e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
|
|
|
þ
|
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the fiscal year ended
December 31,
2009
|
OR
|
o
|
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
Commission file number 1-32747
MARINER ENERGY, INC.
(Exact name of registrant as
specified in its charter)
|
|
|
Delaware
|
|
86-0460233
|
(State or other jurisdiction
of
incorporation or organization)
|
|
(I.R.S. Employer
Identification Number)
|
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:
|
|
|
Title of Each Class
|
|
Name of Each Exchange on Which Registered
|
|
Common Stock, $.0001 par value
Rights to Purchase Preferred Stock
|
|
New York Stock Exchange
New York Stock Exchange
|
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 whether the registrant has submitted
electronically and posted on its corporate Web site, if
any, every Interactive Data File required to be submitted and
posted pursuant to Rule 405 of Regulation S-T during the
preceding 12 months (or for such shorter period that the
registrant was required to submit and post such
files). Yes o 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. o
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):
|
|
|
|
|
|
|
Large accelerated
filer þ
|
|
Accelerated
filer o
|
|
Non-accelerated
filer o
|
|
Smaller reporting
company o
|
|
|
|
|
(Do not check if a smaller reporting company)
|
|
|
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, 2009 was approximately
$1,150,891,162 based on the closing sale price of $11.75 per
share as reported by the New York Stock Exchange on
June 30, 2009. The number of shares of common stock of the
registrant issued and outstanding on February 22, 2010 was
101,780,353.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of registrants Proxy Statement relating to the
Annual Meeting of Stockholders to be held May 5, 2010 are
incorporated by reference into Part III of this
Form 10-K.
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:
|
|
|
|
|
the volatility of oil and natural gas prices;
|
|
|
|
discovery, estimation, development and replacement of oil and
natural gas reserves;
|
|
|
|
cash flow, liquidity and financial position;
|
|
|
|
business strategy;
|
|
|
|
amount, nature and timing of capital expenditures, including
future development costs;
|
|
|
|
availability and terms of capital;
|
|
|
|
timing and amount of future production of oil and natural gas;
|
|
|
|
availability of drilling and production equipment;
|
|
|
|
operating costs and other expenses;
|
|
|
|
prospect development and property acquisitions;
|
|
|
|
risks arising out of our hedging transactions;
|
|
|
|
marketing of oil and natural gas;
|
|
|
|
competition in the oil and natural gas industry;
|
|
|
|
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;
|
|
|
|
governmental regulation of the oil and natural gas industry;
|
|
|
|
environmental liabilities;
|
|
|
|
developments in oil-producing and natural gas-producing
countries;
|
|
|
|
uninsured or underinsured losses in our oil and natural gas
operations;
|
|
|
|
risks related to our level of indebtedness;
|
|
|
|
risks related to significant acquisitions or other strategic
transactions, such as failure to realize expected benefits or
objectives for future operations; and
|
|
|
|
foreign currency risks.
|
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 four principal areas:
|
|
|
|
|
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.
|
|
|
|
Gulf Coast, where, in December 2009, we acquired interests
predominantly in the Vicksburg, Queen City and Deep Frio
producing trends in South Texas. As is the case with our Permian
Basin operation, we expect the relatively lower risk and cost of
exploiting our Gulf Coast properties to further counterbalance
those of our Gulf of Mexico deepwater operations.
|
|
|
|
Gulf of Mexico Deepwater, where we have actively conducted
exploration and development projects since 1996 in water depths
ranging from approximately 1,300 feet up to
7,100 feet. Employing our experienced geoscientists, rich
seismic database, and extensive subsea tieback expertise, we
have participated in more than 79 deepwater wells. Our deepwater
exploration operation targets larger potential reserve
accumulations than are generally accessible onshore or on the
Gulf of Mexico shelf.
|
|
|
|
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 exploration and exploitation 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 onshore operations, as
well as for expansion into new operating areas.
|
We also are investigating a variety of shale and unconventional
resource opportunities in the United States and Canada, such as
green field leasing, joint ventures and acquisitions. In 2009,
we added a team of approximately 10 geoscientists experienced in
unconventional resource plays in those areas. We also formed a
Canadian subsidiary which opened an office in Calgary. We
initially are targeting liquids-rich plays with
3
relatively low entry costs in the Rocky Mountains, South Texas
and the Permian Basin, including unconventional potential of our
existing asset base. During 2009, we acquired working interests
in approximately 80,000 (43,000 net) acres in unconventional
plays in North Dakota, Wyoming, Arkansas and New Mexico. Our
secured revolving credit facility currently limits our
investment in our Canadian operation to $25.0 million.
During 2009, we produced approximately 126.5 Bcfe and our
average daily production rate was 347 MMcfe. At
December 31, 2009, we had 1.087 Tcfe of estimated
proved reserves, of which approximately 56% were onshore (47% in
the Permian Basin and 8% in the Gulf Coast), with the balance
offshore (15% in the Gulf of Mexico deepwater and 29% on the
Gulf of Mexico shelf); 53% were natural gas; and 47% were oil
and natural gas liquids (NGLs). Approximately 66% 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 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
Onshore Acquisition On December 31,
2009, we acquired the reorganized subsidiaries and operations of
Edge Petroleum Corporation (Edge). The material
assets acquired consist primarily of (i) proved reserves
estimated by Ryder Scott Company, L.P. as of December 31,
2009 of 100.5 Bcfe, of which approximately 75% are
developed (consisting of 69% natural gas and 31% oil and NGLs),
81% are located in South Texas, and 44% are in the
Flores/Bloomberg field in Starr County, Texas,
(ii) approximately 60,000 net acres of undeveloped
leasehold, primarily in Texas and New Mexico, and
(iii) deferred tax assets of approximately
$83.3 million, comprised of approximately
$61.2 million in net operating loss carryforwards and
$22.1 million in built-in losses from carryover tax basis
in the properties. The effective date of the acquisition was
June 30, 2009 and the purchase price was
$260.0 million, less adjustments which resulted in a net
purchase price as of December 31, 2009 of approximately
$213.6 million, subject to final adjustments. We financed
the net purchase price by borrowing under our secured revolving
credit facility.
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 intended to
achieve an overall moderate-risk growth profile at attractive
rates of return under most industry conditions.
|
|
|
|
|
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 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, making a number of significant deepwater discoveries in
the Gulf of Mexico in the last five years. In addition, we
believe our reputation for generating high-quality exploration
prospects creates potentially valuable partnering opportunities,
which enables us to participate in exploration projects
developed by other operators.
|
4
|
|
|
|
|
Development: Our development and exploitation
efforts are intended to complement our higher-risk, high-impact
exploration projects through a variety of moderate-risk
activities targeted at maximizing recovery and production from
known reservoirs. These activities are also aimed at finding
overlooked oil and gas accumulations in and around existing
fields and are designed to establish critical operating mass
from which to expand in our focus areas. Our geoscientists and
engineers have a excellent 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.
|
|
|
|
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. 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.
|
Our
Competitive Strengths
We believe our core resources and strengths include:
Diversity of assets and activities. Our assets
and operations are diversified primarily among the Permian
Basin, Gulf Coast 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 of Mexico,
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 onshore, 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. We also are an active participant at MMS lease sales.
Furthermore, we have a large and growing asset base onshore 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.
Exploration expertise. Our seasoned team of
geoscientists has made significant discoveries in the Gulf of
Mexico, achieving a cumulative 62% success rate during the three
years ended December 31, 2009. Our geoscientists
collectively 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. As of December 31, 2009, we
served as operator of properties representing approximately 86%
of our production and had an average 73% 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
5
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 infrastructure through subsea flow lines
and umbilicals. 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, Gulf Coast, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
Approximate
|
|
|
|
|
|
Estimated
|
|
|
Estimated
|
|
|
|
|
|
Working
|
|
|
2009 Net
|
|
|
Proved
|
|
|
Proved Reserves
|
|
|
Operator
|
|
|
Interest %
|
|
|
Production(2)
|
|
|
Reserves
|
|
|
% Oil /% Gas(1)
|
|
|
|
|
|
|
|
|
(Bcfe)
|
|
|
(Bcfe)
|
|
|
|
|
Permian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spraberry (Aldwell Unit)
|
|
|
Mariner
|
|
|
|
75
|
%
|
|
|
8.0
|
|
|
|
245.8
|
|
|
|
66%/34%
|
|
Spraberry (Tamarack)
|
|
|
Mariner
|
|
|
|
93
|
%
|
|
|
4.7
|
|
|
|
142.3
|
|
|
|
77%/23%
|
|
Spraberry (Texas Scottish Rite Hospital)
|
|
|
Mariner
|
|
|
|
100
|
%
|
|
|
1.1
|
|
|
|
43.5
|
|
|
|
74%/26%
|
|
Deadwood
|
|
|
Mariner
|
|
|
|
73
|
%
|
|
|
0.5
|
|
|
|
21.9
|
|
|
|
77%/23%
|
|
Spraberry (North Stiles Unit)
|
|
|
Mariner
|
|
|
|
50
|
%
|
|
|
1.7
|
|
|
|
14.0
|
|
|
|
70%/30%
|
|
Gulf Coast:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Flores
|
|
|
Mariner
|
|
|
|
41
|
%
|
|
|
|
|
|
|
43.9
|
|
|
|
31%/69%
|
|
Chapman Ranch
|
|
|
Mariner
|
|
|
|
90
|
%
|
|
|
|
|
|
|
11.2
|
|
|
|
30%/70%
|
|
Muy Grande
|
|
|
Mariner
|
|
|
|
100
|
%
|
|
|
|
|
|
|
7.4
|
|
|
|
0%/100%
|
|
Duson
|
|
|
BTA
|
|
|
|
44
|
%
|
|
|
|
|
|
|
6.1
|
|
|
|
22%/78%
|
|
Midway Dome
|
|
|
Mariner
|
|
|
|
89
|
%
|
|
|
|
|
|
|
4.4
|
|
|
|
16%/84%
|
|
Gulf of Mexico Deepwater:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atwater Valley 426 (Bass Lite)
|
|
|
Mariner
|
|
|
|
54
|
%
|
|
|
18.4
|
|
|
|
77.0
|
|
|
|
0%/100%
|
|
Garden Banks 462 (Geauxpher)
|
|
|
Mariner
|
|
|
|
60
|
%
|
|
|
13.0
|
|
|
|
24.1
|
|
|
|
10%/90%
|
|
Green Canyon 646 (Daniel Boone)
|
|
|
W&T Offshore
|
|
|
|
40
|
%
|
|
|
1.1
|
|
|
|
19.1
|
|
|
|
69%/31%
|
|
East Breaks 597
|
|
|
Mariner
|
|
|
|
50
|
%
|
|
|
|
|
|
|
9.9
|
|
|
|
61%/39%
|
|
Ewing Bank 921 (North Black Widow)
|
|
|
ENI
|
|
|
|
35
|
%
|
|
|
1.8
|
|
|
|
8.5
|
|
|
|
93%/7%
|
|
Gulf of Mexico Shelf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brazos A19
|
|
|
Mariner
|
|
|
|
100
|
%
|
|
|
|
|
|
|
38.8
|
|
|
|
0%/100%
|
|
Vermilion 380
|
|
|
Mariner
|
|
|
|
100
|
%
|
|
|
1.1
|
|
|
|
33.2
|
|
|
|
47%/53%
|
|
West Cameron 110
|
|
|
Mariner
|
|
|
|
100
|
%
|
|
|
3.0
|
|
|
|
24.6
|
|
|
|
2%/98%
|
|
South Pass 24
|
|
|
Mariner
|
|
|
|
97
|
%
|
|
|
1.5
|
|
|
|
21.2
|
|
|
|
59%/41%
|
|
South Timbalier 49
|
|
|
Mariner
|
|
|
|
100
|
%
|
|
|
|
|
|
|
18.2
|
|
|
|
59%/41%
|
|
|
|
|
(1) |
|
NGLs are included in Oil |
|
(2) |
|
No production results are included for properties of the Edge
subsidiaries we acquired on December 31, 2009. |
6
Permian
Basin Operations
Our Permian Basin operations historically have emphasized
downspacing redevelopment activities in the prolific
oil-producing Spraberry field. Since we began our Permian Basin
redevelopment initiative in 2002, we have increased by
approximately seven-fold our net acreage position and plan
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 2009, our Permian Basin operations produced approximately
18.3 Bcfe (14% of our total production) and accounted for
approximately 515.0 Bcfe or 47% of our total estimated
proved reserves at year end. Oil and NGLs accounted for 71% of
total Permian Basin production for 2009. We drilled
51 wells in the region during 2009, 92% of which were
productive. 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 Aldwell Unit. We operate our wells in this field and
hold an average 75% working interest. At year-end 2009, our
share of estimated proved reserves attributed to this field was
245.8 Bcfe, consisting of 66% oil and NGLs and 34% natural
gas. Net production for 2009 was 8.0 Bcfe.
The Spraberry Tamarack and Spraberry Texas Scottish Rite
Hospital are the next largest fields with 142.3 and
43.5 Bcfe of estimated proved reserves, respectively. The
Deadwood field follows with 21.9 Bcfe of estimated proved
reserves and the Spraberry North Stiles Unit has estimated
proved reserves of 14.0 Bcfe.
Gulf
Coast Operations
On December 31, 2009, we acquired interests in
244.0 gross and 98.3 net acres in South Texas,
predominantly in the Vicksburg, Queen City and Deep Frio
producing trends. As of December 31, 2009, we operated
approximately 275 gross wells in this region and had
151 gross non-operated wells.
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, 2009, we held
interests in 99 deepwater blocks and 38 subsea wells. These
wells were tied back to 17 host production facilities for
production processing. As of December 31, 2009, an
additional six projects (Dalmatian, Wide Berth, Balboa,
Heidelberg, Lucius and Bushwood) were under development for
either tieback to three additional host production facilities or
in the case of Heidelberg and Lucius, production from dedicated
facilities if warranted by the amount of estimated reserves.
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 2009,
our deepwater operations produced approximately 52.8 Bcfe
(42% of our total production) and accounted for approximately
161.7 Bcfe or 15% of our total estimated proved reserves at
year end. Natural gas accounted for 80% of total deepwater
production for 2009. We drilled six wells in the region during
2009, four of which were productive.
We operate Atwater Valley 426, known as Bass Lite, in which we
hold a 54% working interest. It is in the Pleistocene formation
and is located in approximately 6,600 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. Limited
production on Bass Lite began in February 2008 due to a
temporary early production system. The project commenced
production at full capacity once the topside facilities work was
completed in August 2008 and the field produced 18.4 Bcfe
net to our interest during 2009. At year end 2009, our share of
estimated proved reserves attributed to this field was
77.0 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
2,800 feet, was drilled to a total depth of
23,156 feet (measured depth). Production on Geauxpher began
in May 2009 and the
8
field produced 13.0 Bcfe net to our interest during 2009.
At year-end 2009, our share of estimated proved reserves
attributed to the discovery was 24.1 Bcfe, consisting of
10% oil and NGLs and 90% natural gas.
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. Production on Daniel Boone began in
October 2009 and the field produced 1.1 Bcfe net to our
interest during 2009. At year-end 2009, our share of estimated
proved reserves attributed to this field was 19.1 Bcfe,
consisting of 69% oil and 31% natural gas.
We operate East Breaks 597, known as Balboa, in which we hold a
50% working interest. The well lies in water depths of
approximately 3,350 feet and was drilled in July 2001. The
well was completed in September 2009 and is awaiting tieback to
the Boomvang Spar. Production from Balboa is expected in the
second half of 2010. Our share of estimated proved reserves at
year-end 2009 was 9.9 Bcfe consisting of approximately 61%
oil and 39% 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 2009 was
approximately 1.8 Bcfe. At year-end 2009, our share of
estimated proved reserves attributed to the field was
8.5 Bcfe, consisting of 93% oil and 7% 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 (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. 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 2009, our Gulf of Mexico shelf operation produced
approximately 55.4 Bcfe (44% of our total production) and
accounted for approximately 315.1 Bcfe or 29% of our total
estimated proved reserves at year end. Natural gas accounted for
79% of total shelf production for 2009. We drilled ten wells in
the region during 2009, six of which were productive.
Our largest field in the Gulf of Mexico shelf by reserves is
Brazos A19. At year-end 2009, estimated proved reserves, all of
which are undeveloped, attributed to this field were
38.8 Bcfe, of which 100% is natural gas. This is a recently
acquired block and plans are being made to exploit these
reserves.
At year-end 2009 estimated proved reserves attributed to our
Vermillion 380 field were 33.2 Bcfe, consisting of
approximately 47% oil and NGLs and 53% natural gas. During 2008
and 2009, we drilled five wells and added additional production
capacity on the A platform. Hurricane Ike damaged
the structure with the rig on the platform, causing us to
suspend drilling while underwater structural repairs were made.
We brought the platform back on production at reduced rates
until the facilities upgrade was finished. The platform is
currently producing approximately 28 MMcfe per day. Our
working interest in this block is 100%. Production at Vermillion
380 was approximately 1.1 Bcfe in 2009.
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 3.0 Bcfe net in 2009. At year-end 2009,
estimated proved reserves attributed to this field were
24.6 Bcfe, consisting of approximately 2% oil and NGLs and
98% natural gas.
9
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 2009
produced approximately 1.5 Bcfe net. At year-end 2009,
estimated proved reserves attributed to this field were
21.2 Bcfe, consisting of approximately 59% oil and NGLs and
41% natural gas.
We operate South Timbalier 49, in which we hold a 100% working
interest. We initiated full production from this field in
September 2009. We are producing from the first of many
reservoirs encountered in the
A-1 well
and are currently producing approximately 8 MMcfe per day.
At year-end 2009, estimated proved reserves attributed to this
field were 18.2 Bcfe (approximately 59% oil and 41% natural
gas).
Estimated
Proved Reserves
The following tables present certain information with respect to
our estimated proved oil and natural gas reserves. The reserve
information in the tables below is based on estimates made in
fully-engineered reserve reports prepared by Ryder Scott
Company, L.P. (except the amount of standardized measure of
discounted future net cash flows and information in the table
for Sensitivity of Reserves to Prices). Reserve volumes and
values were determined under the method prescribed by the SEC,
which requires the application of the
12-month
average price for natural gas and oil calculated as the
unweighted arithmetic average of the
first-day-of-the-month
price for each month within the
12-month
prior period to the end of the reporting period 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. The proved reserve
estimates represent our net revenue interest in our properties.
10
Summary
of Oil and Gas Reserves as of December 31, 2009
Based on Average 2009 Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
Oil
|
|
|
NGLs
|
|
|
Total
|
|
Reserves Category:
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBbls)
|
|
|
(Bcfe)
|
|
|
Proved Developed
|
|
|
406.8
|
|
|
|
31.5
|
|
|
|
20.1
|
|
|
|
716.4
|
|
Proved Undeveloped
|
|
|
164.6
|
|
|
|
21.0
|
|
|
|
13.4
|
|
|
|
370.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total estimated proved oil and gas reserves
|
|
|
571.4
|
|
|
|
52.5
|
|
|
|
33.5
|
|
|
|
1,087.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV10 value(1) ($ in millions):
|
|
|
|
|
Proved developed reserves
|
|
$
|
1,350.0
|
|
Proved undeveloped reserves
|
|
|
152.2
|
|
|
|
|
|
|
Total PV10 value(1)
|
|
$
|
1,502.2
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
1,468.4
|
|
|
|
|
|
|
Twelve-month average prices used in calculating proved
reserve measures (excluding effects of hedging):
|
|
|
|
|
Natural gas ($/MMBtu)
|
|
$
|
3.87
|
|
Oil ($/Bbl)
|
|
$
|
61.18
|
|
Sensitivity
of Reserves to Prices
By
Principal Product Type and Price Scenario
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
NGLs
|
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBbls)
|
|
|
Proved oil and natural gas reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
10% Increase in Price
|
|
|
576.9
|
|
|
|
53.0
|
|
|
|
33.9
|
|
10% Decrease in Price
|
|
|
565.7
|
|
|
|
51.8
|
|
|
|
32.9
|
|
The following table sets forth certain information with respect
to our estimated proved reserves by geographic area as of
December 31, 2009 based on estimates made in a reserve
report prepared by Ryder Scott Company, L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Proved Developed
|
|
|
Estimated Proved Undeveloped
|
|
|
Estimated Proved
|
|
|
|
Reserve Quantities
|
|
|
Reserve Quantities
|
|
|
Reserve Quantities
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
NGLs
|
|
|
Total
|
|
|
Gas
|
|
|
Oil
|
|
|
NGLs
|
|
|
Total
|
|
|
Total
|
|
Geographic Area
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBbls)
|
|
|
(Bcfe)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
(MMBbls)
|
|
|
(Bcfe)
|
|
|
(Bcfe)
|
|
|
Permian Basin
|
|
|
84.7
|
|
|
|
16.4
|
|
|
|
15.7
|
|
|
|
277.1
|
|
|
|
63.9
|
|
|
|
16.7
|
|
|
|
12.3
|
|
|
|
237.9
|
|
|
|
515.0
|
|
Gulf Coast
|
|
|
43.2
|
|
|
|
0.7
|
|
|
|
2.0
|
|
|
|
59.5
|
|
|
|
16.3
|
|
|
|
0.2
|
|
|
|
0.8
|
|
|
|
22.1
|
|
|
|
81.6
|
|
Gulf of Mexico Deepwater
|
|
|
111.5
|
|
|
|
3.5
|
|
|
|
0.5
|
|
|
|
135.7
|
|
|
|
9.3
|
|
|
|
2.8
|
|
|
|
|
|
|
|
26.0
|
|
|
|
161.7
|
|
Gulf of Mexico Shelf
|
|
|
160.2
|
|
|
|
10.3
|
|
|
|
1.9
|
|
|
|
233.2
|
|
|
|
72.9
|
|
|
|
1.2
|
|
|
|
0.3
|
|
|
|
81.9
|
|
|
|
315.1
|
|
Other onshore
|
|
|
7.2
|
|
|
|
0.6
|
|
|
|
|
|
|
|
10.9
|
|
|
|
2.2
|
|
|
|
0.1
|
|
|
|
|
|
|
|
2.8
|
|
|
|
13.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
406.8
|
|
|
|
31.5
|
|
|
|
20.1
|
|
|
|
716.4
|
|
|
|
164.6
|
|
|
|
21.0
|
|
|
|
13.4
|
|
|
|
370.7
|
|
|
|
1,087.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV10 Value(1)
|
|
|
Standardized
|
|
Geographic Area
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
|
Measure
|
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
Permian Basin
|
|
$
|
440.8
|
|
|
$
|
51.6
|
|
|
$
|
492.4
|
|
|
|
|
|
Gulf Coast
|
|
|
103.8
|
|
|
|
9.8
|
|
|
|
113.6
|
|
|
|
|
|
Gulf of Mexico Deepwater
|
|
|
324.8
|
|
|
|
54.7
|
|
|
|
379.5
|
|
|
|
|
|
Gulf of Mexico Shelf
|
|
|
458.0
|
|
|
|
33.0
|
|
|
|
491.0
|
|
|
|
|
|
Other onshore
|
|
|
22.6
|
|
|
|
3.1
|
|
|
|
25.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,350.0
|
|
|
$
|
152.2
|
|
|
$
|
1,502.2
|
|
|
$
|
1,468.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 or standardized measure 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, 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:
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Present value of estimated future net revenues (PV10)
|
|
$
|
1,502.2
|
|
|
$
|
1,667.5
|
|
|
$
|
3,064.2
|
|
Future income taxes, discounted at 10%
|
|
|
(33.8
|
)
|
|
|
(184.5
|
)
|
|
|
(832.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
1,468.4
|
|
|
$
|
1,483.0
|
|
|
$
|
2,231.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
A combination of technologies is used in estimating our proved
reserves. Approximately 60% of our proved reserves as of
December 31, 2009 were estimated using the performance
method and the balance were estimated using the volumetric
method. A combination of geological structural and isochore
maps, well logs, core analyses, and pressure measurements
support the reserves estimates. In general, reserves
attributable to producing wells or reservoirs were estimated by
performance methods such as decline curve analysis, material
balance or reservoir simulation which used extrapolations of
historical production and pressure data available through
December 2009. In certain cases, producing reserves were more
appropriately estimated by the
12
volumetric method, such as when there was inadequate historical
performance data to establish a definitive trend. Certain
reserves attributable to non-producing and undeveloped
reservoirs were estimated by the volumetric method using
pertinent well and seismic data available through
December 31, 2009.
The process of estimating reserves is complex and requires many
assumptions as discussed below in Item 1A. Risk
Factors. As a result, we have developed internal controls
for estimating and recording reserves. These controls require
reserves to be in compliance with SEC definitions and guidance.
Our controls assign responsibility for compliance in reserves
bookings to our reservoir engineering team. Annual estimates of
our proved reserves and future production and income
attributable to those reserves are prepared using the economic
software package
Ariestm
System Petroleum Economic Evaluation Software, a copyrighted
program of Halliburton. Our reservoir engineering team
coordinates with our land, marketing and accounting departments
and those of our executive officers responsible for given
operating areas in reconciling
year-over-year
reserve changes for each of our fields. These efforts are
designed to help ensure that our database reflects information
pertaining to performance revisions, production, drilling,
acquisitions, sales, recompletions, wells, working interests,
net revenue interests, lease operating expenses, taxes, capital
costs and PV10 of future net revenues. Our reservoir engineering
team certifies this information to a third-party independent
reservoir engineering firm in connection with its preparation of
our proved reserve estimates. Our Chief Operating Officer
reviews the third-party firms estimates of our proved
reserves and ultimately certifies our acceptance of those
estimates. These estimates also are presented to our board of
directors in connection with its consideration of our annual
report on
Form 10-K.
Our reservoir engineering team is led by Richard A. Molohon,
Vice President Reservoir Engineering. He is the
technical person primarily responsible internally for overseeing
the preparation of our reserves estimates by Ryder Scott
Company, L.P. Mr. Molohon has been a Registered
Professional Engineer in Texas since 1983, joined us as a Senior
Reservoir Engineer in 1995 and is a member of the Society of
Petroleum Engineers. For addition information on
Mr. Molohons background, see Executive
Officers below under Item 4. Mr. Molohon reports
to our Chief Operating Officer who reports to our Chairman,
Chief Executive Officer and President. No portion of the
compensation of our management or the reservoir engineering team
is directly dependent on the quantity of reserves booked.
We engage Ryder Scott Company, L.P. to prepare 100% of our
proved reserves estimates. The technical person at Ryder Scott
Company, L.P. primarily responsible for overseeing the
preparation of our reserves estimates is Edward J. Gibbon, a
Senior Vice President of Ryder Scott Company, L.P.
Mr. Gibbon earned a Bachelor of Science degree in Petroleum
Engineering from the Colorado School of Mines in 1968 and is a
Licensed Professional Engineer in the State of Texas and a
Registered Professional Engineer in the State of Louisiana. He
also is a member of the Society of Petroleum Evaluation
Engineers, the Society of Petroleum Engineers, and the Society
of Petrophysicists and Well Log Analysts. Additional information
on Mr. Gibbons background is contained in the report
of Ryder Scott Company, L.P. filed as an exhibit to this Annual
Report on
Form 10-K.
Mr. Gibbon meets the requirements regarding qualifications,
independence, objectivity and confidentiality set forth in the
Standards Pertaining to Estimating and Auditing of Oil and Gas
Reserves Information promulgated by the Society of Petroleum
Engineers.
Proved
Undeveloped Reserves
As of December 31, 2009, our estimated proved undeveloped
reserves (PUDs) totaled 370.7 Bcfe or 34.0% of
our total estimated proved reserves and consisted of
164.6 Bcf of gas, 21.0 MMBbls of oil and
13.4 MMBbls of NGLs. Approximately 64.2% of these PUDs were
in the Permian Basin, 22.1% were in the Gulf of Mexico shelf,
7.0% were in the Gulf of Mexico deepwater, 6.0% were in the Gulf
Coast and 0.7% were in other onshore properties.
During 2009, we converted approximately 49.7 Bcfe or 16.8%
of our total PUDs as of December 31, 2008 to proved
developed reserves as of December 31, 2009, of which
approximately 79.9%, 13.3% and 6.8% were in the Gulf of Mexico
shelf, Gulf of Mexico deepwater and Permian Basin, respectively.
We also developed approximately 7.7 Bcfe during 2009 that
were estimated proved developed reserves in the Permian
13
Basin at December 31, 2009 but were not included in our
year-end 2008 proved reserves. We spent approximately
$125.8 million during 2009 on development activities to
convert PUDs to proved developed reserves. At December 31,
2009, we eliminated approximately 39.7 Bcfe or 13.4% of our
total PUDs as of December 31, 2008, of which approximately
56.9%, 23.9% and 19.2% were in the Gulf of Mexico shelf, Permian
Basin and Gulf of Mexico deepwater, respectively, primarily due
to pricing (59.1% of the total eliminated) and performance
(40.9% of the total eliminated) considerations.
Of our total 370.7 Bcfe of PUDs as of December 31,
2009, approximately 20.2 Bcfe or 5.4% remained undeveloped
for more than five years. Of the 20.2 Bcfe, approximately
62.2% were in the Gulf of Mexico deepwater awaiting expected
conversion to proved developed reserves upon a side track updip
after the current wellbore depletes, and the balance were in the
Spraberry (Aldwell Unit) field in the Permian Basin where we
have been drilling continuously since 2002.
The following tables present our natural gas, oil and NGL
production and revenue, excluding the effects of hedging, by
area for the indicted periods. The tables excludes the
properties of the Edge subsidiaries we acquired on
December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf)
|
|
|
5.0
|
|
|
|
4.0
|
|
|
|
3.7
|
|
Oil (MBbls)
|
|
|
1,468.0
|
|
|
|
1,242.8
|
|
|
|
861.2
|
|
NGLs (MBbls)
|
|
|
744.0
|
|
|
|
578.5
|
|
|
|
387.3
|
|
Total Natural Gas Equivalent (Bcfe)
|
|
|
18.3
|
|
|
|
14.9
|
|
|
|
11.2
|
|
Gulf of Mexico Deepwater:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf)
|
|
|
42.1
|
|
|
|
27.7
|
|
|
|
14.7
|
|
Oil (MBbls)
|
|
|
1,427.0
|
|
|
|
1,850.5
|
|
|
|
1,301.9
|
|
NGLs (MBbls)
|
|
|
362.2
|
|
|
|
264.7
|
|
|
|
126.2
|
|
Total Natural Gas Equivalent (Bcfe)
|
|
|
52.8
|
|
|
|
40.4
|
|
|
|
23.3
|
|
Gulf of Mexico Shelf:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf)
|
|
|
43.7
|
|
|
|
48.1
|
|
|
|
49.4
|
|
Oil (MBbls)
|
|
|
1,576.5
|
|
|
|
1,787.7
|
|
|
|
2,050.3
|
|
NGLs (MBbls)
|
|
|
371.7
|
|
|
|
714.7
|
|
|
|
686.3
|
|
Total Natural Gas Equivalent (Bcfe)
|
|
|
55.4
|
|
|
|
63.1
|
|
|
|
65.8
|
|
Total Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf)
|
|
|
90.8
|
|
|
|
79.8
|
|
|
|
67.8
|
|
Oil (MBbls)
|
|
|
4,471.5
|
|
|
|
4,881.0
|
|
|
|
4,213.4
|
|
NGLs (MBbls)
|
|
|
1,477.9
|
|
|
|
1,557.9
|
|
|
|
1,199.8
|
|
Total Natural Gas Equivalent (Bcfe)
|
|
|
126.5
|
|
|
|
118.4
|
|
|
|
100.3
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Revenue (excluding the effects of hedges)
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
19,775
|
|
|
$
|
31,339
|
|
|
$
|
25,153
|
|
Oil
|
|
|
87,153
|
|
|
|
122,005
|
|
|
|
61,528
|
|
NGLs
|
|
|
23,794
|
|
|
|
30,765
|
|
|
|
17,871
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
130,722
|
|
|
$
|
184,109
|
|
|
$
|
104,552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico Deepwater:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
168,564
|
|
|
$
|
271,979
|
|
|
$
|
104,840
|
|
Oil
|
|
|
86,524
|
|
|
|
180,131
|
|
|
|
90,631
|
|
NGLs
|
|
|
12,611
|
|
|
|
15,053
|
|
|
|
5,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
267,699
|
|
|
$
|
467,163
|
|
|
$
|
201,009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico Shelf:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
176,063
|
|
|
$
|
467,099
|
|
|
$
|
346,078
|
|
Oil
|
|
|
97,164
|
|
|
|
190,504
|
|
|
|
145,634
|
|
NGLs
|
|
|
12,516
|
|
|
|
39,897
|
|
|
|
30,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
285,743
|
|
|
$
|
697,500
|
|
|
$
|
522,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
364,402
|
|
|
$
|
770,417
|
|
|
$
|
476,071
|
|
Oil
|
|
|
270,841
|
|
|
|
492,640
|
|
|
|
297,793
|
|
NGLs
|
|
|
48,921
|
|
|
|
85,715
|
|
|
|
54,192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
684,164
|
|
|
$
|
1,348,772
|
|
|
$
|
828,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Sales Prices and Production Costs
The following table presents our average realized sales prices
and average production costs for the indicated periods. The
table does not include operating results of the subsidiaries we
acquired from Edge on December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Average realized sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
6.08
|
|
|
$
|
9.31
|
|
|
$
|
7.88
|
|
Oil (per Bbl)
|
|
|
70.59
|
|
|
|
86.02
|
|
|
|
67.50
|
|
Natural gas liquids (per Bbl)
|
|
|
33.10
|
|
|
|
55.02
|
|
|
|
45.16
|
|
Total natural gas equivalent ($/Mcfe)
|
|
|
7.25
|
|
|
|
10.54
|
|
|
|
8.71
|
|
Average realized sales prices excluding the effects of
hedging:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
4.01
|
|
|
$
|
9.66
|
|
|
$
|
7.02
|
|
Oil (per Bbl)
|
|
|
60.57
|
|
|
|
100.93
|
|
|
|
70.68
|
|
Natural gas liquids (per Bbl)
|
|
|
33.10
|
|
|
|
55.02
|
|
|
|
45.16
|
|
Total natural gas equivalent ($/Mcfe)
|
|
|
5.41
|
|
|
|
11.39
|
|
|
|
8.26
|
|
Average production costs per Mcfe:
|
|
$
|
1.97
|
|
|
$
|
1.96
|
|
|
$
|
1.52
|
|
15
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, 2009 and December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Oil
|
|
|
1,037.0
|
|
|
|
792.0
|
|
|
|
936.0
|
|
|
|
733.0
|
|
Natural gas
|
|
|
380.0
|
|
|
|
213.8
|
|
|
|
154.0
|
|
|
|
90.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,417.0
|
|
|
|
1,005.8
|
|
|
|
1,090.0
|
|
|
|
823.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
Developed Acres
|
|
|
Undeveloped Acres
|
|
|
Total Acres
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Permian Basin
|
|
|
103,507
|
|
|
|
81,861
|
|
|
|
165,894
|
|
|
|
66,256
|
|
|
|
269,401
|
|
|
|
148,117
|
|
Gulf Coast
|
|
|
64,229
|
|
|
|
27,273
|
|
|
|
37,689
|
|
|
|
19,967
|
|
|
|
101,918
|
|
|
|
47,240
|
|
Gulf of Mexico Deepwater
|
|
|
87,757
|
|
|
|
39,610
|
|
|
|
432,691
|
|
|
|
226,386
|
|
|
|
520,448
|
|
|
|
265,996
|
|
Gulf of Mexico Shelf
|
|
|
697,131
|
|
|
|
383,911
|
|
|
|
313,684
|
|
|
|
228,936
|
|
|
|
1,010,815
|
|
|
|
612,847
|
|
Other Onshore
|
|
|
19,800
|
|
|
|
7,984
|
|
|
|
104,511
|
|
|
|
81,145
|
|
|
|
124,311
|
|
|
|
89,129
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
972,424
|
|
|
|
540,639
|
|
|
|
1,054,469
|
|
|
|
622,690
|
|
|
|
2,026,893
|
|
|
|
1,163,329
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth that portion of our onshore and
offshore undeveloped acreage as of December 31, 2009 that
is subject to expiration absent drilling activity during the
three years ended December 31, 2012 and thereafter.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped Acreage
|
|
|
|
Subject to Expiration in the Year Ended December 31,
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Permian Basin
|
|
|
22,735
|
|
|
|
16,950
|
|
|
|
29,653
|
|
|
|
27,229
|
|
|
|
3,526
|
|
|
|
3,450
|
|
|
|
49,840
|
|
|
|
17,943
|
|
Gulf Coast
|
|
|
22,460
|
|
|
|
19,505
|
|
|
|
17,256
|
|
|
|
13,164
|
|
|
|
224
|
|
|
|
516
|
|
|
|
7,200
|
|
|
|
3,612
|
|
Gulf of Mexico Deepwater
|
|
|
57,600
|
|
|
|
17,856
|
|
|
|
34,560
|
|
|
|
17,280
|
|
|
|
34,560
|
|
|
|
4,212
|
|
|
|
305,971
|
|
|
|
186,930
|
|
Gulf of Mexico Shelf
|
|
|
32,665
|
|
|
|
22,864
|
|
|
|
101,336
|
|
|
|
73,508
|
|
|
|
32,454
|
|
|
|
25,150
|
|
|
|
147,229
|
|
|
|
107,414
|
|
Other Onshore
|
|
|
32,370
|
|
|
|
25,884
|
|
|
|
6,087
|
|
|
|
5,472
|
|
|
|
1,765
|
|
|
|
1,424
|
|
|
|
921
|
|
|
|
513
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
167,830
|
|
|
|
103,059
|
|
|
|
188,892
|
|
|
|
136,653
|
|
|
|
72,529
|
|
|
|
34,752
|
|
|
|
511,161
|
|
|
|
316,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
Drilling
Activity
Certain information with regard to the number of wells drilled
during the years ended December 31, 2009, 2008 and 2007 is
set forth below. The number of wells drilled refers to the
number of wells completed at any time during a given year,
regardless of when drilling was initiated. The following table
does not include any drilling activity of the Edge subsidiaries
we acquired on December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
10.00
|
|
|
|
5.97
|
|
|
|
15.00
|
|
|
|
8.59
|
|
|
|
11.00
|
|
|
|
5.96
|
|
Dry
|
|
|
10.00
|
|
|
|
7.00
|
|
|
|
5.00
|
|
|
|
2.98
|
|
|
|
8.00
|
|
|
|
4.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
20.00
|
|
|
|
12.97
|
|
|
|
20.00
|
|
|
|
11.57
|
|
|
|
19.00
|
|
|
|
10.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
33.00
|
|
|
|
30.08
|
|
|
|
125.00
|
|
|
|
88.93
|
|
|
|
121.00
|
|
|
|
60.43
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
33.00
|
|
|
|
30.08
|
|
|
|
125.00
|
|
|
|
88.93
|
|
|
|
121.00
|
|
|
|
60.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extension wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
14.00
|
|
|
|
9.49
|
|
|
|
3.00
|
|
|
|
3.00
|
|
|
|
|
|
|
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
14.00
|
|
|
|
9.49
|
|
|
|
3.00
|
|
|
|
3.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
57.00
|
|
|
|
45.54
|
|
|
|
143.00
|
|
|
|
100.52
|
|
|
|
132.00
|
|
|
|
66.39
|
|
Dry
|
|
|
10.00
|
|
|
|
7.00
|
|
|
|
5.00
|
|
|
|
2.98
|
|
|
|
8.00
|
|
|
|
4.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
67.00
|
|
|
|
52.54
|
|
|
|
148.00
|
|
|
|
103.50
|
|
|
|
140.00
|
|
|
|
71.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of February 22, 2010, the following wells were drilling:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate
|
|
|
|
|
|
|
|
|
|
Well Name
|
|
Operator
|
|
Working Interest
|
|
|
Location
|
|
Gross
|
|
|
Net
|
|
|
West Cameron 112
A-2
|
|
Mariner
|
|
|
55
|
%
|
|
Shelf
|
|
|
1.00
|
|
|
|
0.55
|
|
South Marsh 11 #58
|
|
Mariner
|
|
|
100
|
%
|
|
Shelf
|
|
|
1.00
|
|
|
|
1.00
|
|
Green Canyon 903 #1
|
|
Anadarko
|
|
|
13
|
%
|
|
Deepwater
|
|
|
1.00
|
|
|
|
0.13
|
|
Cathey 2906 #1
|
|
Mariner
|
|
|
61
|
%
|
|
Permian Basin
|
|
|
1.00
|
|
|
|
0.61
|
|
SRH 1609
|
|
Mariner
|
|
|
100
|
%
|
|
Permian Basin
|
|
|
1.00
|
|
|
|
1.00
|
|
Keathley 46 #2
|
|
Mariner
|
|
|
100
|
%
|
|
Permian Basin
|
|
|
1.00
|
|
|
|
1.00
|
|
Currie 23 #1
|
|
Mariner
|
|
|
50
|
%
|
|
Permian Basin
|
|
|
1.00
|
|
|
|
0.50
|
|
SRH 1705
|
|
Mariner
|
|
|
100
|
%
|
|
Permian Basin
|
|
|
1.00
|
|
|
|
1.00
|
|
Cowden E #5
|
|
Mariner
|
|
|
55
|
%
|
|
Permian Basin
|
|
|
1.00
|
|
|
|
0.55
|
|
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 NGLs production is sold to a variety of
customers under short-term marketing arrangements at
market-based
17
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
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Williams Gas and affiliates
|
|
|
12
|
%
|
|
|
5
|
%
|
|
|
<1
|
%
|
ChevronTexaco and affiliates
|
|
|
13
|
%
|
|
|
16
|
%
|
|
|
23
|
%
|
Plains Marketing LP
|
|
|
11
|
%
|
|
|
5
|
%
|
|
|
7
|
%
|
Shell
|
|
|
9
|
%
|
|
|
10
|
%
|
|
|
10
|
%
|
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
18
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 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 were ordered
by the MMS to pay royalties for natural gas produced in some of
those years. However, we challenged the MMSs authority to
include price thresholds in six of our post-Act leases awarded
in 1996 and 1997 because we believe that post-Act leases are
entitled to automatic royalty relief under the RRA, regardless
of commodity prices. In February 2010, the MMS withdrew its
orders in respect of these leases, closing the matter in our
favor. For more information, see Item 3. Legal
Proceedings.
19
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 and Crude Oil
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- access transportation on a
non-discriminatory basis and at just and reasonable rates 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.
The FERC also regulates interstate crude oil pipeline
transportation rates and service conditions under the Interstate
Commerce Act, which affect the marketing of crude oil produced
by us and the revenues received by us for sales of such oil. The
FERC requires interstate pipelines to provide
non-discriminatory, common
20
carrier service at just and reasonable rates. The intra-state
transportation of crude oil is subject to state regulatory
jurisdiction. FERC and the state agencies modify their
transportation policies and regulations from time to time. Also,
in the Energy Policy Act of 2007, Congress directed the Federal
Trade Commission to impose regulations prohibiting deceptive on
manipulative practices relating to the sale of crude oil. In
2009, the FTC issued a rule similar to FERCs
anti-manipulation rule for gas.
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 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.
|
21
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 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 $75.0 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 $35.0 million to cover
liabilities related to an oil spill. The amount of financial
assurance required under the OPA may be increased up to
$150.0 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
22
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. Except
as outlined below regarding climate change issues, we believe
that compliance with the Clean Air Act and analogous state laws
and regulations will not have a material impact on our
operations or financial condition.
Climate Change. There is increasing attention
in the United States and worldwide concerning the issue of
climate change and the effect of emissions of greenhouse gases
(GHG), in particular from the combustion of fossil
fuels. Under the Clean Air Act and various state analogues,
regulations limiting GHG emissions or imposing reporting
obligations with respect to such emissions have been proposed or
finalized. On October 30, 2009, EPA published a final rule
requiring the reporting of GHG emissions from specified large
sources in the United States beginning in 2011 for emissions
occurring in 2010. In addition, on December 15, 2009, EPA
published a Final Rule finding that current and projected
concentrations of six key GHGs in the atmosphere threaten public
health and welfare of current and future generations. EPA also
found that the combined emissions of these GHGs from new motor
vehicles and new motor vehicle engines contribute to the GHG
pollution that threatens public health and welfare. This Final
Rule, also known as EPAs Endangerment Finding, does not
impose any requirements on industry or other entities directly;
however, after the rules January 14, 2010 effective
date, EPA will be able to finalize motor vehicle GHG standards,
the effect of which could reduce demand for motor fuels refined
from crude oil. Finally, according to EPA, the final motor
vehicle GHG standards will trigger construction and operating
permit requirements for stationary sources. As a result, EPA has
proposed to tailor these programs such that only stationary
sources, including refineries, that emit over 25,000 tons of
GHGs per year will be subject to air permitting requirements. In
addition, on September 22, 2009, EPA issued a
Mandatory Reporting of Greenhouse Gases final rule
(Reporting Rule).
23
The Reporting Rule establishes a new comprehensive scheme
requiring operators of stationary sources emitting more than
established annual thresholds of carbon dioxide-equivalent GHGs
to inventory and report their GHG emissions annually on a
facility-by-facility
basis. Further, proposed legislation has been introduced in
Congress that would establish an economy-wide cap on emissions
of GHGs in the United States and would require most sources of
GHG emissions to obtain GHG emission allowances
corresponding to their annual emissions of GHGs. Any limitation
on emissions of GHGs from our equipment or operations could
require us to incur costs to reduce such emissions. 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. Moreover, incentives to conserve or
use alternative energy sources could reduce demand for fossil
fuels, resulting in a decrease in demand for our products.
Climate change also poses potential physical risks, including an
increase in sea level and changes in weather conditions, such as
an increase in changes in precipitation and extreme weather
events. To the extent that such unfavorable weather conditions
are exacerbated by global climate change or otherwise, our
operations may be adversely affected to a greater degree than we
have previously experienced, including increased delays and
costs. However, the uncertain nature of changes in extreme
weather events (such as increased frequency, duration, and
severity) and the long period of time over which any changes
would take place make estimating any future financial risk to
our operations caused by these physical risks of climate change
extremely challenging.
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.
24
Employees
As of December 31, 2009, we had 328 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
Current
Insurance Against Hurricanes
Mariner is a member of OIL Insurance Limited (OIL),
an energy industry insurance cooperative, which provides Mariner
windstorm insurance coverage. During 2009, the coverage was
subject to a $10.0 million per-occurrence deductible, a
$250.0 million per-occurrence loss limit, and a
$750.0 million industry aggregate per-event loss limit.
Effective January 1, 2010, the coverage is subject to a
per-occurrence deductible which remains under consideration, a
$150.0 million per-occurrence loss limit per member, an
annual maximum of $300.0 million per member, and a
$750.0 million industry aggregate per-event loss limit. In
addition, annual industry windstorm losses exceeding
$300.0 million will be mutualized among windstorm members
in two pools, one for offshore and one for onshore, with future
premiums based upon a pools loss experience and a
members weighted percent of the pools asset base.
Mariner anticipates these changes to increase its loss retention
by approximately $100.0 million for windstorm losses, which
it expects to either self insure, insure through the commercial
market, insure through the purchase of additional OIL coverage
or a combination of these.
Each year, Mariner considers whether to purchase from the
commercial market supplemental or excess insurance which in the
past has provided coverage when OIL limits have been exceeded
(see discussion below under Hurricanes Katrina
and Rita (2005)). The supplemental insurance coverage
offered by the commercial market in 2009 would not have provided
similar coverage and Mariner elected not to purchase it when it
expired on June 1, 2009. Mariner believes its assets are
sufficiently insured through OIL and Mariners expected
ability to cover losses in excess of OIL coverage. Mariner
intends to monitor the commercial market for insurance that
would, based on Mariners historical experience, cover its
expected hurricane-related risks on a cost-effective basis once
OIL limits are exceeded.
As of December 31, 2009, Mariner accrued approximately
$48.0 million for an OIL withdrawal premium contingency. As
part of its OIL membership, Mariner is obligated to pay a
withdrawal premium if it elects to withdraw from OIL. Mariner
does not anticipate withdrawing from OIL; however, due to the
contingency, Mariner periodically reassesses the sufficiency of
its accrued withdrawal premium based on OILs periodic
calculation of the potential withdrawal premium in light of past
losses, and Mariner may adjust its accrual accordingly in the
future. 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. Mariner has entered into
such a security agreement, granting to OIL a senior security
interest in up to the next $50.0 million in excess of
$100.0 million of Mariners Hurricane Ike claim
proceeds payable by OIL. Mariner has the ability to replace the
security agreement with a letter of credit or other acceptable
security in favor of OIL.
Hurricane
Ike (2008)
In 2008, Mariners operations were adversely affected by
Hurricane Ike. The hurricane resulted in shut-in and delayed
production as well as facility repairs and replacement expenses.
Mariner estimates that repairs and plugging and abandonment
costs resulting from Hurricane Ike will total approximately
$160.0 million net to Mariners interest. OIL has
advised Mariner that industry-wide damages from Hurricane Ike
are expected to substantially exceed OILs
$750.0 million industry aggregate per event loss limit and
that OIL expects to initially prorate the payout of all OIL
members Hurricane Ike claims at approximately 50%, subject
to further adjustment. OIL also has indicated that the scaling
factor it expects to apply to Mariners Hurricane Ike
claims will result in settlement at less than 70%. Mariner
expects that approximately 75% of the shortfall in its primary
insurance coverage will be covered under its commercial excess
coverage. In respect of Hurricane Ike
25
claims that Mariner made through December 2009, it received
approximately $30.6 million from OIL and $9.7 million
from excess carriers. Although in 2009 Mariner started receiving
payment in respect of its Hurricane Ike claims, due to the
magnitude of the storm and the complexity of the insurance
claims being processed by the insurance industry, Mariner
expects to maintain a potentially significant insurance
receivable through 2010 while it actively pursues settlement.
Hurricanes
Katrina and Rita (2005)
In 2005, Mariners operations were adversely affected by
Hurricanes Katrina and Rita, resulting in substantial shut-in
and delayed production, as well as necessitating extensive
facility repairs and hurricane-related abandonment operations.
Since 2005, Mariner has incurred approximately
$208.6 million in hurricane expenditures resulting from
Hurricanes Katrina and Rita, of which $130.6 million were
capitalized expenditures and $78.0 million were
hurricane-related abandonment costs.
Applicable insurance for Mariners Hurricane Katrina and
Rita claims with respect to the Gulf of Mexico assets acquired
in March 2006 was provided by OIL. Mariners coverage for
such properties was subject to a deductible of $5.0 million
per occurrence and a $1.0 billion industry-wide loss limit
per occurrence. OIL advised Mariner that the aggregate claims
resulting from each of Hurricanes Katrina and Rita were expected
to exceed the $1.0 billion per occurrence loss limit and
that therefore Mariners insurance recovery was expected to
be reduced pro-rata (approximately 47% for Katrina and 67% for
Rita) with all other competing claims from the storms. During
2008, Mariner settled its Katrina and Rita claims with its
excess insurers for a one-time cash payment of
$48.5 million.
As of December 31, 2009, Mariner had recovered
approximately $137.0 million in respect of Hurricanes
Katrina and Rita, of which $88.5 million was paid by OIL
and $48.5 million was paid by excess insurers. Although
Mariner has received full and final settlement of its insurance
claims in respect of Hurricanes Katrina and Rita as of
December 31, 2009, it may receive from OIL a relatively
immaterial additional amount in respect of Hurricane Rita after
OIL finally adjusts all of its members Hurricane Rita
claims.
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.
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.
Acquisition of properties. Cost incurred to
purchase, lease or otherwise acquire a property, including costs
of lease bonuses and options to purchase or lease properties,
the portion of costs applicable to minerals when land including
mineral rights is purchased in fee, brokers fees, recoding fees,
legal costs, and other costs incurred in acquiring properties.
Analogous reservoir. Analogous reservoirs, as
used in resources assessments, have similar rock and fluid
properties, reservoir conditions (depth, temperature, and
pressure) and drive mechanisms, but are typically at a more
advanced stage of development than the reservoir of interest and
thus may provide concepts to assist in the interpretation of
more limited data and estimation of recovery. This definition
has been abbreviated from the applicable definition contained in
Rule 4-10(a)(2)
of
Regulation S-X.
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.
26
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 production of oil or gas, or in the case of a dry
well, the reporting to the appropriate authority that the well
has been abandoned.
Condensate. A mixture of hydrocarbons that
exists in the gaseous phase at original reservoir temperature
and pressure, but that, when produced, is in the liquid phase at
surface pressure and temperature.
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, on
December 31, 2009).
Developed acreage. The number of acres that
are allocated or assignable to productive wells or wells capable
of production.
Developed reserves. Reserves of any category
that can be expected to be recovered. This definition has been
abbreviated from the definition of Developed oil and gas
reserves contained in
Rule 4-10(a)(6)
of
Regulation S-X.
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 has been abbreviated from the applicable
definition contained in
Rule 4-10(a)(7)
of
Regulation S-X.
Development project. A development project is
the means by which petroleum resources are brought to the status
of economically producible. As examples, the development of a
single reservoir or field, an incremental development in a
producing field, or the integrated development of a group of
several fields and associated facilities with a common ownership
may constitute a development project.
Development well. A well drilled within the
proved area of an oil or gas reservoir to the depth of a
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 well. An exploratory, development or
extension well that proves to be incapable of producing either
oil or gas in sufficient quantities to justify completion as an
oil or gas well.
Dry well costs. Costs incurred in drilling a
well, assuming a well is not productive, including plugging and
abandonment costs.
Economically producible. The term economically
producible, as it relates to a resource, means a resource which
generates revenue that exceeds, or is reasonably expected to
exceed, the costs of the operation. This definition has been
abbreviated from the applicable definition contained in
Rule 4-10(a)(10)
of
Regulation S-X.
Estimated ultimate recovery (EUR). Estimated
ultimate recovery is the sum of reserves remaining as of a given
date and cumulative production as of that date.
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
27
drilling exploratory wells and exploratory-type stratigraphic
test wells. This definition has been abbreviated from the
applicable definition contained in
Rule 4-10(a)(12)
of
Regulation S-X.
Exploratory well. A well drilled to find a new
field or to find a new reservoir in a field previously found to
be productive of oil or gas in another reservoir. Generally, an
exploratory well is any well that is not a development well, an
extension well, a service well, or a stratigraphic test well as
those items are defined in this glossary.
Extension well. A well drilled to extend the
limits of 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 a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition. This definition has been abbreviated
from the applicable definition contained in
Rule 4-10(a)(15)
of
Regulation S-X.
Gas. Natural gas.
Gross acres or gross wells. The total acres or
wells, as the case may be, in which a working interest is owned.
A gross acre or well is an acre or well 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.
MMBbls. 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. A
net acre or well is deemed to exist when the sum of fractional
ownership working interests in gross acres or wells equals one.
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.
Oil. Crude oil. Unless otherwise stated,
references to oil include condensate.
Operator. The individual or company
responsible for the exploration
and/or
exploitation
and/or
production of an oil or gas well or lease.
28
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.
Possible reserves. Those additional reserves
that are less certain to be recovered than probable reserves.
This definition has been abbreviated from the applicable
definition contained in
Rule 4-10(a)(17)
of
Regulation S-X.
Present value of estimated future net revenues or
PV10. 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.
Probable reserves. Those additional reserves
that are less certain to be recovered than proved reserves but
which, together with proved reserves, are as likely as not to be
recovered. This definition has been abbreviated from the
applicable definition contained in
Rule 4-10(a)(18)
of
Regulation S-X.
Production costs. Costs incurred to operate
and maintain wells and related equipment and facilities,
including depreciation and applicable operating costs of support
equipment and facilities and other costs of operating and
maintaining those wells and related equipment and facilities.
They become part of the cost of oil and gas produced. This
definition has been abbreviated from the applicable definition
contained in
Rule 4-10(a)(20)
of
Regulation S-X.
Productive well. An exploratory, development
or extension well that is not a dry well. Productive wells
include producing wells and wells mechanically capable of
production.
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 area. The part of a property to which
proved reserves have been specifically attributed.
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.
Proved properties. Properties with proved
reserves.
Proved reserves. Those quantities of crude oil
and gas, which, by analysis of that geoscience and engineering
data, can be estimated with reasonable certainty to be
economically producible from a given date forward,
from known reservoirs, and under existing economic conditions,
operating methods and government regulations prior
to the time at which contracts providing the right to operate
expire, unless evidence indicates that renewal is reasonably
certain, regardless of whether deterministic or probabilistic
methods are used for the estimation. This definition has been
abbreviated from the definition of Proved oil and gas
reserves contained in
Rule 4-10(a)(22)
of
Regulation S-X.
Recompletion. The completion for production in
an existing well bore to another formation from that which the
well has been previously completed.
29
Reserves. Reserves are estimated remaining
quantities of oil and gas and related substances anticipated to
be economically producible, as of a given date, by application
of development projects to known accumulations. This definition
abbreviated from the applicable definition contained in
Rule 4-10(a)(26)
of
Regulation S-X.
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.
Service well. A well drilled or completed for
the purpose of supporting production in an existing field.
Specific purposes of service wells include gas injection, water
injection, steam injection, air injection, salt-water disposal,
water supply for injection, observation, or injection for
in-situ combustion.
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.
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.
Stratigraphic test well. A stratigraphic test
well is a drilling effort, geologically directed, to obtain
information pertaining to a specific geological condition. The
classification also includes test identified as core tests and
all types of expendable holes related to hydrocarbon
exploration. Stratigraphic tests are classified as
exploratory type if not drilled in a known area or
development type if drilled in a known area.
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.
Tcfe. Trillion cubic feet equivalent of
natural gas.
Undeveloped acreage. Leased acreage on which
wells have not been drilled or completed to a point that would
permit the production of economic quantities of oil or gas
regardless of whether such acreage contains proved reserves.
Undeveloped reserves. Reserves of any category
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 has
been abbreviated from the definition of Undeveloped oil
and gas reserves contained in
Rule 4-10(a)(31)
of
Regulation S-X.
Unproved properties. Properties with no 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
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 future.
Prices for oil and natural gas fluctuate in response to
relatively minor changes in the supply and
30
demand for oil and natural gas, market uncertainty and a variety
of additional factors beyond our control, such as:
|
|
|
|
|
domestic and foreign supply of oil and natural gas;
|
|
|
|
price and quantity of foreign imports;
|
|
|
|
actions of the Organization of Petroleum Exporting Countries and
other state-controlled oil companies relating to oil price and
production controls;
|
|
|
|
level of consumer product demand;
|
|
|
|
domestic and foreign governmental regulations;
|
|
|
|
political conditions in or affecting other oil-producing and
natural gas-producing countries, including the current conflicts
in the Middle East and conditions in South America and Russia;
|
|
|
|
weather conditions;
|
|
|
|
technological advances affecting oil and natural gas consumption;
|
|
|
|
overall U.S. and global economic conditions; and
|
|
|
|
price and availability of alternative fuels.
|
Further, oil prices and natural gas prices do not necessarily
fluctuate in direct relationship to each other. 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
above 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.
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 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.
31
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
which are beyond our control. 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 above
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 generally
base the estimated discounted future net cash flows from our
estimated proved reserves on an unweighted arithmetic average of
the
first-day-of-the
month price for each month during the
12-month
calendar year and year-end costs. 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. During the year ended December 31, 2009, 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 $754.3 million. See below Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations Critical Accounting
Policies and Estimates Oil and Gas Properties,
and Item 8, Note 1 Summary of Significant
Accounting Policies in the Notes to the Consolidated
Financial Statements 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, 2009. 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
32
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 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.
Of our
total estimated proved reserves, approximately 30% are
undeveloped and ultimately may be reclassified as unproved or
not be developed, and 20% are developed non-producing and may
not be produced.
As of December 31, 2009, approximately 30% of our total
estimated proved reserves were undeveloped. The SEC generally
requires that reserves classified as proved undeveloped be
capable of conversion into proved developed within five years of
classification unless specific circumstances justify a longer
time. Approximately 7.8% of our estimated proved undeveloped
reserves as of December 31, 2009 have been classified as
such for at least four years. Proved undeveloped reserves that
are not timely developed are subject to possible
reclassification as non-proved reserves. Substantial downward
adjustments to our estimated proved reserves could have a
material adverse effect on our financial condition and results
of operations, and lower our bank borrowing base and reduce our
access to capital. In addition to our proved undeveloped
reserves, as of December 31, 2009 approximately 20% of our
total estimated proved reserves were developed non-producing.
Not all of our undeveloped or developed non-producing reserves
ultimately may be developed or 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:
|
|
|
|
|
unexpected drilling conditions;
|
33
|
|
|
|
|
pressure or irregularities in formations;
|
|
|
|
equipment failures or accidents;
|
|
|
|
adverse weather conditions, including hurricanes, which are
common in the Gulf of Mexico during certain times of the year;
|
|
|
|
compliance with governmental regulations;
|
|
|
|
unavailability or high cost of drilling rigs, equipment or labor;
|
|
|
|
reductions in oil and natural gas prices; and
|
|
|
|
limitations in the market for oil and natural gas.
|
If any of these factors were to occur with respect to a
particular project, we could lose all or a part of our
investment in the project, or we could fail to realize the
expected benefits from the project, either of which could
materially and adversely affect our revenues and profitability.
Our
exploratory drilling projects are based in part on seismic data,
which is costly and cannot ensure the commercial success of the
project.
Our decisions to purchase, explore, develop and exploit
prospects or properties depend in part on data obtained through
geophysical and geological analyses, production data and
engineering studies, the results of which are often uncertain.
Even when used and properly interpreted,
3-D seismic
data and visualization 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.
Oil
and gas drilling and production involve many business and
operating risks, any one of which could reduce our levels of
production, cause substantial losses or prevent us from
realizing profits.
Our business is subject to all of the operating risks associated
with drilling for and producing oil and natural gas, including:
|
|
|
|
|
fires;
|
|
|
|
explosions;
|
|
|
|
blow-outs and surface cratering;
|
|
|
|
uncontrollable flows of underground natural gas, oil and
formation water;
|
|
|
|
natural events and natural disasters, such as loop currents, and
hurricanes and other adverse weather conditions;
|
|
|
|
pipe or cement failures;
|
|
|
|
casing collapses;
|
|
|
|
lost or damaged oilfield drilling and service tools;
|
|
|
|
abnormally pressured formations; and
|
|
|
|
environmental hazards, such as natural gas leaks, oil spills,
pipeline ruptures and discharges of toxic gases.
|
If any of these events occurs, we could incur substantial losses
as a result of injury or loss of life, severe damage to and
destruction of property, natural resources and equipment,
pollution and other environmental
34
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 above
Item 1. Business Properties
Gulf of Mexico Deepwater Operations 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 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. 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.
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
35
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.
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.
36
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
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
above 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 plugging 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
37
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 certain
insurance policies or procure other desirable insurance on
commercially reasonable terms, if at all. See above
Item 1. Business Insurance Matters.
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
Hurricane Ike. See above Item 1. Business
Insurance Matters and below Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations Liquidity and Capital
Resources for more information.
The
proposed U.S. federal budget for fiscal year 2010 includes
certain provisions that, if passed as originally submitted, will
have an adverse effect on our financial position, results of
operations, and cash flows.
The Office of Management and Budgets proposed
U.S. federal budget for fiscal year 2010 repeals many tax
incentives and deductions that are currently used by
U.S. oil and gas companies and imposes new taxes. The
provisions include: elimination of the ability to fully deduct
intangible drilling costs in the year incurred; increases in the
taxation of foreign source income; levy of an excise tax on Gulf
of Mexico oil and gas production; repeal of the manufacturing
tax deduction for oil and gas companies; and increase in the
geological and geophysical amortization period for independent
producers. Should some or all of these provisions become law,
our taxes will increase, potentially significantly, which would
have a negative impact on our net income and cash flows. Since
none of these proposals have yet to be voted on or become law,
we do not know the ultimate impact these proposed changes may
have on our business.
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:
|
|
|
|
|
diversion of our managements attention to evaluating,
negotiating and integrating significant acquisitions and
strategic transactions;
|
|
|
|
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;
|
|
|
|
our exposure to unforeseen liabilities of acquired businesses,
operations or properties;
|
|
|
|
possibility of faulty assumptions underlying our expectations,
including assumptions relating to reserves, future production,
volumes, revenues, costs and synergies;
|
|
|
|
difficulty associated with coordinating geographically separate
organizations; and
|
|
|
|
challenge of attracting and retaining personnel associated with
acquired operations.
|
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
38
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.
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.
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, and the issuance of debt and equity securities.
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
39
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.
We may
not be able to generate enough cash flow to meet our debt
obligations.
We expect our earnings and cash flow to vary significantly from
year to year due to the cyclical nature of our industry. As a
result, the amount of debt that we can manage, in some periods,
may not be appropriate for us in other periods. Additionally,
our future cash flow may be insufficient to meet our debt
obligations and commitments, including the notes. Any
insufficiency could negatively impact our business. A range of
economic, competitive, business and industry factors will affect
our future financial performance and, as a result, our ability
to generate cash flow from operations and to pay our debt. 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:
|
|
|
|
|
making it more difficult for us to satisfy our debt obligations
and increasing the risk that we may default on our debt
obligations;
|
|
|
|
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;
|
|
|
|
limiting our ability to obtain additional financing in the
future for working capital, capital expenditures, acquisitions
and general corporate and other activities;
|
|
|
|
limiting managements discretion in operating our business;
|
|
|
|
limiting our flexibility in planning for, or reacting to,
changes in our business and the industry in which we operate;
|
|
|
|
detracting from our ability to withstand, successfully, a
downturn in our business or the economy generally;
|
|
|
|
placing us at a competitive disadvantage against less leveraged
competitors; and
|
|
|
|
making us vulnerable to increases in interest rates, because
debt under our bank credit facility will, in some cases, vary
with prevailing interest rates.
|
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 several 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.
40
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 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.
Ownership
of property interests and production operations in areas outside
the United States is subject to foreign currency
risks.
To the extent we generate revenue outside the U.S., our
operations will be sensitive to fluctuations in foreign currency
exchange rates, particularly through the weakening of the
U.S. dollar relative to other currencies. We may experience
currency exchange or other financial losses where we do not take
or unsuccessfully take protective measures against exposure to a
foreign currency, such as through currency exchange contracts.
We also may incur losses as a result of controls over currency
exchange or controls over the repatriation of income or capital.
Our financial statements, presented in U.S. dollars, are
affected by foreign currency fluctuations through both
translation risk and transaction risk.
|
|
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; Lafayette,
Louisiana; and Calgary, Canada. As of December 31, 2009,
our leases covered approximately 102,192 square feet,
6,580 square feet, 14,376 square feet and
3,850 square feet of office space in Houston, Midland,
Lafayette and Calgary, respectively. The leases run through
October 31, 2018, October 31, 2011, September 30,
2013 and November 30, 2014 in Houston, Midland, Lafayette
and Calgary, respectively. The total annual costs of our leases
for 2009 were approximately $3.2 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 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, September 2008 and August 2009, 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 2008, and, accordingly, that royalties were due under
such leases on oil and gas produced in those years (the
Orders). Mariner and MERI believed that the MMS did
not have the statutory authority to include commodity price
threshold language in leases governed by Section 304 of the
RRA, withheld payment of royalties, and challenged the
MMSs authority in administrative appeals respecting those
41
leases subject to the Orders. In February 2010, the MMS notified
us that it withdrew the Orders, rendering our appeals moot and
closing the matter in our favor.
The enforceability of the price threshold provisions in leases
granted pursuant to Section 304 of the RRA was being
litigated in several administrative appeals filed by other
companies in addition to us, as well as in Kerr-McGee
Oil & Gas Corp. v. Allred, 554 F.3d 1082
(5th Cir.), cert denied, Dept of the
Interior v.
Kerr-McGee
Oil & Gas Corp., 130 S. Ct. 236 (2009).
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 (DOI) 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. On
April 14, 2009, the Fifth Circuit denied the DOIs
Petition for Rehearing En Banc. On July 13, 2009, the DOI
filed a Petition for a Writ of Certiorari with the Supreme Court
of the United States. On October 5, 2009, the
U.S. Supreme Court denied the Petition for a Writ of
Certiorari. Accordingly, the Fifth Circuits judgment that
the price threshold provisions are unlawful and unenforceable
under Section 304 of the RRA is final. This judgment was
the basis upon which the MMS withdrew the Orders.
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.
|
|
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 22, 2010) 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
|
|
|
52
|
|
|
Chairman of the Board, Chief Executive Officer and President
|
Dalton F. Polasek
|
|
|
58
|
|
|
Chief Operating Officer
|
Jesus G. Melendrez
|
|
|
51
|
|
|
Senior Vice President, Chief Commercial Officer, Acting Chief
Financial Officer and Treasurer
|
Mike C. van den Bold
|
|
|
47
|
|
|
Senior Vice President and Chief Exploration Officer
|
Judd A. Hansen
|
|
|
54
|
|
|
Senior Vice President Shelf and Onshore
|
Teresa G. Bushman
|
|
|
60
|
|
|
Senior Vice President, General Counsel and Secretary
|
Cory L. Loegering
|
|
|
54
|
|
|
Senior Vice President Deepwater
|
Murray W. Grigg
|
|
|
54
|
|
|
Vice President Unconventional Resources
|
Emily R. McClung
|
|
|
44
|
|
|
Vice President Human Resources
|
Michael C. McCullough
|
|
|
64
|
|
|
Vice President Acquisitions and Divestitures
|
Richard A. Molohon
|
|
|
55
|
|
|
Vice President Reservoir Engineering
|
Kenneth E. Moore, Jr.
|
|
|
63
|
|
|
Vice President Onshore Land
|
Charles H. Odom
|
|
|
56
|
|
|
Vice President Offshore Land and Business Development
|
R. Cris Sherman
|
|
|
49
|
|
|
Vice President and Chief Accounting Officer
|
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
42
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. He is a director of the Bellville Greater Hospital
Foundation and The Association of Former Students of Texas
A&M University.
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.
Jesus G. Melendrez Mr. Melendrez was
named Senior Vice President Chief Commercial Officer
and appointed Acting Chief Financial Officer and Treasurer in
October 2009. He was promoted to Senior Vice
President Corporate Development in April 2006,
serving in that office until October 2009, 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.
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.
43
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.
Murray W. Grigg Mr. Grigg was promoted
to Vice President Unconventional Resources effective
March 2010. He joined Mariner in June 2009 as Director,
Unconventional Resources with more than 30 years of
industry experience as a petroleum engineer. From July 2005 to
June 2009, he was Executive Vice President of Kerogen Resources,
Inc. which he co-founded to specialize in identifying
unconventional oil and gas shale opportunities, particularly in
tight gas sands, gas shales and coal bed methane plays in the
United States and Canada. He focused on these types of plays as
an Engineering Advisor with EnCana Oil & Gas (USA)
from 2004 to July 2005, Chief Exploration Engineer with Tom
Brown, Inc. from 2003 to 2004, Chief Exploration Engineer with
EOG Resources Inc. from 2001 to 2003, and Technical Specialist
with EOG Resources Canada, Inc. from 1998 to 2001.
Mr. Grigg is a member of the American Association of
Petroleum Geologists and Society of Petroleum Engineers.
Emily R. McClung Ms. McClung was
promoted to Vice President Human Resources effective
March 2010, serving as Director of Human Resources from August
2007 to March 2010, and Human Resources Manager from July 2003
to August 2007. She also was employed by Mariner in human
resources from November 1997 to June 2002. From June 2002 to
July 2003, she was Payroll/Benefits Manager of T3 Energy
Services. From August 1988 to November 1997, she was employed by
Bank One Texas, N.A. in customer service, human resource and
trust support capacities, most recently as Trust Account
Specialist in the administration of employee benefit trust plans.
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 40 years of
industry engineering experience, beginning his career in 1968 as
a production engineer with Mobil Oil Corporation.
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.
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.
Charles H. Odom Mr. Odom joined Mariner
in April 2009 as Vice President Offshore Land and
Business Development with more than 30 years of industry
experience. From October 2007 to February 2009,
44
he was Chief Executive Officer of White Bay Energy, LLC, which
he co-founded to focus on oil and gas exploration and
development opportunities in South Texas. From April 2006 to
August 2007, Mr. Odom was the Vice President of Santos USA
responsible for managing oil and gas assets and projects along
the Texas Gulf Coast, on and offshore, and in the
U.S. Rocky Mountain region until its assets were sold. From
August 2005 to August 2007, he was an independent consultant. In
October 2000, Mr. Odom co-founded Gryphon Exploration
Company, which focused on the shallow waters in the Gulf of
Mexico, serving as its Vice President of Land and Business
Development from October 2000 until it was sold in August 2005
to an international oil company. From September 1991 to October
2000, he was President of C. H. Odom Company, a management
consulting firm specializing in oil and gas exploration and
development transactions in the Gulf of Mexico and onshore Texas.
R. Cris Sherman Mr. Sherman joined
Mariner in October 2009 as Vice President and Chief Accounting
Officer with more than 25 years of experience as a
Certified Professional Accountant in the energy industry. He was
a partner at the professional services firm Sirius Solutions,
L.L.L.P. from January 2007 to October 2009, and employed as a
director of Sirius from April 2004 until January 2007. From
March 2003 to April 2004, he was a Director of Reliant
Resources, Inc., primarily responsible for managing accounting
for the retail supply group. From February 2002 to March 2003,
he was Executive Director Accounting Policy of UBS
Warburg Energy, LLC. From July 1998 to February 2002,
Mr. Sherman provided technical accounting and transaction
support primarily to the wholesale gas, power trading and
finance businesses of Enron North America Corp., most recently
as Vice President Transaction Support in 2001 to
2002, and as a Senior Director and Director before then. He was
Director Internal Audit of Dynegy, Inc. from June
1997 to July 1998. He served in various positions with Eastex
Energy Inc. from 1985 to 1988 and 1990 to 1996, most recently as
Vice President and Chief Financial Officer from January 1995 to
May 1996 and Vice President and Controller from June 1993 to
January 1995. From May 1988 to November 1990, he was Vice
President and Controller of Houston Gas Exchange 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
|
|
|
|
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
|
|
|
2009
|
|
|
First Quarter
|
|
$
|
12.59
|
|
|
$
|
6.85
|
|
|
|
|
|
Second Quarter
|
|
|
15.53
|
|
|
|
7.87
|
|
|
|
|
|
Third Quarter
|
|
|
15.19
|
|
|
|
9.88
|
|
|
|
|
|
Fourth Quarter
|
|
|
16.09
|
|
|
|
11.47
|
|
As of February 22, 2010, there were 774 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 2008 or 2009.
Refer below 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 Item 8 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.
45
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
|
|
12/31/09
|
|
Mariner Energy, Inc.
|
|
$
|
100.00
|
|
|
$
|
96.69
|
|
|
$
|
112.88
|
|
|
$
|
50.32
|
|
|
$
|
57.28
|
|
S&P 500 Index
|
|
$
|
100.00
|
|
|
$
|
110.18
|
|
|
$
|
114.07
|
|
|
$
|
70.17
|
|
|
$
|
86.63
|
|
Peer Group(2)
|
|
$
|
100.00
|
|
|
$
|
96.98
|
|
|
$
|
103.61
|
|
|
$
|
37.10
|
|
|
$
|
43.61
|
|
|
|
|
(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. The 2009 data for Energy Partners, Ltd. reflects
adjustment for its issuance on September 21, 2009 of
0.06166332 share of new common stock in exchange for each
former one share of common stock outstanding before its
emergence from bankruptcy. |
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.
46
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, 2009 to October 31, 2009(1)
|
|
|
41,032
|
|
|
$
|
15.74
|
|
|
|
|
|
|
|
|
|
November 1, 2009 to November 30, 2009(1)
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
December 1, 2009 to December 31, 2009(1)
|
|
|
495
|
|
|
$
|
13.35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
41,527
|
|
|
$
|
15.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
These shares were withheld upon the vesting of employee
restricted stock grants in connection with payment of required
withholding taxes. |
47
|
|
Item 6.
|
Selected
Financial Data.
|
The selected financial data table below shows our historical
consolidated financial data as of and for each of the five years
in the period ended December 31, 2009. The historical
consolidated financial data are derived from Mariners
audited Consolidated Financial Statements, including the
consolidated balance sheets at December 31, 2009 and 2008
and the related consolidated statements of operations and cash
flows for each of the three years in the period ended
December 31, 2009, included herein. 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per share data)
|
|
|
Statement of Operations Data(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues(2)
|
|
$
|
942,941
|
|
|
$
|
1,300,507
|
|
|
$
|
874,765
|
|
|
$
|
659,505
|
|
|
$
|
199,710
|
|
Operating expenses(3)
|
|
|
282,353
|
|
|
|
264,832
|
|
|
|
174,522
|
|
|
|
105,739
|
|
|
|
32,218
|
|
Depreciation, depletion and amortization
|
|
|
399,400
|
|
|
|
467,265
|
|
|
|
384,321
|
|
|
|
292,180
|
|
|
|
59,469
|
|
General and administrative expense
|
|
|
79,960
|
|
|
|
60,613
|
|
|
|
42,151
|
|
|
|
33,622
|
|
|
|
36,766
|
|
Operating (loss) income(4)
|
|
|
(581,403
|
)
|
|
|
(381,712
|
)
|
|
|
268,710
|
|
|
|
227,470
|
|
|
|
69,168
|
|
Interest expense, net of amounts capitalized
|
|
|
70,134
|
|
|
|
56,398
|
|
|
|
54,665
|
|
|
|
39,649
|
|
|
|
8,172
|
|
(Benefit) Provision for income taxes
|
|
|
(224,370
|
)
|
|
|
(48,223
|
)
|
|
|
77,324
|
|
|
|
67,344
|
|
|
|
21,294
|
|
Net (loss) income attributable to Mariner Energy, Inc.
|
|
|
(319,409
|
)
|
|
|
(388,713
|
)
|
|
|
143,934
|
|
|
|
121,462
|
|
|
|
40,481
|
|
Earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common share basic
|
|
$
|
(3.34
|
)
|
|
$
|
(4.44
|
)
|
|
$
|
1.68
|
|
|
$
|
1.59
|
|
|
$
|
1.24
|
|
Net (loss) income per common share diluted
|
|
$
|
(3.34
|
)
|
|
$
|
(4.44
|
)
|
|
$
|
1.67
|
|
|
$
|
1.58
|
|
|
$
|
1.20
|
|
|
|
|
(1) |
|
There are no operating results included for the Edge
subsidiaries we acquired on December 31, 2009. |
|
(2) |
|
Includes effects of hedging. |
|
(3) |
|
Operating expenses include lease operating expense, severance
and ad valorem taxes and transportation expenses. |
|
(4) |
|
Includes $754.3 million and $575.6 million of full
cost ceiling test impairments for the years ended
December 31, 2009 and 2008. |
48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Balance Sheet Data(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
$
|
212,321
|
|
|
$
|
374,953
|
|
|
$
|
248,980
|
|
|
$
|
306,018
|
|
|
$
|
141,432
|
|
Current Liabilities
|
|
|
372,611
|
|
|
|
425,564
|
|
|
|
315,189
|
|
|
|
239,727
|
|
|
|
204,006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital deficit
|
|
$
|
(160,290
|
)
|
|
$
|
(50,611
|
)
|
|
$
|
(66,209
|
)
|
|
$
|
66,291
|
|
|
$
|
(62,574
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
2,572,559
|
|
|
|
2,929,877
|
|
|
|
2,420,194
|
|
|
|
2,012,062
|
|
|
|
515,943
|
|
Total assets
|
|
|
2,867,205
|
|
|
|
3,392,793
|
|
|
|
3,083,635
|
|
|
|
2,680,153
|
|
|
|
665,536
|
|
Long-term debt, less current maturities
|
|
|
1,194,850
|
|
|
|
1,170,000
|
|
|
|
779,000
|
|
|
|
654,000
|
|
|
|
156,000
|
|
Stockholders equity
|
|
|
882,955
|
|
|
|
1,120,320
|
|
|
|
1,391,018
|
|
|
|
1,302,591
|
|
|
|
213,336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Cash Flow Data(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
577,667
|
|
|
$
|
862,017
|
|
|
$
|
536,114
|
|
|
$
|
277,161
|
|
|
$
|
165,444
|
|
Net cash used in investing activities
|
|
$
|
(747,108
|
)
|
|
$
|
(1,264,784
|
)
|
|
$
|
(643,780
|
)
|
|
$
|
(561,390
|
)
|
|
$
|
(247,799
|
)
|
Net cash provided by financing activities
|
|
$
|
175,109
|
|
|
$
|
387,429
|
|
|
$
|
116,676
|
|
|
$
|
289,252
|
|
|
$
|
84,370
|
|
|
|
|
(1) |
|
The fair market value of the Edge assets and liabilities we
acquired on December 31, 2009 and cash flows from the
transaction are included in the tables above. |
|
|
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, the Gulf Coast and the Gulf of Mexico. During
2009, we produced approximately 126.5 Bcfe and our average
daily production rate was 347 MMcfe. At December 31,
2009, we had 1.087 Tcfe of estimated proved reserves, of
which approximately 56% were onshore (47% in the Permian Basin
and 8% in the Gulf Coast), with the balance offshore (15% in the
Gulf of Mexico deepwater and 29% on the Gulf of Mexico shelf);
53% were natural gas; and 47% were oil and natural gas liquids
(NGLs). Approximately 66% of our estimated proved
reserves were classified as proved developed.
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 mid-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 sustained recession or
slowdown in economic activity could further 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.
49
Securities Offering. On June 10, 2009, we
sold and issued in concurrent underwritten offerings
$300.0 million aggregate principal amount of our
113/4% senior
notes due 2016, and 11.5 million shares of our common stock
at a public offering price of $14.50 per share. We used
aggregate proceeds from the concurrent offerings, before
deducting estimated offering expenses but after deducting
underwriters discounts and commissions, of approximately
$446.2 million to repay debt under our bank credit facility.
Acquisitions On December 31, 2009, we
acquired the reorganized Edge subsidiaries and operations. The
material assets acquired consist primarily of (i) proved
reserves estimated by Ryder Scott Company, L.P. as of
December 31, 2009 of 100.5 Bcfe, of which
approximately 75% are developed (consisting of 69% natural gas
and 31% oil and NGLs), 81% are located in South Texas, and 44%
are in the Flores/Bloomberg field in Starr County, Texas,
(ii) approximately 60,000 net acres of undeveloped
leasehold, primarily in Texas and New Mexico, and
(iii) deferred tax assets of approximately
$83.3 million, comprised of approximately
$61.2 million in net operating loss carryforwards and
$22.1 million in built-in losses from carryover tax basis
in the properties. The effective date of the acquisition was
June 30, 2009 and the purchase price was
$260.0 million, less adjustments which resulted in a net
purchase price as of December 31, 2009 of approximately
$213.6 million, subject to final adjustments. We financed
the net purchase price by borrowing under our secured revolving
credit facility.
We recorded a gain on the acquisition of approximately
$107.3 million. A gain on acquisition, or a bargain
purchase, can happen in a business combination that is a forced
sale in which the seller is acting under compulsion. Edge filed
for federal bankruptcy protection in October 2009. In December
2009, we were the winning bidder in the bankruptcy auction for
Edges subsidiaries. In addition to Edges distressed
circumstances, the recent worldwide financial and credit crisis
generally depressed financial and commodity markets and demand
for energy assets, thereby further increasing the opportunity
for a bargain purchase. A buyer is required to recognize in
income from continuing operations changes in the amount of its
recognizable deferred tax benefits resulting from a business
combination when circumstances allow. We structured our purchase
of Edges reorganized subsidiaries as a stock acquisition
to obtain the associated tax attributes that we expect to
benefit us in future periods. Those attributes were recorded as
deferred tax assets on an undiscounted basis in accordance with
Accounting Standards Codification Topic 805
Business Combinations and contributed to the
gain recognized on acquisition.
On December 19, 2008, we acquired additional working
interests in our existing property, Atwater Valley
Block 426 (Bass Lite), for approximately
$30.6 million, increasing our working interest by 11.6% to
53.8%.
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. We
operate substantially all of the assets. The purchase prices
were $23.5 million for the February 2008 acquisition and
$19.4 million for the December 2008 acquisition.
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. We paid
$228.8 million for MGOM.
50
Results
of Operations
Year
Ended December 31, 2009 compared to Year Ended
December 31, 2008
Operating
and Financial Results for the Year Ended December 31,
2009
Compared to the Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
(Decrease)
|
|
|
% change
|
|
|
|
(In thousands, except average sales price and unit costs)
|
|
|
Summary Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
90,801
|
|
|
|
79,756
|
|
|
|
11,045
|
|
|
|
14
|
%
|
Oil (MBbls)
|
|
|
4,472
|
|
|
|
4,881
|
|
|
|
(409
|
)
|
|
|
(8
|
)%
|
Natural gas liquids (MBbls)
|
|
|
1,478
|
|
|
|
1,558
|
|
|
|
(80
|
)
|
|
|
(5
|
)%
|
Total natural gas equivalent (MMcfe)
|
|
|
126,498
|
|
|
|
118,389
|
|
|
|
8,109
|
|
|
|
7
|
%
|
Average daily production (MMcfe per day)
|
|
|
347
|
|
|
|
323
|
|
|
|
24
|
|
|
|
7
|
%
|
Hedging Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue gain (loss)
|
|
$
|
187,857
|
|
|
$
|
(28,047
|
)
|
|
$
|
215,904
|
|
|
|
770
|
%
|
Oil revenue gain (loss)
|
|
|
44,801
|
|
|
|
(72,762
|
)
|
|
|
117,563
|
|
|
|
162
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total hedging revenue gain (loss)
|
|
$
|
232,658
|
|
|
$
|
(100,809
|
)
|
|
$
|
333,467
|
|
|
|
331
|
%
|
Average Sales Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) realized(1)
|
|
$
|
6.08
|
|
|
$
|
9.31
|
|
|
$
|
(3.23
|
)
|
|
|
(35
|
)%
|
Natural gas (per Mcf) unhedged
|
|
|
4.01
|
|
|
|
9.66
|
|
|
|
(5.65
|
)
|
|
|
(58
|
)%
|
Oil (per Bbl) realized(1)
|
|
|
70.59
|
|
|
|
86.02
|
|
|
|
(15.43
|
)
|
|
|
(18
|
)%
|
Oil (per Bbl) unhedged
|
|
|
60.57
|
|
|
|
100.93
|
|
|
|
(40.36
|
)
|
|
|
(40
|
)%
|
Natural gas liquids (per Bbl) realized(1)
|
|
|
33.10
|
|
|
|
55.02
|
|
|
|
(21.92
|
)
|
|
|
(40
|
)%
|
Natural gas liquids (per Bbl) unhedged
|
|
|
33.10
|
|
|
|
55.02
|
|
|
|
(21.92
|
)
|
|
|
(40
|
)%
|
Total natural gas equivalent ($/Mcfe) realized(1)
|
|
|
7.25
|
|
|
|
10.54
|
|
|
|
(3.29
|
)
|
|
|
(31
|
)%
|
Total natural gas equivalent ($/Mcfe) unhedged
|
|
|
5.41
|
|
|
|
11.39
|
|
|
|
(5.98
|
)
|
|
|
(53
|
)%
|
Summary of Financial Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
552,259
|
|
|
$
|
742,370
|
|
|
$
|
(190,111
|
)
|
|
|
(26
|
)%
|
Oil revenue
|
|
|
315,642
|
|
|
|
419,878
|
|
|
|
(104,236
|
)
|
|
|
(25
|
)%
|
Natural gas liquids revenue
|
|
|
48,921
|
|
|
|
85,715
|
|
|
|
(36,794
|
)
|
|
|
(43
|
)%
|
Other revenues
|
|
|
26,119
|
|
|
|
52,544
|
|
|
|
(26,425
|
)
|
|
|
(50
|
)%
|
Lease operating expense
|
|
|
249,449
|
|
|
|
231,645
|
|
|
|
17,804
|
|
|
|
8
|
%
|
Severance and ad valorem taxes
|
|
|
14,410
|
|
|
|
18,191
|
|
|
|
(3,781
|
)
|
|
|
(21
|
)%
|
Transportation expense
|
|
|
18,494
|
|
|
|
14,996
|
|
|
|
3,498
|
|
|
|
23
|
%
|
General and administrative expense
|
|
|
79,960
|
|
|
|
60,613
|
|
|
|
19,347
|
|
|
|
32
|
%
|
Depreciation, depletion and amortization
|
|
|
399,400
|
|
|
|
467,265
|
|
|
|
(67,865
|
)
|
|
|
(15
|
)%
|
Full cost ceiling test impairment
|
|
|
754,325
|
|
|
|
575,607
|
|
|
|
178,718
|
|
|
|
31
|
%
|
Goodwill impairment
|
|
|
|
|
|
|
295,598
|
|
|
|
(295,598
|
)
|
|
|
(100
|
)%
|
Other property impairment
|
|
|
|
|
|
|
15,252
|
|
|
|
(15,252
|
)
|
|
|
(100
|
)%
|
Other miscellaneous expense
|
|
|
8,306
|
|
|
|
3,052
|
|
|
|
5,254
|
|
|
|
172
|
%
|
Net interest expense
|
|
|
69,635
|
|
|
|
55,036
|
|
|
|
14,599
|
|
|
|
27
|
%
|
Gain on acquisition
|
|
|
107,259
|
|
|
|
|
|
|
|
107,259
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before taxes
|
|
|
(543,779
|
)
|
|
|
(436,748
|
)
|
|
|
107,031
|
|
|
|
25
|
%
|
Benefit for income taxes
|
|
|
(224,370
|
)
|
|
|
(48,223
|
)
|
|
|
176,147
|
|
|
|
365
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss
|
|
|
(319,409
|
)
|
|
|
(388,525
|
)
|
|
|
(69,116
|
)
|
|
|
(18
|
)%
|
Less: Net income attributable to noncontrolling interest
|
|
|
|
|
|
|
(188
|
)
|
|
|
(188
|
)
|
|
|
(100
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss attributable to Mariner Energy, Inc.
|
|
$
|
(319,409
|
)
|
|
$
|
(388,713
|
)
|
|
$
|
(69,304
|
)
|
|
|
(18
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
1.97
|
|
|
$
|
1.96
|
|
|
$
|
0.01
|
|
|
|
1
|
%
|
Severance and ad valorem taxes
|
|
|
0.11
|
|
|
|
0.15
|
|
|
|
(0.04
|
)
|
|
|
(27
|
)%
|
Transportation expense
|
|
|
0.15
|
|
|
|
0.13
|
|
|
|
0.02
|
|
|
|
15
|
%
|
General and administrative expense
|
|
|
0.63
|
|
|
|
0.51
|
|
|
|
0.12
|
|
|
|
24
|
%
|
Depreciation, depletion and amortization
|
|
|
3.16
|
|
|
|
3.95
|
|
|
|
(.79
|
)
|
|
|
(20
|
)%
|
|
|
|
(1) |
|
Average realized prices include the effects of hedges. |
51
Net Loss attributable to Mariner Energy, Inc. for 2009
was $319.4 million compared to $388.7 million for
2008. The decrease was primarily attributable to an
$132.1 million decrease in impairments, a
$67.9 million decrease in depreciation, depletion and
amortization and a $176.1 million increase in income tax
benefit. These were partially offset by a decrease in revenues
of $357.6 million, a $107.3 million gain on
acquisition and an increase in general and administrative
expense of $19.3 million. Basic and diluted earnings per
share for 2009 were $(3.34) for each measure compared to $(4.44)
for each measure for 2008.
Net Production for 2009 was approximately
126.5 Bcfe, up 8.1 Bcfe or 6.8% from 118.4 Bcfe
from 2008. Natural gas production for 2009 comprised
approximately 72% of total production compared to approximately
67% for 2008.
Natural gas production for 2009 increased 14% to approximately
249 MMcf per day, compared to approximately 218 MMcf
per day for 2008. Oil production for 2009 decreased 8% to
approximately 12,251 barrels per day, compared to
approximately 13,300 barrels per day for 2008. Natural gas
liquids production for 2009 decreased 5% to approximately
4,049 barrels per day, as compared to approximately
4,257 barrels per day for 2008.
Period over period changes in our production were primarily
attributable to the following:
|
|
|
|
|
Increased production of 3.4 Bcfe, or 23%, from our onshore
properties, primarily as a result of our drilling and
development of existing acreage in the Permian Basin.
|
|
|
|
Increased production of 12.4 Bcfe, or 31%, from our Gulf of
Mexico deepwater properties, due primarily to Bass Lite located
in Atwater Valley 426 (which contributed 9.9 Bcfe) and
Geauxpher located in Garden Banks 462 (which contributed
13.0 Bcfe), partially offset by decreases at Pluto located
in Mississippi Canyon 674 (which contributed 3.1 Bcfe) and
Northwest Nansen located in East Breaks 602 (which contributed
6.0 Bcfe).
|
|
|
|
Decreased production of 7.7 Bcfe, or 12%, from our Gulf of
Mexico shelf properties as a result of normal depletion declines
and production interruptions due to repairs on certain fields
totaling 18.8 Bcfe, partially offset by increased
production of 11.1 Bcfe at certain of our properties
including High Island 116 (which contributed 3.4 Bcfe) and
South Marsh Island 76 (which contributed 1.1 Bcfe).
|
Natural gas, oil and NGL revenues for 2009 decreased 27%
to $916.8 million compared to $1,248.0 million for
2008 as a result of lower realized prices (approximately
$416.6 million, net of the effect of hedging), which was
partially offset by increased production (approximately
$85.5 million).
During 2009, our revenues reflected a net recognized hedging
gain of $232.7 million, comprised of $173.7 million in
favorable cash settlements on our hedges, a $58.7 million
reclassification on our liquidated swaps in 2009 and an
unrealized gain of approximately $0.3 million related to
the ineffective portion of open contracts that are not eligible
for deferral in conformity with accounting for derivatives and
hedging under GAAP due primarily to the basis differentials
between the contract price and the indexed price at the point of
sale. This compares to a net recognized hedging loss of
approximately $100.8 million for 2008, 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 GAAP.
52
Our natural gas and oil average sales prices, and the effects of
hedging activities on those prices, are listed in the table
below. We did not conduct hedging activities related to NGL
sales for the years ended December 31, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedging
|
|
|
|
|
|
|
Realized
|
|
|
Unhedged
|
|
|
(Loss) Gain
|
|
|
% Change
|
|
|
Year Ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
6.08
|
|
|
$
|
4.01
|
|
|
$
|
2.07
|
|
|
|
52
|
%
|
Oil (per Bbl)
|
|
|
70.59
|
|
|
|
60.57
|
|
|
|
10.02
|
|
|
|
17
|
%
|
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
|
)%
|
Other revenues for 2009 decreased approximately
$26.4 million to $26.1 million from $52.5 million
for 2008 due primarily to the release of suspended revenue of
$46.5 million in 2008 related to a potential MMS royalty
liability and imputed rent income of $4.3 million in 2008
from the lease of office property acquired in January 2008,
partially offset by a $16.6 million arbitration award
related to a consummated acquisition and $7.4 million in
third party gas sales on commodities purchased to satisfy our
pipeline transportation commitments (discussed in other
miscellaneous expense).
Lease operating expense (LOE) for 2009
increased approximately $17.8 million to
$249.4 million from $231.6 million for 2008, primarily
due to increased costs of $16.5 million attributable to
processing fees primarily related to Atwater 426 (Bass Lite) and
Garden Banks 462 (Geauxpher) not included in first three
quarters of 2008 due to production on those fields commencing
subsequent to that period, $19.9 million of repairs on
certain properties (including $2.6 million on South Marsh
Island 11 and $1.9 million on Eugene Island 292) and
$11.8 million for repairs related to Hurricane Ike. These
increases were offset by a decrease of $24.0 million in the
retrospective contingent OIL insurance premium.
Severance and ad valorem tax for 2009 decreased
approximately $3.8 million to $14.4 million from
$18.2 million for 2008 due to lower production taxes of
$4.5 million, partially offset by increased ad valorem
taxes of $0.7 million.
Transportation expense for 2009 increased approximately
$3.5 million to $18.5 million from $15.0 million
for 2008 due primarily to increased expense at Bass Lite located
in Atwater 426.
General and administrative expense (G&A)
for 2009 increased approximately $19.4 million to
$80.0 million from $60.6 million for 2008. The
increase was due primarily to an increase in share-based
compensation expense of approximately $8.1 million to
$29.1 million from $21.0 million for 2008. Of this
increase, $4.6 million was attributable to long-term
performance-based restricted stock awarded during 2008 and
$3.5 million was due to shares of restricted stock grants
made during 2009. 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. Professional fees and salaries
and wages increased $11.4 million to $63.2 million
from $51.8 million in 2008, mainly due to non-recurring
projects and additional headcount. Capitalized G&A related
to our acquisition, exploration and development activities
increased $1.4 million to $21.2 million from
$19.8 million in 2008.
Depreciation, depletion, and amortization expense
(DD&A) for 2009 decreased approximately
$67.9 million to $399.4 million ($3.16 per Mcfe) from
$467.3 million ($3.95 Mcfe) for 2008. This decrease
primarily resulted from the effects of ceiling test impairments
in 2009 and 2008 of $704.7 million and $575.6 million,
respectively, that substantially lowered the basis of our oil
and gas properties. The change in the depletion rate resulted in
a $107.4 million decrease in expense, partially offset by a
$30.2 million increase in expense due to higher production
for 2009 as compared to 2008.
Full cost ceiling test impairment of $49.6 million
was recognized for the fourth quarter 2009 and
$704.7 million was recognized for the first quarter 2009 as
a result of the net capitalized cost of our proved
53
oil and gas properties exceeding our ceiling limit. See
Critical Accounting Policies and
Estimates Full Cost Ceiling Test for more
detail on this impairment.
Goodwill impairment of $295.6 million was recorded
in the fourth quarter 2008 as a result of our annual impairment
test. The goodwill was originally recorded in conjunction with a
merger transaction consummated in March 2006 and the impairment
was a result of weakened economic conditions and a decline in
our stock price during the fourth quarter 2008. See
Critical Accounting Policies and
Estimates Goodwill for more detail on this
impairment. The impairment reduced our net goodwill balance to
$0 at December 31, 2008 and therefore no goodwill
impairment was noted during 2009.
Other property impairment of $15.3 million was
recognized as a result of our annual impairment assessment
performed on our other property at December 31, 2008. See
Critical Accounting Policies and
Estimates Other Property for more detail on
this impairment. No property impairment was recognized during
2009.
Other miscellaneous expense for 2009 increased
approximately $5.3 million to $8.3 million from
$3.0 million for 2008, due primarily to third party gas
purchases of $6.8 million made to satisfy our pipeline
transportation commitments, the sales of which are included in
other miscellaneous income and increased ad valorem tax of
$1.3 million, partially offset by a decrease in bad debt
expense of approximately $2.9 million.
Net interest expense for 2009 increased approximately
$14.6 million to $69.6 million from $55.0 million
for 2008, due primarily to increased interest expense of
$20.9 million as a result of our issuance of
113/4% senior
notes due 2016, partially offset by decreased interest expense
of $8.4 million on our credit facility as a result of lower
interest rates and reduced borrowing in 2009 as compared to 2008
and increased capitalized interest of $5.1 million.
Gain on acquisition for 2009 of $107.3 was recognized as
a result of our acquisition of the reorganized Edge subsidiaries
and operations. See Note 2 Acquisitions in the
Notes to the Consolidated Financial Statements in Part II,
Item 8 of this Annual Report on
Form 10-K
for more detail.
Provision for income taxes for 2009 reflected an
effective tax rate of 41.3% as compared to 11.0% for 2008. The
increase in our effective tax rate was due primarily to the
effect of a permanent non-deductible goodwill impairment of
$295.6 million in 2008 and a permanent book-tax difference
attributable to the non-taxable gain on acquisition of
$107.3 million in 2009 discussed above. The 2009 effective
tax rate excluding the non-taxable gain on acquisition would
have been 34.5%. The 2008 effective tax rate excluding the
goodwill impairment would have been 34.2%.
54
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 and unit costs)
|
|
|
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
|
|
Other miscellaneous expense
|
|
|
3,052
|
|
|
|
5,061
|
|
|
|
(2,009
|
)
|
|
|
(40
|
)%
|
Other income
|
|
|
|
|
|
|
5,811
|
|
|
|
(5,811
|
)
|
|
|
(100
|
)%
|
Net interest expense
|
|
|
55,036
|
|
|
|
53,262
|
|
|
|
1,774
|
|
|
|
3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) before taxes
|
|
|
(436,748
|
)
|
|
|
221,259
|
|
|
|
(658,007
|
)
|
|
|
(297
|
)%
|
(Benefit) Provision for income taxes
|
|
|
(48,223
|
)
|
|
|
77,324
|
|
|
|
(125,547
|
)
|
|
|
(162
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
|
(388,525
|
)
|
|
|
143,935
|
|
|
|
(532,460
|
)
|
|
|
(370
|
)%
|
Less: Net income attributable to noncontrolling interest
|
|
|
(188
|
)
|
|
|
(1
|
)
|
|
|
(187
|
)
|
|
|
(18,700
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) attributable to Mariner Energy,
Inc.
|
|
$
|
(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. |
Net Loss attributable to Mariner Energy, Inc. 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
55
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 on our hedges and an unrealized
loss of $2.0 million related to the ineffective portion of
open contracts that are not eligible for deferral in conformity
with accounting for derivatives and hedging under GAAP due
primarily to the basis differentials between the contract price
and the indexed price at the point of sale. 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 GAAP.
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 for 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.
56
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 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 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 share-based compensation expense of approximately
$10.1 million to $21.0 million from $10.9 million
for 2007. This increase was due primarily 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 share-based 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 2008 as a result of our annual impairment
test. The goodwill was originally recorded in conjunction with a
merger transaction consummated in March 2006 and the impairment
is a result of weakened economic conditions and a decline in our
stock price during the fourth quarter 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 assessment
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
$1.7 million to $55.0 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.
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%.
57
Liquidity
and Capital Resources
Financial
Condition
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except ratios)
|
|
|
Current ratio(1)
|
|
|
0.6 to 1
|
|
|
|
0.9 to 1
|
|
Working capital deficit(2)
|
|
$
|
(160,290
|
)
|
|
$
|
(50,611
|
)
|
Total debt
|
|
$
|
1,194,850
|
|
|
$
|
1,170,000
|
|
Operating cash flow(3)
|
|
$
|
531,149
|
|
|
$
|
885,887
|
|
Interest expense, net of capitalization
|
|
$
|
70,134
|
|
|
$
|
56,398
|
|
Fixed-charge coverage ratio(4)
|
|
|
|
|
|
|
|
|
Total cash and marketable securities less debt(5)
|
|
$
|
(1,185,931
|
)
|
|
$
|
(1,166,749
|
)
|
Stockholders equity
|
|
$
|
882,955
|
|
|
$
|
1,120,320
|
|
Total liabilities to equity
|
|
|
2.25 to 1
|
|
|
|
2.03 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 cash provided by operating
activities, plus or minus changes in operating assets and
liabilities. See the following Reconciliation of
Non-GAAP Measure: Operating Cash Flow. |
|
(4) |
|
Fixed-charge coverage ratio is net earnings before taxes, net
income attributable to noncontrolling interest and fixed charges
divided by fixed charges (interest expense, net of
capitalization plus amortization of discounts). Due to loss from
operations in 2009 and 2008, the ratio coverage was less than
1:1. We would have needed to generate additional earnings of
$558,440 and $446,399 respectively, to achieve a coverage of 1:1
for that period. |
|
(5) |
|
Total cash and marketable securities less debt is cash and cash
equivalents less long-term debt. |
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,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Net cash provided by operating activities (GAAP)
|
|
$
|
577,667
|
|
|
$
|
862,017
|
|
Changes in operating assets and liabilities
|
|
|
(46,518
|
)
|
|
|
23,870
|
|
|
|
|
|
|
|
|
|
|
Operating cash flow (Non-GAAP)
|
|
$
|
531,149
|
|
|
$
|
885,887
|
|
|
|
|
|
|
|
|
|
|
2009 Cash
Flows
The following table presents cash payments for interest and
income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Cash payments for interest, net of capitalized interest
|
|
$
|
68.9
|
|
|
$
|
62.2
|
|
|
$
|
49.1
|
|
Net cash (refunds) payments for income taxes
|
|
|
(2.0
|
)
|
|
|
2.9
|
|
|
$
|
0.6
|
|
58
Net cash provided by operating activities decreased by
$284.3 million to $577.7 million in 2009 from
$862.0 million in 2008. The decrease was due primarily to
lower revenue resulting from a decrease in realized prices of
$416.6 million, partially offset by increased production of
$85.5 million and a $16.6 million arbitration award.
As of December 31, 2009, we had a working capital deficit
of $160.3 million, due in part to a non-cash current
derivative liability and non-cash abandonment liability offset
by a non-cash deferred income tax assets and $11.1 million
related to the fair market value of current assets acquired in
connection with the acquisition of the reorganized Edge
subsidiaries and operations. In addition, working capital was
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 decreased by
$517.7 million to $747.1 million in 2009 from
$1,264.8 million in 2008 due primarily to decreased capital
expenditures attributable to reduced activity in our drilling
programs partially offset by the 2009 acquisition of the Edge
subsidiaries and operations for approximately
$213.6 million. Additionally, 2008 was impacted by the
acquisition of MGOM, including approximately $15.0 million
of mid-stream assets reflected in other property, and an
increase in other property reflecting an investment of
approximately $34.6 million in office property.
Net cash flows provided by financing activities decreased by
$212.3 million to $175.1 million for 2009 from
$387.4 million for 2008. The decrease was due primarily to
$656.0 million net increased repayments under our bank
credit facility, net of borrowings of approximately
$213.6 million in December 2009 to finance the purchase of
the Edge subsidiaries and operations and $223.5 million in
January 2008 to finance the purchase of MGOM. The decrease was
partially offset by $446.2 million of proceeds (before
deducting estimated offering expenses but after deducting
underwriters discounts and commissions) from debt and
securities offerings in June 2009.
2009 Uses of Capital. Our primary uses of
capital during 2009 were as follows:
|
|
|
|
|
funding capital expenditures (excluding hurricane repairs and
acquisitions) of approximately $524.3 million;
|
|
|
|
funding hurricane repairs and hurricane-related abandonment
expenditures (net of insurance recoveries) of approximately
$6.6 million;
|
|
|
|
paying interest of approximately $68.9 million;
|
|
|
|
funding the purchase of the Edge subsidiaries and operations for
approximately $213.6 million; and
|
|
|
|
paying routine operating and administrative expenses.
|
2009 Capital Expenditures. The following table
presents major components of our capital expenditures during
2009 compared to 2008.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
Oil and natural gas development
|
|
$
|
306,834
|
|
|
$
|
588,456
|
|
Oil and natural gas property acquisitions
|
|
|
236,661
|
|
|
|
302,629
|
|
Oil and natural gas exploration
|
|
|
182,863
|
|
|
|
270,767
|
|
Leasehold acquisitions
|
|
|
21,942
|
|
|
|
152,567
|
|
Corporate expenditures and other
|
|
|
38,462
|
|
|
|
66,668
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures, net of proceeds from property
conveyances
|
|
$
|
786,762
|
|
|
$
|
1,381,087
|
|
|
|
|
|
|
|
|
|
|
2009 Hurricane Expenditures. During the year
ended 2009, we incurred approximately $81.7 million in
hurricane expenditures resulting from Hurricanes Ike and Gustav,
of which $22.7 million were repairs and $59.0 were capital
expenditures. Since 2004, we have incurred approximately
$321.5 million in hurricane
59
expenditures from Hurricanes Ike, Gustav, Ivan, Katrina and
Rita, of which $23.5 million were repairs, $193.9 were
capital expenditures and $104.1 million were
hurricane-related abandonment costs. Net of our deductible of
$24.8 million and insurance proceeds received of
$185.1 million, our insurance receivable at
December 31, 2008 was $8.5 million, all of which 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.
2009 Sources of Capital. Our primary sources
of capital during 2009 were as follows:
|
|
|
|
|
cash flow from operations;
|
|
|
|
net proceeds from sale of senior notes and common stock;
|
|
|
|
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, 2009, 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 $800.0 million scheduled to be
redetermined in February 2010. The redetermination was pending
on February 28, 2010, and we anticipate that it will occur
in March 2010.
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, 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.
We have used borrowings under the facility to facilitate
acquisitions, and have used and may use borrowings under the
facility for general corporate purposes. On June 10, 2009,
we used aggregate proceeds from concurrent offerings of our
113/4% senior
notes due 2016 and common stock, before deducting estimated
offering expenses but after deducting underwriters
discounts and commissions, of approximately $446.2 million
to repay debt under our bank credit facility. These offerings
are discussed further below. We funded our December 2009
acquisition of the Edge subsidiaries and operations by borrowing
approximately $213.6 million under the credit facility.
As of December 31, 2009 and 2008, advances outstanding
under the credit facility were $305.0 million and
$570.0 million, respectively. In addition, as of
December 31, 2009 four letters of credit were outstanding
totaling $4.7 million, of which $4.2 million is
required for plugging and abandonment obligations at certain of
our offshore fields. As of December 31, 2009, after
accounting for the $4.7 million of letters of credit, we
had $490.3 million available to borrow under the credit
facility.
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. At December 31, 2009, when
borrowings at both LIBOR and prime-based rates were outstanding,
the blended interest rate was 3.40% on all amounts borrowed. At
December 31, 2008, the interest rate was 3.31%. During the
year ended December 31, 2009, the commitment fee on unused
capacity was 0.250% to 0.375% per annum through March 23,
2009 and 0.5% per annum thereafter.
60
The credit facility subjects us to various restrictive covenants
and contains 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:
|
|
|
|
|
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 these and other credit facility
covenants as of December 31, 2009 when the ratio of
consolidated current assets plus the unused borrowing base to
consolidated current liabilities was 2.38 to 1.0 and the ratio
of total debt to EBITDA was 1.99 to 1.0. 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.
Our payment and performance of 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 the assets of our
subsidiaries, except our Canadian subsidiary, and guaranteed by
our subsidiaries, other than Mariner Energy Resources, Inc.
which is a co-borrower, and our Canadian subsidiary.
Senior Notes Mariner has outstanding the
following three issues of debt issued in registered
transactions, referred to collectively as the Notes:
|
|
|
|
|
$300 million principal amount of
113/4% Senior
Notes due 2016 issued in June 2009 (the
113/4% Notes);
|
|
|
|
$300 million principal amount of 8% Senior Notes due
2017 issued in April 2007 (the
8% Notes); and
|
|
|
|
$300 million principal amount of
71/2% Senior
Notes due 2013 issued in April 2006 (the
71/2% Notes).
|
We sold and issued the
113/4% Notes
on June 10, 2009 at 97.093% of principal amount, for an
initial yield to maturity of 12.375%, in an underwritten
offering registered under the Securities Act of 1933, as amended
(1933 Act). Net offering proceeds, after
deducting underwriters discounts and estimated offering
expenses but before giving effect to the underwriters
reimbursement of up to $0.5 million for offering expenses,
were approximately $284.8 million. We used net offering
proceeds (before deducting estimated offering expenses) to repay
debt under our bank credit facility. The
113/4% Notes
were issued under an Indenture among Mariner, the guarantors
party thereto and Wells Fargo Bank, N.A., as trustee (the
Base Indenture), as amended and supplemented by the
First Supplemental Indenture thereto among the same parties,
each dated as of June 10, 2009. Pursuant to the Base
Indenture, we may issue multiple series of debt securities from
time to time.
The Notes are governed by indentures that are substantially
identical for each series. 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 our existing and future senior
unsecured indebtedness, and are effectively subordinated in
right of payment to our senior secured indebtedness, including
our obligations under our 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 our 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
61
of the guarantor subsidiary and effectively subordinate to all
existing and future secured indebtedness of the guarantor
subsidiary, including its guarantees of indebtedness under our
bank credit facility, to the extent of the collateral securing
such indebtedness.
The
113/4% Notes
mature on June 30, 2016 with interest payable on June 30
and December 30 of each year beginning December 30, 2009.
The 8% Notes mature on May 15, 2017 with interest
payable on May 15 and November 15 of each year. The
71/2% Notes
mature on April 15, 2013 with interest payable on April 15
and October 15 of each year. There is no sinking fund for the
Notes.
We may redeem the
113/4% Notes
at any time before June 30, 2013, the 8% Notes at any
time before May 15, 2012 and the
71/2% Notes
at any time before April 15, 2010, 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, we 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:
|
|
|
|
|
113/4% Notes
|
|
8% Notes
|
|
71/2% Notes
|
|
June 30, 2013 at 105.875%
|
|
May 15, 2012 at 104.000%
|
|
April 15, 2010 at 103.750%
|
June 30, 2014 at 102.938%
|
|
May 15, 2013 at 102.667%
|
|
April 15, 2011 at 101.875%
|
June 30, 2015 and after at 100.000%
|
|
May 15, 2014 at 101.333%
|
|
April 15, 2012 and after at 100.000%
|
|
|
May 15, 2015 and after at 100.000%
|
|
|
In addition, before June 30, 2012, we may redeem up to 35%
of the
113/4% Notes
with the proceeds of equity offerings at a price equal to
111.750% of the principal amount of the
113/4% Notes
redeemed plus accrued but unpaid interest. Before May 15,
2010, we 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 a change of control triggering event (as defined in each of
the indentures governing the Notes) occurs, subject to certain
exceptions, we must give holders of the Notes the opportunity to
sell to us 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.
We and our restricted subsidiaries are subject to certain
negative covenants under each of the indentures governing the
Notes. The indentures limit the ability of us and each of our
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 our subsidiaries to us;
|
|
|
|
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
113/4% Notes
offering were approximately $5.9 million, excluding
discounts of $8.7 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. Costs associated with the
71/2% Notes
offering were approximately $8.5 million, excluding
discounts of $3.8 million.
62
Common Stock Offering On June 10, 2009,
we sold and issued 11.5 million shares of our common stock
at a public offering price of $14.50 per share in an
underwritten offering registered under the 1933 Act. The
total sold includes 1.5 million shares issued upon full
exercise of the underwriters overallotment option. Net
offering proceeds, after deducting underwriters discounts
and estimated offering expenses but before giving effect to the
underwriters reimbursement of up to $0.5 million for
offering expenses, were approximately $159.2 million. We
used net offering proceeds (before deducting estimated offering
expenses of approximately $0.5 million) to repay debt under
our bank credit facility.
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 we may identify;
|
|
|
|
paying routine operating and administrative expenses; and
|
|
|
|
paying other commitments comprised largely of cash settlement of
hedging obligations and debt service.
|
2010
Capital Expenditures.
We anticipate that our base operating capital expenditures for
2010 will be approximately $660.0 million (excluding
hurricane-related expenditures and acquisitions), with
significant potential for increase or decrease depending upon
drilling success, acquisition opportunities and cash flow during
the year. Approximately 67% of the base operating capital
program is planned to be allocated to development activities,
26% 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
$44.5 million during 2010 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, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Period
|
|
|
|
Total
|
|
|
2010
|
|
|
2011-2012
|
|
|
2013-2014
|
|
|
Thereafter
|
|
|
|
(In thousands)
|
|
|
Debt obligations(1)
|
|
$
|
1,205,000
|
|
|
$
|
|
|
|
$
|
305,000
|
|
|
$
|
300,000
|
|
|
$
|
600,000
|
|
Interest obligations(2)
|
|
|
501,434
|
|
|
|
92,120
|
|
|
|
174,734
|
|
|
|
124,973
|
|
|
|
109,607
|
|
Operating leases
|
|
|
19,841
|
|
|
|
2,620
|
|
|
|
5,089
|
|
|
|
4,201
|
|
|
|
7,931
|
|
Abandonment liabilities
|
|
|
417,887
|
|
|
|
54,915
|
|
|
|
105,214
|
|
|
|
51,844
|
|
|
|
205,914
|
|
Seismic obligations
|
|
|
7,933
|
|
|
|
6,929
|
|
|
|
1,004
|
|
|
|
|
|
|
|
|
|
Capital accrual obligations
|
|
|
140,941
|
|
|
|
140,941
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OIL Theoretical Withdrawal(3)
|
|
|
48,000
|
|
|
|
11,040
|
|
|
|
24,493
|
|
|
|
12,467
|
|
|
|
|
|
Rig commitment
|
|
|
15,686
|
|
|
|
15,686
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other liabilities(4)
|
|
|
103,547
|
|
|
|
103,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash commitments
|
|
$
|
2,460,269
|
|
|
$
|
427,798
|
|
|
$
|
615,534
|
|
|
$
|
493,485
|
|
|
$
|
923,452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
As of December 31, 2009, we had incurred debt obligations
under our bank credit facility and the Notes. |
|
(2) |
|
Interest obligations represent interest due on the bank credit
facility and the Notes per annum. Future interest obligations
under our bank credit facility are uncertain, due to the
variable interest rate on fluctuating balances. Based on a 3.40%
weighted average interest rate on amounts outstanding under our |
63
|
|
|
|
|
bank credit facility as of December 31, 2009, our cash
payments for interest would be $10.4 million annually for
2010 through 2011 and $0.9 million in 2012. |
|
(3) |
|
We have accrued approximately $48.0 million as of
December 31, 2009, 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. |
|
(4) |
|
Other liabilities include accrued LOE of $21.3 million,
accrued liabilities of $15.2 million, gas balancing of
$9.7 million, oil and gas payable of $38.8 million,
accrued compensation of $12.0 million, other G&A of
$3.3 million and other liabilities for $3.2 million. |
Adequacy
of Capital Sources and Liquidity
Future Capital Resources. Our anticipated
sources of liquidity in the future are as follows:
|
|
|
|
|
cash flow from operations in future periods;
|
|
|
|
proceeds under our bank credit facility;
|
|
|
|
proceeds from insurance policies relating to hurricane
repairs; and
|
|
|
|
proceeds from future capital markets transactions as needed.
|
Historically, we generally have tailored our operating capital
program (exclusive of hurricane-related expenditures and
acquisitions) within our projected operating cash flow so that
our operating capital requirements were largely self-funding. In
2010, we anticipate that this program will exceed our projected
operating cash flow due primarily to accelerated development of
our long-lived, oily Permian Basin properties, and development
of two deepwater discoveries and our unconventional resource
portfolio. 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. We
generally expect to fund future acquisitions on a case by case
basis through a combination of bank debt and capital markets
activities.
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
Our 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, 2009, four such letters
of credit totaling $4.7 million were outstanding.
64
Fair
Value Measurement
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.
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 accounting for fair value measurements and disclosures
under GAAP.
During the twelve months ended December 31, 2009, we
recorded a net liability for the decrease in the fair value of
our derivative financial instruments of $161.5 million,
principally due to the increase in natural gas and oil commodity
prices above our swap prices. The decrease was comprised of a
decrease in accumulated other comprehensive income of
approximately $253.7 million, net of income taxes of
$140.8 million, approximately $173.7 million of
favorable cash hedging settlements and a $58.7 million gain
on liquidated swaps during the period reflected in natural gas
and oil revenues and an unrealized non-cash gain due to hedging
ineffectiveness under GAAP of approximately $0.3 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 our 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 accounting for asset retirement and
environmental obligations under GAAP, 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 reduce net capitalized costs
65
unless the sale or disposition causes a significant change in
the relationship between costs and the estimated value of proved
reserves.
Full
Cost Ceiling Test
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 natural gas and oil prices used to
calculate the full cost ceiling limitation are the
12-month
average prices, calculated as the unweighted arithmetic average
of the
first-day-of-the-month
price for each month within the
12-month
period prior to the end of the reporting period, 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 accounting for derivative
instruments and hedging activities under GAAP to hedge against
the volatility of oil and natural gas prices. In accordance with
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, 2009, the net capitalized cost of proved
oil and gas properties exceeded the ceiling limit and we
recorded an impairment of $49.6 million
($31.9 million, net of tax). The impairment would have been
$159.2 million ($102.3 million, net of tax) if we had
not used hedge adjusted prices for the volumes that were subject
to hedges. This impairment is due primarily to a decline in the
12-month
average oil and gas commodity prices used from January 1,
2009 through December 1, 2009 as compared to the spot
prices utilized at March 31, 2009 and December 31,
2008 when we recorded non-cash ceiling test impairments of
$704.7 million ($454.6 million, net of tax) and
$575.6 million ($369.1 million, net of tax),
respectively. The ceiling limit of our proved reserves was
calculated at December 31, 2009 based upon
12-month
average market prices of $3.87 per Mcf for gas and $61.18 per
barrel for oil, adjusted for market differentials. At
March 31, 2009 and December 31, 2008, the ceiling
limit of our proved reserves was calculated based on quoted
market spot prices of $3.63 and $5.71 per Mcf for gas and $49.65
and $44.61 per barrel for oil, respectively, adjusted for market
differentials. At December 31, 2007 the ceiling limit
exceeded the net capitalized costs of our proved oil and gas
properties and no impairment was recorded. We may be required to
recognize additional non-cash impairment charges in future
reporting periods if the average
12-month
market prices for oil and natural gas were to decline. At
December 31, 2009, we had 48,697,000 MMbtus of natural
gas and 3,815,500 Bbls of oil of future production hedged.
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
Costs associated with unproved properties and properties under
development are excluded from the full cost amortization base
until the properties have been evaluated. Additionally, the
costs associated with seismic data, leasehold acreage, wells
currently drilling and capitalized interest are also initially
excluded from the amortization base. Unevaluated leasehold costs
are either transferred to the amortization base once evaluation
is complete or the lease expires on leasehold acreage. Until
that time, the costs are subject to impairment,
66
which is assessed quarterly. Leasehold costs are transferred to
the amortization base to the extent a property is determined to
be impaired. In addition, a portion of incurred (if not
previously included in the amortization base) and future
estimated development costs associated with qualifying major
development projects may be temporarily excluded from the
amortization base. To qualify, a project must require
significant costs to ascertain the quantities of proved reserves
attributable to the properties under development (e.g., the
installation of an offshore production platform from which
development wells are to be drilled). Incurred and estimated
future development costs are allocated between completed and
future work. Any temporarily excluded costs are included in the
amortization base upon the earlier of when the associated
reserves are determined to be proved or impairment is indicated.
The decision to withhold costs from the amortization base and
the timing of the transfer of those costs into the amortization
base involve a significant amount of judgment and may be subject
to changes over time based on several factors, including our
drilling plans, availability of capital, project economics and
results of drilling on adjacent acreage. At December 31,
2009, we had a total of approximately $292.2 million of
costs excluded from the amortization base of our full cost
pools. Because the application of the full cost ceiling test at
December 31, 2009 resulted in an excess of the carrying
value of oil and gas properties over the ceiling limit,
inclusion of some or all of our unevaluated property costs in
the amortization base, without adding any associated reserves,
would have resulted in a larger ceiling test impairment.
Future
Development and Abandonment Costs
Future development costs include costs incurred to obtain access
to proved reserves, such as drilling costs and the installation
of production equipment. Future abandonment costs include costs
to dismantle and relocate or dispose of production platforms,
gathering systems and related structures and restoration costs
of land and seabed. We develop estimates of these costs for each
of our properties based upon their geographic location, type of
production structure, water depth, reservoir depth and
characteristics, market demand for equipment, currently
available procedures and ongoing consultations with construction
and engineering consultants. Because these costs typically
extend many years into the future, estimating these future costs
is difficult and requires management to make judgments that are
subject to future revisions based upon numerous factors,
including changing technology and the political and regulatory
environment. We review these assumptions and estimates of future
development and abandonment costs on an annual basis, or more
frequently if an event occurs or circumstances change that would
affect our assumptions and estimates.
DD&A
Our rate for recording DD&A is dependent upon estimates of
our proved reserves, future development and abandonment costs
and capital spending. If the estimates of proved reserves
decline, the rate at which we record DD&A expense
increases, reducing our net income. This decline may result from
lower market prices, which may make it uneconomic to drill for
and produce higher cost fields. The decline in proved reserve
estimates may impact the outcome of the full cost ceiling test.
In addition, increases in costs required to develop our reserves
would increase the rate at which we record DD&A expense. We
are unable to predict changes in future development costs as
such costs are dependent on the success of our development
program, as well as future economic conditions.
Abandonment
Liability
In accordance with accounting for asset retirement and
environmental obligations under GAAP, 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 adoption, we recorded an asset
retirement obligation to reflect our legal obligations related
to future plugging and abandonment of our oil and natural gas
wells. The liability is accreted to its then present value each
period, and the capitalized cost, net of salvage, 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.
67
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.
Goodwill
We account for goodwill in accordance with GAAP which 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. At November 30, 2008, we
had $295.6 million in goodwill. 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 2008, the carrying value of our reporting unit exceeded
the fair value of our net assets 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 $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 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 a merger transaction
consummated in March 2006. There was no remaining balance of
goodwill in 2009 to assess for impairment.
Income
Taxes
Our provision for taxes includes both state and federal taxes.
We record our federal income taxes in accordance with accounting
for income taxes under GAAP 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 carryforwards 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.
We also account for uncertainty in income taxes recognized in
the financial statements in accordance with GAAP 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
68
of operations and cash flows. We do not have uncertain tax
positions outstanding and, as such, did not record a liability
for the years ended December 31, 2009 and 2008.
Derivative
Financial Instruments
We utilize 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 accounting for
derivatives and hedging under GAAP. 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 our
Consolidated Statements of Operations as the physical production
hedged by the contracts is delivered. We present the fair value
of our derivatives on a net basis in accordance with GAAP.
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.
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 us 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
We recognize oil and natural gas revenues when they are realized
or realizable and earned. Revenues are considered realized or
realizable and earned when persuasive evidence of an arrangement
exists, delivery has occurred and title has transferred, the
sellers price to the buyer is fixed or determinable and
collectability is reasonably assured.
When we have an interest with other producers in properties from
which natural gas is produced, we use the entitlement method to
account for any imbalances. Imbalances occur when we sell more
or less product than we are entitled to under our ownership
percentage. Revenue is recognized only on the entitlement
percentage of volumes sold. Any amount that we sell in excess of
our entitlement is treated as a liability and is not recognized
as revenue. Any amount of entitlement in excess of the amount we
sell is recognized as revenue and a receivable is accrued.
69
Share-Based
Compensation Expense
We account for share-based compensation in accordance with the
fair value recognition provisions of accounting for stock
compensation under GAAP. Under those fair value recognition
provisions, share-based compensation cost is measured at the
grant date based on the calculated fair 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
In February 2010, the Financial Accounting Standards Board
issued authoritative guidance which requires additional
information to be disclosed principally in respect of
Level 3 fair value measurements and transfers to and from
Level 1 and Level 2 measurements. In addition,
enhanced disclosure is required concerning inputs and valuation
techniques used to determine Level 2 and Level 3 fair
value measurements. The guidance is generally effective for
interim and annual reporting periods beginning after
December 15, 2009; however, the requirements to disclose
separately purchases, sales, issuances, and settlements in the
Level 3 reconciliation are effective for fiscal years
beginning after December 15, 2010 (and for interim periods
within such years). Early adoption is allowed. We are currently
evaluating the potential impact of adoption.
|
|
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 2009
levels, a 10% increase in commodity prices from those as of
December 31, 2009 would increase our cash flow by
approximately $68.4 million for the year ended
December 31, 2010.
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.
During 2009, the Company liquidated certain natural gas and
crude oil fixed price swaps that previously had been designated
as cash flow hedges for accounting purposes in respect of
10,205,560 MMBtu of natural gas and 977,000 Bbls of
crude oil. The Company received $58.7 million in
conjunction with these liquidations and recognized natural gas
and oil revenues of $35.3 million and $23.4 million,
respectively.
70
Derivative 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,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Cash Gain (Loss) on Settlements(1)
|
|
$
|
173,684
|
|
|
$
|
(98,814
|
)
|
|
$
|
46,732
|
|
Gain (Loss) on Hedge Ineffectiveness(1)(2)
|
|
|
264
|
|
|
|
(1,995
|
)
|
|
|
(1,655
|
)
|
Reclassification of Liquidated Swaps(3)
|
|
|
58,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
232,658
|
|
|
$
|
(100,809
|
)
|
|
$
|
45,077
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Designated as cash flow hedges pursuant to accounting for
derivatives and hedging under GAAP. |
|
(2) |
|
Unrealized loss recognized in natural gas revenue related to the
ineffective portion of open contracts that are not eligible for
deferral under GAAP due primarily to the basis differentials
between the contract price and the indexed price at the point of
sale. |
|
(3) |
|
Natural gas and crude oil fixed price swaps liquidated in the
first and third quarter 2009 that do not qualify for hedge
accounting. These amounts include net losses of
$2.8 million for the year ended December 31, 2009. |
As of December 31, 2009, the Company had the following
hedging contracts outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average
|
|
|
Fair Value
|
|
Fixed Price Swaps
|
|
Quantity
|
|
|
Fixed Price
|
|
|
Asset/(Liability)
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Natural Gas (MMbtus)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1 December 31, 2010
|
|
|
22,619,000
|
|
|
$
|
5.88
|
|
|
$
|
2,239
|
|
January 1 December 31, 2011
|
|
|
13,650,000
|
|
|
$
|
6.45
|
|
|
|
1,540
|
|
January 1 December 31, 2012
|
|
|
6,588,000
|
|
|
$
|
6.62
|
|
|
|
497
|
|
January 1 December 31, 2013
|
|
|
5,840,000
|
|
|
$
|
6.76
|
|
|
|
410
|
|
Crude Oil (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1 December 31, 2010
|
|
|
1,934,500
|
|
|
$
|
67.48
|
|
|
|
(27,708
|
)
|
January 1 December 31, 2011
|
|
|
978,100
|
|
|
$
|
73.24
|
|
|
|
(11,309
|
)
|
January 1 December 31, 2012
|
|
|
494,100
|
|
|
$
|
80.77
|
|
|
|
(3,058
|
)
|
January 1 December 31, 2013
|
|
|
408,800
|
|
|
$
|
82.81
|
|
|
|
(2,195
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
(39,584
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008, 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, 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We have reviewed the financial strength of our counterparties
and believe the credit risk associated with these swaps to be
minimal. Hedges with counterparties that are lenders under our
bank credit facility are secured under the bank credit facility.
71
As of December 31, 2009, we expect to realize within the
next 12 months approximately $25.5 million in net
losses resulting from hedging activities currently recorded in
accumulated other comprehensive income. The net hedging loss is
expected to be realized as a decrease of $27.7 million to
oil revenues and an increase of $2.2 million to natural gas
revenues.
Interest
Rate Market Risk
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. At December 31, 2009,
the blended interest rate on our outstanding bank debt was
3.40%. If the balance of our bank debt at December 31, 2009
were to remain constant, a 10% increase in market interest rates
would decrease our cash flow by approximately $1.0 million
for the year ended December 31, 2010.
|
|
Item 8.
|
Financial
Statements and Supplementary Data.
|
Index to
Financial Statements
72
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, 2009. Management excluded from
its evaluation the internal control over financial reporting of
the subsidiaries of Edge Petroleum Corporation (the Edge
Subsidiaries) which Mariner acquired on December 31,
2009. The total assets of the Edge Subsidiaries as of
December 31, 2009 constituted approximately 11% of
Mariners total assets as of December 31, 2009.
Deloitte & Touche LLP, Mariners independent
auditor for 2009, 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/ Jesus
G. Melendrez
|
Scott D. Josey,
Chairman of the Board,
Chief Executive Officer and President
|
|
Jesus G. Melendrez,
Senior Vice President, Chief Commercial Officer,
Acting Chief Financial Officer and Treasurer
|
Houston, Texas
March 1, 2010
73
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, 2009 and 2008, and the related
consolidated statements of operations, stockholders
equity, and cash flows for each of the three years in the period
ended December 31, 2009. We also have audited the
Companys internal control over financial reporting as of
December 31, 2009, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway
Commission. As described in Managements Report on Internal
Control over Financial Reporting (Report of
Management), management excluded from its evaluation the
internal control over financial reporting of the subsidiaries of
Edge Petroleum Corporation (the Edge Subsidiaries)
which the Company acquired on December 31, 2009. The total
assets of the Edge Subsidiaries as of December 31, 2009
constituted approximately 11% of the total assets of the Company
as of December 31, 2009. Accordingly, our audit did not
include the internal control over financial reporting of the
Edge Subsidiaries. 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 Report of Management.
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
74
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, 2009 and 2008, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2009, 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, 2009, based on the criteria
established in Internal Control Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
As discussed in Note 1 to the consolidated financial
statements, on December 31, 2009, the Company adopted
Accounting Standards Update
No. 2010-3,
Oil and Gas Reserve Estimation and
Disclosures and Accounting Standards Codification
Topic 805, Business Combinations.
/s/ DELOITTE &
TOUCHE LLP
Houston, Texas
March 1, 2010
75
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except share data)
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
8,919
|
|
|
$
|
3,251
|
|
Receivables, net of allowances of $3,408 and $3,868, respectively
|
|
|
148,725
|
|
|
|
219,920
|
|
Insurance receivables
|
|
|
8,452
|
|
|
|
13,123
|
|
Derivative financial instruments
|
|
|
2,239
|
|
|
|
121,929
|
|
Intangible assets
|
|
|
22,615
|
|
|
|
2,353
|
|
Prepaid expenses and other
|
|
|
11,667
|
|
|
|
14,377
|
|
Deferred income tax
|
|
|
9,704
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
212,321
|
|
|
|
374,953
|
|
Property and Equipment:
|
|
|
|
|
|
|
|
|
Proved oil and gas properties, full cost method
|
|
|
5,117,273
|
|
|
|
4,448,146
|
|
Unproved properties, not subject to amortization
|
|
|
292,237
|
|
|
|
201,121
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas properties
|
|
|
5,409,510
|
|
|
|
4,649,267
|
|
Other property and equipment
|
|
|
55,695
|
|
|
|
53,115
|
|
Accumulated depreciation, depletion and amortization:
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
|
(2,884,411
|
)
|
|
|
(1,767,028
|
)
|
Other properties
|
|
|
(8,235
|
)
|
|
|
(5,477
|
)
|
|
|
|
|
|
|
|
|
|
Total accumulated depreciation, depletion and amortization
|
|
|
(2,892,646
|
)
|
|
|
(1,772,505
|
)
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
2,572,559
|
|
|
|
2,929,877
|
|
Insurance Receivables
|
|
|
|
|
|
|
22,132
|
|
Derivative Financial Instruments
|
|
|
902
|
|
|
|
|
|
Deferred Income Tax
|
|
|
12,491
|
|
|
|
|
|
Other Assets, net of amortization
|
|
|
68,932
|
|
|
|
65,831
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
2,867,205
|
|
|
$
|
3,392,793
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
3,579
|
|
|
$
|
3,837
|
|
Accrued liabilities
|
|
|
137,206
|
|
|
|
107,815
|
|
Accrued capital costs
|
|
|
140,941
|
|
|
|
195,833
|
|
Deferred income tax
|
|
|
|
|
|
|
23,148
|
|
Abandonment liability
|
|
|
54,915
|
|
|
|
82,364
|
|
Accrued interest
|
|
|
8,262
|
|
|
|
12,567
|
|
Derivative financial instruments
|
|
|
27,708
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
372,611
|
|
|
|
425,564
|
|
Long-Term Liabilities:
|
|
|
|
|
|
|
|
|
Abandonment liability
|
|
|
362,972
|
|
|
|
325,880
|
|
Deferred income tax
|
|
|
|
|
|
|
319,766
|
|
Derivative financial instruments
|
|
|
15,017
|
|
|
|
|
|
Long-term debt
|
|
|
1,194,850
|
|
|
|
1,170,000
|
|
Other long-term liabilities
|
|
|
38,800
|
|
|
|
31,263
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
1,611,639
|
|
|
|
1,846,909
|
|
Commitments and Contingencies (see Note 8)
|
|
|
|
|
|
|
|
|
Stockholders Equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $.0001 par value; 20,000,000 shares
authorized, no shares issued and outstanding at
December 31, 2009 and December 31, 2008
|
|
|
|
|
|
|
|
|
Common stock, $.0001 par value; 180,000,000 shares
authorized, 101,806,825 shares issued and outstanding at
December 31, 2009; 180,000,000 shares authorized,
88,846,073 shares issued and outstanding at
December 31, 2008
|
|
|
10
|
|
|
|
9
|
|
Additional
paid-in-capital
|
|
|
1,257,526
|
|
|
|
1,071,347
|
|
Accumulated other comprehensive (loss) income
|
|
|
(25,955
|
)
|
|
|
78,181
|
|
Accumulated deficit
|
|
|
(348,626
|
)
|
|
|
(29,217
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
882,955
|
|
|
|
1,120,320
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY
|
|
$
|
2,867,205
|
|
|
$
|
3,392,793
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes to the Consolidated Financial
Statements
are an integral part of these financial statements
76
MARINER
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands except share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
552,259
|
|
|
$
|
742,370
|
|
|
$
|
534,537
|
|
Oil
|
|
|
315,642
|
|
|
|
419,878
|
|
|
|
284,405
|
|
Natural gas liquids
|
|
|
48,921
|
|
|
|
85,715
|
|
|
|
54,192
|
|
Other revenues
|
|
|
26,119
|
|
|
|
52,544
|
|
|
|
1,631
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
942,941
|
|
|
|
1,300,507
|
|