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UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K/A
(Amendment No. 1)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2008
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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Commission file number 1-32747
MARINER ENERGY, INC.
(Exact name of registrant as
specified in its charter)
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Delaware
(State or other jurisdiction
of
incorporation or organization)
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86-0460233
(I.R.S. Employer
Identification Number)
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One
BriarLake Plaza, Suite 2000
2000 West Sam Houston Parkway South
Houston, Texas 77042
(Address
of principal executive offices and zip code)
(713) 954-5500
(Registrants telephone
number, including area code)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, $.0001 par value
Rights to Purchase Preferred Stock
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New York Stock Exchange
New York Stock Exchange
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Securities
registered pursuant to section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Exchange
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Exchange Act during the preceding 12 months (or for
such shorter period that the registrant was required to file
such reports) and (2) has been subject to such filing
requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of the registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
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Large accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller reporting
company o
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
The aggregate market value of the registrants common stock
held by non-affiliates on June 30, 2008 was approximately
$3,166,804,986 based on the closing sale price of $36.97 per
share as reported by the New York Stock Exchange on
June 30, 2008. The number of shares of common stock of the
registrant issued and outstanding on February 20, 2009 was
90,057,276.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of registrants Proxy Statement relating to the
Annual Meeting of Stockholders to be held May 11, 2009 are
incorporated by reference into Part III of this
Form 10-K.
EXPLANATORY
NOTE
The purpose of this Amendment No. 1 on
Form 10-K/A
(this
Form 10-K/A)
is to amend Item 8 of Part II of our Annual Report on
Form 10-K
for the fiscal year ended December 31, 2008, which was
filed with the Securities and Exchange Commission (the
SEC) on March 2, 2009 (the 2008
10-K).
The amendments correct two tables in note 16 (Supplemental
Oil and Gas Reserve and Standardized Measure Information
(Unaudited)) to the consolidated financial statements.
Corrections have been made to the table presenting
Estimated Quantities of Proved Reserves and in the
table presenting the principal sources of change in the
Standardized Measure of discounted future net cash flows. The
corrections do not change the total estimated quantities of
proved reserves as of December 31, 2008 or the Standardized
Measure of discounted future net cash flows as of
December 31, 2008 reported in those tables in the 2008
10-K.
In accordance with
Rule 12b-15
under the Securities Exchange Act of 1934, as amended (the
Exchange Act), this
Form 10-K/A
amends and restates Item 8 of Part II of the 2008
10-K in its
entirety. In addition, as required by
Rule 12b-15
under the Exchange Act, new certifications by our principal
executive officer and principal financial officer are filed as
exhibits to this
Form 10-K/A
under Item 15 of Part IV.
For ease in preparing our annual report to stockholders under
Rule 14a-3
of the Exchange Act, which historically has consisted primarily
of our
Form 10-K
for a given year, this
Form 10-K/A
restates, without change, Items 1 through 4 of Part I,
Items 5 through 7A and 9 through 9B of Part II, and
Items 10 through 14 of Part III of the 2008
10-K.
Except as noted above, this Annual Report
Form 10-K/A
does not reflect events occurring after the filing of the 2008
10-K on
March 2, 2009 and no attempt has been made in this
Form 10-K/A
to modify or update other disclosures made in the 2008
10-K.
Accordingly, this
Form 10-K/A
should be read in conjunction with our filings made with the SEC
after the filing of the 2008
10-K.
TABLE OF
CONTENTS
1
CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING INFORMATION
Various statements in this annual report, including those that
express a belief, expectation, or intention, as well as those
that are not statements of historical fact, are forward-looking
statements within the meaning of the Private Securities
Litigation Reform Act of 1995. 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, 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 annual report speak only as of the date of this annual
report; we disclaim any obligation to update these statements
unless required by 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 described in
Item 1A. Risk Factors and Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations elsewhere in this annual report.
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 events and
natural disasters such as loop currents, hurricanes, fires,
floods and other natural events, 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; and
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risks related to significant acquisitions or other strategic
transactions, such as failure to realize expected benefits or
objectives for future operations.
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2
PART I
The following discussion is intended to assist you in
understanding our business and the results of our operations. It
should be read in conjunction with the Consolidated Financial
Statements and the related notes that appear elsewhere in this
report. Certain statements made in our discussion may be forward
looking. Forward-looking statements involve risks and
uncertainties and a number of factors could cause actual results
or outcomes to differ materially from our expectations. See
Cautionary Statements at the beginning of this
report on
Form 10-K
for additional discussion of some of these risks and
uncertainties. Unless the context otherwise requires or
indicates, references to Mariner, we,
our, ours, and us refer to
Mariner Energy, Inc. and its consolidated subsidiaries
collectively. Certain oil and natural gas industry terms used in
this annual report are defined in the Glossary of Oil and
Natural Gas Terms set forth in Item 1.
Business of this annual report.
General
Mariner Energy, Inc. is an independent oil and gas exploration,
development, and production company. We were incorporated in
August 1983 as a Delaware corporation. Our corporate
headquarters are located at One BriarLake Plaza,
Suite 2000, 2000 West Sam Houston Parkway South,
Houston, Texas 77042. Our telephone number is
(713) 954-5500
and our website address is www.mariner-energy.com. Our common
stock is listed on the New York Stock Exchange and trades under
the symbol ME.
We currently operate in three principal geographic areas:
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Permian Basin, where we are an active driller in the prolific
Spraberry field at depths between 6,000 and
10,000 feet. Our increasing Permian Basin operation, which
is characterized by long reserve life, stable drilling and
production performance, and relatively lower capital
requirements, somewhat counterbalances the higher geological
risk, operational challenges and capital requirements attendant
to most of our Gulf of Mexico deepwater operations. We have
expanded our presence in the region, targeting a combination of
infill drilling activities in established producing trends,
including the Spraberry, Dean and Wolfcamp trends, as well as
exploration activities in emerging plays such as the Wolfberry
and newer Wolfcamp trends.
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Gulf of Mexico Deepwater, where we have actively conducted
exploration and development projects since 1996 in water depths
ranging from 1,300 feet up to 7,000 feet. Employing
our experienced geoscientists, rich seismic database, and
extensive subsea tieback expertise, we have participated in more
than 84 deepwater wells. Our deepwater exploration operation
targets larger potential reserve accumulations than are
generally accessible onshore or on the Gulf of Mexico shelf.
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Gulf of Mexico Shelf, where we drill or participate in
conventional shelf wells and deep shelf wells extending to 1,300
foot water depths. We currently pursue a two-pronged strategy on
the shelf, combining opportunistic acquisitions of legacy
producing fields believed to hold exploitation potential and
active exploration activities targeting conventional and deep
shelf opportunities. Given the highly mature nature of this area
and the steep production declines characteristic of most wells
in this region, the goal of our shallow water or shelf operation
is to maximize cash flow for reinvestment in our deepwater and
Permian Basin operations, as well as for expansion into new
operating areas.
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During 2008, we produced approximately 118.4 Bcfe and our
average daily production rate was 323 MMcfe per day. At
December 31, 2008, we had 973.9 Bcfe of estimated
proved reserves, of which approximately 57% were natural gas and
43% were oil, natural gas liquids (NGLs) and
condensate. Approximately 70% of our estimated proved reserves
were classified as proved developed.
We file annual, quarterly and current reports, proxy statements
and other information as required by the Securities and Exchange
Commission (SEC). Our SEC filings are available to
the public over the Internet at the SECs web site at
www.sec.gov. or at the SECs public reference room at
450 Fifth Street, N.W., Washington, D.C. 20549. Please
call the SEC at
1-800-SEC-0330
for further information about the public reference room. Reports
and other information about Mariner can be inspected at the
offices of the New York Stock Exchange, 20 Broad Street,
New York, New York 10005. Copies of our SEC filings are
available free of
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charge on our website at www.mariner-energy.com as soon as
reasonably practicable after we electronically file such
material with, or furnish it to, the SEC. The information on our
website is not a part of this annual report. Copies of our SEC
filings can also be provided to you at no cost by writing or
telephoning us at our corporate headquarters.
Recent
Developments
Gulf of Mexico Deepwater Acquisition On
December 19, 2008, we acquired additional working interests
in our existing property, Atwater Valley Block 426 (Bass
Lite), for approximately $32.6 million, increasing our
working interest by 11.6% to 53.8%. We internally estimated
proved reserves attributable to the acquisition of approximately
17.6 Bcfe (100% natural gas).
Acquisition of Incremental Spraberry
Interests On February 29, 2008 and
December 1, 2008, we acquired additional working interests
in certain of our existing properties in the Spraberry field in
the Permian Basin, increasing our average working interest
across these properties to approximately 80%. We internally
estimated proved reserves attributable to the acquisition of
approximately 27.4 Bcfe. We operate substantially all of
the assets. The purchase prices were approximately
$21.7 million for the February acquisition and
$19.4 million for the December acquisition.
Impact of
Worldwide Financial Crisis and Lower Commodity Prices on Capital
Program
In recent years, oil and gas commodity prices generally trended
upwards in response to robust demand and constrained supplies,
with oil and gas prices peaking at more than $140.00 per barrel
and $13.00 per Mcf, respectively, in July 2008. In response to
the sustained increase in commodity prices, the oil and gas
industry experienced significant increases in activity and in
demand for oil field services. The increased demand for these
services resulted in significant inflation in the cost of
drilling rigs, services, equipment and labor.
In the second half of 2008, a world-wide economic recession and
oversupply of natural gas in North America led to an
unprecedented decline in oil and gas prices, with oil falling by
more than $100.00 per barrel from its peak earlier in 2008.
However, the inflated cost of oil field services resulting from
sustained historically high commodity prices did not decrease in
line with the decline in commodity prices. The prospect of
continued low commodity prices and disproportionately high
service costs has constrained the industrys capital
reinvestment and undermined rates of return in new projects,
particularly those in areas characterized by high costs or long
reserve lives. In order to manage our capital program within
expected cash flows, we tentatively have reduced our 2009
capital budget by more than 50% from 2008.
Our 2009 activities in the Permian Basin will focus primarily on
expanding beyond our typical Spraberry infill drilling operation
into new exploration plays, such as the Wolfberry and Wolfcamp
Detrital trends. We plan to delineate prospects and determine
their economic viability. Our goal is to expand our prospect
inventory and generate opportunities to drill when commodity
prices or service costs adjust to levels expected to yield more
attractive returns. Until then, we are scaling down our infill
drilling and development activities to primarily lease-saving
operations and contractual drilling commitments. We also
anticipate substantially reduced recompletion and development
activities in our Gulf of Mexico shelf operation until commodity
price and service cost dynamics adjust to allow a more
attractive rate of return. In addition, we are allocating a
disproportionate portion of our 2009 capital budget to our Gulf
of Mexico deepwater exploration program due primarily to
contractual drilling commitments.
Balanced
Growth Strategy
We are a growth company and strive to increase our reserves and
production from our existing asset base as well as through
expansion into new operating areas. Our management team pursues
a balanced growth strategy employing varying elements of
exploration, development, and acquisition activities in
complementary operating regions intended to achieve an overall
moderate-risk growth profile at attractive rates of return under
most industry conditions.
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Exploration: Our exploration program is
designed to facilitate organic growth through exploration in a
wide variety of exploratory drilling projects, including
higher-risk, high-impact projects that have the potential to
create substantial value for our stockholders. We view
exploration as a core competency. We typically dedicate a
significant portion of our capital program each year to
prospecting for new oil
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and gas fields, including in the Gulf of Mexico deepwater where
reserve accumulations are typically much larger than those found
onshore or on the shelf. Our explorationists have a
distinguished track record in the Gulf of Mexico. Our reputation
for generating high-quality exploration prospects also can
create potentially valuable partnering opportunities, which can
enable us to participate in exploration projects developed by
other operators.
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Development: Our development efforts are
intended to complement our higher-risk exploration projects
through a variety of moderate-risk activities targeted at
maximizing recovery and production from known reservoirs as well
as finding overlooked oil and gas accumulations in and around
existing fields. Our geoscientists and engineers have a solid
track record in effectively developing new fields, redeveloping
legacy fields, rejuvenating production, controlling unit costs,
and adding incremental reserves at attractive finding costs in
both onshore and offshore fields. Our development and
exploitation program strives to enhance the rate of returns of
our projects, allowing us to establish critical operating mass
from which to expand in our focus areas, and generate a rich
portfolio of relatively lower-risk engineering/exploitation
projects that counterbalance our higher-risk exploration
activities.
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Acquisitions: In addition to our internal
exploration and development activities on our existing
properties, we also compete actively for new oil and gas
properties through property acquisitions as well as corporate
transactions. Our management team has substantial experience
identifying and executing a wide variety of tactical and
strategic transactions that augment our existing operations or
present opportunities to expand into new operating regions. We
primarily focus our acquisition efforts on stable, onshore
basins such as the Permian Basin, which can counterbalance our
growing deepwater exploration operations, but we also respond in
an opportunistic fashion to attractive acquisition opportunities
in the Gulf of Mexico. Due to our existing prospect inventory,
we are not compelled to make acquisitions in order to grow;
however we expect to continue to pursue acquisitions
aggressively on an opportunistic basis as an integral part of
our growth strategy.
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Our
Competitive Strengths
We believe our core resources and strengths include:
Diversity of assets and activities. Our assets
and operations are diversified among the Permian Basin and the
Gulf of Mexico deepwater and shelf. Each of these areas involves
distinctly different operational characteristics, as well as
different financial and operational risks and rewards. Moreover,
within these operating areas we pursue a breadth of exploration,
development and acquisition activities, which in turn entail
unique risks and rewards. By diversifying our assets both
onshore and in the Gulf, and pursuing a full range of
exploration, development and acquisition activities, we strive
to mitigate concentration risk and avoid overdependence on any
single activity to facilitate our growth. By maintaining a
variety of investment opportunities ranging from high-risk,
high-impact projects in the deepwater to relatively low-risk,
repeatable projects in the Permian Basin, we attempt to execute
a balanced capital program and attain a more moderate
company-wide risk profile while still affording our stockholders
the significant potential upside attendant to an active
deepwater exploration company.
Large prospect inventory. We believe we have
significant potential for growth through the exploration and
development of our existing asset base. We are one of the
largest leaseholders among independent producers in the Gulf of
Mexico. Additionally, we are an active participant at MMS lease
sales. We were the apparent high bidder on three blocks at the
Outer Continental Shelf 207 Lease Sale held on August 20,
2008 by the MMS. The MMS awarded all three blocks to us,
yielding an aggregate exposure of $0.9 million. We hold a
100% working interest in each of these blocks. In addition, the
MMS awarded us 19 blocks on which we were the apparent high
bidder at the Central Gulf of Mexico Lease Sale 206 held by the
MMS on March 19, 2008. The awarded blocks involve seven
deepwater subsalt prospects (both Miocene and Lower Tertiary),
four deepwater prospects, four deep shelf prospects, and one
conventional shelf prospect. Our net exposure on the awarded
bids was $79.1 million and our working interest ranges from
33% to 100%. Furthermore, in the Permian Basin we have a large
and growing asset base that we anticipate is capable of
sustaining our current drilling program for a number of years.
We believe that our large acreage position makes us less
dependent on acquisitions for our growth as compared to
companies that have less extensive drilling inventories.
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Exploration expertise. Our seasoned team of
geoscientists has made significant discoveries in the Gulf of
Mexico and has achieved a cumulative 65% success rate during the
three years ended December 31, 2008. Our geoscientists each
average almost 30 years of relevant industry experience. We
believe our emphasis on exploration allows us a competitive
advantage over other companies who are either wholly dependent
on acquisitions for growth or only sporadically engage in more
limited exploration activities.
Operational control and substantial working
interests. We serve as operator of properties
representing approximately 87% of our production and have an
average 74% working interest in our operated properties. We
believe operating our properties gives us a competitive
advantage over non-operating interest holders, particularly in a
challenging financial environment, since operatorship better
allows us to determine the extent and timing of our capital
programs, as well as to assert the most direct impact on
operating costs.
Extensive seismic library. We have access to
recent-vintage, regional
3-D seismic
data covering a significant portion of the Gulf of Mexico. We
use seismic technology in our exploration program to identify
and assess prospects, and in our development program to assess
hydrocarbon reservoirs with a goal of optimizing drilling,
workover and recompletion operations. We believe that our
investment in
3-D seismic
data gives us an advantage over companies with less extensive
seismic resources in that we are better able to interpret
geological events and stratigraphic trends on a more precise
geographical basis utilizing more detailed analytical data.
Subsea tieback expertise. We have accumulated
an extensive track record in the use of subsea tieback
technology, which enables production from subsea wells to
existing third-party production facilities through subsea flow
line and umbilical infrastructure. This technology typically
allows us to avoid the significant lead time and capital
commitment associated with the fabrication and installation of
production platforms or floating production facilities, thereby
accelerating our project start ups and reducing our financial
exposure. In turn, we believe this lowers the economic
thresholds of our target prospects and allows us to exploit
reserves that otherwise may be considered non-commercial because
of the high cost of stand-alone production facilities.
Properties
Our principal oil and gas properties are located in the Permian
Basin and the Gulf of Mexico deepwater and shelf. The Gulf of
Mexico properties are primarily in federal waters. The following
table presents our top fields by estimated proved reserves for
each principal geographic area:
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Net
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Approximate
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Estimated
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Estimated
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Working
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2008 Net
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Proved
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Proved Reserves
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Operator
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Interest %
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Production
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Reserves
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% Oil /% Gas(1)
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(Bcfe)
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(Bcfe)
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Permian Basin:
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Spraberry
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Mariner
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80
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%
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13.5
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419.1
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69%/31%
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Gulf Of Mexico Deepwater:
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Atwater Valley 426 (Bass Lite)
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Mariner
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54
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%
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8.5
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95.8
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0%/100%
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Garden Banks 462 (Geauxpher)
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Mariner
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60
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%
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32.7
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3%/97%
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Green Canyon 646 (Daniel Boone)
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W&T Offshore
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40
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%
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18.3
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68%/32%
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East Breaks 558/602 (Northwest Nansen)
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Anadarko
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33-50
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%
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12.9
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16.6
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34%/66%
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Ewing Bank 921 (North Black Widow)
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ENI
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35
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%
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1.9
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7.8
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91%/9%
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Gulf Of Mexico Shelf:
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Vermilion 380
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Mariner
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80
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%
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0.5
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33.1
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50%/50%
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Vermilion 14/26/35
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Mariner
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100
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%
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1.5
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30.1
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8%/92%
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West Cameron 110
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Mariner
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100
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%
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4.7
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29.3
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4%/96%
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South Pass 24
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Mariner
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97
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%
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1.8
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21.5
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61%/39%
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High Island 116
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|
|
Mariner
|
|
|
|
100
|
%
|
|
|
0.8
|
|
|
|
19.5
|
|
|
|
3%/97%
|
|
|
|
|
(1) |
|
NGLs are included in Oil |
6
Permian
Basin Operations
Our Permian Basin operations historically have emphasized
downspacing redevelopment activities in the prolific
oil-producing Spraberry field in the Permian Basin. Since we
began our Permian Basin redevelopment initiative in 2002, we
have increased by approximately five-fold our net acreage
position in the related fields and are targeting the Permian
Basin for continued expansion through our Permian Basin
operations headquarters in Midland, Texas. Production from
the region is primarily from the Spraberry, Dean and Wolfcamp
formations at depths between 6,000 and 10,000 feet, and is
heavily weighted toward long-lived oil and NGLs.
During 2008, our Permian Basin operations produced approximately
14.9 Bcfe (13% of our total production) and accounted for
approximately 436.6 Bcfe or 45% of our total estimated
proved reserves at year end. Oil and NGLs accounted for 73% of
total the Permian Basin production for 2008. We drilled
122 wells in the region during 2008 with a 100% success
rate. Based upon our current level of drilling activity, our
drilling inventory in this area would sustain a five-year
drilling program.
Our largest field in the Permian Basin by reserves is the
Spraberry Field, where we have been active for more than
20 years. We operate our wells in this field and hold an
average 80% working interest. This property consists of net
developed and undeveloped acres of 55,989 and 8,907,
respectively on which there were 829 wells as of
December 31, 2008 producing approximately 13.5 Bcfe
net in 2008. This field is located in the Spraberry trend and
productive zones in the field include the Spraberry, Dean and
Wolfcamp formations. At year-end 2008, our share of estimated
proved reserves attributed to this field was 419.1 Bcfe,
consisting of 69% oil and 31% natural gas.
7
Gulf
of Mexico Deepwater Operations
We have acquired and maintained a significant acreage position
in the Gulf of Mexico deepwater. We have successfully generated
and operated deepwater exploration and development projects
since 1996. As a corollary to our exploration activities, we
have pioneered sophisticated deepwater development strategies
employing extensive subsea tieback technologies that allow us to
produce our discoveries without the expense of permanent
production facilities. As of December 31, 2008, we held
interests in 95 deepwater blocks and 40 subsea wells. These
wells were tied back to 31 host production facilities for
production processing. An additional four wells were then under
development for tieback to two additional host production
facilities. Although we have interests throughout the Gulf of
Mexico, we focus much of our efforts in infrastructure-dominated
corridors where our subsea technology can be most efficiently
deployed. We feel our geological understanding based on
exploration success in these corridors gives us a competitive
advantage in assessing prospects and vying for new leases.
Production in our Gulf of Mexico deepwater operations is largely
from Pleistocene to lower Miocene aged formations and varies
between oil and gas depending on formation and age. During 2008,
our deepwater operation produced approximately 40.4 Bcfe
(34% of our total production) and accounted for approximately
198.7 Bcfe or 20% of our total estimated proved reserves at
year end. Natural gas accounted for 69% of total deepwater
production for 2008. We drilled eight wells in the region during
2008 with a 63% success rate.
We operate Atwater Valley 426, known as Bass Lite, in which in
December 2008 we increased our working interest by 11.6% to
53.8%. It is in the Pleistocene formation and is located in
approximately 6,750 feet of water. The field consists of
two development wells drilled during 2007 that are connected by
a 56-mile
subsea tieback to the Devils Tower spar. Production on
Bass Lite began in February 2008 and the field produced
8.5 Bcfe net to our interest during 2008. The project
commenced production at full capacity once the topside
facilities work was completed in August 2008. At year end 2008,
our share of estimated proved reserves attributed to this field
was 95.8 Bcfe, of which 100% are natural gas.
We operate Garden Banks 462, known as Geauxpher, in which we
hold a 60% working interest. We made this deepwater discovery in
June 2008. The well, which lies in water depths of approximately
2,700 feet, was drilled to a total depth of
23,156 feet (measured depth). At year-end 2008, our share
of estimated proved reserves attributed to the discovery was
32.7 Bcfe, consisting of 3% oil and 97% natural gas. A
two-well development is underway, with initial production
expected during the first half of 2009. Apache Corporation holds
a 40% working interest in the development.
Green Canyon 646, known as Daniel Boone, is operated by W&T
Offshore, Inc. and consists of one well in the
Pliocene/Pleistocene formation. It is located in approximately
4,200 feet of water and we have an approximate 40% working
interest in the well. The field is being developed and first
production is expected in 2009. At year end 2008, our share of
estimated proved reserves attributed to this field was
18.3 Bcfe, consisting of 68% oil and 32% natural gas.
East Breaks 558/602, known as Northwest Nansen, is operated by
Anadarko Petroleum Corp. The field, which is in the
Pliocene/Pleistocene formation, consists of four wells in
approximately 3,500 feet of water that are connected by
subsea tiebacks to the Nansen spar. We hold a 50% working
interest in the East Breaks 558 well, which was completed
as a gas well, and a 33% working interest in the three East
Breaks 602 wells, which were completed as oil wells. The
field began producing in February 2008 and the field produced
12.9 Bcfe net to our interest during 2008. At year end
2008, our share of estimated proved reserves attributed to the
field was 16.6 Bcfe, consisting of 34% oil and 66% natural
gas.
Ewing Bank 921, known as North Black Widow, is operated by ENI
Petroleum US and began producing in the Pliocene/Pleistocene
formation in 2007. We hold an approximate 35% working interest
in one well, which is located in approximately 1,700 feet
of water. Our share of net production during 2008 was
approximately 1.9 Bcfe. At year end 2008, our share of
estimated proved reserves attributed to the field was
7.8 Bcfe, consisting of 91% oil and 9% natural gas.
Gulf
of Mexico Shelf Operations
As an operator on the Gulf of Mexico shelf for a number of
years, we expanded our Gulf of Mexico shelf operations in 2006
through our acquisition of the Gulf of Mexico operations of
Forest Oil Corporation
8
(Forest) and in January 2008 through our acquisition
of an indirect subsidiary of StatoilHydro ASA that owns
substantially all of its former Gulf of Mexico shelf assets and
operations. We increased our interests in shelf operations to
335 blocks at year-end 2008 from 235 blocks at year-end 2007.
Due to our operational scale and substantial lease position on
the shelf, we are able to pursue a diverse array of exploration
and development projects on the shelf, including numerous
engineering projects designed to increase production and
reserves, as well as to manage production costs through
optimization of topside facilities and efficiencies of scale.
Drilling prospects run the gamut from relatively small,
low-risk, conventional shelf projects that can be drilled from
one of our numerous existing platform facilities, to
high-impact, deep shelf exploration prospects at depths
approaching 20,000 total vertical feet.
During 2008, our Gulf of Mexico shelf operation produced
approximately 63.1 Bcfe (53% of our total production) and
accounted for approximately 338.6 Bcfe or 35% of our total
estimated proved reserves at year end. Natural gas accounted for
76% of total shelf production for 2008. We drilled 17 wells
in the region during 2008 with an 88% success rate.
Our largest field in the Gulf of Mexico Shelf by reserves is
Vermilion 380. At year-end 2008, estimated proved reserves
attributed to this field were 33.1 Bcfe, consisting of
approximately 50% oil and 50% natural gas. During 2008, we
drilled three wells and completed one well before Hurricane Ike
damaged the platform. Hurricane Ike also interrupted the
drilling of a fourth well. Remaining development involves
finishing the drilling of the fourth well, drilling a fifth well
and completing the remaining wells. We anticipate that
production from the five new wells will commence by third
quarter 2009. The field currently has two producing wells (one
of which is the new well we drilled and completed in
2008) in 340 feet of water. These two wells produced
approximately 0.5 Bcfe in 2008. We generated this prospect
from former Forest properties and hold a 100% working interest
in the newly drilled wells.
We operate Vermilion
14/26/35,
which consists of 10 producing wells in less than 20 feet
of water. We hold a 100% working interest in this field. It has
been producing for more than 20 years from numerous
formations and in 2008 produced approximately 1.5 Bcfe net.
At year-end 2008, estimated proved reserves attributed to this
field were 30.1 Bcfe, consisting of approximately 8% oil
and 92% natural gas.
We operate our 100% working interest in West Cameron 110 which
consists of six producing wells. We operate the field, which has
been producing for more than 20 years from numerous
formations in approximately 40 feet of water and produced
approximately 4.7 Bcfe net in 2008. At year-end 2008,
estimated proved reserves attributed to this field were
29.3 Bcfe, consisting of approximately 4% oil and 96%
natural gas.
We operate South Pass 24, which consists of 25 producing wells
in approximately 10 feet of water. We have a 97% working
interest in the property. South Pass 24 has been producing for
more than 50 years from numerous formations, and in 2008
produced approximately 1.8 Bcfe net. At year-end 2008,
estimated proved reserves attributed to this field were
21.5 Bcfe, consisting of approximately 61% oil and 39%
natural gas.
We operate High Island 116, which consists of one producing well
in approximately 30 feet of water. We have a 100% working
interest in the property. It has been producing for more than
20 years and in 2008 produced approximately 0.8 Bcfe
net. At year-end 2008, estimated proved reserves attributed to
this field were 19.5 Bcfe, consisting of approximately 3%
oil and 97% natural gas.
9
The following table presents our total production volumes and
revenue, excluding the effects of hedging and other revenues, by
area for the year ended December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
Volumes
|
|
|
Revenue
|
|
|
|
|
|
|
(In thousands)
|
|
|
Permian Basin:
|
|
|
|
|
|
|
|
|
Natural Gas (Bcf)
|
|
|
4.0
|
|
|
$
|
31,339
|
|
Oil (Mbbls)
|
|
|
1,242.8
|
|
|
|
122,005
|
|
NGLs (Mbbls)
|
|
|
578.5
|
|
|
|
30,765
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas Equivalent (Bcfe)
|
|
|
14.9
|
|
|
$
|
184,109
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico Deepwater:
|
|
|
|
|
|
|
|
|
Natural Gas (Bcf)
|
|
|
27.7
|
|
|
$
|
271,979
|
|
Oil (Mbbls)
|
|
|
1,850.5
|
|
|
|
180,131
|
|
NGLs (Mbbls)
|
|
|
264.7
|
|
|
|
15,053
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas Equivalent (Bcfe)
|
|
|
40.4
|
|
|
$
|
467,163
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico Shelf:
|
|
|
|
|
|
|
|
|
Natural Gas (Bcf)
|
|
|
48.1
|
|
|
$
|
467,099
|
|
Oil (Mbbls)
|
|
|
1,787.7
|
|
|
|
190,504
|
|
NGLs (Mbbls)
|
|
|
714.7
|
|
|
|
39,897
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas Equivalent (Bcfe)
|
|
|
63.0
|
|
|
$
|
697,500
|
|
|
|
|
|
|
|
|
|
|
Total Production:
|
|
|
|
|
|
|
|
|
Natural Gas (Bcf)
|
|
|
79.8
|
|
|
$
|
770,417
|
|
Oil (Mbbls)
|
|
|
4,881.0
|
|
|
|
492,640
|
|
NGLs (Mbbls)
|
|
|
1,557.9
|
|
|
|
85,715
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas Equivalent (Bcfe)
|
|
|
118.4
|
|
|
$
|
1,348,772
|
|
|
|
|
|
|
|
|
|
|
10
Estimated
Proved Reserves
The following table presents certain information with respect to
our estimated proved oil and natural gas reserves. The reserve
information in the table below is based on estimates made in
fully-engineered reserve reports prepared by Ryder Scott
Company, L.P. Reserve volumes and values were determined under
the method prescribed by the SEC, which requires the application
of period end prices and current 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December, 31
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Estimated proved oil and natural gas reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas reserves (Bcf)
|
|
|
558.0
|
|
|
|
448.4
|
|
|
|
426.7
|
|
Oil (MMbbls)
|
|
|
43.8
|
|
|
|
41.9
|
|
|
|
32.0
|
|
Natural gas liquids (MMbbls)
|
|
|
25.5
|
|
|
|
22.6
|
|
|
|
16.1
|
|
Total proved oil and natural gas reserves (Bcfe)
|
|
|
973.9
|
|
|
|
835.8
|
|
|
|
715.5
|
|
Total proved developed reserves (Bcfe)
|
|
|
677.7
|
|
|
|
563.9
|
|
|
|
408.7
|
|
PV10 value(1) ($ in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
$
|
1,530.1
|
|
|
$
|
2,389.1
|
|
|
$
|
1,198.9
|
|
Proved undeveloped reserves
|
|
|
137.4
|
|
|
|
675.1
|
|
|
|
362.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total PV10 value(1)
|
|
$
|
1,667.5
|
|
|
$
|
3,064.2
|
|
|
$
|
1,561.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
1,483.0
|
|
|
$
|
2,231.9
|
|
|
$
|
1,239.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices used in calculating end of period proved reserve
measures (excluding effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/MMBtu)
|
|
$
|
5.71
|
|
|
$
|
6.79
|
|
|
$
|
5.62
|
|
Oil ($/bbl)
|
|
$
|
44.61
|
|
|
$
|
96.01
|
|
|
$
|
61.06
|
|
The following table sets forth certain information with respect
to our estimated proved reserves by geographic area as of
December 31, 2008 based on estimates made in a reserve
report prepared by Ryder Scott Company, L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Proved
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve Quantities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
NGLs
|
|
|
Total
|
|
|
PV10 Value(1)
|
|
|
Standardized
|
|
Geographic Area
|
|
(Bcf)
|
|
|
(MMbbls)
|
|
|
(MMbbls)
|
|
|
(Bcfe)
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
|
Measure
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions of dollars)
|
|
|
(In millions)
|
|
|
Permian Basin
|
|
|
136.2
|
|
|
|
27.3
|
|
|
|
22.7
|
|
|
|
436.6
|
|
|
|
359.3
|
|
|
|
(46.3
|
)
|
|
|
313.0
|
|
|
|
|
|
Gulf of Mexico Deepwater
|
|
|
165.9
|
|
|
|
5.4
|
|
|
|
0.1
|
|
|
|
198.7
|
|
|
|
608.5
|
|
|
|
25.2
|
|
|
|
633.7
|
|
|
|
|
|
Gulf of Mexico Shelf
|
|
|
255.9
|
|
|
|
11.1
|
|
|
|
2.7
|
|
|
|
338.6
|
|
|
|
562.3
|
|
|
|
158.5
|
|
|
|
720.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
558.0
|
|
|
|
43.8
|
|
|
|
25.5
|
|
|
|
973.9
|
|
|
|
1,530.1
|
|
|
|
137.4
|
|
|
|
1,667.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves
|
|
|
420.9
|
|
|
|
25.9
|
|
|
|
16.9
|
|
|
|
677.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,483.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
PV10 value (PV10) is not a measure under generally
accepted accounting principles in the United States of America
(GAAP) and differs from the corollary GAAP measure
standardized measure of discounted future net cash
flows in that PV10 is calculated without regard to future
income taxes. Management believes that the presentation of PV10
values is relevant and useful to our investors because it
presents the discounted future net cash flows attributable to
our estimated proved reserves independent of our individual
income tax attributes, thereby isolating the intrinsic value of
the estimated future cash flows attributable to our reserves.
Because many factors that are unique to each individual company
affect the amount of future income taxes to be paid, the use of
a pre-tax measure provides greater comparability of assets when
evaluating companies. For these reasons, management uses, and
believes the industry generally uses, |
11
|
|
|
|
|
the PV10 measure in evaluating and comparing acquisition
candidates and assessing the potential return on investment
related to investments in oil and natural gas properties. |
|
|
|
PV10 is not a measure of financial or operating performance
under GAAP, nor should it be considered in isolation or as a
substitute for the standardized measure of discounted future net
cash flows as defined under GAAP. For our presentation of the
standardized measure of discounted future net cash flows, please
see Note 16. Supplemental Oil and Gas Reserve and
Standardized Measure Information in the Notes to the
Consolidated Financial Statements in Part II, Item 8
in this Annual Report on
Form 10-K.
The table below provides a reconciliation of PV10 to
standardized measure of discounted future net cash flows. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Non-GAAP Reconciliation:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Present value of estimated future net revenues (PV10)
|
|
$
|
1,667.5
|
|
|
$
|
3,064.2
|
|
|
$
|
1,561.5
|
|
Future income taxes, discounted at 10%
|
|
|
(184.5
|
)
|
|
|
(832.3
|
)
|
|
|
(321.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
1,483.0
|
|
|
$
|
2,231.9
|
|
|
$
|
1,239.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Uncertainties are inherent in estimating quantities of proved
reserves, including many risk factors beyond our control.
Reserve engineering is a subjective process of estimating
subsurface accumulations of oil and natural gas that cannot be
measured in an exact manner, and the accuracy of any reserve
estimate is a function of the quality of available data and the
interpretation thereof. As a result, estimates by different
engineers often vary, sometimes significantly. In addition,
physical factors such as the results of drilling, testing and
production subsequent to the date of an estimate, as well as
economic factors such as change in product prices and operating
costs, may require revision of such estimates. Accordingly, oil
and natural gas quantities ultimately recovered will vary from
reserve estimates.
Productive
Wells
The following table sets forth the number of productive oil and
natural gas wells in which we owned an interest as of
December 31, 2008 and December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Oil
|
|
|
936.0
|
|
|
|
733.0
|
|
|
|
939.0
|
|
|
|
684.0
|
|
Natural Gas
|
|
|
154.0
|
|
|
|
90.2
|
|
|
|
223.0
|
|
|
|
130.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,090.0
|
|
|
|
823.2
|
|
|
|
1,162.0
|
|
|
|
814.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acreage
The following table sets forth certain information with respect
to actual developed and undeveloped acreage in which we own an
interest as of December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
Developed Acres
|
|
|
Undeveloped Acres
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Permian Basin
|
|
|
72,818
|
|
|
|
60,801
|
|
|
|
79,299
|
|
|
|
48,827
|
|
Gulf of Mexico Deepwater
|
|
|
102,560
|
|
|
|
48,618
|
|
|
|
393,120
|
|
|
|
224,275
|
|
Gulf of Mexico Shelf
|
|
|
821,250
|
|
|
|
433,384
|
|
|
|
455,153
|
|
|
|
345,204
|
|
Other Onshore
|
|
|
1,477
|
|
|
|
373
|
|
|
|
5
|
|
|
|
127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
998,105
|
|
|
|
543,176
|
|
|
|
927,577
|
|
|
|
618,433
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
The following table sets forth that portion of our onshore and
offshore undeveloped acreage as of December 31, 2008 that
is subject to expiration absent drilling activity during the
three years ended December 31, 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped Acreage
|
|
|
|
Subject to Expiration in the Year Ended December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Permian Basin
|
|
|
1,520
|
|
|
|
928
|
|
|
|
27,439
|
|
|
|
14,474
|
|
|
|
35,624
|
|
|
|
17,665
|
|
Gulf of Mexico Deepwater
|
|
|
17,280
|
|
|
|
14,112
|
|
|
|
23,040
|
|
|
|
3,456
|
|
|
|
40,320
|
|
|
|
30,960
|
|
Gulf of Mexico Shelf
|
|
|
83,526
|
|
|
|
59,646
|
|
|
|
37,665
|
|
|
|
25,364
|
|
|
|
135,087
|
|
|
|
103,508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
102,326
|
|
|
|
74,686
|
|
|
|
88,144
|
|
|
|
43,294
|
|
|
|
211,031
|
|
|
|
152,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
Activity
Certain information with regard to our drilling activity during
the years ended December 31, 2008, 2007 and 2006 is set
forth below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
17.00
|
|
|
|
10.59
|
|
|
|
11.00
|
|
|
|
5.96
|
|
|
|
14.00
|
|
|
|
5.83
|
|
Dry
|
|
|
5.00
|
|
|
|
2.98
|
|
|
|
8.00
|
|
|
|
4.91
|
|
|
|
8.00
|
|
|
|
3.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
22.00
|
|
|
|
13.57
|
|
|
|
19.00
|
|
|
|
10.87
|
|
|
|
22.00
|
|
|
|
9.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
125.00
|
|
|
|
88.93
|
|
|
|
121.00
|
|
|
|
60.43
|
|
|
|
168.00
|
|
|
|
86.23
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
125.00
|
|
|
|
88.93
|
|
|
|
121.00
|
|
|
|
60.43
|
|
|
|
168.00
|
|
|
|
86.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
142.00
|
|
|
|
99.52
|
|
|
|
132.00
|
|
|
|
66.39
|
|
|
|
182.00
|
|
|
|
92.06
|
|
Dry
|
|
|
5.00
|
|
|
|
2.98
|
|
|
|
8.00
|
|
|
|
4.91
|
|
|
|
8.00
|
|
|
|
3.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
147.00
|
|
|
|
102.5
|
|
|
|
140.00
|
|
|
|
71.30
|
|
|
|
190.00
|
|
|
|
95.71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing
and Customers
We market substantially all of the oil and natural gas
production from the properties we operate, as well as the
properties operated by others where our interest is significant.
Our natural gas, oil and condensate production is sold to a
variety of customers under short-term marketing arrangements at
market-based prices. The following table lists customers
accounting for more than 10% of our total revenues for the year
indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Total
|
|
|
|
Revenues for
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
Customer
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
BP Energy
|
|
|
5
|
%
|
|
|
9
|
%
|
|
|
14
|
%
|
ChevronTexaco and affiliates
|
|
|
16
|
%
|
|
|
23
|
%
|
|
|
23
|
%
|
Louis Dreyfus Energy
|
|
|
6
|
%
|
|
|
9
|
%
|
|
|
10
|
%
|
Plains Marketing LP
|
|
|
5
|
%
|
|
|
7
|
%
|
|
|
11
|
%
|
Shell
|
|
|
10
|
%
|
|
|
10
|
%
|
|
|
8
|
%
|
13
Title to
Properties
Substantially all of our properties currently are subject to
liens securing our bank credit facility and obligations under
hedging arrangements with lenders under our bank credit
facility. In addition, our properties are subject to customary
royalty interests, liens incident to operating agreements, liens
for current taxes and other typical burdens and encumbrances. We
do not believe that any of these burdens or encumbrances
materially interfere with the use of such properties in the
operation of our business. Our properties may also be subject to
obligations or duties under applicable laws, ordinances, rules,
regulations and orders of governmental authorities.
We believe that we have performed customary investigation of,
and have satisfactory title to or rights in, all of our
producing properties. As is customary in the oil and natural gas
industry, minimal investigation of title is made at the time of
acquisition of undeveloped properties. Title investigation is
made usually only before commencement of drilling operations. We
believe that title issues are less likely to arise with offshore
oil and natural gas properties than with onshore properties.
Competition
We believe that our leasehold acreage, exploration, drilling and
production capabilities, large
3-D seismic
database and technical and operational experience enable us to
compete effectively. However, our primary competitors include
major integrated oil and natural gas companies, nationally owned
or sponsored enterprises, and domestic independent oil and
natural gas companies. Many of our larger competitors possess
and employ financial and personnel resources substantially
greater than those available to us. Such companies may be able
to pay more for productive oil and natural gas properties and
exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than our
financial or personnel resources permit. Our ability to acquire
additional prospects and discover reserves in the future is
dependent upon our ability to evaluate and select suitable
properties and consummate transactions in a highly competitive
environment. In addition, there is substantial competition for
capital available for investment in the oil and natural gas
industry. 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.
Royalty
Relief
The Outer Continental Shelf Deep Water Royalty Relief Act
(RRA), effective November 28, 1995, provides
that all tracts in the Western and Central Planning Areas of the
Gulf of Mexico, including whole lease blocks in the Eastern
Planning Area of the Gulf of Mexico lying west of 87 degrees, 30
minutes West longitude, in water more than 200 meters deep and
offered for bid within five years after the effective date of
the RRA, will be entitled to royalty relief as follows:
|
|
|
Water Depth
|
|
Royalty Relief
|
|
200-400
meters
|
|
no royalty payable on the first 17.5 million BOE produced
|
400-800
meters
|
|
no royalty payable on the first 52.5 million BOE produced
|
800 meters or deeper
|
|
no royalty payable on the first 87.5 million BOE produced
|
Leases offered for bid within five years after the effective
date of the RRA are referred to as post-Act leases.
The RRA also allows federal offshore lessees the opportunity to
apply for discretionary royalty relief for new production on
leases acquired before the RRA was enacted, or pre-Act
leases. If the MMS determines that new production under a
pre-Act lease would not be economic without royalty relief, then
the MMS may relieve a portion of the royalty to make the project
economic.
In addition to granting discretionary royalty relief, the MMS
has elected to include royalty relief provisions in many leases
issued after November 28, 2000, or post-2000
leases. For these post-2000 lease sales that have occurred
to-date for which the MMS has elected to include royalty relief,
the MMS has specified the water depth categories and royalty
suspension volumes applicable to production from leases issued
in the sale.
In 2004, the MMS adopted additional royalty relief incentives
for production of natural gas from reservoirs located deep under
shallow waters of the Gulf of Mexico. These incentives apply to
natural gas
14
produced in water depths of less than 200 meters and from deep
natural gas accumulations of at least 15,000 feet of true
vertical depth. Drilling of qualified wells must have started on
or after March 26, 2003, and production must begin before
May 3, 2009, unless the lessee obtains a one-year
extension. These incentives generally apply only to production
that occurs during years when the average price of natural gas
on the New York Mercantile Exchange does not exceed the price
threshold of $10.15 per million Btu, expressed in 2007 dollars.
In regulations published in November 2008, the MMS implemented
additional royalty relief provisions to reflect statutory
changes enacted in the Energy Policy Act of 2005. The
regulations provide enhanced incentives for gas production from
wells of at least 20,000 feet of true vertical depth in
waters of 400 meters or less. These regulations also expand the
royalty relief incentives for natural gas produced from leases
in waters 200 to 400 meters deep by entitling such leases to the
royalty relief incentives available under the existing
regulations for leases in less than 200 meters of water, with
two exceptions. First, the incentive for production in waters
200 to 400 meters in depth applies to wells for which drilling
began on or after May 18, 2007, rather than March 26,
2003, and that begin production before May 3, 2013, rather
than May 3, 2009. Second, the applicable price threshold is
$4.55 per million Btu, expressed in 2007 dollars, rather than
$10.15.
The impact of royalty relief can be significant. Effective with
lease sales in 2008, royalty rates for leases in all water
depths in the Gulf of Mexico increased to 18.75% of production.
For Gulf of Mexico leases awarded in 2007 lease sales, the
royalty rate was 16.7% of production in all water depths.
Royalty relief can substantially improve the economics of
projects located in deepwater or in shallow water involving deep
natural gas.
Many of our MMS leases that are subject to royalty relief
contain language that suspends royalty relief if commodity
prices exceed predetermined threshold levels for a given
calendar year. As a result, royalty relief for a lease in a
particular calendar year may be contingent upon average
commodity prices remaining below the price threshold specified
for that year. Since 2000, commodity prices have exceeded some
of the predetermined price thresholds, except in 2002, for a
number of our projects. For the affected leases, we have been
ordered by the MMS to pay royalties for natural gas produced in
some of those years. However, we have challenged the MMSs
authority to include price thresholds in six of our post-Act
leases awarded in 1996 and 1997. We believe that post-Act leases
are entitled to automatic royalty relief under the RRA,
regardless of commodity prices, and have pursued administrative
and judicial remedies in this dispute with the MMS. For more
information concerning the contested royalty payments and the
MMSs demands, see Item 3. Legal
Proceedings.
Regulation
Our operations are subject to extensive and continually changing
regulation affecting the oil and natural gas industry. Many
departments and agencies, both federal and state, are authorized
by statute to issue, and have issued, rules and regulations
binding on the oil and natural gas industry and its individual
participants. The failure to comply with such rules and
regulations can result in substantial penalties. The regulatory
burden on the oil and natural gas industry increases our cost of
doing business and, consequently, affects our profitability. We
do not believe that we are affected in a significantly different
manner by these regulations than are our competitors.
Transportation
and Sale of Natural Gas
Historically, the transportation and sale for resale of natural
gas in interstate commerce have been regulated pursuant to the
Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and
the regulations promulgated thereunder by the Federal Energy
Regulatory Commission, or FERC. In the past, the federal
government has regulated the prices at which natural gas could
be sold. Deregulation of natural gas sales by producers began
with the enactment of the Natural Gas Policy Act of 1978. In
1989, Congress enacted the Natural Gas Wellhead Decontrol Act,
which removed all remaining Natural Gas Act of 1938 and Natural
Gas Policy Act of 1978 price and non-price controls affecting
producer sales of natural gas effective January 1, 1993.
Congress could, however, re-enact price controls in the future.
The FERC regulates interstate natural gas pipeline
transportation rates and service conditions, which affect the
marketing of gas produced by us and the revenues received by us
for sales of such natural gas. The FERC requires interstate
pipelines to provide open-
15
access transportation on a non-discriminatory basis for all
natural gas shippers. The FERC frequently reviews and modifies
its regulations regarding the transportation of natural gas with
the stated goal of fostering competition within all phases of
the natural gas industry. In addition, with respect to
production onshore or in state waters, the intra-state
transportation of natural gas would be subject to state
regulatory jurisdiction as well.
In August, 2005, Congress enacted the Energy Policy Act of 2005,
or EP Act 2005. Among other matters, EP Act 2005 amends the
Natural Gas Act, or NGA, to make it unlawful for any
entity, including otherwise non-jurisdictional producers
such as Mariner, to use any deceptive or manipulative device or
contrivance in connection with the purchase or sale of natural
gas or the purchase or sale of transportation services subject
to regulation by the FERC, in contravention of rules prescribed
by the FERC. On January 19, 2006, the FERC issued
regulations implementing this provision. The regulations make it
unlawful in connection with the purchase or sale of natural gas
subject to the jurisdiction of the FERC, or the purchase or sale
of transportation services subject to the jurisdiction of the
FERC, for any entity, directly or indirectly, to use or employ
any device, scheme or artifice to defraud; to make any untrue
statement of material fact or omit to make any such statement
necessary to make the statements made not misleading; or to
engage in any act or practice that operates as a fraud or deceit
upon any person. EP Act 2005 also gives the FERC authority to
impose civil penalties for violations of the NGA up to
$1,000,000 per day per violation. The new anti-manipulation rule
does not apply to activities that relate only to intrastate or
other non-jurisdictional sales or gathering, but does apply to
activities of otherwise non-jurisdictional entities to the
extent the activities are conducted in connection
with gas sales, purchases or transportation subject to
FERC jurisdiction. It therefore reflects a significant expansion
of the FERCs enforcement authority. We do not anticipate
we will be affected any differently than other producers of
natural gas.
Additional proposals and proceedings that might affect the
natural gas industry are considered from time to time by
Congress, the FERC, state regulatory bodies and the courts. We
cannot predict when or if any such proposals might become
effective or their effect, if any, on our operations. The
natural gas industry historically has been closely regulated;
thus, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue
indefinitely into the future.
Regulation
of Production
The production of oil and natural gas is subject to regulation
under a wide range of state and federal statutes, rules, orders
and regulations. State and federal statutes and regulations
require permits for drilling operations, drilling bonds, and
reports concerning operations. Texas and Louisiana, the states
in which we own and operate properties, have regulations
governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from oil and
natural gas wells, the spacing of wells, and the plugging and
abandonment of wells and removal of related production
equipment. Texas and Louisiana also restrict production to the
market demand for oil and natural gas and several states have
indicated interests in revising applicable regulations. These
regulations can limit the amount of oil and natural gas we can
produce from our wells, limit the number of wells, or limit the
locations at which we can conduct drilling operations. Moreover,
each state generally imposes a production or severance tax with
respect to production and sale of crude oil, natural gas and gas
liquids within its jurisdiction.
Most of our offshore operations are conducted on federal leases
that are administered by the MMS. Such leases require compliance
with detailed MMS regulations and orders pursuant to the Outer
Continental Shelf Lands Act that are subject to interpretation
and change by the MMS. Among other things, we are required to
obtain prior MMS approval for our exploration plans and
development and production plans at each lease. MMS regulations
also impose construction requirements for production facilities
located on federal offshore leases, as well as detailed
technical requirements for plugging and abandonment of wells,
and removal of platforms and other production facilities on such
leases. The MMS requires lessees to post surety bonds, or
provide other acceptable financial assurances, to ensure all
obligations are satisfied on federal offshore leases. The cost
of these surety bonds or other financial assurances can be
substantial, and there is no assurance that bonds or other
financial assurances can be obtained in all cases. We are
currently in compliance with all MMS financial assurance
requirements. Under certain circumstances, the MMS is authorized
to suspend or terminate
16
operations on federal offshore leases. Any suspension or
termination of operations on our offshore leases could have an
adverse effect on our financial condition and results of
operations.
Our crude oil and gas production is subject to royalty interests
established under the applicable leases. Royalty on production
from state and private leases is generally governed by state law
and royalty on production from leases on federal or Indian lands
is governed by federal law. The MMS is authorized by statute to
administer royalty valuation and collection for production from
federal and Indian leases. The MMS generally exercises this
authority through standards established under its regulations
and related policies. We do not anticipate that we will be
affected by changes in federal or state law affecting royalty
obligations any differently than other producers of crude oil
and natural gas.
Environmental
and Safety Regulations
Our operations are subject to numerous stringent and complex
laws and regulations at the federal, state and local levels
governing the discharge of materials into the environment or
otherwise relating to human health and environmental protection.
These laws and regulations may, among other things:
|
|
|
|
|
require acquisition of a permit before drilling commences;
|
|
|
|
restrict the types, quantities and concentrations of various
materials that can be released into the environment in
connection with drilling and production activities; and
|
|
|
|
limit or prohibit construction or drilling activities in certain
ecologically sensitive and other protected areas.
|
Failure to comply with these laws and regulations or to obtain
or comply with permits may result in the assessment of
administrative, civil and criminal penalties, imposition of
remedial requirements and the imposition of injunctions to force
future compliance. Offshore drilling in some areas has been
opposed by environmental groups and, in some areas, has been
restricted. Our business and prospects could be adversely
affected to the extent laws are enacted or other governmental
action is taken that prohibits or restricts our exploration and
production activities or imposes environmental protection
requirements that result in increased costs to us or the oil and
natural gas industry in general.
The following is a summary of some of the existing laws and
regulations to which our business operations are subject:
Spills and Releases. The Comprehensive
Environmental Response, Compensation, and Liability Act
(CERCLA), and analogous state laws, impose joint and
several liability, without regard to fault or the legality of
the original act, on certain classes of persons that contributed
to the release of a hazardous substance into the
environment. These persons include the owner and
operator of the site where the release occurred,
past owners and operators of the site, and companies that
disposed or arranged for the disposal of the hazardous
substances found at the site. Responsible parties under CERCLA
may be liable for the costs of cleaning up hazardous substances
that have been released into the environment and for damages to
natural resources. Additionally, it is not uncommon for
neighboring landowners and other third parties to file tort
claims for personal injury and property damage allegedly caused
by the release of hazardous substances into the environment. In
the course of our ordinary operations, we may generate waste
that may fall within CERCLAs definition of a
hazardous substance.
We currently own, lease or operate, and have in the past owned,
leased or operated, numerous properties that for many years have
been used for the exploration and production of oil and gas.
Many of these properties have been operated by third parties
whose actions with respect to the treatment and disposal or
release of hydrocarbons or other wastes were not under our
control. It is possible that hydrocarbons or other wastes may
have been disposed of or released on or under such properties,
or on or under other locations where such wastes may have been
taken for disposal. These properties and wastes disposed thereon
may be subject to CERCLA and analogous state laws. Under such
laws, we could be required to remove or remediate previously
disposed wastes (including wastes disposed of or released by
prior owners or operators), to clean up contaminated property
(including contaminated groundwater) or to perform remedial
plugging operations to prevent future contamination, or to pay
the costs of such remedial measures. Although we believe we have
utilized operating and disposal practices that are standard in
the industry, during the course of operations
17
hydrocarbons and other wastes may have been released on some of
the properties we own, lease or operate. We are not presently
aware of any pending
clean-up
obligations that could have a material impact on our operations
or financial condition.
The Oil Pollution Act (OPA). The
OPA and regulations thereunder impose strict, joint and several
liability on responsible parties for damages,
including natural resource damages, resulting from oil spills
into or upon navigable waters, adjoining shorelines or in the
exclusive economic zone of the United States. A
responsible party includes the owner or operator of
an onshore facility and the lessee or permittee of the area in
which an offshore facility is located. The OPA establishes a
liability limit for onshore facilities of $350 million,
while the liability limit for offshore facilities is equal to
all removal costs plus up to $75 million in other damages.
These liability limits may not apply if a spill is caused by a
partys gross negligence or willful misconduct, the spill
resulted from violation of a federal safety, construction or
operating regulation, or if a party fails to report a spill or
to cooperate fully in a
clean-up.
The OPA also requires the lessee or permittee of an offshore
area in which a covered offshore facility is located to provide
financial assurance in the amount of $35 million to cover
liabilities related to an oil spill. The amount of financial
assurance required under the OPA may be increased up to
$150 million depending on the risk represented by the
quantity or quality of oil that is handled by a facility. The
failure to comply with the OPAs requirements may subject a
responsible party to civil, criminal, or administrative
enforcement actions. We are not aware of any action or event
that would subject us to liability under the OPA, and we believe
that compliance with the OPAs financial assurance and
other operating requirements will not have a material impact on
our operations or financial condition.
Water Discharges. The Federal Water Pollution
Control Act of 1972, also known as the Clean Water Act, imposes
restrictions and controls on the discharge of produced waters
and other oil and gas pollutants into navigable waters. These
controls have become more stringent over the years, and it is
possible that additional restrictions may be imposed in the
future. Permits must be obtained to discharge pollutants into
state and federal waters. Certain state regulations and the
general permits issued under the Federal National Pollutant
Discharge Elimination System, or NPDES, program prohibit the
discharge of produced waters and sand, drilling fluids, drill
cuttings and certain other substances related to the oil and gas
industry into certain coastal and offshore waters. The Clean
Water Act provides for civil, criminal and administrative
penalties for unauthorized discharges of oil and other
pollutants, and imposes liability on parties responsible for
those discharges for the costs of cleaning up any environmental
damage caused by the release and for natural resource damages
resulting from the release. Comparable state statutes impose
liabilities and authorize penalties in the case of an
unauthorized discharge of petroleum or its derivatives, or other
pollutants, into state waters.
In furtherance of the Clean Water Act, the Environmental
Protection Agency (EPA) promulgated the Spill
Prevention, Control, and Countermeasure (SPCC)
regulations, which require facilities that possess certain
threshold quantities of oil that could impact navigable waters
or adjoining shorelines to prepare SPCC plans and meet specified
construction and operating standards. The SPCC regulations were
revised in 2002 and required the amendment of SPCC plans before
February 18, 2006, if necessary, and required compliance
with the implementation of such amended plans by August 18,
2006. This compliance deadline has been extended multiple times
and on May 16, 2007 was extended until July 1, 2009.
We have SPCC plans and similar contingency plans in place at
several of our facilities, and may be required to prepare such
plans for additional facilities where a spill or release of oil
could reach or impact jurisdictional waters of the United
States. We do not anticipate that the revisions to the SPCC
regulations will cause a material impact on our operations or
financial condition.
Air Emissions. The Federal Clean Air Act and
associated state laws and regulations restrict the emission of
air pollutants from many sources, including oil and natural gas
operations. New facilities may be required to obtain permits
before operations can commence, and existing facilities may be
required to obtain additional permits and incur capital costs in
order to remain in compliance. Federal and state regulatory
agencies can impose administrative, civil and criminal penalties
for non-compliance with air permits or other requirements of the
Clean Air Act and associated state laws and regulations. We
believe that compliance with the Clean Air
18
Act and analogous state laws and regulations will not have a
material impact on our operations or financial condition.
Recent scientific studies have suggested that emissions of
certain gases, commonly referred to as greenhouse
gases and including carbon dioxide and methane, may be
contributing to warming of the Earths atmosphere. In
response to such studies, the U.S. Congress is actively
considering legislation to reduce emissions of greenhouse gases.
In addition, at least 17 states have declined to wait for
Congress to develop and implement climate control legislation
and have already taken legal measures to reduce emissions of
greenhouse gases. Also, as a result of the U.S. Supreme
Courts decision on April 2, 2007 in Massachusetts,
et al. v. EPA, the EPA must consider whether it is
required to regulate greenhouse gas emissions from mobile
sources (e.g., cars and trucks) even if Congress does not adopt
new legislation specifically addressing emissions of greenhouse
gases. The Courts holding in Massachusetts that
greenhouse gases fall under the Federal Clean Air Acts
definition of air pollutant may also result in
future regulation of greenhouse gas emissions from stationary
sources under various Clean Air Act programs, including those
that may be used in our operations. It is not possible at this
time to predict how legislation that may be enacted to address
greenhouse gas emissions would impact our business. However,
future laws and regulations could result in increased compliance
costs or additional operating restrictions, and could have a
material adverse effect on our business, financial condition,
demand for our operations, results of operations, and cash flows.
Waste Handling. The Resource Conservation and
Recovery Act (RCRA), and analogous state and local
laws and regulations govern the management of wastes, including
the treatment, storage and disposal of hazardous wastes. RCRA
imposes stringent operating requirements, and liability for
failure to meet such requirements, on a person who is either a
generator or transporter of hazardous
waste or an owner or operator of a
hazardous waste treatment, storage or disposal facility. RCRA
specifically excludes from the definition of hazardous waste
drilling fluids, produced waters, and other wastes associated
with the exploration, development, or production of crude oil
and natural gas. A similar exemption is contained in many of the
state counterparts to RCRA. As a result, we are not required to
comply with a substantial portion of RCRAs requirements
because our operations generate minimal quantities of hazardous
wastes. However, these wastes may be regulated by EPA or state
agencies as solid waste. In addition, ordinary industrial
wastes, such as paint wastes, waste solvents, laboratory wastes,
and waste compressor oils, may be regulated under RCRA as
hazardous waste. We do not believe the current costs of managing
our wastes, as they are presently classified, to be significant.
However, any repeal or modification of the oil and natural gas
exploration and production exemption, or modifications of
similar exemptions in analogous state statutes, would increase
the volume of hazardous waste we are required to manage and
dispose of and would cause us, as well as our competitors, to
incur increased operating expenses.
Endangered Species Act. The Endangered Species
Act, or ESA, restricts activities that may affect endangered or
threatened species or their habitats. We believe that we are in
substantial compliance with the ESA. However, the designation of
previously unidentified endangered or threatened species could
cause us to incur additional costs or become subject to
operating restrictions or bans in the affected areas.
Safety. The Occupational Safety and Health
Act, or OSHA, and other similar laws and regulations govern the
protection of the health and safety of employees. The OSHA
hazard communication standard, EPA community right-to-know
regulations under Title III of CERCLA and analogous state
statutes require that information be maintained about hazardous
materials used or produced in our operations and that this
information be provided to employees, state and local
governments and citizens. We believe that we are in substantial
compliance with these requirements and with other applicable
OSHA requirements.
Employees
As of December 31, 2008, we had 276 full-time
employees. Our employees are not represented by any labor
unions. We have never experienced a work stoppage or strike and
we consider relations with our employees to be satisfactory.
Insurance
Matters
Mariner is a member of OIL Insurance, Ltd. (OIL), an
energy industry insurance cooperative, which provides our
primary layer of physical damage and windstorm insurance
coverage. Our coverage is subject to
19
a $10.0 million per-occurrence deductible for our assets
and a $250.0 million per-occurrence loss limit. However, if
a single event causes losses to all OIL-insured assets in excess
of $750.0 million, amounts covered for such losses will be
reduced on a pro-rata basis among OIL members.
In addition to our primary coverage through OIL, we also
maintain commercial difference in conditions
insurance that would apply (with no additional deductible) once
our limits with OIL are exhausted, as well as partial business
interruption insurance covering certain of our significant
producing fields and certain other fields situated in hurricane
prone areas. Our business interruption coverage begins to
provide benefits after a
60-day
waiting period once the designated field is shut-in due to a
covered event and is limited to 35% of the forecast cash flow
from each designated property. Our commercial policy expires
annually on June 1, and is subject to a general limit of
$100.0 million per occurrence and in the case of named
windstorms, a combined annual aggregate limit of
$100.0 million covering both property damage and business
interruption.
In 2008, our operations were adversely affected by Hurricane
Ike. The hurricane resulted in shut-in and delayed production as
well as facility repairs and replacement expenses. We are
evaluating the nature and extent of damage resulting from the
hurricane. With respect to Hurricane Ike, our OIL coverage has a
$10.0 million per occurrence deductible and a
$250.0 million per occurrence limit, subject to an
industry-wide loss limit per occurrence of $750.0 million.
To the extent that aggregate claims exceed the OIL industry-wide
loss limit per occurrence, we expect our insurance recovery
would be reduced pro-rata with all other competing claims from
Hurricane Ike and the shortfall covered by our commercial excess
insurance, subject to policy limits.
Applicable insurance for our Hurricane Katrina and Rita claims
with respect to the Gulf of Mexico assets previously acquired
from Forest is provided by OIL. Our coverage for the former
Forest properties is subject to a deductible of
$5.0 million per occurrence and a $1.0 billion
industry-wide loss limit per occurrence. OIL has advised us that
the aggregate claims resulting from each of Hurricanes Katrina
and Rita are expected to exceed the $1.0 billion per
occurrence loss limit and that therefore, our insurance recovery
is expected to be reduced pro-rata with all other competing
claims from the storms. During 2008, we settled our Katrina and
Rita claims with our excess insurance providers for a one-time
payment of $48.5 million. The insurance coverage for
Mariners legacy properties is subject to a
$3.75 million deductible. See Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations Liquidity and Capital
Resources for more information.
Glossary
of Oil and Natural Gas Terms
The following is a description of the meanings of some of the
oil and natural gas industry terms used in this annual report.
The definitions of proved developed reserves, proved reserves
and proved undeveloped reserves have been abbreviated from the
applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definitions of those terms can be viewed on the
website at
http://www.sec.gov/about/forms/forms-x.pdf.
Effective for annual reports on
Forms 10-K
for years ending on or after December 31, 2009, certain
definitions contained in
Rule 4-10(a)
will be revised to reflect the SECs adoption of its final
rule on the Modernization of Oil and Gas Reporting. See
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations Recent
Accounting Pronouncements for more information.
3-D
seismic data. (Three-Dimensional Seismic Data)
Geophysical data that depicts the subsurface strata in three
dimensions.
3-D seismic
data typically provides a more detailed and accurate
interpretation of the subsurface strata than two dimensional
seismic data.
Appraisal well. A well drilled several spacing
locations away from a producing well to determine the boundaries
or extent of a productive formation and to establish the
existence of additional reserves.
Bbl. One stock tank barrel, or 42
U.S. gallons liquid volume, of crude oil or other liquid
hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent,
determined using the ratio of six Mcf of natural gas to one bbl
of crude oil, condensate or natural gas liquids.
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Block. A block depicted on the Outer
Continental Shelf Leasing and Official Protraction Diagrams
issued by the MMS or a similar depiction on official protraction
or similar diagrams issued by a state bordering on the Gulf of
Mexico.
Boe. Barrels of oil equivalent, with six
thousand cubic feet of natural gas being equivalent to one
barrel of oil.
Btu or British Thermal Unit. The quantity of
heat required to raise the temperature of one pound of water by
one degree Fahrenheit.
Completion. The installation of permanent
equipment for the production of oil or natural gas, or in the
case of a dry hole, the reporting of abandonment to the
appropriate agency.
Condensate. Liquid hydrocarbons associated
with the production of a primarily natural gas reserve.
Conventional shelf well. A well drilled on the
outer continental shelf to subsurface depths above
15,000 feet.
Deep shelf well. A well drilled on the outer
continental shelf to subsurface depths below 15,000 feet.
Deepwater. Depths greater than 1,300 feet
(the approximate depth of deepwater designation by the MMS).
Developed acreage. The number of acres that
are allocated or assignable to productive wells or wells capable
of production.
Development costs. Costs incurred to obtain
access to proved reserves and to provide facilities for
extracting, treating, gathering and storing the oil and gas.
This definition of development costs has been abbreviated from
the applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definition of this term can be viewed on the website
at
http://www.sec.gov/about/forms/forms-x.pdf.
Development well. A well drilled within the
proved boundaries of an oil or natural gas reservoir with the
intention of completing the stratigraphic horizon known to be
productive.
Differential. An adjustment to the price of
oil or gas from an established spot market price to reflect
differences in the quality
and/or
location of oil or gas.
Dry hole. A well found to be incapable of
producing hydrocarbons in sufficient quantities such that
proceeds from the sale of such production exceed production
expenses and taxes.
Dry hole costs. Costs incurred in drilling a
well, assuming a well is not successful, including plugging and
abandonment costs.
Exploitation. Ordinarily considered to be a
form of development within a known reservoir.
Exploration costs. Costs incurred in
identifying areas that may warrant examination and in examining
specific areas that are considered to have prospects of
containing oil and gas reserves, including costs of drilling
exploratory wells. This definition of exploratory costs has been
abbreviated from the applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definition of this term can be viewed on the website
at
http://www.sec.gov/about/forms/forms-x.pdf.
Exploratory well. A well drilled to find and
produce oil or gas reserves not classified as proved, to find a
new reservoir in a field previously found to be productive of
oil or gas in another reservoir or to extend a known reservoir.
Farm-in or farm-out. An agreement under which
the owner of a working interest in an oil or gas lease assigns
the working interest or a portion of the working interest to
another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells
in order to earn its interest in the acreage. The assignor
usually retains a royalty or reversionary interest in the lease.
The interest received by an assignee is a farm-in
while the interest transferred by the assignor is a
farm-out.
Field. An area consisting of either a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
Gas. Natural gas.
21
Gross acres or gross wells. The total acres or
wells, as the case may be, in which a working interest is owned.
Lease operating expenses. The expenses of
lifting oil or gas from a producing formation to the surface,
and the transportation and marketing thereof, constituting part
of the current operating expenses of a working interest, and
also including labor, superintendence, supplies, repairs,
short-lived assets, maintenance, allocated overhead costs, ad
valorem taxes and other expenses incidental to production, but
not including lease acquisition or drilling or completion
expenses.
Mbbls. Thousand barrels of crude oil or other
liquid hydrocarbons.
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent,
determined using the ratio of six Mcf of natural gas to one bbl
of crude oil, condensate or natural gas liquids.
MMBls. Million barrels of crude oil or other
liquid hydrocarbons.
MMBtu. Million British Thermal Units.
MMcf. Million cubic feet of natural gas.
MMcfe. Million cubic feet equivalent,
determined using the ratio of six Mcf of natural gas to one bbl
of crude oil, condensate or natural gas liquids.
MMS. Minerals Management Service of the United
States Department of the Interior.
Net acres or net wells. The sum of the
fractional working interests owned in gross acres or wells.
Net revenue interest. An interest in all oil
and natural gas produced and saved from, or attributable to, a
particular property, net of all royalties, overriding royalties,
net profits interests, carried interests, reversionary interests
and any other burdens to which the persons interest is
subject.
Operator. The individual or company
responsible for the exploration
and/or
exploitation
and/or
production of an oil or gas well or lease.
Payout. Generally refers to the recovery by
the incurring party to an agreement of its costs of drilling,
completing, equipping and operating a well before another
partys participation in the benefits of the well commences
or is increased to a new level.
Plugging and abandonment. Refers to the
sealing off of fluids in the strata penetrated by a well so that
the fluids from one stratum will not escape into another or to
the surface. Regulations of many states require plugging of
abandoned wells.
PV10 or present value of estimated future net
revenues. An estimate of the present value of the
estimated future net revenues from proved oil and gas reserves
at a date indicated after deducting estimated production and ad
valorem taxes, future capital costs and operating expenses, but
before deducting any estimates of federal income taxes. The
estimated future net revenues are discounted at an annual rate
of 10%, in accordance with the SECs practice, to determine
their present value. The present value is shown to
indicate the effect of time on the value of the revenue stream
and should not be construed as being the fair market value of
the properties. Estimates of future net revenues are made using
oil and natural gas prices and operating costs at the date
indicated and held constant for the life of the reserves.
Productive well. A well that is found to be
capable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production exceed production
expenses and taxes.
Prospect. A specific geographic area, which
based on supporting geological, geophysical or other data and
also preliminary economic analysis using reasonably anticipated
prices and costs, is deemed to have potential for the discovery
of commercial hydrocarbons.
Proved developed non-producing
reserves. Proved developed reserves expected to
be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved
developed reserves that are expected to be recovered from
completion intervals currently open in existing wells and
capable of production to market.
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Proved developed reserves. Proved reserves
that can be expected to be recovered from existing wells with
existing equipment and operating methods. This definition of
proved developed reserves has been abbreviated from the
applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definition of this term can be viewed on the website
at
http://www.sec.gov/about/forms/forms-x.pdf.
Proved reserves. The estimated quantities of
crude oil, natural gas and natural gas liquids that geological
and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions. This definition of proved
reserves has been abbreviated from the applicable definitions
contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire definition of this term can be viewed on the website
at
http://www.sec.gov/about/forms/forms-x.pdf.
Proved undeveloped reserves. Proved reserves
that are expected to be recovered from new wells on undrilled
acreage or from existing wells where a relatively major
expenditure is required for recompletion. This definition of
proved undeveloped reserves has been abbreviated from the
applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
The entire term definition can be viewed at website
http://www.sec.gov/about/forms/forms-x.pdf.
Recompletion. The completion for production in
an existing well bore to another formation from that which the
well has been previously completed.
Reservoir. A porous and permeable underground
formation containing a natural accumulation of producible oil
and/or gas
that is confined by impermeable rock or water barriers and is
individual and separate from other reservoirs.
Shelf. Areas in the Gulf of Mexico with depths
less than 1,300 feet. Our shelf area and operations also
includes a small amount of properties and operations in the
onshore and bay areas of the Gulf Coast.
Subsea tieback. A method of completing a
productive well by connecting its wellhead equipment located on
the sea floor by means of control umbilical and flow lines to an
existing production platform located in the vicinity.
Subsea trees. Wellhead equipment installed on
the ocean floor.
Standardized measure of discounted future net cash
flows. The standardized measure represents
value-based information about an enterprises proved oil
and gas reserves based on estimates of future cash flows,
including income taxes, from production of proved reserves
assuming continuation of year-end economic and operating
conditions.
Undeveloped acreage. Lease acreage on which
wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil or gas
regardless of whether or not such acreage contains proved
reserves.
Working interest. The operating interest that
gives the owner the right to drill, produce and conduct
operating activities on the property and receive a share of
production.
Risks
Relating to the Oil and Natural Gas Industry and to Our
Business
The
recent worldwide financial and credit crisis could lead to an
extended worldwide economic recession and have a material
adverse effect on our results of operations and
liquidity.
The recent worldwide financial and credit crisis has reduced the
availability of liquidity and credit to fund the continuation
and expansion of industrial business operations worldwide. The
shortage of liquidity and credit combined with recent
substantial losses in worldwide equity markets could lead to an
extended worldwide economic recession. A recession or slowdown
in economic activity would likely reduce worldwide demand for
energy and result in lower oil and natural gas prices, which
could materially adversely affect our profitability and results
of operations.
In addition, the economic crisis may adversely affect our
liquidity. We may be unable to obtain adequate funding under our
bank credit facility because our lending counterparties may be
unwilling or unable to meet their funding obligations, or
because our borrowing base under the facility may be decreased
as the result of a redetermination, reducing it due to lower oil
or natural gas prices, operating difficulties, declines in
reserves or
23
other reasons. If funding is not available as needed, or is
available only on unfavorable terms, we may be unable to meet
our obligations as they come due or we may be unable to
implement our business strategies or otherwise take advantage of
business opportunities or respond to competitive pressures.
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 increased to,
and then declined significantly from, historical highs in 2008
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:
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domestic and foreign supply of oil and natural gas;
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price and quantity of foreign imports;
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actions of the Organization of Petroleum Exporting Countries and
other state-controlled oil companies relating to oil price and
production controls;
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level of consumer product demand;
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domestic and foreign governmental regulations;
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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;
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weather conditions;
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technological advances affecting oil and natural gas consumption;
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overall U.S. and global economic conditions; and
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price and availability of alternative fuels.
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Further, oil prices and natural gas prices do not necessarily
fluctuate in direct relationship to each other. To the extent
that oil or natural gas comprises more than 50% of our
production or estimated proved reserves, our financial results
may be more sensitive to movements in prices of that commodity.
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. See
Item 1. Business Estimated Proved
Reserves. In addition, we may, from time to time, enter
into long-term contracts based upon our reasoned expectations
for commodity price levels. If commodity prices subsequently
decrease significantly for a sustained period, we may be unable
to perform our obligations or otherwise breach the contract and
be liable for damages.
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 other factors, many of
24
which are beyond our control. At December 31, 2008,
approximately 30% of our estimated proved reserves were proved
undeveloped.
If the interpretations or assumptions we use in arriving at our
estimates prove to be inaccurate, the amount of oil and natural
gas that we ultimately recover may differ materially from the
estimated quantities and net present value of reserves shown in
this report. See Item 1. Business
Estimated Proved Reserves for information about our oil
and gas reserves.
In
estimating future net revenues from estimated 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 estimated
proved reserves referred to in this report 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 estimated
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.
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 estimated 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 SEC 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 natural 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. At December 31, 2008, the net capitalized cost of
our proved oil and gas properties exceeded the ceiling limit and
we recorded a non-cash ceiling test impairment of
$575.6 million during the fourth quarter. Refer to
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations
Critical Accounting Policies and Estimates Oil and
Gas Properties, and Note 1. Summary of
Significant Accounting Policies in the Notes to the
Consolidated Financial Statements in Part II, Item 8
of this Annual Report on
Form 10-K
for a discussion of our use of the full cost method of
accounting for our oil and gas properties and its impact at
December 31, 2008. We may incur other 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
estimated 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. 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 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
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current and future production, our production rates will decline
even if we drill the undeveloped locations that were included in
our estimated 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
50% of our total estimated proved reserves are either developed
non-producing or undeveloped and those reserves may not
ultimately be produced or developed.
As of December 31, 2008, approximately 20% of our total
estimated proved reserves were developed non-producing and
approximately 30% were undeveloped. 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 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:
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unexpected drilling conditions;
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pressure or irregularities in formations;
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equipment failures or accidents;
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adverse weather conditions, including hurricanes, which are
common in the Gulf of Mexico during certain times of the year;
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compliance with governmental regulations;
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unavailability or high cost of drilling rigs, equipment or labor;
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reductions in oil and natural gas prices; and
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limitations in the market for oil and natural gas.
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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 techniques only assist geoscientists and
geologists in identifying subsurface structures and hydrocarbon
indicators.
3-D seismic
data do 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 may 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.
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Oil
and gas drilling and production involve many business and
operating risks, any one of which could reduce our levels of
production, cause substantial losses or prevent us from
realizing profits.
Our business is subject to all of the operating risks associated
with drilling for and producing oil and natural gas, including:
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fires;
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explosions;
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blow-outs and surface cratering;
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uncontrollable flows of underground natural gas, oil and
formation water;
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natural events and natural disasters, such as loop currents, and
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 natural 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.
Exploration for oil or natural gas in the Gulf of Mexico
deepwater 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. Moreover, deepwater projects
often lack proximity to the physical and oilfield service
infrastructure present in the shallow waters of the Gulf of
Mexico, necessitating significant capital investment in subsea
flow line infrastructure. Subsea tieback production systems
require 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. As a result, a significant amount of
time and capital must be invested before we can market 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. See
Item 1. Business Properties
Gulf of Mexico Deepwater Operations in this Annual Report
on
Form 10-K
for information about our use of tieback technology.
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 typically enter into hedging arrangements pertaining to a
substantial portion of our expected future production in order
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
27
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. Our hedging
arrangements reduced the benefit we received from increases in
oil and natural gas prices by approximately $100.8 million
in 2008. 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.
Counterparty
contract default could have an adverse effect on
us.
Our revenues are generated under contracts with various
counterparties. Results of operations would be adversely
affected as a result of non-performance by any of these
counterparties of their contractual obligations under the
various contracts. A counterpartys default or
non-performance could be caused by factors beyond our control
such as a counterparty experiencing credit default. A default
could occur as a result of circumstances relating directly to
the counterparty, such as defaulting on its credit obligations,
or due to circumstances caused by other market participants
having a direct or indirect relationship with the counterparty.
Defaults by counterparties may occur from time to time, and this
could negatively impact our results of operations, financial
position and cash flows.
Properties
we acquire 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 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 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.
Increased drilling activity periodically results in service cost
increases and shortages in drilling rigs, personnel, equipment
and supplies in certain areas. 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. Increases in
drilling activity in the United States or the Gulf of Mexico
could exacerbate this situation.
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Competition
in the oil and natural gas industry is intense and many of our
competitors have resources that are greater than ours, giving
them an advantage in evaluating and obtaining properties and
prospects.
We operate in a highly competitive environment for acquiring
prospects and productive properties, marketing oil and natural
gas and securing equipment and trained personnel. Many of our
competitors are major and large independent oil and natural gas
companies and possess and employ financial, technical and
personnel resources substantially greater than ours. Those
companies may be able to develop and acquire more prospects and
productive properties than our financial or personnel resources
permit. Our ability to acquire additional prospects and discover
reserves in the future will depend on our ability to evaluate
and select suitable properties and consummate transactions in a
highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and
natural gas industry. Larger competitors may be better able to
withstand sustained periods of unsuccessful drilling and absorb
the burden of changes in laws and regulations more easily than
we can, which would adversely affect our competitive position.
We may not be able to compete successfully in the future in
acquiring prospective reserves, developing reserves, marketing
hydrocarbons, attracting and retaining quality personnel and
raising additional capital.
Financial
difficulties encountered by our farm-out partners, working
interest owners 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 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 United States 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
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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 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
Item 1. 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 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 fully 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 the losses sustained in 2005 from
Hurricanes Katrina and Rita and in 2008 from Hurricane Ike, as
well as other factors affecting market conditions, premiums and
deductibles for certain insurance policies, including windstorm
insurance, have increased substantially. 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 that 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. 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 Item 1. Business
Insurance Matters and Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital Resources for
more information.
Risks
Relating to Significant Acquisitions and Other Strategic
Transactions
The
evaluation and integration of significant acquisitions may be
difficult.
We periodically evaluate acquisitions of reserves, properties,
prospects and leaseholds and other strategic transactions that
appear to fit within our overall business strategy. Significant
acquisitions and other strategic transactions may involve many
risks, including:
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diversion of our managements attention to evaluating,
negotiating and integrating significant acquisitions and
strategic transactions;
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challenge and cost of integrating acquired operations,
information management and other technology systems and business
cultures with those of ours while carrying on our ongoing
business;
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our exposure to unforeseen liabilities of acquired businesses,
operations or properties;
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possibility of faulty assumptions underlying our expectations,
including assumptions relating to reserves, future production,
volumes, revenues, costs and synergies;
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difficulty associated with coordinating geographically separate
organizations; and
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challenge of attracting and retaining personnel associated with
acquired operations.
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The process of integrating operations could cause an
interruption of, or loss of momentum in, the activities of our
business. Members of our senior management may be required to
devote considerable amounts of time to this integration process,
which will decrease the time they will have to manage our
business. If our senior management is not able to effectively
manage the integration process, or if any significant business
activities are interrupted as a result of the integration
process, our business could suffer.
If we
fail to realize the anticipated benefits of a significant
acquisition, our results of operations may be lower than we
expect.
The success of a significant acquisition will depend, in part,
on our ability to realize anticipated growth opportunities from
combining the acquired assets or operations with those of ours.
Even if a combination is successful, it may not be possible to
realize the full benefits we may expect in estimated proved
reserves, production volume, cost savings from operating
synergies or other benefits anticipated from an acquisition or
realize these benefits within the expected time frame.
Anticipated benefits of an acquisition may be offset by
operating losses relating to changes in commodity prices, or in
oil and natural gas industry conditions, or by risks and
uncertainties relating to the exploratory prospects of the
combined assets or operations, or an increase in operating or
other costs or other difficulties. If we fail to realize the
benefits we anticipate from an acquisition, our results of
operations may be adversely affected.
Financing
and other liabilities of a significant acquisition may adversely
affect our financial condition and results of operations or be
dilutive to stockholders.
Future significant acquisitions and other strategic transactions
could result in our incurring additional debt, contingent
liabilities and expenses, all of which could decrease our
liquidity or otherwise have a material adverse effect on our
financial condition and operating results. In addition, an
issuance of securities in connection with such transactions
could dilute or lessen the rights of our current common
stockholders.
Risks
Relating to Financings
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 may require financing beyond our cash flow from operations to
fully execute our business plan. 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 borrowings from affiliates. In the future, we will
require substantial capital to fund our business plan and
operations. We expect to meet our needs from one or more of our
excess cash flow, debt financings and equity offerings.
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. This could also result in a curtailment of our
operations relating to exploration and development of our
prospects, which in turn could result in a decline in our oil
and natural gas reserves.
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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 price volatility. 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. Many of these factors, such as
oil and natural gas prices, economic and financial conditions in
our industry and the global economy or competitive initiatives
of our competitors, are beyond our control.
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 our debt obligations.
Our level of indebtedness and the covenants contained in the
agreements governing our debt could have important consequences
for our operations, including:
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making it more difficult for us to satisfy our debt obligations
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 bank 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 bank credit facility and the
indentures governing our two series of senior unsecured notes,
we must comply with certain financial covenants, including
current asset and total debt ratio requirements under the bank
credit facility. 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 indentures or the bank
credit facility could result in a default under the applicable
agreement or a cross default under each 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 that we will
be able to generate sufficient cash flow to pay the interest on
our debt or those 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
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bank 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,
the value of our assets and our operating performance at the
time of such offering or other financing. We cannot assure that
any such offerings, refinancing or sale of assets could be
successfully completed.
|
|
Item 1B.
|
Unresolved
Staff Comments.
|
None.
See Item 1. Business for discussion of oil and
gas properties and locations.
We have offices in Houston and Midland, Texas and Lafayette,
Louisiana. As of December 31, 2008, our leases covered
approximately 94,226 square feet, 6,580 square feet
and 14,376 square feet of office space in Houston, Midland
and Lafayette, respectively. The leases run through
October 31, 2018, October 31, 2011 and
September 30, 2013 in Houston, Midland and Lafayette,
respectively. The total annual costs of our leases for 2008 were
approximately $2.1 million.
|
|
Item 3.
|
Legal
Proceedings.
|
Mariner and its subsidiary, Mariner Energy Resources, Inc.
(MERI), own numerous properties in the Gulf of
Mexico. Certain of such properties were leased from the MMS
subject to the RRA. Section 304 of the RRA relieves lessees
of the obligation to pay royalties on certain leases until after
a designated volume has been produced. Four of these leases held
by Mariner and two held by MERI that are producing or have
produced contain lease language (inserted by the MMS) that
conditions royalty relief on commodity prices remaining below
specified thresholds. Since 2000, commodity prices have exceeded
some of the predetermined thresholds, except in 2002. In May
2006 and September 2008, the MMS issued orders asserting that
the price thresholds had been exceeded in calendar years 2000,
2001, and each of the years from 2003 through 2007, and,
accordingly, that royalties were due under such leases on oil
and gas produced in those years. The potential liability of MERI
under its leases relate to production from the leases commencing
July 1, 2005, the effective date of Mariners
acquisition of MERI. Mariner and MERI believe that the MMS did
not have the statutory authority to include commodity price
threshold language in the leases governed by Section 304 of
the RRA and accordingly have withheld payment of royalties.
Mariner and MERI have challenged the MMSs authority in
pending administrative appeals for those leases for which the
MMS has issued orders to pay.
The enforceability of the price threshold provisions in leases
granted pursuant to Section 304 of the RRA is currently
being litigated in several administrative appeals filed by other
companies in addition to Mariner, as well as in Kerr-McGee
Oil & Gas Corp. v. Allred,
No. 08-30069
(5th Cir.). In the Kerr-McGee litigation, the
district court in the Western District of Louisiana granted
Kerr-McGees motion for summary judgment, ruling that the
price threshold provisions are unlawful and unenforceable under
Section 304 of the RRA. Kerr-McGee Oil & Gas
Corp. v. Allred, No. 2:06 CV 0439 (W.D. La.) (Mem.
Ruling filed Oct. 30, 2007). The Department of the Interior
appealed that judgment to the United States Court of Appeals for
the Fifth Circuit. On January 12, 2009, the Fifth Circuit
affirmed the district courts judgment that the price
provisions are unlawful based on Section 304 of the RRA.
Kerr-McGee Oil & Gas Corp. v.
U.S. Dept of Interior,
F.3d , 2009 WL 57883 (5th Cir. Jan. 12, 2009).
Until the appeals process is complete, we will continue to
monitor the case. Given the judicial history of the case, we
determined that as of December 31, 2008, we no longer will
record a liability for our estimated exposure to the MMS on our
leases granted pursuant to Section 304 of the RRA. At
December 31, 2008, this liability would have been
$57.3 million, including interest. In addition, as of
December 31, 2008, we began including in our estimated
proved reserves those reserves attributable to these RRA
Section 304 leases which, at December 31, 2008, was
approximately 18.1 Bcfe.
In the ordinary course of business, we are a claimant
and/or a
defendant in various legal proceedings, including proceedings as
to which we have insurance coverage and those that may involve
the filing of liens against us or our assets. We do not consider
our exposure in these proceedings, individually or in the
aggregate, to be material.
33
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders.
|
Not applicable.
Executive
Officers of the Registrant
The following table sets forth the names, ages (as of
February 20, 2009) and titles of the individuals who
are executive officers of Mariner. All executive officers hold
office until their successors are elected and qualified. There
are no family relationships among any of our directors or
executive officers.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position with Company
|
|
Scott D. Josey
|
|
|
51
|
|
|
Chairman of the Board, Chief Executive Officer and President
|
Dalton F. Polasek
|
|
|
57
|
|
|
Chief Operating Officer
|
John H. Karnes
|
|
|
47
|
|
|
Senior Vice President, Chief Financial Officer and Treasurer
|
Mike C. van den Bold
|
|
|
46
|
|
|
Senior Vice President and Chief Exploration Officer
|
Judd A. Hansen
|
|
|
53
|
|
|
Senior Vice President Shelf and Onshore
|
Teresa G. Bushman
|
|
|
59
|
|
|
Senior Vice President, General Counsel and Secretary
|
Cory L. Loegering
|
|
|
53
|
|
|
Senior Vice President Deepwater
|
Jesus G. Melendrez
|
|
|
50
|
|
|
Senior Vice President Corporate Development
|
Richard A. Molohon
|
|
|
54
|
|
|
Vice President Reservoir Engineering
|
Michael C. McCullough
|
|
|
63
|
|
|
Vice President Acquisitions and Divestitures
|
Kenneth E. Moore, Jr.
|
|
|
62
|
|
|
Vice President Onshore Land
|
Scott D. Josey Mr. Josey has served as
Chairman of the Board since August 2001. Mr. Josey was
appointed Chief Executive Officer in October 2002 and President
in February 2005. From 2000 to 2002, Mr. Josey served as
Vice President of Enron North America Corp. and co-managed its
Energy Capital Resources group. From 1995 to 2000,
Mr. Josey provided investment banking services to the oil
and gas industry and portfolio management services. From 1993 to
1995, Mr. Josey was a Director with Enron
Capital & Trade Resources Corp. in its energy
investment group. From 1982 to 1993, Mr. Josey worked in
all phases of drilling, production, pipeline, corporate planning
and commercial activities at Texas Oil and Gas Corp.
Mr. Josey is a member of the Society of Petroleum Engineers
and the Independent Producers Association of America.
Dalton F. Polasek Mr. Polasek was
appointed Chief Operating Officer in February 2005. From
April 2004 to February 2005, Mr. Polasek served as
Executive Vice President Operations and Exploration.
From August 2003 to April 2004, he served as Senior Vice
President Shelf and Onshore. From August 2002
to August 2003, he was Senior Vice President, and from October
2001 to January 2003, he was a consultant to Mariner. Prior to
joining Mariner, Mr. Polasek was self employed from
February 2001 to October 2001 and served as: Vice President of
Gulf Coast Engineering for Basin Exploration, Inc. from 1996
until February 2001; Vice President of Engineering for SMR
Energy Income Funds from 1994 to 1996; director of Gulf Coast
Acquisitions and Engineering for General Atlantic Resources,
Inc. from 1991 to 1994; and manager of planning and business
development for Mark Producing Company from 1983 to 1991. He
began his career in 1975 as a reservoir engineer for Amoco
Production Company. Mr. Polasek is a Registered
Professional Engineer in Texas, and a member of the Independent
Producers Association of America and the Society of Petroleum
Engineers.
John H. Karnes Mr. Karnes was appointed
Senior Vice President, Chief Financial Officer and Treasurer in
October 2006. He was Senior Vice President and Chief Financial
Officer of CDX Gas, LLC from July 2006 to August 2006. He served
as Executive Vice President and Chief Financial Officer of
Maxxam Inc. from April 2006 to July 2006. He served as Senior
Vice President and Chief Financial Officer of The Houston
Exploration Company from November 2002 through December 2005.
Earlier in his career, he served in senior management roles at
several publicly-traded companies, including Encore Acquisition
Company, Snyder Oil Corporation and Apache Corporation,
practiced law with the national law firm of Kirkland &
Ellis, and was employed in various roles in the securities
industry.
34
Mike C. van den Bold Mr. van den Bold was
promoted to Senior Vice President and Chief Exploration Officer
in April 2006 and served as Vice President and Chief Exploration
Officer from April 2004 to April 2006. From October 2001 to
April 2004, he served as Vice President Exploration.
Mr. van den Bold joined Mariner in July 2000 as Senior
Development Geologist. From 1996 to 2000, Mr. van den Bold
worked for British-Borneo Oil & Gas plc. He began his
career at British Petroleum. Mr. van den Bold has more than
20 years of industry experience. He is a Certified
Petroleum Geologist, a Texas Board Certified Geologist and a
member of the American Association of Petroleum Geologists.
Judd A. Hansen Mr. Hansen was promoted
to Senior Vice President Shelf and Onshore in April
2006 and served as Vice President Shelf and Onshore
from February 2002 to April 2006. From April 2001 to February
2002, Mr. Hansen was self-employed as a consultant. From
1997 until March 2001, Mr. Hansen was employed as
Operations Manager of the Gulf Coast Division for Basin
Exploration, Inc. From 1991 to 1997, he was employed in various
engineering positions at Greenhill Petroleum Corporation,
including Senior Production Engineer and Workover/Completion
Superintendent. Mr. Hansen started his career with Shell
Oil Company in 1978 and has 30 years of experience in
conducting operations in the oil and gas industry.
Teresa G. Bushman Ms. Bushman was
promoted to Senior Vice President, General Counsel and Secretary
in April 2006 and served as Vice President, General Counsel and
Secretary from June 2003 to April 2006. From 1996 until joining
Mariner in 2003, Ms. Bushman was employed by Enron North
America Corp., most recently as Assistant General Counsel
representing the Energy Capital Resources group, which provided
debt and equity financing to the oil and gas industry. Prior to
joining Enron, Ms. Bushman was a partner with Jackson
Walker, LLP, in Houston.
Cory L. Loegering Mr. Loegering was
promoted to Senior Vice President Deepwater in
September 2006 and served as Vice President
Deepwater from August 2002 to September 2006. Mr. Loegering
joined Mariner in July 1990 and since 1998 has held various
positions including Vice President of Petroleum Engineering and
Director of Deepwater development. Mr. Loegering was
employed by Tenneco from 1982 to 1988, in various positions
including as senior engineer in the economic, planning and
analysis group in Tennecos corporate offices.
Mr. Loegering began his career with Conoco in 1977 and held
positions in the construction, production and reservoir
departments responsible for Gulf of Mexico production and
development. Mr. Loegering has 31 years of experience
in the industry.
Jesus G. Melendrez Mr. Melendrez was
promoted to Senior Vice President Corporate
Development in April 2006 and served as Vice
President Corporate Development from July 2003 to
April 2006. Mr. Melendrez also served as a director of
Mariner from April 2000 to July 2003. From February 2000 until
July 2003, Mr. Melendrez was a Vice President of Enron
North America Corp. in the Energy Capital Resources group where
he managed the groups portfolio of oil and gas
investments. He was a Senior Vice President of Trading and
Structured Finance with TXU Energy Services from 1997 to 2000,
and from 1992 to 1997, Mr. Melendrez was employed by Enron
in various commercial positions in the areas of domestic oil and
gas financing and international project development. From 1980
to 1992, Mr. Melendrez was employed by Exxon in various
reservoir engineering and planning positions.
Richard A. Molohon Mr. Molohon was
appointed Vice President Reservoir Engineering in
May 2006. He joined Mariner in January 1995 as a Senior
Reservoir Engineer and since then has held various positions in
reservoir engineering, economics, acquisitions and dispositions,
exploration, development, and planning and basin analysis,
including Senior Staff Engineer from January 2000 to January
2004, and Manager, Reserves and Economics from January 2004 to
May 2006. Mr. Molohon has more than 30 years of
industry experience. He began his career with Amoco Production
Company as a Production Engineer from 1977 until 1980. From 1980
to 1991, he was a Project Petroleum Engineer for various
subsidiaries of Tenneco, Inc. From 1991 to 1995 he was a Senior
Acquisition Engineer for General Atlantic Inc. Mr. Molohon
has been a Registered Professional Engineer in Texas since 1983
and is a member of the Society of Petroleum Engineers.
Michael C. McCullough Mr. McCullough was
promoted to Vice President Acquisitions and
Divestitures in February 2008. He served as Manager,
Acquisitions/Exploitation from March 2006 to February 2008,
and as Senior Reservoir Engineer from May 2004 to March 2006.
Mr. McCullough was employed by Basin Exploration, Inc. from
1999 to 2001 and its successor, Stone Energy Corporation, from
2001 to 2004, in general reservoir engineering, lease sales and
acquisitions capacities. He has approximately
35
40 years of industry engineering experience, beginning his
career in 1968 as a production engineer with Mobil Oil
Corporation.
Kenneth E. Moore, Jr. Mr. Moore was
promoted to Vice President Onshore Land in February
2008. A Certified Professional Landman, he was employed by
Mariner in December 2004 as Onshore Business Development Manager
and in November 2006, became Manager, Land/Business Development
(Onshore). Mr. Moore served Mariner from November 2003 to
December 2004 as an independent contractor performing land
services through his firm Moore Land & Minerals which
provided a full range of land services to various clients in the
Texas Gulf Coast and the Permian Basin areas from September 2001
to December 2004. Mr. Moore has almost 35 years of
industry land experience, beginning his career in 1974 as a
landman with Gulf Oil Corporation.
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity
Securities.
|
Mariners common stock trades on the New York Stock
Exchange (NYSE) under the symbol ME. The
following table sets forth the reported high and low closing
sales prices of our common stock for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
Period Ended
|
|
High
|
|
|
Low
|
|
|
|
2007
|
|
|
First Quarter
|
|
$
|
20.33
|
|
|
$
|
16.95
|
|
|
|
|
|
Second Quarter
|
|
|
25.65
|
|
|
|
19.30
|
|
|
|
|
|
Third Quarter
|
|
|
25.26
|
|
|
|
18.87
|
|
|
|
|
|
Fourth Quarter
|
|
|
25.00
|
|
|
|
20.67
|
|
|
2008
|
|
|
First Quarter
|
|
$
|
29.60
|
|
|
$
|
23.69
|
|
|
|
|
|
Second Quarter
|
|
|
37.01
|
|
|
|
26.84
|
|
|
|
|
|
Third Quarter
|
|
|
36.45
|
|
|
|
19.77
|
|
|
|
|
|
Fourth Quarter
|
|
|
19.54
|
|
|
|
7.48
|
|
As of February 20, 2009 there were 763 holders of record of
our issued and outstanding common stock. We believe that there
are significantly more beneficial holders of our stock.
We currently intend to retain our earnings for the development
of our business and do not expect to pay any cash dividends. We
did not pay any cash dividends for fiscal years 2007 or 2008.
Refer to Item 7. Managements Discussion and
Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Bank Credit Facility and
Note 3. Long-Term Debt in the Notes to the
Consolidated Financial Statements in Part II, Item 8
of this Annual Report on
Form 10-K
for a discussion of certain covenants in our bank credit
facility and indentures governing our senior unsecured notes
which restrict our ability to pay dividends.
36
Performance
Graph
The following graph compares the cumulative total stockholder
return for our common stock to that of the Standard &
Poors 500 Index and a peer group for the period indicated
as prescribed by SEC rules. Cumulative total return
means the change in share price during the measurement period,
plus cumulative dividends for the measurement period (assuming
dividend reinvestment), divided by the share price at the
beginning of the measurement period. The graph assumes $100 was
invested on March 3, 2006 (the date on which our common
stock began regular way trading on the NYSE) in each of our
common stock, the Standard & Poors Composite 500
Index and a peer group.
COMPARISON
OF CUMULATIVE TOTAL RETURN AMONG
MARINER ENERGY, INC., THE S&P 500 INDEX AND A DEFINED PEER
GROUP(1),(2)
Note: The stock price performance of our common stock is not
necessarily indicative of future performance.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative Total Return(1)
|
|
|
Initial
|
|
12/31/06
|
|
12/31/07
|
|
12/31/08
|
|
Mariner Energy, Inc.
|
|
$
|
100.00
|
|
|
$
|
96.69
|
|
|
$
|
112.88
|
|
|
$
|
50.32
|
|
S&P 500 Index
|
|
$
|
100.00
|
|
|
$
|
110.18
|
|
|
$
|
114.07
|
|
|
$
|
70.17
|
|
Peer Group(2)
|
|
$
|
100.00
|
|
|
$
|
97.09
|
|
|
$
|
103.74
|
|
|
$
|
37.16
|
|
|
|
(1)
|
Total return assuming reinvestment of dividends. Assumes $100
invested on March 3, 2006 in each of Mariners common
stock, the S&P 500 Index, and a peer group of companies.
Initial data is taken from March 3, 2006, the date on which
Mariners common stock began regular way trading on the
NYSE.
|
|
(2)
|
Composed of the following seven independent oil and gas
exploration and production companies: ATP Oil &
Gas Corporation, Callon Petroleum Co., Energy Partners, Ltd.,
McMoRan Exploration Co., Plains Exploration &
Production Company, Stone Energy Corporation, and W&T
Offshore, Inc. This peer group differs by one member from the
peer group for the stock performance graph included in our 2007
annual report. McMoRan Exploration Co. replaces Bois dArc
Energy, Inc. which ceased to exist in 2008 when it was merged
into a wholly-owned subsidiary of peer group member Stone Energy
Corporation.
|
The above information under the caption Performance
Graph shall not be deemed to be soliciting
material and shall not be deemed to be incorporated by
reference by any general statement incorporating by reference
this
Form 10-K
into any filing under the Securities Act of 1933, as amended, or
the Securities Exchange Act of 1934, as amended, and shall not
otherwise be deemed filed under such acts.
37
Issuer
Purchases of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number
|
|
|
|
|
|
|
|
|
|
|
|
|
of Shares
|
|
|
Maximum Number
|
|
|
|
|
|
|
|
|
|
(or Units)
|
|
|
(or Approximate
|
|
|
|
|
|
|
|
|
|
Purchased as
|
|
|
Dollar Value) of
|
|
|
|
Total Number
|
|
|
Average
|
|
|
Part of Publicly
|
|
|
Shares (or Units)
|
|
|
|
of Shares
|
|
|
Price Paid
|
|
|
Announced
|
|
|
that May Yet Be
|
|
|
|
(or Units)
|
|
|
per Share
|
|
|
Plans or
|
|
|
Purchased Under the
|
|
Period
|
|
Purchased
|
|
|
(or Unit)
|
|
|
Programs
|
|
|
Plans or Programs
|
|
|
October 1, 2008 to October 31, 2008(1)
|
|
|
3,235
|
|
|
$
|
16.31
|
|
|
|
|
|
|
|
|
|
November 1, 2008 to November 30, 2008(1)
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
December 1, 2008 to December 31, 2008(1)
|
|
|
2,639
|
|
|
$
|
8.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
5,874
|
|
|
$
|
13.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
These shares were withheld upon the vesting of employee
restricted stock grants in connection with payment of required
withholding taxes. |
38
|
|
Item 6.
|
Selected
Financial
Data.
|
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 Merger). Prior to the Merger, we were owned
indirectly by Enron Corp. As a result of the Merger, we ceased
being affiliated with Enron Corp in 2004.
The selected financial data table below shows our historical
consolidated financial data as of and for the years ended
December 31, 2008, 2007, 2006 and 2005, the period from
March 3, 2004 through December 31, 2004, and the
period from January 1, 2004 through March 2, 2004. The
historical consolidated financial data as of and for the years
ended December 31, 2008, 2007 and 2006, are derived from
Mariners audited Consolidated Financial Statements
included herein, and the historical consolidated financial data
as of and for the year ended December 31, 2005, and for the
periods March 3, 2004 through December 31, 2004
(Post-2004 Merger) and January 1, 2004 through
March 2, 2004 (Pre-2004 Merger), are derived
from Mariners audited Consolidated Financial Statements
that are not included herein. The financial information
contained herein is presented in the style of Post-2004 Merger
activity and Pre-2004 Merger activity 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. You should read the following
data in connection with Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations and the Consolidated Financial
Statements and related notes thereto included in Part II,
Item 8 of this Annual Report on
Form 10-K,
where there is additional disclosure regarding the information
in the following table. Mariners historical results are
not necessarily indicative of results to be expected in future
periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
through
|
|
|
through
|
|
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
|
(In thousands, except per share data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues(1)
|
|
$
|
1,300,507
|
|
|
$
|
874,765
|
|
|
$
|
659,505
|
|
|
$
|
199,710
|
|
|
$
|
174,423
|
|
|
$
|
39,764
|
|
Operating expenses(2)
|
|
|
264,832
|
|
|
|
174,522
|
|
|
|
105,739
|
|
|
|
32,218
|
|
|
|
23,322
|
|
|
|
5,191
|
|
Depreciation, depletion and amortization
|
|
|
467,265
|
|
|
|
384,321
|
|
|
|
292,180
|
|
|
|
59,469
|
|
|
|
54,281
|
|
|
|
10,630
|
|
General and administrative expense
|
|
|
60,613
|
|
|
|
42,151
|
|
|
|
33,622
|
|
|
|
36,766
|
|
|
|
7,641
|
|
|
|
1,131
|
|
Operating (loss) income(3)
|
|
|
(381,712
|
)
|
|
|
268,710
|
|
|
|
227,470
|
|
|
|
69,168
|
|
|
|
88,222
|
|
|
|
22,812
|
|
Interest expense, net of amounts capitalized
|
|
|
56,398
|
|
|
|
54,665
|
|
|
|
39,649
|
|
|
|
8,172
|
|
|
|
6,045
|
|
|
|
5
|
|
(Benefit) Provision for income taxes
|
|
|
(48,223
|
)
|
|
|
77,324
|
|
|
|
67,344
|
|
|
|
21,294
|
|
|
|
28,783
|
|
|
|
8,072
|
|
Net (loss) income
|
|
|
(388,713
|
)
|
|
|
143,934
|
|
|
|
121,462
|
|
|
|
40,481
|
|
|
|
53,619
|
|
|
|
14,826
|
|
Earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common share basic
|
|
$
|
(4.44
|
)
|
|
$
|
1.68
|
|
|
$
|
1.59
|
|
|
$
|
1.24
|
|
|
$
|
1.80
|
|
|
$
|
0.50
|
|
Net (loss) income per common share diluted
|
|
$
|
(4.44
|
)
|
|
$
|
1.67
|
|
|
$
|
1.58
|
|
|
$
|
1.20
|
|
|
$
|
1.80
|
|
|
$
|
0.50
|
|
|
|
|
(1) |
|
Includes effects of hedging. |
|
(2) |
|
Operating expenses include lease operating expense, severance
and ad valorem taxes and transportation expenses. |
|
(3) |
|
2008 includes $575.6 million of full cost ceiling test
impairment, $295.6 million of goodwill impairment and
$15.3 million of other property impairment. |
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Balance Sheet Data:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
$
|
374,953
|
|
|
$
|
248,980
|
|
|
$
|
306,018
|
|
|
$
|
141,432
|
|
|
$
|
65,746
|
|
Current Liabilities
|
|
|
425,564
|
|
|
|
315,189
|
|
|
|
239,727
|
|
|
|
204,006
|
|
|
|
101,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital deficit
|
|
$
|
(50,611
|
)
|
|
$
|
(66,209
|
)
|
|
$
|
66,291
|
|
|
$
|
(62,574
|
)
|
|
$
|
(35,666
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
2,929,877
|
|
|
|
2,420,194
|
|
|
|
2,012,062
|
|
|
|
515,943
|
|
|
|
303,773
|
|
Total assets
|
|
|
3,392,793
|
|
|
|
3,083,635
|
|
|
|
2,680,153
|
|
|
|
665,536
|
|
|
|
376,019
|
|
Long-term debt, less current maturities
|
|
|
1,170,000
|
|
|
|
779,000
|
|
|
|
654,000
|
|
|
|
156,000
|
|
|
|
115,000
|
|
Stockholders equity
|
|
|
1,120,320
|
|
|
|
1,391,018
|
|
|
|
1,302,591
|
|
|
|
213,336
|
|
|
|
133,907
|
|
|
|
|
(1) |
|
Balance sheet data as of December 31, 2004 reflects
purchase accounting adjustments to oil and gas properties, total
assets and stockholders equity resulting from the
acquisition of our former indirect parent on March 2, 2004. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-2004 Merger
|
|
|
Pre-2004 Merger
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 3,
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
through
|
|
|
through
|
|
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
|
March 2,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
862,017
|
|
|
$
|
536,113
|
|
|
$
|
277,161
|
|
|
$
|
165,444
|
|
|
$
|
135,243
|
|
|
$
|
20,295
|
|
Net cash used in investing activities
|
|
$
|
(1,264,784
|
)
|
|
$
|
(643,779
|
)
|
|
$
|
(561,390
|
)
|
|
$
|
(247,799
|
)
|
|
$
|
(132,977
|
)
|
|
$
|
(15,341
|
)
|
Net cash provided (used) by financing activities
|
|
$
|
387,429
|
|
|
$
|
116,676
|
|
|
$
|
289,252
|
|
|
$
|
84,370
|
|
|
$
|
(64,853
|
)
|
|
$
|
|
|
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
|
Business
Overview
We are an independent oil and natural gas exploration,
development and production company with principal operations in
the Permian Basin and the Gulf of Mexico. As of
December 31, 2008, approximately 70% of our total estimated
proved reserves were classified as proved developed, with
approximately 45% of the total estimated proved reserves located
in the Permian Basin, 20% in the Gulf of Mexico deepwater and
35% on the Gulf of Mexico shelf.
Our revenues, profitability and future growth depend
substantially on prevailing prices for oil and natural 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 historically have been very volatile.
Oil and natural gas prices increased to, and then declined
significantly from, historical highs in 2008 and may fluctuate
and decline 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 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.
The recent worldwide financial and credit crisis has reduced the
availability of liquidity and credit to fund the continuation
and expansion of industrial business operations worldwide. The
shortage of liquidity and credit combined with recent
substantial losses in worldwide equity markets could lead to an
extended worldwide economic recession. A recession or slowdown
in economic activity would likely reduce worldwide demand for
energy and result in lower oil and natural gas prices, which
could materially adversely affect our profitability and results
of operations.
40
Acquisitions. On December 19, 2008, we
acquired additional working interests in our existing property,
Atwater Valley Block 426 (Bass Lite), for approximately
$32.6 million, increasing our working interest by 11.6% to
53.8%. We internally estimated proved reserves attributable to
the acquisition of approximately 17.6 Bcfe (100% natural
gas).
On January 31, 2008, we acquired 100% of the equity in a
subsidiary of Hydro Gulf of Mexico, Inc. pursuant to a
Membership Interest Purchase Agreement executed on
December 23, 2007. The acquired subsidiary, now known as
Mariner Gulf of Mexico LLC (MGOM), was an indirect
subsidiary of StatoilHydro ASA and owns substantially all of its
former Gulf of Mexico shelf operations. A summary of these
assets and operations as of January 1, 2008 includes:
|
|
|
|
|
Ryder Scott Company, L.P. estimated proved oil and gas reserves
of 49.7 Bcfe, 93% of which are developed;
|
|
|
|
interests in 36 (16 net) producing wells producing approximately
53 MMcfe per day net to MGOMs interest, 76% of which
Mariner now operates;
|
|
|
|
gas gathering systems comprised of 31 miles of
10-inch,
12-inch and
16-inch
pipelines; and
|
|
|
|
approximately 106,000 net acres of developed leasehold and
256,000 net acres of undeveloped leasehold.
|
We paid approximately $243.0 million for MGOM, subject to
customary purchase price adjustments, including
$8.0 million for reimbursement of drilling costs
attributable to the High Island 166 #5 well.
On December 31, 2007, February 29, 2008, and
December 1, 2008 we acquired additional working interests
in certain of our existing properties in the Spraberry field in
the Permian Basin. We internally estimated proved reserves
attributable to the December 2007 acquisition of approximately
94.9 Bcfe (75% oil and NGLs), to the February 2008
acquisition of approximately 14.0 Bcfe (65% oil and NGLs)
and to the December 2008 acquisition of approximately
13.4 Bcfe (66% oil and NGLs). We operate substantially all
of the assets. The purchase prices, subject to customary
purchase price adjustments, were approximately
$122.5 million for the December 2007 acquisition,
$21.7 million for the February 2008 acquisition and
$19.4 million for the December 2008 acquisition.
On March 2, 2006, a subsidiary of Mariner completed a
merger transaction with Forest Energy Resources, Inc. (the
Forest Merger) pursuant to which Mariner effectively
acquired Forests Gulf of Mexico operations. Prior to the
consummation of the Forest 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 Forest Merger, Forest distributed all
of the outstanding shares of Forest Energy Resources to Forest
stockholders 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 Forest
Merger, approximately 59% of Mariner common stock was held by
stockholders of Forest and approximately 41% of Mariner common
stock was held by the pre-merger stockholders of Mariner. In the
Forest Merger, Mariner issued 50,637,010 shares of common
stock to the stockholders of Forest Energy Resources, Inc. Our
acquisition of Forest Energy Resources added approximately
298 Bcfe of estimated proved reserves. The Forest Merger
has had a significant effect on the comparability of operating
and financial results between periods.
41
Results
of Operations
Year
Ended December 31, 2008 compared to Year Ended
December 31, 2007
Operating
and Financial Results for the Year Ended December 31,
2008
Compared to the Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
(Decrease)
|
|
|
% change
|
|
|
|
(In thousands, except average sales price)
|
|
|
Summary Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
79,756
|
|
|
|
67,793
|
|
|
|
11,963
|
|
|
|
18
|
%
|
Oil (Mbbls)
|
|
|
4,881
|
|
|
|
4,214
|
|
|
|
667
|
|
|
|
16
|
%
|
Natural gas liquids (Mbbls)
|
|
|
1,558
|
|
|
|
1,200
|
|
|
|
358
|
|
|
|
30
|
%
|
Total natural gas equivalent (MMcfe)
|
|
|
118,389
|
|
|
|
100,273
|
|
|
|
18,116
|
|
|
|
18
|
%
|
Average daily production (MMcfe per day)
|
|
|
323
|
|
|
|
275
|
|
|
|
48
|
|
|
|
18
|
%
|
Hedging Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue gain (loss)
|
|
$
|
(28,047
|
)
|
|
$
|
58,465
|
|
|
$
|
(86,512
|
)
|
|
|
(148
|
)%
|
Oil revenue loss
|
|
|
(72,762
|
)
|
|
|
(13,388
|
)
|
|
|
(59,374
|
)
|
|
|
443
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total hedging revenue gain (loss)
|
|
$
|
(100,809
|
)
|
|
$
|
45,077
|
|
|
$
|
(145,886
|
)
|
|
|
(324
|
)%
|
Average Sales Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) realized(1)
|
|
$
|
9.31
|
|
|
$
|
7.88
|
|
|
$
|
1.43
|
|
|
|
18
|
%
|
Natural gas (per Mcf) unhedged
|
|
|
9.66
|
|
|
|
7.02
|
|
|
|
2.64
|
|
|
|
38
|
%
|
Oil (per Bbl) realized(1)
|
|
|
86.02
|
|
|
|
67.50
|
|
|
|
18.52
|
|
|
|
27
|
%
|
Oil (per Bbl) unhedged
|
|
|
100.93
|
|
|
|
70.68
|
|
|
|
30.25
|
|
|
|
43
|
%
|
Natural gas liquids (per Bbl) realized(1)
|
|
|
55.02
|
|
|
|
45.16
|
|
|
|
9.86
|
|
|
|
22
|
%
|
Natural gas liquids (per Bbl) unhedged
|
|
|
55.02
|
|
|
|
45.16
|
|
|
|
9.86
|
|
|
|
22
|
%
|
Total natural gas equivalent ($/Mcfe) realized(1)
|
|
|
10.54
|
|
|
|
8.71
|
|
|
|
1.83
|
|
|
|
21
|
%
|
Total natural gas equivalent ($/Mcfe) unhedged
|
|
|
11.39
|
|
|
|
8.26
|
|
|
|
3.13
|
|
|
|
38
|
%
|
Summary of Financial Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
742,370
|
|
|
$
|
534,537
|
|
|
$
|
207,833
|
|
|
|
39
|
%
|
Oil revenue
|
|
|
419,878
|
|
|
|
284,405
|
|
|
|
135,473
|
|
|
|
48
|
%
|
Natural gas liquids revenue
|
|
|
85,715
|
|
|
|
54,192
|
|
|
|
31,523
|
|
|
|
58
|
%
|
Other revenues
|
|
|
52,544
|
|
|
|
1,631
|
|
|
|
50,913
|
|
|
|
3,122
|
%
|
Lease operating expense
|
|
|
231,645
|
|
|
|
152,627
|
|
|
|
79,018
|
|
|
|
52
|
%
|
Severance and ad valorem taxes
|
|
|
18,191
|
|
|
|
13,101
|
|
|
|
5,090
|
|
|
|
39
|
%
|
Transportation expense
|
|
|
14,996
|
|
|
|
8,794
|
|
|
|
6,202
|
|
|
|
71
|
%
|
General and administrative expense
|
|
|
60,613
|
|
|
|
42,151
|
|
|
|
18,462
|
|
|
|
44
|
%
|
Depreciation, depletion and amortization
|
|
|
467,265
|
|
|
|
384,321
|
|
|
|
82,944
|
|
|
|
22
|
%
|
Full cost ceiling test impairment
|
|
|
575,607
|
|
|
|
|
|
|
|
575,607
|
|
|
|
N/A
|
|
Goodwill impairment
|
|
|
295,598
|
|
|
|
|
|
|
|
295,598
|
|
|
|
N/A
|
|
Other property impairment
|
|
|
15,252
|
|
|
|
|
|
|
|
15,252
|
|
|
|
N/A
|
|
Net interest expense
|
|
|
56,398
|
|
|
|
53,262
|
|
|
|
3,136
|
|
|
|
6
|
%
|
Income (Loss) before taxes and minority interest
|
|
|
(436,748
|
)
|
|
|
221,259
|
|
|
|
(658,007
|
)
|
|
|
(297
|
)%
|
(Benefit) Provision for income taxes
|
|
|
(48,223
|
)
|
|
|
77,324
|
|
|
|
(125,547
|
)
|
|
|
(162
|
)%
|
Net income (loss)
|
|
|
(388,713
|
)
|
|
|
143,934
|
|
|
|
(532,647
|
)
|
|
|
(370
|
)%
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
1.96
|
|
|
$
|
1.52
|
|
|
$
|
0.44
|
|
|
|
29
|
%
|
Severance and ad valorem taxes
|
|
|
0.15
|
|
|
|
0.13
|
|
|
|
0.02
|
|
|
|
15
|
%
|
Transportation expense
|
|
|
0.13
|
|
|
|
0.09
|
|
|
|
0.04
|
|
|
|
44
|
%
|
General and administrative expense
|
|
|
0.51
|
|
|
|
0.42
|
|
|
|
0.09
|
|
|
|
21
|
%
|
Depreciation, depletion and amortization
|
|
|
3.95
|
|
|
|
3.83
|
|
|
|
0.12
|
|
|
|
3
|
%
|
|
|
|
(1) |
|
Average realized prices include the effects of hedges. |
42
Net loss for 2008 was $388.7 million compared to net
income of $143.9 million for 2007. The decrease was
primarily attributable to $886.5 million in impairments
resulting from our full cost ceiling test, other property
impairment and goodwill, as discussed below. Basic and
fully-diluted earnings per share for 2008 were $(4.44) for each
measure compared to $1.68 and $1.67, respectively for 2007.
Net production Natural gas production increased
approximately 18% in 2008 to approximately 218 MMcf per
day, compared to approximately 186 MMcf per day in 2007.
Oil production increased 16% in 2008 to approximately
13,300 barrels per day, compared to approximately
11,500 barrels per day in 2007. Natural gas liquids
production increased 30% in 2008 and total overall production
increased 18% in 2008 to approximately 323 MMcfe per day,
compared to 275 MMcfe per day in 2007. Natural gas
production comprised approximately 67% of total production in
both 2008 and 2007.
Net production in the Gulf of Mexico for 2008 increased 16% to
103.5 Bcfe from 89.1 Bcfe for 2007 primarily
reflecting the start up in 2008 of production from several new
projects, most notably, Northwest Nansen located in East Breaks
602 (which contributed 12.9 Bcfe) and Bass Lite located in
Atwater 426 (which contributed 8.4 Bcfe), and the impact of
our acquisition of MGOM (which contributed 13.1 Bcfe). This
increase was offset by the impacts of Hurricanes Gustav and Ike
in the third quarter which resulted in net shut-in production
(assuming pre-hurricane net production levels remained constant)
of approximately 20 Bcfe.
Onshore production for 2008 increased 33% to 14.9 Bcfe from
11.2 Bcfe for 2007, primarily as a result of our
acquisition of additional interests and drilling and development
of existing acreage in the Permian Basin (which contributed
2.6 Bcfe in 2008).
Natural gas, oil and NGL revenues for 2008 increased 43%
to $1,248.0 million compared to $873.1 million for
2007 as a result of increased pricing (approximately
$217.1 million, net of the effect of hedging), and
increased production (approximately $157.8 million).
During 2008, our revenues reflected a net recognized hedging
loss of $100.8 million comprised of $98.8 million in
unfavorable cash settlements and an unrealized loss of
$2.0 million related to the ineffective portion not
eligible for deferral under SFAS 133. This compares to a
net recognized hedging gain of approximately $45.1 million
for 2007, comprised of $46.7 million in favorable cash
settlements and an unrealized loss of $1.6 million related
to the ineffective portion not eligible for deferral under
SFAS 133.
Our natural gas and oil average sales prices, and the effects of
hedging activities on those prices, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedging
|
|
|
|
|
|
|
Realized
|
|
|
Unhedged
|
|
|
(Loss) Gain
|
|
|
% Change
|
|
|
Year Ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
9.31
|
|
|
$
|
9.66
|
|
|
$
|
(0.35
|
)
|
|
|
(4
|
)%
|
Oil (per Bbl)
|
|
|
86.02
|
|
|
|
100.93
|
|
|
|
(14.91
|
)
|
|
|
(15
|
)%
|
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.88
|
|
|
$
|
7.02
|
|
|
$
|
0.86
|
|
|
|
12
|
%
|
Oil (per Bbl)
|
|
|
67.50
|
|
|
|
70.68
|
|
|
|
(3.18
|
)
|
|
|
(4
|
)%
|
Other revenues for 2008 increased approximately
$50.9 million to $52.5 million from $1.6 million
for 2007 as a result of the release of suspended revenue of
$46.5 million related to a potential MMS royalty liability
and $4.3 million of imputed rent from the lease of office
property acquired in January 2008.
Lease operating expense (LOE) in 2008
increased approximately $79.0 million to
$231.6 million from $152.6 million for 2007, primarily
as a result of a $36.0 million multiple-year retrospective
contingent OIL insurance premium. LOE also was imparted by
start-up of
production in February 2008 from Bass Lite and Northwest Nansen,
the acquisition of MGOM in January 2008, and the impact of the
additional Permian Basin assets acquired at year-end 2007, which
are long-lived and typically carry a higher
per-unit LOE.
Severance and ad valorem tax for 2008 increased
approximately $5.1 million to $18.2 million from
$13.1 million for 2007 due to increased severance as a
result of higher oil prices and increased production
43
from the drilling and completion of additional wells and our
acquisition of additional interests in the Permian Basin.
Transportation expense for 2008 increased approximately
$6.2 million to $15.0 million from $8.8 million
for 2007 due primarily to commencement of production in 2008 at
Bass Lite, Northwest Nansen, Galveston 352 and High Island A467.
General and administrative expense (G&A)
for 2008 increased approximately $18.4 million to
$60.6 million from $42.2 million for 2007. The
increase was due primarily to an increase in stock compensation
expense of approximately $10.1 million to
$21.0 million from $10.9 million for 2007. This
increase was primarily due to long-term performance-based
restricted stock awarded during 2008. See Note 5.
Share-Based Compensation in the Notes to the Consolidated
Financial Statements in Part II, Item 8 of this Annual
Report on
Form 10-K
for more detail on stock grants. Beginning in 2008, that portion
of Lafayette and Midland office expense that is directly related
to production activity was classified as LOE, and we began
capitalizing stock compensation expense attributable to those
non-officer employees directly engaged in exploration,
development and acquisition activities. Capitalized G&A
related to our acquisition, exploration and development
activities increased $5.8 million to $19.8 million in
2008 from $14.0 million in 2007.
Depreciation, depletion, and amortization expense for
2008 increased approximately $83.0 million to
$467.3 million from $384.3 million for 2007, primarily
as a result of increased production from our acquisitions of
MGOM and additional interests in the Permian Basin properties,
and start-up
production from Bass Lite and Northwest Nansen.
Full cost ceiling test impairment of $575.6 million
was recognized in December 2008 as a result of the net
capitalized cost of our proved oil and gas properties exceeding
our ceiling limit. See Critical Accounting
Policies and Estimates Oil and Gas Properties
for more detail on this impairment.
Goodwill impairment of $295.6 million was recorded
in the fourth quarter of 2008 as a result of our annual
impairment test. The goodwill was originally recorded in
conjunction with the Forest Merger and the impairment is a
result of weakened economic conditions and a decline in our
stock price during the fourth quarter of 2008. See
Critical Accounting Policies and
Estimates Goodwill for more detail on this
impairment.
Other property impairment of $15.3 million was
recognized as a result of our annual impairment assessement
performed on our other property. See Critical
Accounting Policies and Estimates Other
Property for more detail on this impairment.
Net interest expense for 2008 increased approximately
$3.1 million to $56.4 million from $53.3 million
for 2007 due primarily to an increase in average daily debt
levels, partially offset by lower interest rates, and an
additional four months of interest expense related to our
8% Senior Notes due 2017 issued on April 30, 2007.
Capitalized interest increased to $9.7 million in 2008 from
$0.5 million in 2007.
Income before taxes and minority interest for 2008
decreased approximately $658.0 million to a loss of
$436.7 million from income of $221.3 million for 2007
due primarily to $886.5 million in impairments related to
our full cost ceiling test, other property and goodwill as
discussed above.
Provision for income taxes for 2008 reflected an
effective tax rate of 11.0% as compared to 34.9% for 2007. The
decrease in our effective tax rate was due primarily to a
permanent book-tax difference attributable to the goodwill
impairment discussed above. Excluding this permanent book-tax
difference, the effective rate for 2008 would have been 34.2%.
44
Year
Ended December 31, 2007 compared to Year Ended
December 31, 2006
Operating and Financial Results for the Year Ended
December 31, 2007
Compared to the Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
% change
|
|
|
|
(In thousands, except average sales price)
|
|
|
Summary Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
67,793
|
|
|
|
56,064
|
|
|
|
11,729
|
|
|
|
21
|
%
|
Oil (Mbbls)
|
|
|
4,214
|
|
|
|
3,237
|
|
|
|
977
|
|
|
|
30
|
%
|
Natural gas liquids (Mbbls)
|
|
|
1,200
|
|
|
|
838
|
|
|
|
362
|
|
|
|
43
|
%
|
Total natural gas equivalent (MMcfe)
|
|
|
100,273
|
|
|
|
80,512
|
|
|
|
19,761
|
|
|
|
25
|
%
|
Average daily production (MMcfe per day)
|
|
|
275
|
|
|
|
221
|
|
|
|
54
|
|
|
|
25
|
%
|
Hedging Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue gain
|
|
$
|
58,465
|
|
|
$
|
32,881
|
|
|
$
|
25,584
|
|
|
|
78
|
%
|
Oil revenue gain (loss)
|
|
|
(13,388
|
)
|
|
|
90
|
|
|
|
(13,478
|
)
|
|
|
(100
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total hedging revenue gain
|
|
$
|
45,077
|
|
|
$
|
32,971
|
|
|
$
|
12,106
|
|
|
|
37
|
%
|
Average Sales Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) realized(1)
|
|
$
|
7.88
|
|
|
$
|
7.37
|
|
|
$
|
0.51
|
|
|
|
7
|
%
|
Natural gas (per Mcf) unhedged
|
|
|
7.02
|
|
|
|
6.78
|
|
|
|
0.24
|
|
|
|
4
|
%
|
Oil (per Bbl) realized(1)
|
|
|
67.50
|
|
|
|
62.63
|
|
|
|
4.87
|
|
|
|
8
|
%
|
Oil (per Bbl) unhedged
|
|
|
70.68
|
|
|
|
62.61
|
|
|
|
8.07
|
|
|
|
13
|
%
|
Natural gas liquids (per Bbl) realized(1)
|
|
|
45.16
|
|
|
|
48.37
|
|
|
|
(3.21
|
)
|
|
|
(7
|
)%
|
Natural gas liquids (per Bbl) unhedged
|
|
|
45.16
|
|
|
|
48.37
|
|
|
|
(3.21
|
)
|
|
|
(7
|
)%
|
Total natural gas equivalent ($/Mcfe) realized(1)
|
|
|
8.71
|
|
|
|
8.15
|
|
|
|
0.56
|
|
|
|
7
|
%
|
Total natural gas equivalent ($/Mcfe) unhedged
|
|
|
8.26
|
|
|
|
7.74
|
|
|
|
0.52
|
|
|
|
7
|
%
|
Summary of Financial Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
534,537
|
|
|
$
|
412,967
|
|
|
$
|
121,570
|
|
|
|
29
|
%
|
Oil revenue
|
|
|
284,405
|
|
|
|
202,744
|
|
|
|
81,661
|
|
|
|
40
|
%
|
Natural gas liquids revenue
|
|
|
54,192
|
|
|
|
40,507
|
|
|
|
13,685
|
|
|
|
34
|
%
|
Other revenues
|
|
|
1,631
|
|
|
|
3,287
|
|
|
|
(1,656
|
)
|
|
|
(50
|
)%
|
Lease operating expense
|
|
|
152,627
|
|
|
|
91,592
|
|
|
|
61,035
|
|
|
|
67
|
%
|
Severance and ad valorem taxes
|
|
|
13,101
|
|
|
|
9,070
|
|
|
|
4,031
|
|
|
|
44
|
%
|
Transportation expense
|
|
|
8,794
|
|
|
|
5,077
|
|
|
|
3,717
|
|
|
|
73
|
%
|
General and administrative expense
|
|
|
42,151
|
|
|
|
33,622
|
|
|
|
8,529
|
|
|
|
25
|
%
|
Depreciation, depletion and amortization
|
|
|
384,321
|
|
|
|
292,180
|
|
|
|
92,141
|
|
|
|
32
|
%
|
Net interest expense
|
|
|
53,262
|
|
|
|
38,664
|
|
|
|
14,598
|
|
|
|
38
|
%
|
Income before taxes and minority interest
|
|
|
221,259
|
|
|
|
188,806
|
|
|
|
32,453
|
|
|
|
17
|
%
|
Provision for income taxes
|
|
|
77,324
|
|
|
|
67,344
|
|
|
|
9,980
|
|
|
|
15
|
%
|
Net income
|
|
|
143,934
|
|
|
|
121,462
|
|
|
|
22,472
|
|
|
|
19
|
%
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
1.52
|
|
|
$
|
1.14
|
|
|
$
|
0.38
|
|
|
|
33
|
%
|
Severance and ad valorem taxes
|
|
|
0.13
|
|
|
|
0.11
|
|
|
|
0.02
|
|
|
|
18
|
%
|
Transportation expense
|
|
|
0.09
|
|
|
|
0.06
|
|
|
|
0.03
|
|
|
|
50
|
%
|
General and administrative expense
|
|
|
0.42
|
|
|
|
0.42
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
3.83
|
|
|
|
3.63
|
|
|
|
0.20
|
|
|
|
6
|
%
|
|
|
|
(1) |
|
Average realized prices include the effects of hedges. |
Net income for 2007 was $143.9 million compared to
$121.5 million for 2006. The increase was primarily the
result of higher operating income attributable to 12 full months
of our ownership of the Forest Gulf of Mexico operations. Basic
and fully-diluted earnings per share for 2007 were $1.68 and
$1.67, respectively compared to $1.59 and $1.58, respectively
for 2006.
Net production Natural gas production increased 21% in
2007 to approximately 186 MMcf per day, compared to
approximately 154 MMcf per day in 2006. Oil production
increased 30% in 2007 to approximately 11,500 barrels per
day, compared to approximately 8,900 barrels per day in
2006. Natural gas
45
liquids increased 43% in 2007 and total overall production
increased 25% in 2007 to approximately 275 MMcfe per day,
compared to 221 MMcfe per day in 2006. Natural gas
production comprised approximately 68% of total production in
2007 compared to approximately 70% in 2006. The increase in
production and the oil to gas ratio resulted from the 12 full
months of ownership of the Forest Gulf of Mexico operations in
2007, compared to approximately 10 months in 2006. Our Gulf
of Mexico production in 2006 was adversely affected by the 2005
hurricane season, resulting in shut-in production and startup
delays. As a result of ongoing repairs to pipelines, facilities,
terminals and host facilities, most of the shut-in production
recommenced by the end of 2006. Specifically, 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.
Production in the Gulf of Mexico increased 25% to 89.1 Bcfe
for 2007 from 71.3 Bcfe for 2006, while onshore production
increased 22% to 11.2 Bcfe for 2007 from 9.2 Bcfe for
2006.
Natural gas, oil and NGL revenues for 2007 increased 33%
to $873.1 million compared to $656.2 million for 2006
as a result of increased pricing (approximately
$161.1 million, net of the effect of hedging), and
increased production (approximately $55.9 million).
During 2007, our revenues reflect a net recognized hedging gain
of approximately $45.1 million, comprised of
$46.7 million in favorable cash settlements and an
unrealized loss of $1.6 million related to the ineffective
portion not eligible for deferral under SFAS 133. This
compares to a net recognized hedging gain of approximately
$33.0 million for 2006, comprised of $11.3 million in
favorable cash settlements and an unrealized gain of
$4.2 million related to the ineffective portion not
eligible for deferral under SFAS 133. In addition, the fair
value of oil and natural gas derivatives acquired through the
Forest Merger resulted in a $17.5 million non-cash gain.
The fair value of the acquired derivatives was fully recognized
in 2006.
The effects of hedging activities on our average sales prices
were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedging
|
|
|
|
|
|
|
Realized
|
|
|
Unhedged
|
|
|
Gain (Loss)
|
|
|
% Change
|
|
|
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.88
|
|
|
$
|
7.02
|
|
|
$
|
0.86
|
|
|
|
12
|
%
|
Oil (per Bbl)
|
|
|
67.50
|
|
|
|
70.68
|
|
|
|
(3.18
|
)
|
|
|
(4
|
)%
|
Year Ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.37
|
|
|
$
|
6.78
|
|
|
$
|
0.59
|
|
|
|
9
|
%
|
Oil (per Bbl)
|
|
|
62.63
|
|
|
|
59.68
|
|
|
|
2.95
|
|
|
|
5
|
%
|
Lease operating expense in 2007 increased 67% to
$152.6 million from $91.6 million for 2006. The
increase primarily was attributable to 12 full months of
ownership of the Forest Gulf of Mexico shelf assets in 2007 as
compared to only 10 months in 2006, which carry a higher
operating cost than Mariners legacy deepwater operations.
Additionally, insurance premiums increased to $17.8 million
in 2007 from $10.5 million in 2006 as a result of
Hurricanes Katrina and Rita. Field costs increased
$7.6 million
year-over-year
in the Permian Basin with the addition of new productive wells
in the Spraberry field.
Severance and ad valorem taxes were $13.1 million
and $9.1 million for 2007 and 2006, respectively. The
increase was primarily attributable to increased production and
appreciated property values on the Permian Basin properties.
Transportation expense for 2007 was $8.8 million
compared to $5.1 million for 2006. The increase was
primarily due to increased production.
Depreciation, depletion and amortization
(DD&A) expense increased 32% to
$384.3 million from $292.2 million for 2007 and 2006,
respectively. The increase was a result of increased production
due to 12 full months of ownership of the Forest Gulf of Mexico
operations in 2007 as compared to only ten months in 2006, as
well as an increase in the
unit-of-production
depreciation, depletion and amortization rate. The per unit rate
increased 6% primarily due to an increase in deepwater
development activities and the Forest Gulf of Mexico operations,
as well as increased accretion of asset retirement obligations
due to the Forest Gulf of Mexico operations.
46
General and administrative expense totaled
$42.2 million for 2007, compared to $33.6 million for
2006. The increase was primarily related to a $4.4 million
increase in professional fees associated with system
enhancements, Sarbanes-Oxley compliance efforts, insurance claim
activities and an increase in health insurance costs. In
addition, overhead reimbursements billed or received from
working interest owners decreased $4.2 million from
$16.7 million in 2006 to $12.5 million in 2007.
Salaries and wages for 2007 remained relatively flat at
$35.2 million as the integration of the Forest Gulf of
Mexico operations has stabilized. The 2006 G&A expenses
included severance, retention, relocation and transition costs
of $2.6 million related to the acquisition of the Forest
Gulf of Mexico operations.
Capitalized G&A related to our acquisition, exploration and
development activities increased to $14.0 million in 2007
from $11.0 million for 2006.
G&A expense includes charges for share-based compensation
expense of $10.9 million for 2007 compared to
$10.2 million for 2006. For 2007 and 2006, $7.0 and
$6.6 million of share-based compensation expense,
respectively, resulted from amortization of the cost of
restricted stock granted at the closing of Mariners equity
private placement in March 2005 and the remaining related to the
amortization of new grants issued in 2007 and 2006 with vesting
periods of three to four years. The restricted stock related to
Mariners equity private placement fully vested by May 2006
and there will be no further charges related to those stock
grants.
Net interest expense increased to $53.3 million from
$38.7 million for 2007 and 2006, respectively. This
increase was primarily due to an increase in average debt levels
to $632.1 million for 2007 from $475.1 million for
2006. Debt increased during 2007 as a result of the April 2007
issuance of $300 million principal amount of 8% Senior
Notes due 2017, as well as continuing hurricane-related repair
and abandonment costs of $37.8 million. Additionally, the
amendment and restatement of the bank 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. Capitalized interest
decreased from $1.5 million in 2006 to $0.5 million in
2007.
Income before taxes and minority interest increased 17%
to $221.3 million from $188.8 million for 2007 and
2006, respectively. This increase was primarily the result of
higher operating income attributed to 12 full months of
ownership of the Forest Gulf of Mexico operations.
Provision for income taxes reflected an effective tax
rate of 34.9% for 2007 as compared to an effective tax rate of
35.7% for the comparable period of 2006.
Liquidity
and Capital Resources
Financial
Condition
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except ratios)
|
|
|
Current ratio(1)
|
|
|
0.9 to 1
|
|
|
|
0.8 to 1
|
|
Working capital deficit(2)
|
|
|
(50,611
|
)
|
|
|
(66,209
|
)
|
Total debt
|
|
|
1,170,000
|
|
|
|
779,000
|
|
Operating cash flow(3)
|
|
|
885,887
|
|
|
|
622,610
|
|
Interest expense, net of capitalization
|
|
|
56,398
|
|
|
|
54,665
|
|
Fixed-charge coverage ratio(4)
|
|
|
(5.63
|
)
|
|
|
4.93
|
|
Total cash and marketable securities less debt
|
|
|
(1,166,749
|
)
|
|
|
(760,411
|
)
|
Stockholders equity
|
|
|
1,120,320
|
|
|
|
1,391,018
|
|
Total liabilities to equity
|
|
|
2.03 to 1
|
|
|
|
1.22 to 1
|
|
|
|
|
(1) |
|
Current ratio is current assets divided by current liabilities. |
|
(2) |
|
Working capital deficit is the difference between current assets
and current liabilities. |
|
(3) |
|
Operating cash flow is net income before allowance for doubtful
accounts, deferred income tax, DD&A, amortization of
deferred financing costs, ineffectiveness of derivative
instruments, share-based compensation expense, impairments and
minority interest. See the following Reconciliation of
Non-GAAP Measure: Operating Cash Flow. |
47
|
|
|
(4) |
|
Fixed-charge coverage ratio is net earnings before taxes,
minority interest and fixed charges divided by fixed charges
(interest expense, net of capitalization plus amortization of
discounts.) |
Reconciliation
of Non-GAAP Measure: Operating Cash Flow
Operating cash flow (OCF) is not a financial or
operating measure under GAAP. The table below reconciles OCF to
related GAAP information. We believe that OCF 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
OCF should not be considered in isolation or as a substitute for
net income, operating income, cash flow from operating
activities or any other measure of financial performance
presented in accordance with GAAP or as a measure of our
profitability or liquidity.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Cash flow from operating activities (GAAP)
|
|
$
|
862,017
|
|
|
$
|
536,113
|
|
Changes in operating assets and liabilities
|
|
|
23,870
|
|
|
|
86,497
|
|
|
|
|
|
|
|
|
|
|
Operating cash flow (Non-GAAP)
|
|
$
|
885,887
|
|
|
$
|
622,610
|
|
|
|
|
|
|
|
|
|
|
2008 Cash
Flows
The following table presents cash payments for interest and
income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Cash payments for interest
|
|
$
|
62.2
|
|
|
$
|
49.1
|
|
|
$
|
28.8
|
|
Cash payments for income taxes
|
|
|
2.9
|
|
|
$
|
0.6
|
|
|
$
|
|
|
Net cash provided by operating activities increased by
$325.9 million to $862.0 million in 2008 from
$536.1 million in 2007. The increase was due to greater
operating revenue due to an increase in production of
48 MMcfe per day or $157.8 million and an increase in
the realized price per Mcfe of $1.83 or $217.1 million,
offset by higher lease operating expense.
As of December 31, 2008, the Company had a working capital
deficit of $50.6 million, including non-cash current
derivative assets and liabilities and deferred tax assets and
liabilities. In addition, working capital is negatively impacted
by accrued capital expenditures. This deficit will be funded by
cash flow from operating activities and our bank credit
facility, as needed.
Net cash flows used in investing activities increased to
$1,264.8 million in 2008 from $643.8 million in 2007
primarily due to the acquisition of MGOM (including
approximately $15.0 million of mid-stream assets reflected
in other property), increased capital expenditures attributable
to increased activity in our drilling programs, and an increase
in other property reflecting an investment of approximately
$34.6 million in office property. This increase was
partially offset by $31.8 million of restricted cash
released in January 2007 from the sale of our interest in Garden
Banks 422 (Cottonwood).
Net cash flows provided by financing activities were
$387.4 million for 2008 compared to $116.7 million for
2007. The increase was due primarily to $223.5 million
borrowed in January 2008 under our bank credit facility to
finance the purchase of MGOM and net increased borrowings of
$342.5 million for working capital requirements. This
increase was partially offset by the decrease attributable to
the proceeds received from our issuance in April 2007 of
$300.0 million aggregate principal amount of 8% senior
notes due in 2017.
2008 Uses of Capital. Our primary uses of
capital during 2008 were as follows:
|
|
|
|
|
funding capital expenditures (excluding hurricane repairs and
acquisitions) of approximately $1,005.7 million;
|
|
|
|
funding hurricane repairs and hurricane-related abandonment
expenditures of approximately $55.6 million;
|
|
|
|
paying interest of approximately $62.2 million;
|
48
|
|
|
|
|
funding the purchase of MGOM for approximately
$223.5 million; and
|
|
|
|
paying routine operating and administrative expenses.
|
2008 Capital Expenditures. The following table
presents major components of our capital expenditures during
2008 compared to 2007.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
Oil and natural gas development
|
|
$
|
588,456
|
|
|
$
|
448,577
|
|
Oil and natural gas property acquisitions
|
|
|
302,629
|
|
|
|
122,895
|
|
Oil and natural gas exploration
|
|
|
270,767
|
|
|
|
182,645
|
|
Leasehold acquisitions
|
|
|
152,567
|
|
|
|
24,189
|
|
Corporate expenditures and other
|
|
|
66,668
|
|
|
|
15,952
|
|
Proceeds from property conveyances(1)
|
|
|
|
|
|
|
(4,116
|
)
|
|
|
|
|
|
|
|
|
|
Total capital expenditures, net of proceeds from property
conveyances
|
|
$
|
1,381,087
|
|
|
$
|
790,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Proceeds from sale of Cottonwood project in 2006 (Garden Banks
244) were recorded as restricted cash of which
$5.0 million remained as of December 31, 2007 (Refer
to Restricted Cash under
Note 1. Summary of Significant Accounting
Policies in the Notes to the Consolidated Financial
Statements in Part II, Item 8 of this Annual Report on
Form 10-K). |
2008 Hurricane Expenditures. During the year
ended 2008, we incurred approximately $21.7 million in
hurricane expenditures resulting from Hurricanes Ike and Gustav,
of which $0.8 million were repairs and $20.9 were capital
expenditures. Since 2004, we have incurred approximately
$213.5 million in hurricane expenditures from Hurricanes
Ike, Gustav, Ivan, Katrina and Rita, of which $0.8 million
were repairs, $158.2 were capital expenditures and
$54.5 million were hurricane-related abandonment costs. Net
of our deductible of $14.4 million and insurance proceeds
received of $69.4 million, our insurance receivable at
December 31, 2008 was $35.3 million, of which an
estimated $13.1 million is expected to be settled within
the next 12 months. However, due to the magnitude of
Hurricanes Ike, Katrina and Rita and the complexity of the
insurance claims being processed by the insurance industry, the
timing of our ultimate insurance recovery cannot be assured. We
expect to maintain a potentially significant insurance
receivable through 2010 in respect of Hurricane Ike while we
actively pursue settlement of our claims to minimize the impact
to our working capital and liquidity. We expect to recover
substantially all of our outstanding OIL claims in respect of
Hurricanes Katrina and Rita by 2010. Any differences between our
insurance recoveries and insurance receivables will be recorded
as adjustments to our oil and natural gas properties.
2008 Sources of Capital. Our primary sources
of capital during 2008 were as follows:
|
|
|
|
|
cash flow from operations;
|
|
|
|
borrowings under our revolving bank credit facility; and
|
|
|
|
insurance proceeds.
|
Bank Credit Facility We have a secured
revolving credit facility with a group of banks pursuant to an
amended and restated credit agreement dated March 2, 2006,
as further amended. The credit facility matures January 31,
2012 and is subject to a borrowing base which is redetermined
periodically. As of December 31, 2008, maximum credit
availability under the facility was $1.0 billion, including
up $50.0 million in letters of credit, subject to a
borrowing base of $850.0 million scheduled to be
redetermined in February 2009. The redetermination was pending
on February 28, 2009, and we anticipate that it will occur
in March 2009.
The lenders redetermine the borrowing base periodically based
upon their evaluation of our oil and gas reserves and other
factors. Any increase in the borrowing base requires the consent
of all lenders. The outstanding principal balance of loans under
the credit facility may not exceed the borrowing base. If the
borrowing base falls below the sum of the amount borrowed and
uncollateralized letter of credit exposure,
49
then to the extent of the deficit, we must prepay borrowings and
cash collateralize letter of credit exposure, pledge additional
unencumbered collateral, repay borrowings and cash collateralize
letters of credit on an installment basis, or effect some
combination of these actions.
Borrowings under the bank credit facility bear interest at
either a LIBOR-based rate or a prime-based rate, at our option,
plus a specified margin. We must pay a commitment fee of 0.250%
to 0.375% per year on unused availability under the bank credit
facility. We have used borrowings under the facility to
facilitate the Forest Merger and acquisition of MGOM, and have
used and may use borrowings under the facility for general
corporate purposes.
As of December 31, 2008 and 2007, $570.0 million and
$179.0 million, respectively, were outstanding under the
credit facility, and the interest rates were 3.31% and 7.25%,
respectively. In addition, as of December 31, 2008 five
letters of credit totaling $7.2 million were outstanding,
of which $4.2 million was required for plugging and
abandonment obligations at certain of our offshore fields.
Payment and performance of our obligations under the credit
facility (including any obligations under commodity and interest
rate hedges entered into with facility lenders) are secured by
liens upon substantially all of our assets, and guaranteed by
our subsidiaries, other than MERI which is a co-borrower. We
also are subject to various restrictive covenants and other
usual and customary terms and conditions, including limits on
additional debt, cash dividends and other restricted payments,
liens, investments, asset dispositions, mergers and speculative
hedging. Financial covenants under the credit facility require
us to, among other things:
|
|
|
|
|
maintain a ratio of consolidated current assets plus the unused
borrowing base to consolidated current liabilities of not less
than 1.0 to 1.0; and
|
|
|
|
maintain a ratio of total debt to EBITDA (as defined in the
credit agreement) of not more than 2.5 to 1.0.
|
We were in compliance with the financial covenants under the
bank credit facility as of December 31, 2008. Our breach of
these covenants would be an event of default, after which the
lenders could terminate their lending obligations and accelerate
maturity of any outstanding indebtedness under the credit
facility which then would become due and payable in full. An
unrescinded acceleration of maturity under the bank credit
facility would constitute an event of default under our senior
notes described below, which could trigger acceleration of
maturity of the indebtedness evidenced by the senior notes.
Senior Notes Mariner has outstanding the
following two issues of debt issued in registered transactions,
referred to collectively as the Notes:
|
|
|
|
|
$300 million principal amount of
71/2% Senior
Notes due 2013 issued in March 2006 (the
71/2% Notes)
|
|
|
|
$300 million principal amount of 8% Senior Notes due
2017 issued in April 2007 (the 8% Notes)
|
The Notes are senior unsecured obligations of Mariner, rank
senior in right of payment to any future subordinated
indebtedness, rank equally in right of payment with each other
and with Mariners existing and future senior unsecured
indebtedness and are effectively subordinated in right of
payment to Mariners senior secured indebtedness, including
its obligations under its bank credit facility, to the extent of
the collateral securing such indebtedness, and to all existing
and future indebtedness and other liabilities of any
non-guarantor subsidiaries.
The Notes are jointly and severally guaranteed on a senior
unsecured basis by Mariners existing and future domestic
subsidiaries. In the future, the guarantees may be released or
terminated under certain circumstances. Each subsidiary
guarantee ranks senior in right of payment to any future
subordinated indebtedness of the guarantor subsidiary, ranks
equally in right of payment to all existing and future senior
unsecured indebtedness of the guarantor subsidiary and
effectively subordinate to all existing and future secured
indebtedness of the guarantor subsidiary, including its
guarantees of indebtedness under Mariners bank credit
facility, to the extent of the collateral securing such
indebtedness.
Interest on the
71/2% Notes
is payable on April 15 and October 15 of each year. The
71/2% Notes
mature on April 15, 2013. Interest on the 8% Notes is
payable on May 15 and November 15 of each year, beginning
November 15, 2007. The 8% Notes mature on May 15,
2017. There is no sinking fund for the Notes.
50
The Company may redeem the
71/2% Notes
at any time before April 15, 2010 and the 8% Notes at
any time before May 15, 2012, in each case at a price equal
to the principal amount redeemed plus a make-whole premium,
using a discount rate of the Treasury rate plus 0.50% and
accrued but unpaid interest. Beginning on the dates indicated
below, the Company may redeem the Notes from time to time, in
whole or in part, at the prices set forth below (expressed as
percentages of the principal amount redeemed) plus accrued but
unpaid interest:
|
|
|
71/2% Notes
|
|
8% Notes
|
|
April 15, 2010 at 103.750%
|
|
May 15, 2012 at 104.000%
|
April 15, 2011 at 101.875%
|
|
May 15, 2013 at 102.667%
|
April 15, 2012 and thereafter at 100.000%
|
|
May 15, 2014 at 101.333%
|
|
|
May 15, 2015 and thereafter at 100.000%
|
In addition, before April 15, 2009, the Company may redeem
up to 35% of the
71/2% Notes
with the proceeds of equity offerings at a price equal to
107.50% of the principal amount of the
71/2% Notes
redeemed. Before May 15, 2010, the Company may redeem up to
35% of the 8% Notes with the proceeds of equity offerings
at a price equal to 108% of the principal amount of the
8% Notes redeemed plus accrued but unpaid interest.
If the Company experiences a change of control (as defined in
each of the indentures governing the Notes), subject to certain
exceptions, the Company must give holders of the Notes the
opportunity to sell to the Company their Notes, in whole or in
part, at a purchase price equal to 101% of the principal amount,
plus accrued and unpaid interest and liquidated damages to the
date of purchase.
The Company and its restricted subsidiaries are subject to
certain negative covenants under each of the indentures
governing the Notes. The indentures limit the ability of the
Company and each of its restricted subsidiaries to, among other
things:
|
|
|
|
|
make investments;
|
|
|
|
incur additional indebtedness or issue preferred stock;
|
|
|
|
create certain liens;
|
|
|
|
sell assets;
|
|
|
|
enter into agreements that restrict dividends or other payments
from its subsidiaries to itself;
|
|
|
|
consolidate, merge or transfer all or substantially all of its
assets;
|
|
|
|
engage in transactions with affiliates;
|
|
|
|
pay dividends or make other distributions on capital stock or
subordinated indebtedness; and
|
|
|
|
create unrestricted subsidiaries.
|
Costs associated with the
71/2% Notes
offering were approximately $8.5 million, excluding
discounts of $3.8 million. Costs associated with the
8% Notes offering included aggregate underwriting discounts
of approximately $5.3 million and offering expenses of
approximately $1.3 million.
Future Uses of Capital. Our identified needs
for liquidity in the future are as follows:
|
|
|
|
|
funding future capital expenditures;
|
|
|
|
funding hurricane repairs and hurricane-related abandonment
operations;
|
|
|
|
financing any future acquisitions that Mariner may identify;
|
|
|
|
paying routine operating and administrative expenses; and
|
|
|
|
paying other commitments comprised largely of cash settlement of
hedging obligations and debt service.
|
2009 Capital Expenditures. In the second half
of 2008, a world-wide economic recession and oversupply of
natural gas in North America led to an unprecedented decline in
oil and gas prices. However, the inflated cost of oil field
services resulting from sustained historically high commodity
prices did not decrease
51
in line with the decline in commodity prices. The prospect of
continued low commodity prices and disproportionately high
service costs has constrained the industrys capital
reinvestment and undermined rates of return in new projects,
particularly those in areas characterized by high costs or long
reserve lives. In order to manage our capital program within
expected cash flows, we tentatively have reduced our 2009
capital budget by more than 50% from 2008. Refer to Item.
1. Business Impact of Worldwide Financial Crisis and
Lower Commodity Prices on Capital Program in Part I
of this Annual Report on
Form 10-K
for an outline of our planned 2009 activities in the Permian
Basin and Gulf of Mexico.
We anticipate that our base operating capital expenditures for
2009 will be approximately $430.6 million (excluding
hurricane-related expenditures and acquisitions), with
significant potential for increase or decrease depending upon
drilling success and cash flow experience during the year.
Approximately 48% of the base operating capital program is
planned to be allocated to development activities, 45% to
exploration activities, and the remainder to other items
(primarily capitalized overhead and interest). In addition, we
estimate to incur additional hurricane-related costs of
$36.1 million during 2009 related to Hurricane Ike, that we
believe is substantially covered under applicable insurance.
Complete recovery or settlement is not expected to occur during
the next 12 months.
Obligations
and Commitments
Consolidated Contractual Obligations The
following table presents a summary of our consolidated
contractual obligations and commercial commitments as of
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Period
|
|
|
|
Total
|
|
|
2009
|
|
|
2010-2011
|
|
|
2012-2013
|
|
|
Thereafter
|
|
|
|
(In thousands)
|
|
|
Debt obligations(1)
|
|
$
|
1,170,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
870,000
|
|
|
$
|
300,000
|
|
Interest obligations(2)
|
|
|
355,523
|
|
|
|
65,367
|
|
|
|
130,734
|
|
|
|
78,545
|
|
|
|
80,877
|
|
Operating leases
|
|
|
21,646
|
|
|
|
2,240
|
|
|
|
5,031
|
|
|
|
4,498
|
|
|
|
9,877
|
|
Abandonment liabilities
|
|
|
408,244
|
|
|
|
82,364
|
|
|
|
73,393
|
|
|
|
83,205
|
|
|
|
169,282
|
|
Seismic obligations
|
|
|
3,000
|
|
|
|
2,333
|
|
|
|
667
|
|
|
|
|
|
|
|
|
|
Capital accrual obligations
|
|
|
195,833
|
|
|
|
195,833
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OIL Theoretical Withdrawal(3)
|
|
|
36,000
|
|
|
|
6,391
|
|
|
|
14,586
|
|
|
|
15,023
|
|
|
|
|
|
Rig commitment
|
|
|
183,882
|
|
|
|
124,450
|
|
|
|
59,432
|
|
|
|
|
|
|
|
|
|
Other liabilities(4)
|
|
|
99,091
|
|
|
|
99,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash commitments
|
|
$
|
2,473,219
|
|
|
$
|
578,069
|
|
|
$
|
283,843
|
|
|
$
|
1,051,271
|
|
|
$
|
560,036
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
As of December 31, 2008, we incurred debt obligations under
our bank credit facility, the Notes. |
|
(2) |
|
Interest obligations represent interest due on the bank credit
facility and the Notes at 7.5% and 8%. Future interest
obligations under our bank credit facility are uncertain, due to
the variable interest rate on fluctuating balances. Based on a
3.31% weighted average interest rate on amounts outstanding
under our bank credit facility as of December 31, 2008, our
cash payments for interest would be $18.9 million annually
for 2009 through 2011 and $1.6 million in 2012. |
|
(3) |
|
We accrued approximately $36.0 million as of
December 31, 2008, for an insurance premium contingency
related to our membership in OIL. As part of our membership, we
are obligated to pay a withdrawal premium if we elect to
withdraw from OIL. We do not anticipate withdrawing from OIL;
however, due to the contingency, OIL calculates a potential
withdrawal premium annually based on past losses and we accrue a
liability for the potential premium. OIL requires smaller
members to provide a letter of credit or other acceptable
security in favor of OIL to secure payment of the withdrawal
premium. Acceptable security has included a letter of credit or
a security agreement pursuant to which a member grants OIL a
security interest in certain claim proceeds payable by OIL to
the member. We anticipate that we will enter into such a
security agreement, granting to OIL a security interest in a
portion of our Hurricane Ike claim proceeds payable by OIL. We
expect to have the ability to replace the security agreement
with a letter of credit or other acceptable security in favor of
OIL. |
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Other liabilities include accrued LOE of $30.9 million,
accrued liabilities of $11.0 million, gas balancing of
$15.9 million, oil and gas payable of $24.5 million,
accrued compensation of $10.7 million, other G&A of
$4.2 million and other liabilities for $1.9 million. |
Adequacy
of Capital Sources and Liquidity
Future Capital Resources. Our anticipated
sources of liquidity in the future are as follows:
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cash flow from operations in future periods;
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proceeds under our bank credit facility;
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proceeds from insurance policies relating to hurricane
repairs; and
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proceeds from future capital markets transactions as needed.
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In 2009, we intend to tailor our operating capital program
(exclusive of hurricane-related expenditures and acquisitions)
within our projected operating cash flow so that our operating
capital requirements are largely self-funding under normal
commodity price assumptions. We anticipate using proceeds under
our bank credit facility only for working capital needs or
acquisitions and not generally to fund our operations. We would
generally expect to fund future acquisitions on a case by case
basis through a combination of bank debt and capital markets
activities. Based on our current operating plan and assumed
price case, our expected cash flow from operations and continued
access to our bank credit facility allows us ample liquidity to
conduct our operations as planned for the foreseeable future.
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. 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
bank credit facility are largely dependent on our level of
estimated proved reserves and current oil and natural gas
prices. If either our estimated proved reserves or commodity
prices decrease, amounts available to us to borrow under our
bank credit facility could be reduced. If our cash flows are
less than anticipated or amounts available for borrowing are
reduced, we may be forced to defer planned capital expenditures.
In addition, the recent worldwide financial and credit crisis
may adversely affect our liquidity. We may be unable to obtain
adequate funding under our bank credit facility because our
lending counterparties may be unwilling or unable to meet their
funding obligations, or because our borrowing base under the
facility may be decreased as the result of a redetermination,
reducing it due to lower oil or natural gas prices, operating
difficulties, declines in reserves or other reasons. If funding
is not available as needed, or is available only on unfavorable
terms, we may be unable to meet our obligations as they come due
or we may be unable to implement our business strategies or
otherwise take advantage of business opportunities or respond to
competitive pressures.
Off-Balance
Sheet Arrangements
Mariners bank credit facility has a letter of credit
subfacility of up to $50.0 million that is included as a
use of the borrowing base. As of December 31, 2008, five
such letters of credit totaling $7.2 million were
outstanding.
Fair
Value Measurement
We determine fair value for our natural gas and crude oil
costless collars using fair value measurements based on the
Black-Scholes valuation model, adjusted for credit risk. The
credit risk adjustment for collar liabilities is based on our
credit quality and the credit risk adjustment for collar assets
is based on the credit quality of our counterparty. Such
valuations have historically approximated our exit price for
such derivatives. We validate the fair value measurements of our
collars using a Black-Scholes pricing model using observable
market data, to the extent available, and unobservable or
adjusted data, if observable data is not available or is not
representative of fair value. As of December 31, 2008, our
internal calculations of fair value were determined using market
data.
53
We determine the fair value of our natural gas and crude oil
fixed price swaps by reference to forward pricing curves for
natural gas and oil futures contracts. The difference between
the forward price curve and the contractual fixed price is
discounted to the measurement date using a credit-risk adjusted
discount rate. The credit risk adjustment for swap liabilities
is based on our credit quality and the credit risk adjustment
for swap assets is based on the credit quality of our
counterparty. Our fair value determinations of our swaps have
historically approximated our exit price for such derivatives.
Due to unavailability of observable volatility data input or use
of adjusted implied volatility for our collars, we have
determined that fair value measurements of all of our collars
are categorized as level 3 in accordance with
SFAS No. 157, Fair Value Measurements
(SFAS 157) (see Note 9, Fair Value
Measurements in the Notes to Consolidated Financial
Statements in Part II, Item 8 of this Annual Report on
Form 10-K). As of December 31, 2008 we had no collars
outstanding. We have determined that the fair value methodology
described above for our swaps is consistent with observable
market inputs and have categorized our swaps as level 2 in
accordance with SFAS 157.
During the twelve months ended December 31, 2008, we
recorded an asset for the increase in the fair value of our
derivative financial instruments of $154.2 million,
principally due to the decrease in natural gas and oil commodity
prices below our swap prices and floor prices in our collars.
The increase was comprised of an increase in accumulated other
comprehensive income of approximately $165.7 million, net
of income taxes of $91.3 million, approximately
$98.8 million of unfavorable cash hedging settlements
during the period reflected in natural gas and oil revenues, and
an unrealized non-cash loss due to hedging ineffectiveness under
SFAS 133 of approximately $2.0 million reflected in
natural gas revenues.
We expect the continued volatility of natural gas and oil
commodity prices to have a material impact on the fair value of
our derivatives positions. It is our intent to hold all of our
derivatives positions to maturity such that realized gains or
losses are generally recognized in income when the hedged
natural gas or oil is produced and sold. While the derivatives
settlements may decrease (or increase) our effective price
realized, the ultimate settlement of our derivatives positions
is not expected to materially adversely affect our liquidity,
results of operations or cash flows.
Critical
Accounting Policies and Estimates
Our discussion and analysis of Mariners financial
condition and results of operations are based upon Consolidated
Financial Statements that have been prepared in accordance with
GAAP. The preparation of these Consolidated 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 Consolidated Financial Statements. See
Note 1. Summary of Significant Accounting
Policies in the Notes to the Consolidated Financial
Statements in Part II, Item 8 of this Annual Report on
Form 10-K.
We analyze our estimates, including those related to oil and gas
revenues; oil and gas properties; fair value of derivative
instruments; goodwill; abandonment liabilities; income taxes;
commitments and contingencies; depreciation, depletion and
amortization; share-based compensation; and full-cost ceiling
calculation. Our estimates are based on historical experience
and various 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 Consolidated Financial Statements.
Oil
and Gas Properties
Our 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, including
certain G&A costs. G&A costs associated with
production, operations, marketing and general corporate
activities are expensed as incurred. The capitalized costs,
coupled with our estimated asset retirement obligations recorded
in accordance with Statement of Financial Accounting Standards
(SFAS) No. 143, Accounting for Asset
Retirement Obligations (SFAS 143), are
included in the amortization base and amortized to expense using
the unit-of-production method. Amortization is calculated based
on estimated proved oil and gas reserves. Proceeds from the sale
or disposition of oil and gas properties are applied to
54
reduce net capitalized costs unless the sale or disposition
causes a significant change in the relationship between costs
and the estimated value of proved reserves.
Capitalized costs (net of accumulated depreciation, depletion
and amortization and deferred income taxes) of proved oil and
gas properties are subject to a ceiling. The ceiling limits
these costs to an amount equal to the present value, discounted
at 10%, of estimated future net cash flows from estimated proved
reserves less estimated future operating and development costs,
abandonment costs (net of salvage value) and estimated related
future income taxes. The full-cost ceiling limitation is
calculated using natural gas and oil prices in effect as of the
balance sheet date and is adjusted for basis or
location differentials. Price is held constant over the life of
the reserves.
We use derivative financial instruments that qualify for cash
flow hedge accounting under SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities, (SFAS 133) to hedge against
the volatility of natural gas prices. In accordance with
Securities and Exchange Commission (SEC) guidelines,
we include estimated future cash flows from our hedging program
in our ceiling test calculation. If net capitalized costs
related to proved properties exceed the ceiling limit, the
excess is impaired and recorded in the Consolidated Statements
of Operations.
At December 31, 2008, the net capitalized cost of proved
oil and gas properties exceeded the ceiling limit due to a
decline in oil and gas commodity prices during the fourth
quarter 2008 and the Company recorded a non-cash ceiling test
impairment of $575.6 million during the fourth quarter. The
writedown would have been $695.6 million if we had not used
hedge adjusted prices for the volumes that were subject to
hedges. The ceiling limit of our proved reserves was calculated
based upon quoted market prices of $5.71 per Mcfe for gas and
$44.61 per barrel for oil, adjusted for market differentials for
the year ended December 31, 2008. If commodity prices
continue to deteriorate during the first quarter of 2009, we may
be required to record a ceiling test impairment which could be
material to our financial position and results of operations.
Estimated
Proved Reserves
Our most significant financial estimates are based on estimates
of proved oil and natural gas reserves. Estimates of proved
reserves are key components in determining 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. 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
Company, L.P.
Unproved
Properties
The costs associated with unevaluated properties and properties
under development are not initially included in the full-cost
amortization base. These costs relate to unproved leasehold
acreage and include costs for seismic data, wells and production
facilities in progress and wells pending determination. Interest
is capitalized on the costs in unproved properties while in the
development stage. Unevaluated leasehold costs are transferred
to the amortization base once determination has been made or
upon expiration of a lease. Geological and geophysical costs,
including
3-D seismic
data costs, are included in the full-cost amortization base as
incurred when such costs cannot be associated with specific
unevaluated properties for which we own a direct interest.
Seismic data costs are associated with specific unevaluated
properties if the seismic data is acquired for the purpose of
evaluating acreage or trends covered by a leasehold interest
owned by us. We make this determination based on an analysis of
leasehold and seismic maps and discussions with our Chief
Exploration Officer. Geological and geophysical costs included
in unproved properties are transferred to the full-cost
amortization base along with the associated leasehold costs on a
specific project basis. Costs associated with wells in progress
and wells pending determination are transferred to the
amortization base once a determination is made whether or not
proved reserves can be assigned to the property. Costs of dry
holes are transferred to the amortization base immediately upon
determination that the well is unsuccessful. All items included
in our unevaluated property balance are assessed on a quarterly
basis for possible impairment or reduction in value.
55
Abandonment
Liability
In accordance with SFAS 143, we record the fair value of a
liability for the legal obligation to retire an asset in the
period in which it is incurred and capitalize the corresponding
cost by increasing the carrying amount of the related long-lived
asset. Upon our adoption of SFAS 143, we recorded an asset
retirement obligation to reflect our legal obligations related
to future plugging and abandonment of its oil and natural gas
wells. 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, the difference is
recognized in Oil and Gas Properties.
To estimate the fair value of an asset retirement obligation, we
employ a present value technique, which reflects certain
assumptions, including our credit-adjusted risk-free interest
rate, the estimated settlement date of the liability and the
estimated current cost to settle the liability. Changes in
timing or to the original estimate of cash flows will result in
changes to the carrying amount of the liability.
Other
Property
Other property and equipment is recorded at cost and consists of
real estate, IT equipment, office furniture and fixtures,
leasehold improvements and gas gathering systems. Acquisitions
and betterments are capitalized; maintenance and repairs are
expensed as incurred. Depreciation of other property and
equipment is provided on a straight-line basis over their
estimated useful lives, which range from three to twenty-two
years. Per SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets
(SFAS 144), we assess other property for
impairment when events indicate the carrying value exceeds fair
value. As a result of our SFAS 144 assessment performed at
December 31, 2008, an impairment of $15.3 million was
recorded related to office property.
Goodwill
We account for goodwill in accordance with
SFAS No. 142 Goodwill and Other Intangible
Assets (SFAS 142). SFAS 142 requires
goodwill to be tested for impairment on an annual basis and
between annual tests when events or circumstances indicate a
potential impairment. In a purchase transaction, goodwill
represents the excess of the purchase price over the estimated
fair value of the assets acquired net of the fair value of
liabilities assumed. We follow the full cost method of
accounting and all of our oil and gas properties are located in
the United States. For the purpose of performing an impairment
test, we have determined that we have one reporting unit. Our
goodwill impairment reviews consist of a two-step process. The
first step is to determine the fair value of our reporting unit
and compare it to the carrying value of the related net assets.
Fair value is determined based on our estimates of market
values. If this fair value exceeds the carrying value no further
analysis or goodwill write-down is required. The second step is
required if the fair value of the reporting unit is less than
the carrying value of the net assets. In this step the implied
fair value of the reporting unit is allocated to all the
underlying assets and liabilities, including both recognized and
unrecognized tangible and intangible assets, based on their fair
values. If necessary, goodwill is then written-down to its
implied fair value.
We perform our goodwill test annually on November 30 and more
often if circumstances require. Amounts recorded in goodwill
relate to the excess purchase price paid in association with the
Forest Merger. See Note 2. Acquisitions and
Dispositions Forest Gulf of Mexico Operation
in the Notes to the Consolidated Financial Statements in
Part II, Item 8 of this Annual Report on
Form 10-K.
In connection with our annual impairment test on
November 30, 2008, we performed a step one impairment
analysis. As a result of weakened economic conditions and a
decline in our stock price during the fourth quarter of 2008,
the carrying value of our reporting unit exceeded the fair value
and a step two analysis was required to determine the
impairment. Our fair value estimates in step two were developed
using a weighted average cost of capital (WACC) of
12.0% and a control premium of 25.0%. A 1.0% increase and
decrease of the WACC would have changed the fair value by (3.7%)
and 4.0% respectively. We allocated the estimated fair value
determined using these assumptions to the identifiable tangible
and intangible assets and liabilities of our reporting unit
based on their respective values. This allocation indicated no
residual value for goodwill and we recorded approximately
$295.6 million of goodwill impairment in continuing
operations as of December 31, 2008. We had previously
determined that there was no impairment loss in continuing
operations
56
as of December 31, 2007 and 2006, respectively. In 2007,
goodwill decreased as a result of changes in the book and tax
basis related to the Forest Merger.
Income
Taxes
Our provision for taxes includes both state and federal taxes.
The Company records its federal income taxes in accordance with
SFAS No. 109, Accounting for Income Taxes
(SFAS 109) 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 basis of assets and liabilities. Deferred
tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those
temporary differences and carry forwards are expected to be
recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in
the period that includes the enactment date. Valuation
allowances are established when necessary to reduce deferred tax
assets to the amount more likely than not to be recovered.
Effective January 1, 2007, we adopted FASB Interpretation
No. 48, Accounting for Uncertainty in Income Taxes
(an interpretation of FASB Statement No. 109)
(FIN 48). This interpretation clarified the
accounting for uncertainty in income taxes recognized in the
financial statements by prescribing a recognition threshold and
measurement attribute for a tax position taken or expected to be
taken in a tax return. We apply significant judgment in
evaluating our tax positions and estimating our provision for
income taxes. During the ordinary course of business, there are
many transactions and calculations for which the ultimate tax
determination is uncertain. The actual outcome of these future
tax consequences could differ significantly from these
estimates, which could impact our financial position, results of
operations and cash flows. We do not have uncertain tax
positions outstanding and, as such, did not recorded a
FIN 48 liability for the years ended December 31, 2008
and 2007.
Additionally, 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.
Derivative
Financial Instruments
The Company utilizes derivative instruments 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 and fixed-price
crude oil and natural gas purchase and sale commitments. Such
agreements are accounted for as cash flow hedges in accordance
with SFAS 133. Gains and losses resulting from these
transactions, recorded at market value, are deferred and
recorded in Accumulated Other Comprehensive Income as
appropriate, until recognized as operating income in the
Companys Consolidated Statements of Operations as the
physical production hedged by the contracts is delivered. The
Company presents the fair value of its derivatives on a net
basis in accordance with FASB Interpretation No. 39
Offsetting of Amounts Related to Certain Contracts an
interpretation of APB Opinion No. 10 and FASB Statement
No. 105 (FIN 39).
We are required to assess the effectiveness of all our
derivative contracts at inception and at every quarter-end. If
open contracts cease to qualify for hedge accounting,
mark-to-market accounting is utilized and changes in the fair
value of open contracts are recognized in the Consolidated
Statements of Operations. Mark-to-market accounting may cause
volatility in Net Income. Fair value is assessed, measured and
estimated by obtaining forward commodity pricing, credit
adjusted risk-free interest rates and estimated volatility
factors. In addition, forward price curves and estimates of
future volatility factors are used to assess and measure the
effectiveness of our open contracts at the end of each period.
The fair values we report in our Consolidated Financial
Statements change as estimates are revised to reflect actual
results, changes in market conditions or other factors, many of
which are beyond our control.
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.
57
The conditions to be met for a derivative instrument to qualify
as a cash flow hedge are the following: (i) the item to be
hedged exposes the Company to price risk; (ii) the
derivative reduces the risk exposure and is designated as a
hedge at the time the derivative contract is entered into; and
(iii) at the inception of the hedge and throughout the
hedge period there is a high correlation of changes in the
market value of the derivative instrument and the fair value of
the underlying item being hedged.
When the designated item associated with a derivative instrument
matures, is sold, extinguished or terminated, derivative gains
or losses are recognized as part of the gain or loss on sale or
settlement of the underlying item. When a derivative instrument
is associated with an anticipated transaction that is no longer
expected to occur or if correlation no longer exists, the gain
or loss on the derivative is recognized in income to the extent
the future results have not been offset by the effects of price
or interest rate changes on the hedged item since the inception
of the hedge.
Revenue
Recognition
Oil revenues are recognized when production is sold to a
purchaser at a fixed or determinable price, and delivery has
occurred and title has transferred. Natural gas and NGLs
revenues are recorded using the entitlement method. Under the
entitlement method, revenue is recorded when title passes based
on the Companys net interest or nominated deliveries. The
Company records its entitled share of revenues based on entitled
volumes and contracted sales prices. The sales price for natural
gas, crude oil and NGLs are adjusted for revenue deductions. The
revenue deductions are based on contractual or historical data
and do not require significant judgment. Subsequently, these
revenue deductions are adjusted to reflect actual charges based
on third party documents. Historically, these adjustments have
been insignificant. Since there is a ready market for natural
gas, crude oil and NGLs, the Company sells the majority of its
products soon after production at various locations at which
time title and risk of loss pass to the buyer. As a result, the
Company maintains a minimum amount of product inventory in
storage.
Gas imbalances occur when Mariner sells more or less than its
entitled ownership percentage of total gas production. Any
amount received in excess (overproduction) of Mariners
share is treated as a liability. If Mariner receives less than
it is entitled, the shortage (underproduction) is recorded as a
receivable. Imbalances are reduced either by subsequent
recoupment of
over-and-under
deliveries or by cash settlement, as required by applicable
contracts. Production imbalances are recorded 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 exists. Mariners gas imbalances are
not material, as oil and natural gas volumes sold are not
significantly different from its share of production
Share-Based
Compensation Expense
We account for share-based compensation in accordance with the
fair value recognition provisions of SFAS No. 123(R),
Share-Based Payment (SFAS 123(R)).
Under the fair value recognition provisions of SFAS 123(R),
share-based compensation cost is measured at the grant date
based on the value of the award and is recognized as expense
over the vesting period. We use the Black-Scholes option pricing
model to determine the fair value of options on the grant date,
which requires judgment in estimating the expected life of the
option and the expected volatility of our stock. We use a Monte
Carlo simulation to estimate the fair value of restricted stock
granted in 2008 under our stock incentive plans long-term
performance-based restricted stock program.
Recent
Accounting Pronouncements
On December 31, 2008, the SEC issued the final rule,
Modernization of Oil and Gas Reporting
(Final Rule). The Final Rule adopts revisions to the
SECs oil and gas reporting disclosure requirements and is
effective for annual reports on
Forms 10-K
for years ending on or after December 31, 2009. Early
adoption of the Final Rule is prohibited. The revisions are
intended to provide investors with a more meaningful and
comprehensive understanding of oil and gas reserves to help
investors evaluate their investments in oil and gas companies.
The amendments are also designed to modernize the oil and gas
disclosure requirements to align
58
them with current practices and changes in technology. Revised
requirements in the SECs Final Rule include, but are not
limited to:
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Oil and gas reserves must be reported using the average price
over the prior 12 month period, rather than year-end prices;
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Companies will be allowed to report, on an optional basis,
probable and possible reserves;
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Non-traditional reserves, such as oil and gas extracted from
coal and shales, will be included in the definition of oil
and gas producing activities;
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Companies will be permitted to use new technologies to determine
proved reserves, as long as those technologies have been
demonstrated empirically to lead to reliable conclusions with
respect to reserve volumes;
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Companies will be required to disclose, in narrative form,
additional details on their proved undeveloped reserves (PUDs),
including the total quantity of PUDs at year end, any material
changes to PUDs that occurred during the year, investments and
progress made to convert PUDs to developed oil and gas reserves
and an explanation of the reasons why material concentrations of
PUDs in individual fields or countries have remained undeveloped
for five years or more after disclosure as PUDs;
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Companies will be required to report the qualifications and
measures taken to assure the independence and objectivity of any
business entity or employee primarily responsible for preparing
or auditing the reserves estimates.
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We are currently evaluating the potential impact of the Final
Rule. The SEC is discussing the Final Rule with the FASB staff
to align FASB accounting standards with the new SEC rules. These
discussions may delay the required compliance date. Absent any
change in the effective date, we will begin complying with the
disclosure requirements in our annual report on
Form 10-K
for the year ended December 31, 2009.
In October 2008, the FASB issued Staff Position
(FSP)
No. 157-3,
Determining the Fair Value of a Financial Asset When the
Market for That Asset Is Not Active
(FSP 157-3).
FSP 157-3
applies to financial assets within the scope of accounting
pronouncements that require or permit fair value measurements in
accordance with SFAS No. 157, Fair Value
Measurements (SFAS 157) and clarifies the
application of SFAS 157 in a market that is not active.
This FSP also provides an example to illustrate key
considerations in determining the fair value of a financial
asset when the market for that financial asset is not active.
This FSP was effective upon issuance, including prior periods
for which financial statements have not been issued. Revisions
resulting from a change in the valuation technique or its
application are accounted for as a change in accounting estimate
according to SFAS No. 154 Accounting Changes and
Error Corrections. The adoption of
FSP 157-3
did not have a material effect on the Companys results of
operations, financial position or cash flows.
In May 2008, the FASB issued SFAS No. 162, The
Hierarchy of Generally Accepted Accounting Principles
(SFAS 162). SFAS 162 is intended to
improve financial reporting by identifying a consistent
framework, or hierarchy, for selecting accounting principles to
be used in preparing financial statements that are presented in
conformity with GAAP for nongovernmental entities. The FASB
believes that the GAAP hierarchy should be directed to entities
because it is the entity (not its auditor) that is responsible
for selecting accounting principles for financial statements
that are presented in conformity with GAAP. This statement
became effective on November 15, 2008 following the
SECs approval of the Public Company Accounting Oversight
Board amendments to AU Section 411, The Meaning of
Present Fairly in Conformity With Generally Accepted Accounting
Principles. The adoption of SFAS 162 did not have a
material effect on our results of operations, financial position
or cash flows.
In April 2008, the FASB issued FSP
No. 142-3,
Determination of the Useful Life of Intangible
Assets
(FSP 142-3).
FSP 142-3
amends the factors that should be considered in developing
renewal or extension assumptions used to determine the useful
life of a recognized intangible asset under FASB Statement
No. 142, Goodwill and Other Intangible Assets.
FSP 142-3
is effective for financial statements issued after
December 15, 2008. The adoption of
FSP 142-3
did not have a material effect on our results of operations,
financial position, or cash flows.
59
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities an amendment of FASB Statement
No. 133 (SFAS 161). SFAS 161 is
intended to improve financial reporting about derivative
instruments and hedging activities by requiring enhanced
disclosures to enable investors to better understand their
effects on an entitys financial position, financial
performance, and cash flows. SFAS 161 is effective for
financial statements issued for fiscal years and interim periods
beginning after November 15, 2008, with early application
encouraged. SFAS 161 also improves transparency about the
location and amounts of derivative instruments in an
entitys financial statements; how derivative instruments
and related hedged items are accounted for under
SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities
(SFAS 133); and how derivative instruments and
related hedged items affect its financial position, financial
performance, and cash flows. SFAS 161 achieves these
improvements by requiring disclosure of the fair values of
derivative instruments and their gains and losses in a tabular
format. It also provides more information about an entitys
liquidity by requiring disclosure of derivative features that
are credit-risk related. Finally, it requires cross-referencing
within footnotes to enable financial statement users to locate
important information about derivative instruments. We currently
are evaluating the effect the adoption of SFAS 161 will
have on our results of operations, financial position and cash
flows.
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations
(SFAS 141(R)), which replaces SFAS 141.
SFAS 141(R) establishes principles and requirements for how
an acquirer recognizes and measures in its financial statements
the identifiable assets acquired, the liabilities assumed, any
non-controlling interest in the acquiree and the goodwill
acquired. The Statement also establishes disclosure requirements
which will enable users to evaluate the nature and financial
effects of the business combination. SFAS 141(R) is
effective for fiscal years beginning after December 15,
2008. The adoption of SFAS 141(R) will have an impact on
accounting for business combinations with the effect dependent
upon acquisitions at that time.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements an amendment of Accounting Research
Bulletin No. 51 (SFAS 160),
which establishes accounting and reporting standards for
ownership interests in subsidiaries held by parties other than
the parent, the amount of consolidated net income attributable
to the parent and to the noncontrolling interest, changes in a
parents ownership interest and the valuation of retained
non-controlling equity investments when a subsidiary is
deconsolidated. The Statement also establishes reporting
requirements that provide sufficient disclosures that clearly
identify and distinguish between the interests of the parent and
the interests of the non-controlling owners. SFAS 160 is
effective for fiscal years beginning after December 15,
2008. The adoption of SFAS 160 is not expected to have a
material effect on our results of operations, financial position
or cash flows.
During February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and Financial
Liabilities (SFAS 159). SFAS 159
permits entities to choose to measure many financial instruments
and certain other items at fair value that are not currently
required to be measured at fair value, and thereby mitigate
volatility in reported earnings caused by measuring related
assets and liabilities differently without having to apply
complex hedge accounting provisions. This Statement also
establishes presentation and disclosure requirements designed to
facilitate comparisons between entities that choose different
measurement attributes for similar types of assets and
liabilities. SFAS 159 was effective for the Company as of
January 1, 2008. SFAS 159 did not have an impact on
the Companys Consolidated Financial Statements as the
Company elected not to measure at fair value additional
financial assets and liabilities not already required to be
measured at fair value.
In September 2006, the FASB issued SFAS 157, which
establishes guidelines for measuring fair value and expands
disclosures regarding fair value measurements. SFAS 157
does not require any new fair value measurements but rather it
eliminates inconsistencies in the guidance found in various
prior accounting pronouncements. SFAS 157 was effective for
fiscal years beginning after November 15, 2007. In February
2008, the FASB issued FSP
No. FAS 157-2,
Effective Date of FASB Statement No. 157, which
delayed the effective date of SFAS 157 for nonfinancial
assets and nonfinancial liabilities, except for items that are
recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually). This FSP is
effective for financial statements issued during fiscal years
beginning after November 15, 2008, and interim periods
within those fiscal years for items within the scope of this
FSP. Accordingly, our adoption of
60
SFAS 157 was limited to financial assets and liabilities,
which primarily affects the valuation of the Companys
derivative contracts. The adoption of SFAS 157 with respect
to financial assets and liabilities did not have a material
impact on our net asset values (see Note 11 to the
Consolidated Financial Statements in Part II, Item 8
of this Annual Report on
Form 10-K).
The Company is still in the process of evaluating SFAS 157
with respect to its effect on nonfinancial assets and
liabilities and therefore has not yet determined the impact that
it will have on its financial statements upon full adoption in
2009. Nonfinancial assets and liabilities for which the Company
has not applied the provisions of SFAS 157 include its
asset retirement obligations and assets held for future sale
when applicable.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market
Risk.
|
Commodity
Prices and Related Hedging Activities
Our major market risk exposure continues to be the prices
applicable to our natural gas and oil production. The sales
price of our production is primarily driven by the prevailing
market price. Historically, prices received for our natural gas
and oil production have been volatile and unpredictable.
Hypothetically, if production levels were to remain at 2008
levels, a 10% increase in commodity prices from those as of
December 31, 2008 would increase our cash flow by
approximately $134.9 million for the year ended
December 31, 2009.
The energy markets have historically been very volatile, and we
can reasonably expect that oil and gas prices will be subject to
wide fluctuations in the future. In an effort to reduce the
effects of the volatility of the price of oil and natural gas on
our operations, management has adopted a policy of hedging oil
and natural gas prices from time to time primarily through the
use of commodity price swap agreements and costless collar
arrangements. While the use of these hedging arrangements limits
the downside risk of adverse price movements, it also limits
future gains from favorable movements. In addition, forward
price curves and estimates of future volatility are used to
assess and measure the ineffectiveness of our open contracts at
the end of each period. If open contracts cease to qualify for
hedge accounting, the mark-to-market change in fair value is
recognized in oil and natural gas revenue in the Consolidated
Statements of Operations. Not qualifying for hedge accounting
and cash flow hedge designation will cause volatility in Net
Income. The fair values we report in our Consolidated Financial
Statements change as estimates are revised to reflect actual
results, changes in market conditions or other factors, many of
which are beyond our control.
Hedge gains and losses are recorded by commodity type in oil and
natural gas revenues in the Consolidated Statements of
Operations. The effects on our oil and gas revenues from our
hedging activities were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Cash (Loss) Gain on Settlements
|
|
$
|
(98,814
|
)
|
|
$
|
46,732
|
|
|
$
|
11,273
|
|
(Loss) Gain on Hedge Ineffectiveness(1)
|
|
|
(1,995
|
)
|
|
|
(1,655
|
)
|
|
|
4,175
|
|
Non-cash Gain on hedges acquired(2)
|
|
|
|
|
|
|
|
|
|
|
17,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(100,809
|
)
|
|
$
|
45,077
|
|
|
$
|
32,971
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Unrealized (loss) gain recognized in natural gas revenue related
to the ineffective portion of open contracts that are not
eligible for deferral under SFAS 133 Accounting for
Derivative Instruments and Hedging Activities, due
primarily to the basis differentials between the contract price
and the indexed price at the point of sale. |
|
(2) |
|
In 2006, relating to the hedges acquired through the Forest
transaction. |
61
As of December 31, 2008, the Company had the following
hedging activity outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average
|
|
|
Fair Value
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Fixed Price
|
|
|
Asset
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1 December 31, 2009
|
|
|
31,642,084
|
|
|
$
|
8.48
|
|
|
$
|
74,709
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1 December 31, 2009
|
|
|
2,172,210
|
|
|
$
|
76.15
|
|
|
|
47,220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
121,929
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007, the Company had the following
hedging activity outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average
|
|
|
Fair Value
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Fixed Price
|
|
|
Asset/(Liability)
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Natural Gas (MMBtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1 December 31, 2008
|
|
|
40,583,847
|
|
|
$
|
8.46
|
|
|
$
|
27,672
|
|
January 1 December 31, 2009
|
|
|
31,642,084
|
|
|
$
|
8.48
|
|
|
|
(1,494
|
)
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1 December 31, 2008
|
|
|
2,263,552
|
|
|
$
|
78.99
|
|
|
|
(31,219
|
)
|
January 1 December 31, 2009
|
|
|
2,172,210
|
|
|
$
|
76.15
|
|
|
|
(23,158
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
(28,199
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
Costless Collars
|
|
Quantity
|
|
|
Floor
|
|
|
Cap
|
|
|
Asset/(Liability)
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Natural Gas (MMBtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1 December 31, 2008
|
|
|
12,347,000
|
|
|
$
|
7.83
|
|
|
$
|
14.60
|
|
|
$
|
7,201
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1 December 31, 2008
|
|
|
1,195,495
|
|
|
$
|
61.66
|
|
|
$
|
86.81
|
|
|
|
(11,259
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(4,058
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of February 20, 2009, there were no hedging transactions
entered into subsequent to December 31, 2008 except as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
Period
|
|
Instrument Type
|
|
|
Quantity
|
|
|
Price
|
|
|
Natural Gas (MMbtus) 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1 December 31
|
|
|
Fixed Price Swaps
|
|
|
|
19,665,000
|
|
|
$
|
6.19 Fixed
|
|
Crude Oil (Bbls) 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
February 1 December 31
|
|
|
Fixed Price Swaps
|
|
|
|
977,047
|
|
|
$
|
51.46 Fixed
|
|
We have reviewed the financial strength of our counterparties
and believe the credit risk associated with these swaps and
costless collars to be minimal. Hedges with counterparties that
are lenders under our bank credit facility are secured under the
bank credit facility.
As of December 31, 2008, the Company expects to realize
within the next 12 months approximately $121.9 million
in net gains resulting from hedging activities that are
currently recorded in accumulated other comprehensive income.
These hedging gains are expected to be realized as an increase
of $47.2 million to oil revenues and an increase of
$74.7 million to natural gas revenues. On January 29,
2008, the Company liquidated crude oil fixed price swaps in
respect of 977 thousand barrels in exchange for a cash payment
of $10.1 million and installment payments of
$13.5 million to be received monthly throughout 2009.
62
Interest
Rates
Borrowings under our bank credit facility mature on
January 31, 2012 and bear interest at either a LIBOR-based
rate or a prime-based rate, at our option, plus a specified
margin. Both options expose us to risk of earnings loss due to
changes in market rates. We have not entered into interest rate
hedges that would mitigate such risk. During 2008, the interest
rate on our outstanding bank debt was 3.31%. If the balance of
our bank debt at December 31, 2008 were to remain constant,
a 10% increase in market interest rates would decrease our cash
flow by approximately $1.9 million for the year ended
December 31, 2008.
|
|
Item 8.
|
Financial
Statements and Supplementary
Data.
|
Index to
Financial Statements
63
MANAGEMENTS
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including Mariners chief executive officer and
chief financial officer, is responsible for establishing and
maintaining adequate internal control over financial reporting
for Mariner. Mariners internal control system was designed
to provide reasonable assurance to Mariners management and
directors regarding the preparation and fair presentation of
published financial statements. Because of its inherent
limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the
risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with policies or
procedures may deteriorate.
Management conducted an evaluation of the effectiveness of
internal control over financial reporting based on the
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on this evaluation, management concluded that
Mariners internal control over financial reporting was
effective as of December 31, 2008. Deloitte &
Touche LLP, Mariners independent auditor for 2008, has
issued an attestation report on Mariners internal control
over financial reporting that is included in the accompanying
Report of Independent Registered Public Accounting Firm.
|
|
|
/s/ SCOTT
D. JOSEY
|
|
/s/ JOHN
H. KARNES
|
Scott D. Josey,
Chairman of the Board,
Chief Executive Officer and President
|
|
John H. Karnes,
Senior Vice President,
Chief Financial Officer and Treasurer
|
Houston, Texas
March 2, 2009
64
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Mariner Energy, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of
Mariner Energy, Inc. and subsidiaries (the Company)
as of December 31, 2008 and 2007, and the related
consolidated statements of operations, stockholders
equity, and cash flows for each of the three years in the period
ended December 31, 2008. We also have audited the
Companys internal control over financial reporting as of
December 31, 2008, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway
Commission. The Companys management is responsible for
these financial statements, for maintaining effective internal
control over financial reporting, and for its assessment of the
effectiveness of internal control over financial reporting
included in the accompanying Managements Report on
Internal Control over Financial Reporting. Our responsibility is
to express an opinion on these financial statements and an
opinion on the Companys internal control over financial
reporting based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement and whether effective internal
control over financial reporting was maintained in all material
respects. Our audits of the financial statements included
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. Our audit of internal control over financial
reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a
material weakness exists, and testing and evaluating the design
and operating effectiveness of internal control based on the
assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We
believe that our audits provide a reasonable basis for our
opinions.
A companys internal control over financial reporting is a
process designed by, or under the supervision of, the
companys principal executive and principal financial
officers, or persons performing similar functions, and effected
by the companys board of directors, management, and other
personnel to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of the inherent limitations of internal control over
financial reporting, including the possibility of collusion or
improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a
timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting
to future periods are subject to the risk that the controls may
become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may
deteriorate.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Mariner Energy, Inc. and subsidiaries as of
December 31, 2008 and 2007, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2008, in conformity with
accounting principles generally accepted in the United States of
America. Also, in our opinion, the Company maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2008, based on the criteria
established in Internal Control Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
DELOITTE &
TOUCHE LLP
Houston, Texas
March 2, 2009
65
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except share data)
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3,251
|
|
|
$
|
18,589
|
|
Receivables, net of allowances of $3,868 and $2,449, respectively
|
|
|
219,920
|
|
|
|
157,774
|
|
Insurance receivables
|
|
|
13,123
|
|
|
|
26,683
|
|
Derivative financial instruments
|
|
|
121,929
|
|
|
|
11,863
|
|
Intangible assets
|
|
|
2,353
|
|
|
|
17,209
|
|
Prepaid expenses and other
|
|
|
14,377
|
|
|
|
10,630
|
|
Deferred tax asset
|
|
|
|
|
|
|
6,232
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
374,953
|
|
|
|
248,980
|
|
Property and Equipment:
|
|
|
|
|
|
|
|
|
Proved oil and gas properties, full-cost method
|
|
|
4,448,146
|
|
|
|
3,118,273
|
|
Unproved properties, not subject to amortization
|
|
|
201,121
|
|
|
|
40,455
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas properties
|
|
|
4,649,267
|
|
|
|
3,158,728
|
|
Other property and equipment
|
|
|
53,115
|
|
|
|
15,545
|
|
Accumulated depreciation, depletion and amortization:
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
|
(1,767,028
|
)
|
|
|
(751,127
|
)
|
Other properties
|
|
|
(5,477
|
)
|
|
|
(2,952
|
)
|
Total accumulated depreciation, depletion and amortization
|
|
|
(1,772,505
|
)
|
|
|
(754,079
|
)
|
Total property and equipment, net
|
|
|
2,929,877
|
|
|
|
2,420,194
|
|
Restricted Cash
|
|
|
|
|
|
|
5,000
|
|
Goodwill
|
|
|
|
|
|
|
295,598
|
|
Insurance Receivables
|
|
|
22,132
|
|
|
|
56,924
|
|
Derivative Financial Instruments
|
|
|
|
|
|
|
691
|
|
Other Assets, net of amortization
|
|
|
65,831
|
|
|
|
56,248
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
3,392,793
|
|
|
$
|
3,083,635
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
3,837
|
|
|
$
|
1,064
|
|
Accrued liabilities
|
|
|
107,815
|
|
|
|
96,936
|
|
Accrued capital costs
|
|
|
195,833
|
|
|
|
159,010
|
|
Deferred income tax
|
|
|
23,148
|
|
|
|
|
|
Abandonment liability
|
|
|
82,364
|
|
|
|
30,985
|
|
Accrued interest
|
|
|
12,567
|
|
|
|
7,726
|
|
Derivative financial instruments
|
|
|
|
|
|
|
19,468
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
425,564
|
|
|
|
315,189
|
|
Long-Term Liabilities:
|
|
|
|
|
|
|
|
|
Abandonment liability
|
|
|
325,880
|
|
|
|
191,021
|
|
Deferred income tax
|
|
|
319,766
|
|
|
|
343,948
|
|
Derivative financial instruments
|
|
|
|
|
|
|
25,343
|
|
Long-term debt
|
|
|
1,170,000
|
|
|
|
779,000
|
|
Other long-term liabilities
|
|
|
31,263
|
|
|
|
38,115
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
1,846,909
|
|
|
|
1,377,427
|
|
Commitments and Contingencies (see Note 8)
|
|
|
|
|
|
|
|
|
Minority Interest
|
|
|
|
|
|
|
1
|
|
Stockholders Equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $.0001 par value; 20,000,000 shares
authorized, no shares issued and outstanding at
December 31, 2008 and December 31, 2007
|
|
|
|
|
|
|
|
|
Common stock, $.0001 par value; 180,000,000 shares
authorized, 88,846,073 shares issued and outstanding at
December 31, 2008; 180,000,000 shares authorized,
87,229,312 shares issued and outstanding at
December 31, 2007
|
|
|
9
|
|
|
|
9
|
|
Additional
paid-in-capital
|
|
|
1,071,347
|
|
|
|
1,054,089
|
|
Accumulated other comprehensive income/(loss)
|
|
|
78,181
|
|
|
|
(22,576
|
)
|
Accumulated retained earnings
|
|
|
(29,217
|
)
|
|
|
359,496
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,120,320
|
|
|
|
1,391,018
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY
|
|
$
|
3,392,793
|
|
|
$
|
3,083,635
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes to the Consolidated Financial
Statements
are an integral part of these financial statements
66
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands except share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
742,370
|
|
|
$
|
534,537
|
|
|
$
|
412,967
|
|
Oil
|
|
|
419,878
|
|
|
|
284,405
|
|
|
|
202,744
|
|
Natural gas liquids
|
|
|
85,715
|
|
|
|
54,192
|
|
|
|
40,507
|
|
Other revenues
|
|
|
52,544
|
|
|
|
1,631
|
|
|
|
3,287
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
1,300,507
|
|
|
|
874,765
|
|
|
|
659,505
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
231,645
|
|
|
|
152,627
|
|
|
|
91,592
|
|
Severance and ad valorem taxes
|
|
|
18,191
|
|
|
|
13,101
|
|
|
|
9,070
|
|
Transportation expense
|
|
|
14,996
|
|
|
|
8,794
|
|
|
|
5,077
|
|
General and administrative expense
|
|
|
60,613
|
|
|
|
42,151
|
|
|
|
33,622
|
|
Depreciation, depletion and amortization
|
|
|
467,265
|
|
|
|
384,321
|
|
|
|
292,180
|
|
Full cost ceiling test impairment
|
|
|
575,607
|
|
|
|
|
|
|
|
|
|
Goodwill impairment
|
|
|
295,598
|
|
|
|
|
|
|
|
|
|
Other property impairment
|
|
|
15,252
|
|
|
|
|
|
|
|
|
|
Other miscellaneous expense
|
|
|
3,052
|
|
|
|
5,061
|
|
|
|
494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
1,682,219
|
|
|
|
606,055
|
|
|
|
432,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING (LOSS) INCOME
|
|
|
(381,712
|
)
|
|
|
268,710
|
|
|
|
227,470
|
|
Other Income/(Expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
1,362
|
|
|
|
1,403
|
|
|
|
985
|
|
Interest expense, net of amounts capitalized
|
|
|
(56,398
|
)
|
|
|
(54,665
|
)
|
|
|
(39,649
|
)
|
Other income
|
|
|
|
|
|
|
5,811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) Income Before Taxes and Minority Interest
|
|
|
(436,748
|
)
|
|
|
221,259
|
|
|
|
188,806
|
|
Benefit (Provision) for Income Taxes
|
|
|
48,223
|
|
|
|
(77,324
|
)
|
|
|
(67,344
|
)
|
Minority Interest
|
|
|
(188
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET (LOSS) INCOME
|
|
$
|
(388,713
|
)
|
|
$
|
143,934
|
|
|
$
|
121,462
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per share basic
|
|
$
|
(4.44
|
)
|
|
$
|
1.68
|
|
|
$
|
1.59
|
|
Net (loss) income per share diluted
|
|
$
|
(4.44
|
)
|
|
$
|
1.67
|
|
|
$
|
1.58
|
|
Weighted average shares outstanding basic
|
|
|
87,491,385
|
|
|
|
85,645,199
|
|
|
|
76,352,666
|
|
Weighted average shares outstanding diluted
|
|
|
87,491,385
|
|
|
|
86,125,811
|
|
|
|
76,810,466
|
|
The accompanying Notes to the Consolidated Financial
Statements
are an integral part of these financial statements
67
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Comprehensive
|
|
|
Accumulated
|
|
|
Total
|
|
|
|
Common
|
|
|
Stock
|
|
|
Paid-In-
|
|
|
Income/
|
|
|
Retained
|
|
|
Stockholders
|
|
|
|
Stock
|
|
|
Amount
|
|
|
Capital
|
|
|
(Loss)
|
|
|
Earnings
|
|
|
Equity
|
|
|
|
(In thousands)
|
|
|
Balance at December 31, 2005
|
|
|
35,615
|
|
|
$
|
4
|
|
|
$
|
160,705
|
|
|
$
|
(41,473
|
)
|
|
$
|
94,100
|
|
|
$
|
213,336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares issued Forest transaction
|
|
|
50,637
|
|
|
|
5
|
|
|
|
886,142
|
|
|
|
|
|
|
|
|
|
|
|
886,147
|
|
Common shares issued restricted stock
|
|
|
907
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury stock bought and cancelled on same day
|
|
|
(808
|
)
|
|
|
|
|
|
|
(14,027
|
)
|
|
|
|
|
|
|
|
|
|
|
(14,027
|
)
|
Forfeiture of restricted stock
|
|
|
(27
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of unearned compensation
|
|
|
|
|
|
|
|
|
|
|
9,247
|
|
|
|
|
|
|
|
|
|
|
|
9,247
|
|
Share-based compensation expense stock options
|
|
|
|
|
|
|
|
|
|
|
980
|
|
|
|
|
|
|
|
|
|
|
|
980
|
|
Stock options exercised
|
|
|
52
|
|
|
|
|
|
|
|
718
|
|
|
|
|
|
|
|
|
|
|
|
718
|
|
Merger adjustments
|
|
|
|
|
|
|
|
|
|
|
158
|
|
|
|
|
|
|
|
|
|
|
|
158
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
121,462
|
|
|
|
121,462
|
|
Change in fair value of derivative hedging
instruments net of income taxes of $35,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63,139
|
|
|
|
|
|
|
|
63,139
|
|
Hedge settlements reclassified to income net of
income taxes of $11,540
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,431
|
|
|
|
|
|
|
|
21,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84,570
|
|
|
|
121,462
|
|
|
|
206,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
86,376
|
|
|
$
|
9
|
|
|
$
|
1,043,923
|
|
|
$
|
43,097
|
|
|
$
|
215,562
|
|
|
$
|
1,302,591
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares issued restricted stock
|
|
|
906
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury stock bought and cancelled on same day
|
|
|
(72
|
)
|
|
|
|
|
|
|
(1,553
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,553
|
)
|
Forfeiture of restricted stock
|
|
|
(45
|
)
|
|
|
|
|
|
|
(907
|
)
|
|
|
|
|
|
|
|
|
|
|
(907
|
)
|
Amortization of unearned compensation
|
|
|
|
|
|
|
|
|
|
|
10,375
|
|
|
|
|
|
|
|
|
|
|
|
10,375
|
|
Share-based compensation expense stock options
|
|
|
|
|
|
|
|
|
|
|
1,422
|
|
|
|
|
|
|
|
|
|
|
|
1,422
|
|
Stock options exercised
|
|
|
64
|
|
|
|
|
|
|
|
829
|
|
|
|
|
|
|
|
|
|
|
|
829
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
143,934
|
|
|
|
143,934
|
|
Change in fair value of derivative hedging
instruments net of income taxes of ($52,385)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(94,935
|
)
|
|
|
|
|
|
|
(94,935
|
)
|
Hedge settlements reclassified to income net of
income taxes of $15,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,262
|
|
|
|
|
|
|
|
29,262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(65,673
|
)
|
|
|
143,934
|
|
|
|
78,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
87,229
|
|
|
$
|
9
|
|
|
$
|
1,054,089
|
|
|
$
|
(22,576
|
)
|
|
$
|
359,496
|
|
|
$
|
1,391,018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares issued restricted stock
|
|
|
1,734
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury stock bought and cancelled on same day
|
|
|
(144
|
)
|
|
|
|
|
|
|
(4,313
|
)
|
|
|
|
|
|
|
|
|
|
|
(4,313
|
)
|
Forfeiture of restricted stock
|
|
|
(29
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of unearned compensation
|
|
|
|
|
|
|
|
|
|
|
20,327
|
|
|
|
|
|
|
|
|
|
|
|
20,327
|
|
Share-based compensation expense stock options
|
|
|
|
|
|
|
|
|
|
|
502
|
|
|
|
|
|
|
|
|
|
|
|
502
|
|
Stock options exercised
|
|
|
56
|
|
|
|
|
|
|
|
742
|
|
|
|
|
|
|
|
|
|
|
|
742
|
|
Comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(388,713
|
)
|
|
|
(388,713
|
)
|
Change in fair value of derivative hedging
instruments net of income taxes of ($35,891)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(64,918
|
)
|
|
|
|
|
|
|
(64,918
|
)
|
Hedge settlements reclassified to income net of
income taxes of $91,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
165,675
|
|
|
|
|
|
|
|
165,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100,757
|
|
|
|
(388,713
|
)
|
|
|
(287,956
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
88,846
|
|
|
$
|
9
|
|
|
$
|
1,071,347
|
|
|
$
|
78,181
|
|
|
$
|
(29,217
|
)
|
|
$
|
1,120,320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes to the Consolidated Financial
Statements
are an integral part of these financial statements
68
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Cash flow from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(388,713
|
)
|
|
$
|
143,934
|
|
|
$
|
121,462
|
|
Adjustments to reconcile net income to net cash provided by
|
|
|
|
|
|
|
|
|
|
|
|
|
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax
|
|
|
(49,403
|
)
|
|
|
77,324
|
|
|
|
67,344
|
|
Depreciation, depletion and amortization
|
|
|
467,265
|
|
|
|
384,321
|
|
|
|
295,292
|
|
Ineffectiveness of derivative instruments
|
|
|
1,995
|
|
|
|
1,655
|
|
|
|
(4,175
|
)
|
Full cost ceiling test impairment
|
|
|
575,607
|
|
|
|
|
|
|
|
|
|
Goodwill impairment
|
|
|
295,598
|
|
|
|
|
|
|
|
|
|
Other property impairment
|
|
|
15,252
|
|
|
|
|
|
|
|
|
|
Share-based compensation
|
|
|
21,017
|
|
|
|
10,890
|
|
|
|
10,229
|
|
MMS royalty relief and other
|
|
|
(52,731
|
)
|
|
|
4,486
|
|
|
|
226
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(63,015
|
)
|
|
|
(9,805
|
)
|
|
|
(12,972
|
)
|
Insurance receivables
|
|
|
47,839
|
|
|
|
(22,606
|
)
|
|
|
(55,690
|
)
|
Prepaid expenses and other
|
|
|
(1,853
|
)
|
|
|
(23,406
|
)
|
|
|
18,626
|
|
Accounts payable and accrued liabilities
|
|
|
(6,841
|
)
|
|
|
(30,680
|
)
|
|
|
(169,819
|
)
|
Net realized loss on derivative contracts acquired
|
|
|
|
|
|
|
|
|
|
|
6,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
862,017
|
|
|
|
536,113
|
|
|
|
277,161
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions and additions to oil and gas properties
|
|
|
(1,220,067
|
)
|
|
|
(674,740
|
)
|
|
|
(540,374
|
)
|
Additions to other property and equipment
|
|
|
(49,717
|
)
|
|
|
|
|
|
|
(2,207
|
)
|
Property conveyances
|
|
|
|
|
|
|
4,130
|
|
|
|
33,829
|
|
Purchase price adjustment
|
|
|
|
|
|
|
|
|
|
|
(20,808
|
)
|
Restricted cash designated for investment
|
|
|
5,000
|
|
|
|
26,830
|
|
|
|
(31,830
|
)
|
Minority interest
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(1,264,784
|
)
|
|
|
(643,779
|
)
|
|
|
(561,390
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt and working capital acquired from Forest Energy Resources,
Inc.
|
|
|
|
|
|
|
|
|
|
|
(176,200
|
)
|
Repayment of term note
|
|
|
|
|
|
|
|
|
|
|
(4,000
|
)
|
Credit facility borrowings
|
|
|
1,268,000
|
|
|
|
564,000
|
|
|
|
682,000
|
|
Credit facility repayments
|
|
&nbs |