posam
As filed with the Securities and Exchange Commission on
November 13, 2006
Registration
No. 333-137441
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Post-Effective Amendment
No. 1
to
Form S-4
REGISTRATION
STATEMENT
UNDER
THE SECURITIES ACT OF
1933
Mariner Energy, Inc.
(Exact name of registrant as
specified in its charter)
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Delaware
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1311
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86-0460233
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(State or other jurisdiction
of
incorporation or organization)
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(Primary Standard Industrial
Classification Code Number)
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(I.R.S. Employer
Identification No.)
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One Briar Lake Plaza,
Suite 2000
2000 West Sam Houston
Parkway South
Houston, Texas 77042
(713) 954-5500
(Address, including zip code,
and telephone number, including area code, of registrants
principal executive offices)
Teresa Bushman
Senior Vice President and
General Counsel
Mariner Energy, Inc.
One Briar Lake Plaza,
Suite 2000
2000 West Sam Houston
Parkway South
Houston, Texas 77042
(713) 954-5505
(Name, address, including zip
code, and telephone number, including area code, of agent for
service)
Copies to:
Kelly B. Rose
Baker Botts L.L.P.
910 Louisiana
One Shell Plaza
Houston, Texas 77002
(713) 229-1234
Approximate date of commencement of proposed sale of the
securities to the public: As soon as practicable
following the effectiveness of this Registration Statement.
If the securities being registered on this Form are to be
offered in connection with the formation of a holding company
and there is compliance with General Instruction G, check the
following box. o
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act
of 1933, check the following box and list the Securities Act
registration statement number of the earlier effective
registration statement for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act of 1933, check the
following box and list the Securities Act registration statement
number of the earlier effective registration statement for the
same offering. o
TABLE OF
ADDITIONAL REGISTRANT GUARANTORS
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State or Other
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Primary Standard
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Jurisdiction of
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I.R.S. Employer
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Industrial
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Incorporation or
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Identification
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Classification
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Exact Name of Registrant Guarantor(1)
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Organization
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Number
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Code Number
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Mariner Energy Resources, Inc.
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Delaware
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20-3541629
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1311
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Mariner LP LLC
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Delaware
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20-4414029
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1311
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Mariner Energy Texas LP
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Delaware
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20-2341980
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1311
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(1)
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The address and telephone number
for each guarantor is One BriarLake Plaza, Suite 2000,
2000 West Sam Houston Parkway South, Houston, Texas 77042,
and the telephone number at that address is
(713) 954-5500.
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The registrants hereby amend this registration statement on such
date or dates as may be necessary to delay its effective date
until the registrants shall file a further amendment which
specifically states that this registration statement shall
thereafter become effective in accordance with section 8(a)
of the Securities Act of 1933 or until the registration
statement shall become effective on such date as the Commission
acting pursuant to said section 8(a), may determine.
The
information in this prospectus is not complete and may be
changed. Certain broker-dealers may not sell these securities
until the registration statement filed with the Securities and
Exchange Commission is effective. This prospectus is not an
offer to sell these securities and it is not soliciting an offer
to buy these securities in any state where such offer or sale is
not permitted.
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Registration No. 333-137441
SUBJECT
TO COMPLETION
PRELIMINARY PROSPECTUS DATED
NOVEMBER 13, 2006
PROSPECTUS
$300,000,000
71/2%
Senior Notes due 2013
The Offer
to Exchange
$300,000,000
71/2% Senior
Notes due 2013
that have been registered under the Securities Act of 1933
for any and all
$300,000,000
71/2% Senior
Notes due 2013
expired at 5:00 P.M.,
New York City time, on November 9, 2006.
We offered to exchange an aggregate principal amount of
$300,000,000 of registered
71/2% Senior
Notes due 2013, which we refer to as the new notes, for any and
all of our original unregistered
71/2% Senior
Notes due 2013 that were issued in a private offering on
April 24, 2006, which we refer to as the old notes. The
exchange offer expired at 5:00 p.m., New York City time, on
November 9, 2006, which we refer to as the exchange date. Each
broker-dealer (other than an affiliate of ours) that receives
new notes for its own account in the exchange offer in exchange
for securities that were acquired by such broker-dealer as a
result of market-making or other trading activities must deliver
a prospectus meeting the requirements of the Securities Act of
1933 in connection with any resale of new notes. We have agreed
that, for a period of 90 days after the exchange date, we
will make the prospectus available to any broker-dealer for use
in connection with any such resale.
Terms of
the exchange offer:
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We exchanged all outstanding old notes that were validly
tendered and not withdrawn prior to the expiration of the
exchange offer for an equal principal amount of new notes.
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The terms of the new notes are substantially identical to those
of the old notes, except that the transfer restrictions,
registration rights and special interest provisions relating to
the old notes do not apply to the new notes.
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The ability to withdraw tenders of old notes ceased upon
expiration of the exchange offer.
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The exchange of new notes for old notes is not a taxable
transaction for U.S. federal income tax purposes.
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We did not receive any proceeds from the exchange offer.
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The new notes are eligible for trading in the Private Offering,
Resales and Trading Automatic Linkage (PORTAL) Market. SM We do
not intend to apply for a listing of the new notes on any
securities exchange or for their inclusion on any automated
dealer quotation system.
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See Risk Factors beginning on page 18 for a
discussion of risks you should consider in connection with the
notes.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or passed upon the adequacy or accuracy of this
prospectus. Any representation to the contrary is a criminal
offense.
We may amend or supplement this prospectus from time to time by
filing amendments or supplements as required. You should read
this entire prospectus and related documents and any amendments
or supplements to this prospectus carefully before making your
investment decision.
The date of this prospectus is November , 2006.
TABLE OF
CONTENTS
THIS PROSPECTUS IS PART OF A REGISTRATION STATEMENT WE
FILED WITH THE SECURITIES AND EXCHANGE COMMISSION, OR SEC. IN
MAKING YOUR INVESTMENT DECISION, YOU SHOULD RELY ONLY ON THE
INFORMATION CONTAINED IN THIS PROSPECTUS, IN THE ACCOMPANYING
LETTER OF TRANSMITTAL OR THE INFORMATION TO WHICH WE HAVE
REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH
ANY OTHER INFORMATION. IF YOU RECEIVE ANY UNAUTHORIZED
INFORMATION, YOU MUST NOT RELY ON IT. THIS PROSPECTUS MAY ONLY
BE USED WHERE IT IS LEGAL TO EXCHANGE THE OLD NOTES. YOU SHOULD
NOT ASSUME THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS IS
ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT COVER
OF THIS PROSPECTUS.
Until January 8, 2007, all dealers that effect
transactions in these securities, whether or not participating
in this exchange offer, may be required to deliver a prospectus.
This is in addition to the dealers obligation to deliver a
prospectus when acting as underwriters and with respect to their
unsold allotments or subscriptions.
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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 may,
will, 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
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;
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discovery, estimation, development and replacement of oil and
natural gas reserves;
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cash flow, liquidity and financial position;
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business strategy;
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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;
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risks arising out of our hedging transactions;
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marketing of oil and natural gas;
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competition in the oil and natural gas industry;
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the impact of weather and the occurrence of natural disasters
such as hurricanes, fires, floods and other catastrophic events
and natural disasters;
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governmental regulation of the oil and natural gas industry;
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environmental liabilities;
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developments in oil-producing and natural gas-producing
countries;
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uninsured or underinsured losses in our oil and natural gas
operations;
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risks related to our level of indebtedness;
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our merger with Forest Energy Resources, including strategic
plans, expectations and objectives for future operations, and
the realization of expected benefits from the
transaction; and
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disruption from the merger with Forest Energy Resources making
it more difficult to manage Mariners business.
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WHERE YOU
CAN FIND MORE INFORMATION
We file annual, quarterly and current reports, proxy statements
and other information with the SEC. Our SEC filings are
available to the public over the Internet at the SECs web
site at www.sec.gov. You also may read and copy any document we
file at the SECs public reference room in
Washington, D.C. Please call the SEC at
1-800-SEC-0330
for further information about the public reference room. Reports
and other information concerning us can also be inspected at the
offices of the New York Stock Exchange, 20 Broad Street,
New York, New York 10005. Our common stock is listed and traded
on the New York Stock Exchange under the trading symbol
ME.
You may request a copy of these filings, which we will provide
to you at no cost, by writing or telephoning us at the following
address: Mariner Energy, Inc., One Briar Lake Plaza,
Suite 2000, 2000 West Sam Houston Parkway South,
Houston, Texas 77004. Our phone number is
(713) 954-5555.
Our website address is www.mariner-energy.com. The information
on our website is not a part of this prospectus.
We filed a registration statement on
Form S-4
to register with the SEC the new notes issued in exchange for
the old notes and guarantees thereof. This prospectus is part of
that registration statement. As allowed by the SECs rules,
this prospectus does not contain all of the information you can
find in the registration statement or the exhibits to the
registration statement. You should note that where we summarize
in the prospectus the material terms of any contract, agreement
or other document filed as an exhibit to the registration
statement, the summary information provided in the prospectus is
less complete than the actual contract, agreement or document.
You should refer to the exhibits filed to the registration
statement for copies of the actual contract, agreement or
document.
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PROSPECTUS
SUMMARY
This summary highlights information appearing in other
sections of this prospectus. It does not contain all of the
information you may wish to consider before participating in the
exchange offer. We urge you to read this entire prospectus to
understand fully the terms of the notes and other considerations
that may be important to you in making your decision regarding
the exchange offer, including the Risk Factors
section beginning on page 18 of this prospectus. As used in
this prospectus, unless the context otherwise requires or
indicates, references to Mariner, we,
our, ours, and us refer to
Mariner Energy, Inc. and its subsidiaries collectively. Certain
oil and natural gas industry terms used in this prospectus are
defined in the Glossary of Oil and Natural Gas Terms
beginning on page 165. References to pro forma
and on a pro forma basis mean on a pro forma basis,
giving effect to our merger with Forest Energy Resources, Inc.
which was completed on March 2, 2006, as if this merger had
occurred on the applicable date of determination or on the first
day of the applicable period. The unaudited pro forma
information contained in this prospectus 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. The pro forma 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 pro forma financial information as
being 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.
Our
Company
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 in West Texas.
Our management has significant expertise and a successful
operating track record in these areas. In the three-year period
ended December 31, 2005, we added approximately 280 Bcfe of
proved reserves and produced approximately 100 Bcfe, while
deploying approximately $475 million of capital on
acquisitions, exploration and development.
Our primary operating strategy is to generate high-quality
exploration and development projects, which enables us to add
value through the drill bit. Our expertise in project generation
also facilitates our participation in high-quality projects
generated by other operators. We will also pursue acquisitions
of producing assets that have the potential to provide
acceptable risk-adjusted rates of return and further reserve
additions through exploration, exploitation, and development
opportunities. We target a balanced exposure to development,
exploitation and exploration opportunities, both offshore and
onshore and seek to maintain a moderate risk profile.
On March 2, 2006, we completed a merger transaction with
Forest Energy Resources, Inc., which we refer to as Forest
Energy Resources. As a result of this merger, we acquired the
Gulf of Mexico operations of Forest Oil Corporation (NYSE: FST),
which we refer to as the Forest Gulf of Mexico operations. We
refer to Forest Oil Corporation as Forest.
As of December 31, 2005, we had 338 Bcfe of estimated
proved reserves, of which approximately 62% were natural gas and
38% were oil and condensate, and 50% of which was proved
developed. Pro forma for the merger transaction, as of
December 31, 2005, we had 644 Bcfe of estimated proved
reserves, of which approximately 68% were natural gas and 32%
were oil and condensate, and 56% of which was proved developed.
Our pro forma production for 2005 was approximately
95 Bcfe, or 260 MMcfe per day on average. During the
year ended December 31, 2005, our pro forma EBITDA was
approximately $438.6 million, including $25.7 million
of non-cash compensation expense related to restricted stock and
stock options granted in 2005, but excluding general and
administrative expenses of the Forest Gulf of Mexico operations.
Our production for the nine months ended September 30, 2006
was approximately 55 Bcfe, or 200 MMcfe per day on
average, and pro forma for the merger, 62 Bcfe, or
229 MMcfe per day on average. During the nine months ended
September 30, 2006, our EBITDA was approximately
$340.7 million, and pro forma for the
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merger, approximately $391.7 million, in each case,
including $9.0 million of non-cash compensation expense
related to restricted stock and stock options. We believe the
overhead costs associated with the Forest Gulf of Mexico
operations in 2006 will be approximately $6.4 million, net
of capitalized amounts. See footnote 1 on page 13 for
our definition of EBITDA and a reconciliation of net income to
EBITDA.
The following table sets forth certain information with respect
to our estimated proved reserves, production and acreage by
geographic area on a pro forma basis for our merger with Forest
Energy Resources as of December 31, 2005. 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.
Proved reserve estimates do not include any value for probable
or possible reserves which may exist, nor do they include any
value for undeveloped acreage. The proved reserve estimates
represent our net revenue interest in our properties. The
reserve information for Mariner as of December 31, 2005 is
based on estimates made in a reserve report prepared by Ryder
Scott Company, L.P., independent petroleum engineers
(Ryder Scott). The reserve information as of
December 31, 2005 for the Forest Gulf of Mexico operations
is based on estimates made by internal staff engineers of
Forest, which estimates were audited by Ryder Scott.
Accordingly, the pro forma reserve information presented below
includes both reserves that were estimated by Ryder Scott and
reserves that were estimated by internal staff engineers of
Forest and audited by Ryder Scott. This information is presented
on a pro forma basis, giving effect to our merger with Forest
Energy Resources as though it had been consummated on
December 31, 2005. We consummated the merger on
March 2, 2006.
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Pro Forma
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Production for
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Year Ended
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Pro Forma
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December 31,
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Estimated Proved
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2005
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Reserve Quantities
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Pro Forma
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(Natural
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Oil
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Natural
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Total
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Total Net
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Gas
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Geographic Area
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(MMbbls)
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Gas (Bcf)
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(Bcfe)
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Acreage
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Equivalent (Bcfe))
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West Texas
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16.7
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105.5
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205.5
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31,199
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6.6
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Gulf of Mexico Deepwater(1)
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4.8
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95.7
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124.5
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241,320
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14.0
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Gulf of Mexico Shelf(2)
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12.7
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237.6
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313.7
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652,086
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74.3
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Total
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34.2
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438.8
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643.7
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924,605
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94.9
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Proved Developed Reserves
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18.4
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252.1
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362.3
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(1) |
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Deepwater refers to water depths greater than 1,300 feet
(the approximate depth of deepwater designation for royalty
purposes by the U.S. Minerals Management Service). |
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Shelf refers to water depths less than 1,300 feet and
includes an insignificant amount of Gulf Coast onshore
properties. |
Our
Strategy and Our Competitive Strengths
Our
Strategy
The principal elements of our operating strategy include:
Generating and pursuing high-quality
prospects. We expect to continue our strategy of
growth through the drill bit by continuing to identify and
develop high-impact shelf, deep shelf and deepwater projects in
the Gulf of Mexico. Our technical team has significant expertise
in, and a successful track record of achieving growth by,
generating prospects internally and selectively participating in
prospects generated by other operators. We believe the Gulf of
Mexico is an area that offers substantial growth opportunities,
and our acquisition of the Forest Gulf of Mexico operations has
more than doubled our existing undeveloped acreage position in
the Gulf, providing numerous additional exploration,
exploitation and development opportunities.
Maintaining a moderate risk profile. We seek
to manage our risk profile by targeting a balanced exposure to
development, exploitation and exploration opportunities. For
example, we intend to continue
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to develop and seek to expand our West Texas asset base, which
contributes stable cash flows and long-lived reserves to our
portfolio as a counterbalance to our high-impact,
high-production Gulf of Mexico assets. We also seek to mitigate
and diversify our risk in drilling projects by selling partial
or entire interests in projects to industry partners or by
entering into arrangements with industry partners in which they
agree to pay a disproportionate share of drilling costs and
compensate us for expenses incurred in prospect generation. We
also enter into trades or farm-in transactions whereby we
acquire interests in third-party generated prospects, thereby
gaining exposure to a greater number of prospects. We expect
more opportunities to participate in these prospects in the
future as a result of our larger scale and increased cash flow
from the Forest Gulf of Mexico operations.
Pursuing opportunistic acquisitions. Until
2005, we grew our reserves primarily through the drill bit. In
2005 we added significant proved reserves primarily through
acquisitions in West Texas and subsequently in March 2006,
through the acquisition of the Forest Gulf of Mexico operations.
As part of our growth strategy, we will seek to continue to
acquire producing assets that have the potential to provide
acceptable risk-adjusted rates of return and further reserve
additions through exploration, exploitation and development
opportunities.
Our
Competitive Strengths
We believe our core resources and strengths include:
Our high-quality assets with geographic and geological
diversity. Our assets and operations are
diversified among the Gulf of Mexico shelf, deep shelf and
deepwater, and West Texas. Our asset portfolio provides a
balanced exposure to long-lived West Texas reserves, Gulf of
Mexico shelf growth opportunities and high-impact deepwater
prospects.
Our large inventory of prospects. We believe
we have significant potential for growth through the development
of our existing asset base. The acquisition of the Forest Gulf
of Mexico operations more than doubled our existing undeveloped
acreage position in the Gulf of Mexico to approximately
450,000 net acres and increased our total net leasehold
acreage offshore to nearly one million acres, providing numerous
exploration, exploitation and development opportunities. As of
September 30, 2006, we have an inventory of approximately
890 drilling locations in West Texas, which we believe
would require approximately six years to drill at our current
rate. These include approximately 430 locations pertaining
to 98 Bcfe of estimated net proved undeveloped reserves and
approximately 460 other locations.
Our successful track record of finding and developing oil and
gas reserves. We have demonstrated our expertise
in finding and developing additional proved reserves. In the
three-year period ended December 31, 2005, we deployed
approximately $475 million of capital on acquisitions,
exploration and development, while adding approximately
280 Bcfe of proved reserves and producing approximately
100 Bcfe.
Our depth of operating experience. Our team of
41 geoscientists, engineers, geologists and other technical
professionals and landmen as of September 30, 2006 average
more than 22 years of experience in the exploration and
production business (including extensive experience in the Gulf
of Mexico), much of it with major oil companies. The addition of
experienced Forest personnel to Mariners team of technical
professionals has further enhanced our ability to generate and
maintain an inventory of high-quality drillable prospects and to
further develop and exploit our assets. Mariners technical
team has also proven to be an effective and efficient operator
in West Texas, as evidenced by our successful production and
reserve growth there in recent years.
Our technology and production techniques. Our
team of geoscientists currently has access to seismic data from
multiple, recent
vintage 3-D
seismic databases covering more than 7,000 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. We also have
extensive experience and a successful track record in the use of
subsea tieback technology to connect
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offshore wells to existing production facilities. This
technology facilitates production from offshore properties
without the necessity of fabrication and installation of
platforms and top-side facilities that typically are more costly
and 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,
2005, we were directly involved in 14 projects (five of which we
operated) utilizing subsea tieback systems in water depths
ranging from 475 feet to more than 6,700 feet. As of
September 30, 2006, we had 18 subsea wells in water depths
ranging from 450 feet to more than 4,700 feet. These
wells were tied back to 13 host production facilities for
production processing. An additional nine wells in water depths
ranging from 465 feet to more than 6,800 feet were
then under development for tieback to five additional host
production facilities.
Recent
Developments
Forest
Gulf of Mexico Merger
On March 2, 2006, we completed a merger transaction with
Forest Energy Resources. Prior to the consummation of the
merger, Forest transferred and contributed the assets and
certain liabilities associated with its Gulf of Mexico
operations to Forest Energy Resources. Immediately prior to the
merger, Forest distributed all of the outstanding shares of
Forest Energy Resources to Forest shareholders on a pro rata
basis. Forest Energy Resources then merged with a newly-formed
subsidiary of Mariner, became a new wholly-owned subsidiary of
Mariner and changed its name to Mariner Energy Resources, Inc.
Immediately following the merger, approximately 59% of Mariner
common stock was held by shareholders of Forest and
approximately 41% of Mariner common stock was held by the
pre-merger stockholders of Mariner.
Forest Energy Resources had approximately 306 Bcfe of
estimated proved reserves as of December 31, 2005, of which
approximately 76% were natural gas, and 24% were oil and
condensate. The reserves and operations acquired from Forest are
concentrated in the shelf and deep shelf of the Gulf of Mexico
and represent a significant addition to Mariners asset
portfolio in those areas of operation.
We believe our acquisition of the Forest Gulf of Mexico
operations and the scale they bring to our business has further
moderated our risk profile, provided many exploration,
exploitation and development opportunities, enhanced our ability
to participate in prospects generated by other operators, and
added a significant cash flow generating resource that has
improved our ability to compete effectively in the Gulf of
Mexico and fund exploration activities and acquisitions. We
believe we are well-positioned to optimize the Forest Energy
Resources assets through aggressive and timely exploitation.
West
Cameron Acquisition
In August 2006, we acquired the interest of BP Exploration and
Production Inc., which we refer to as BP, in West
Cameron Block 110 and the southeast quarter of West Cameron
Block 111 in the Gulf of Mexico. The interest was acquired
by our subsidiary, Mariner Energy Resources, Inc., exercising
its preferential right to purchase. BP retained its interest in
depths below 15,000 feet. In the Forest merger, we acquired
Forest Energy Resources 37.5% interest in the properties.
As a result of the August 2006 acquisition, Mariner Energy
Resources, Inc. now owns 100% of the working interest, exclusive
of the deep rights retained by BP, and Mariner Energy, Inc.
became operator of the interests owned by its subsidiary. The
acquisition cost, net of preliminary purchase price adjustments,
was approximately $70.9 million, which was financed by
borrowing under our senior secured credit facility. A
$10.4 million letter of credit under our senior secured
credit facility also was issued in favor of BP to secure
plugging and abandonment obligations. The acquisition adds
proved reserves estimated by us to be 20 Bcfe as of
August 1, 2006. Production associated with the acquired
interest was approximately 11 MMcfe/day during July 2006.
4
Material
Gulf of Mexico Discovery
In October 2006, we announced that we made a material
conventional shelf discovery in the High Island
116 #5ST1 well, drilled to a total measured depth of
14,683 feet / 13,150 feet true vertical depth. The
well encountered approximately 540 feet of net true
vertical depth pay in thirteen sands. We anticipate completion
and initial production in the fourth quarter of 2006. High
Island 116 is part of the Forest Gulf of Mexico operations we
acquired in March 2006. We have a 100% working interest and an
approximate 72% net revenue interest in the well.
Effects
of the 2005 Hurricane Season
In 2005, our operations were adversely affected by one of the
most active and severe hurricane seasons in recorded history,
resulting in shut-in production and startup delays. We estimate
that as of September 30, 2006, approximately 12 MMcfe
per day of production remained shut-in and approximately
33 MMcfe per day of production had recommenced since
June 30, 2006. The four deepwater projects that experienced
startup delays have recommenced production. As a result of
ongoing repairs to pipelines, facilities, terminals and host
facilities, we expect most of the remaining shut-in production
to recommence by the end of 2006 and the balance in 2007, except
that an immaterial amount of production is not expected to
recommence.
We estimate the costs to repair damage caused by the hurricanes
to our platforms and facilities will be approximately
$85 million. However, until we are able to complete all the
repair work this estimate is subject to significant variance.
For the insurance period covering the 2005 hurricane activity,
we carried a $3 million annual deductible and a
$0.5 million single occurrence deductible for the Mariner
assets. Insurance covering the Forest Gulf of Mexico properties
carried a $5 million deductible for each occurrence. Until
the repairs are completed and we submit costs to our insurance
underwriters for review, the full extent of our insurance
recoveries and the resulting net cost to us for Hurricanes
Katrina and Rita will be unknown. However, we expect the total
costs not covered by the combined insurance policies to be less
than $15 million.
Corporate
Information
We were incorporated in August 1983 as a Delaware corporation.
We have three subsidiaries, Mariner Energy Resources, Inc., a
Delaware corporation, Mariner LP LLC, a Delaware limited
liability company, and Mariner Energy Texas LP, a Delaware
limited partnership. 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
The
Exchange Offer
On April 24, 2006, we completed an unregistered offering of
the old notes. As part of that offering, we entered into a
registration rights agreement with the initial purchasers of the
old notes in which we agreed, among other things, to use
commercially reasonable efforts to complete the exchange offer
which expired on November 9, 2006. Each broker-dealer (other
than an affiliate of ours) that receives new notes for its own
account in the exchange offer in exchange for securities that
were acquired by such broker-dealer as a result of market-making
or other trading activities must deliver a prospectus meeting
the requirements of the Securities Act in connection with any
resale of new notes. In the registration rights agreement, we
also agreed that for a period of 90 days after the exchange
date, we will make this prospectus available to any
broker-dealer for use in connection with any such resale. We
refer to the old notes and the new notes (separately or
collectively, as the context indicates) as the
notes. The following is a brief summary of the
exchange offer that expired on November 9, 2006. Please also see
Exchange Offer.
|
|
|
Old Notes |
|
71/2% Senior
Notes due April 15, 2013, which were issued on
April 24, 2006. |
|
New Notes |
|
71/2% Senior
Notes due April 15, 2013. The terms of the new notes are
substantially identical to those terms of the old notes, except
that the transfer restrictions, registration rights and special
interest provisions relating to the old notes do not apply to
the new notes. |
|
Exchange Offer |
|
We offered to exchange $300.0 million principal amount of
our new notes that have been registered under the Securities Act
for an equal amount of our old notes to satisfy our obligations
under the registration rights agreement. |
|
|
|
The new notes evidence the same debt as the old notes and are
issued under and entitled to the benefits of the same indenture
that governs the old notes. Holders of the old notes do not have
any appraisal or dissenters rights in connection with the
exchange offer. Because the new notes are registered, the new
notes will not be subject to transfer restrictions, and holders
of old notes that have tendered and had their old notes accepted
in the exchange offer have no registration rights. |
|
Expiration Date |
|
The exchange offer expired at 5:00 P.M., New York City
time, on November 9, 2006. The ability to withdraw tenders
of old notes pursuant to the exchange offer ceased upon
expiration of the exchange offer. |
6
Description
of Senior Notes
The terms of the new notes and those of the outstanding old
notes are substantially identical, except that the transfer
restrictions and registration rights relating to the old notes
do not apply to the new notes. As a result, the new notes will
not bear legends restricting their transfer and will not have
the benefit of the registration rights and related special
interest provisions contained in the old notes. The new notes
represent the same debt as the old notes for which they are
being exchanged. Both the old notes and the new notes are
governed by the same indenture.
|
|
|
Issuer |
|
Mariner Energy, Inc. |
|
Notes Offered |
|
$300,000,000 principal amount of its
71/2% Senior
Notes due 2013. |
|
Maturity Date |
|
April 15, 2013. |
|
Interest Rate |
|
71/2% per
year (calculated using a
360-day
year). |
|
Interest Payment Dates |
|
Each April 15 and October 15, beginning October 15,
2006. |
|
Ranking |
|
The notes are our general unsecured senior obligations.
Accordingly, they rank: |
|
|
|
effectively subordinate to all of our existing and
future secured indebtedness, including indebtedness under our
credit facility, to the extent of the collateral securing such
indebtedness;
|
|
|
|
effectively subordinate to all existing and future
indebtedness and other liabilities of any non-guarantor
subsidiaries (other than indebtedness and liabilities owed to
us); |
|
|
|
pari passu in right of payment to all of our
existing and future senior unsecured indebtedness; and |
|
|
|
senior in right of payment to any future
subordinated indebtedness. |
|
|
|
As of September 30, 2006, we had total indebtedness of
approximately $614 million, $300 million of which was
the notes, and approximately $314 million of which was
secured indebtedness to which the notes effectively were
subordinated as to the value of the collateral. We also then had
three letters of credit outstanding for $40.0 million,
$10.4 million and $4.2 million, each of which
effectively was senior to the notes to the extent of the
collateral securing such indebtedness. |
|
Subsidiary Guarantees |
|
The notes are jointly and severally guaranteed on a senior
unsecured basis by our existing and future domestic
subsidiaries. In the future, the guarantees may be released or
terminated under certain circumstances. Each subsidiary
guarantee ranks: |
|
|
|
effectively subordinate to all existing and future
secured indebtedness of the guarantor subsidiary, including its
guarantee of indebtedness under our credit facility, to the
extent of the collateral securing such indebtedness; |
|
|
|
pari passu in right of payment to all existing and
future senior unsecured indebtedness of the guarantor
subsidiary; and |
|
|
|
senior in right of payment to any future
subordinated indebtedness of the guarantor subsidiary. |
7
|
|
|
|
|
As of September 30, 2006, the guarantor subsidiary Mariner
Energy Resources, Inc. had approximately $176.2 million of
unsecured indebtedness outstanding under an intercompany note
payable to us. The other two guarantor subsidiaries were
guarantors but not indebted under our senior secured credit
facility and had no other indebtedness outstanding. |
|
Optional Redemption |
|
At any time prior to April 15, 2009, we may redeem up to
35% of each of the notes with the net cash proceeds of certain
equity offerings at the redemption prices set forth under
Description of Senior Notes Optional
Redemption, if at least 65% of the aggregate principal
amount of the notes issued under the indenture remains
outstanding immediately after such redemption and the redemption
occurs within 180 days of the closing date of such equity
offering. |
|
|
|
At any time prior to April 15, 2010, we may redeem the
notes, in whole or in part, at a make whole
redemption price set forth under Description of Senior
Notes Optional Redemption. On and after
April 15, 2010, we may redeem the notes, in whole or in
part, at the redemption prices set forth under Description
of Senior Notes Optional Redemption. |
|
Change of Control Triggering Event |
|
If a Change of Control Triggering Event occurs, we must offer to
repurchase the notes at the redemption price set forth under
Description of Senior Notes Repurchase at the
Option of Holders Change of Control. |
|
Certain Covenants |
|
The indenture governing the notes contains covenants that, among
other things, limit our ability and the ability of our
restricted subsidiaries to: |
|
|
|
make investments; |
|
|
|
incur additional indebtedness or issue preferred
stock; |
|
|
|
create certain liens; |
|
|
|
sell assets; |
|
|
|
enter into agreements that restrict dividends or
other payments from our subsidiaries to us; |
|
|
|
consolidate, merge or transfer all or substantially
all of the assets of our company; |
|
|
|
engage in transactions with affiliates; |
|
|
|
pay dividends or make other distributions on capital
stock or subordinated indebtedness; and |
|
|
|
create unrestricted subsidiaries. |
8
|
|
|
|
|
These covenants are subject to important exceptions and
qualifications. In addition, substantially all of the covenants
will terminate before the notes mature if one of two specified
ratings agencies assigns the notes an investment grade rating in
the future and no events of default exist under the indentures.
Any covenants that cease to apply to us as a result of achieving
an investment grade rating will not be restored, even if the
credit rating assigned to the notes later falls below an
investment grade rating. See Description of Senior
Notes Certain Covenants. |
|
Absence of Established Market for the Notes |
|
The new notes are generally freely transferable but are also new
securities for which there will not initially be a market.
Accordingly, we cannot assure you as to the development or
liquidity of any market for the new notes. The notes will be
eligible for trading in the
PORTALsm
Market. We do not intend to apply for a listing of the new notes
on any securities exchange or for the inclusion on any automated
dealer quotation system. |
|
Use of Proceeds |
|
We will not receive any proceeds from the exchange offer. |
9
Summary
Historical Financial Information
The following table shows Mariners summary historical
consolidated financial data as of and for the nine months ended
September 30, 2006 and September 30, 2005, the year
ended December 31, 2005, the period from January 1,
2004 through March 2, 2004, the period from March 3,
2004 through December 31, 2004, and each of the three years
ended December 31, 2003. The summary historical
consolidated financial data for the year ended December 31,
2005, the period from January 1, 2004 through March 2,
2004, the period from March 3, 2004 through
December 31, 2004, and each of the three years ended
December 31, 2003 are derived from Mariners audited
financial statements included herein, and the historical
consolidated financial data as of and for the two years ended
December 31, 2002 are derived from Mariners audited
financial statements that are not included herein. The summary
historical consolidated financial data for the nine months ended
September 30, 2006 and the nine months ended
September 30, 2005 has been derived from Mariners
unaudited financial statements. 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 with Forest Energy Resources.
Mariners historical results are not necessarily indicative
of results to be expected in future periods.
The merger between a subsidiary of Mariner and Forest Energy
Resources was consummated on March 2, 2006. Accordingly,
the financial information as of September 30, 2006 below
includes the Forest Gulf of Mexico operations as of and after
March 2, 2006.
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 Post-2004 Merger activity (for the March 3, 2004
through December 31, 2004 period, the year ended
December 31, 2005 and the nine months ended
September 30, 2006 and September 30, 2005) and
Pre-2004 Merger activity (for all periods prior to
March 2, 2004) 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.
10
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|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Operations
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues(1)
|
|
$
|
438.4
|
|
|
$
|
151.2
|
|
|
$
|
199.7
|
|
|
$
|
174.4
|
|
|
|
$
|
39.8
|
|
|
$
|
142.5
|
|
|
$
|
158.2
|
|
|
$
|
155.0
|
|
Lease operating expenses
|
|
|
62.9
|
|
|
|
17.7
|
|
|
|
24.9
|
|
|
|
19.3
|
|
|
|
|
3.5
|
|
|
|
23.2
|
|
|
|
25.2
|
|
|
|
19.2
|
|
Severance and ad valorem taxes
|
|
|
5.7
|
|
|
|
2.5
|
|
|
|
5.0
|
|
|
|
2.1
|
|
|
|
|
0.6
|
|
|
|
1.5
|
|
|
|
0.9
|
|
|
|
0.9
|
|
Transportation expenses
|
|
|
4.0
|
|
|
|
1.7
|
|
|
|
2.3
|
|
|
|
1.9
|
|
|
|
|
1.1
|
|
|
|
6.3
|
|
|
|
10.5
|
|
|
|
12.0
|
|
Depreciation, depletion and
amortization
|
|
|
192.2
|
|
|
|
43.4
|
|
|
|
59.4
|
|
|
|
54.3
|
|
|
|
|
10.6
|
|
|
|
48.3
|
|
|
|
70.8
|
|
|
|
63.5
|
|
Impairment of production equipment
held for use
|
|
|
|
|
|
|
0.5
|
|
|
|
1.8
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative settlement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
|
|
|
|
|
|
|
|
Impairment of Enron related
receivables
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
|
|
29.5
|
|
General and administrative expenses
|
|
|
25.1
|
|
|
|
26.7
|
|
|
|
37.1
|
|
|
|
7.6
|
|
|
|
|
1.1
|
|
|
|
8.1
|
|
|
|
7.7
|
|
|
|
9.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
148.5
|
|
|
|
58.7
|
|
|
|
69.2
|
|
|
|
88.2
|
|
|
|
|
22.9
|
|
|
|
51.9
|
|
|
|
39.9
|
|
|
|
20.6
|
|
Interest income
|
|
|
0.5
|
|
|
|
0.7
|
|
|
|
0.8
|
|
|
|
0.2
|
|
|
|
|
0.1
|
|
|
|
0.8
|
|
|
|
0.4
|
|
|
|
0.7
|
|
Interest expense
|
|
|
(26.4
|
)
|
|
|
(5.4
|
)
|
|
|
(8.2
|
)
|
|
|
(6.0
|
)
|
|
|
|
|
|
|
|
(7.0
|
)
|
|
|
(10.3
|
)
|
|
|
(8.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
122.6
|
|
|
|
54.0
|
|
|
|
61.8
|
|
|
|
82.4
|
|
|
|
|
23.0
|
|
|
|
45.7
|
|
|
|
30.0
|
|
|
|
12.4
|
|
Provision for income taxes
|
|
|
(44.4
|
)
|
|
|
(18.4
|
)
|
|
|
(21.3
|
)
|
|
|
(28.8
|
)
|
|
|
|
(8.1
|
)
|
|
|
(9.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting method net of tax effects
|
|
$
|
78.2
|
|
|
$
|
35.6
|
|
|
|
40.5
|
|
|
|
53.6
|
|
|
|
|
14.9
|
|
|
|
36.3
|
|
|
|
30.0
|
|
|
|
12.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect
per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.07
|
|
|
$
|
1.10
|
|
|
|
1.24
|
|
|
|
1.80
|
|
|
|
|
0.50
|
|
|
|
1.22
|
|
|
|
1.01
|
|
|
|
0.42
|
|
Diluted
|
|
|
1.06
|
|
|
|
1.07
|
|
|
|
1.20
|
|
|
|
1.80
|
|
|
|
|
0.50
|
|
|
|
1.22
|
|
|
|
1.01
|
|
|
|
0.42
|
|
Cumulative effect of changes in
accounting method
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.9
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
78.2
|
|
|
$
|
35.6
|
|
|
$
|
40.5
|
|
|
$
|
53.6
|
|
|
|
$
|
14.9
|
|
|
$
|
38.2
|
|
|
$
|
30.0
|
|
|
$
|
12.4
|
|
Net income per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.07
|
|
|
$
|
1.10
|
|
|
$
|
1.24
|
|
|
$
|
1.80
|
|
|
|
$
|
0.50
|
|
|
$
|
1.29
|
|
|
$
|
1.01
|
|
|
$
|
0.42
|
|
Diluted
|
|
|
1.06
|
|
|
|
1.07
|
|
|
|
1.20
|
|
|
|
1.80
|
|
|
|
|
0.50
|
|
|
|
1.29
|
|
|
|
1.01
|
|
|
|
0.42
|
|
Capital Expenditure and
Disposal Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, including
leasehold/seismic
|
|
|
169.1
|
|
|
|
23.6
|
|
|
$
|
60.9
|
|
|
$
|
40.4
|
|
|
|
$
|
7.5
|
|
|
$
|
31.6
|
|
|
$
|
40.4
|
|
|
$
|
66.3
|
|
Development and other
|
|
|
347.9
|
|
|
|
106.8
|
|
|
|
191.8
|
|
|
|
93.2
|
|
|
|
|
7.8
|
|
|
|
51.7
|
|
|
|
65.7
|
|
|
|
98.2
|
|
Proceeds from property conveyances
|
|
|
(2.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(121.6
|
)
|
|
|
(52.3
|
)
|
|
|
(90.5
|
)
|
Total capital expenditures net of
proceeds from property conveyances
|
|
|
515.0
|
|
|
|
130.4
|
|
|
$
|
252.7
|
|
|
$
|
133.6
|
|
|
|
$
|
15.3
|
|
|
$
|
(38.3
|
)
|
|
$
|
53.8
|
|
|
$
|
74.0
|
|
11
|
|
|
(1) |
|
Includes effects of hedging. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions)
|
|
Balance Sheet
Data(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net, full
cost method
|
|
$
|
2,061.9
|
|
|
$
|
393.3
|
|
|
$
|
515.9
|
|
|
$
|
303.8
|
|
|
|
$
|
207.9
|
|
|
$
|
287.6
|
|
|
$
|
290.6
|
|
Total assets
|
|
|
2,700.7
|
|
|
|
502.2
|
|
|
|
665.5
|
|
|
|
376.0
|
|
|
|
|
312.1
|
|
|
|
360.2
|
|
|
|
363.9
|
|
Long-term debt, less current
maturities
|
|
|
614.0
|
|
|
|
79.0
|
|
|
|
156.0
|
|
|
|
115.0
|
|
|
|
|
|
|
|
|
99.8
|
|
|
|
99.8
|
|
Stockholders equity
|
|
|
1,267.1
|
|
|
|
178.6
|
|
|
|
213.3
|
|
|
|
133.9
|
|
|
|
|
218.2
|
|
|
|
170.1
|
|
|
|
180.1
|
|
Working capital (deficit)(2)
|
|
|
(75.3
|
)
|
|
|
(30.2
|
)
|
|
|
(46.4
|
)
|
|
|
(18.7
|
)
|
|
|
|
38.3
|
|
|
|
(24.4
|
)
|
|
|
(19.6
|
)
|
Other Financial
Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ratio of earnings to fixed
charges(3)
|
|
|
5.43
|
|
|
|
10.23
|
|
|
|
7.88
|
|
|
|
17.17
|
|
|
|
|
6.83
|
|
|
|
3.56
|
|
|
|
1.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Balance sheet data as of September 30, 2006 reflects
consolidation of the assets of the Forest Gulf of Mexico
operations effective March 2, 2006. 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. |
|
(3) |
|
For the purposes of determining the ratio of earnings to fixed
charges, earnings consist of income before taxes, plus fixed
charges, less capitalized interest, and fixed charges consist of
interest expense (net of capitalized interest), plus capitalized
interest, plus amortized discounts related to indebtedness. |
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions)
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$
|
340.7
|
|
|
$
|
102.7
|
|
|
$
|
130.4
|
|
|
$
|
143.5
|
|
|
|
$
|
33.4
|
|
|
$
|
100.3
|
|
|
$
|
113.9
|
|
|
$
|
113.6
|
|
Net cash provided by operating
activities
|
|
|
172.8
|
|
|
|
135.4
|
|
|
|
165.4
|
|
|
|
135.2
|
|
|
|
|
20.3
|
|
|
|
88.9
|
|
|
|
60.3
|
|
|
|
113.5
|
|
Net cash (used) provided by
investing activities
|
|
|
(423.5
|
)
|
|
|
(142.1
|
)
|
|
|
(247.8
|
)
|
|
|
(133.0
|
)
|
|
|
|
(15.3
|
)
|
|
|
52.9
|
|
|
|
(53.8
|
)
|
|
|
(74.0
|
)
|
Net cash (used) provided by
financing activities
|
|
|
251.0
|
|
|
|
8.7
|
|
|
|
84.4
|
|
|
|
64.9
|
|
|
|
|
|
|
|
|
(100.0
|
)
|
|
|
|
|
|
|
(30.0
|
)
|
Reconciliation of
Non-GAAP Measures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$
|
340.7
|
|
|
$
|
102.7
|
|
|
$
|
130.4
|
|
|
$
|
143.5
|
|
|
|
$
|
33.4
|
|
|
$
|
100.3
|
|
|
$
|
113.9
|
|
|
$
|
113.6
|
|
Changes in working capital
|
|
|
(158.9
|
)
|
|
|
25.1
|
|
|
|
20.0
|
|
|
|
6.2
|
|
|
|
|
(13.2
|
)
|
|
|
7.2
|
|
|
|
(20.4
|
)
|
|
|
7.5
|
|
Non-cash hedge gain/(loss)(2)
|
|
|
8.2
|
|
|
|
(3.6
|
)
|
|
|
(4.5
|
)
|
|
|
(7.9
|
)
|
|
|
|
|
|
|
|
(2.0
|
)
|
|
|
(23.2
|
)
|
|
|
|
|
Amortization/other
|
|
|
(0.3
|
)
|
|
|
0.9
|
|
|
|
1.2
|
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
0.6
|
|
Stock compensation expense
|
|
|
9.0
|
|
|
|
17.6
|
|
|
|
25.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense
|
|
|
(25.9
|
)
|
|
|
(4.7
|
)
|
|
|
(7.4
|
)
|
|
|
(5.8
|
)
|
|
|
|
0.1
|
|
|
|
(6.2
|
)
|
|
|
(9.9
|
)
|
|
|
(8.2
|
)
|
Income tax expense
|
|
|
|
|
|
|
(2.6
|
)
|
|
|
|
|
|
|
(1.6
|
)
|
|
|
|
|
|
|
|
(10.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
$
|
172.8
|
|
|
$
|
135.4
|
|
|
$
|
165.4
|
|
|
$
|
135.2
|
|
|
|
$
|
20.3
|
|
|
$
|
88.9
|
|
|
$
|
60.3
|
|
|
$
|
113.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
EBITDA means earnings before interest, income taxes,
depreciation, depletion and amortization and impairments. For
the nine months ended September 30, 2006 and 2005, EBITDA
includes $9.0 million and $17.6 million, respectively,
in non-cash compensation expense related to restricted stock and
stock options. For the year ended December 31, 2005, EBITDA
includes $25.7 million in non-cash 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 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 dedesignation 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. 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.
The value at the time of the merger and included in 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. |
13
Summary
Selected Unaudited Pro Forma Combined Condensed Financial
Information
The merger between a subsidiary of Mariner and Forest Energy
Resources was consummated on March 2, 2006. Accordingly,
actual balance sheet information of the combined company as of
September 30, 2006 is included elsewhere in this prospectus.
The following unaudited pro forma combined condensed operating
results for the nine months ended September 30, 2006 and
the year ended December 31, 2005 give effect to the merger
as if it had occurred on January 1, 2005. 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 36.
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.
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
Year Ended
|
|
|
|
Ended
|
|
|
December 31,
|
|
|
|
September 30, 2006
|
|
|
2005
|
|
|
|
(In millions, except earnings per share and share data)
|
|
|
OPERATING RESULTS:
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
505.9
|
|
|
$
|
592.0
|
|
Net income
|
|
|
92.6
|
|
|
|
58.0
|
|
Earnings per share
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.09
|
|
|
$
|
0.70
|
|
Diluted
|
|
$
|
1.09
|
|
|
$
|
0.69
|
|
Weighted average shares outstanding
|
|
|
|
|
|
|
|
|
Basic
|
|
|
84,770,289
|
|
|
|
83,304,592
|
|
Diluted
|
|
|
85,245,547
|
|
|
|
84,454,427
|
|
14
Summary
Reserve and Operating Data
The following tables present certain information with respect to
our estimated proved oil and natural gas reserves at year end
and operating data for the periods presented. The 2005
information is also presented on a pro forma basis, giving
effect to our merger with Forest Energy Resources as though it
had been consummated on January 1, 2005. We consummated the
merger on March 2, 2006.
Estimated
Proved Reserves
The reserve information in the table below for Mariner is based
on estimates made in reserve reports prepared by Ryder Scott.
The reserve information as of December 31, 2005 for the
Forest Gulf of Mexico operations is based on estimates made by
internal staff engineers at Forest, which estimates were audited
by Ryder Scott. Accordingly, the pro forma reserve information
presented below includes both reserves that were estimated by
Ryder Scott and reserves that were estimated by internal staff
engineers at Forest and audited by Ryder Scott.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
As of the Year Ended
|
|
|
|
Year Ended
|
|
|
December 31,
|
|
|
|
December 31, 2005
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Estimated proved oil and
natural gas reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas reserves (Bcf)
|
|
|
438.8
|
|
|
|
207.7
|
|
|
|
151.9
|
|
|
|
127.6
|
|
Oil (MMbbls)
|
|
|
34.1
|
|
|
|
21.6
|
|
|
|
14.3
|
|
|
|
13.1
|
|
Total proved oil and natural gas
reserves (Bcfe)
|
|
|
643.7
|
|
|
|
337.6
|
|
|
|
237.5
|
|
|
|
206.1
|
|
Total proved developed reserves
(Bcfe)
|
|
|
362.3
|
|
|
|
167.4
|
|
|
|
109.4
|
|
|
|
96.6
|
|
PV10 value ($ in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
$
|
2,023.4
|
|
|
$
|
849.6
|
|
|
$
|
335.4
|
|
|
$
|
314.6
|
|
Proved undeveloped reserves
|
|
|
1,028.4
|
|
|
|
432.2
|
|
|
|
332.6
|
|
|
|
218.9
|
|
Total PV10 value
|
|
|
3,051.8
|
|
|
|
1,281.8
|
|
|
|
668.0
|
|
|
|
533.5
|
|
Standardized measure
|
|
|
2,201.7
|
|
|
|
906.6
|
|
|
|
494.4
|
|
|
|
418.2
|
|
Prices used in calculating end
of period proved reserve measures (excluding effects of
hedging)(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/MMBtu)
|
|
$
|
10.05
|
|
|
$
|
10.05
|
|
|
$
|
6.15
|
|
|
$
|
5.96
|
|
Oil ($/bbl)
|
|
|
61.04
|
|
|
|
61.04
|
|
|
|
43.45
|
|
|
|
32.52
|
|
|
|
|
(1) |
|
Our PV10 values have been calculated using NYMEX prices at the
end of the relevant period, as adjusted for our price
differentials. Please read Note 11 to the audited Mariner
financial statements contained in this prospectus. |
15
Operating
Data
The following table presents certain information with respect to
our production and operating data for the periods presented.
Information for the nine months ended September 30, 2006
and the year ended December 31, 2005 also is presented on a
pro forma basis, giving effect to our merger with Forest Energy
Resources as though it had been consummated on January 1,
2005. The merger was consummated on March 2, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
Nine Months
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
Year Ended
|
|
|
Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
December 31,
|
|
|
September 30,
|
|
|
Year Ended December 31,
|
|
|
|
September 30, 2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf)
|
|
|
45.6
|
|
|
|
67.5
|
|
|
|
39.3
|
|
|
|
18.4
|
|
|
|
23.8
|
|
|
|
23.8
|
|
Oil (Mbbls)
|
|
|
2.8
|
|
|
|
4.6
|
|
|
|
2.5
|
|
|
|
1.8
|
|
|
|
2.3
|
|
|
|
1.6
|
|
Total natural gas equivalent (Bcfe)
|
|
|
62.4
|
|
|
|
94.9
|
|
|
|
54.5
|
|
|
|
29.1
|
|
|
|
37.6
|
|
|
|
33.4
|
|
Average daily natural gas
equivalent (MMcfe)
|
|
|
228.5
|
|
|
|
260.0
|
|
|
|
200.0
|
|
|
|
79.7
|
|
|
|
103.0
|
|
|
|
91.5
|
|
Average realized sales price
per unit (excluding the effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
7.25
|
|
|
$
|
8.04
|
|
|
$
|
7.05
|
|
|
$
|
8.33
|
|
|
$
|
6.12
|
|
|
$
|
5.43
|
|
Oil ($/bbl)
|
|
|
61.23
|
|
|
|
48.86
|
|
|
|
62.13
|
|
|
|
51.66
|
|
|
|
38.52
|
|
|
|
26.85
|
|
Total natural gas equivalent
($/Mcfe)
|
|
|
8.05
|
|
|
|
8.07
|
|
|
|
7.94
|
|
|
|
8.43
|
|
|
|
6.23
|
|
|
|
5.15
|
|
Average realized sales price
per unit (including the effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
7.42
|
|
|
$
|
6.40
|
|
|
$
|
7.25
|
|
|
$
|
6.66
|
|
|
$
|
5.80
|
|
|
$
|
4.40
|
|
Oil ($/bbl)
|
|
|
58.95
|
|
|
|
34.18
|
|
|
|
59.58
|
|
|
|
41.23
|
|
|
|
33.17
|
|
|
|
23.74
|
|
Total natural gas equivalent
($/Mcfe)
|
|
|
8.07
|
|
|
|
6.20
|
|
|
|
8.00
|
|
|
|
6.74
|
|
|
|
5.70
|
|
|
|
4.27
|
|
Expenses ($/Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.26
|
|
|
$
|
1.04
|
|
|
$
|
1.15
|
|
|
$
|
0.86
|
|
|
$
|
0.61
|
|
|
$
|
0.69
|
|
Severance and ad valorem taxes
|
|
|
0.10
|
|
|
|
0.13
|
|
|
|
0.10
|
|
|
|
0.17
|
|
|
|
0.07
|
|
|
|
0.05
|
|
Transportation
|
|
|
0.07
|
|
|
|
0.06
|
|
|
|
0.07
|
|
|
|
0.08
|
|
|
|
0.08
|
|
|
|
0.19
|
|
General and administrative, net(1)
|
|
|
|
|
|
|
|
|
|
|
0.46
|
|
|
|
1.27
|
|
|
|
0.23
|
|
|
|
0.24
|
|
Depreciation, depletion and
amortization (excluding impairments)(2)
|
|
|
3.51
|
|
|
|
3.47
|
|
|
|
3.53
|
|
|
|
2.04
|
|
|
|
1.73
|
|
|
|
1.45
|
|
|
|
|
(1) |
|
Net of overhead reimbursements received from other working
interest owners and amounts capitalized under the full cost
accounting method. Includes non-cash stock compensation expense
of $9.0 million for the nine months ended
September 30, 2006 and $17.6 million in 2005. General
and administrative expenses, net of capitalized amounts, are not
included in pro forma 2005 because accounts of such costs were
not historically maintained for the Forest Gulf of Mexico
operations as a separate business unit. We |
16
|
|
|
|
|
believe the overhead costs associated with the Forest Gulf of
Mexico operations in 2006 will approximate $6.4 million,
net of capitalized amounts. |
|
(2) |
|
Pro forma depreciation, depletion and amortization gives effect
to the acquisition of the Forest Gulf of Mexico operations and a
preliminary estimate of their
step-up in
value basis the unit of production method under the full cost
method of accounting. |
17
RISK
FACTORS
You should consider carefully the following risks, as well as
the other information set forth in this prospectus, before
deciding to participate in the exchange offer. Any of the
following risks could materially adversely affect our business,
financial condition or results of operations, which in turn
could adversely affect our ability to pay the notes. In such
case, you may lose all or part of your original investment.
Risks
Related to the Exchange Offer
If you
do not properly tender your old notes, you will continue to hold
unregistered outstanding notes and your ability to transfer
those notes will be adversely affected.
If you do not exchange your old notes for new notes in the
exchange offer, you will continue to be subject to the
restrictions on transfer of your old notes described in the
legend on the certificates representing your old notes. In
general, you may only offer or sell the old notes if they are
registered under the Securities Act and applicable state
securities laws or offered and sold under an exemption from
those requirements. We do not plan to register any sale of the
old notes under the Securities Act unless required to do so
under the limited circumstances set forth in the registration
rights agreement. In addition, the issuance of the new notes may
adversely affect the trading market for untendered, or tendered
but unaccepted, old notes. For further information regarding the
consequences of not tendering your old notes in the exchange
offer, see The Exchange Offer Consequences of
Failure to Exchange and Material United States
Federal Income Tax Considerations.
We will only issue new notes in exchange for old notes that you
timely and properly tender. Therefore, you should allow
sufficient time to ensure timely delivery of the old notes and
you should carefully follow the instructions on how to tender
your old notes. Neither we nor the exchange agent is required to
tell you of any defects or irregularities with respect to your
tender of old notes. See The Exchange Offer
Procedures for Tendering Old Notes and Description
of Senior Notes.
You
may find it difficult to sell your new notes.
Because there is no public market for the new notes, you may not
be able to resell them. The new notes will be registered under
the Securities Act but will constitute a new issue of securities
with no established trading market. An active market may not
develop for the new notes and any trading market that does
develop may not be liquid. We do not intend to apply to list the
new notes for trading on any securities exchange or to arrange
for quotation on any automated dealer quotation system. The
trading market for the new notes may be adversely affected by:
|
|
|
|
|
changes in the overall market for non-investment grade
securities;
|
|
|
|
changes in our financial performance or prospects;
|
|
|
|
the prospects for companies in our industry generally;
|
|
|
|
the number of holders of the new notes;
|
|
|
|
the interest of securities dealers in making a market for the
new notes; and
|
|
|
|
prevailing interest rates and general economic conditions.
|
Historically, the market for non-investment grade debt has been
subject to substantial volatility in prices. The market for the
new notes, if any, may be subject to similar volatility.
Prospective investors in the new notes should be aware that they
may be required to bear the financial risks of such investment
for an indefinite period of time.
Some
holders who exchange their old notes may be deemed to be
underwriters.
If you exchange your old notes in the exchange offer for the
purpose of participating in a distribution of the new notes, you
may be deemed to have received restricted securities and, if so,
will be required to comply
18
with the registration and prospectus delivery requirements of
the Securities Act in connection with any resale transaction.
See The Exchange Offer Resale of the New
Notes; Plan of Distribution.
Risks
Relating to the Oil and Natural Gas Industry and to Our
Business
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 62% of our estimated proved reserves (68% on a pro
forma basis) as of December 31, 2005 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, 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 project production rates
and timing of development expenditures. We also analyze the
available geological, geophysical, production 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 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
19
other factors, many of which are beyond our control. At
December 31, 2005, 50% of our estimated proved reserves
were proved undeveloped (44% on a pro forma basis).
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 Business Estimated Proved
Reserves for information about our oil and gas reserves.
In
estimating future net revenues from proved reserves, we assume
that future prices and costs are fixed and apply a fixed
discount factor. If any such assumption or the discount factor
is 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 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 base the
estimated discounted future net cash flows from our proved
reserves 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 Minerals Management
Service, or 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 Business Royalty
Relief, and Business Legal
Proceedings. 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 their present value. In addition, the
10% discount factor that we 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.
If oil
and natural gas prices decrease, we may be required to
write-down the carrying value
and/or the
estimates of total reserves of our oil and natural gas
properties.
Accounting rules applicable to us require that we review
periodically the carrying value of our oil and natural gas
properties for possible impairment. Based on specific market
factors and circumstances at the time of prospective impairment
reviews and the continuing evaluation of development plans,
production data, economics and other factors, we may be required
to write-down the carrying value of our oil and natural gas
properties. A write-down constitutes a non-cash charge to
earnings. We may incur non-cash charges in the future, which
could have a material adverse effect on our results of
operations in the period taken. We may also reduce our estimates
of the reserves that may be economically recovered, which could
have the effect of reducing the value of our reserves.
We
need to replace our reserves at a faster rate than companies
whose reserves have longer production periods. Our failure to
replace our reserves would result in decreasing reserves and
production over time.
Unless we conduct successful exploration and development
activities or acquire properties containing proven reserves, our
proved reserves will decline as reserves are depleted. Producing
oil and natural gas reserves are generally characterized by
declining production rates that vary depending on reservoir
characteristics and other factors. High production rates
generally result in recovery of a relatively higher percentage
of reserves from properties during the initial few years of
production. A significant portion of our current operations are
conducted in the Gulf of Mexico, especially since our merger
with Forest Energy Resources. Production from reserves in the
Gulf of Mexico generally declines more rapidly than reserves
from reservoirs in other producing regions. As a result, our
need to replace reserves from new investments is relatively
greater than those of producers who produce their reserves over
a longer time period, such as those
20
producers whose reserves are located in areas where the rate of
reserve production is lower. If we are not able to find, develop
or acquire additional reserves to replace our current and future
production, our production rates will decline even if we drill
the undeveloped locations that were included in our proved
reserves. Our future oil and natural gas reserves and
production, and therefore our cash flow and income, are
dependent on our success in economically finding or acquiring
new reserves and efficiently developing our existing reserves.
Approximately
65% of our total estimated proved reserves are either developed
non-producing or undeveloped (71% on a pro forma basis), and
those reserves may not ultimately be produced or
developed.
As of December 31, 2005, approximately 15% of our total
estimated proved reserves were developed non-producing (27% on a
pro forma basis) and approximately 50% were undeveloped (44% on
a pro forma basis). These reserves may not ultimately be
developed or produced. Furthermore, not all of our undeveloped
or developed non-producing reserves may be ultimately produced
during the time periods we have planned, at the costs we have
budgeted, or at all, which in turn may have in a material
adverse effect on our results of operations.
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 is 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.
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:
|
|
|
|
|
unexpected drilling conditions;
|
|
|
|
pressure or irregularities in formations;
|
|
|
|
equipment failures or accidents;
|
|
|
|
adverse weather conditions, including hurricanes, which are
common in the Gulf of Mexico during certain times of the year;
|
|
|
|
compliance with governmental regulations;
|
|
|
|
unavailability or high cost of drilling rigs, equipment or labor;
|
|
|
|
reductions in oil and natural gas prices; and
|
|
|
|
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.
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
21
techniques only assist geoscientists and geologists in
identifying subsurface structures and hydrocarbon indicators.
3-D seismic
data does not enable an interpreter to conclusively determine
whether hydrocarbons are present or producible economically. In
addition, the use of
3-D seismic
and other advanced technologies require greater predrilling
expenditures than other 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.
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:
|
|
|
|
|
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, such as hurricanes and other adverse weather
conditions;
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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.
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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.
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 our operations, see Managements
Discussion and Analysis of Financial Condition and Results of
Operations Recent Developments.
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 utilize
subsea completion and tieback technology. As of
September 30, 2006, we had 18 subsea wells. These
wells were tied back to 13 host production facilities for
production processing. An additional nine wells were then under
development for tieback to five additional host production
facilities. The installation of subsea production systems to
tieback and operate subsea wells requires substantial time and
the use of advanced and very sophisticated installation
equipment supported by remotely operated vehicles. These
operations may encounter mechanical difficulties and equipment
failures that could result in significant cost overruns.
Furthermore, the deepwater operations generally lack the
physical
22
and oilfield service infrastructure present in the 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.
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, our hedging arrangements reduced the
benefit we received from increases in the prices for oil and
natural gas by approximately $49 million for the calendar
year 2005 and increased the benefit we received by $1.5 million
for the nine months ended September 30, 2006. 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.
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, exploration arrangements with other
parties, the issuance of debt securities, 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.
Properties
we acquire (including the Forest Gulf of Mexico properties we
acquired in March 2006) 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 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
23
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.
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.
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 in availability 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.
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.
Financial
difficulties encountered by our farm-out partners or third-party
operators could adversely affect our ability to timely complete
the exploration and development of our prospects.
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
24
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.
We
cannot control the timing or scope of drilling and development
activities on properties we do not operate, and therefore we may
not be in a position to control 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.
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, or 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 Business Regulation
for more information on our regulatory and environmental matters.
Compliance
with MMS regulations could significantly delay or curtail our
operations or require us to make material expenditures, all of
which could have a material adverse effect on our financial
condition or results of operations.
A significant portion of our operations are located on federal
oil and natural gas leases that are administered by the MMS. As
an offshore operator, we must obtain MMS approval for our
exploration, development and production plans prior to
commencing such operations. The MMS has promulgated regulations
that, among other things, require us to meet stringent
engineering and construction specifications, restrict the
flaring or venting of natural gas, govern the plug and
abandonment of wells located offshore and
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the installation and removal of all production facilities, and
govern the calculation of royalties and the valuation of crude
oil produced from federal leases.
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 which 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. In addition,
we have not yet been able to determine the full extent of our
insurance recovery and the net cost to us resulting from the
hurricanes. See Business Insurance
Matters for more information.
Risks
Relating to Our Merger with Forest Energy Resources
The
integration of the Forest Gulf of Mexico operations 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 prior to the merger;
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the possibility of faulty assumptions underlying our
expectations;
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the difficulty associated with coordinating geographically
separate organizations;
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the challenge of integrating the business cultures of the two
companies;
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attracting and retaining personnel associated with the Forest
Gulf of Mexico operations following the merger; and
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the challenge and cost of integrating the information technology
systems of the two companies.
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The process of integrating our 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.
If we
fail to realize the anticipated benefits of the merger, our
results of operations may be lower than we 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
26
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, our results
of operations may be adversely affected.
We
expect to incur significant charges relating to the integration
plan that could materially and adversely affect our
period-to-period
results of operations.
We anticipate that from time to time we will incur charges to
our earnings in connection with the integration of the Forest
Gulf of Mexico operations into our business. 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 are not yet able to quantify the
costs or timing of the integration. Some factors affecting the
cost of the integration include 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 were provided by Forest. During the
nine months ended September 30, 2006, we incurred
approximately $2.6 million of such costs.
In
order to preserve the tax-free treatment of the spin-off of
Forest Energy Resources, we are 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.
In connection with the merger we entered into a tax sharing
agreement, which imposes ongoing restrictions on Forest and on
us to ensure that applicable statutory requirements under the
Internal Revenue Code of 1986, as amended, or the Code, and
applicable Treasury regulations continue to be met so that the
spin-off of Forest Energy Resources 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 could have a negative impact on our business.
Risks
Relating to the Notes
We may
not be able to generate enough cash flow to meet our debt
obligations.
We expect our earnings and cash flow to vary significantly from
year to year due to the cyclical nature of our industry. As a
result, the amount of debt that we can manage in some periods
may not be appropriate for us in other periods. Additionally,
our future cash flow may be insufficient to meet our debt
obligations and commitments, including the notes. Any
insufficiency could negatively impact our business. A range of
economic, competitive, business and industry factors will affect
our future financial performance, and, as a result, our ability
to generate cash flow from operations and to pay our debt,
including the notes. Many of these factors, such as oil and gas
prices, economic and financial conditions in our industry and
the global economy or competitive initiatives of our
competitors, are beyond our control.
27
If we do not generate enough cash flow from operations to
satisfy our debt obligations, we may have to undertake
alternative financing plans, such as:
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refinancing or restructuring our debt;
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selling assets;
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reducing or delaying capital investments; or
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seeking to raise additional capital.
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However, we cannot assure you that undertaking alternative
financing plans, if necessary, would allow us to meet our debt
obligations. Our inability to generate sufficient cash flow to
satisfy our debt obligations, including our obligations under
the notes, or to obtain alternative financing, could materially
and adversely affect our business, financial condition, results
of operations and prospects.
The
notes and the guarantees will be unsecured and effectively
subordinated to our and our subsidiary guarantors existing
and future secured indebtedness.
The notes and the guarantees are general unsecured senior
obligations ranking effectively junior in right of payment to
all existing and future secured debt of ours and that of each
subsidiary guarantor, respectively, including obligations under
our credit facility, to the extent of the value of the
collateral securing the debt. As of September 30, 2006,
after giving effect to borrowings under our amended and restated
credit facility and to the offering of the old notes and the
application of the proceeds therefrom, our total indebtedness
was $614.0 million, $300.0 million of which was the
old notes and $314.0 million of which effectively was
senior in right of payment to the notes to the extent of the
value of the collateral securing that indebtedness. We also then
had three letters of credit outstanding for $40.0 million,
$10.4 million and $4.2 million, each of which
effectively is senior to the notes to the extent of the
collateral securing such indebtedness. Further, we then had
$121.4 million in additional borrowing capacity under our
credit facility which if borrowed would have been secured debt
effectively senior in right of payment to the notes to the
extent of the value of the collateral securing that indebtedness.
If we or a subsidiary guarantor are declared bankrupt, become
insolvent or are liquidated or reorganized, any secured debt of
ours or that subsidiary guarantor will be entitled to be paid in
full from our assets or the assets of the guarantor, as
applicable, securing that debt before any payment may be made
with respect to the notes or the affected guarantees. Holders of
the notes participate ratably with all holders of our unsecured
indebtedness that does not rank junior to the notes, including
all of our other general creditors, based upon the respective
amounts owed to each holder or creditor, in our remaining
assets. In any of the foregoing events, we cannot assure you
that there will be sufficient assets to pay amounts due on the
notes. As a result, holders of the notes would likely receive
less, ratably, than holders of secured indebtedness.
Our
debt level and the covenants in the agreements governing our
debt could negatively impact our financial condition, results of
operations and business prospects and prevent us from fulfilling
our obligations under the notes.
Our level of indebtedness, and the covenants contained in the
agreements governing our debt, could have important consequences
for our operations, including by:
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making it more difficult for us to satisfy our obligations under
the notes or other debt and increasing the risk that we may
default on our debt obligations;
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requiring us to dedicate a substantial portion of our cash flow
from operations to required payments on debt, thereby reducing
the availability of cash flow for working capital, capital
expenditures and other general business activities;
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limiting our ability to obtain additional financing in the
future for working capital, capital expenditures, acquisitions
and general corporate and other activities;
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limiting managements discretion in operating our business;
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limiting our flexibility in planning for, or reacting to,
changes in our business and the industry in which we operate;
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detracting from our ability to withstand successfully a downturn
in our business or the economy generally;
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placing us at a competitive disadvantage against less leveraged
competitors; and
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making us vulnerable to increases in interest rates, because
debt under our credit facility will in some cases vary with
prevailing interest rates.
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We may be required to repay all or a portion of our debt on an
accelerated basis in certain circumstances. If we fail to comply
with the covenants and other restrictions in the agreements
governing our debt, it could lead to an event of default and the
consequent acceleration of our obligation to repay outstanding
debt. Our ability to comply with these covenants and other
restrictions may be affected by events beyond our control,
including prevailing economic and financial conditions.
In addition, under the terms of our credit facility and the
indenture, we must comply with certain financial covenants,
including current asset and total debt ratio requirements. Our
ability to comply with these covenants in future periods will
depend on our ongoing financial and operating performance, which
in turn will be subject to general economic conditions and
financial, market and competitive factors, in particular the
selling prices for our products and our ability to successfully
implement our overall business strategy.
The breach of any of the covenants in the indenture or the
credit facility could result in a default under the applicable
agreement which would permit the applicable lenders or
noteholders, as the case may be, to declare all amounts
outstanding thereunder to be due and payable, together with
accrued and unpaid interest. We may not have sufficient funds to
make such payments. If we are unable to repay our debt out of
cash on hand, we could attempt to refinance such debt, sell
assets or repay such debt with the proceeds from an equity
offering. We cannot assure you that we will be able to generate
sufficient cash flow to pay the interest on our debt or that
future borrowings, equity financings or proceeds from the sale
of assets will be available to pay or refinance such debt. The
terms of our debt, including our credit facility, may also
prohibit us from taking such actions. Factors that will affect
our ability to raise cash through an offering of our capital
stock, a refinancing of our debt or a sale of assets include
financial market conditions, restrictions in our tax sharing
agreement with Forest and the value of our assets and operating
performance at the time of such offering or other financing. We
cannot assure you that any such offering, refinancing or sale of
assets could be successfully completed.
Our
variable rate indebtedness subjects us to interest rate risk,
which could cause our debt service obligations to increase
significantly.
Borrowings under our credit facility bear interest at variable
rates and expose us to interest rate risk. If interest rates
increase, our debt service obligations on the variable rate
indebtedness would increase even though the amount borrowed
remained the same, and our net income and cash available for
servicing our indebtedness would decrease.
Despite
our and our subsidiaries current level of indebtedness, we
may still be able to incur substantially more debt. This could
further exacerbate the risks associated with our substantial
indebtedness.
We and our subsidiaries may be able to incur substantial
additional indebtedness in the future, subject to certain
limitations. The terms of our indenture will not prohibit us or
our subsidiaries from doing so. For example, as of
September 30, 2006, we were able to borrow up to
$362.5 million on a revolving basis under our credit
facility that was increased to $450 million in October
2006. If new debt is added to our current debt levels, the
related risks that we and our subsidiaries now face could
intensify. Our level of indebtedness could, for instance,
prevent us from engaging in transactions that might otherwise be
beneficial to us or from making desirable capital expenditures.
This could put us at a competitive disadvantage relative to
other less leveraged competitors that have more cash flow to
devote to their operations. In addition, the incurrence of
additional
29
indebtedness could make it more difficult to satisfy our
existing financial obligations, including those relating to the
notes.
We may
not be able to repurchase the notes upon a change of
control.
Upon the occurrence of certain change of control events, we are
required to offer to repurchase all or any part of the notes
then outstanding for cash at 101% of the principal amount. The
source of funds for any repurchase required as a result of any
change of control will be our available cash or cash generated
from our operations or other sources, including:
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borrowings under our credit facilities or other sources;
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sales of assets; or
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sales of equity.
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We cannot assure you that sufficient funds would be available at
the time of any change of control to repurchase your notes. In
addition, our credit facility prohibits, and any future credit
facilities may prohibit, such repurchases. Additionally, a
change of control (as defined in the indenture for
the notes) will be an event of default under our credit facility
that would permit the lenders to accelerate the debt outstanding
under the credit facility. Finally, using available cash to fund
the potential consequences of a change of control may impair our
ability to obtain additional financing in the future, which
could negatively impact our ability to conduct our business
operations.
A
subsidiary guarantee could be voided if it constitutes a
fraudulent transfer under U.S. bankruptcy or similar state
law, which would prevent the holders of the notes from relying
on that subsidiary to satisfy claims.
Under U.S. bankruptcy law and comparable provisions of
state fraudulent transfer laws, our subsidiary guarantees can be
voided, or claims under the subsidiary guarantees may be
subordinated to all other debts of that subsidiary guarantor if,
among other things, the subsidiary guarantor, at the time it
incurred the indebtedness evidenced by its guarantee or, in some
states, when payments become due under the guarantee, received
less than reasonably equivalent value or fair consideration for
the incurrence of the guarantee and:
|
|
|
|
|
was insolvent or rendered insolvent by reason of such incurrence;
|
|
|
|
was engaged in a business or transaction for which the
guarantors remaining assets constituted unreasonably small
capital; or
|
|
|
|
intended to incur, or believed that it would incur, debts beyond
its ability to pay those debts as they mature.
|
Our subsidiary guarantees may also be voided, without regard to
the above factors, if a court found that the subsidiary
guarantor entered into the guarantee with the actual intent to
hinder, delay or defraud its creditors.
A court would likely find that a subsidiary guarantor did not
receive reasonably equivalent value or fair consideration for
its guarantee if the subsidiary guarantor did not substantially
benefit directly or indirectly from the issuance of the
guarantees. If a court were to void a subsidiary guarantee, you
would no longer have a claim against the subsidiary guarantor.
Sufficient funds to repay the notes may not be available from
other sources, including the remaining subsidiary guarantors, if
any. In addition, the court might direct you to repay any
amounts that you already received from the subsidiary guarantor.
The measures of insolvency for purposes of fraudulent transfer
laws vary depending upon the governing law. Generally, a
guarantor would be considered insolvent if:
|
|
|
|
|
the sum of its debts, including contingent liabilities, were
greater than the fair saleable value of all its assets;
|
30
|
|
|
|
|
the present fair saleable value of its assets is less than the
amount that would be required to pay its probable liability on
its existing debts, including contingent liabilities, as they
become absolute and mature; or
|
|
|
|
it could not pay its debts as they become due.
|
Each subsidiary guarantee contains a provision intended to limit
the subsidiary guarantors liability to the maximum amount
that it could incur without causing the incurrence of
obligations under its subsidiary guarantee to be a fraudulent
transfer. Such provision may not be effective to protect the
subsidiary guarantees from being voided under fraudulent
transfer law.
A
financial failure by us or our subsidiaries may result in the
assets of any or all of those entities becoming subject to the
claims of all creditors of those entities.
A financial failure by us or our subsidiaries could affect
payment of the notes if a bankruptcy court were to substantively
consolidate us and our subsidiaries. If a bankruptcy court
substantively consolidated us and our subsidiaries, the assets
of each entity would become subject to the claims of creditors
of all entities. This would expose holders of notes not only to
the usual impairments arising from bankruptcy, but also to
potential dilution of the amount ultimately recoverable because
of the larger creditor base. Furthermore, forced restructuring
of the notes could occur through the cram-down
provisions of the bankruptcy code. Under these provisions, the
notes could be restructured over your objections as to their
general terms, primarily interest rate and maturity.
31
THE
EXCHANGE OFFER
This section of the prospectus describes certain aspects of
the exchange offer which expired on November 9, 2006. Each
broker-dealer (other than an affiliate of ours) that receives
new notes for its own account in the exchange offer in exchange
for securities that were acquired by such broker-dealer as a
result of market-making or other trading activities must deliver
a prospectus meeting the requirements of the Securities Act of
1933 in connection with any resale of new notes. We have agreed
that, for a period of 90 days after the exchange date, we
will make the prospectus available to any broker-dealer for use
in connection with any such resale. While we believe that this
description covers the material terms of the exchange offer that
may remain relevant notwithstanding expiration or the exchange
offer, this summary may not contain all of the information that
is important to you. You should carefully read this entire
document.
Purpose
and Effects of the Exchange Offer
We initially issued $300.0 million principal amount of old
notes on April 24, 2006 in a private offering. The initial
purchasers subsequently offered and sold a portion of the old
notes only to qualified institutional buyers as
defined in and in compliance with Rule 144A and outside the
United States in compliance with Regulation S of the
Securities Act.
In connection with the sale of the old notes, we entered into an
exchange and registration rights agreement, which requires us
|
|
|
|
|
to cause the old notes to be registered under the Securities
Act, or
|
|
|
|
to file with the SEC a registration statement under the
Securities Act with respect to an issue of new notes identical
in all material respects to the old notes, and
|
|
|
|
use our commercially reasonable efforts to cause such
registration statement to become effective under the Securities
Act, and
|
|
|
|
upon the effectiveness of that registration statement, to offer
to the holders of the old notes the opportunity to exchange
their old notes for a like principal amount of new notes, which
will be issued without a restrictive legend and which may be
reoffered and resold by the holder without restrictions or
limitations under the Securities Act.
|
We made the exchange offer to satisfy our obligations under the
exchange and registration rights agreement. The term
holder with respect to the exchange offer means any
person in whose name old notes are registered on our or the
Depository Trust Companys (DTC) books or any
other person who has obtained a properly completed bond power
from the registered holder, or any person whose old notes are
held of record by DTC who desires to deliver such old notes by
book-entry transfer at DTC.
We have not requested, and do not intend to request, an
interpretation by the staff of the SEC with respect to whether
the new notes issued in the exchange offer in exchange for the
old notes may be offered for sale, resold or otherwise
transferred by any holder without compliance with the
registration and prospectus delivery provisions of the
Securities Act. Based on interpretations by the staff of the SEC
set forth in no-action letters issued to third parties, we
believe the new notes issued in exchange for old notes may be
offered for resale, resold and otherwise transferred by any
holder without compliance with the registration and prospectus
delivery provisions of the Securities Act provided that:
|
|
|
|
|
you are not a broker-dealer who purchased old notes directly
from us for resale pursuant to Rule 144A or any other
available exemption under the Securities Act,
|
|
|
|
you are not our or any subsidiary guarantors
affiliate, or
|
|
|
|
you acquire the new notes in the ordinary course of your
business and that you have no arrangement or understanding with
any person to participate in the distribution of the new notes.
|
Any holder who tenders in the exchange offer with the intention
to participate, or for the purpose of participating, in a
distribution of the new notes or who is our affiliate may not
rely upon such interpretations by the staff of the SEC and, in
the absence of an exemption, must comply with the registration
and prospectus
32
delivery requirements of the Securities Act in connection with
any secondary resale transaction. Any holder to comply with such
requirements may incur liabilities under the Securities Act for
which the holder is not indemnified by us.
Resale of
the New Notes; Plan of Distribution
Each broker-dealer that receives new notes for its own account
pursuant to the exchange offer must acknowledge that it will
deliver a prospectus in connection with any resale of new notes.
This prospectus, as it may be amended or supplemented from time
to time, may be used by a broker-dealer in connection with
resales of new notes received in exchange for old notes where
such old notes were acquired as a result of market-making
activities or other trading activities. In addition, until
January 8, 2007, all dealers effecting transactions in the
new notes, whether or not participating in this distribution,
may be required to deliver a prospectus. This requirement is in
addition to the obligation of dealers to deliver a prospectus
when acting as underwriters and with respect to their unsold
allotments or subscriptions.
We will not receive any proceeds from any sale of new notes by
broker-dealers. New notes received by broker-dealers for their
own account pursuant to the exchange offer may be sold from time
to time in one or more transactions:
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|
|
|
|
in the
over-the-counter
market,
|
|
|
|
in negotiated transactions,
|
|
|
|
through the writing of options on the new notes or a combination
of such methods of resale,
|
|
|
|
at market prices prevailing at the time of resale,
|
|
|
|
at prices related to such prevailing market prices, or
|
|
|
|
at negotiated prices.
|
Any such resale may be made directly to purchasers or to or
through brokers or dealers who may receive compensation in the
form of commissions or concessions from any such broker-dealer
or the purchasers of any such new notes.
Any broker-dealer that resells new notes received for its own
account pursuant to the exchange offer and any broker or dealer
that participates in a distribution of such new notes may be
deemed to be an underwriter within the meaning of
the Securities Act and any profit on any such resale of new
notes and any commission on concessions received by any such
persons may be deemed to be underwriting compensation under the
Securities Act. The letter of transmittal states that, by
acknowledging that it will deliver a prospectus and by
delivering a prospectus, a broker-dealer will not be deemed to
admit that it is an underwriter within the meaning
of the Securities Act.
33
USE OF
PROCEEDS
The exchange offer was intended to satisfy our obligations under
the registration rights agreement. We will not receive any
proceeds from the issuance of the new notes in the exchange
offer. In consideration for issuing the new notes as
contemplated in this prospectus, we will receive, in exchange,
outstanding old notes in like principal amount. We will cancel
all old notes surrendered in exchange for new notes in the
exchange offer. As a result, the issuance of the new notes will
not result in any increase or decrease in our indebtedness.
The net proceeds from the offering of the sale of the old notes
in the initial private placement were approximately
$287.9 million. We used those proceeds, together with cash
on hand, to repay borrowings under our amended and restated
credit facility. The borrowings under the credit facility were
used to:
|
|
|
|
|
refinance indebtedness incurred by Forest Energy Resources in
connection its acquisition by us.
|
|
|
|
pay transaction expenses associated with the merger; and
|
|
|
|
repay $165.0 million under our prior credit facility with
Union Bank of California.
|
34
CAPITALIZATION
The following table sets forth our consolidated capitalization
as of September 30, 2006.
This table should be read together with our financial statements
and the related notes included in this prospectus.
|
|
|
|
|
|
|
As of September 30,
|
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Long-term debt:
|
|
|
|
|
Credit facility
revolving note(1)
|
|
$
|
314,000
|
|
Senior Notes
|
|
|
300,000
|
|
Total long-term debt
|
|
|
614,000
|
|
Stockholders Equity
|
|
$
|
1,267,062
|
|
Total capitalization
|
|
$
|
1,881,062
|
|
|
|
|
(1) |
|
In connection with our merger with Forest Energy Resources on
March 2, 2006, we amended and restated our existing secured
credit facility to, among other things, increase maximum credit
availability to $500 million for revolving loans, including
up to $50 million in letters of credit, with a
$400 million borrowing base as of that date; add an
additional dedicated $40 million letter of credit facility
that does not affect the borrowing base; and add Mariner Energy
Resources, Inc. as a co-borrower. Our credit facility was
further amended in April 2006 to increase the borrowing base to
$430 million which subsequently automatically reduced to
$362.5 million upon closing of the offering of the old
notes and then was increased to $450 million in
October 2006, subject to redetermination or adjustment. The
revolving credit facility matures on March 2, 2010. At
September 30, 2006, approximately $328.6 million was
outstanding under the revolving credit facility, including two
letters of credit for $4.2 million and $10.4 million.
The $40 million letter of credit outstanding as of
September 30, 2006 under the dedicated letter of credit
facility matures on March 2, 2009. See
Managements Discussion and Analysis of Financial
Condition and Results of Operations Credit
Facility for more information. |
35
UNAUDITED
PRO FORMA COMBINED CONDENSED FINANCIAL INFORMATION
The merger between a subsidiary of Mariner and Forest Energy
Resources was consummated on March 2, 2006. Accordingly,
actual balance sheet information of the combined company as of
September 30, 2006 is included elsewhere in this prospectus.
The following unaudited pro forma combined statements of
operations and explanatory notes present how the combined
statements of Mariner and the Forest Gulf of Mexico operations
may have appeared had the businesses actually been combined as
of January 1, 2005.
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 elsewhere in this
prospectus. 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.
36
MARINER
ENERGY, INC.
UNAUDITED
PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS
For the
Nine Months Ended September 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest Energy
|
|
|
|
|
|
Mariner
|
|
|
|
Mariner
|
|
|
Resources, Inc.
|
|
|
Merger
|
|
|
Pro Forma
|
|
|
|
Historical(1)
|
|
|
Historical(2)
|
|
|
Adjustments(3)
|
|
|
Combined
|
|
|
|
(In thousands, except share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & gas sales
|
|
$
|
211,587
|
|
|
$
|
291,885
|
|
|
|
|
|
|
$
|
503,472
|
|
Other revenues
|
|
|
2,401
|
|
|
|
|
|
|
|
|
|
|
|
2,401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
213,988
|
|
|
|
291,885
|
|
|
|
|
|
|
|
505,873
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
27,089
|
|
|
|
51,765
|
|
|
|
|
|
|
|
78,854
|
|
Severance and ad valorem taxes
|
|
|
5,205
|
|
|
|
1,203
|
|
|
|
|
|
|
|
6,408
|
|
Transportation expenses
|
|
|
2,728
|
|
|
|
1,458
|
|
|
|
|
|
|
|
4,186
|
|
General and administrative expenses
|
|
|
23,872
|
|
|
|
809
|
|
|
|
|
(4)
|
|
|
24,681
|
|
Depreciation, depletion and
amortization
|
|
|
82,194
|
|
|
|
|
|
|
|
136,797
|
(5)
|
|
|
218,991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
141,088
|
|
|
|
55,235
|
|
|
|
136,797
|
|
|
|
333,120
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
72,900
|
|
|
|
236,650
|
|
|
|
(136,797
|
)
|
|
|
172,753
|
|
Interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
487
|
|
|
|
|
|
|
|
|
|
|
|
487
|
|
Expense, net of amounts capitalized
|
|
|
(17,693
|
)
|
|
|
|
|
|
|
(10,786
|
)(6)
|
|
|
(28,479
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before taxes
|
|
|
55,694
|
|
|
|
236,650
|
|
|
|
(147,583
|
)
|
|
|
144,761
|
|
Provision for income
taxes
|
|
|
(20,966
|
)
|
|
|
|
|
|
|
(31,173
|
)(7)
|
|
|
(52,139
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
34,728
|
|
|
$
|
236,650
|
|
|
$
|
(178,756
|
)
|
|
$
|
92,622
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per
share basic
|
|
$
|
1.02
|
|
|
|
|
|
|
|
|
|
|
$
|
1.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per
share diluted
|
|
$
|
1.00
|
|
|
|
|
|
|
|
|
|
|
$
|
1.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding basic
|
|
|
34,133,279
|
|
|
|
|
|
|
|
50,637,010
|
|
|
|
84,770,289
|
|
Weighted average shares
outstanding diluted
|
|
|
34,557,697
|
|
|
|
|
|
|
|
50,687,850
|
|
|
|
85,245,547
|
|
37
MARINER
ENERGY, INC.
UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF
OPERATIONS
For the Year Ended December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest Energy
|
|
|
|
|
|
Mariner
|
|
|
|
Mariner
|
|
|
Resources, Inc.
|
|
|
Merger
|
|
|
Pro Forma
|
|
|
|
Historical(1)
|
|
|
Historical(2)
|
|
|
Adjustments(3)
|
|
|
Combined
|
|
|
|
(In thousands, except share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & gas sales
|
|
$
|
196,122
|
|
|
$
|
392,272
|
|
|
$
|
|
|
|
$
|
588,394
|
|
Other revenues
|
|
|
3,588
|
|
|
|
|
|
|
|
|
|
|
|
3,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
199,710
|
|
|
|
392,272
|
|
|
|
|
|
|
|
591,982
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
24,882
|
|
|
|
78,001
|
|
|
|
|
|
|
|
102,883
|
|
Severance and ad valorem taxes
|
|
|
5,000
|
|
|
|
2,738
|
|
|
|
|
|
|
|
7,738
|
|
Transportation expenses
|
|
|
2,336
|
|
|
|
3,383
|
|
|
|
|
|
|
|
5,719
|
|
General and administrative expenses
|
|
|
37,053
|
|
|
|
|
|
|
|
|
(4)
|
|
|
37,053
|
|
Depreciation, depletion and
amortization
|
|
|
59,426
|
|
|
|
|
|
|
|
270,390
|
(5)
|
|
|
329,816
|
|
Impairment of production equipment
held for use
|
|
|
1,845
|
|
|
|
|
|
|
|
|
|
|
|
1,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
130,542
|
|
|
|
84,122
|
|
|
|
270,390
|
|
|
|
485,054
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
69,168
|
|
|
|
308,150
|
|
|
|
(270,390
|
)
|
|
|
106,928
|
|
Interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
779
|
|
|
|
|
|
|
|
|
|
|
|
779
|
|
Expense, net of amounts capitalized
|
|
|
(8,172
|
)
|
|
|
|
|
|
|
(10,378
|
)(8)
|
|
|
(18,550
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before taxes
|
|
|
61,775
|
|
|
|
308,150
|
|
|
|
(280,768
|
)
|
|
|
89,157
|
|
Provision for income
taxes
|
|
|
(21,294
|
)
|
|
|
|
|
|
|
(9,911
|
)(7)
|
|
|
(31,205
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
40,481
|
|
|
$
|
308,150
|
|
|
$
|
(290,679
|
)
|
|
$
|
57,952
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per
share basic
|
|
$
|
1.24
|
|
|
|
|
|
|
|
|
|
|
$
|
0.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per
share diluted
|
|
$
|
1.20
|
|
|
|
|
|
|
|
|
|
|
$
|
0.69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding basic
|
|
|
32,667,582
|
|
|
|
|
|
|
|
50,637,010
|
|
|
|
83,304,592
|
|
Weighted average shares
outstanding diluted
|
|
|
33,766,577
|
|
|
|
|
|
|
|
50,687,850
|
|
|
|
84,454,427
|
|
|
|
|
(1) |
|
The historical Mariner information presented excludes activity
related to the Forest Gulf of Mexico operations as Mariner
acquired them in the merger consummated on March 2, 2006. |
|
(2) |
|
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 nine months ended September 30, 2006
and for the year ended December 31, 2005. |
|
(3) |
|
Transaction costs consisting of accounting, consulting and legal
fees are anticipated to be approximately $10.3 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. |
38
|
|
|
(4) |
|
The pro forma general and administrative expenses do not include
costs associated with the Forest Gulf of Mexico assets. Mariner
believes the overhead costs associated with these operations in
2006 will be approximately $6.4 million, net of capitalized
amounts. |
|
(5) |
|
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. |
|
(6) |
|
To adjust interest expense to give effect to the financing
activities in connection with the organization of Forest Energy
Resources assuming an interest rate of 6.375% based on the terms
of the senior bank credit facility obtained by Forest Energy
Resources. The interest rates used are
30-day LIBOR
plus 1.50%, or 6.375%, as of September 30, 2006. A change
in interest rates of approximately 10% would result in a change
in pro forma combined interest of approximately
$0.9 million for the nine months ended September 30,
2006. |
|
(7) |
|
To record income tax expense on the combined company results of
operations based on a statutory federal tax rate of 35.0%. |
|
(8) |
|
To adjust interest expense to give effect to the financing
activities in connection with the organization of Forest Energy
Resources assuming an interest rate of 5.89% for the year ended
December 31, 2005 based on the terms of the senior term
loan facility obtained by Forest Energy Resources. The interest
rates used are
30-day LIBOR
plus 1.50%, or 5.89% as of December 31, 2005. A change in
interest rates of approximately 10% would result in a change in
pro forma combined interest expense of approximately
$1.0 million for the year ended December 31, 2005. |
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 January 1, 2005. The
combination of the Forest Gulf of Mexico operations with
Mariners operations 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 December 31, 2005
were 306.1 Bcfe and production for the year ended
December 31, 2005 was approximately 65.8 Bcfe, a
reserve life on an annualized basis of 4.7. 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
corresponding higher rate of depreciation, depletion, and
amortization. As of December 31, 2005, Mariners
proved reserves totaled 337.6 Bcfe and production for the
year ended December 31, 2005 was approximately
29.1 Bcfe, a reserve life on an annualized basis of 11.6.
For the combined operations, as of December 31, 2005,
proved reserves would have totaled approximately 643.7 Bcfe
and production for the year ended December 31, 2005 would
have totaled 94.9 Bcfe, a reserve life on an annualized
basis of 6.8. 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 on
page F-56
and footnote 3 in Forests Gulf of Mexico Operations
Notes to Statements of Revenues and Direct Operating Expenses
for additional information presented in accordance with the
requirements of Statement of Financial Accounting Standards
No. 69, Disclosures About Oil and Gas Producing Activities.
39
ESTIMATED
PRO FORMA COMBINED QUANTITIES OF PROVED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest Energy Resources, Inc.
|
|
|
|
|
|
|
Mariner Historical
|
|
|
Historical
|
|
|
Mariner Pro Forma Combined
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Natural
|
|
|
Gas
|
|
|
|
|
|
Natural
|
|
|
Gas
|
|
|
|
|
|
Natural
|
|
|
Gas
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Equivalent
|
|
|
Liquids
|
|
|
Gas
|
|
|
Equivalent
|
|
|
Liquids
|
|
|
Gas
|
|
|
Equivalent
|
|
|
|
(Mbbl)
|
|
|
(MMcf)
|
|
|
(MMcfe)
|
|
|
(Mbbl)
|
|
|
(MMcf)
|
|
|
(MMcfe)
|
|
|
(Mbbl)
|
|
|
(MMcf)
|
|
|
(MMcfe)
|
|
|
December 31, 2004
|
|
|
14,255
|
|
|
|
151,933
|
|
|
|
237,465
|
|
|
|
11,650
|
|
|
|
269,808
|
|
|
|
339,708
|
|
|
|
25,905
|
|
|
|
421,741
|
|
|
|
577,173
|
|
Revisions of previous estimates
|
|
|
835
|
|
|
|
963
|
|
|
|
5,971
|
|
|
|
3,123
|
|
|
|
4,815
|
|
|
|
23,553
|
|
|
|
3,958
|
|
|
|
5,778
|
|
|
|
29,524
|
|
Extensions, discoveries and other
additions
|
|
|
1,167
|
|
|
|
22,307
|
|
|
|
29,309
|
|
|
|
504
|
|
|
|
5,639
|
|
|
|
8,663
|
|
|
|
1,671
|
|
|
|
27,946
|
|
|
|
37,972
|
|
Production
|
|
|
(1,791
|
)
|
|
|
(18,354
|
)
|
|
|
(29,100
|
)
|
|
|
(2,783
|
)
|
|
|
(49,120
|
)
|
|
|
(65,818
|
)
|
|
|
(4,574
|
)
|
|
|
(67,474
|
)
|
|
|
(94,918
|
)
|
Purchases of reserves in place
|
|
|
7,181
|
|
|
|
50,837
|
|
|
|
93,923
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,181
|
|
|
|
50,837
|
|
|
|
93,923
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
21,647
|
|
|
|
207,686
|
|
|
|
337,568
|
|
|
|
12,494
|
(1)
|
|
|
231,142
|
|
|
|
306,106
|
(1)
|
|
|
34,141
|
|
|
|
438,828
|
|
|
|
643,674
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes 3,223 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
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
Natural
|
|
Gas
|
|
|
|
Natural
|
|
Gas
|
|
|
|
Natural
|
|
Gas
|
|
|
Oil
|
|
Gas
|
|
Equivalent
|
|
Liquids
|
|
Gas
|
|
Equivalent
|
|
Liquids
|
|
Gas
|
|
Equivalent
|
|
|
(Mbbl)
|
|
(MMcf)
|
|
(MMcfe)
|
|
(Mbbl)
|
|
(MMcf)
|
|
(MMcfe)
|
|
(Mbbl)
|
|
(MMcf)
|
|
(MMcfe)
|
|
December 31, 2005
|
|
|
9,564
|
|
|
|
110,011
|
|
|
|
167,395
|
|
|
|
8,792
|
|
|
|
142,143
|
|
|
|
194,895
|
|
|
|
18,356
|
|
|
|
252,154
|
|
|
|
362,290
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
PRO FORMA
COMBINED STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ending December 31, 2005
|
|
|
|
|
|
|
Forest Energy
|
|
|
Mariner
|
|
|
|
Mariner
|
|
|
Resources, Inc.
|
|
|
Pro Forma
|
|
|
|
Historical
|
|
|
Historical
|
|
|
Combined
|
|
|
Future cash inflows
|
|
$
|
3,451,321
|
|
|
$
|
2,849,998
|
|
|
$
|
6,301,319
|
|
Future production costs
|
|
|
(687,583
|
)
|
|
|
(226,248
|
)
|
|
|
(913,831
|
)
|
Future development costs
|
|
|
(386,497
|
)
|
|
|
(386,855
|
)
|
|
|
(773,352
|
)
|
Future income taxes
|
|
|
(695,921
|
)
|
|
|
(649,002
|
)
|
|
|
(1,344,923
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
1,681,320
|
|
|
|
1,587,893
|
|
|
|
3,269,213
|
|
Discount of future net cash flows
at 10% per annum
|
|
|
(774,755
|
)
|
|
|
(292,730
|
)
|
|
|
(1,067,485
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash flows
|
|
$
|
906,565
|
|
|
$
|
1,295,163
|
|
|
$
|
2,201,728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of period
|
|
$
|
494,382
|
|
|
$
|
925,837
|
|
|
$
|
1,420,219
|
|
Increase (decrease) in discounted
future net cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas
produced, net of production costs
|
|
|
(213,189
|
)
|
|
|
(436,385
|
)
|
|
|
(649,574
|
)
|
Net changes in prices and
production costs
|
|
|
425,317
|
|
|
|
692,164
|
|
|
|
1,117,481
|
|
Extensions and discoveries, net of
future development and production costs
|
|
|
119,501
|
|
|
|
53,744
|
|
|
|
173,245
|
|
Purchases of reserves in place
|
|
|
189,782
|
|
|
|
|
|
|
|
189,782
|
|
Development costs during period
and net change in development costs
|
|
|
46,632
|
|
|
|
7,022
|
|
|
|
53,654
|
|
Revision of previous quantity
estimates
|
|
|
16,323
|
|
|
|
109,207
|
|
|
|
125,530
|
|
Net change in income taxes
|
|
|
(201,647
|
)
|
|
|
(178,643
|
)
|
|
|
(380,290
|
)
|
Accretion of discount before
income taxes
|
|
|
49,438
|
|
|
|
122,217
|
|
|
|
171,655
|
|
Changes in production rates
(timing) and other
|
|
|
(19,974
|
)
|
|
|
|
|
|
|
(19,974
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of period
|
|
$
|
906,565
|
|
|
$
|
1,295,163
|
|
|
$
|
2,201,728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41
SELECTED
HISTORICAL FINANCIAL INFORMATION FOR MARINER
The following table shows Mariners summary historical
consolidated financial data as of and for the nine months ended
September 30, 2006 and September 30, 2005, the year
ended December 31, 2005, the period from January 1,
2004 through March 2, 2004, the period from March 3,
2004 through December 31, 2004, and each of the three years
ended December 31, 2003. The summary historical
consolidated financial data for the year ended December 31,
2005, the period from January 1, 2004 through March 2,
2004, the period from March 3, 2004 through
December 31, 2004, and the year ended December 31,
2003 are derived from Mariners audited financial
statements included herein, and the historical consolidated
financial data as of and for the two years ended
December 31, 2002 are derived from Mariners audited
financial statements that are not included herein. The summary
historical consolidated financial data for the nine months ended
September 30, 2006 and the nine months ended
September 30, 2005 has been derived from Mariners
unaudited financial statements. 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 with Forest Energy Resources.
Mariners historical results are not necessarily indicative
of results to be expected in future periods.
The merger between a subsidiary of Mariner and Forest Energy
Resources was consummated on March 2, 2006. Accordingly,
the financial information as of September 30, 2006 below
includes the Forest Gulf of Mexico operations as of and after
March 2, 2006.
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 Post-2004 Merger activity (for the March 3, 2004
through December 31, 2004 period, the year ended
December 31, 2005 and the nine months ended
September 30, 2006 and September 30, 2005) and
Pre-2004 Merger activity (for all periods prior to March 2,
2004) 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Operations
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues(1)
|
|
$
|
438.4
|
|
|
$
|
151.2
|
|
|
$
|
199.7
|
|
|
$
|
174.4
|
|
|
|
$
|
39.8
|
|
|
$
|
142.5
|
|
|
$
|
158.2
|
|
|
$
|
155.0
|
|
Lease operating expenses
|
|
|
62.9
|
|
|
|
17.7
|
|
|
|
24.9
|
|
|
|
19.3
|
|
|
|
|
3.5
|
|
|
|
23.2
|
|
|
|
25.2
|
|
|
|
19.2
|
|
Severance and ad valorem taxes
|
|
|
5.7
|
|
|
|
2.5
|
|
|
|
5.0
|
|
|
|
2.1
|
|
|
|
|
0.6
|
|
|
|
1.5
|
|
|
|
0.9
|
|
|
|
0.9
|
|
Transportation expenses
|
|
|
4.0
|
|
|
|
1.7
|
|
|
|
2.3
|
|
|
|
1.9
|
|
|
|
|
1.1
|
|
|
|
6.3
|
|
|
|
10.5
|
|
|
|
12.0
|
|
Depreciation, depletion and
amortization
|
|
|
192.2
|
|
|
|
43.4
|
|
|
|
59.4
|
|
|
|
54.3
|
|
|
|
|
10.6
|
|
|
|
48.3
|
|
|
|
70.8
|
|
|
|
63.5
|
|
Impairment of production equipment
held for use
|
|
|
|
|
|
|
0.5
|
|
|
|
1.8
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative settlement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
|
|
|
|
|
|
|
|
Impairment of Enron related
receivables
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
|
|
29.5
|
|
General and administrative expenses
|
|
|
25.1
|
|
|
|
26.7
|
|
|
|
37.1
|
|
|
|
7.6
|
|
|
|
|
1.1
|
|
|
|
8.1
|
|
|
|
7.7
|
|
|
|
9.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
148.5
|
|
|
|
58.7
|
|
|
|
69.2
|
|
|
|
88.2
|
|
|
|
|
22.9
|
|
|
|
51.9
|
|
|
|
39.9
|
|
|
|
20.6
|
|
Interest income
|
|
|
0.5
|
|
|
|
0.7
|
|
|
|
0.8
|
|
|
|
0.2
|
|
|
|
|
0.1
|
|
|
|
0.8
|
|
|
|
0.4
|
|
|
|
0.7
|
|
Interest expense
|
|
|
(26.4
|
)
|
|
|
(5.4
|
)
|
|
|
(8.2
|
)
|
|
|
(6.0
|
)
|
|
|
|
|
|
|
|
(7.0
|
)
|
|
|
(10.3
|
)
|
|
|
(8.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
122.6
|
|
|
|
54.0
|
|
|
|
61.8
|
|
|
|
82.4
|
|
|
|
|
23.0
|
|
|
|
45.7
|
|
|
|
30.0
|
|
|
|
12.4
|
|
Provision for income taxes
|
|
|
(44.4
|
)
|
|
|
(18.4
|
)
|
|
|
(21.3
|
)
|
|
|
(28.8
|
)
|
|
|
|
(8.1
|
)
|
|
|
(9.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions, except per share data)
|
|
Income before cumulative effect of
change in accounting method net of tax effects
|
|
$
|
78.2
|
|
|
$
|
35.6
|
|
|
$
|
40.5
|
|
|
$
|
53.6
|
|
|
|
$
|
14.9
|
|
|
$
|
36.3
|
|
|
$
|
30.0
|
|
|
$
|
12.4
|
|
Income before cumulative effect
per common unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
1.07
|
|
|
|
1.10
|
|
|
$
|
1.24
|
|
|
$
|
1.80
|
|
|
|
$
|
0.50
|
|
|
$
|
1.22
|
|
|
$
|
1.01
|
|
|
$
|
0.42
|
|
Diluted
|
|
|
1.06
|
|
|
|
1.07
|
|
|
|
1.20
|
|
|
|
1.80
|
|
|
|
|
0.50
|
|
|
|
1.22
|
|
|
|
1.01
|
|
|
|
0.42
|
|
Cumulative effect of changes in
accounting method
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
78.2
|
|
|
$
|
35.6
|
|
|
$
|
40.5
|
|
|
$
|
53.6
|
|
|
|
$
|
14.9
|
|
|
$
|
38.2
|
|
|
$
|
30.0
|
|
|
$
|
12.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.07
|
|
|
$
|
1.10
|
|
|
$
|
1.24
|
|
|
$
|
1.80
|
|
|
|
$
|
0.50
|
|
|
$
|
1.29
|
|
|
$
|
1.01
|
|
|
$
|
0.42
|
|
Diluted
|
|
|
1.06
|
|
|
|
1.07
|
|
|
|
1.20
|
|
|
|
1.80
|
|
|
|
|
0.50
|
|
|
|
1.29
|
|
|
|
1.01
|
|
|
|
0.42
|
|
Capital Expenditure and
Disposal Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, including
leasehold/seismic
|
|
|
169.1
|
|
|
|
23.6
|
|
|
$
|
60.9
|
|
|
$
|
40.4
|
|
|
|
$
|
7.5
|
|
|
$
|
31.6
|
|
|
$
|
40.4
|
|
|
$
|
66.3
|
|
Development and other
|
|
|
347.9
|
|
|
|
106.8
|
|
|
|
191.8
|
|
|
|
93.2
|
|
|
|
|
7.8
|
|
|
|
51.7
|
|
|
|
65.7
|
|
|
|
98.2
|
|
Proceeds from property conveyances
|
|
|
(2.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(121.6
|
)
|
|
|
(52.3
|
)
|
|
|
(90.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures net of
proceeds from property conveyances
|
|
$
|
515.0
|
|
|
$
|
130.4
|
|
|
$
|
252.7
|
|
|
$
|
133.6
|
|
|
|
$
|
15.3
|
|
|
$
|
(38.3
|
)
|
|
$
|
53.8
|
|
|
$
|
74.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes effects of hedging. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2001
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net, full
cost method
|
|
$
|
2,061.9
|
|
|
$
|
393.3
|
|
|
$
|
515.9
|
|
|
$
|
303.8
|
|
|
|
$
|
207.9
|
|
|
$
|
287.6
|
|
|
$
|
290.6
|
|
Total assets
|
|
|
2,700.7
|
|
|
|
502.2
|
|
|
|
665.5
|
|
|
|
376.0
|
|
|
|
|
312.1
|
|
|
|
360.2
|
|
|
|
363.9
|
|
Long-term debt, less current
maturities
|
|
|
614.0
|
|
|
|
79.0
|
|
|
|
156.0
|
|
|
|
115.0
|
|
|
|
|
|
|
|
|
99.8
|
|
|
|
99.8
|
|
Stockholders equity
|
|
|
1,267.1
|
|
|
|
178.6
|
|
|
|
213.3
|
|
|
|
133.9
|
|
|
|
|
218.2
|
|
|
|
170.1
|
|
|
|
180.1
|
|
Working capital (deficit)(2)
|
|
|
(75.3
|
)
|
|
|
(30.2
|
)
|
|
|
(46.4
|
)
|
|
|
(18.7
|
)
|
|
|
|
38.3
|
|
|
|
(24.4
|
)
|
|
|
(19.6
|
)
|
Other Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ratio of Earnings to Fixed
Charges(3)
|
|
|
5.43
|
|
|
|
10.23
|
|
|
|
7.88
|
|
|
|
17.17
|
|
|
|
|
6.83
|
|
|
|
3.56
|
|
|
|
1.82
|
|
|
|
|
(1) |
|
Balance sheet data as of September 30, 2006 reflects
consolidation of the assets of the Forest Gulf of Mexico
operations as of March 2, 2006. 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. |
43
|
|
|
(2) |
|
Working capital (deficit) excludes current derivative assets and
liabilities, deferred tax assets and restricted cash. |
|
(3) |
|
For the purposes of determining the ratio of earnings to fixed
charges, earnings consist of the sum of income before taxes,
plus fixed charges, less capitalized interest, and fixed charges
consist of interest expense (net of capitalized interest), plus
capitalized interest, plus amortized discounts related to
indebtedness. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
March 2,
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$
|
340.7
|
|
|
$
|
102.7
|
|
|
$
|
130.4
|
|
|
$
|
143.5
|
|
|
|
$
|
33.4
|
|
|
$
|
100.3
|
|
|
$
|
113.9
|
|
|
$
|
113.6
|
|
Net cash provided by operating
activities
|
|
|
172.8
|
|
|
|
135.4
|
|
|
|
165.4
|
|
|
|
135.2
|
|
|
|
|
20.3
|
|
|
|
88.9
|
|
|
|
60.3
|
|
|
|
113.5
|
|
Net cash (used) provided by
investing activities
|
|
|
(423.5
|
)
|
|
|
(142.1
|
)
|
|
|
(247.8
|
)
|
|
|
(133.0
|
)
|
|
|
|
(15.3
|
)
|
|
|
52.9
|
|
|
|
(53.8
|
)
|
|
|
(74.0
|
)
|
Net cash (used) provided by
financing activities
|
|
|
251.0
|
|
|
|
8.7
|
|
|
|
84.4
|
|
|
|
64.9
|
|
|
|
|
|
|
|
|
(100.0
|
)
|
|
|
|
|
|
|
(30.0
|
)
|
Reconciliation of
Non-GAAP Measures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$
|
340.7
|
|
|
$
|
102.7
|
|
|
$
|
130.4
|
|
|
$
|
143.5
|
|
|
|
$
|
33.4
|
|
|
$
|
100.3
|
|
|
$
|
113.9
|
|
|
$
|
113.6
|
|
Changes in working capital
|
|
|
(158.9
|
)
|
|
|
25.1
|
|
|
|
20.0
|
|
|
|
6.2
|
|
|
|
|
(13.2
|
)
|
|
|
7.2
|
|
|
|
(20.4
|
)
|
|
|
7.5
|
|
Non-cash hedge gain/(loss)(2)
|
|
|
8.2
|
|
|
|
(3.6
|
)
|
|
|
(4.5
|
)
|
|
|
(7.9
|
)
|
|
|
|
|
|
|
|
(2.0
|
)
|
|
|
(23.2
|
)
|
|
|
|
|
Amortization/other
|
|
|
(0.3
|
)
|
|
|
0.9
|
|
|
|
1.2
|
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
0.6
|
|
Stock compensation expense
|
|
|
9.0
|
|
|
|
17.6
|
|
|
|
25.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense
|
|
|
(25.9
|
)
|
|
|
(4.7
|
)
|
|
|
(7.4
|
)
|
|
|
(5.8
|
)
|
|
|
|
0.1
|
|
|
|
(6.2
|
)
|
|
|
(9.9
|
)
|
|
|
(8.2
|
)
|
Income tax expense
|
|
|
|
|
|
|
(2.6
|
)
|
|
|
|
|
|
|
(1.6
|
)
|
|
|
|
|
|
|
|
(10.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
$
|
172.8
|
|
|
$
|
135.4
|
|
|
$
|
165.4
|
|
|
$
|
135.2
|
|
|
|
$
|
20.3
|
|
|
$
|
88.9
|
|
|
$
|
60.3
|
|
|
$
|
113.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
EBITDA means earnings before interest, income taxes,
depreciation, depletion and amortization and impairments. For
the nine months ended September 30, 2006 and 2005, EBITDA
includes $9.0 million and $17.6 million, respectively,
in non-cash compensation expense related to restricted stock and
stock options. For the year ended December 31, 2005, EBITDA
includes $25.7 million in non-cash 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 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 dedesignation 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. 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.
The value at the time of the merger and included in 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. |
44
MANAGEMENTS
DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
We are an independent oil and natural gas exploration,
development and production company with principal operations in
the Gulf of Mexico and 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. As a result of increased drilling of shelf prospects,
the acquisition of Forests Gulf of Mexico assets located
primarily on the shelf, and development activities in West
Texas, 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 West
Texas properties. As of December 31, 2005 (after giving
effect to the merger transaction with Forest Energy Resources),
approximately 56% of our proved reserves were classified as
proved developed, with approximately 32% of the reserves located
in West Texas, 19% in the Gulf of Mexico deepwater and 49% on
the Gulf of Mexico shelf.
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 Enron
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) and
Combined (for the full period from January 1 through
December 31, 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 $38 million of the
remaining net proceeds of approximately $44 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 Enron 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.
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 significantly in the future. Although we attempt
to mitigate the impact of price declines and provide for more
predictable cash flows through our hedging strategy, a
substantial or extended decline in oil and natural gas prices or
poor drilling results could have a
45
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. Conversely, the use of derivative instruments also can
prevent us from realizing the full benefit of upward price
movements.
Recent
Developments
Forest Gulf of Mexico Merger. On March 2,
2006, a subsidiary of Mariner completed a merger transaction
with Forest Energy Resources. Prior to the consummation of the
merger, Forest transferred and contributed the assets and
certain liabilities associated with its Gulf of Mexico
operations to Forest Energy Resources. Immediately prior to the
merger, Forest distributed all of the outstanding shares of
Forest Energy Resources to Forest shareholders on a pro rata
basis. Forest Energy Resources then merged with a newly-formed
subsidiary of Mariner, became a new wholly-owned subsidiary of
Mariner, and changed its name to Mariner Energy Resources, Inc.
Immediately following the merger, approximately 59% of Mariner
common stock was held by shareholders of Forest and
approximately 41% of Mariner common stock was held by the
pre-merger stockholders of Mariner. In the merger, Mariner
issued 50,637,010 shares of common stock to Forest
shareholders. Our acquisition of Forest Energy Resources added
approximately 306 Bcfe of estimated proved reserves as of
December 31, 2005, of which 76% were natural gas and 24%
were oil and condensate.
West Cameron Acquisition. In August 2006, we
acquired the interest of BP Exploration and Production Inc.,
which we refer to as BP, in West Cameron
Block 110 and the southeast quarter of West Cameron
Block 111 in the Gulf of Mexico. The interest was acquired
by our subsidiary, Mariner Energy Resources, Inc., exercising
its preferential right to purchase. BP retained its interest in
depths below 15,000 feet. In the Forest merger, we acquired
Forest Energy Resources 37.5% interest in the properties.
As a result of the August 2006 acquisition, Mariner Energy
Resources, Inc. now owns 100% of the working interest, exclusive
of the deep rights retained by BP, and Mariner Energy, Inc.
became operator of the interests owned by its subsidiary. The
acquisition cost, net of preliminary purchase price adjustments,
was approximately $70.9 million, which was financed by
borrowing under our senior secured credit facility. A
$10.4 million letter of credit under our senior secured
credit facility also was issued in favor of BP to secure
plugging and abandonment obligations. The acquisition adds
proved reserves estimated by us to be 20 Bcfe as of
August 1, 2006. Production associated with the acquired
interest was approximately 11 MMcfe/day during July 2006.
Material Gulf of Mexico Discovery. In October
2006, we announced that we made a material conventional shelf
discovery in the High Island 116 #5ST1 well, drilled
to a total measured depth of 14,683 feet / 13,150 feet
true vertical depth. The well encountered approximately
540 feet of net true vertical depth pay in thirteen sands.
We anticipate completion and initial production in the fourth
quarter of 2006. High Island 116 is part of the Forest Gulf of
Mexico operations we acquired in March 2006. We have a 100%
working interest and an approximate 72% net revenue interest in
the well.
Effects of the 2005 Hurricane Season. In 2005,
our operations were adversely affected by one of the most active
and severe hurricane seasons in recorded history, resulting in
shut-in production and startup delays. We estimate that as of
September 30, 2006, approximately 12 MMcfe per day of
production remained shut-in and approximately 33 MMcfe per
day of production had recommenced since June 30, 2006. The
four deepwater projects that experienced startup delays have
recommenced production. As a result of ongoing repairs to
pipelines, facilities, terminals and host facilities, we expect
most of the remaining shut-in production to recommence by the
end of 2006 and the balance in 2007, except that an immaterial
amount of production is not expected to recommence.
We estimate that the costs to repair damage caused by the
hurricanes to our platforms and facilities will be approximately
$85 million. However, until we are able to complete all of
the repair work, this estimate is subject to significant
variance. For the insurance period covering the 2005 hurricane
activity, we carried a $3 million annual deductible and a
$0.5 million single occurrence deductible for the Mariner
assets. Insurance covering the Forest Gulf of Mexico properties
carried a $5 million deductible for each occurrence. Until
the repairs are completed and we submit costs to our insurance
underwriters for their review, the full extent of our insurance
recoveries and the resulting net costs to us for Hurricanes
Katrina and Rita will be unknown. See
46
Business Insurance Matters. However, we
expect the total costs not covered by the combined insurance
policies to be less than $15 million.
2006
Highlights
For the nine months ended September 30, 2006, we recognized
net income of $78.2 million on total revenues of
$438.4 million compared to net income of $35.6 million
on total revenues of $151.2 million for the nine months
ended September 30, 2005. Production, revenues and net
income increased significantly from results reported a year ago
primarily as a result of consolidation as of March 2, 2006
of assets acquired in the merger transaction with Forest Energy
Resources. Production for the first nine months of 2006 averaged
200 MMcfe per day (54.5 Bcfe total for the period),
compared to average daily production of 82 MMcfe per day
for the first nine months of 2005 (22.5 Bcfe total for the
period). Production for the first nine months of 2006 continued
to be adversely effected by the 2005 hurricane season.
2005
Highlights
During the year ended December 31, 2005, we recognized net
income of $40.5 million on total revenues of
$199.7 million compared to net income of $68.4 million
on total revenues of $214.2 million in 2004. Net income
decreased 41% compared to 2004, primarily due to recognizing
$25.7 million of stock compensation expense in 2005, and a
23% decrease in production, partially offset by a 35%
improvement in net commodity prices realized by us (before the
effects of hedging.) Our 2005 results were also negatively
impacted by increased hedging losses of $49.3 million in
2005 compared to a $19.8 million loss in 2004. We produced
approximately 29.1 Bcfe during 2005 and our average daily
production rate was 80 MMcfe compared to 37.6 Bcfe, or
103 MMcfe per day, for 2004. Production during the last two
quarters of 2005 was negatively impacted by the effects of the
2005 hurricane season. We invested approximately
$252.7 million in total capital in 2005 compared to
$148.9 million in 2004.
Our 2005 results reflect the private placement of an additional
3.6 million shares of stock in March 2005. The net proceeds
of approximately $44 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 2005 and recorded
compensation expense of $25.7 million in 2005 related to
the restricted stock and options.
2004
Highlights
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 invested approximately $148.9 million in total capital
in 2004 compared to $83.3 million in 2003.
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.
Production
For the first nine months of 2006, our production averaged
144 MMcf of natural gas per day and approximately
9,300 barrels of oil per day, or a total of approximately
200 MMcfe per day. Natural gas production comprised
approximately 72% of total production for the nine months ended
September 30, 2006 compared to approximately 64% for the
comparable period in 2005. This increase in the gas to oil ratio
47
primarily resulted from the acquisition of the Forest Gulf of
Mexico operations. Production continued to be adversely affected
by the 2005 hurricane season, resulting in shut-in production
and startup delays. We estimate that as of September 30,
2006, approximately 12 MMcfe per day of production remained
shut-in and approximately 33 MMcfe per day of production
had recommenced since June 30, 2006. The four deepwater
projects that experienced startup delays have recommenced
production. As a result of ongoing repairs to pipelines,
facilities, terminals and host facilities, we expect most of the
remaining shut-in production to recommence by the end of 2006
and the balance in 2007, except that an immaterial amount of
production is not expected to recommence.
Our production for 2005 averaged approximately 50 MMcf of
natural gas per day and approximately 4,900 barrels of oil
per day, or a total of approximately 80 MMcfe per day.
Natural gas production comprised approximately 63% of total
production in 2005 and 2004.
In the last two quarters of 2005 our production was negatively
impacted by Hurricanes Katrina and Rita. Production shut-in and
deferred because of the hurricanes impact totaled
approximately 6-8 Bcfe during the last two quarters of
2005. As of December 31, 2005 approximately 5 MMcfe
per day of production remained shut-in awaiting repairs,
primarily associated with our Baccarat property, which was
brought back on-line in January 2006. 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 until the fourth quarter of 2005. 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). Our Rigel project recommenced production in the
first quarter of 2006, and our Pluto and Ochre projects
recommenced production in the third quarter of 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. 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. It subsequently has been shut-in since Hurricane
Katrina, with production expected to recommence in the first
quarter of 2007 after completion of host platform repairs.
Production from Mississippi Canyon 66 (Ochre) recommenced in the
third quarter of 2006, producing at about the same net rate of
approximately 6.5 MMcfe per day as it was immediately prior
to Hurricane Ivan.
Historically, a majority of our total production has been
comprised of natural gas. We anticipate that our acquisition of
the Forest Gulf of Mexico operations will increase our
concentration in natural gas production. 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
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 recommenced in January 2006. We
recommenced production at our Swordfish project in the fourth
quarter of 2005, at our Rigel project in the first quarter of
2006 and at our Pluto project in the third quarter of 2006.
Production recommenced in October 2006 at our Ewing Banks 921
(North Black Widow) project. Uncertainties, including
scheduling, weather, and construction lead times, could cause
further delays in the
start-up of
any one of the projects.
48
Oil and
Gas Property Costs
Of the total $517.0 million of capital expenditures
incurred in the first nine months of 2006, approximately
$264.9 million or 51% related to development activities (of
which about $39.5 million was onshore), $169.1 million
or 33% related to exploration activities, including the
acquisition of leasehold and seismic, and the balance of
approximately $83.0 million or 16% related to the West
Cameron 110/111 acquisition, capitalized expenses and minor
corporate items.
In 2005, we incurred approximately $242.6 million in
capital costs related to property acquisitions, exploration, and
development activities and approximately $10.1 million for
capital costs associated with the installation of our Aldwell
unit gathering system and other minor corporate items. Of the
total $252.7 million of capital expenditures incurred in
2005, approximately 51% related to development activities and
capitalized overhead and interest, 24% for exploration
activities, including the acquisition of leasehold and seismic,
21% for property acquisitions, and the balance was associated
with the Aldwell Unit gathering system and minor corporate
items. Of the $121.7 million incurred on development
activities and capitalized overhead and interest, approximately
27% were for onshore operations, 69% for deep water operations,
and 4% for shelf Gulf of Mexico operations. Expenditures for
property acquisitions included $46.1 million for assets
located in West Texas and $7.9 million to acquire
additional interests in offshore Gulf of Mexico projects.
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. We incurred approximately $47.9 million of
exploration capital expenditures in 2004.
Oil and
Gas Reserves
We have maintained our reserve base through exploration and
exploitation activities despite selling 44.4 Bcfe of our
reserves in 2002. Historically, we have not acquired significant
reserves through acquisition activities; however, in 2005, we
acquired 93.9 Bcfe of estimated proved reserves primarily
in West Texas. In March 2006, we acquired estimated proved
reserves of 306.1 Bcfe as a result of the merger with
Forest Energy Resources. As of December 31, 2005, Ryder
Scott estimated our net proved reserves at approximately
337.6 Bcfe, with a PV10 of approximately $1.3 billion
and a standardized measure of discounted future net cash flows
attributable to our estimated proved reserves of approximately
$906.6 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 and for more information concerning our
reserve estimates.
Development activities and acquisitions in West Texas and Gulf
of Mexico deepwater divestitures have significantly changed our
reserve profile since 2002. Proved reserves as of
December 31, 2005 were comprised of 61% West Texas, 6% Gulf
of Mexico shelf and 33% Gulf of Mexico deepwater compared to 33%
West Texas, 19% Gulf of Mexico shelf and 48% Gulf of Mexico
deepwater as of December 31, 2002. Proved undeveloped
reserves were approximately 50% of total proved reserves as of
December 31, 2005. Approximately 25% of proved undeveloped
reserves were related to our West Texas Aldwell Unit, where we
had 100% development drilling success on 170 wells from
2002 through 2005. Pro forma for the merger transaction, as of
December 31, 2005, we had approximately 644 Bcfe of proved
reserves, of which 32% were in West Texas, 49% in the Gulf of
Mexico shelf and 19% in the Gulf of Mexico deepwater. Proved
undeveloped reserves were approximately 44% of total proved
reserves as of December 31, 2005 on a pro forma basis.
49
Since December 31, 1997, we have added proved undeveloped
reserves attributable to 13 deepwater projects. As of
December 31, 2005, ten of those projects have either been
converted to proved developed reserves or sold as indicated in
the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved
|
|
|
|
|
|
|
|
|
Undeveloped
|
|
|
|
|
|
|
|
|
Reserves
|
|
|
Year
|
|
|
|
Property
|
|
(Bcfe)(1)
|
|
|
Added
|
|
|
Year Converted to Proved Developed or Sold
|
|
Mississippi Canyon 718 (Pluto)(2)
|
|
|
25.1
|
|
|
|
1998
|
|
|
2000 (100% converted to
proved developed)
|
Ewing Bank 966 (Black Widow)
|
|
|
14.0
|
|
|
|
1999
|
|
|
2000 (100% converted to
proved developed)
|
Mississippi Canyon 773 (Devils
Tower)
|
|
|
28.0
|
|
|
|
2000
|
|
|
2001 (100% of Mariners
interest sold)
|
Mississippi Canyon 305 (Aconcagua)
|
|
|
19.2
|
|
|
|
2000
|
|
|
2001 (100% of Mariners
interest sold)
|
Green Canyon 472/473 (King Kong)
|
|
|
25.5
|
|
|
|
2000
|
|
|
2002 (100% converted to
proved developed)
|
Green Canyon 516 (Yosemite)
|
|
|
14.9
|
|
|
|
2001
|
|
|
2002 (100% converted to
proved developed)
|
East Breaks 579 (Falcon)
|
|
|
66.8
|
|
|
|
2001
|
|
|
2002 (50% of Mariners
interest sold) 2003 (all of Mariners remaining interest
sold)
|
Viosca Knoll 917 (Swordfish)
|
|
|
13.4
|
|
|
|
2001
|
|
|
2005 (100% converted to
proved developed)
|
Green Canyon 178 (Baccarat)
|
|
|
4.0
|
|
|
|
2004
|
|
|
2005 (100% converted to
proved developed)
|
Mississippi Canyon 296/252 (Rigel)
|
|
|
22.4
|
|
|
|
2003
|
|
|
2005 (75% converted to proved
developed/25% remains undeveloped)
|
|
|
|
(1) |
|
Net proved undeveloped reserves attributable to the project in
the year it was first added to our proved reserves. |
|
(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, 2005, 8.9 Bcfe of our net proved reserves
attributable to this project were classified as proved behind
pipe reserves. Production from Pluto recommenced in the third
quarter of 2006. |
The proved undeveloped reserves attributable to the remaining
two deepwater projects were added as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved
|
|
|
|
|
|
Year Expected
|
|
|
|
Undeveloped
|
|
|
|
|
|
to Convert
|
|
|
|
Reserves
|
|
|
Year
|
|
|
to Proved
|
|
Property
|
|
(Bcfe)(1)
|
|
|
Added
|
|
|
Developed Status
|
|
|
Green Canyon 646 (Daniel Boone)
|
|
|
16.4
|
|
|
|
2003
|
|
|
|
2008
|
|
Atwater Valley 380/381/382/425/426
(Bass Lite)
|
|
|
32.3
|
|
|
|
2005
|
|
|
|
2008
|
|
Ewing Bank 921 (North Black Widow)
|
|
|
3.7
|
|
|
|
2005
|
|
|
|
2006
|
|
|
|
|
(1) |
|
Net proved undeveloped reserves attributable to the project as
of December 31, 2005. |
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.
50
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, the cash
losses on contracts settled for natural gas and oil produced
during the nine-month period ended September 30, 2006 was
$8.3 million. An $8.3 million non-cash gain was also
recorded for the nine-month period ended September 30, 2006
relating to the hedges acquired through the Forest transaction.
Additionally, an unrealized gain of $1.4 million was
recognized for the nine-month period ended September 30,
2006 related to the ineffective portion of open contracts that
were not eligible for deferral under SFAS 133 due primarily
to the basis differentials between the contract price, which is
NYMEX-based for oil and Henry Hub-based for gas, and the indexed
price at the point of sale. We incurred cash hedging losses of
$53.8 million in 2005, of which $4.5 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
September 30, 2006, December 31, 2005 or
December 31, 2004.
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.
Additionally, in accordance with purchase price accounting
implemented at the time of the Forest transaction, we recorded
the
mark-to-market
liability of Forest Energy Resources hedge contracts as of
March 2, 2006 totaling $17.5 million. As of
December 31, 2005, the amount of our
mark-to-market
hedge liabilities totaled $63.8 million and at
September 30, 2006 our mark to market assets totaled
$73.9 million. See Liquidity and Capital
Resources Commodity Prices and Related Hedging
Activities.
For the nine months ended September 30, 2006, assuming a
totally unhedged position, our price sensitivity for
year-to-date
revenues for a 10% change in average oil prices and average gas
prices received is approximately $15.7 million and
$27.7 million, respectively. For the year ended
December 31, 2005, assuming a totally unhedged position,
our price sensitivity for 2005 net revenues for a 10%
change in average oil prices and average gas prices received is
approximately $9.3 million and $15.3 million,
respectively. 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.
Operating
Costs
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
deepwater fields. Lease operating expenses
51
also include indirect costs such as oil and gas property
insurance and overhead allocations in accordance with joint
operating agreements.
Severance and ad valorem taxes are comprised of severance,
production and ad valorem taxes and are generally variable costs
based on production, except for ad valorem taxes.
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
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.
Under full cost accounting rules, total capitalized costs are
limited to a ceiling equal to the present value of future net
revenues (which excludes future cash outflows associated with
settlement of asset retirement obligations), discounted at 10%
per annum, plus the lower of cost or fair value of unproved
properties less income tax effects (the ceiling
limitation). We perform a quarterly ceiling test to
evaluate whether the net book value of our full cost pool
exceeds the ceiling limitation. If capitalized costs (net of
accumulated depreciation, depletion and amortization) less
related deferred taxes are greater than the discounted future
net revenues or ceiling limitation, a write-down or impairment
of the full cost pool is required. A write-down of the carrying
value of the full cost pool is a non-cash charge that reduces
earnings and impacts stockholders equity in the period of
occurrence and typically results in lower depreciation,
depletion and amortization expense in future periods. Once
incurred, a write-down is not reversible at a later date.
The ceiling test is calculated using natural gas and oil prices
in effect as of the balance sheet date and adjusted for
basis or location differential, held constant over
the life of the reserves. We use derivative financial
instruments that qualify for cash flow hedge accounting under
SFAS 133, Accounting for Derivative Instruments and
Hedging Activities to hedge against the volatility of
natural gas prices and, in accordance with SEC guidelines, we
include estimated future cash flows from our hedging program in
our ceiling test calculation. At September 30, 2006, the
effects of the cash flow hedges impacted the ceiling test by
$209.0 million. Without the hedges, a write-down of the
carrying value of the full cost pool of $125.3 million on a
pre-tax basis would have been indicated. On an after-tax basis,
the write-down would have been $81.5 million.
52
Proved
Reserves
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.
Compensation
Expense
As a result of the adoption of SFAS Statement
No. 123(R), we record compensation expense for the fair
value of restricted stock and stock options that are granted. In
general, compensation expense will be determined at the date of
grant based on the fair value of the stock or options granted.
The fair value then will be amortized to compensation expense
over the applicable vesting periods.
Revenue
Recognition
We use the entitlements method of accounting for the recognition
of natural gas and oil revenues. Under this method of
accounting, income is recorded based on our net revenue interest
in production or nominated deliveries. We incur production gas
volume imbalances in the ordinary course of business. Net
deliveries in excess of entitled amounts are recorded as
liabilities, while net under deliveries are reflected as assets.
Imbalances are reduced either by subsequent recoupment of
over-and-under
deliveries or by cash settlement, as required by applicable
contracts. Production imbalances are
marked-to-market
at the end of each month at the lowest of (i) the price in
effect at the time of production; (ii) the current market
price; or (iii) the contract price, if a contract is in
hand.
Income
Taxes
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. In May 2006, the State of Texas enacted
substantial changes to its tax structure beginning in 2007 by
implementing a new margin tax of 1% to be imposed on revenues
less certain costs, as specified in the legislation. During the
second quarter of 2006, we increased our provision by an
additional $1.3 million to provide for deferred taxes to
the State of Texas under the newly enacted margin tax.
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.
53
Hedging
Program
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 Accumulated
Other Comprehensive Income (AOCI) as appropriate,
until recognized as operating income as the physical production
hedged by the contracts is delivered.
The net cash flows related to any recognized gains or losses
associated with these hedges are reported as oil and gas
revenues and presented in cash flows from operations. If the
hedge is terminated prior to expected maturity, gains or losses
are deferred and included in income in the same period as the
physical production hedged by the contracts is delivered.
The conditions to be met for a derivative instrument to qualify
as a cash flow hedge are the following: (i) the item to be
hedged exposes 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.
Use of
Estimates in the Preparation of Financial
Statements
The preparation of the consolidated 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 dates of the financial statements and the reported
amounts of revenues and expenses during the reporting periods.
Our most significant financial estimates are based on remaining
proved natural gas and oil reserves. Estimates of proved
reserves are key components of our depletion rate for natural
gas and oil properties, our unevaluated properties and our full
cost ceiling test. In addition, estimates are used in computing
taxes, preparing accruals of operating costs and production
revenues, asset retirement obligations, fair value and
effectiveness of derivative instruments and fair value of stock
options and the related compensation expense. Because of the
inherent nature of the estimation process, actual results could
differ materially 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, see Production.
54
Nine
Months Ended September 30, 2006 Compared to Nine Months
Ended September 30, 2005
Operating
and Financial Results for the Nine Months Ended
September 30, 2006
Compared to the Nine Months Ended September 30,
2005
|
|
|
|
|
|
|
|
|
|
|
For the Nine-Month Period
|
|
|
|
Ended September 30,
|
|
Summary Operating Information:
|
|
2006
|
|
|
2005
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
2,534
|
|
|
|
1,336
|
|
Natural Gas (MMcf)
|
|
|
39,298
|
|
|
|
14,508
|
|
Total (MMcfe)
|
|
|
54,503
|
|
|
|
22,521
|
|
Average daily production (MMcfe/d)
|
|
|
200
|
|
|
|
82
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(1)
|
|
$
|
59.58
|
|
|
$
|
40.12
|
|
Natural gas (per Mcf)(1)
|
|
|
7.25
|
|
|
|
6.54
|
|
Total natural gas equivalent
($/Mcfe)(1)
|
|
|
8.00
|
|
|
|
6.59
|
|
Oil and gas revenues:
|
|
|
|
|
|
|
|
|
Oil sales(1)
|
|
$
|
150,982
|
|
|
$
|
53,579
|
|
Gas sales(1)
|
|
|
285,008
|
|
|
|
94,913
|
|
Total oil and gas revenues(1)
|
|
|
435,990
|
|
|
|
148,492
|
|
Other revenues
|
|
|
2,401
|
|
|
|
2,753
|
|
Lease operating expenses
|
|
|
62,863
|
|
|
|
17,678
|
|
Severance and ad valorem taxes
|
|
|
5,710
|
|
|
|
2,492
|
|
Transportation expenses
|
|
|
4,031
|
|
|
|
1,697
|
|
Depreciation, depletion and
amortization
|
|
|
192,222
|
|
|
|
43,457
|
|
General and administrative expenses
|
|
|
25,050
|
|
|
|
26,726
|
|
Impairment of production equipment
held for use
|
|
|
|
|
|
|
498
|
|
Net interest expense
|
|
|
25,906
|
|
|
|
4,720
|
|
Income before taxes
|
|
|
122,609
|
|
|
|
53,977
|
|
Provision for income taxes
|
|
|
44,385
|
|
|
|
18,414
|
|
Net income
|
|
|
78,224
|
|
|
|
35,563
|
|
|
|
|
(1) |
|
Includes the effects of hedging |
Production: Production for the first nine
months of 2006 averaged 200 MMcfe per day (54.5 Bcfe
total for the period) compared to average daily production of
82 MMcfe per day for the first nine months of 2005
(22.5 Bcfe total for the period). The increased production
levels for the nine months ended September 30, 2006
resulted primarily from the acquisition of the Forest Gulf of
Mexico operations. The first nine months of 2006 continued to be
adversely effected by the 2005 hurricane season, resulting in
shut-in production and startup delays. We estimate that as of
September 30, 2006, approximately 12 MMcfe per day of
production remained shut-in and approximately 33 MMcfe per
day of production had recommenced since June 30, 2006. The
four deepwater projects that experienced startup delays have
recommenced production. As a result of ongoing repairs to
pipelines, facilities, terminals and host facilities, we expect
most of the remaining shut-in production to recommence by the
end of 2006 and the balance in 2007, except that an immaterial
amount of production is not expected to recommence.
Production in the Gulf of Mexico increased 167% to
47.7 Bcfe from 17.9 Bcfe for the nine-month periods ended
September 30, 2006 and 2005, respectively, while onshore
production increased 46% to 6.8 Bcfe from 4.7 Bcfe for
the nine-month periods ended September 30, 2006 and 2005,
respectively. Natural gas production comprised 72% of our total
production for the first nine months of 2006 compared to 65% for
the
55
first nine months of 2005. The increase in the
gas-to-oil
ratio was primarily the result of the acquisition of the Forest
Gulf of Mexico operations.
Oil and gas revenues: Total oil and gas
revenues increased 194% to $436.0 million for the
nine-month period ended September 30, 2006 compared to
$148.5 million for the nine-month period ended
September 30, 2005. Natural gas revenues were
$285.0 million and $94.9 million for the nine-month
periods ended September 30, 2006 and 2005, respectively.
Total oil revenues for the nine-month period ended
September 30, 2006 were $151.0 million, compared to
$53.6 million for the nine-month period ended
September 30, 2005.
Natural gas prices (excluding the effects of hedging) for the
first nine months of 2006 averaged $7.05/Mcf compared to
$7.23/Mcf for the comparable period of 2005. Oil prices
(excluding the effects of hedging) for the first nine months of
2006 averaged $62.13/Bbl compared to $50.17/Bbl for the
comparable period of 2005. For the first nine months of 2006,
hedges increased average natural gas pricing by $0.20/Mcf to
$7.25/Mcf and reduced average oil pricing by $2.55/Bbl to
$59.58/Bbl, resulting in a net recognized hedging gain of
$1.5 million.
The cash activity on contracts settled for natural gas and oil
produced during the nine-month period ended September 30,
2006 was an $8.3 million loss. An $8.3 million
non-cash gain was also recorded for the nine-month period ended
September 30, 2006 relating to the hedges acquired through
the Forest Energy Resources merger. Additionally, an unrealized
gain of $1.4 million was recognized for the nine-month
period ended September 30, 2006 related to the ineffective
portion of open contracts that were not eligible for deferral
under SFAS 133 due primarily to the basis differentials
between the contract price, which is NYMEX-based for oil and
Henry Hub-based for gas, and the indexed price at the point of
sale.
Lease operating expenses (including workover expenses)
were $62.9 million for the nine-month period ended
September 30, 2006 compared to $17.7 million for the
nine-month period ended September 30, 2005. The increase
primarily was attributable to the consolidation of the Forest
Gulf of Mexico operations and increased costs attributable to
the addition of new productive wells onshore. Lease operating
costs rose to $1.15 per Mcfe for the nine-month period
ended September 30, 2006 compared to $0.78 per Mcfe
for the nine-month period ended September 30, 2005.
Continued shut-in production from the impact of the 2005
hurricanes contributed to the increased per-unit operating costs.
Severance and ad valorem taxes were $5.7 million and
$2.5 million for the nine-month periods ended
September 30, 2006 and 2005, respectively. The increase was
primarily attributable to the consolidation of the Forest Gulf
of Mexico operations and the resulting increased production. For
the nine-month periods ended September 30, 2006 and 2005,
severance and ad valorem taxes were $0.10 and $0.11 per
Mcfe, respectively.
Transportation expenses for the nine-month period ended
September 30, 2006 were $4.0 million, or
$0.07 Mcfe, compared to $1.7 million, or
$0.08 per Mcfe, for the nine-month period ended
September 30, 2005. The nine-month transportation expenses
per Mcfe remained comparable.
Depreciation, depletion, and amortization
(DD&A) expense increased 342% to
$192.2 million from $43.5 million for the nine-month
periods ended September 30, 2006 and 2005, respectively.
The increase was a result of increased production due to the
consolidation of the Forest Gulf of Mexico operations, as well
as an increase in the
unit-of-production
depreciation, depletion and amortization rate. The rate
increased to $3.53 per Mcfe from $1.93 per Mcfe for
the nine-month periods ended September 30, 2006 and 2005,
respectively. The per unit increase primarily resulted from the
increase of offshore production to 88% of total production at
September 30, 2006 as compared to 79% at September 30,
2005 because offshore assets have shorter estimated lives.
Another factor for the rate increase was increased accretion of
asset retirement obligations due to the consolidation of the
Forest Gulf of Mexico operations.
General and administrative (G&A) expenses
totaled $25.1 million for the first nine months of
2006, compared to $26.7 million for the first nine months
of 2005. G&A expense includes charges for stock compensation
expense of $9.0 million for the first nine months of 2006
compared to $17.6 million in the first nine months of 2005.
For the first nine months of 2006, $6.6 million of
compensation expense resulted from amortization of the cost of
restricted stock granted at the closing of Mariners
private equity placement in March 2005 and the remaining related
to the amortization of new grants issued in 2006 with vesting
periods
56
of three to four years. The restricted stock related to
Mariners private equity placement was fully vested in May
2006 and there will be no future charges related to those stock
grants. The 2005 compensation expense relates solely to the
amortization of the restricted stock granted under
Mariners private equity placement. Included in the 2006
G&A expenses are severance, retention, relocation and
transition costs related to the acquisition of the Forest Gulf
of Mexico operations of $2.6 million for the first nine
months of 2006. Salaries and wages in the first nine months of
2006 increased by $11.8 million compared to the same
year-earlier period. The increase was primarily the result of
staffing additions related to the acquisition of the Forest Gulf
of Mexico operations. In addition, the first nine months of 2005
included $2.3 million in payments to our former
stockholders to terminate a services agreement. Reported G&A
expenses in the first nine months of 2006 are net of
$12.2 million of overhead reimbursements billed or received
from other working interest owners, compared to
$3.1 million for the comparable period of 2005.
Net interest expense increased 449% to $25.9 million
from $4.7 million for the nine-month period ended
September 30, 2006 and 2005, respectively. This increase
was primarily due to an increase in average debt levels to
$420.2 million for the nine-month period ended
September 30, 2006 from $81.3 million for the
nine-month period ended September 30, 2005. The increased
debt was primarily the result of the issuance of
$300 million of notes, the assumption of debt in the Forest
Energy Resources merger and the use of our bank facility to
finance capital expenditures in excess of cash flows.
Additionally, the amendment and restatement of the credit
facility on March 2, 2006 was treated as an extinguishment
of debt for accounting purposes, and resulted in a charge of
$1.2 million to interest expense.
Income before income taxes increased to
$122.6 million from $54.0 million for the nine-month
periods ended September 30, 2006 and 2005, respectively.
This increase was primarily the result of higher operating
income attributed to the Forest Gulf of Mexico operations.
Provision for income taxes had an effective tax rate of
36.2% for the nine months ended September 30, 2006 as
compared to an effective tax rate of 34.1% for the comparable
period of 2005. The increase in the effective tax rate for the
nine months ended September 30, 2006 is primarily a result
of the Texas Margins tax, which was enacted during the second
quarter of 2006 for all properties residing in Texas. Excluding
the effects of the Texas Margins tax, the effective rate would
have been 35% for the nine months ended September 30, 2006.
57
Year
Ended December 31, 2005 compared to Year Ended
December 31, 2004
Operating
and Financial Results for the Year Ended December 31,
2005
Compared to the Year Ended December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
Non-GAAP
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
Combined
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
Year Ended
|
|
|
2004 through
|
|
|
2004 through
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
Summary Operating Information:
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
2004
|
|
|
|
(In thousands, except average sales price)
|
|
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,791
|
|
|
|
2,298
|
|
|
|
1,885
|
|
|
|
413
|
|
Natural gas (MMcf)
|
|
|
18,354
|
|
|
|
23,782
|
|
|
|
19,549
|
|
|
|
4,233
|
|
Total (MMcfe)
|
|
|
29,100
|
|
|
|
37,569
|
|
|
|
30,856
|
|
|
|
6,713
|
|
Average daily production (MMcfe/d)
|
|
|
80
|
|
|
|
103
|
|
|
|
101
|
|
|
|
112
|
|
Hedging activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues (loss)
|
|
$
|
(18,671
|
)
|
|
$
|
(12,300
|
)
|
|
$
|
(11,614
|
)
|
|
$
|
(686
|
)
|
Gas revenues (loss)
|
|
|
(30,613
|
)
|
|
|
(7,498
|
)
|
|
|
(8,929
|
)
|
|
|
1,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total hedging revenues (loss)
|
|
$
|
(49,284
|
)
|
|
$
|
(19,798
|
)
|
|
$
|
(20,543
|
)
|
|
$
|
745
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) realized(1)
|
|
$
|
41.23
|
|
|
$
|
33.17
|
|
|
$
|
33.69
|
|
|
$
|
30.75
|
|
Oil (per Bbl) unhedged
|
|
|
51.66
|
|
|
|
38.52
|
|
|
|
39.86
|
|
|
|
32.41
|
|
Natural gas (per Mcf) realized(1)
|
|
|
6.66
|
|
|
|
5.80
|
|
|
|
5.67
|
|
|
|
6.39
|
|
Natural gas (per Mcf) unhedged
|
|
|
8.33
|
|
|
|
6.12
|
|
|
|
6.13
|
|
|
|
6.05
|
|
Total natural gas equivalent
($/Mcfe) realized(1)
|
|
|
6.74
|
|
|
|
5.70
|
|
|
|
5.65
|
|
|
|
5.92
|
|
Total natural gas equivalent
($/Mcfe) unhedged
|
|
|
8.43
|
|
|
|
6.23
|
|
|
|
6.32
|
|
|
|
5.81
|
|
Oil and gas revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
73,831
|
|
|
$
|
76,207
|
|
|
$
|
63,498
|
|
|
$
|
12,709
|
|
Gas sales
|
|
|
122,291
|
|
|
|
137,980
|
|
|
|
110,925
|
|
|
|
27,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas revenues
|
|
$
|
196,122
|
|
|
$
|
214,187
|
|
|
$
|
174,423
|
|
|
$
|
39,764
|
|
Other revenues
|
|
|
3,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
29,882
|
|
|
|
25,484
|
|
|
|
21,363
|
|
|
|
4,121
|
|
Transportation expenses
|
|
|
2,336
|
|
|
|
3,029
|
|
|
|
1,959
|
|
|
|
1,070
|
|
Depreciation, depletion and
amortization
|
|
|
59,426
|
|
|
|
64,911
|
|
|
|
54,281
|
|
|
|
10,630
|
|
General and administrative expenses
|
|
|
37,053
|
|
|
|
8,772
|
|
|
|
7,641
|
|
|
|
1,131
|
|
Impairment of production equipment
held for use
|
|
|
1,845
|
|
|
|
957
|
|
|
|
957
|
|
|
|
|
|
Net interest expense (income)
|
|
|
7,393
|
|
|
|
5,734
|
|
|
|
5,820
|
|
|
|
(86
|
)
|
Income before taxes
|
|
|
61,775
|
|
|
|
105,300
|
|
|
|
82,402
|
|
|
|
22,898
|
|
Provision for income taxes
|
|
|
21,294
|
|
|
|
36,855
|
|
|
|
28,783
|
|
|
|
8,072
|
|
Net income
|
|
|
40,481
|
|
|
|
68,445
|
|
|
|
53,619
|
|
|
|
14,826
|
|
|
|
|
(1) |
|
Average realized prices include the effects of hedges. |
Net production during 2005 decreased approximately 23% to
29.1 Bcfe from 37.6 Bcfe in 2004 primarily due to
decreased Gulf of Mexico production, partially offset by
increased onshore production. Mariners production was
negatively impacted during the third and fourth quarters of 2005
due to hurricane activity, primarily Katrina and Rita.
Production shut-in and deferred because of the hurricanes
impact totaled approximately 6-8 Bcfe during the third and
fourth quarters of 2005. As of December 31, 2005,
approximately
58
5 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
2005 at our Swordfish, Ochre, Pluto, and Rigel development
projects was delayed awaiting repairs to host facilities.
Swordfish recommenced production in the fourth quarter of 2005,
Rigel recommenced production in the first quarter of 2006, and
Ochre and Pluto recommenced production in the third quarter of
2006.
Increased development drilling at our Aldwell unit in West Texas
contributed to a 60% increase in onshore production to an
average of approximately 18.1 MMcfe per day in 2005 from an
average of approximately 11.3 MMcfe per day in 2004.
In the deepwater Gulf of Mexico, production decreased
approximately 32% to an average of approximately 32.3 MMcfe
per day in 2005 compared to an average of approximately
47.2 MMcfe per day in 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 was negatively impacted by hurricane
activity as well as by expected declines. As previously
discussed, hurricane-related delays in commencement of
production at our Swordfish, Pluto and Rigel development
projects also contributed to the production decline.
In the Gulf of Mexico shelf, production decreased by
approximately 34% to an average of approximately 29.2 MMcfe
per day in 2005 from an average of approximately 44.1 MMcfe
per day in 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 and Hurricanes
Katrina and Rita in 2005. 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
and the impact of the 2005 hurricane season.
Hedging activities in 2005 decreased our average realized
natural gas price received by $1.67 per Mcf and revenues by
$30.6 million, compared with a decrease of $0.32 per
Mcf and revenues of $7.5 million in 2004. Our hedging
activities with respect to crude oil during 2005 decreased the
average sales price received by $10.43 per barrel and
revenues by $18.7 million compared with a decrease of
$5.35 per barrel and revenues of $12.3 million for
2004.
Oil and gas revenues decreased 8% to $196.1 million
in 2005 when compared to 2004 oil and gas revenues of
$214.2 million, due to the aforementioned 23% decrease in
production, partially offset by an 18% increase in realized
prices (including the effects of hedging) to $6.74 per Mcfe
in 2005 from $5.70 per Mcfe in 2004.
Other revenues of $3.6 million in 2005 represent an
indemnity payment of $1.9 million received from our former
stockholder related to the 2004 merger and $1.7 million
generated by our West Texas Aldwell unit gathering system.
Lease operating expenses increased 17% to
$29.9 million in 2005 from $25.5 million in 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 deepwater
fields. On a per unit basis, lease operating expenses were
$1.03 per Mcfe in 2005 compared to $0.68 per Mcfe in 2004.
The increased per unit costs also reflect lower production rates
in 2005, including hurricane-related disruptions.
Transportation expenses were $2.3 million or
$0.08 per Mcfe in 2005, compared to $3.0 million or
$0.08 per Mcfe in 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
(DD&A) expense decreased 8% to
$59.4 million during 2005 from $64.9 million for 2004
as a result of decreased production of 8.5 Bcfe in 2005
compared to 2004, partially offset by an increase in the
unit-of-production
depreciation, depletion and amortization rate to
59
$2.04 per Mcfe for 2005 from $1.73 per Mcfe for 2004.
The per unit increase was primarily the result of an increase in
future development costs on our deepwater development fields.
General and administrative (G&A) expenses,
which are net of $6.9 million and $4.4 million of
overhead reimbursements billed or received from other working
interest owners in 2005 and 2004, respectively, increased 322%
to $37.1 million during 2005 compared to $8.8 million
in 2004. The increase was primarily due to recognizing
$25.7 million in stock compensation expense related to
restricted stock and options granted in 2005. We also paid
$2.3 million to our former stockholders to terminate a
services agreement in 2005, compared to $1.0 million under
the same agreement in 2004. In addition, G&A expenses
increased by $1.6 million due to a reduction in the amount
of G&A capitalized in 2005 compared to 2004.
Impairment of production equipment held for use reflects
the reduction of the carrying cost of our inventory by
$1.8 million and $1.0 million as of December 31,
2005 and December 31, 2004, respectively. In 2005, the
reduction in estimated value primarily related to subsea trees
and wellhead equipment held in inventory.
Net interest expense for 2005 increased 25% to
$7.4 million from $5.7 million in 2004, primarily due
to higher average debt levels in 2005 compared to 2004. In
connection with the merger on March 2, 2004, Mariner
incurred $135 million in new bank debt and issued a
$10 million promissory note to JEDI. For comparison
purposes, approximately ten months of interest related to such
borrowings is reflected in 2004 compared to twelve months of
interest in 2005.
Income before income taxes decreased to
$61.8 million for 2005 compared to $105.3 million for
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
$21.3 million for 2005 from $36.9 million for 2004 as
a result of decreased operating income for 2005 compared to 2004.
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
Non-GAAP
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
|
|
|
Combined
|
|
|
2004 through
|
|
|
2004 through
|
|
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
|
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
|
|
60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
Non-GAAP
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
|
|
|
Combined
|
|
|
2004 through
|
|
|
2004 through
|
|
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
Summary Operating Information:
|
|
2003
|
|
|
2004
|
|
|
2004
|
|
|
2004
|
|
|
|
(In thousands, except average sales price)
|
|
|
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
|
|
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 revenue
|
|
$
|
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
|
|
Net income
|
|
|
38,244
|
|
|
|
68,445
|
|
|
|
53,619
|
|
|
|
14,826
|
|
|
|
|
(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.
61
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.
DD&A 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.
G&A expenses, which are 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.
Liquidity
and Capital Resources
Cash
Flows and Liquidity
Secured Bank Credit Facility. At
December 31, 2005, we had $152 million in advances
outstanding under our secured revolving credit facility with a
borrowing base as of that date of $170 million. In January
2006, the borrowing base was increased to $185 million. In
connection with the merger with Forest Energy Resources on
March 2, 2006, we amended and restated our existing credit
facility to increase maximum credit availability to
$500 million for revolving loans, including up to
$50 million in letters of credit, with a $400 million
borrowing base as of that date. On March 2, 2006, after
giving effect to funds required at closing to refinance
$176.2 million of debt assumed in the merger and other
merger-related costs, our total debt drawn under the facility
was approximately $350 million, including a
$4.2 million letter of credit required for plugging and
abandonment obligations at one of our offshore fields. On
April 7, 2006, the borrowing base under the secured credit
facility was increased to $430 million, subject to
redetermination or adjustment. On April 24, 2006, the
borrowing base was reduced to $362.5 million in accordance
with an amendment to the credit facility related to our offering
of $300 million of senior notes. For subsequent qualifying
bond issuances, the amendment provides that the borrowing base
in effect on the closing date of such a bond issuance will
automatically reduce by 25% of the aggregate principal amount of
such bond issuance to the extent that it does not refinance the
principal amount of an existing bond issuance. The secured
credit facility permits Mariners issuance of certain
unsecured bonds of up to $350 million in aggregate
principal amount that have a non-default interest rate of 10% or
less per annum and a scheduled maturity date after March 1,
2012. Mariners sale and issuance of $300 million of
senior notes in April 2006 constituted such a qualifying bond
issuance. At September 30, 2006, approximately
$328.6 million was outstanding under our revolving secured
credit facility, including the $4.2 million letter of
credit and a $10.4 million letter of credit issued in
August 2006 to BP to secure certain assumed offshore
plugging and abandonment obligations. The borrowing
62
base was increased to $450 million in October 2006, subject
to redetermination or adjustment. This credit facility matures
on March 2, 2010.
The amendment and restatement of our secured credit facility on
March 2, 2006 also provided for an additional
$40 million letter of credit that is not included as a use
of the borrowing base and matures on March 2, 2009. The
$40 million letter of credit was issued in favor of Forest
to secure Mariners performance of its obligations to drill
and complete 150 wells under an existing
drill-to-earn
program. This letter of credit will reduce periodically by an
amount equal to the product of $0.5 million times the
number of wells exceeding 75 that are drilled and completed. The
first reduction of approximately $4.3 million occurred in
October 2006 based upon the 83 wells drilled and completed
as of September 30, 2006. We expect additional reductions
based upon quarterly drilling activity, with the next reduction
anticipated in January 2007.
Private Placement of Senior Unsecured Notes due
2013. On April 24, 2006, Mariner sold and
issued to eligible purchasers $300 million aggregate
principal amount of its
71/2% senior
notes due 2013 pursuant to Rule 144A under the Securities
Act. The notes were priced to yield 7.75% to maturity. Net
proceeds, after deducting initial purchasers discounts and
commissions and offering expenses, were approximately
$287.9 million. Mariner used the net proceeds to repay
borrowings under its secured credit facility. The issuance of
the notes was a qualifying bond issuance under Mariners
secured credit facility and resulted in an automatic reduction
of its borrowing base to $362.5 million as of
April 24, 2006. For a description of the terms of the
notes, see Description of Senior Notes. Costs
associated with the notes offering were approximately
$8.3 million, excluding discounts of $3.8 million.
JEDI Term Promissory Note. As part of the 2004
merger consideration payable to JEDI, we issued a term
promissory note to JEDI in the amount of $10 million. The
note bore 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
remained 10% per annum. We chose to pay the interest in
cash rather than in kind. The JEDI note was secured by a lien on
three of our Gulf of Mexico properties with no proved reserves.
We could offset against the note the amount of certain claims
for indemnification that could be asserted against JEDI under
the terms of the merger agreement. The JEDI note contained
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 2005 private equity placement to repay a portion of the JEDI
note. As of December 31, 2005, $4 million was still
outstanding under the JEDI note. This note was repaid in full on
its maturity date of March 2, 2006.
Working Capital. Working capital at
September 30, 2006 was a negative $75.3 million,
excluding current derivative liabilities and deferred taxes.
This was a result of increased accrued capital obligations for
drilling and development projects in progress. Working capital
at December 31, 2005 was negative $46.4 million,
excluding current derivative liabilities and deferred taxes.
Accrued liabilities (including accounts payable) and accrued
receivables (including accounts receivable) at December 31,
2005 increased by approximately 91% and 68%, respectively, over
levels at December 31, 2004 primarily due to increased
accrued obligations for drilling and development projects in
progress at year end 2005 and related accruals of amounts owed
by partners. 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 2003 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.
Capital Expenditures. In the first nine months
of 2006, our capital expenditures were approximately
$517.0 million, of which approximately 51% related to
development activities; 46% related to the acquisition of
BPs interest in West Cameron
110/111 and
exploration activities, including the acquisition of leasehold
and
63
seismic; and the balance related to capitalized expenses and
minor corporate items. Our 2005 capital expenditures were
$252.7 million. Approximately 48% of our capital
expenditures were incurred for development projects, 24% for
exploration activities, 21% for acquisitions of developed
properties, and the remainder for other items (primarily
expenditures for our Aldwell gathering system, capitalized
overhead and interest). The following table presents major
components of our capital expenditures for the nine months ended
September 30, 2006 and for each of the three years in the
period ended December 31, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
|
Combined
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
Nine Months
|
|
|
|
|
|
Year
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
|
|
|
Ended
|
|
|
Year Ended
|
|
|
Ended
|
|
|
2004 to
|
|
|
2004 to
|
|
|
Year Ended
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
2004
|
|
|
2003
|
|
|
|
(In millions)
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Leasehold acquisition
|
|
$
|
15.5
|
|
|
$
|
11.5
|
|
|
$
|
4.8
|
|
|
$
|
4.4
|
|
|
$
|
0.4
|
|
|
$
|
4.8
|
|
Oil and natural gas exploration
|
|
|
154.3
|
|
|
|
50.0
|
|
|
|
43.0
|
|
|
|
35.9
|
|
|
|
7.1
|
|
|
|
26.8
|
|
Oil and natural gas development
|
|
|
264.2
|
|
|
|
121.7
|
|
|
|
88.6
|
|
|
|
82.0
|
|
|
|
6.6
|
|
|
|
44.3
|
|
Proceeds from property conveyances
|
|
|
(2.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(121.6
|
)
|
Acquisitions
|
|
|
70.9
|
|
|
|
53.4
|
|
|
|
4.9
|
|
|
|
4.9
|
|
|
|
|
|
|
|
|
|
Other items (primarily gathering
system, capitalized overhead and interest)
|
|
|
12.1
|
|
|
|
16.1
|
|
|
|
7.6
|
|
|
|
6.4
|
|
|
|
1.2
|
|
|
|
7.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures, net of
proceeds from property conveyances
|
|
$
|
515.0
|
|
|
$
|
252.7
|
|
|
$
|
148.9
|
|
|
$
|
133.6
|
|
|
$
|
15.3
|
|
|
$
|
(38.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our net capital expenditures for 2005 increased by
$103.8 million as compared to 2004, primarily as a result
of increased acquisitions, primarily in West Texas, and
increased expenditures on development activities. 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.
We had no long-term debt outstanding as of December 31,
2003. As of December 31, 2005 and 2004, long-term debt was
$156 million and $115 million, respectively. As of
September 30, 2006, long-term debt was $614 million.
We anticipate that total capital expenditures for 2006 will
approximate $690.0 million (of which approximately
$70.9 million is attributable to the West Cameron
acquisition described under Recent
Developments), with approximately 57% allocated to
development activities, 41% to exploration activities, and the
remainder to other items (primarily capitalized overhead and
interest). The 2006 budget is an increase of approximately 83%
over our 2005 expenditures. The increase is primarily driven by
the addition of the Forest Gulf of Mexico operations,
continuation of our deepwater development activities, and
expansion of our exploration activities, including increasing
our acquisition of leasehold and seismic data. In addition, we
expect to incur approximately $85 million for repairs of
damage caused by Hurricanes Katrina and Rita. While this will be
a cash outflow in 2006, we expect to recover these costs through
insurance reimbursements beginning in early 2007, although
complete insurance settlement of all hurricane-related claims
may take several additional quarters. See
Business Insurance Matters. Since we
believe these costs to be reimbursable, they will not be
reflected in reported 2006 capital expenditures.
Cash Flows. During the first nine months of
2006, we utilized our secured credit facility to fund amounts
for capital expenditures incurred in excess of cash flows.
Although we expect to fund exploration and
64
development capital expenditures during the remainder of 2006
from internally generated cash flows, the credit facility may be
utilized for such expenditures exceeding current projections and
for acquisitions.
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 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. 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 reduced. If our cash flows are less than
anticipated or amounts available for borrowing under our
revolving credit facility are reduced or we can not access the
high yield or other debt markets, 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
year ended December 31, 2005, our Gulf of Mexico properties
comprised about 77% of our total production or 93% on a pro
forma basis. We plan to maintain an active drilling program for
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 and we begin to exploit our newly acquired
offshore assets. 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 that subsequently
was amended and restated. The new credit facility was fully
drawn at inception for $135 million. In addition, we issued
a $10 million promissory note to JEDI as part of the merger
consideration. See Enron Related Matters
and JEDI Term Promissory Note. Net
proceeds from a private equity placement were approximately
$44 million, of which $6 million was used to pay down
the JEDI promissory note with the remainder used to pay down the
credit facility. The JEDI note was fully repaid at its maturity
date of March 2, 2006.
For the years ended December 31, 2005 and 2004, our
interest rate sensitivity for a change in interest rates of
1/8 percent on average outstanding debt under our credit
facility is approximately $0.1 million and
$0.1 million, respectively. The LIBOR rate on which our
bank borrowings are primarily based was 4.69% as of
March 2, 2006.
We had net cash inflows of $0.3 million and
$2.0 million for the nine-month periods ended
September 30, 2006 and 2005, respectively, and a net cash
inflow of $2.0 million in 2005 compared to a net cash
outflow of $57.6 million in 2004 and a net cash inflow of
$41.8 million in 2003. A discussion of the major components
of cash flows for these periods follows.
65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
Non-GAAP
|
|
Period from
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
Combined
|
|
March 3,
|
|
January 1,
|
|
|
|
|
Nine Months
|
|
Year Ended
|
|
Year Ended
|
|
2004 to
|
|
2004 to
|
|
Year Ended
|
|
|
Ended September 30,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
March 2,
|
|
December 31,
|
|
|
2006
|
|
2005
|
|
2005
|
|
2004
|
|
2004
|
|
2004
|
|
2003
|
|
|
(In millions)
|
|
Cash flows provided by operating
activities
|
|
$
|
172.8
|
|
|
$
|
135.4
|
|
|
$
|
165.4
|
|
|
$
|
155.5
|
|
|
$
|
135.2
|
|
|
$
|
20.3
|
|
|
$
|
88.9
|
|
Net cash flows from operations increased by $37.4 million
to $172.8 million from $135.4 million for the
nine-month periods ended September 30, 2006 and 2005,
respectively. The increase was primarily due to increased
operating revenues attributable to the Forest Gulf of Mexico
operations acquired.
Cash flows provided by operating activities in 2005 increased by
$9.9 million compared to 2004. The increase was primarily
due to negative changes in working capital offset by lowered
operating revenues. Cash flows provided by operating activities
in 2004 increased by $66.6 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Merger
|
|
Pre-Merger
|
|
|
|
|
|
|
|
|
Non-GAAP
|
|
Period from
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
Combined
|
|
March 3,
|
|
January 1,
|
|
|
|
|
Nine Months
|
|
Year Ended
|
|
Year Ended
|
|
2004 to
|
|
2004 to
|
|
Year Ended
|
|
|
Ended September 30,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
March 2,
|
|
December 31,
|
|
|
2006
|
|
2005
|
|
2005
|
|
2004
|
|
2004
|
|
2004
|
|
2003
|
|
|
(In millions)
|
|
Cash flows (used in) provided by
investing activities
|
|
$
|
(423.5
|
)
|
|
$
|
(142.1
|
)
|
|
$
|
(247.8
|
)
|
|
$
|
(148.3
|
)
|
|
$
|
(133.0
|
)
|
|
$
|
(15.3
|
)
|
|
$
|
52.9
|
|