserves. In accordance with SEC requirements, we and Forest
base the estimated discounted future net cash flows from our
proved reserves and the proved reserves of the Forest Gulf of
Mexico operations on fixed prices and costs as of the date of
the estimate. Actual future prices and costs fluctuate over time
and may differ materially from those used in the present value
estimate. In addition, discounted future net cash flows are
estimated assuming that royalties to the MMS with respect to our
affected offshore Gulf of Mexico properties will be paid or
suspended for the life of the properties based upon oil and
natural gas prices as of the date of the estimate. See
BusinessRoyalty Relief. Since actual future
prices fluctuate over time, royalties may be required to be paid
for various portions of the life of the properties and suspended
for other portions of the life of the properties.
The timing of both the production and expenses from the
development and production of oil and natural gas properties
will affect both the timing of actual future net cash flows from
our proved reserves and the proved reserves of the Forest Gulf
of Mexico operations and their present value. In addition, the
10% discount factor that we and Forest use to calculate the net
present value of future net cash flows for reporting purposes in
accordance with the SECs rules may not necessarily be the
most appropriate discount factor. The effective interest rate at
various times and the risks associated with our business or the
oil and gas industry in general will affect the appropriateness
of the 10% discount factor in arriving at an accurate net
present value of future net cash flows.
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Unless we replace our oil and natural gas reserves, our
reserves and production will decline. |
Our future oil and natural gas production depends on our success
in finding or acquiring additional reserves. If we fail to
replace reserves through drilling or acquisitions, our level of
production and cash flows will be affected adversely. In
general, production from oil and natural gas properties declines
as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Our total proved reserves decline as
reserves are produced unless we conduct other successful
exploration and development activities or acquire properties
containing proved reserves, or both. Our ability to make the
necessary capital investment to maintain or expand our asset
base of oil and natural gas reserves would be impaired to the
extent cash flow from operations is reduced and external sources
of capital become limited or unavailable. We may not be
successful in exploring for, developing or acquiring additional
reserves.
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Relatively short production periods or reserve life for
Gulf of Mexico properties subjects us to higher reserve
replacement needs and may impair our ability to replace
production during periods of low oil and natural gas
prices. |
Due to high production rates, production of reserves from
reservoirs in the Gulf of Mexico generally declines more rapidly
than from reservoirs in other producing regions. As a result,
our reserve replacement needs from new prospects may be greater
than those of other oil and gas companies. If the merger is
consummated, the proportion of short-lived Gulf of Mexico
properties relative to our total properties will increase
substantially. Also, our revenues and return on capital will
depend significantly on prices prevailing during these
relatively short production periods. Our ability to slow or shut
in production from producing wells during periods of low prices
for oil and natural gas may be limited by reservoir
characteristics or by our need to generate revenues to fund
ongoing capital commitments or repay debt.
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Any production problems related to our Gulf of Mexico
properties could reduce our revenue, profitability and cash flow
materially. |
A substantial portion of our exploration and production
activities are located in the Gulf of Mexico. This concentration
of activity makes us more vulnerable than some other industry
participants to the risks associated with the Gulf of Mexico,
including delays and increased costs relating to adverse weather
conditions such as hurricanes, which are common in the Gulf of
Mexico during certain times of the year, drilling rig and other
oilfield services and compliance with environmental and other
laws and regulations.
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Our exploration and development activities may not be
commercially successful. |
Exploration activities involve numerous risks, including the
risk that no commercially productive oil or natural gas
reservoirs will be discovered. In addition, the future cost and
timing of drilling, completing and producing wells is often
uncertain. Furthermore, drilling operations may be curtailed,
delayed or canceled as a result of a variety of factors,
including:
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unexpected drilling conditions; |
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pressure or irregularities in formations; |
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equipment failures or accidents; |
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adverse weather conditions, including hurricanes, which are
common in the Gulf of Mexico during certain times of the year; |
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compliance with governmental regulations; |
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unavailability or high cost of drilling rigs, equipment or labor; |
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reductions in oil and natural gas prices; and |
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limitations in the market for oil and natural gas. |
If any of these factors were to occur with respect to a
particular project, we could lose all or a part of our
investment in the project, or we could fail to realize the
expected benefits from the project, either of which could
materially and adversely affect our revenues and profitability.
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Our exploratory drilling projects are based in part on
seismic data, which is costly and cannot ensure the commercial
success of the project. |
Our decisions to purchase, explore, develop and exploit
prospects or properties depend in part on data obtained through
geophysical and geological analyses, production data and
engineering studies, the results of which are often uncertain.
Even when used and properly interpreted,
3-D seismic data and
visualization techniques only assist geoscientists and
geologists in identifying subsurface structures and hydrocarbon
indicators. They do not allow the interpreter to know
conclusively if hydrocarbons are present or producible
economically. In addition, the use of
3-D seismic and other
advanced technologies require greater
26
predrilling expenditures than traditional drilling strategies.
Because of these factors, we could incur losses as a result of
exploratory drilling expenditures. Poor results from exploration
activities could have a material adverse effect on our future
cash flows, ability to replace reserves and results of
operations.
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Oil and gas drilling and production involve many business
and operating risks, any one of which could reduce our levels of
production, cause substantial losses or prevent us from
realizing profits. |
Our business is subject to all of the operating risks associated
with drilling for and producing oil and natural gas, including:
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fires; |
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explosions; |
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blow-outs and surface cratering; |
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uncontrollable flows of underground natural gas, oil and
formation water; |
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natural disasters; |
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pipe or cement failures; |
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casing collapses; |
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lost or damaged oilfield drilling and service tools; |
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abnormally pressured formations; and |
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environmental hazards, such as natural gas leaks, oil spills,
pipeline ruptures and discharges of toxic gases. |
If any of these events occurs, we could incur substantial losses
as a result of injury or loss of life, severe damage to and
destruction of property, natural resources and equipment,
pollution and other environmental damage,
clean-up
responsibilities, regulatory investigation and penalties,
suspension of our operations and repairs to resume operations.
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Our offshore operations involve special risks that could
increase our cost of operations and adversely affect our ability
to produce oil and gas. |
Offshore operations are subject to a variety of operating risks
specific to the marine environment, such as capsizing,
collisions and damage or loss from hurricanes or other adverse
weather conditions. These conditions can cause substantial
damage to facilities and interrupt production. As a result, we
could incur substantial liabilities that could reduce or
eliminate the funds available for exploration, development or
leasehold acquisitions, or result in loss of equipment and
properties. For more information on the impact of recent
hurricanes on Mariners operations and the Forest Gulf of
Mexico operations, see Managements Discussion and
Analysis of Financial Condition and Results of Operations
Recent Developments beginning on page 56 and
Managements Discussion and Analysis of Financial
Condition and Results of Operations of the Forest Gulf of Mexico
Operations Recent Developments beginning on
page 141.
Exploration for oil or natural gas in the deepwater of the Gulf
of Mexico generally involves greater operational and financial
risks than exploration on the shelf. Deepwater drilling
generally requires more time and more advanced drilling
technologies, involving a higher risk of technological failure
and usually higher drilling costs. Our deepwater wells use
subsea completion techniques with subsea trees tied back to host
production facilities with flow lines. The installation of these
subsea trees and flow lines requires substantial time and the
use of advanced remote installation mechanics. These operations
may encounter mechanical difficulties and equipment failures
that could result in significant cost overruns. Furthermore, the
deepwater operations generally lack the physical and oilfield
service infrastructure present in the
27
shallow waters of the Gulf of Mexico. As a result, a significant
amount of time may elapse between a deepwater discovery and our
marketing of the associated oil or natural gas, increasing both
the financial and operational risk involved with these
operations. Because of the lack and high cost of infrastructure,
some reserve discoveries in the deepwater may never be produced
economically.
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Our hedging transactions may not protect us adequately
from fluctuations in oil and natural gas prices and may limit
future potential gains from increases in commodity prices or
result in losses. |
We enter into hedging arrangements from time to time to reduce
our exposure to fluctuations in oil and natural gas prices and
to achieve more predictable cash flow. These financial
arrangements typically take the form of price swap contracts and
costless collars. Hedging arrangements expose us to the risk of
financial loss in some circumstances, including situations when
the other party to the hedging contract defaults on its contract
or production is less than expected. During periods of high
commodity prices, hedging arrangements may limit significantly
the extent to which we can realize financial gains from such
higher prices. For example, in calendar year 2004, our hedging
arrangements reduced the benefit we received from increases in
the prices for oil and natural gas by approximately
$27.6 million ($76.9 million on a pro forma basis,
including the Forest Gulf of Mexico operations). Although we
currently maintain an active hedging program, we may choose not
to engage in hedging transactions in the future. As a result, we
may be affected adversely during periods of declining oil and
natural gas prices.
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We will require additional capital to fund our future
activities. If we fail to obtain additional capital, we may not
be able to implement fully our business plan, which could lead
to a decline in reserves. |
We depend on our ability to obtain financing beyond our cash
flow from operations. Historically, we have financed our
business plan and operations primarily with internally generated
cash flow, bank borrowings, proceeds from the sale of oil and
natural gas properties, entering into exploration arrangements
with other parties, the issuance of public debt, privately
raised equity and, prior to the bankruptcy of Enron Corp. (our
indirect parent company until March 2, 2004), borrowings
from Enron affiliates. In the future, we will require
substantial capital to fund our business plan and operations. We
expect to be required to meet our needs from our excess cash
flow, debt financings and additional equity offerings (subject
to certain federal tax limitations during the two-year period
following the spin-off). Sufficient capital may not be available
on acceptable terms or at all. If we cannot obtain additional
capital resources, we may curtail our drilling, development and
other activities or be forced to sell some of our assets on
unfavorable terms.
The issuance of additional debt would require that a portion of
our cash flow from operations be used for the payment of
interest on our debt, thereby reducing our ability to use our
cash flow to fund working capital, capital expenditures,
acquisitions and general corporate requirements, which could
place us at a competitive disadvantage relative to other
competitors. Additionally, if revenues decrease as a result of
lower oil or natural gas prices, operating difficulties or
declines in reserves, our ability to obtain the capital
necessary to undertake or complete future exploration and
development programs and to pursue other opportunities may be
limited, which could result in a curtailment of our operations
relating to exploration and development of our prospects, which
in turn could result in a decline in our oil and natural gas
reserves.
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Properties we acquire (including the Forest Gulf of Mexico
properties) may not produce as projected, and we may be unable
to determine reserve potential, identify liabilities associated
with the properties or obtain protection from sellers against
such liabilities. |
Properties we acquire, including the Forest Gulf of Mexico
properties, may not produce as expected, may be in an unexpected
condition and may subject us to increased costs and liabilities,
including environmental liabilities. The reviews we conduct of
acquired properties prior to acquisition are not capable of
identifying all potential adverse conditions. Generally, it is
not feasible to review in depth every individual property
involved in each acquisition. Ordinarily, we will focus our
review efforts on the higher
28
value properties or properties with known adverse conditions and
will sample the remainder. However, even a detailed review of
records and properties may not necessarily reveal existing or
potential problems or permit a buyer to become sufficiently
familiar with the properties to assess fully their condition,
any deficiencies, and development potential. Inspections may not
always be performed on every well, and environmental problems,
such as ground water contamination, are not necessarily
observable even when an inspection is undertaken.
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Market conditions or transportation impediments may hinder
our access to oil and natural gas markets or delay our
production. |
Market conditions, the unavailability of satisfactory oil and
natural gas transportation or the remote location of our
drilling operations may hinder our access to oil and natural gas
markets or delay our production. The availability of a ready
market for our oil and natural gas production depends on a
number of factors, including the demand for and supply of oil
and natural gas and the proximity of reserves to pipelines or
trucking and terminal facilities. In deepwater operations, the
availability of a ready market depends on the proximity of and
our ability to tie into existing production platforms owned or
operated by others and the ability to negotiate commercially
satisfactory arrangements with the owners or operators. We may
be required to shut in wells or delay initial production for
lack of a market or because of inadequacy or unavailability of
pipeline or gathering system capacity. When that occurs, we are
unable to realize revenue from those wells until the production
can be tied to a gathering system. This can result in
considerable delays from the initial discovery of a reservoir to
the actual production of the oil and natural gas and realization
of revenues.
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The unavailability or high cost of drilling rigs,
equipment, supplies or personnel could affect adversely our
ability to execute on a timely basis our exploration and
development plans within budget, which could have a material
adverse effect on our financial condition and results of
operations. |
Shortages or the high cost of drilling rigs, equipment, supplies
or personnel could delay or affect adversely our exploration and
development operations, which could have a material adverse
effect on our financial condition and results of operations. An
increase in drilling activity in the U.S. or the Gulf of
Mexico could increase the cost and decrease the availability of
necessary drilling rigs, equipment, supplies and personnel.
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Competition in the oil and natural gas industry is
intense, and many of our competitors have resources that are
greater than ours giving them an advantage in evaluating and
obtaining properties and prospects. |
We operate in a highly competitive environment for acquiring
prospects and productive properties, marketing oil and natural
gas and securing equipment and trained personnel. Many of our
competitors are major and large independent oil and natural gas
companies, and possess and employ financial, technical and
personnel resources substantially greater than ours. Those
companies may be able to develop and acquire more prospects and
productive properties than our financial or personnel resources
permit. Our ability to acquire additional prospects and discover
reserves in the future will depend on our ability to evaluate
and select suitable properties and consummate transactions in a
highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and
natural gas industry. Larger competitors may be better able to
withstand sustained periods of unsuccessful drilling and absorb
the burden of changes in laws and regulations more easily than
we can, which would adversely affect our competitive position.
We may not be able to compete successfully in the future in
acquiring prospective reserves, developing reserves, marketing
hydrocarbons, attracting and retaining quality personnel and
raising additional capital.
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Financial difficulties encountered by our farm-out
partners or third-party operators could affect the exploration
and development of our prospects adversely. |
From time to time, we enter into farm-out agreements to fund a
portion of the exploration and development costs of our
prospects. Moreover, other companies operate some of the other
properties in which we have an ownership interest. Liquidity and
cash flow problems encountered by our partners and co-owners of
our properties may lead to a delay in the pace of drilling or
project development that may be detrimental to a project.
In addition, our farm-out partners and working interest owners
may be unwilling or unable to pay their share of the costs of
projects as they become due. In the case of a farm-out partner,
we may have to obtain alternative funding in order to complete
the exploration and development of the prospects subject to the
farm-out agreement. In the case of a working interest owner, we
may be required to pay the working interest owners share
of the project costs. We cannot assure you that we would be able
to obtain the capital necessary in order to fund either of these
contingencies.
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We cannot control the drilling and development activities
on properties we do not operate, and therefore we may not be in
a position to control the timing of development efforts, the
associated costs or the rate of production of the
reserves. |
Other companies operate some of the properties in which we have
an interest. As a result, we have a limited ability to exercise
influence over operations for these properties or their
associated costs. Our dependence on the operator and other
working interest owners for these projects and our limited
ability to influence operations and associated costs could
materially adversely affect the realization of our targeted
returns on capital in drilling or acquisition activities. The
success and timing of drilling and development activities on
properties operated by others therefore depend upon a number of
factors that are outside of our control, including timing and
amount of capital expenditures, the operators expertise
and financial resources, approval of other participants in
drilling wells and selection of technology.
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Compliance with environmental and other government
regulations could be costly and could affect production
negatively. |
Exploration for and development, production and sale of oil and
natural gas in the U.S. and the Gulf of Mexico are subject to
extensive federal, state and local laws and regulations,
including environmental and health and safety laws and
regulations. We may be required to make large expenditures to
comply with these environmental and other requirements. Matters
subject to regulation include, among others, environmental
assessment prior to development, discharge and emission permits
for drilling and production operations, drilling bonds, and
reports concerning operations and taxation.
Under these laws and regulations, and also common law causes of
action, we could be liable for personal injuries, property
damage, oil spills, discharge of pollutants and hazardous
materials, remediation and
clean-up costs and
other environmental damages. Failure to comply with these laws
and regulations or to obtain or comply with required permits may
result in the suspension or termination of our operations and
subject us to remedial obligations as well as administrative,
civil and criminal penalties. Moreover, these laws and
regulations could change in ways that substantially increase our
costs. We cannot predict how agencies or courts will interpret
existing laws and regulations, whether additional or more
stringent laws and regulations will be adopted or the effect
these interpretations and adoptions may have on our business or
financial condition. For example, the Oil Pollution Act of 1990
(the OPA) imposes a variety of regulations on
responsible parties related to the prevention of oil
spills. The implementation of new, or the modification of
existing, environmental laws or regulations promulgated pursuant
to the OPA could have a material adverse impact on us. Further,
Congress or the MMS could decide to limit exploratory drilling
or natural gas production in additional areas of the Gulf of
Mexico. Accordingly, any of these liabilities, penalties,
suspensions, terminations or regulatory changes could have a
material adverse effect on our financial condition and results
of operations. See BusinessRegulation for more
information on our regulatory and environmental matters.
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Our insurance may not protect us against our business and
operating risks. |
We maintain insurance for some, but not all, of the potential
risks and liabilities associated with our business. For some
risks, we may not obtain insurance if we believe the cost of
available insurance is excessive relative to the risks
presented. As a result of market conditions, premiums and
deductibles for certain insurance policies can increase
substantially, and in some instances, certain insurance may
become unavailable or available only for reduced amounts of
coverage. As a result, we may not be able to renew our existing
insurance policies or procure other desirable insurance on
commercially reasonable terms, if at all.
Although we maintain insurance at levels we believe are
appropriate and consistent with industry practice, we are not
fully insured against all risks, including drilling and
completion risks that are generally not recoverable from third
parties or insurance. In addition, pollution and environmental
risks generally are not fully insurable. Losses and liabilities
from uninsured and underinsured events and delay in the payment
of insurance proceeds could have a material adverse effect on
our financial condition and results of operations. The impact of
Hurricanes Katrina and Rita have resulted in escalating
insurance costs and less favorable coverage terms. See
Business Insurance Matters and The
Forest Gulf of Mexico Operations Insurance
Matters for more information.
Risks Related to our Business if the Merger is not
Consummated
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If the merger is not ultimately consummated, the market
value of our common stock could decline, and our ability to
consummate alternate acquisition transactions could be
reduced. |
If the proposed merger with Forest Energy Resources is not
ultimately consummated, whether because our stockholders do not
adopt the merger agreement at the annual meeting or because some
other condition to closing is not satisfied, the market value of
our common stock could be reduced. Our stock price could be
adversely affected for other reasons related to the failure to
close, including due to our reduced opportunities to consummate
alternate transactions, or simply because the market had
perceived the failed transaction as accretive to our
stockholders. In addition, we may not meet the listing
requirements for listing on the New York Stock Exchange if the
proposed merger is not consummated, which would disqualify us
from listing our common stock on that exchange.
In addition, if the merger is not consummated our ability to
enter into other merger or acquisition transactions could be
hindered. Under the terms of the merger agreement, if the
agreement is terminated in certain circumstances where an
alternate proposal to acquire us is outstanding, we could be
required to pay Forest a termination fee and expense
reimbursement upon the consummation of an alternate transaction.
The termination fee and expense reimbursement provisions would
therefore have the effect of making it more costly to acquire
us, reducing the likelihood that such an acquisition would
occur. Moreover, potential acquisition partners could be
deterred from pursuing transactions with us, because they may
speculate that the failure was caused by due diligence problems
or other issues that motivated Forest not to close the
transaction.
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If the merger is not consummated, a significant part of
the value of our production and reserves will be concentrated in
a small number of offshore properties. As a result, any
production problems or inaccuracies in reserve estimates related
to those properties could reduce our revenue, profitability and
cash flow materially. |
During December 2005, approximately 69% of our daily production
came from 19 offshore fields. If mechanical problems, storms or
other events curtail a substantial portion of this production in
the future, our cash flow would be affected adversely. At
December 31, 2004, approximately 37% of our proved reserves
were located on seven offshore properties. If the actual
reserves associated with any one of these properties are less
than our estimated reserves, our results of operations and
financial condition could be adversely affected. During the
three years ended December 31, 2002, 2003 and 2004, weather
and
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mechanical problems affecting our offshore producing properties
resulted in aggregate downtime for our offshore producing
properties of 7.3%, 7.1% and 7.3%, respectively.
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If the merger is not consummated, the smaller size of our
operations relative to those of the combined operations could
reduce our ability to participate in projects or pursue
acquisition opportunities that would increase our
profitability. |
The proposed merger with Forest Energy Resources would
approximately triple the pro forma daily net production of
Mariner on a stand-alone basis. If the merger is not
consummated, the scale of our operations would be significantly
smaller than that of the combined operations. The smaller
operational scale could adversely impact our ability, relative
to our ability if the merger were consummated, to participate in
larger scale exploratory and development drilling projects or to
pursue acquisition opportunities. The inability to participate
in such transactions could reduce our profitability and
adversely affect our results of operations.
Risks Related to the Spin-Off and the Merger
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The consummation of the merger is subject to numerous
conditions, many of which are beyond our control. |
The merger will be completed only if certain conditions,
including the following, are satisfied (or waived in certain
cases):
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the adoption of the merger agreement by Mariner stockholders
holding a majority of the Mariner common stock and the approval
of the proposed amendment to Mariners certificate of
incorporation; |
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the absence of legal restrictions that would prevent the
completion of the transactions; |
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the receipt by Forest, Mariner and Forest Energy Resources of an
opinion from their respective counsel to the effect that the
merger will be treated as a reorganization for federal income
tax purposes; |
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the completion of the spin-off in accordance with the
distribution agreement; |
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the receipt of material consents, approvals and authorizations
of governmental authorities; |
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the expiration or termination of any applicable waiting period
under the Hart-Scott-Rodino Act; |
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the SEC declaring effective the registration statements of
Mariner relating to the shares of Mariner common stock to be
issued in the merger and those shares held by its existing
stockholders; |
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the representations and warranties contained in the merger
agreement being materially true and correct, the performance in
all material respects by the parties of their covenants and
other agreements in the merger agreement; |
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the approval for listing on the New York Stock Exchange or
Nasdaq of Mariners common stock; and |
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Mariner and Forest receiving the consents required pursuant to
their credit facilities (with Mariner or Forest Energy Resources
having entered into a new or amended credit facility sufficient
to operate the combined businesses), and Forest receiving any
consents required from its bondholders. |
We cannot assure you that the conditions to the consummation of
the merger will be satisfied or waived, or that the closing will
occur. Some of the conditions, such as the adoption of the merger
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agreement by our stockholders, the absence of legal restrictions
and the receipt of required consents are partially or completely
beyond our control.
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The market value of our common stock could decline if
large amounts of our common stock are sold following the
spin-off and merger. |
The market price of our common stock could decline as a result
of sales of a large number of shares in the market after the
completion of the spin-off and merger or the perception that
these sales could occur. Immediately after the merger, Forest
shareholders will hold, in the aggregate, approximately 58% of
our common stock on a pro forma basis. Currently, Forest
shareholders include index funds tied to various stock indices,
and institutional investors subject to various investing
guidelines. Because we may not be included in these indices at
the time of the merger or may not meet the investing guidelines
of some of these institutional investors, these index funds and
institutional investors may decide to sell the Mariner common
stock they receive in the merger. These sales may negatively
affect the price of our common stock and also may make it more
difficult for us to obtain additional capital by selling equity
securities in the future at a time and at a price that we deem
appropriate.
Historically, Forest has operated with properties in diverse
geographic locations, including the Gulf Coast, the Western
United States, Alaska, Canada and other international locations.
In contrast, following the spin-off and merger, Mariner will
operate as a stand-alone oil and gas exploration, development
and production company with operations primarily in the Gulf of
Mexico and in West Texas. Shareholders of Forest who chose to
invest in a geographically diverse company may not wish to
continue to invest in one that is less geographically diverse,
such as Mariner. As a result, such shareholders may seek to sell
the shares of our common stock received in the merger.
|
|
|
The integration of the Forest Gulf of Mexico operations
following the merger will be difficult, and will divert our
managements attention away from our normal
operations. |
There is a significant degree of difficulty and management
involvement inherent in the process of integrating the Forest
Gulf of Mexico operations. These difficulties include:
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|
|
the challenge of integrating the Forest Gulf of Mexico
operations while carrying on the ongoing operations of our
business; |
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|
|
the challenge of managing a significantly larger company, with
more than twice the PV10 of Mariner on a stand-alone basis; |
|
|
|
faulty assumptions underlying our expectations; |
|
|
|
the difficulty associated with coordinating geographically
separate organizations; |
|
|
|
the challenge of integrating the business cultures of the two
companies; |
|
|
|
attracting and retaining personnel associated with the Forest
Gulf of Mexico operations following the merger; and |
|
|
|
the challenge and cost of integrating the information technology
systems of the two companies. |
The process of integrating operations could cause an
interruption of, or loss of momentum in, the activities of our
business. Members of our senior management may be required to
devote considerable amounts of time to this integration process,
which will decrease the time they will have to manage our
business. If our senior management is not able to effectively
manage the integration process, or if any significant business
activities are interrupted as a result of the integration
process, our business could suffer.
33
|
|
|
If we fail to realize the anticipated benefits of the
merger, stockholders may receive lower returns than they
expect. |
The success of the merger will depend, in part, on our ability
to realize the anticipated growth opportunities from combining
the Forest Gulf of Mexico operations with Mariner. Even if we
are able to successfully combine the two businesses, it may not
be possible to realize the full benefits of the proved reserves,
enhanced growth of production volume, cost savings from
operating synergies and other benefits that we currently expect
to result from the merger, or realize these benefits within the
time frame that is currently expected. The benefits of the
merger may be offset by operating losses relating to changes in
commodity prices, or in oil and gas industry conditions, or by
risks and uncertainties relating to the combined companys
exploratory prospects, or an increase in operating or other
costs or other difficulties. If we fail to realize the benefits
we anticipate from the merger, stockholders may receive lower
returns on our stock than they expect.
|
|
|
We expect to incur significant charges relating to the
integration plan that could materially and adversely affect our
period-to-period results of operations following the
merger. |
We are developing a plan to integrate the Forest Gulf of Mexico
operations with our operations after the merger. Following the
merger, we anticipate that from time to time we will incur
charges to our earnings in connection with the integration.
These charges will include expenses incurred in connection with
relocating and retaining employees and increased professional
and consulting costs. We also expect to incur significant
expenses related to being a public company. We will not be able
to quantify the exact amount of these charges or the period(s)
in which they will be incurred until after the merger is
completed. Some factors affecting the cost of the integration
include the timing of the closing of the merger, the training of
new employees, the amount of severance and other
employee-related payments resulting from the merger, and the
limited length of time during which transitional services are
provided by Forest.
|
|
|
The number of shares Forest shareholders will receive in
the merger is not subject to adjustment based on the value of
the Mariner or the Forest Gulf of Mexico operations.
Accordingly, because this value may fluctuate, the market value
of the Mariner common stock that Forest shareholders receive in
the merger may not reflect the value of the individual companies
at the time of the merger. |
Following the spin-off and the merger, the holders of Forest
common stock will ultimately become entitled to receive
approximately 0.8 shares of Mariner common stock for each
Forest share they own. This ratio will not be adjusted for
changes in the value of our company or the Forest Gulf of Mexico
operations. If our value relative to the Forest Gulf of Mexico
operations increases (or the value of the Forest Gulf of Mexico
operations decreases relative to our value) prior to the
completion of the merger, the market value of the Mariner common
stock that Forest shareholders receive in the merger may not
reflect the then-current relative values of the individual
companies.
|
|
|
Regulatory agencies may delay or impose conditions on
approval of the spin-off and the merger, which may diminish the
anticipated benefits of the merger. |
Completion of the spin-off and merger is conditioned upon the
receipt of required governmental consents, approvals, orders and
authorizations. While we intend to pursue vigorously all
required governmental approvals and do not know of any reason
why we would not be able to obtain the necessary approvals in a
timely manner, the requirement to receive these approvals before
the spin-off and merger could delay the completion of the
spin-off and merger, possibly for a significant period of time
after Mariner stockholders have approved the merger proposal at
the annual meeting. In addition, these governmental agencies may
attempt to condition their approval of the merger on the
imposition of conditions that could have a material adverse
effect on our operating results or the value of our common stock
after the spin-off and merger are completed.
34
Any delay in the completion of the spin-off and merger could
diminish anticipated benefits of the spin-off and merger or
result in additional transaction costs, loss of revenue or other
effects associated with uncertainty about the transaction. Any
uncertainty over the ability of the companies to complete the
spin-off and merger could make it more difficult for us to
retain key employees or to pursue business strategies. In
addition, until the spin-off and merger are completed, the
attention of our management may be diverted from ongoing
business concerns and regular business responsibilities to the
extent management is focused on matters relating to the
transaction, such as obtaining regulatory approvals.
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|
|
In order to preserve the tax-free treatment of the
spin-off, we will be required to abide by potentially
significant restrictions which could limit our ability to
undertake certain corporate actions (such as the issuance of our
common shares or the undertaking of a change in control) that
otherwise could be advantageous. |
The tax sharing agreement imposes ongoing restrictions on Forest
and on us to ensure that applicable statutory requirements under
the Internal Revenue Code and applicable Treasury regulations
continue to be met so that the spin-off remains tax-free to
Forest and its shareholders. As a result of these restrictions,
our ability to engage in certain transactions, such as the
redemption of our common stock, the issuance of equity
securities and the utilization of our stock as currency in an
acquisition, will be limited for a period of two years following
the spin-off.
If Forest or Mariner takes or permits an action to be taken (or
omits to take an action) that causes the spin-off to become
taxable, the relevant entity generally will be required to bear
the cost of the resulting tax liability to the extent that the
liability results from the actions or omissions of that entity.
If the spin-off became taxable, Forest would be expected to
recognize a substantial amount of income, which would result in
a material amount of taxes. Any such taxes allocated to us would
be expected to be material to us, and could cause our business,
financial condition and operating results to suffer. These
restrictions may reduce our ability to engage in certain
business transactions that otherwise might be advantageous to us
and our stockholders and could have a negative impact on our
business and stockholder value.
|
|
|
Some of our directors and executive officers have
interests that are different from, or in addition to, the
interests of our stockholders. |
When considering the recommendations of our board of directors,
you should be aware that some of our directors and executive
officers have interests and arrangements that may be different
from your interests as stockholders, including:
|
|
|
|
|
arrangements regarding the appointment of directors and officers
of Mariner following the merger; and |
|
|
|
arrangements whereby our executive officers will receive a cash
payment of $1,000 each in exchange for the waiver of certain
rights under their employment agreements, including the
automatic vesting or acceleration of restricted stock and
options upon the completion of the merger and the right to
receive a lump sum cash payment if the officer voluntarily
terminates employment without good reason within nine months
following the completion of the merger. |
Risks Related to our Common Stock
|
|
|
An active market for our common stock may not develop and
the market price for shares of our common stock may be highly
volatile and could be subject to wide fluctuations after this
offering. |
We are a private company, and there is no public market for our
common stock. An active market for our common stock may not
develop or may not be sustained after this offering. In
addition, we cannot assure you as to the liquidity of any such
market that may develop or the price that our stockholders may
obtain for their shares of our common stock.
35
Even if an active trading market develops, the market price for
shares of our common stock may be highly volatile and could be
subject to wide fluctuations. Some of the factors that could
negatively affect our share price include:
|
|
|
|
|
actual or anticipated downward revisions in our reserve
estimates; |
|
|
|
our operating results being less than anticipated; |
|
|
|
reductions in oil and gas prices; |
|
|
|
publication of unfavorable research reports about us or the
exploration and production industry; |
|
|
|
increases in market interest rates which may increase our cost
of capital; |
|
|
|
the enactment of more stringent laws or regulations applicable
to our business, or unfavorable court rulings or enforcement or
legal actions; |
|
|
|
increases in royalties or taxes payable in the operation of our
business; |
|
|
|
a general decline in market valuations of similar companies; |
|
|
|
adverse market reaction to any increased indebtedness we incur
in the future; |
|
|
|
departures of key management personnel; |
|
|
|
increases to our asset retirement obligations; |
|
|
|
adverse actions taken by our stockholders; |
|
|
|
negative speculation in the press or investment
community; and |
|
|
|
adverse general market and economic conditions. |
|
|
|
We do not anticipate paying any dividends on our common
stock in the foreseeable future. |
We do not expect to declare or pay any cash or other dividends
in the foreseeable future on our common stock. Our existing
revolving credit facility restricts our ability to pay cash
dividends on our common stock, and we may also enter into other
credit agreements or other borrowing arrangements in the future
that restrict our ability to declare or pay cash dividends on
our common stock.
|
|
|
Mariner stockholders will experience substantial and
immediate dilution as a result of the merger, and may experience
dilution of their ownership interests due to the future issuance
of additional shares of our common stock, which could have an
adverse effect on our stock price. |
If the merger is completed, the current owners of Mariners
common stock will experience substantial and immediate dilution
from the issuance of shares of Mariner common stock to Forest
shareholders, such that the Mariner stockholders will own
approximately 42% of the Mariner common stock following the
merger. Additionally, we may in the future issue our previously
authorized and unissued securities, resulting in the dilution of
the ownership interests of our present stockholders. We are
currently authorized to issue 70 million shares of common
stock and 20 million shares of preferred stock with such
designations, preferences and rights as determined by our board
of directors. As a result of the proposed amendment to our
certificate of incorporation, our authorized shares would be
increased to 180 million shares of common stock and
20 million shares of preferred stock. Pursuant to the
proposed addition of shares to our stock incentive plan, the
maximum number of shares issuable under the plan would, if the
proposal is approved, be increased to 6.5 million shares.
The potential issuance of such additional shares of common stock
may create downward pressure on the trading price of our common
stock. We may also issue additional shares of our common stock
or other securities that are convertible into or exercisable for
common stock (subject to certain federal tax limitations during
the two-year period following the spin-off) in connection with
the hiring of personnel, future acquisitions, future public
offerings or private placements of our securities for capital
raising purposes, or for other business purposes. Future sales
of substantial amounts of our common stock, or the perception
that sales could occur, could have a material adverse effect on
the price of our common stock.
36
|
|
|
Provisions in our organizational documents and under
Delaware law could delay or prevent a change in control of our
company, which could adversely affect the price of our common
stock. |
The existence of some provisions in our organizational documents
and under Delaware law could delay or prevent a change in
control of our company, which could adversely affect the price
of our common stock. The provisions in our certificate of
incorporation and bylaws that could delay or prevent an
unsolicited change in control of our company include a staggered
board of directors, board authority to issue preferred stock,
and advance notice provisions for director nominations or
business to be considered at a stockholder meeting. In addition,
Delaware law imposes restrictions on mergers and other business
combinations between us and any holder of 15% or more of our
outstanding common stock. See Description of Capital
Stock.
37
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Various statements in this prospectus, including those that
express a belief, expectation, or intention, as well as those
that are not statements of historical fact, are forward-looking
statements. The forward-looking statements may include
projections and estimates concerning the timing and success of
specific projects and our future production, revenues, income
and capital spending. Our forward-looking statements are
generally accompanied by words such as estimate,
project, predict, believe,
expect, anticipate,
potential, plan, goal or
other words that convey the uncertainty of future events or
outcomes. The forward-looking statements in this prospectus
speak only as of the date of this prospectus; we disclaim any
obligation to update these statements unless required by
securities law, and we caution you not to rely on them unduly.
We have based these forward-looking statements on our current
expectations and assumptions about future events. While our
management considers these expectations and assumptions to be
reasonable, they are inherently subject to significant business,
economic, competitive, regulatory and other risks, contingencies
and uncertainties, most of which are difficult to predict and
many of which are beyond our control. We disclose important
factors that could cause our actual results to differ materially
from our expectations under Risk Factors,
Managements Discussion and Analysis of Financial
Condition and Results of Operations of the Forest Gulf of Mexico
Operations, Managements Discussion and
Analysis of Financial Condition and Results of Operations
and elsewhere in this prospectus. These risks, contingencies and
uncertainties relate to, among other matters, the following:
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|
|
the volatility of oil and natural gas prices; |
|
|
|
discovery, estimation, development and replacement of oil and
natural gas reserves; |
|
|
|
cash flow, liquidity and financial position; |
|
|
|
business strategy; |
|
|
|
amount, nature and timing of capital expenditures, including
future development costs; |
|
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|
availability and terms of capital; |
|
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|
timing and amount of future production of oil and natural gas; |
|
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|
availability of drilling and production equipment; |
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|
operating costs and other expenses; |
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|
|
prospect development and property acquisitions; |
|
|
|
marketing of oil and natural gas; |
|
|
|
competition in the oil and natural gas industry; |
|
|
|
the impact of weather and the occurrence of natural disasters
such as fires, floods and other catastrophic events and natural
disasters; |
|
|
|
governmental regulation of the oil and natural gas industry; |
|
|
|
developments in oil-producing and natural gas-producing
countries; |
|
|
|
the proposed merger, including strategic plans, expectations and
objectives for future operations, the completion of those
transactions, and the realization of expected benefits from the
transactions; and |
|
|
|
disruption from the merger making it more difficult to manage
Mariners business. |
38
USE OF PROCEEDS
We will not receive any of the proceeds from the sale of the
shares of common stock offered by this prospectus. Any proceeds
from the sale of the shares offered by this prospectus will be
received by the selling stockholders.
CAPITALIZATION
The following table shows our capitalization as of
September 30, 2005. You should refer to Selected
Historical Consolidated Financial Data,
Managements Discussion and Analysis of Financial
Condition and Results of Operations and the financial
statements included elsewhere in this prospectus in evaluating
the material presented below.
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|
September 30, | |
|
|
2005 | |
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| |
|
|
(in millions) | |
Long-term debt:
|
|
|
|
|
|
Credit facility revolving note due March 2007
|
|
$ |
75.0 |
|
|
Promissory note to former indirect stockholder(1)
|
|
|
4.0 |
|
|
|
|
|
|
|
Total long-term debt
|
|
|
79.0 |
|
Stockholders equity(2)
|
|
|
178.6 |
|
|
|
|
|
|
|
Total capitalization
|
|
$ |
257.6 |
|
|
|
|
|
|
|
(1) |
For a description of the promissory note to our former indirect
stockholder, see Managements Discussion and Analysis
of Financial Condition and Results of Operations JEDI Term
Promissory Note. |
|
(2) |
Reflects the receipt of net proceeds from the sale of
3.6 million shares reduced by approximately
$1.9 million of offering costs. |
39
DILUTION
Our net tangible book value as of September 30, 2005 was
$5.01 per share of common stock. Net tangible book value
per share is determined by dividing our tangible net worth
(tangible assets less total liabilities) by the
35,615,400 shares of our common stock that were outstanding
on September 30, 2005. Investors who purchase our common
stock in this offering may pay a price per share that exceeds
the net tangible book value per share of our common stock. If
you purchase our common stock from the selling stockholders
identified in this prospectus, you will experience immediate
dilution of $14.99 in the net tangible book value per share of
our common stock assuming a sale price of $20.00 per share,
representing the September 30, 2005 price at which the
shares traded in the PORTAL
Market®.
The following table illustrates the per share dilution to new
investors purchasing shares from the selling stockholders
identified in this prospectus:
|
|
|
|
|
|
|
|
|
|
Assumed offering price per share |
|
$ |
20.00 |
|
|
Net tangible book value per share at September 30, 2005
|
|
$ |
5.01 |
|
|
|
|
|
|
Increase per share attributable to new investors
|
|
|
-0- |
|
|
|
|
|
Net tangible book value per share after this offering |
|
|
5.01 |
|
|
|
|
|
Dilution per share to new investors |
|
$ |
14.99 |
|
|
|
|
|
The foregoing discussion and table are based upon the number of
shares actually issued and outstanding as of September 30,
2005. As of September 30, 2005, we had 809,000 stock
options outstanding at an average exercise price of
approximately $14.00 per share, none of which were vested
as of September 30, 2005. To the extent the market value of
our shares is greater than $14.00 per share and any of
these outstanding options are exercised, there may be further
dilution to new investors.
DIVIDEND POLICY
We do not expect to pay dividends in the near future. Our credit
facility contains restrictions on the payment of dividends to
stockholders. See Managements Discussion and
Analysis of Financial Condition and Results of
OperationsCredit Facility.
40
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
The following table shows Mariners historical consolidated
financial data as of and for each of the four years ended
December 31, 2003, the period from January 1, 2004
through March 2, 2004, the period from March 3, 2004
through December 31, 2004, the period from March 3,
2004 through September 30, 2004 and the nine-month period
ended September 30, 2005. The historical consolidated
financial data as of and for the four years ended
December 31, 2003, the period from January 1, 2004
through March 2, 2004 and the period from March 3,
2004 through December 31, 2004 are derived from
Mariners audited financial statements included herein, and
the historical consolidated financial data for the period from
March 3, 2004 through September 30, 2004 and the
nine-month period ended September 30, 2005 are derived from
unaudited financial statements of Mariner. You should read the
following data in connection with Managements
Discussion and Analysis of Financial Condition and Results of
Operations and the consolidated financial statements
included elsewhere in this prospectus, where there is additional
disclosure regarding the information in the following table,
including pro forma information regarding the merger.
Mariners historical results are not necessarily indicative
of results to be expected in future periods.
On March 2, 2004, Mariners former indirect parent,
Mariner Energy LLC, merged with MEI Acquisitions, LLC, an
affiliate of the private equity funds, Carlyle/ Riverstone
Global Energy and Power Fund II, L.P. and ACON Investments
LLC. The financial information contained herein is presented in
the style of Pre-2004 Merger activity (for all periods prior to
March 2, 2004) and Post-2004 Merger activity (for the
March 3, 2004 through December 31, 2004 period and the
March 3, 2004 through September 30, 2004 period) to
reflect the impact of the restatement of assets and liabilities
to fair value as required by push-down purchase
accounting at the March 2, 2004 merger date.
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|
Post-2004 Merger | |
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|
Pre-2004 Merger | |
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| |
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| |
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Period from | |
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Period from | |
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Period from | |
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March 3, | |
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January 1, | |
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Nine Months | |
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March 3, | |
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2004 | |
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2004 | |
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Ended | |
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2004 through | |
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through | |
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through | |
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Year Ended December 31, | |
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September 30, | |
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September 30, | |
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December 31, | |
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March 2, | |
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| |
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2005 | |
|
2004 | |
|
2004 | |
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|
2004 | |
|
2003 | |
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2002 | |
|
2001 | |
|
2000 | |
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| |
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| |
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| |
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| |
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| |
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| |
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|
(in millions, except per share data) | |
Statement of Operations Data:
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|
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|
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|
|
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|
Total revenues(1)
|
|
$ |
151.2 |
|
|
$ |
122.5 |
|
|
$ |
174.4 |
|
|
|
$ |
39.8 |
|
|
$ |
142.5 |
|
|
$ |
158.2 |
|
|
$ |
155.0 |
|
|
$ |
121.1 |
|
|
Lease operating expenses
|
|
|
20.2 |
|
|
|
15.1 |
|
|
|
21.4 |
|
|
|
|
4.1 |
|
|
|
24.7 |
|
|
|
26.1 |
|
|
|
20.1 |
|
|
|
17.2 |
|
|
Transportation expenses
|
|
|
1.7 |
|
|
|
3.7 |
|
|
|
1.9 |
|
|
|
|
1.1 |
|
|
|
6.3 |
|
|
|
10.5 |
|
|
|
12.0 |
|
|
|
7.8 |
|
|
Depreciation, depletion and amortization
|
|
|
43.4 |
|
|
|
37.4 |
|
|
|
54.3 |
|
|
|
|
10.6 |
|
|
|
48.3 |
|
|
|
70.8 |
|
|
|
63.5 |
|
|
|
56.8 |
|
|
Impairment of production equipment held for use
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|
|
0.5 |
|
|
|
1.0 |
|
|
|
1.0 |
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|
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|
|
|
|
|
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|
Derivative settlement
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
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|
|
3.2 |
|
|
|
|
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|
Impairment of Enron related receivables
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|
|
|
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|
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|
|
3.2 |
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|
|
29.5 |
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|
|
|
|
|
General and administrative expenses
|
|
|
26.7 |
|
|
|
6.2 |
|
|
|
7.6 |
|
|
|
|
1.1 |
|
|
|
8.1 |
|
|
|
7.7 |
|
|
|
9.3 |
|
|
|
6.5 |
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|
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|
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Operating income
|
|
|
58.7 |
|
|
|
59.1 |
|
|
|
88.2 |
|
|
|
|
22.9 |
|
|
|
51.9 |
|
|
|
39.9 |
|
|
|
20.6 |
|
|
|
32.8 |
|
|
Interest income
|
|
|
0.7 |
|
|
|
0.2 |
|
|
|
0.2 |
|
|
|
|
0.1 |
|
|
|
0.8 |
|
|
|
0.4 |
|
|
|
0.7 |
|
|
|
0.1 |
|
|
Interest expense
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|
|
(5.4 |
) |
|
|
(4.4 |
) |
|
|
(6.0 |
) |
|
|
|
|
|
|
|
(7.0 |
) |
|
|
(10.3 |
) |
|
|
(8.9 |
) |
|
|
(11.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
54.0 |
|
|
|
54.9 |
|
|
|
82.4 |
|
|
|
|
23.0 |
|
|
|
45.7 |
|
|
|
30.0 |
|
|
|
12.4 |
|
|
|
21.9 |
|
|
Provision for income taxes
|
|
|
(18.4 |
) |
|
|
(19.2 |
) |
|
|
(28.8 |
) |
|
|
|
(8.1 |
) |
|
|
(9.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting method
net of tax effects
|
|
|
35.6 |
|
|
|
35.7 |
|
|
|
53.6 |
|
|
|
|
14.9 |
|
|
|
36.3 |
|
|
|
30.0 |
|
|
|
12.4 |
|
|
|
21.9 |
|
|
Income before cumulative effect per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
1.10 |
|
|
|
1.20 |
|
|
|
1.80 |
|
|
|
|
.50 |
|
|
|
1.22 |
|
|
|
1.01 |
|
|
|
.42 |
|
|
|
.74 |
|
|
|
Diluted
|
|
|
1.07 |
|
|
|
1.20 |
|
|
|
1.80 |
|
|
|
|
.50 |
|
|
|
1.22 |
|
|
|
1.01 |
|
|
|
.42 |
|
|
|
.74 |
|
|
Cumulative effect of changes in accounting method
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
35.6 |
|
|
$ |
35.7 |
|
|
$ |
53.6 |
|
|
|
$ |
14.9 |
|
|
$ |
38.2 |
|
|
$ |
30.0 |
|
|
$ |
12.4 |
|
|
$ |
21.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
1.10 |
|
|
|
1.20 |
|
|
|
1.80 |
|
|
|
|
.50 |
|
|
|
1.29 |
|
|
|
1.01 |
|
|
|
.42 |
|
|
|
.74 |
|
|
|
Diluted
|
|
|
1.07 |
|
|
|
1.20 |
|
|
|
1.80 |
|
|
|
|
.50 |
|
|
|
1.29 |
|
|
|
1.01 |
|
|
|
.42 |
|
|
|
.74 |
|
Capital Expenditure and Disposal Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, including leasehold/seismic
|
|
$ |
23.6 |
|
|
$ |
35.7 |
|
|
$ |
40.4 |
|
|
|
$ |
7.5 |
|
|
$ |
31.6 |
|
|
$ |
40.4 |
|
|
$ |
66.3 |
|
|
$ |
46.7 |
|
|
Development and other
|
|
|
106.8 |
|
|
|
50.2 |
|
|
|
93.2 |
|
|
|
|
7.8 |
|
|
|
51.7 |
|
|
|
65.7 |
|
|
|
98.2 |
|
|
|
61.4 |
|
|
Proceeds from property conveyances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(121.6 |
) |
|
|
(52.3 |
) |
|
|
(90.5 |
) |
|
|
(29.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures net of proceeds from property
conveyances
|
|
$ |
130.4 |
|
|
$ |
85.9 |
|
|
$ |
133.6 |
|
|
|
$ |
15.3 |
|
|
$ |
(38.3 |
) |
|
$ |
53.8 |
|
|
$ |
74.0 |
|
|
$ |
79.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Includes effects of hedging. |
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger | |
|
|
Pre-2004 Merger | |
|
|
| |
|
|
| |
|
|
|
|
|
December 31, | |
|
|
September 30, | |
|
December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
2003 | |
|
2002 | |
|
2001 | |
|
2000 | |
|
|
| |
|
| |
|
|
| |
|
| |
|
| |
|
| |
|
|
(in millions) | |
Balance Sheet Data:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net, full cost method
|
|
$ |
393.3 |
|
|
$ |
303.8 |
|
|
|
$ |
207.9 |
|
|
$ |
287.6 |
|
|
$ |
290.6 |
|
|
$ |
287.8 |
|
|
Total assets
|
|
|
502.2 |
|
|
|
376.0 |
|
|
|
|
312.1 |
|
|
|
360.2 |
|
|
|
363.9 |
|
|
|
335.4 |
|
|
Long-term debt, less current maturities
|
|
|
79.0 |
|
|
|
115.0 |
|
|
|
|
|
|
|
|
99.8 |
|
|
|
99.8 |
|
|
|
129.7 |
|
|
Stockholders equity
|
|
|
178.6 |
|
|
|
133.9 |
|
|
|
|
218.2 |
|
|
|
170.1 |
|
|
|
180.1 |
|
|
|
141.9 |
|
|
Working capital (deficit)(2)
|
|
|
(30.2 |
) |
|
|
(18.7 |
) |
|
|
|
38.3 |
|
|
|
(24.4 |
) |
|
|
(19.6 |
) |
|
|
(15.4 |
) |
|
|
(1) |
Balance sheet data as of December 31, 2004 reflects
purchase accounting adjustments to oil and gas properties, total
assets and stockholders equity resulting from the
acquisition of our former indirect parent on March 2, 2004. |
|
(2) |
Working capital (deficit) excludes current derivative assets and
liabilities, deferred tax assets and restricted cash. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger | |
|
|
Pre-2004 Merger | |
|
|
| |
|
|
| |
|
|
|
|
Period from | |
|
|
Period from | |
|
|
|
|
|
|
Period from | |
|
March 3, | |
|
|
January 1, | |
|
|
|
|
Nine Months | |
|
March 3, | |
|
2004 | |
|
|
2004 | |
|
|
|
|
Ended | |
|
2004 through | |
|
through | |
|
|
through | |
|
Year Ended December 31, | |
|
|
September 30, | |
|
September 30, | |
|
December 31, | |
|
|
March 2, | |
|
| |
|
|
2005 | |
|
2004 | |
|
2004 | |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
2001 | |
|
2000 | |
|
|
| |
|
| |
|
| |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(in millions) | |
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$ |
102.7 |
|
|
$ |
97.5 |
|
|
$ |
143.5 |
|
|
|
$ |
33.4 |
|
|
$ |
100.3 |
|
|
$ |
113.9 |
|
|
$ |
113.6 |
|
|
$ |
89.6 |
|
Net cash provided by operating activities
|
|
|
135.4 |
|
|
|
96.8 |
|
|
|
135.9 |
|
|
|
|
20.3 |
|
|
|
103.5 |
|
|
|
60.3 |
|
|
|
113.5 |
|
|
|
63.9 |
|
Net cash (used) provided by investing activities
|
|
|
(142.1 |
) |
|
|
(85.9 |
) |
|
|
(133.6 |
) |
|
|
|
(15.3 |
) |
|
|
38.3 |
|
|
|
(53.8 |
) |
|
|
(74.0 |
) |
|
|
(79.1 |
) |
Net cash (used) provided by financing activities
|
|
|
8.7 |
|
|
|
(74.9 |
) |
|
|
64.9 |
|
|
|
|
|
|
|
|
(100.0 |
) |
|
|
|
|
|
|
(30.0 |
) |
|
|
17.4 |
|
Reconciliation of Non-GAAP Measures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$ |
102.7 |
|
|
$ |
97.5 |
|
|
$ |
143.5 |
|
|
|
$ |
33.4 |
|
|
$ |
100.3 |
|
|
$ |
113.9 |
|
|
$ |
113.6 |
|
|
$ |
89.6 |
|
Changes in working capital
|
|
|
25.1 |
|
|
|
9.7 |
|
|
|
6.9 |
|
|
|
|
(13.2 |
) |
|
|
21.8 |
|
|
|
(20.4 |
) |
|
|
7.5 |
|
|
|
(15.5 |
) |
Non-cash hedge gain(2)
|
|
|
(3.6 |
) |
|
|
(5.1 |
) |
|
|
(7.9 |
) |
|
|
|
|
|
|
|
(2.0 |
) |
|
|
(23.2 |
) |
|
|
|
|
|
|
|
|
Amortization/other
|
|
|
0.9 |
|
|
|
0.5 |
|
|
|
0.8 |
|
|
|
|
|
|
|
|
|
|
|
|
(0.1 |
) |
|
|
0.6 |
|
|
|
0.7 |
|
Stock compensation expense
|
|
|
17.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense
|
|
|
(4.7 |
) |
|
|
(4.2 |
) |
|
|
(5.8 |
) |
|
|
|
0.1 |
|
|
|
(6.2 |
) |
|
|
(9.9 |
) |
|
|
(8.2 |
) |
|
|
(10.9 |
) |
Income tax expense
|
|
|
(2.6 |
) |
|
|
(1.6 |
) |
|
|
(1.6 |
) |
|
|
|
|
|
|
|
(10.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$ |
135.4 |
|
|
$ |
96.8 |
|
|
$ |
135.9 |
|
|
|
$ |
20.3 |
|
|
$ |
103.5 |
|
|
$ |
60.3 |
|
|
$ |
113.5 |
|
|
$ |
63.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
EBITDA means earnings before interest, income taxes,
depreciation, depletion and amortization. For the nine months
ended September 30, 2005, EBITDA includes
$17.6 million in non-cash stock compensation expense
related to restricted stock and stock options granted in 2005.
We believe that EBITDA is a widely accepted financial indicator
that provides additional information about our ability to meet
our future requirements for debt service, capital expenditures
and working capital, but EBITDA should not be considered in
isolation or as a substitute for net income, operating income,
net cash provided by operating activities or any other measure
of financial performance presented in |
42
|
|
|
accordance with generally accepted accounting principles or as a
measure of a companys profitability or liquidity. |
|
(2) |
In accordance with SFAS No. 133 Accounting for
Derivative Instruments and Hedging Activities, as amended
by SFAS No. 137 and No. 138, we de-designated our
contracts effective December 2, 2001 after the counterparty
(an affiliate of Enron Corp.) filed for bankruptcy and
recognized all market value changes subsequent to such
de-designation in our earnings. The value recorded up to the
time of de-designation and included in Accumulated Other
Comprehensive Income (AOCI), has reversed out of
AOCI and into earnings as the original corresponding production,
as hedged by the contracts, is produced. We have designated
subsequent hedge contracts as cash flow hedges with gains and
losses resulting from the transactions recorded at market value
in AOCI, as appropriate, until recognized as operating income in
our Statement of Operations as the physical production hedged by
the contracts is delivered. |
43
UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL
INFORMATION
The following unaudited pro forma combined financial information
and explanatory notes present how the combined financial
statements of Mariner and the Forest Gulf of Mexico operations
may have appeared had the businesses actually been combined as
of September 30, 2005 (with respect to the balance sheet
information using currently available fair value information) or
as of January 1, 2004 (with respect to statements of
operations information). The unaudited pro forma combined
financial information shows the impact of the merger on the
historical financial position and results of operations under
the purchase method of accounting with Mariner treated as the
acquirer. Under this method of accounting, the assets and
liabilities of the Forest Gulf of Mexico operations are recorded
by Mariner at their estimated fair values as of the date the
merger is completed.
The unaudited pro forma combined balance sheet as of
September 30, 2005 assumes the merger was completed on that
date. The unaudited pro forma combined statements of operations
gives effect to the merger as if it had been completed on
January 1, 2004. The merger agreement was executed on
September 9, 2005 and provides for Mariner to issue
approximately 50.6 million shares of common stock as
consideration to Forest Energy Resources common stockholders.
The unaudited pro forma combined financial information has been
derived from and should be read together with the historical
consolidated financial statements of Mariner and the statements
of revenues and direct operating expenses of the Forest Gulf of
Mexico operations, which are included herein. The statements of
revenues and direct operating expenses of the Forest Gulf of
Mexico operations do not include all of the costs of doing
business.
The unaudited pro forma combined condensed financial information
is for illustrative purposes only. The financial results may
have been different had the Forest Gulf of Mexico operations
been an independent company and had the companies always been
combined. You should not rely on the unaudited pro forma
combined condensed financial information as being indicative of
the historical results that would have been achieved had the
merger occurred in the past or the future financial results that
Mariner will achieve after the merger.
In addition, the purchase price allocation is preliminary and
will be finalized following the closing of the merger. The final
purchase price allocation will be determined after closing based
on the actual fair value of current assets, current liabilities,
indebtedness, long-term liabilities, proven and unproven oil and
gas properties, identifiable intangible assets and the final
number of shares of Mariner common stock issued in the merger
and for unvested stock options that are outstanding at closing.
We are continuing to evaluate all of these items; accordingly,
the final purchase price may differ in material respects from
that presented in the unaudited pro forma combined condensed
balance sheet.
The combination of the Forest Gulf of Mexico operations with
Mariners is expected to cause the average reserve life of
Mariners oil and gas properties to decrease from current
levels and to result in a higher rate of depreciation,
depletion, and amortization for the combined operations. For
example, the estimated proved reserves of the Forest Gulf of
Mexico properties as of June 30, 2005 were 328 Bcfe and
production for the six months ended June 30, 2005 (prior to
hurricane related disruptions) was approximately 40.8 Bcfe, a
reserve life on an annualized basis of 4.0. This ratio is
indicative of the relatively higher productive rates of offshore
oil and gas properties when compared to most onshore fields.
While the higher productive rates generally result in a faster
return on investment than onshore fields, they also result in a
faster depletion of the underlying proved reserves and a
resulting higher rate of depreciation, depletion, and
amortization. As of June 30, 2005, Mariners proved
reserves totaled 328 Bcfe and production for the six months
ended June 30, 2005 (prior to hurricane disruptions) was
approximately 16.5 Bcfe, a reserve life on an annualized basis
of 9.9. For the combined operations, as of June 30, 2005,
proved reserves would have totaled approximately 599 Bcfe and
production for the six months ended June 30, 2005 would
have totaled 57.3 Bcfe, a reserve life on an annualized basis of
5.7. Mariner will also write-up the Forest Gulf of Mexico
operations to estimated fair value as of the merger date, which
is also expected to cause the underlying DD&A rate to
increase for the combined operations.
44
In connection with the merger, Mariner and Mariner Energy
Resources expect to enter into a $500 million senior
secured revolving credit facility, and Mariner also expects to
obtain a $40 million senior secured letter of credit
facility. The initial borrowing base of the revolving credit
facility will be $400 million. The revolving credit
facility will mature on the fourth anniversary of the closing
and may be used for general corporate purposes. The letter of
credit facility will mature on the third anniversary of the
closing.
In connection with the spin-off and the payment of the cash
amount by Forest Energy Resources to Forest pursuant to the
distribution agreement, Forest Energy Resources intends to enter
into a new senior term loan facility with Union Bank of
California, or UBOC, as lender, in an amount equal to the lesser
of the cash amount, plus the amount of the arrangement and
upfront fees and expenses associated with the facility, and
$200 million, plus the amount of the arrangement and
upfront fees and expenses associated with the facility. At
Forest Energy Resources election, interest will be
determined by reference to (1) the UBOC Reference Rate or
(2) the London interbank offered rate, or LIBOR, plus 1.50%
per annum. In the event that any portion of the facility is
outstanding after 30 days, the interest rate will increase,
at Forest Energy Resources election, to (1) the UBOC
Reference Rate, plus 5% per annum or (2) LIBOR plus 6.50%
per annum. Interest will be payable at the applicable maturity
date for LIBOR-loans and quarterly for UBOC Reference Rate loans.
The Forest Energy Resources facility is expected to be repaid
with borrowings under Mariners and Mariner Energy
Resources $500 million revolving credit facility. The
facility will mature 90 days from closing of the spin-off
and merger and the principal will be due at maturity.
Prepayments will be permitted at any time without premium or
penalty (except for breakage and related costs associated with
prepayments of Eurodollar loans), subject to minimum amount
requirements. The facility will be unsecured with a negative
pledge on Forest Energy Resources existing oil and gas
properties and all other assets of Forest Energy Resources.
The facility will contain various covenants that limit Forest
Energy Resources ability to do the following, among other
things, except as contemplated by the distribution agreement and
the merger agreement:
|
|
|
|
|
incur indebtedness; |
|
|
|
grant certain liens; |
|
|
|
merge or consolidate with another entity; |
|
|
|
sell assets except in the ordinary course of business; |
|
|
|
make certain loans and investments; and |
|
|
|
permit trade payables to exceed 90 days. |
If an event of default exists under the facility, the lender
will be able to accelerate the maturity of the facility and
exercise other rights and remedies. Events of default include
defaults in payment or performance under the facility,
misrepresentations, cross-defaults to other debt or material
obligations of Forest Energy Resources, and insolvency, material
judgments, certain changes of ownership and any material adverse
change affecting Forest Energy Resources.
45
MARINER ENERGY, INC.
UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEET
As of September 30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mariner | |
|
|
Mariner | |
|
Merger | |
|
Pro Forma | |
|
|
Historical | |
|
Adjustments(1) | |
|
Combined | |
|
|
| |
|
| |
|
| |
|
|
(in thousands) | |
ASSETS |
Current Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
4,564 |
|
|
$ |
|
|
|
$ |
4,564 |
|
|
Receivables
|
|
|
50,259 |
|
|
|
|
|
|
|
50,259 |
|
|
Deferred tax asset
|
|
|
30,480 |
|
|
|
|
|
|
|
30,480 |
|
|
Prepaid expenses and other
|
|
|
18,732 |
|
|
|
2,874 |
(2) |
|
|
21,606 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
104,035 |
|
|
|
2,874 |
|
|
|
106,909 |
|
Property and Equipment, net
|
|
|
393,258 |
|
|
|
1,463,846 |
(3) |
|
|
1,857,104 |
|
Goodwill
|
|
|
|
|
|
|
142,000 |
(3) |
|
|
142,000 |
|
Other Assets, net of amortization
|
|
|
4,916 |
|
|
|
7,597 |
(2) |
|
|
12,513 |
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
502,209 |
|
|
$ |
1,616,317 |
|
|
$ |
2,118,526 |
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
14,573 |
|
|
$ |
|
|
|
$ |
14,573 |
|
|
Accrued liabilities
|
|
|
88,993 |
|
|
|
32,491 |
(2) |
|
|
121,484 |
|
|
Accrued interest
|
|
|
141 |
|
|
|
|
|
|
|
141 |
|
|
Derivative liability
|
|
|
76,902 |
|
|
|
108,031 |
(2) |
|
|
184,933 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
180,609 |
|
|
|
140,522 |
|
|
|
321,131 |
|
Long-Term Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Abandonment liability
|
|
|
26,314 |
|
|
|
116,203 |
(2) |
|
|
142,517 |
|
|
Deferred income tax
|
|
|
6,468 |
|
|
|
168,852 |
(4) |
|
|
175,320 |
|
|
Derivative liability
|
|
|
28,221 |
|
|
|
17,203 |
(2) |
|
|
45,424 |
|
|
Bank debt
|
|
|
75,000 |
|
|
|
200,000 |
(5) |
|
|
275,000 |
|
|
Note payable
|
|
|
4,000 |
|
|
|
|
|
|
|
4,000 |
|
|
New debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term liabilities
|
|
|
3,000 |
|
|
|
|
|
|
|
3,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
143,003 |
|
|
|
502,258 |
|
|
|
645,261 |
|
Stockholders Equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
4 |
|
|
|
5 |
(6) |
|
|
9 |
|
|
Additional paid-in capital
|
|
|
171,667 |
|
|
|
973,532 |
(3) |
|
|
1,145,199 |
|
|
Unearned compensation
|
|
|
(14,548 |
) |
|
|
|
|
|
|
(14,548 |
) |
|
Accumulated other comprehensive (loss)
|
|
|
(67,708 |
) |
|
|
|
|
|
|
(67,708 |
) |
|
Accumulated retained earnings
|
|
|
89,182 |
|
|
|
|
|
|
|
89,182 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
178,597 |
|
|
|
973,537 |
|
|
|
1,152,134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY
|
|
$ |
502,209 |
|
|
$ |
1,616,317 |
|
|
$ |
2,118,526 |
|
|
|
|
|
|
|
|
|
|
|
46
MARINER ENERGY, INC.
UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF
OPERATIONS
For the Nine Months Ended September 30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest Energy | |
|
|
|
Mariner | |
|
|
Mariner | |
|
Resources, Inc. | |
|
Merger | |
|
Pro Forma | |
|
|
Historical | |
|
Historical(7) | |
|
Adjustments(1) | |
|
Combined | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(in thousands, except per share data) | |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & gas sales
|
|
$ |
148,492 |
|
|
$ |
326,722 |
|
|
$ |
|
|
|
$ |
475,214 |
|
|
Other revenues
|
|
|
2,753 |
|
|
|
|
|
|
|
|
|
|
|
2,753 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
151,245 |
|
|
|
326,722 |
|
|
|
|
|
|
|
477,967 |
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
20,170 |
|
|
|
59,379 |
|
|
|
|
|
|
|
79,549 |
|
|
Transportation expenses
|
|
|
1,697 |
|
|
|
2,484 |
|
|
|
|
|
|
|
4,181 |
|
|
General and administrative expenses
|
|
|
26,726 |
|
|
|
|
|
|
|
|
|
|
|
26,726 |
|
|
Depreciation, depletion and amortization
|
|
|
43,457 |
|
|
|
|
|
|
|
201,255 |
(8) |
|
|
244,712 |
|
|
Impairment of production equipment held for use
|
|
|
498 |
|
|
|
|
|
|
|
|
|
|
|
498 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
92,548 |
|
|
|
61,863 |
|
|
|
201,255 |
|
|
|
355,666 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
58,697 |
|
|
|
264,859 |
|
|
|
(201,255 |
) |
|
|
122,301 |
|
Interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
696 |
|
|
|
|
|
|
|
|
|
|
|
696 |
|
|
Expense, net of amounts capitalized
|
|
|
(5,416 |
) |
|
|
|
|
|
|
(8,010 |
)(9) |
|
|
(13,426 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before taxes
|
|
|
53,977 |
|
|
|
|
|
|
|
(209,265 |
) |
|
|
109,571 |
|
Provision for income taxes
|
|
|
(18,414 |
) |
|
|
|
|
|
|
(19,936 |
)(10) |
|
|
(38,350 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
35,563 |
|
|
|
|
|
|
|
(229,201 |
) |
|
|
71,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per sharebasic
|
|
|
1.10 |
|
|
|
|
|
|
|
|
|
|
|
0.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per sharediluted
|
|
|
1.07 |
|
|
|
|
|
|
|
|
|
|
|
0.85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstandingbasic
|
|
|
32,438 |
|
|
|
|
|
|
|
50,637 |
|
|
|
83,075 |
|
Weighted average shares outstandingdiluted
|
|
|
33,313 |
|
|
|
|
|
|
|
50,637 |
|
|
|
83,950 |
|
47
MARINER ENERGY, INC.
UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF
OPERATIONS
For the Year Ended December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest Energy | |
|
|
|
Mariner | |
|
|
Mariner | |
|
Resources, Inc. | |
|
Merger | |
|
Pro Forma | |
|
|
Historical | |
|
Historical(7) | |
|
Adjustments(1) | |
|
Combined | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(in thousands, except per share data) | |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & gas sales
|
|
$ |
214,187 |
|
|
$ |
453,139 |
|
|
$ |
|
|
|
$ |
667,326 |
|
|
Other revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
214,187 |
|
|
|
453,139 |
|
|
|
|
|
|
|
667,326 |
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
25,484 |
|
|
|
81,627 |
|
|
|
|
|
|
|
107,111 |
|
|
Transportation expenses
|
|
|
3,029 |
|
|
|
2,175 |
|
|
|
|
|
|
|
5,204 |
|
|
General and administrative expenses
|
|
|
8,772 |
|
|
|
|
|
|
|
|
|
|
|
8,772 |
|
|
Depreciation, depletion and amortization
|
|
|
64,911 |
|
|
|
|
|
|
|
303,261 |
(8) |
|
|
368,172 |
|
|
Impairment of production equipment held for use
|
|
|
957 |
|
|
|
|
|
|
|
|
|
|
|
957 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
103,153 |
|
|
|
83,802 |
|
|
|
303,261 |
|
|
|
490,216 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
111,034 |
|
|
|
369,337 |
|
|
|
(303,261 |
) |
|
|
177,110 |
|
Interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
316 |
|
|
|
|
|
|
|
|
|
|
|
316 |
|
|
Expense, net of amounts capitalized
|
|
|
(6,050 |
) |
|
|
|
|
|
|
(7,840 |
)(9) |
|
|
(13,890 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before taxes
|
|
|
105,300 |
|
|
|
|
|
|
|
(311,101 |
) |
|
|
163,536 |
|
Provision for income taxes
|
|
|
(36,855 |
) |
|
|
|
|
|
|
(20,383 |
)(10) |
|
|
(57,238 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
68,445 |
|
|
|
|
|
|
|
(331,484 |
) |
|
|
106,298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per sharebasic
|
|
|
2.30 |
|
|
|
|
|
|
|
|
|
|
|
1.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per sharediluted
|
|
|
2.30 |
|
|
|
|
|
|
|
|
|
|
|
1.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstandingbasic
|
|
|
29,748 |
|
|
|
|
|
|
|
50,637 |
|
|
|
80,385 |
|
Weighted average shares outstandingdiluted
|
|
|
29,748 |
|
|
|
|
|
|
|
50,637 |
|
|
|
80,385 |
|
48
Notes to Unaudited Pro Forma Combined Condensed Financial
Data
The unaudited Mariner Pro Forma Combined financial
data have been prepared to give effect to Mariners
acquisition of the Forest Gulf of Mexico operations, which will
be spun off to Forest shareholders. Information under the
heading Merger Adjustments gives effect to the
adjustments related to the acquisition of the Forest Gulf of
Mexico operations. The unaudited pro forma combined condensed
statements are not necessarily indicative of the results of
Mariners future operations.
The unaudited pro forma combined financial information has been
derived from and should be read together with the historical
consolidated financial statements of Mariner and the statements
of revenues and direct operating expenses of the Forest Gulf of
Mexico operations. The statements of revenues and direct
operating expenses of the Forest Gulf of Mexico operations do
not include all of the costs of doing business.
|
|
(1) |
Transaction costs consisting of accounting, consulting and legal
fees are anticipated to be approximately $12 million. These
costs are directly attributable to the transaction and have been
excluded from the pro forma financial statements as they
represent material nonrecurring charges. |
|
(2) |
To record other current and long-term assets that we will
receive in the spin-off and liabilities that we will assume as a
result of the spin-off
reflected at their estimated fair market values, including
inventory of $2.1 million, abandonment escrows of
$0.7 million, gas imbalances of $7.6 million, asset
retirement obligations of $146.6 million and derivative
liabilities of $125.2 million. |
|
(3) |
To record the preliminary purchase price allocation to the fair
value of assets acquired, including oil and gas properties and
goodwill. These adjustments also adjust depreciation, depletion
and amortization expense to give effect to the acquisition of
the Forest Gulf of Mexico operations and their
step-up in value using
the unit of production method under the full cost method of
accounting. |
|
(4) |
To record the deferred tax position of the combined company,
inclusive of the deferred tax
gross-up in connection
with the acquisition. |
|
(5) |
To record $200.0 million of debt that Forest Energy
Resources, Inc. will incur under the terms of the distribution
agreement. The actual amount of debt to be incurred will be
adjusted to reflect the net cash proceeds generated by the
Forest Gulf of Mexico operations since June 30, 2005
pursuant to the terms of the distribution agreement. Mariner
plans to refinance the debt, which will mature 90 days
after the closing, with a revolving credit facility that matures
on the fourth anniversary of the closing. Forest Energy
Resources, Inc. will be primarily liable for all indebtedness
incurred in connection with the spin-off or any refinancing
thereof. |
|
(6) |
To record issuance of 50,637,010 shares of common stock at
par value of $.0001 per share. |
|
(7) |
The Forest Gulf of Mexico operations historically have been
operated as part of Forests total oil and gas operations.
No historical GAAP-basis financial statements exist for the
Forest Gulf of Mexico operations on a stand-alone basis;
however, statements of revenues and direct operating expenses
are presented for the year ended December 31, 2004
(audited) and for the nine months ended September 30,
2005 (unaudited). |
|
(8) |
To adjust depreciation, depletion and amortization expense to
give effect to the acquisition of the Forest Gulf of Mexico
operations and their
step-up in value using
the unit of production method under the full cost method of
accounting. |
|
(9) |
To adjust interest expense to give effect to the financing
activities in connection with the organization of Forest Energy
Resources, Inc. assuming an interest rate of 5.34% for the nine
months ended September 30, 2005 and 3.92% for the year
ended December 31, 2004 based on the terms of the senior
term loan facility to be obtained by Forest Energy Resources.
The interest rates used reflect
30-day LIBOR plus
1.50%, or 5.34% as of September 30, 2005 and 3.92% as of
December 31, 2004. A change in interest rates of
1/8
percent would result in a change in interest expense of
approximately $0.1 million and $0.2 million for the
nine months ended September 30, 2005, and the year ended
December 31, 2004, respectively. |
|
|
(10) |
To record income tax expense on the combined company results of
operations based on a statutory combined federal and state tax
rate of 35%. |
49
Supplemental Pro Forma Combined Oil and Gas Reserve and
Standardized Measure Information (Unaudited)
The following unaudited supplemental pro forma oil and natural
gas reserve tables present how the combined oil and gas reserve
and standardized measure information of Mariner and the Forest
Gulf of Mexico operations may have appeared had the businesses
actually been combined as of December 31, 2004. The
Supplemental Pro Forma Combined Oil and Gas Reserve and
Standardized Measure Information is for illustrative purposes
only. You should refer to footnote 10 in Mariners
Notes to the Financial Statements beginning on page
F-32 and
footnote 3 in Forests Gulf of Mexico Operations Notes
to Statements of Revenues and Direct Operating Expenses
beginning on page F-39
for additional information presented in accordance with the
requirements of Statement of Financial Accounting Standards
No. 69, Disclosures About Oil and Gas Producing Activities.
ESTIMATED PRO FORMA COMBINED QUANTITIES OF PROVED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest Energy Resources, Inc. | |
|
|
|
|
Mariner Historical | |
|
Historical | |
|
Mariner Pro Forma Combined | |
|
|
| |
|
| |
|
| |
|
|
|
|
Natural Gas | |
|
|
|
Natural Gas | |
|
|
|
Natural Gas | |
|
|
Oil | |
|
Natural Gas | |
|
Equivalent | |
|
Liquids | |
|
Natural Gas | |
|
Equivalent | |
|
Liquids | |
|
Natural Gas | |
|
Equivalent | |
|
|
(Mbbl) | |
|
(MMcf) | |
|
(Mmcfe) | |
|
(Mbbl) | |
|
(MMcf) | |
|
(Mmcfe) | |
|
(Mbbl) | |
|
(MMcf) | |
|
(Mmcfe) | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
December 31, 2003
|
|
|
13,079 |
|
|
|
127,584 |
|
|
|
206,060 |
|
|
|
11,357 |
|
|
|
295,347 |
|
|
|
363,489 |
|
|
|
24,436 |
|
|
|
422,931 |
|
|
|
569,549 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
1,249 |
|
|
|
19,797 |
|
|
|
27,291 |
|
|
|
1,693 |
|
|
|
(2,860 |
) |
|
|
7,298 |
|
|
|
2,942 |
|
|
|
16,937 |
|
|
|
34,589 |
|
Extensions, discoveries and other additions
|
|
|
2,225 |
|
|
|
28,334 |
|
|
|
41,684 |
|
|
|
630 |
|
|
|
14,449 |
|
|
|
18,229 |
|
|
|
2,855 |
|
|
|
42,783 |
|
|
|
59,913 |
|
Sales of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(2,298 |
) |
|
|
(23,782 |
) |
|
|
(37,570 |
) |
|
|
(3,230 |
) |
|
|
(61,684 |
) |
|
|
(81,064 |
) |
|
|
(5,528 |
) |
|
|
(85,466 |
) |
|
|
(118,634 |
) |
Purchases of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,200 |
|
|
|
24,556 |
|
|
|
31,756 |
|
|
|
1,200 |
|
|
|
24,556 |
|
|
|
31,756 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004
|
|
|
14,255 |
|
|
|
151,933 |
|
|
|
237,465 |
|
|
|
11,650 |
(1) |
|
|
269,808 |
|
|
|
339,708 |
|
|
|
25,905 |
(1) |
|
|
421,741 |
|
|
|
577,173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Includes 598 Mbbls of natural gas liquids. |
ESTIMATED PRO FORMA COMBINED QUANTITIES OF PROVED DEVELOPED
RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest Energy Resources, Inc. | |
|
|
|
|
Mariner Historical | |
|
Historical | |
|
Mariner Pro Forma Combined | |
|
|
| |
|
| |
|
| |
|
|
|
|
Natural Gas | |
|
|
|
Natural Gas | |
|
|
|
Natural Gas | |
|
|
Oil | |
|
Natural Gas | |
|
Equivalent | |
|
Liquids | |
|
Natural Gas | |
|
Equivalent | |
|
Liquids | |
|
Natural Gas | |
|
Equivalent | |
|
|
(Mbbl) | |
|
(MMcf) | |
|
(Mmcfe) | |
|
(Mbbl) | |
|
(MMcf) | |
|
(Mmcfe) | |
|
(Mbbl) | |
|
(MMcf) | |
|
(Mmcfe) | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
December 31, 2004
|
|
|
6,339 |
|
|
|
71,361 |
|
|
|
109,395 |
|
|
|
9,471 |
|
|
|
201,759 |
|
|
|
258,585 |
|
|
|
15,810 |
|
|
|
273,120 |
|
|
|
367,980 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50
PRO FORMA COMBINED STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ending December 31, 2004 | |
|
|
| |
|
|
|
|
Forest Energy | |
|
Mariner Pro | |
|
|
Mariner | |
|
Resources, Inc. | |
|
Forma | |
|
|
Historical | |
|
Historical | |
|
Combined | |
|
|
| |
|
| |
|
| |
Future cash inflows
|
|
$ |
1,601,240 |
|
|
$ |
2,155,217 |
|
|
$ |
3,756,457 |
|
Future production costs
|
|
|
(308,190 |
) |
|
|
(272,020 |
) |
|
|
(580,210 |
) |
Future development costs
|
|
|
(193,689 |
) |
|
|
(357,592 |
) |
|
|
(551,281 |
) |
Future income taxes
|
|
|
(285,701 |
) |
|
|
(412,477 |
) |
|
|
(698,178 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
813,660 |
|
|
|
1,113,128 |
|
|
|
1,926,788 |
|
Discount of future net cash flows at 10% per annum
|
|
|
(319,278 |
) |
|
|
(187,291 |
) |
|
|
(506,569 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$ |
494,382 |
|
|
$ |
925,837 |
|
|
$ |
1,420,219 |
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of period
|
|
$ |
418,159 |
|
|
$ |
949,421 |
|
|
$ |
1,367,580 |
|
Increase (decrease) in discounted future net cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced, net of production
costs
|
|
|
(185,673 |
) |
|
|
(426,405 |
) |
|
|
(612,078 |
) |
|
Net changes in prices and production costs
|
|
|
27,767 |
|
|
|
11,628 |
|
|
|
39,395 |
|
|
Extensions and discoveries, net of future development and
production costs
|
|
|
102,905 |
|
|
|
88,999 |
|
|
|
191,904 |
|
|
Development costs during period and net change in development
costs
|
|
|
44,417 |
|
|
|
79,642 |
|
|
|
124,059 |
|
|
Revision of previous quantity estimates
|
|
|
89,814 |
|
|
|
28,701 |
|
|
|
118,515 |
|
|
Sales of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in income taxes
|
|
|
(27,634 |
) |
|
|
(28,550 |
) |
|
|
(56,184 |
) |
|
Purchases of reserves in place
|
|
|
|
|
|
|
100,681 |
|
|
|
100,681 |
|
|
Accretion of discount before income taxes
|
|
|
41,816 |
|
|
|
121,720 |
|
|
|
163,536 |
|
|
Changes in production rates (timing) and other
|
|
|
(17,189 |
) |
|
|
|
|
|
|
(17,189 |
) |
|
|
|
|
|
|
|
|
|
|
Balance, end of period
|
|
$ |
494,382 |
|
|
$ |
925,837 |
|
|
$ |
1,420,219 |
|
|
|
|
|
|
|
|
|
|
|
51
STRENGTHS AND STRATEGIES OF MARINER FOLLOWING THE MERGER
Following the merger we expect Mariner to be an independent oil
and gas exploration, development and production company focused
offshore in the Gulf of Mexico and onshore in the Permian Basin
of West Texas. On a pro forma basis as of December 31,
2004, the combined company had 577 Bcfe of estimated proved
reserves. Approximately 64% of these reserves were developed;
36% were undeveloped. Approximately 73% of our estimated proved
reserves were natural gas and natural gas liquids, and 27% were
oil and condensate. The reserves are geographically distributed
approximately 62% on the Gulf of Mexico shelf, 18% in the Gulf
of Mexico deepwater and 20% in the Permian Basin in West Texas.
As of December 31, 2004, the pro forma PV10 of the combined
company was approximately $1.9 billion, and the pro forma
standardized measure of discounted future net cash flows
attributable to its estimated proved reserves was approximately
$1.4 billion. Please see BusinessEstimated
Proved Reserves and The Forest Gulf of Mexico
OperationsEstimated Proved Reserves for a definition
of PV10 and reconciliations of PV10 to the standardized measure
of discounted future net cash flows.
Mariner is focused on the generation and development of new Gulf
of Mexico deepwater, deep shelf and shelf projects and the
development of its existing asset base in West Texas.
Historically, Mariner has achieved growth through the drill bit;
however, as part of our growth strategy, we also seek to acquire
assets that provide acceptable risk-adjusted rates of return and
have significant potential for further reserve additions through
development and exploitation activities.
We believe Mariners core resources and strengths include:
|
|
|
|
|
our high-quality assets with geographic and geological diversity; |
|
|
|
our successful track record of finding and developing oil and
gas reserves; and |
|
|
|
our depth of operating experience. |
The integration and further development and exploitation of the
Forest Gulf of Mexico operations into our business will further
diversify and, in our view, complement our existing business,
provide additional resources for future growth beyond the
producing assets acquired, and afford a larger scale to increase
our ability to compete effectively. We expect the effectiveness
of our growth strategy to be enhanced by the addition of the
Forest Gulf of Mexico assets.
High-Quality Assets. We believe our asset base has
significant potential:
|
|
|
|
|
Our deepwater projects have the potential to provide large
reserves, high production volumes and substantial cash flow.
Approximately 65 Bcfe of our undeveloped estimated proved
reserves as of December 31, 2004, are located in our
high-impact deepwater projectsSwordfish, Pluto, Rigel,
Baccarat, and Daniel Boone. The Baccarat project commenced
production in July 2005 (although production was shut-in due to
Hurricane Rita and recommenced in January 2006), and the
Swordfish project commenced production in October 2005.
Notwithstanding delays caused primarily by 2005 hurricane
activity, we believe Pluto and Rigel will commence production in
the second quarter of 2006. Proved undeveloped reserves
attributable to those projects have been recategorized as proved
developed reserves. Daniel Boone is currently scheduled for
production in 2008. |
|
|
|
The Gulf of Mexico is an area that offers substantial growth
opportunities, and we expect to continue to generate shelf, deep
shelf and deepwater Gulf of Mexico prospects. The Forest Gulf of
Mexico assets will more than double our existing undeveloped
acreage position to approximately 465,000 net acres and
increase our total net leasehold acreage offshore to nearly
1 million acres, providing numerous exploration,
exploitation and development opportunities. We believe the
additional acreage also will provide increased exposure to
farm-out opportunities from other oil and gas operators. Our
team of geoscientists currently has access to seismic data from
multiple, recent vintage 3-D seismic databases covering
more than 6,600 blocks in the Gulf of Mexico that we intend
to continue to use to develop prospects on acreage being
evaluated for leasing and to develop and further refine
prospects on our expanded acreage position. The combination of
our |
52
|
|
|
|
|
undeveloped acreage position, inventory of development
prospects, seismic data and technical knowledge should enhance
our ability to select projects with the greatest return
potential for future development. We will also gain access to a
significant infrastructure in the shelf that we believe will
provide substantial cost efficiencies to the combined operations. |
|
|
|
Our West Texas assets provide stable cash flow and long-lived
reserves, with significant development opportunities. In West
Texas, during the three years ended December 31, 2004, we
drilled 105 wells, all commercially successful, added
approximately 76 Bcfe of estimated proved reserves, and
increased our average daily production by more than 400%. Our
52 Bcfe of undeveloped estimated proved reserves in West
Texas includes 162 locations. Our recent West Texas
acquisition adds to our asset base an approximate 35% working
interest in over 200 existing producing wells and, we
believe, will provide future infill development opportunities,
much like our Aldwell unit. This recent acquisition, in
conjunction with our existing West Texas acreage, gives Mariner
an inventory of multi-year development drilling opportunities. |
Successful Track Record of Finding and Developing Oil and Gas
Reserves. In the three-year period ended December 31,
2004, Mariner deployed approximately $337 million of
capital on acquisitions, exploration and development, while
adding approximately 191 Bcfe of proved reserves and
producing approximately 111 Bcfe. In addition to our
successful West Texas drilling program, in the three-year period
ended December 31, 2004, we have participated in the
drilling of 33 exploration wells in the Gulf of Mexico,
with 15 of these wells resulting in the discovery of commercial
oil and gas reserves.
Our technical professionals average more than 20 years of
experience in the exploration and production business, much of
it with major oil companies, including extensive experience in
the Gulf of Mexico. The addition of experienced Forest personnel
to Mariners team of geoscientists and technical and
operational professionals should further enhance our ability to
generate and maintain an inventory of high-quality drillable
prospects and to further develop and exploit our assets.
We seek to mitigate our risk in drilling projects by entering
into arrangements with industry partners in which they agree to
pay a disproportionate share of dry hole costs and compensate us
for expenses incurred in prospect generation. We intend to
continue our practice of sharing costs of offshore exploration
and development activities by selling interests in projects to
industry partners. From time to time, we may sell entire
interests in offshore prospects in order to better diversify our
portfolio. We also enter into trades or farm-in transactions
whereby we acquire interests in third-party generated prospects.
We expect more opportunities to participate in these prospects
as a result of the scale and increased cash flow the merger will
bring.
Depth of Operating Experience. Our engineers have
extensive experience in offshore Gulf of Mexico completion and
production techniques, both in the deepwater and on the shelf.
We have extensive experience and a successful track record in
the use of subsea tieback technology to connect offshore wells
to existing production facilities. This technology facilitates
production from offshore properties without the necessity of
fabrication and installation of more costly platforms and top
side facilities that typically require longer lead times. We
believe the use of subsea tiebacks in appropriate projects
enables us to bring production online more quickly, makes target
prospects more profitable, and allows us to exploit reserves
that may otherwise be considered non-commercial because of the
high cost of infrastructure. In the Gulf of Mexico, in the three
years ended December 31, 2004, we were directly involved in
thirteen projects (five of which we operated) utilizing subsea
tieback systems in water depths ranging from 475 feet to
more than 7,000 feet, and in five projects (three of which
we operated) developed through the use of platforms.
Mariner has proven to be an effective and efficient operator in
West Texas, as evidenced by our results there in recent years.
In addition to conducting a successful drilling program,
increasing our production and expanding our asset base, we have
improved our net operating margin by reducing our operating
costs and increasing our realized share of production.
53
We expect that our acquisition of the Forest Gulf of Mexico
assets and the scale it brings to our business will:
|
|
|
|
|
reduce our concentration risk; |
|
|
|
provide many exploration, exploitation and development
opportunities; |
|
|
|
enable us to increase the number of our internally-generated
prospects; |
|
|
|
expand our sphere of influence and enhance our ability to
participate in prospects generated by other operators; and |
|
|
|
add a significant cash flow generating resource that will
improve our ability to compete effectively in the Gulf of Mexico
and provide funding for acquisition projects. |
We believe we are well positioned to optimize the Forest Gulf of
Mexico assets through aggressive and timely exploitation. Our
diverse, high-quality assets, our ability to find and develop
oil and gas reserves, and our operating experience should
provide a strong platform from which to grow and create value
for our shareholders.
54
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
On March 2, 2004, Mariners former indirect parent,
Mariner Energy LLC, merged with MEI Acquisitions, LLC, an
affiliate of the private equity funds, Carlyle/ Riverstone
Global Energy and Power Fund II, L.P. and ACON Investments
LLC. Prior to the merger, we were owned indirectly by JEDI,
which was an indirect wholly-owned subsidiary of Enron Corp. The
gross merger consideration was $271.1 million (which
excludes $7.0 million of acquisition costs and other
expenses paid directly by Mariner), $100 million of which
was provided as equity by our new owners. As a result of the
merger, we are no longer affiliated with Enron Corp. See
BusinessEnron Related Matters. The merger did
not result in a change in our strategic direction or operations.
The financial information contained herein is presented in the
style of Pre-2004 Merger activity (for all periods prior to
March 2, 2004) and Post-2004 Merger activity (for the
March 3, 2004 through December 31, 2004 period) to
reflect the impact of the restatement of assets and liabilities
to fair value as required by push-down purchase
accounting at the March 2, 2004 merger date. The
application of push-down accounting had no effect on our 2004
results of operations other than immaterial increases in
depreciation, depletion and amortization expense and interest
expense and a related decrease in our provision for income
taxes. To facilitate managements discussion and analysis
of financial condition and results of operations, we have
presented 2004 financial information as Pre-2004 Merger (for the
January 1 through March 2, 2004 period), Post-2004 Merger
(for the March 3, 2004 through December 31, 2004
period), Combined (for the full period from January 1 through
December 31, 2004), Post-2004 Merger (for the March 3,
2004 through September 30, 2004 period) and Combined (for
the full period from January 1, 2004 through
September 30, 2004). The combined presentation does not
reflect the adjustments to our statement of operations that
would be reflected in a pro forma presentation. However, because
such adjustments are not material, we believe that our combined
presentation presents a fair presentation and facilitates an
understanding of our results of operations.
In March 2005, we completed a private placement of
16,350,000 shares of our common stock to qualified
institutional buyers,
non-U.S. persons
and accredited investors, which generated approximately
$229 million of gross proceeds, or approximately
$211 million net of initial purchasers discount,
placement fee and offering expenses. Our former sole
stockholder, MEI Acquisitions Holdings, LLC, also sold
15,102,500 shares of our common stock in the private
placement. We used $166 million of the net proceeds from
the sale of 12,750,000 shares of common stock to purchase
and retire an equal number of shares of our common stock from
our former sole stockholder. We used $39 million of the
remaining net proceeds of approximately $45 million to
repay borrowings drawn on our credit facility, and the balance
to pay down $6 million of a $10 million promissory
note payable to JEDI. See BusinessEnron Related
Matters. As a result, after the private placement, an
affiliate of MEI Acquisitions Holdings, LLC beneficially owned
approximately 5.3% of our outstanding common stock. See
Security Ownership of Certain Beneficial Owners and
Management.
We are an independent oil and natural gas exploration,
development and production company with principal operations in
the Gulf of Mexico and the Permian Basin in West Texas. In the
Gulf of Mexico, our areas of operation include the deepwater and
the shelf area. We have been active in the Gulf of Mexico and
West Texas since the mid-1980s. During the last three years, as
a result of increased drilling of shelf prospects and
development drilling in our Aldwell Unit, we have evolved from a
company with primarily a deepwater focus to one with a balance
of exploitation and exploration of the Gulf of Mexico deepwater
and shelf, and longer-lived Permian Basin properties.
Our revenues, profitability and future growth depend
substantially on prevailing prices for oil and gas and our
ability to find, develop and acquire oil and gas reserves that
are economically recoverable while controlling and reducing
costs. The energy markets have historically been very volatile.
Commodity prices are currently at or near historical highs and
may fluctuate and decline significantly in the future. Although
we attempt to mitigate the impact of price declines through our
hedging strategy, a substantial or extended
55
decline in oil and natural gas prices or poor drilling results
could have a material adverse effect on our financial position,
results of operations, cash flows, quantities of natural gas and
oil reserves that we can economically produce and our access to
capital.
Approximately 29 Mmcfe per day of natural gas and
approximately 3,000 bbls per day of oil and condensate net
to our interest were initially shut-in as a result of the
effects of Hurricane Katrina in August 2005. The majority of
this production was returned within two weeks of the hurricane,
and substantially all within three weeks of the hurricane.
Additionally, we are experiencing delays in startup of three of
our projects primarily as a result of Hurricane Katrina which is
anticipated to defer commencement of production to as late as
the second quarter of 2006. Approximately 60 MMcfe per day
of production net to our interest was shut-in initially as a
result of the effects of Hurricane Rita in late September 2005.
Approximately 53 MMcfe per day of production, or
approximately 90% of our pre-hurricane production, was restored
within two weeks of the hurricane. Our operated platforms appear
to have sustained minimal damage attributable to the storm.
First reports from operators of other facilities handling our
production indicated varying degrees of damage to their
facilities, the full extent of which may not be known for some
time. Although a submersible rig engaged in drilling operations
on our East Cameron Block 79 property was moved off
location by Hurricane Rita, a substitute rig was subsequently
provided, the damage to the well was repaired and drilling
recommenced in the last quarter of 2005. Other planned
operations also are delayed as a result of the effects of both
hurricanes. We cannot estimate a range of loss arising from the
hurricanes until we are able to more completely assess the
impacts on our properties and the properties of our operational
partners. Until we are able to complete all the repair work and
submit costs to our insurance underwriters for review, the full
extent of our insurance recovery and the resulting net cost to
us for Hurricanes Katrina and Rita will be unknown. For the
insurance period ending September 30, 2005, we carry a
$3.0 million annual deductible and a $.375 million
single occurrence deductible.
We entered into an agreement effective in October 2005 covering
approximately 33,000 acres in West Texas, pursuant to
which, upon closing, we acquired an approximate 35% working
interest in approximately 200 existing producing wells effective
November 1, 2005, and committed to drill an additional 150
wells within a four year period, funding $36.5 million of
our partners share of drilling costs for such 150-well
drilling program. We will obtain an assignment of an approximate
35% working interest in the entire committed acreage upon
completion of the 150-well program.
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Nine Months Ended September 30, 2005
Highlights |
During the first nine months of 2005, we recognized net income
of $35.6 million on total revenues of $151.2 million
compared to net income of $50.5 million on total revenues of
$162.3 million in the first nine months of 2004. Net income
decreased 30% compared to the first nine months of 2004,
primarily due to recognizing $17.6 million of stock
compensation expense in the first nine months of 2005, and a 21%
decrease in production, partially offset by higher realized net
oil and gas prices. We produced approximately 22.5 Bcfe during
the first nine months of 2005 and our average daily production
rate was 82 Mmcfe compared to 28.4 Bcfe, or
104 Mmcfe per day, for the same period in 2004. Production
during the third quarter of 2005 was negatively impacted by the
effects of the 2005 hurricane season. We invested approximately
$130.3 million in oil and natural gas properties in the
first nine months of 2005, compared to $101.0 million in
the same period in 2004.
Our first nine months 2005 results reflect the private placement
of an additional 3.6 million shares of stock in March. The
net proceeds of approximately $45 million generated by the
private placement were used to repay existing debt. We also
granted 2,267,270 shares of restricted stock and options to
purchase 809,000 shares of stock in the first nine months of
2005 and recorded compensation expense of $17.6 million in
the first nine months of 2005 related to the restricted stock
and options.
56
We recognized net income of $68.4 million in 2004 compared
to net income of $38.2 million in 2003. The increase in net
income was primarily the result of improvements in operating
results, including a 13% increase in production volumes, a 21%
improvement in the net commodity prices realized by us (before
the effects of hedging) and an 8% decrease in lease operating
expenses and transportation expenses on a per unit basis. These
improvements were partially offset by an 8% increase in general
and administrative expenses and a 34% increase in
depreciation, depletion, and amortization expenses. Our hedging
results also improved by $9.7 million to a
$19.8 million loss, from a $29.5 million loss in the
prior year. In addition, we recorded income tax expenses of
$36.9 million in 2004 compared to $9.4 million in 2003.
We have incurred and expect to continue to incur substantial
capital expenditures. However, for the three years ended
December 31, 2004, our capital expenditures of
$337.3 million have been below our combined cash flow from
operations and proceeds from property sales.
During 2004, we increased our proved reserves by approximately
69 Bcfe, bringing estimated proved reserves as of
December 31, 2004 to approximately 237.5 Bcfe after
2004 production of 37.6 Bcfe.
We had $2.5 million and $60.2 million in cash and cash
equivalents as of December 31, 2004 and December 31,
2003, respectively.
Three of our shelf properties, Ewing Bank 977 (Dice), West
Cameron 333 (Royal Flush) and High Island 46 (Green Pepper)
began producing in the first quarter of 2005. Our production for
the first nine months of 2005 averaged approximately
53 MMcf of natural gas per day and approximately
4,900 barrels of oil per day or a total of approximately
82 MMcfe per day.
In the third quarter of 2005 our production was negatively
impacted by Hurricanes Katrina and Rita. Production shut-in and
deferred because of the hurricanes impact totaled
approximately 1.3 Bcfe during the third quarter of 2005.
Currently approximately 7 MMcfe per day of production remains
shut-in awaiting repairs, primarily associated with our Baccarat
property. While we believe physical damage to our existing
platforms and facilities was relatively minor from both
hurricanes, the effects of the storms caused damage to onshore
pipeline and processing facilities that resulted in a portion of
our production being temporarily shut-in, or in the case of our
Viosca Knoll 917 (Swordfish) project, postponed. In addition,
Hurricane Katrina caused damage to platforms that host three of
our development projects: Mississippi Canyon 718 (Pluto),
Mississippi Canyon 296 (Rigel), and Mississippi Canyon 66
(Ochre). Repairs to these facilities may take up to six months,
pushing commencement of production on these projects into 2006.
Our December 2004 total production averaged approximately
58 MMcf of natural gas per day and approximately
5,700 barrels of oil per day or total equivalents of
approximately 92 MMcfe per day. Natural gas production
comprised approximately 63% of total production. In September
2004, Mariner incurred damage from Hurricane Ivan that affected
our Mississippi Canyon 66 (Ochre) and Mississippi
Canyon 357 fields. Production from Mississippi Canyon
357 was shut-in until March 2005, when necessary repairs were
completed and production recommenced. Production from
Mississippi Canyon 66 (Ochre) remains shut-in and is
expected to recommence in the first quarter of 2006. This field
was producing at a net rate of approximately 6.5 MMcfe per
day immediately prior to the hurricane.
Historically, a majority of our total production has been
comprised of natural gas. We anticipate that our concentration
in natural gas production will continue. As a result,
Mariners revenues, profitability and cash flows will be
more sensitive to natural gas prices than to oil and condensate
prices.
Generally, our producing properties in the Gulf of Mexico will
have high initial production rates followed by steep declines.
As a result, we must continually drill for and develop new oil
and gas reserves to replace those being depleted by production.
Substantial capital expenditures are required to find and
57
develop these reserves. Our challenge is to find and develop
reserves at economic rates and commence production of these
reserves as quickly and efficiently as possible.
Deepwater discoveries typically require a longer lead time to
bring to productive status. Since 2001, we have made several
deepwater discoveries that are in various stages of development.
We commenced production at our Green Canyon 178 (Baccarat)
project in the third quarter of 2005. However, damage sustained
by the host facility during Hurricane Rita caused production to
be shut-in. Production is expected to recommence in the first
quarter of 2006. We commenced production at our Swordfish
project in the fourth quarter of 2005. We currently anticipate
commencing production in the second quarter of 2006 at our
Pluto, Rigel and Ewing Banks 921 (North Black Widow) projects.
However, as described above, Hurricanes Katrina and Rita have
delayed start up of these projects from their original
anticipated commencement dates. Other uncertainties, including
scheduling, weather, and construction lead times, could cause
further delays in the start up of any one or all of the projects.
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Oil and Gas Property Costs |
In the nine months ended September 30, 2005, we incurred
approximately $130.4 million in capital expenditures with
70% related to development activities primarily at our Aldwell
Unit and for our Viosca Knoll 917 (Swordfish), Mississippi
Canyon 718 (Pluto) and Mississippi Canyon 296 (Rigel) offshore
projects. We also expended $10.0 million for the
acquisition of oil and gas property interests in the first nine
months of 2005, comprised of $3.5 million for properties
located in the West Texas Permian Basin area, $5.0 million
for Atwater Valley 426 (Bass Lite) and $1.5 million for
East Breaks 513/514/558 (LaSalle). We incurred approximately
$23.6 million of exploration capital expenditures in the
first nine months of 2005.
During 2004, we incurred approximately $148.9 million in
capital expenditures with 60% related to development activities,
32% related to exploration activities, including the acquisition
of leasehold and seismic, and the remainder related to
acquisitions and other items (primarily capitalized overhead and
interest).
We spent approximately $88.6 million in development capital
expenditures in 2004 primarily on Aldwell Unit development and
for Viosca Knoll 917 (Swordfish), Mississippi Canyon 718
(Pluto), and West Cameron 333 (Royal Flush) offshore projects.
All capital expenditures for exploration activities relate to
offshore projects, and approximately 30% of exploration capital
expended during 2004 was for leasehold, seismic, and geological
and geophysical costs. During 2004 we participated in fourteen
exploration wells, with seven being successful. We incurred
approximately $47.9 million of exploration capital
expenditures in 2004.
We anticipate that, based on our current budget, capital
expenditures in 2005 will approximate $250 million with
approximately 48% allocated to development projects, 27% to
exploration activities, 21% to acquisitions and the remainder to
other items (primarily capitalized overhead and interest).
However, the effects of Hurricanes Katrina and Rita may delay
some planned operations into 2006.
We have maintained our reserve base through exploration and
exploitation activities despite selling 79.7 Bcfe of our
reserves since the fourth quarter of 2001. Historically, we have
not acquired significant reserves through acquisition
activities. As of December 31, 2004, Ryder Scott estimated
our net proved reserves at approximately 237.5 Bcfe, with a
PV10 of approximately $668 million and a standardized
measure of discounted future net cash flows attributable to our
estimated proved reserves of approximately $494.4 million.
Please see BusinessEstimated Proved Reserves
for a definition of PV10 and a reconciliation of PV10 to the
standardized measure of discounted future net cash flows. To
generate our net proved reserves as of June 30, 2005, our
management reviewed and updated our historical lease operating
expenses, updated our transportation and basis differentials,
updated NYMEX prices, adjusted for roll-off and production
performance since December 31, 2004, added any new proved
undeveloped reserves (including those resulting from our Bass
Lite project), updated the categorization of our projects
58
as either proved undeveloped, proved developed producing or
proved behind pipe, and adjusted capital expenditures and timing
of cash outlays. See BusinessEstimated Proved
Reserves for more information concerning our reserve
estimates.
The development drilling at our West Texas Aldwell Unit and Gulf
of Mexico deepwater divestitures have significantly changed our
reserve profile since 2001. Proved reserves as of
December 31, 2004 were comprised of 48% West Texas Permian
Basin, 15% Gulf of Mexico shelf and 37% Gulf of Mexico deepwater
compared to 20% West Texas Permian Basin, 15% Gulf of Mexico
shelf and 65% Gulf of Mexico deepwater as of December 31,
2001. Proved undeveloped reserves were approximately 54% of
total proved reserves as of December 31, 2004.
Approximately 39% of proved undeveloped reserves were related to
our West Texas Aldwell Unit, where we had 100% development
drilling success on 105 wells from 2002 through 2004.
Since December 31, 1997, we have added proved undeveloped
reserves attributable to 12 deepwater projects. Of those
projects, ten have either been converted to proved developed
reserves or sold as indicated in the following table.
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Net Proved |
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Undeveloped |
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Reserves |
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Year |
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Property |
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(Bcfe)(1) |
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Added |
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Year Converted to Proved Developed or Sold |
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Mississippi Canyon 718 (Pluto)(2)
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25.1 |
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1998 |
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2000 (100% converted to proved developed) |
Ewing Bank 966 (Black Widow)
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14.0 |
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1999 |
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2000 (100% converted to proved developed) |
Mississippi Canyon 773 (Devils Tower)
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28.0 |
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2000 |
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2001 (100% of Mariners interest sold) |
Mississippi Canyon 305 (Aconcagua)
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19.2 |
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2000 |
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2001 (100% of Mariners interest sold) |
Green Canyon 472/473 (King Kong)
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25.5 |
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2000 |
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2002 (100% converted to proved developed) |
Green Canyon 516 (Yosemite)
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14.9 |
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2001 |
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2002 (100% converted to proved developed) |
East Breaks 579 (Falcon)
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66.8 |
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2001 |
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2002 (50% of Mariners interest sold)
2003 (all of Mariners remaining interest sold) |
Viosca Knoll 917 (Swordfish)
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13.4 |
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2001 |
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2005 (100% converted to proved developed) |
Green Canyon 178 (Baccarat)
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4.0 |
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2004 |
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2005 (100% converted to proved developed) |
Mississippi Canyon 296/252 (Rigel)
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22.4 |
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2003 |
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2005 (75% converted to proved developed/ 25% remains
undeveloped) |
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(1) |
Net proved undeveloped reserves attributable to the project in
the year it was first added to our proved reserves. |
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(2) |
This field was shut-in in April 2004 pending the drilling of a
new well and installation of an extension to the existing
infield flowline and umbilical. As a result, as of
December 31, 2004, 9.0 Bcfe of our net proved reserves
attributable to this project were classified as proved
undeveloped reserves. We expect production from Pluto to
recommence in the second quarter of 2006. |
The proved undeveloped reserves attributable to the remaining
two deepwater projects were added as follows:
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Net Proved |
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Undeveloped |
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Year Expected to |
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Reserves |
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Year |
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Convert to Proved |
Property |
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(Bcfe)(1) |
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Added |
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Developed Status |
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Green Canyon 646 (Daniel Boone)
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16.4 |
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2003 |
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2007 |
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Atwater Valley 380/381/382/425/426 (Bass Lite)
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30.7 |
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2005 |
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2007 |
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(1) |
Net proved undeveloped reserves attributable to the project as
of June 30, 2005. |
59
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Oil and Natural Gas Prices and Hedging Activities |
Prices for oil and natural gas can fluctuate widely, thereby
affecting the amount of cash flow available for capital
expenditures, our ability to borrow and raise additional capital
and the amount of oil and natural gas that we can economically
produce. Recently, oil and natural gas prices have been at or
near historical highs and very volatile as a result of various
factors, including weather, industrial demand, war and political
instability and uncertainty related to the ability of the energy
industry to provide supply to meet future demand.
Our revenues, profitability and future growth depend
substantially on prevailing prices for oil and gas and our
ability to find, develop and acquire oil and gas reserves that
are economically recoverable while controlling and reducing
costs. A substantial or extended decline in oil and natural gas
prices or poor drilling results could have a material adverse
effect on our financial position, results of operations, cash
flows, quantities of oil and natural gas reserves that we can
economically produce and access to capital.
We enter into hedging arrangements from time to time to reduce
our exposure to fluctuations in oil and natural gas prices.
Typically, our hedging strategy involves entering into commodity
price swap arrangements and costless collars with third parties.
Price swap arrangements establish a fixed price and an
index-related price for the covered commodity. When the
index-related price exceeds the fixed price, we pay the third
party the difference, and when the fixed price exceeds the
index-related prices, the third party pays us the difference.
Costless collars establish fixed cap (maximum) and floor
(minimum) prices as well as an index-related price for the
covered commodity. When the index-related price exceeds the
fixed cap price, we pay the third party the difference, and when
the index-related price is less than the fixed floor price, the
third party pays us the difference. While our hedging
arrangements enable us to achieve a more predictable cash flow,
these arrangements also limit the benefits of increased prices.
As a result of increased oil and natural gas prices, we incurred
cash hedging losses of $27.7 million in 2004, of which
$7.9 million relates to the hedge liability recorded at the
March 2, 2004 merger date. Major challenges related to our
hedging activities include a determination of the proper
production volumes to hedge and acceptable commodity price
levels for each hedge transaction. Our hedging activities may
also require that we post cash collateral with our
counterparties from time to time to cover credit risk. We had no
collateral requirements as of December 31, 2004 or
September 30, 2005.
In accordance with purchase price accounting implemented at the
time of the merger of our former indirect parent company on
March 2, 2004, we recorded the
mark-to-market
liability of our hedge contracts at such date totaling
$12.4 million as a liability on our balance sheet. As of
December 31, 2004, the amount of our
mark-to-market hedge
liabilities totaled $22.4 million. See
Liquidity and Capital ResourcesCommodity
Prices and Related Hedging Activities.
For the year ended December 31, 2004, assuming a totally
unhedged position, our price sensitivity for 2004 historical net
revenues for a 10% change in average oil prices and average gas
prices received is approximately $8.9 million and
$14.5 million, respectively. For the nine months ended
September 30, 2005, assuming a totally unhedged position,
our price sensitivity for net revenues in the first nine months
of 2005 for a 10% change in average oil prices and average gas
prices received is approximately $6.7 million and
$10.5 million, respectively.
We classify our operating costs as lease operating expense,
transportation expense, and general and administrative expenses.
Lease operating expenses are comprised of those costs and
expenses necessary to produce oil and gas after an individual
well or field has been completed and prepared for production.
These costs include direct costs such as field operations,
general maintenance expenses, work-overs, and the costs
associated with production handling agreements for most of our
deep water fields. Lease operating expenses also include
indirect costs such as oil and gas property insurance and
overhead allocations in accordance with joint operating
agreements. We also include severance, production, and ad
valorem taxes as lease operating expenses.
60
Transportation costs are generally variable costs associated
with transportation of product to sales meters from the wellhead
or field gathering point. General and administrative include
employee compensation costs (including stock compensation
expense), the costs of third party consultants and
professionals, rent and other costs of leasing and maintaining
office space, the costs of maintaining computer hardware and
software, and insurance and other items.
Critical Accounting Policies and Estimates
Our discussion and analysis of Mariners financial
condition and results of operations are based upon financial
statements that have been prepared in accordance with GAAP in
the U.S. The preparation of these financial statements
requires us to make estimates and judgments that affect the
reported amounts of assets, liabilities, revenues and expenses.
Our significant accounting policies are described in Note 1
to our financial statements. We analyze our estimates, including
those related to oil and gas revenues, oil and gas properties,
fair value of derivative instruments, income taxes and
contingencies and litigation, and base our estimates on
historical experience and various other assumptions that we
believe to be reasonable under the circumstances. Actual results
may differ from these estimates under different assumptions or
conditions. We believe the following critical accounting
policies affect our more significant judgments and estimates
used in the preparation of our financial statements:
Oil and gas properties are accounted for using the full-cost
method of accounting. All direct costs and certain indirect
costs associated with the acquisition, exploration and
development of oil and gas properties are capitalized.
Amortization of oil and gas properties is provided using the
unit-of-production
method based on estimated proved oil and gas reserves. No gains
or losses are recognized upon the sale or disposition of oil and
gas properties unless the sale or disposition represents a
significant quantity of oil and gas reserves, which would have a
significant impact on depreciation, depletion and amortization.
The net carrying value of proved oil and gas properties is
limited to an estimate of the future net revenues (discounted at
10%) from proved oil and gas reserves based on period-end prices
and costs.
The costs of unproved properties are excluded from amortization
using the full-cost method of accounting. These costs are
assessed quarterly for possible inclusion in the full-cost
property pool based on geological and geophysical data. If a
reduction in value has occurred, costs being amortized are
increased. The majority of the costs relating to our unproved
properties will be evaluated over the next three years.
Our most significant financial estimates are based on estimates
of proved natural gas and oil reserves. Estimates of proved
reserves are key components of our unevaluated properties, our
rate for recording depreciation, depletion and amortization and
our full cost ceiling limitation. There are numerous
uncertainties inherent in estimating quantities of proved
reserves and in projecting future revenues, rates of production
and timing of development expenditures, including many factors
beyond our control. The estimation process relies on assumptions
and interpretations of available geologic, geophysical,
engineering and production data, and the accuracy of reserve
estimates is a function of the quality and quantity of available
data. Our reserves are fully engineered on an annual basis by
Ryder Scott, our independent petroleum engineers.
As a result of the adoption of SFAS Statement
No. 123(R), we will record compensation expense for the
fair value of restricted stock and stock options that were
granted on March 11, 2005 pursuant to our Equity
Participation Plan and Stock Incentive Plan and for the fair
value of subsequent grants of stock options or restricted stock
made pursuant to our Stock Incentive Plan. In general,
compensation expense will be determined at the date of grant
based on the fair value of the stock or options granted.
61
The fair value of restricted stock that we granted following the
closing of the private equity placement pursuant to our Equity
Participation Plan was estimated to be $31.7 million. The
fair value will be amortized to compensation expense over the
applicable vesting periods. Stock options and restricted stock
granted under our Stock Incentive Plan will also result in
recognition of compensation expense in accordance with FASB
No. 123(R). For more information concerning our Equity
Participation Plan, see Management of MarinerEquity
Participation Plan.
We recognize oil and gas revenue from our interests in producing
wells as oil and gas from those wells is produced and sold under
the entitlements method. Oil and gas volumes sold are not
significantly different from our share of production.
Our taxable income through 2004 has been included in a
consolidated U.S. income tax return with our former
indirect parent company, Mariner Energy LLC. The intercompany
tax allocation policy provides that each member of the
consolidated group compute a provision for income taxes on a
separate return basis. We record income taxes using an asset and
liability approach which results in the recognition of deferred
tax assets and liabilities for the expected future tax
consequences of temporary differences between the book carrying
amounts and the tax bases of assets and liabilities. Valuation
allowances are established when necessary to reduce deferred tax
assets to the amount more likely than not to be recovered. In
February 2005, Mariner Energy LLC was merged into us, and we
will file our own income tax return following the effective date
of that merger.
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Capitalized Interest Costs |
We capitalize interest based on the cost of major development
projects which are excluded from current depreciation,
depletion, and amortization calculations.
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Accrual for Future Abandonment Costs |
SFAS No. 143, Accounting for Asset Retirement
Obligations, addresses accounting and reporting for
obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs.
SFAS No. 143 requires that the fair value of a
liability for an assets retirement obligation be recorded
in the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present
value each period, and the capitalized cost is depreciated over
the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or
loss is recognized.
In June 1998 the FASB issued SFAS No. 133,
Accounting for Derivative Instruments and Certain Hedging
Activities. In June 2000 the FASB issued
SFAS No. 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activity, an Amendment of
SFAS No. 133. SFAS No. 133 and
SFAS No. 138 require that all derivative instruments
be recorded on the balance sheet at their respective fair values.
Mariner utilizes derivative instruments, typically in the form
of natural gas and crude oil price swap agreements and costless
collar arrangements, in order to manage price risk associated
with future crude oil and natural gas production. These
agreements are accounted for as cash flow hedges. Gains and
losses resulting from these transactions are recorded at fair
market value and deferred to the extent such amounts are
effective. Such gains or losses are recorded in AOCI as
appropriate, until recognized as operating income as the
physical production hedged by the contracts is delivered.
62
The net cash flows related to any recognized gains or losses
associated with these hedges are reported as oil and gas
revenues and presented in cash flows from operations. If the
hedge is terminated prior to expected maturity, gains or losses
are deferred and included in income in the same period as the
physical production hedged by the contracts is delivered.
The conditions to be met for a derivative instrument to qualify
as a cash flow hedge are the following: (i) the item to be
hedged exposes Mariner 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.
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Use of Estimates in the Preparation of Financial
Statements |
The preparation of financial statements in conformity with GAAP
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.
Results of Operations
For certain information with respect to our oil and natural gas
production, average sales price received and expenses per unit
of production for the three years ended December 31, 2004,
see BusinessProduction.
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Nine Months Ended September 30, 2005 compared to Nine
Months Ended September 30, 2004 |
Operating and Financial Results for the Nine Months Ended
September 30, 2005 Compared
to the Nine Months Ended September 30, 2004
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Non-GAAP | |
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Post-Merger | |
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Pre-Merger | |
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Nine Months Ended | |
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March 3, 2004 | |
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January 1, 2004 | |
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through September 30, | |
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through March 2, | |
Summary Operating Information: |
|
2005 | |
|
2004 | |
|
2004 | |
|
2004 | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(in thousands, except average sales price) | |
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,336 |
|
|
|
1,748 |
|
|
|
1,335 |
|
|
|
413 |
|
Natural gas (MMcf)
|
|
|
14,508 |
|
|
|
17,959 |
|
|
|
13,726 |
|
|
|
4,233 |
|
Total (Mmcfe)
|
|
|
22,521 |
|
|
|
28,444 |
|
|
|
21,731 |
|
|
|
6,713 |
|
Average daily production (Mmcfe/d)
|
|
|
82 |
|
|
|
104 |
|
|
|
102 |
|
|
|
112 |
|
Hedging activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues (loss)
|
|
$ |
(13,421 |
) |
|
$ |
(6,874 |
) |
|
$ |
(6,188 |
) |
|
$ |
(686 |
) |
Gas revenues (loss)
|
|
|
(9,979 |
) |
|
|
(1,010 |
) |
|
|
(2,441 |
) |
|
|
1,431 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total hedging revenues (loss)
|
|
$ |
(23,400 |
) |
|
$ |
(7,884 |
) |
|
$ |
(8,629 |
) |
|
$ |
745 |
|
63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP | |
|
|
|
|
|
|
|
|
Combined | |
|
Post-Merger | |
|
Pre-Merger | |
|
|
|
|
| |
|
| |
|
| |
|
|
Nine Months Ended | |
|
Period from | |
|
Period from | |
|
|
September 30, | |
|
March 3, 2004 | |
|
January 1, 2004 | |
|
|
| |
|
through September 30, | |
|
through March 2, | |
Summary Operating Information: |
|
2005 | |
|
2004 | |
|
2004 | |
|
2004 | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(in thousands, except average sales price) | |
Average Sales Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) realized(1)
|
|
$ |
40.12 |
|
|
$ |
32.78 |
|
|
$ |
33.41 |
|
|
$ |
30.75 |
|
Oil (per Bbl) unhedged
|
|
|
50.17 |
|
|
|
36.71 |
|
|
|
38.05 |
|
|
|
32.41 |
|
Natural gas (per Mcf) realized(1)
|
|
|
6.54 |
|
|
|
5.85 |
|
|
|
5.68 |
|
|
|
6.39 |
|
Natural gas (per Mcf) unhedged
|
|
|
7.23 |
|
|
|
5.90 |
|
|
|
5.86 |
|
|
|
6.05 |
|
Total natural gas equivalent ($/Mcfe) realized(1)
|
|
|
6.59 |
|
|
|
5.71 |
|
|
|
5.64 |
|
|
|
5.92 |
|
Total natural gas equivalent ($/Mcfe) unhedged
|
|
|
7.63 |
|
|
|
5.98 |
|
|
|
6.04 |
|
|
|
5.81 |
|
Oil and gas revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$ |
53,579 |
|
|
$ |
57,285 |
|
|
$ |
44,576 |
|
|
$ |
12,709 |
|
Gas sales
|
|
|
94,913 |
|
|
|
105,005 |
|
|
|
77,950 |
|
|
|
27,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas revenues
|
|
$ |
148,492 |
|
|
$ |
162,290 |
|
|
$ |
122,526 |
|
|
$ |
39,764 |
|
Other revenues
|
|
|
2,753 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
20,170 |
|
|
|
19,194 |
|
|
|
15,073 |
|
|
|
4,121 |
|
Transportation expenses
|
|
|
1,697 |
|
|
|
4,814 |
|
|
|
3,744 |
|
|
|
1,070 |
|
Depreciation, depletion and amortization
|
|
|
43,457 |
|
|
|
48,094 |
|
|
|
37,464 |
|
|
|
10,630 |
|
General and administrative expenses
|
|
|
26,726 |
|
|
|
7,305 |
|
|
|
6,174 |
|
|
|
1,131 |
|
Net interest expense (income)
|
|
|
4,720 |
|
|
|
4,127 |
|
|
|
4,213 |
|
|
|
(86 |
) |
Income before taxes
|
|
|
53,977 |
|
|
|
77,799 |
|
|
|
54,901 |
|
|
|
22,898 |
|
Provision for income taxes
|
|
|
18,414 |
|
|
|
27,293 |
|
|
|
19,221 |
|
|
|
8,072 |
|
|
|
(1) |
Average realized prices include the effects of hedges. |
Net production during the nine months ended
September 30, 2005 decreased approximately 21% to
22.5 Bcfe from 28.4 Bcfe in the same period of 2004
primarily due to decreased Gulf of Mexico production, partially
offset by increased onshore production. Mariners
production was negatively impacted during the third quarter of
2005 due to hurricane activity, primarily Katrina and Rita.
Production shut-in and deferred because of the hurricanes
impact totaled approximately 1.3 Bcfe during the third
quarter of 2005. As of September 30, 2005, approximately
7 MMcfe per day of production remained shut-in awaiting
repairs, primarily associated with our Baccarat property
(although, production therefrom recommenced in January 2006).
Additionally, production that was anticipated to commence in the
third quarter of 2005 at our Swordfish, Pluto, and Rigel
development projects has been delayed until the fourth quarter
of 2005 for Swordfish, and into 2006 at Pluto and Rigel,
awaiting repairs to host facilities.
Increased development drilling at our Aldwell unit in West Texas
contributed to a 61% increase in onshore production to an
average of approximately 17.1 Mmcfe per day in the first
nine months of 2005 from an average of approximately
10.5 Mmcfe per day in the first nine months of 2004.
In the deepwater Gulf of Mexico, production decreased
approximately 30% to an average of approximately 33 Mmcfe
per day in the first nine months of 2005 compared to an average
of approximately 47 Mmcfe per day in the first nine months
of 2004. The decrease was largely due to reduced production at
our Black Widow, Yosemite and Pluto fields. Pluto was shut-in in
April 2004 pending drilling of the new Mississippi Canyon
674 #3 well and installation of an extension to the
existing subsea facilities. Production at Black Widow and
Yosemite are undergoing expected declines.
64
In the Gulf of Mexico shelf, production decreased by
approximately 30% to an average of approximately 32 Mmcfe
per day in the first nine months of 2005 from an average of
approximately 46 Mmcfe per day in the first nine months of
2004. About 6.2 Mmcfe per day of the decrease is
attributable to our Ochre field which remains shut-in due to the
effects of Hurricane Ivan in September 2004. Production from
three new shelf discoveries (Green Pepper, Royal Flush, and
Dice) and production from the 2004 acquisition of interests in
five offshore fields offset normal declines at our other Gulf of
Mexico shelf fields.
Hedging activities in the first nine months of 2005
decreased our average realized natural gas price received by
$0.69 per Mcf and revenues by $10.0 million, compared
with a decrease of $0.05 per Mcf and revenues of
$1.0 million for the same period in 2004. Our hedging
activities with respect to crude oil during the first nine
months of 2005 decreased the average sales price received by
$10.05 per barrel and revenues by $13.4 million
compared with a decrease of $3.93 per barrel and revenues
of $6.9 million for the same period in 2004.
Oil and gas revenues decreased 6% to $148.5 million
in the first nine months of 2005 when compared to first nine
months 2004 oil and gas revenues of $162.3 million, due to
the aforementioned 21% decrease in production, partially offset
by a 16% increase in realized prices (including the effects of
hedging) to $6.59 per Mcfe in the first nine months of 2005
from $5.71 per Mcfe in the same period in 2004.
Other revenues of $2.7 million in the first nine
months of 2005 represent an indemnity payment received from our
former stockholder related to the merger of $1.9 million
and $0.8 million generated by our West Texas Aldwell unit
gathering system.
Lease operating expenses increased 5% to
$20.2 million in the first nine months of 2005 from
$19.2 million in the first nine months of 2004. The
increased costs were primarily attributable to the addition of
new producing wells at our Aldwell Unit offset by reduced costs
on our Black Widow, King Kong/Yosemite, and Pluto deep water
fields. On a per unit basis, lease operating expenses were $0.90
per Mcfe in the first nine months of 2005 compared to $0.67 per
Mcfe in the first nine months of 2004. The increased per unit
costs also reflect lower production rates in the 2005 period,
including hurricane-related disruptions.
Transportation expenses were $1.7 million or
$0.08 per Mcfe in the first nine months of 2005, compared
to $4.8 million or $0.17 per Mcfe in the first nine
months of 2004. The reduction is primarily attributable to our
deepwater fields and includes reductions caused by the filing of
new and higher transportation allowances with the MMS on two of
our deepwater fields for purpose of royalty calculation.
Depreciation, depletion, and amortization expense
decreased 10% to $43.5 million during the first nine
months of 2005 from $48.1 million for the first nine months
of 2004 as a result of decreased production of 5.9 Bcfe in
the first nine months of 2005 compared to the first nine months
of 2004, partially offset by an increase in the
unit-of-production
depreciation, depletion and amortization rate to $1.93 per
Mcfe for the first nine months of 2005 from $1.69 per Mcfe
for the same period in 2004. The per unit increase was primarily
the result of an increase in future development costs on our
deepwater development fields.
General and administrative expenses
(G&A), which are net of $3.1 million
and $2.2 million of overhead reimbursements billed or
received from other working interest owners in the first nine
months of 2005 and 2004, respectively, increased 266% to
$26.7 million during the first nine months of 2005 compared
to $7.3 million in the first nine months of 2004. The
increase was primarily due to recognizing $17.6 million in
stock compensation expense related to restricted stock and
options granted in the first nine months of 2005. We also paid
$2.3 million to our former stockholders to terminate a
services agreement in the first nine months of 2005, compared to
$1.0 million under the same agreement in the first nine
months of 2004. In addition, G&A expenses increased by
$1.8 million due to a reduction in the amount of G&A
capitalized in the first nine months of 2005 compared to the
first nine months of 2004.
Net interest expense for the first nine months of 2005
increased 14% to $4.7 million from $4.1 million in the
first nine months of 2004, primarily due to lower average debt
levels in the first nine months of 2004 compared to the first
nine months of 2005. In connection with the Merger on
March 2, 2004, Mariner
65
incurred $135 million in new bank debt and issued a
$10 million promissory note to JEDI. For comparison
purposes, approximately seven months of interest related to such
borrowings is reflected in the first nine months of 2004
compared to nine months of interest in 2005.
Income before income taxes decreased to
$54.0 million for the first nine months of 2005 compared to
$77.8 million for the same period in 2004, attributable
primarily to the decrease in oil and gas revenues resulting from
the decreased production and increased G&A expenses, both as
noted above. Offsetting these factors were the receipt of other
income related to the indemnity payment and lower DD&A and
transportation expenses.
Provision for income taxes decreased to
$18.4 million for the first nine months of 2005 from
$27.3 million for the first nine months of 2004 as a result
of decreased operating income for the nine months ended
September 30, 2005 compared to the prior period.
|
|
|
Year Ended December 31, 2004 compared to Year Ended
December 31, 2003 |
Operating and Financial Results for the Year Ended
December 31, 2004 Compared to
the Year Ended December 31, 2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP | |
|
|
|
|
|
|
|
|
Combined | |
|
Post-Merger | |
|
Pre-Merger | |
|
|
|
|
| |
|
| |
|
| |
|
|
|
|
Period from | |
|
Period from | |
|
|
Year Ended December 31, | |
|
March 3, 2004 | |
|
January 1, 2004 | |
|
|
| |
|
through December 31, | |
|
through March 2, | |
Summary Operating Information: |
|
2003 | |
|
2004 | |
|
2004 | |
|
2004 | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(in thousands, except average sales price) | |
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,600 |
|
|
|
2,298 |
|
|
|
1,885 |
|
|
|
413 |
|
Natural gas (MMcf)
|
|
|
23,772 |
|
|
|
23,782 |
|
|
|
19,549 |
|
|
|
4,233 |
|
Total (Mmcfe)
|
|
|
33,374 |
|
|
|
37,569 |
|
|
|
30,856 |
|
|
|
6,713 |
|
Average daily production (Mmcfe/d)
|
|
|
91 |
|
|
|
103 |
|
|
|
101 |
|
|
|
112 |
|
Hedging activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues (loss)
|
|
$ |
(4,969 |
) |
|
$ |
(12,299 |
) |
|
$ |
(11,613 |
) |
|
$ |
(686 |
) |
Gas revenues (loss)
|
|
|
(24,494 |
) |
|
|
(7,498 |
) |
|
|
(8,929 |
) |
|
|
1,431 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total hedging revenues (loss)
|
|
$ |
(29,463 |
) |
|
$ |
(19,797 |
) |
|
$ |
(20,542 |
) |
|
$ |
745 |
|
Average Sales Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) realized(1)
|
|
$ |
23.74 |
|
|
$ |
33.17 |
|
|
$ |
33.69 |
|
|
$ |
30.75 |
|
Oil (per Bbl) unhedged
|
|
|
26.85 |
|
|
|
38.52 |
|
|
|
39.85 |
|
|
|
32.41 |
|
Natural gas (per Mcf) realized(1)
|
|
|
4.40 |
|
|
|
5.80 |
|
|
|
5.67 |
|
|
|
6.39 |
|
Natural gas (per Mcf) unhedged
|
|
|
5.43 |
|
|
|
6.12 |
|
|
|
6.13 |
|
|
|
6.05 |
|
Total natural gas equivalent ($/Mcfe) realized(1)
|
|
|
4.27 |
|
|
|
5.70 |
|
|
|
5.65 |
|
|
|
5.92 |
|
Total natural gas equivalent ($/Mcfe) unhedged
|
|
|
5.15 |
|
|
|
6.23 |
|
|
|
6.32 |
|
|
|
5.81 |
|
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP | |
|
|
|
|
|
|
|
|
Combined | |
|
Post-Merger | |
|
Pre-Merger | |
|
|
|
|
| |
|
| |
|
| |
|
|
|
|
Period from | |
|
Period from | |
|
|
Year Ended December 31, | |
|
March 3, 2004 | |
|
January 1, 2004 | |
|
|
| |
|
through December 31, | |
|
through March 2, | |
Summary Operating Information: |
|
2003 | |
|
2004 | |
|
2004 | |
|
2004 | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(in thousands, except average sales price) | |
Oil and gas revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$ |
37,992 |
|
|
$ |
76,207 |
|
|
$ |
63,498 |
|
|
$ |
12,709 |
|
Gas sales
|
|
|
104,551 |
|
|
|
137,980 |
|
|
|
110,925 |
|
|
|
27,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas revenues
|
|
$ |
142,543 |
|
|
$ |
214,187 |
|
|
$ |
174,423 |
|
|
$ |
39,764 |
|
Lease operating expenses
|
|
|
24,719 |
|
|
|
25,484 |
|
|
|
21,363 |
|
|
|
4,121 |
|
Transportation expenses
|
|
|
6,252 |
|
|
|
3,029 |
|
|
|
1,959 |
|
|
|
1,070 |
|
Depreciation, depletion and amortization
|
|
|
48,339 |
|
|
|
64,911 |
|
|
|
54,281 |
|
|
|
10,630 |
|
General and administrative expenses
|
|
|
8,098 |
|
|
|
8,772 |
|
|
|
7,641 |
|
|
|
1,131 |
|
Impairment of production equipment held for use
|
|
|
|
|
|
|
957 |
|
|
|
957 |
|
|
|
|
|
Net interest expense (income)
|
|
|
6,225 |
|
|
|
5,734 |
|
|
|
5,820 |
|
|
|
(86 |
) |
Income before taxes and change in accounting method
|
|
|
45,688 |
|
|
|
105,300 |
|
|
|
82,402 |
|
|
|
22,898 |
|
Provision for income taxes
|
|
|
9,387 |
|
|
|
36,855 |
|
|
|
28,783 |
|
|
|
8,072 |
|
|
|
(1) |
Average realized prices include the effects of hedges. |
Net production during 2004 increased to 37.6 Bcfe
from 33.4 Bcfe during 2003 primarily due to the
commencement of production on our Roaring Fork and Ochre
projects, offset by normal production declines on existing
fields.
Hedging activities in 2004 decreased our average realized
natural gas price received by $0.32 per Mcf and revenues by
$7.5 million, compared with a decrease of $1.03 per
Mcf and revenues of $24.5 million for 2003. Our hedging
activities with respect to crude oil during 2004 decreased the
average sales price received by $5.35 per bbl and revenues
by $12.3 million compared with a decrease of $3.11 per
bbl and revenues of $5.0 million for 2003.
Oil and gas revenues increased 50% to $214.2 million
during 2004 when compared to 2003 oil and gas revenues of
$142.5 million, due to a 13% increase in production and a
33% increase in realized prices (including the effects of
hedging) to $5.70 per Mcfe in 2004 from $4.27 per Mcfe
in 2003.
Lease operating expenses increased 3% to
$25.5 million in 2004 from $24.7 million in 2003 due
to increased activity in our West Texas Aldwell project,
partially offset by lower compression costs on our
King Kong and Yosemite projects and the shut-in of our
Pluto project for a large portion of 2004 pending the drilling
and completion of the Mississippi Canyon 674 No. 3 well,
which has been drilled and awaits installation of flowlines and
related facilities.
Transportation expenses were $3.0 million for 2004,
compared to $6.3 million for 2003. In the fourth quarter of
2004, we filed new transportation allowances with the MMS for
purpose of royalty calculation. This resulted in a
$3.2 million decrease in transportation expense in 2004
compared to 2003. In addition, transportation expense from our
new Roaring Fork field was offset by declines from our existing
fields.
Depreciation, depletion, and amortization expense
increased 34% to $64.9 million during 2004 from
$48.3 million for 2003 as a result of an increase in the
unit-of-production
depreciation, depletion and amortization rate to $1.73 per
Mcfe from $1.45 per Mcfe for the comparable period and a
production increase of 4.2 Bcfe in 2004 compared to 2003.
The per unit increase is primarily attributable to non-cash
purchase accounting adjustments resulting from the merger.
67
G&A, which is net of $4.4 million of overhead
reimbursements received from other working interest owners,
increased 8% to $8.8 million during 2004 compared to
$8.1 million in 2003 primarily due to increased
compensation costs paid in connection with the merger and
payments made pursuant to services contracts with affiliates of
our sole stockholder, offset by increased overhead recoveries
from our partners and amounts capitalized.
Impairment of production equipment held for use reflects
the reduction of the carrying cost of our inventory as of
December 31, 2004 by $1.0 million to account for a
reduction in estimated value primarily related to subsea trees
held in inventory.
Net interest expense for 2004 decreased 8% to
$5.7 million from $6.2 million for 2003, primarily due
to the repayment of our senior subordinated notes in August
2003, replaced by lower-cost bank debt in March 2004.
Income before income taxes and change in accounting method
increased to $105.3 million for 2004 compared to
$45.7 million in 2003, attributable primarily to the
increase in oil and gas revenues resulting from the increased
production and realized prices noted above.
Provision for income taxes increased to
$36.9 million for 2004 from $9.4 million for 2003 as a
result of increased current year operating income.
|
|
|
Year Ended December 31, 2003 Compared to Year Ended
December 31, 2002 |
Net production decreased during 2003 to 33.4 Bcfe
from 39.8 Bcfe in 2002. Production from new drilling in our
onshore Aldwell project and offshore Roaring Fork and Vermilion
143 projects was offset by production declines in other fields
and loss of production from our offshore Pluto project during
the first seven months of 2003 as a result of a flowline
mechanical problem that required extended maintenance.
Hedging activities in 2003 decreased our average realized
natural gas price received by $1.03 per Mcf and revenues by
$24.5 million, compared with an increase of $0.68 per
Mcf and revenues of $20.3 million in 2002. Our hedging
activities with respect to crude oil during 2003 decreased the
average sales price received by $3.11 per bbl and revenues
by $5.0 million compared with an increase of $1.25 per
bbl and revenues of $2.1 million in 2002.
Oil and gas revenues decreased 10% to $142.5 million
in 2003 from $158.2 million in 2002 (including the effects
of hedge gains and losses), due to a 16% decrease in production
offset by an 8% increase in average realized prices to
$4.27 per Mcfe in 2003 from $3.97 per Mcfe in 2002
including the effects of hedging gains and losses.
Lease operating expenses decreased 5% to
$24.7 million in 2003 from $26.1 million in 2002 due
to the reduced chemical requirements at our King Kong and
Yosemite projects offset by higher chemical costs at our Pluto
field.
Transportation expenses decreased 40% to
$6.3 million for 2003 from $10.5 million for 2002. The
decrease was primarily attributable to lower minimum fees
required under the transportation agreement for our Pluto
project.
Depreciation, depletion, and amortization expense
decreased 32% to $48.3 million for 2003 from
$70.8 million for 2002 as a result of the decrease in the
unit-of-production
depreciation, depletion and amortization rate to $1.45 per
Mcfe from $1.78 per Mcfe and 6.4 Bcfe of less
production in 2003 compared to 2002. The primary driver behind
the reduced DD&A rate per Mcfe was the reduction of our full
cost pool and concurrent reduction of proved reserves by the
proceeds from the sale of an interest in the Falcon and Harrier
properties in 2003.
Early derivative settlements of non hedge designated
instruments resulted in a loss of $3.2 million in 2003.
There were no similar transactions in 2002.
G&A, which is net of $1.8 million of overhead
reimbursements received from other working interest owners,
increased 5% to $8.1 million for 2003 from
$7.7 million for 2002. The increase was comprised of
68
an 11% reduction in gross G&A (before capitalized items and
overhead recoveries) driven primarily by reduced professional
service costs and office rent, offset by higher employee
compensation costs, which included retention payments. The
reduction in gross G&A was offset by reduced overhead
recoveries and capitalized items compared to 2002.
Net interest expense for 2003 decreased 37% to
$6.2 million from $9.9 million for 2002, primarily due
to mid-year retirement of our senior subordinated notes.
Income before income taxes and change in accounting method
increased to a net income of $45.7 million for 2003
from $30.0 million in 2002, primarily as a result of 30%
higher operating income (primarily driven by lower DD&A
partially offset by lower oil and gas revenues) all as described
more fully above.
Provision for income taxes increased to $9.4 million
in 2003 as a result of Mariner utilizing all of its net
operating losses. The provision for income taxes in 2002 was $0.
Liquidity and Capital Resources
Working capital at September 30, 2005 was negative
$30.2 million, excluding current derivative liabilities and
related tax effects. Accounts payable and accrued liabilities at
September 30, 2005 increased by approximately 23% over
levels at December 31, 2004 primarily due to increased
current obligations for our Swordfish and Pluto development
projects at quarter end. As of December 31, 2004, we had
negative working capital of approximately $18.7 million
compared to positive working capital of $38.3 million at
December 31, 2003, in each case excluding current
derivative liabilities and restricted cash. The reduction in
working capital from the prior year is primarily the result of a
change in the manner Mariner utilizes excess cash. At year-end
2003, Mariner operated with no debt and consequently accumulated
cash (approximately $60 million at year-end 2003) generated
by operations and asset sales in order to fund future
obligations and business activities. In March 2004, Mariner
entered into a revolving credit facility, and since then has
utilized excess cash to pay down outstanding advances to
maintain debt levels as low as possible. In addition, our
accounts payable and accrued liabilities at December 31,
2004 increased by about 32% over levels at December 31,
2003 primarily as a result of funding for development of our
deepwater projects in progress at year end.
Our 2004 capital expenditures were $148.9 million.
Approximately 60% of our capital expenditures were incurred for
development projects, 32% for exploration activities and the
remainder for acquisitions and other items (primarily
capitalized overhead and interest).
We anticipate that our capital expenditures for 2005 will
approximate $250 million with approximately 48%
allocated to development projects, 27% to exploration
activities, 21% to acquisitions and the remainder to other items
(primarily capitalized overhead and interest). This is an
increase of approximately $98 million over our original
2005 budget. The increase is primarily driven by acquisitions of
interests in properties, by new drilling projects at LaSalle/ NW
Nansen, and by the cost of remediating a flow line obstruction
at our Pluto project.
With the anticipated increase in capital expenditures and
reduced production, partially from the impact of hurricanes,
cash flows generated by operations for 2005 will not be
sufficient to fund our 2005 capital expenditures. Any
requirements for funding that exceed our cash flows will be
funded through additional borrowings under our existing
revolving credit facility. We currently have a borrowing base of
$185 million with approximately $75 million drawn as
of September 30, 2005. Because of increased capital
expenditures in the fourth quarter of 2005 (including about $40
million for acquisitions) and reduced cash flows, borrowings
under the revolving credit facility increased to approximately
$152.0 million by year-end 2005.
However, the timing of expenditures (especially regarding
deepwater projects) is unpredictable. Also, our cash flows are
heavily dependent on the oil and natural gas commodity markets
and our ability to
69
hedge oil and natural gas prices is limited by our revolving
credit facility to no more than 80% of our expected production
from proved developed producing reserves. If either oil or
natural gas commodity prices decrease from their current levels,
our ability to finance our planned capital expenditures could be
affected negatively. Furthermore, amounts available for
borrowing under our revolving credit facility are largely
dependent on our level of proved reserves and current oil and
natural gas prices. If either our proved reserves or commodity
prices decrease, amounts available to us to borrow under our
revolving credit facility could be negatively affected. If our
cash flows are less than anticipated or amounts available for
borrowing under our revolving credit facility are reduced, we
may be forced to defer planned capital expenditures.
In addition, our future oil and natural gas production depends
on our success in finding or acquiring additional reserves. If
we fail to replace reserves through drilling or acquisitions,
our cash flows will be affected adversely. In general,
production from oil and natural gas properties declines as
reserves are depleted, with the rate of decline depending on
reservoir characteristics. Our total proved reserves decline as
reserves are produced unless we conduct other successful
exploration and development activities or acquire properties
containing proved reserves, or both. Our ability to make the
necessary capital investment to maintain or expand our asset
base of oil and natural gas reserves would be impaired to the
extent cash flow from operations is reduced and external sources
of capital become limited or unavailable. We may not be
successful in exploring for, developing or acquiring additional
reserves.
Our existing proved reserves are comprised of West Texas and
Gulf of Mexico properties. The West Texas properties are
relatively long-life in nature characterized by relatively low
decline rates (lower productive rates) while the Gulf of Mexico
properties are shorter-life in nature characterized by
relatively high decline rates (higher productive rates). For the
nine months ended September 30, 2005, our Gulf of Mexico
properties comprised about 79% of our total production. We plan
to maintain an active drilling program on our onshore properties
with the intention of maintaining or increasing production in
those areas. Although production from our existing offshore
wells will decline more rapidly over time than our onshore
wells, the percentage of production attributable to our offshore
wells is expected to increase in the coming years as more of our
undeveloped deep water projects commence production. While we
expect this trend to continue for the near future, oil and gas
production (especially for our offshore properties) can be
heavily affected by reservoir characteristics and unforeseen
events (such as hurricanes and other casualties), so we can not
predict with any certainty the timing of declines in production
or the commencement of production from new projects.
In conjunction with the March 2004 merger, we established a new
credit facility maturing on March 2, 2007. The new credit
facility was fully drawn at inception for $135 million. See
Credit Facility. In addition, we issued a
$10 million promissory note to JEDI as part of the merger
consideration. See BusinessEnron Related
Matters and JEDI Term Promissory Note.
This note matures in March 2006. Net proceeds from a private
equity placement were approximately $45 million, of which
$6 million was used to pay down the JEDI promissory note
with the remainder used to pay down the credit facility.
For the year ended December 31, 2004 and the nine months
ended September 30, 2005, our interest rate sensitivity for
a change in interest rates of
1/8
percent on average outstanding debt under our credit facility is
approximately $0.2 million and $0.1 million,
respectively. The LIBOR rate on which our bank borrowings are
primarily based was 4.19% as of November 23, 2005.
70
We had a net cash outflow of $57.6 million in 2004,
compared to a net cash inflow of $41.8 million in 2003 and
a net cash inflow of $6.5 million in 2002. A discussion of
the major components of cash flows for these periods follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-Merger | |
|
|
|
|
|
|
| |
|
|
Combined | |
|
Post-Merger | |
|
|
|
|
|
|
| |
|
| |
|
|
|
Year Ended | |
|
|
|
|
Period from | |
|
Period from | |
|
December 31, | |
|
|
Year Ended | |
|
March 3, 2004 to | |
|
January 1, 2004 to | |
|
| |
|
|
December 31, 2004 | |
|
December 31, 2004 | |
|
March 2, 2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(in millions) | |
Cash flows provided by operating activities
|
|
$ |
156.2 |
|
|
$ |
135.9 |
|
|
$ |
20.3 |
|
|
$ |
103.5 |
|
|
$ |
60.3 |
|
Cash flows provided by operating activities in 2004 increased by
$52.7 million compared to 2003 primarily due to improved
operating results and net income driven by increased production
volumes and higher net oil and natural gas prices realized by
Mariner.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-Merger | |
|
|
|
|
|
|
| |
|
|
Combined | |
|
Post-Merger | |
|
|
|
|
|
|
| |
|
| |
|
|
|
Year Ended | |
|
|
|
|
Period from | |
|
Period from | |
|
December 31, | |
|
|
Year Ended | |
|
March 3, 2004 to | |
|
January 1, 2004 to | |
|
| |
|
|
December 31, 2004 | |
|
December 31, 2004 | |
|
March 2, 2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(in millions) | |
Cash flows used in (provided by) investing activities
|
|
$ |
148.9 |
|
|
$ |
133.6 |
|
|
$ |
15.3 |
|
|
$ |
(38.3 |
) |
|
$ |
53.8 |
|
Cash flows used in investing activities in 2004 increased by
$187.2 million compared to 2003 due to increased capital
expenditures in 2004 and the sale of assets in prior years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-Merger | |
|
|
|
|
|
|
| |
|
|
Combined | |
|
Post-Merger | |
|
|
|
|
|
|
| |
|
| |
|
|
|
Year Ended | |
|
|
|
|
Period from | |
|
Period from | |
|
December 31, | |
|
|
Year Ended | |
|
March 3, 2004 to | |
|
January 1, 2004 to | |
|
| |
|
|
December 31, 2004 | |
|
December 31, 2004 | |
|
March 2, 2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(in millions) | |
Cash flows used in financing activities
|
|
$ |
(64.9 |
) |
|
$ |
(64.9 |
) |
|
|
|
|
|
$ |
(100.0 |
) |
|
|
|
|
Cash flows used in financing activities in 2004 decreased by
$35.1 million compared to 2003 as a result of a
$166 million dividend to our former indirect parent used to
help repay a term loan to an affiliate of Enron Corp. and
the placement of our revolving credit facility.
|
|
|
Commodity Prices and Related Hedging Activities |
The energy markets have historically been very volatile, and
there can be no assurance that oil and gas prices will not be
subject to wide fluctuations in the future. In an effort to
reduce the effects of the volatility of the price of oil and
natural gas on our operations, management has adopted a policy
of hedging oil and natural gas prices from time to time
primarily through the use of commodity price swap agreements and
costless collar arrangements. While the use of these hedging
arrangements limits the downside risk of adverse price
movements, it also limits future gains from favorable movements.
71
As of September 30, 2005, Mariner had the following hedge
contracts outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2005 | |
|
|
|
|
Fixed | |
|
Fair Value | |
Fixed Price Swaps |
|
Quantity | |
|
Price | |
|
Gain/(Loss) | |
|
|
| |
|
| |
|
| |
|
|
|
|
|
|
(in millions) | |
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 1December 31, 2005
|
|
|
138,000 |
|
|
$ |
25.22 |
|
|
$ |
(5.7 |
) |
|
January 1December 31, 2006
|
|
|
140,160 |
|
|
|
29.56 |
|
|
|
(5.2 |
) |
Natural Gas (MMBtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 1December 31, 2005
|
|
|
1,352,400 |
|
|
|
5.00 |
|
|
|
(12.3 |
) |
|
January 1December 31, 2006
|
|
|
1,827,547 |
|
|
|
5.53 |
|
|
|
(13.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$ |
(36.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2005 | |
|
|
|
|
|
|
|
|
Fair Value | |
Costless Collars |
|
Quantity | |
|
Floor | |
|
Cap | |
|
Gain/(Loss) | |
|
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
(in millions) | |
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 1December 31, 2005
|
|
|
57,960 |
|
|
$ |
35.60 |
|
|
$ |
44.77 |
|
|
$ |
(1.2 |
) |
|
January 1December 31, 2006
|
|
|
251,850 |
|
|
|
32.65 |
|
|
|
41.52 |
|
|
|
(6.2 |
) |
|
January 1December 31, 2007
|
|
|
202,575 |
|
|
|
31.27 |
|
|
|
39.83 |
|
|
|
(4.8 |
) |
Natural Gas (MMBtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 1December 31, 2005
|
|
|
2,189,600 |
|
|
|
6.01 |
|
|
|
8.02 |
|
|
|
(12.3 |
) |
|
January 1December 31, 2006
|
|
|
7,347,450 |
|
|
|
5.78 |
|
|
|
7.85 |
|
|
|
(29.1 |
) |
|
January 1December 31, 2007
|
|
|
5,310,750 |
|
|
|
5.49 |
|
|
|
7.22 |
|
|
|
(14.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(68.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2004, Mariner had the following hedge
contracts outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 | |
|
|
|
|
Fixed | |
|
Fair Value | |
Fixed Price Swaps |
|
Quantity | |
|
Price | |
|
Gain/(Loss) | |
|
|
| |
|
| |
|
| |
|
|
|
|
|
|
(in millions) | |
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1December 31, 2005
|
|
|
606,000 |
|
|
$ |
26.15 |
|
|
$ |
(10.0 |
) |
|
January 1December 31, 2006
|
|
|
140,160 |
|
|
|
29.56 |
|
|
|
(1.5 |
) |
Natural Gas (MMBtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1December 31, 2005
|
|
|
8,670,159 |
|
|
|
5.41 |
|
|
|
(7.0 |
) |
|
January 1December 31, 2006
|
|
|
1,827,547 |
|
|
|
5.53 |
|
|
|
(1.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$ |
(20.4 |
) |
|
|
|
|
|
|
|
|
|
|
72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 | |
|
|
|
|
|
|
|
|
Fair Value | |
Costless Collars |
|
Quantity | |
|
Floor | |
|
Cap | |
|
Gain/(Loss) | |
|
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
(in millions) | |
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1December 31, 2005
|
|
|
229,950 |
|
|
$ |
35.60 |
|
|
$ |
44.77 |
|
|
$ |
(0.4 |
) |
|
January 1December 31, 2006
|
|
|
251,850 |
|
|
|
32.65 |
|
|
|
41.52 |
|
|
|
(0.7 |
) |
|
January 1December 31, 2007
|
|
|
202,575 |
|
|
|
31.27 |
|
|
|
39.83 |
|
|
|
(0.6 |
) |
Natural Gas (MMBtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1December 31, 2005
|
|
|
2,847,000 |
|
|
|
5.73 |
|
|
|
7.80 |
|
|
|
0.4 |
|
|
January 1December 31, 2006
|
|
|
3,514,950 |
|
|
|
5.37 |
|
|
|
7.35 |
|
|
|
(0.3 |
) |
|
January 1December 31, 2007
|
|
|
1,806,750 |
|
|
|
5.08 |
|
|
|
6.26 |
|
|
|
(0.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(2.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
We have reviewed the financial strength of our hedge
counterparties and believe our credit risk to be minimal. Under
the terms of some of these transactions, from time to time we
may be required to provide security in the form of cash or
letters of credit to our counterparties. As of December 31,
2004 and September 30, 2005, we had no deposits for
collateral.
The following table sets forth the results of third party
hedging transactions during the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(dollars in millions) | |
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantity settled (MMBtus)
|
|
|
18,823,063 |
|
|
|
25,520,000 |
|
|
|
|
|
Increase (Decrease) in Natural Gas Sales
|
|
$ |
(10.8 |
) |
|
$ |
(27.1 |
) |
|
|
|
|
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantity settled (Mbbls)
|
|
|
1,554 |
|
|
|
730 |
|
|
|
353 |
|
Increase (Decrease) in Crude Oil Sales
|
|
$ |
(16.9 |
) |
|
$ |
(5.0 |
) |
|
$ |
(0.8 |
) |
In accordance with purchase price accounting implemented at the
time of the merger of our former indirect parent on
March 2, 2004, we recorded the
mark-to-market
liability of our hedge contracts at such date totaling
$12.4 million as a liability on our balance sheet. See
Critical Accounting Policies and
EstimatesHedging Program. For the year ended
December 31, 2004, $7.9 million of the
$27.7 million of cash hedge losses relate to the liability
recorded at the time of the merger.
Borrowings under our revolving credit the facility, discussed
below, mature on March 2, 2007, and bear interest at either
a LIBOR-based rate or a prime-based rate, at our option, plus a
specified margin. Both options expose us to risk of earnings
loss due to changes in market rates. We have not entered into
interest rate hedges that would mitigate such risk.
We have a revolving credit facility which provides up to
$200 million of revolving borrowing capacity, subject to a
borrowing base limitation. We currently expect to replace this
credit facility when the merger is completed. See
Financing Arrangements Relating to the Spin-Off and the
Merger beginning on page 138. The borrowing capacity
is currently subject to a borrowing base of $185 million.
The borrowing base is subject to redetermination by the lenders
quarterly; provided however, if at least $10 million of
unused availability exists, the borrowing base will be
redetermined semi-annually. The borrowing base is
73
based upon the evaluation by the lenders of our oil and gas
reserves and other factors. Any increase in the borrowing base
requires the consent of all lenders.
Borrowings under the facility bear interest, at our option, at a
rate of (i) LIBOR plus 2.00% to 2.75% depending upon
utilization, or (ii) the greater of (a) the Federal
Funds Rate plus 0.50% or (b) the Reference Rate, plus 0.00%
to 0.50% depending upon utilization.
Substantially all of our assets, other than the assets securing
the term promissory note issued to JEDI, are pledged to secure
the credit facility and obligations under hedging arrangements
with members of our bank group. In addition, both of our
subsidiaries, Mariner Energy Texas LP and Mariner LP LLC, have
guaranteed our obligations under the credit facility. We must
pay a commitment fee of 0.25% to 0.50% per year on the
unused availability under the credit facility, depending upon
utilization.
The credit facility contains various restrictive covenants and
other usual and customary terms and conditions of a revolving
credit facility, including limitations on the payment of cash
dividends and other restricted payments, limitations on the
incurrence of additional debt, prohibitions on the sale of
assets, and requirements for hedging a portion of our oil and
natural gas production. Financial covenants require us to, among
other things:
|
|
|
|
|
maintain a ratio, as of the last day of each fiscal quarter, of
(a) current assets (excluding cash posted as collateral to
secure hedging obligations) plus unused availability under the
credit facility to (b) current liabilities (excluding the
current portion of debt and current portion of hedge
liabilities) of not less than 1.00 to 1.00; |
|
|
|
maintain a ratio, as of the last day of each fiscal quarter, of
(a) EBITDA (earnings before interest, taxes, depreciation,
amortization and depletion) to (b) the sum of interest
expense and maintenance capital expenditures for such period and
20% (on an annualized basis) of outstanding advances, of not
less than 1.20 to 1.00; and |
|
|
|
maintain a ratio, as of the last day of each fiscal quarter, of
(a) total debt to (b) EBITDA of not greater than 1.75
to 1.00 prior to the issuance of bonds as described in the
credit agreement and 3.00 to 1.00 thereafter. |
The credit facility also contains customary events of default,
including the occurrence of a change of control or default by us
in the payment or performance of any other indebtedness equal to
or exceeding $2.0 million.
As of September 30, 2005, $75.0 million was
outstanding under the credit facility, and the weighted average
interest rate was 5.84%. This debt matures on March 2,
2007. Because of increased capital expenditures in the fourth
quarter of 2005 (including about $40 million for
acquisitions) and reduced cash flows, borrowings under the
revolving credit facility increased to approximately
$152.0 million by year-end 2005.
Our management is considering a possible sale in a private
placement of between $150 and $250 million in aggregate
principal amount of notes. The notes would not be registered
under the Securities Act or any state securities laws and may
not be offered or sold in the United States absent registration
or an applicable exemption from registration. We expect that the
notes would be offered only to qualified institutional buyers
under Rule 144A and non-U.S. persons under
Regulation S. We anticipate that the net proceeds from the
offering would be used to repay borrowings under our credit
facility, and that the terms of the notes would be no more
restrictive than the terms of our credit facility.
|
|
|
JEDI Term Promissory Note |
As part of the merger consideration payable to JEDI, we issued a
term promissory note to JEDI in the amount of $10 million.
The note matures on March 2, 2006, and bears interest,
payable in kind at our option, at a rate of 10% per annum
until March 2, 2005, and 12% per annum thereafter
unless paid in cash in which event the rate remains 10% per
annum. We have chosen to pay the interest in cash rather than in
kind. The JEDI note is secured by a lien on three of our
properties with no proved reserves located
74
in the Gulf of Mexico. We can offset against the note the amount
of certain claims for indemnification that can be asserted
against JEDI under the terms of the merger agreement. The JEDI
term promissory note contains customary events of default,
including an event of default triggered by the occurrence of an
event of default under our credit facility. We used
$6 million of the proceeds from the recent private equity
placement to repay a portion of the JEDI note. As of
September 30, 2005, $4 million was still outstanding
under the JEDI note.
|
|
|
Capital Expenditures and Capital Resources |
The following table presents major components of our capital
expenditures for each of the three years in the period ended
December 31, 2004.
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-Merger | |
|
|
|
|
|
|
| |
|
|
Combined | |
|
Post-Merger | |
|
|
|
|
|
|
| |
|
| |
|
|
|
Year Ended | |
|
|
|
|
Period from | |
|
Period from | |
|
December 31, | |
|
|
Year Ended | |
|
March 3, 2004 to | |
|
January 1, 2004 | |
|
| |
|
|
December 31, 2004 | |
|
December 31, 2004 | |
|
to March 2, 2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(in millions) | |
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Leasehold acquisition
|
|
$ |
4.8 |
|
|
$ |
4.4 |
|
|
$ |
0.4 |
|
|
$ |
4.8 |
|
|
$ |
14.9 |
|
|
Oil and natural gas exploration
|
|
|
43.0 |
|
|
|
35.9 |
|
|
|
7.1 |
|
|
|
26.8 |
|
|
|
25.5 |
|
Oil and natural gas development
|
|
|
88.6 |
|
|
|
82.0 |
|
|
|
6.6 |
|
|
|
44.3 |
|
|
|
55.3 |
|
Proceeds from property conveyances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(121.6 |
) |
|
|
(52.3 |
) |
Acquisitions
|
|
|
4.9 |
|
|
|
4.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other items (primarily capitalized overhead and interest)
|
|
|
7.6 |
|
|
|
6.4 |
|
|
|
1.2 |
|
|
|
7.4 |
|
|
|
10.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures, net of proceeds from property
conveyances
|
|
$ |
148.9 |
|
|
$ |
133.6 |
|
|
$ |
15.3 |
|
|
$ |
(38.3 |
) |
|
$ |
53.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our net capital expenditures for 2004 increased by
$187.2 million, as compared to 2003, as a result of
increased exploration and development expenditures with no
offsetting proceeds from property conveyances in 2004.
Our net capital expenditures for 2003 decreased
$92.1 million as compared to 2002 as a result of higher
proceeds from property conveyances and overall lower capital
expenditures as result of our shift to a more balanced portfolio
among Gulf of Mexico deepwater and shelf and onshore properties.
We had no long-term debt outstanding as of December 31,
2003. As of December 31, 2004, long-term debt was
$115 million. See Credit Facility.
75
Contractual Commitments
We have numerous contractual commitments in the ordinary course
of business, debt service requirements and operating lease
commitments. The following table summarizes these commitments at
December 31, 2004:
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less | |
|
|
|
|
|
|
|
|
|
|
Than One | |
|
|
|
|
|
More Than | |
|
|
Total | |
|
Year | |
|
1-3 Years | |
|
3-5 Years | |
|
5 Years | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(in millions) | |
Long-term debt obligations(1)
|
|
$ |
115.0 |
|
|
$ |
|
|
|
$ |
115.0 |
|
|
$ |
|
|
|
$ |
|
|
Interest obligations(2)
|
|
|
0.6 |
|
|
|
0.5 |
|
|
|
0.1 |
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
1.1 |
|
|
|
0.6 |
|
|
|
0.5 |
|
|
|
|
|
|
|
|
|
Abandonment liabilities
|
|
|
24.0 |
|
|
|
4.7 |
|
|
|
7.2 |
|
|
|
7.7 |
|
|
|
4.4 |
|
Derivative liability(3)
|
|
|
22.4 |
|
|
|
17.0 |
|
|
|
5.4 |
|
|
|
|
|
|
|
|
|
Other long-term liabilities
|
|
|
3.0 |
|
|
|
2.0 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash commitments
|
|
$ |
166.1 |
|
|
$ |
24.8 |
|
|
$ |
129.2 |
|
|
$ |
7.7 |
|
|
$ |
4.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
As of December 31, 2004, we had incurred debt obligations
under our credit facility and the JEDI promissory note that are
due as follows: $10 million in 2006; and $105 million
in 2007. However, we used a portion of the net proceeds of the
private equity placement to repay a portion of amounts
outstanding under our credit facility and $6 million under
the JEDI promissory note. As of November 30, 2005, we had
incurred debt obligations under our credit facility of
$75 million and under the JEDI promissory note of
$4 million. |
|
(2) |
Interest obligations represent approximately 14 months of
interest due on the JEDI promissory note at 10%. Future interest
obligations under our credit facility are uncertain, due to the
variable interest rate on fluctuating balances. Based on a 5.2%
weighted average interest rate on amounts outstanding under our
credit facility as of December 31, 2004, $5.5 million,
$5.5 million and $0.9 million would be due under the
credit facility in 2005, 2006 and 2007, respectively. |
|
(3) |
As of September 30, 2005, the fair value of the derivative
liabilities was $105.1 million, including
$76.9 million due in less than one year. |
MMS AppealMariner operates numerous properties in
the Gulf of Mexico. Two of such properties were leased from the
MMS subject to the Outer Continental Shelf Deep Water Royalty
Relief Act (the RRA). The RRA relieved the
obligation to pay royalties on certain predetermined leases
until a designated volume is produced. These two leases
contained language that limited royalty relief if commodity
prices exceeded predetermined levels. For the years 2000, 2001,
2003 and 2004, commodity prices exceeded the predetermined
levels. Management believes the MMS did not have the authority
to set pricing limits, and Mariner filed an administrative
appeal with the MMS and has withheld royalties regarding this
matter. The MMS filed a motion to dismiss our appeal with the
Department of the Interiors Board of Land Appeals. On
April 6, 2005, the Board of Land Appeals granted the
MMS motion and dismissed our appeal. On October 3,
2005, we filed suit in the U.S. District Court for the
Southern District of Texas seeking judicial review of the
dismissal of our appeal by the Board of Land Appeals. Mariner
has recorded a liability for 100% of the exposure on this matter
which on September 30, 2005 was $14.6 million. For
additional information concerning the contested royalty payments
and the MMSs demands, see BusinessLegal
Proceedings below.
Off-Balance Sheet Arrangements
Transportation ContractIn 1999, Mariner constructed
a 29-mile flowline from
a third party platform to the Mississippi Canyon 674 subsea
well. After commissioning, MEGS LLC, an Enron affiliate,
purchased the flowline from Mariner and its joint interest
partner. In addition, Mariner entered into a firm transportation
contract with MEGS LLC at a rate of $0.26 per MMBtu to
transport Mariners share of approximately
130,000,000 MMbtus of natural gas from the commencement of
production through March 2009. Mariners working interest
in the well is 51%. For the year ended December 31, 2003,
Mariner paid
76
$1.9 million on this contract. The remaining volume
commitment was 14,707,107 MMbtus or $3.8 million net
to Mariner. Pursuant to the contract, Mariner was required to
deliver minimum quantities through the flowline or be subject to
minimum monthly payment requirements.
On May 10, 2004, Mariner and the other 49% working interest
owner in the Mississippi Canyon 674 well purchased the
flowline from MEGS LLC for an adjusted purchase price of
approximately $3.8 million, of which approximately
$1.9 million was paid by Mariner, and terminated the
transportation contract and associated liability. Accordingly,
we currently have no off-balance sheet arrangements.
Recent Accounting Pronouncements
On December 16, 2004, the FASB issued FASB Statement
No. 123 (revised 2004), Share-Based Payment,
(FASB No. 123(R)) that addresses the accounting for
share-based payment transactions (for example, stock options and
awards of restricted stock) in which an employer receives
employee-services in exchange for equity securities of Mariner
or liabilities that are based on the fair value of
Mariners equity securities. The new standard replaces FASB
Statement No. 123, Accounting for Stock-Based
Compensation (FASB No. 123) and supersedes APB
Opinion No. 25, Accounting for Stock Issued to
Employees, and generally requires such transactions be
accounted for using a fair-value-based method that recognizes
compensation expense rather than the optional pro forma
disclosure allowed under FASB No. 123. Mariner adopted the
provisions of the new standard on January 1, 2005.
As a result of the adoption of the above described
SFAS No. 123(R), we recorded compensation expense for
the fair value of restricted stock that was granted pursuant to
our Equity Participation Plan (see Management of
MarinerEquity Participation Plan) and for subsequent
grants of stock options or restricted stock made pursuant to the
Mariner Energy, Inc. Stock Incentive Plan (see Management
of MarinerStock Incentive Plan). We recorded
compensation expense for the restricted stock grants equal to
their fair value at the time of the grant, amortized pro rata
over the restricted period. General and administrative expense
for the nine months ended September 30, 2005 includes
$17.2 million of compensation expense related to restricted
stock granted in 2005 and $0.4 million of compensation
expense related to stock options outstanding as of
September 30, 2005.
On September 2, 2004, the FASB issued FASB Staff Position
No. FAS 142-2, Application of FASB Statement
No. 142, Goodwill and Other Intangible Assets, to Oil and
Gas Producing Entities, addressing whether the scope
exception within SFAS No. 142, Goodwill and
Other Intangible Assets includes the balance sheet
classification and disclosures for drilling and mineral rights
of oil and gas producing properties. The FASB staff concluded
that the accounting framework for oil and gas entities is based
on the level of established reserves, not whether an asset is
tangible or intangible, and thus the scope exception extended to
the balance sheet classification and disclosure provisions for
such assets.
On September 28, 2004, the SEC released Staff Accounting
Bulletin (SAB) 106 regarding the application of
SFAS 143, Accounting for Asset Retirement Obligations
(AROs), by oil and gas producing companies
following the full cost accounting method. Pursuant to
SAB 106, oil and gas producing companies that have adopted
SFAS 143 should exclude the future cash outflows associated
with settling AROs (ARO liabilities) from the computation of the
present value of estimated future net revenues for the purposes
of the full cost ceiling calculation. In addition, estimated
dismantlement and abandonment costs, net of estimated salvage
values, that have been capitalized (ARO assets) should be
included in the amortization base for computing depreciation,
depletion and amortization expense. Disclosures are required to
include discussion of how a companys ceiling test and
depreciation, depletion and amortization calculations are
impacted by the adoption of SFAS 143. SAB 106 is
effective prospectively as of the beginning of the first fiscal
quarter beginning after October 4, 2004. Since our adoption
of SFAS 143 on January 1, 2003, we have calculated the
ceiling test and our depreciation, depletion and amortization
expense in accordance with the interpretations set forth in
SAB 106; therefore, the adoption SAB 106 had no effect
on our financial statements.
77
On December 16, 2004, the FASB issued Statement 153,
Exchanges of Nonmonetary Assets, an amendment of APB
Opinion No. 29, to clarify the accounting for nonmonetary
exchanges of similar productive assets. SFAS 153 eliminates
the exception from the fair value measurement for nonmonetary
exchanges of similar productive assets and replaces it with a
general exception for exchanges of nonmonetary assets that do
not have commercial substance. The statement will be applied
prospectively and is effective for nonmonetary asset exchanges
occurring in fiscal periods beginning after June 15, 2005.
We do not have any nonmonetary transactions for any period
presented to which this statement would apply. We do not expect
the adoption of SFAS 153 to have a material impact on our
financial statements.
Quantitative and Qualitative Disclosures About Market
Risk.
For a discussion of our market risk, See Liquidity
and Capital ResourcesCommodity Prices and Related Hedging
Activities.
78
BUSINESS
We are an independent oil and gas exploration, development and
production company with principal operations in the Gulf of
Mexico and the Permian Basin in West Texas. As of
December 31, 2004, we had 237.5 Bcfe of estimated
proved reserves, of which approximately 64% were natural gas and
36% were oil and condensate. The estimated pre-tax PV10 value of
our estimated proved reserves as of December 31, 2004 was
approximately $668 million, and the standardized measure of
discounted future net cash flows attributable to our estimated
proved reserves was approximately $494.4 million. Please
see Estimated Proved Reserves for a definition
of PV10 and a reconciliation of PV10 to the standardized measure
of discounted future net cash flows. As of December 31,
2004, approximately 46% of our estimated proved reserves were
classified as proved developed. For the year ended
December 31, 2004, our total net production was
37.6 Bcfe. Our estimated proved reserve base is balanced,
with 48% of the reserves located in the Permian Basin of West
Texas, 37% in the Gulf of Mexico deepwater and 15% on the Gulf
of Mexico shelf as of December 31, 2004.
The distribution of our proved reserves reflects our efforts
over the last three years to diversify our asset base, which in
prior years had been focused primarily in the Gulf of Mexico
deepwater. We have shifted some of our focus on deepwater
activities to increased exploration and development on the Gulf
of Mexico shelf and exploitation of our West Texas Permian Basin
properties. By allocating our resources among these three areas,
we expect to balance the risks associated with the exploration
and development of our asset base. We intend to continue to
pursue moderate-risk exploratory and development drilling
projects in the Gulf of Mexico deepwater and on the Gulf of
Mexico shelf, including select deep shelf prospects, and also
target low-risk infill drilling projects in West Texas. It is
our practice to generate most of our prospects internally, but
from time to time we also acquire third-party generated
prospects. We then drill to find oil and natural gas reserves, a
process that we refer to as growth through the drill
bit.
The following discussion includes statements that may be deemed
forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. See
Cautionary Statement Concerning Forward-Looking
Statements for more details. Also, the discussion uses
terms that pertain to the oil and gas industry, and you should
see Glossary of Oil and Natural Gas Terms for the
definition of certain terms.
79
Significant Properties
We own oil and gas properties, producing and non-producing,
onshore in Texas and offshore in the Gulf of Mexico, primarily
in federal waters. Our largest properties, based on the present
value of estimated future net proved reserves as of
December 31, 2004, are shown in the following table.
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|
|
|
|
|
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|
|
Approximate | |
|
|
|
Date | |
|
Estimated | |
|
|
|
|
|
|
|
|
Mariner | |
|
Water | |
|
Gross | |
|
Production | |
|
Proved | |
|
|
|
Standardized | |
|
|
|
|
Working | |
|
Depth | |
|
Producing | |
|
Commenced/ | |
|
Reserves | |
|
PV10 Value | |
|
Measure | |
|
|
Operator | |
|
Interest | |
|
(Feet) | |
|
Wells(1) | |
|
Expected | |
|
(Bcfe) | |
|
(In $ Millions)(2) | |
|
(In $ Millions) | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
% | |
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Permian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aldwell Unit
|
|
|
Mariner |
|
|
|
66.5 |
(3) |
|
|
Onshore |
|
|
|
185 |
|
|
|
1949 |
|
|
|
112.7 |
|
|
$ |
203.8 |
|
|
|
|
|
Gulf of Mexico Deepwater:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi Canyon 296/252 (Rigel)
|
|
|
Dominion |
|
|
|
22.5 |
|
|
|
5,200 |
|
|
|
0 |
|
|
Second Quarter 2006 |
|
|
22.4 |
|
|
|
82.9 |
|
|
|
|
|
|
Viosca Knoll 917/961/962 (Swordfish)
|
|
|
Mariner(4) |
|
|
|
15.0 |
|
|
|
4,700 |
|
|
|
2 |
|
|
Fourth Quarter 2005 |
|
|
13.4 |
|
|
|
59.3 |
|
|
|
|
|
|
Green Canyon 516 (Yosemite)
|
|
|
ENI |
|
|
|
44.0 |
|
|
|
3,900 |
|
|
|
1 |
|
|
|
2002 |
|
|
|
15.1 |
|
|
|
66.6 |
|
|
|
|
|
|
Mississippi Canyon 718 (Pluto)(5)
|
|
|
Mariner |
|
|
|
51.0 |
|
|
|
2,830 |
|
|
|
0 |
|
|
|
1999 |
|
|
|
9.0 |
|
|
|
31.7 |
|
|
|
|
|
|
Green Canyon 178 (Baccarat)
|
|
|
W&T |
|
|
|
40.0 |
|
|
|
1,400 |
|
|
|
0 |
|
|
Third Quarter 2005 |
|
|
4.0 |
|
|
|
14.3 |
|
|
|
|
|
|
Green Canyon 472/473 (King Kong)
|
|
|
ENI |
|
|
|
50.0 |
|
|
|
3,850 |
|
|
|
0 |
|
|
|
2002 |
|
|
|
1.2 |
|
|
|
2.0 |
|
|
|
|
|
Gulf of Mexico Shelf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi Canyon 66 (Ochre)(6)
|
|
|
Mariner |
|
|
|
75.0 |
|
|
|
1,150 |
|
|
|
0 |
|
|
|
2004 |
|
|
|
3.6 |
|
|
|
11.7 |
|
|
|
|
|
|
Other Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43 |
|
|
|
|
|
|
|
56.1 |
|
|
|
195.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
231 |
|
|
|
|
|
|
|
237.5 |
|
|
$ |
668.0 |
|
|
$ |
494.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Wells producing or capable of producing as of December 31,
2004. |
|
(2) |
Please see Estimated Proved Reserves for a
definition of PV10 and a reconciliation of PV10 to the
standardized measure of discounted future net cash flows. |
|
(3) |
We operate the field and own working interests in individual
wells ranging from approximately 33% to 84%. |
|
(4) |
Mariner served as operator until December 2005, at which
time pursuant to certain contractual arrangements, Noble Energy,
Inc., a 60% partner in the project, began serving as operator. |
|
(5) |
This field was shut-in in April 2004 pending the drilling of a
new well and installation of an extension to the existing
infield flowline and umbilical. As a result, as of
December 31, 2004, 9.0 Bcfe of our net proved reserves
attributable to this project were classified as proved
undeveloped reserves. We expect production from Pluto to
recommence in the second quarter of 2006. |
|
(6) |
Field has been shut in since September 2004 due to destruction
of host platform by Hurricane Ivan. |
Aldwell Unit. We operate and own working interests in
individual wells ranging from 33% to 84% (with an average
working interest of approximately 66.5%), in the
18,500-acre Aldwell
Unit. The field is located in the heart of the Spraberry
geologic trend southeast of Midland, Texas, and has produced oil
and gas since 1949. We began our recent redevelopment of the
Aldwell Unit by drilling eight wells in the fourth quarter of
2002, 43 wells in 2003, and 54 wells in 2004. As of
December 31, 2004, there were a total of 185 wells
producing or capable of producing in the field. Our aggregate
net capital expenditures for
80
the 2004 drilling program in the field were approximately
$20.3 million, and we added 27 Bcfe of proved
reserves, while producing 4.0 Bcfe.
During 2005, we have accelerated our development program in West
Texas. Through September 30, 2005, we had drilled 65 new
wells at our Aldwell and North Stiles Units. All of our drilling
in the Aldwell and North Stiles Units has resulted in
commercially successful wells that are expected to produce in
quantities sufficient to exceed costs of drilling and completion.
We have completed construction of our own oil and gas gathering
system and compression facilities in the Aldwell Unit. We began
flowing gas production through the new facilities on
June 1, 2005. We have also entered into new contracts with
third parties to provide processing of our natural gas and
transportation of our oil produced in the unit. The new gas
arrangement also provides us with the option to sell our gas to
one of four firm or five interruptible sales pipelines versus a
single outlet under the former arrangement. We expect these
arrangements to improve the economics of production from the
Aldwell Unit.
In December 2004, we acquired an approximate 45% working
interest in two Permian Basin fields containing over
4,000 acres. We believe the fields contain more than twenty
80-acre infill drilling
locations and that either or both may also have
40-acre infill drilling
opportunities. We have commenced drilling operations in one of
the fields. In February 2005, we acquired five producing wells
located in Howard County, Texas, approximately 50 miles
north of our Aldwell Unit. The purchase price was
$3.5 million, subject to post-closing adjustments.
In August 2005, but effective in October 2005, we entered into
an agreement covering approximately 33,000 acres in West
Texas, pursuant to which, upon closing, we acquired an
approximate 35% working interest in approximately 200 existing
producing wells effective November 1, 2005, and committed
to drill an additional 150 wells within a four year period,
funding $36.5 million of our partners share of
drilling costs for such
150-well drilling
program. We will obtain an assignment of an approximate 35%
working interest in the entire committed acreage upon completion
of the 150-well program.
Mississippi Canyon 296 (Rigel). Mariner generated the
Rigel prospect and acquired its interest in Mississippi Canyon
block 296 at a federal offshore Gulf lease sale in March
1999. Pursuant to an agreement with third parties, in September
1999 we cross-assigned leasehold interests in Mississippi Canyon
blocks 208, 252 and 296 with the result that our working
interest in all three blocks is now 22.5%. The project is
located approximately 130 miles southeast of New Orleans,
Louisiana, in water depth of approximately 5,200 feet. A
successful exploration well was drilled on the prospect in 1999.
In September 2003, a successful appraisal well was drilled. This
project is currently under development with a single subsea well
and a planned 12-mile
subsea tie back to an existing subsea manifold that is connected
to an existing platform. We expect production to begin in the
second quarter of 2006.
Viosca Knoll 917/961/962 (Swordfish). Mariner generated
the Swordfish prospect and entered into a farm-out agreement
with BP in September 2001. We operated Swordfish until
December 2005 and own a 15% working interest in this
project, which is located in the deepwater Gulf of Mexico
105 miles southeast of New Orleans, Louisiana, in a water
depth of approximately 4,700 feet. In November and December
of 2001, we drilled two successful exploration wells on
blocks 917 and 962. In August 2004, a successful appraisal
well found additional reserves on block 961. All wells have
been completed. Due to the impact of Hurricane Katrina on the
host facility, initial production was delayed until the fourth
quarter of 2005.
Green Canyon 516 (Yosemite). Mariner generated the
Yosemite prospect and acquired the prospect at a Gulf of Mexico
federal lease sale in 1998. We have a 44% working interest in
this project, located in approximately 3,900 feet of water,
approximately 150 miles southeast of New Orleans. In 2001,
we drilled an exploratory well on the prospect, and in February
2002, we commenced production via a joint King Kong/ Yosemite
16 mile subsea tieback to an existing platform.
81
Mississippi Canyon 718 (Pluto). Mariner initially
acquired an interest in this project in 1997, two years after
gas was discovered on the project. We operate the property and
own a 51% working interest in the project and the
29-mile flowline that
connects to a third-party production platform. We developed the
field with a single subsea well which is located in the Gulf of
Mexico approximately 150 miles southeast of New Orleans,
Louisiana, at a water depth of approximately 2,830 feet.
The field was shut-in in April 2004 pending the drilling of a
new well and completion of the installation of an extension to
the existing infield flowline and umbilical. Installation of the
subsea facilities is now complete. During startup
operations, a paraffin plug was discovered in the flowline
between the Pluto field and the host facility. Remediation
efforts are in progress and nearing completion. Production is
expected to recommence in the second quarter of 2006, following
completion of repairs to the host facilities necessitated by
damage inflicted by Hurricane Katrina.
Green Canyon 178 (Baccarat). Mariner generated the
Baccarat prospect and acquired a 100% working interest in Green
Canyon block 178 at a Gulf of Mexico federal offshore lease
sale in July 2003. The project is located in approximately
1,400 feet of water approximately 145 miles southwest
of New Orleans, Louisiana. Subsequent to the acquisition,
Mariner entered into a farmout agreement, retaining a 40%
working interest in the project. A successful exploration well
was drilled in May 2004. The project is under development as a
subsea tieback to an existing host platform and was brought
online in the third quarter of 2005. The host platform sustained
damage during Hurricane Rita, resulting in production being
shut-in. Production recommenced in January 2006.
Green Canyon 472/473 (King Kong). In July 2000, Mariner
acquired a 50% working interest in the King Kong Gulf of Mexico
project. The project is located in approximately 3,850 feet
of water, approximately 150 miles southeast of New Orleans.
Mariner completed the project as a joint King Kong/ Yosemite
16 mile subsea tieback to an existing platform. Production
began in February 2002.
|
|
|
Other Prospects and Activity |
In late 2004, we participated in a successful exploratory well
in our North Black Widow prospect in Ewing Banks 921, which is
located approximately 125 miles south of New Orleans in
approximately 1,700 feet of water. We have a 35% working
interest in this project. A development plan for the North Black
Widow prospect has been approved and the operator of this
project currently anticipates production from this project to
begin in the second quarter of 2006. At June 30, 2005
approximately 4.5 Bcfe of estimated proved reserves have
been assigned net to Mariners interest.
In May 2005, we acquired an additional 18.75% working interest
in the Bass Lite project for approximately $5.0 million,
bringing our total working interest to 38.75%. The Bass Lite
project is located in Atwater Valley blocks 380, 381, 382,
425 and 426, approximately 200 miles southeast of New
Orleans in approximately 6,500 feet of water. We were
elected operator of this project, subject to MMS approval, and
negotiations continue with third party host facilities and
partners to establish firm development plans. At June 30,
2005 approximately 30.7 Bcfe of estimated proved reserves
have been assigned net to Mariners interest.
In June 2005, we increased our working interest in the LaSalle
project (East Breaks 558, 513, and 514) to 100% by acquiring the
remaining working interest owned by a third party for
$1.5 million. The blocks contain an undeveloped discovery,
as well as exploration potential. As of December 31, 2004,
we have booked no proved reserves to this project. We have
recently executed a participation agreement with Kerr McGee to
jointly develop the LaSalle project and Kerr McGees nearby
NW Nansen exploitation project (East Breaks 602). Under the
proposed participation agreement, Mariner owns a 33% working
interest in the NW Nansen project and a 50% working
interest in the LaSalle project. The LaSalle and NW Nansen
projects are located approximately 150 miles south of
Galveston, Texas in water depths of approximately 3,100 and
3,300 feet, respectively. The development of these projects
may require the drilling of up to four wells in 2005 and 2006
and related completion and facility capital in 2006.
At the King Kong/ Yosemite field (Green Canyon blocks 516,
472, and 473) we have planned, in conjunction with the operator,
a two well drilling program to exploit potential new reserve
additions. We
82
anticipate drilling one development well and one exploration
wellthe first on block 473 and the second on
block 472, both in the first quarter of 2006. We own a 50%
working interest in blocks GC 472 and 473 and a 44% working
interest in block 516.
Mississippi Canyon 66 (Ochre). Mariner acquired its Ochre
prospect at a Gulf of Mexico federal lease sale in March 2002.
We operate and own a 75% working interest in this project, which
is located in the Gulf of Mexico approximately 100 miles
southeast of New Orleans, Louisiana, in a water depth of
approximately 1,150 feet. In late 2002, we drilled a
successful exploration well on the prospect and commenced
production in the first quarter of 2004 via subsea tieback of
approximately 7 miles to the Taylor Mississippi Canyon 20
platform. In September 2004, Hurricane Ivan destroyed the Taylor
platform. We recently entered into a production handling
agreement with the operator of a nearby replacement host
facility, and production is expected to recommence in the first
quarter of 2006, following completion of repairs to the host
facility necessitated by damage inflicted by Hurricane Katrina
and the installation of the flowline and umbilical.
In connection with the March 2005 Central Gulf of Mexico federal
lease sale, we were awarded West Cameron block 386 located
in water depth of approximately 85 feet. In connection with
the August 2005 Western Gulf of Mexico lease sale, we were
awarded one shelf block (High Island A2) and four deepwater
blocks (East Breaks 344, East Breaks 843, East Breaks 844
and East Breaks 709).
In May 2005 we drilled the Capricorn discovery well, which
encountered over 100 net feet of pay in four zones. The
Capricorn project is located in High Island block A341
approximately 115 miles south southwest of Cameron,
Louisiana in approximately 240 feet of water. We anticipate
drilling an appraisal well and installing the necessary platform
and facilities in the first quarter of 2006, with first
production anticipated in 2006. We are the operator and own a
60% working interest in the project.
Estimated Proved Reserves
The following tables set forth certain information with respect
to our estimated proved reserves by geographic area as of
December 31, 2004. Reserve volumes and values were
determined under the method prescribed by the SEC which requires
the application of period-end prices and costs held constant
throughout the projected reserve life. The reserve information
as of December 31, 2004 is based on estimates made in a
reserve report prepared by Ryder Scott. A summary of Ryder
Scotts report on our proved reserves as of
December 31, 2004 is attached to this prospectus as
Annex A and is consistent with filings we make with federal
agencies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Proved | |
|
|
|
|
|
|
|
|
|
|
Reserve Quantities | |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Natural | |
|
|
|
PV10 Value(3) | |
|
|
|
|
Oil | |
|
Gas | |
|
Total | |
|
| |
|
Standardized | |
Geographic Area |
|
(MMbbls) | |
|
(Bcf) | |
|
(Bcfe) | |
|
Developed | |
|
Undeveloped | |
|
Total | |
|
Measure | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
|
|
(millions) | |
|
|
|
|
|
|
|
|
(millions) | |
|
|
West Texas Permian Basin
|
|
|
8.7 |
|
|
|
62.8 |
|
|
|
114.8 |
|
|
$ |
141.1 |
|
|
$ |
64.4 |
|
|
$ |
205.5 |
<