e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2005
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or
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number:
001-16179
Energy Partners, Ltd.
(Exact name of registrant as
specified in its charter)
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Delaware
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72-1409562
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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201 St. Charles Avenue,
Suite 3400
New Orleans, Louisiana
(Address of principal
executive offices)
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70170
(Zip Code)
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Registrants telephone number, including area code:
504-569-1875
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Exchange on Which
Registered
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Common Stock, Par Value $0.01 Per
Share
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by a 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
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 Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports) and (2) has been subject
to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of the registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2
of the Exchange Act. (Check One)
Large accelerated
filer þ Accelerated
filer o Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined by
Rule 12b-2
of the
Act). Yes o No þ
The aggregate market value of the common stock held by
non-affiliates of the registrant at June 30, 2005 based on
the closing price of such stock as quoted on the New York Stock
Exchange on that date was $877,972,594.
As of February 22, 2006 there were 38,017,698 shares
of the registrants common stock, par value $0.01 per
share, outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE:
Portions of the registrants definitive proxy statement for
its 2006 Annual Meeting of Stockholders have been incorporated
by reference into Part III of this
Form 10-K.
FORWARD
LOOKING STATEMENTS
All statements other than statements of historical fact
contained in this Report on
Form 10-K
(Report) and other periodic reports filed by us
under the Securities Exchange Act of 1934 and other written or
oral statements made by us or on our behalf, are forward-looking
statements. When used herein, the words anticipates,
expects, believes, goals,
intends, plans, or projects
and similar expressions are intended to identify forward-looking
statements. It is important to note that forward-looking
statements are based on a number of assumptions about future
events and are subject to various risks, uncertainties and other
factors that may cause our actual results to differ materially
from the views, beliefs and estimates expressed or implied in
such forward-looking statements. We refer you specifically to
the section Risk Factors in Item 1A of this
Report. Although we believe that the assumptions on which any
forward-looking statements in this Report and other periodic
reports filed by us are reasonable, no assurance can be given
that such assumptions will prove correct. All forward-looking
statements in this Report are expressly qualified in their
entirety by the cautionary statements in this paragraph and
elsewhere in this Report.
PART I
Items 1 &
2. Business and Properties
We were incorporated in January 1998 and operate in a single
segment as an independent oil and natural gas exploration and
production company. Our current operations are concentrated in
the shallow to moderate depth waters of the Gulf of Mexico Shelf
and the Gulf Coast onshore regions and, as a result of an
acquisition of undeveloped acreage in early 2006, the deepwater
Gulf of Mexico. We concentrate on this core focus area because
it provides us with favorable geologic and economic conditions,
including multiple reservoir formations, regional economies of
scale, extensive infrastructure and comprehensive geologic
databases. We believe that these regions offer a balanced and
expansive array of existing and prospective exploration,
exploitation and development opportunities in both established
productive horizons and deeper geologic formations. In addition,
we intend to evaluate reserve and exploratory acquisition
opportunities outside of our core focus area. As of
December 31, 2005, we had estimated proved reserves of
approximately 166.9 Bcf of natural gas and 31.5 Mmbbls
of oil, or an aggregate of approximately 59.3 Mmboe, with a
present value of estimated pre-tax future net cash flows of
$1.8 billion, and a standardized measure of discounted
future net cash flows of $1.3 billion.
We have a team of geoscientists and management professionals
with considerable region-specific geological, geophysical,
technical and operational experience. We have grown through a
combination of exploration, exploitation and development
drilling and multi-year, multi-well
drill-to-earn
programs, as well as strategic acquisitions of oil and natural
gas fields in the Gulf of Mexico Shelf and the Gulf Coast
onshore areas. As we have grown, we have strengthened our
management team, expanded our property base, reduced our
geographic concentration, and moved to a more balanced oil and
natural gas reserves and production profile. We have also
expanded our technical knowledge base through the addition of
high quality personnel and geophysical and geological data.
Our common stock is traded on the New York Stock Exchange under
the symbol EPL. We maintain a website at
www.eplweb.com which contains information about us, including
links to our annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and all related amendments. In addition, our website contains
our Corporate Governance Guidelines and the charters for our
Audit, Compensation and Nominating Committees. Copies of such
information are also available by writing to the Secretary of
the Company at 201 St. Charles Avenue, Suite 3400, New
Orleans, Louisiana 70170. Our web site and the information
contained in it and connected to it shall not be deemed
incorporated by reference into this Report on
Form 10-K.
Acquisition
of South Louisiana Reserves and Prospects
On January 20, 2005, we closed an acquisition of properties
and reserves onshore in south Louisiana for $149.6 million
in cash, after adjustments for the exercise of preferential
rights by third parties and closing adjustments. The properties
acquired included nine fields, four of which were producing at
the time of the closing through 14 wells, with estimated
acquisition date proved reserves of 51.2 Bcfe. Also
included were interests in
3
22 exploratory prospects. The transaction expanded the
exploration opportunities in our expanded focus area. Concurrent
with the closing, our bank credit facility borrowing base was
increased to $150 million, of which $60 million was
drawn to fund the acquisition. In connection with the
acquisition, we also entered into a two-year agreement with the
seller of the properties that defines an area of mutual interest
(AMI) encompassing over one million acres. We intend
to continue to explore and develop oil and natural gas reserves
in the AMI over the two year term jointly with the seller. The
proved reserves acquired from the seller, prospects and the AMI
are in the southern portions of Terrebone, Lafourche and
Jefferson Parishes in Louisiana.
Exploration
and Development Expenditures
Our exploration and development expenditures for 2005 totaled
$478.7 million inclusive of a $0.9 million contingent
consideration payment to former stockholders of a company
acquired in 2002 and $170.5 million related to acquisitions
in 2005. For 2006, we have budgeted exploration and development
expenditures of $360 million. The drilling portfolio, both
onshore and offshore, includes a mixture of lower risk
development and exploitation wells, moderate risk exploration
opportunities and higher risk, higher potential exploration
projects. Our 2006 budget does not include any acquisitions of
proved reserves that may occur during the year.
Our
Properties
At December 31, 2005, we had interests in 38 producing
fields and 5 fields under development all of which are located
in the Gulf of Mexico Shelf and the Gulf Coast onshore regions
(the Gulf of Mexico Region). These fields fall into
four focus areas which we identify as our Eastern, Central and
Western offshore and Gulf Coast onshore areas. The Eastern
offshore area is comprised of two producing fields, including
the East Bay field. The Central offshore area is comprised of
six producing fields, four of which are contiguous and cover
most of the Bay Marchand salt dome. The Western offshore area,
which extends from areas offshore central and western Louisiana
to areas offshore Texas, is comprised of 21 producing fields.
Our Gulf Coast onshore area is located in South Louisiana,
with nine producing fields. Over the last several years, we have
continued to add to our leasehold acreage position in these
areas through federal and state lease sales, acquisitions and
trades with industry partners.
Eastern
Offshore Area
East Bay is the key asset in our Eastern offshore area and is
located 89 miles southeast of New Orleans near the mouth of
the Mississippi River. East Bay contains producing wells located
onshore along the coastline and in water depths ranging up to
approximately 171 feet. East Bay is comprised primarily of
the South Pass 24, 26 and 27 fields. Through a number of
state and federal lease sales, we have acquired acreage that is
contiguous to East Bay in several additional South Pass blocks
as well as across the river in West Delta blocks. We own an
average 96% interest in our acreage position in this area
with our working interest ranging from 18% to 100% and our net
revenue interest varying up to a maximum of 86%. Inclusive of
all lease acquisitions, our leasehold area covered
47,307 gross acres (45,403 net acres) at the end of
2005. Our Eastern offshore area operations accounted for
approximately 21% of our net daily production during 2005.
Central
Offshore Area
The core assets of our Central offshore area, the fields located
in Greater Bay Marchand, are located approximately 60 miles
south of New Orleans in water depths of 181 feet or less.
Our key assets in this area include the South Timbalier 26 and
41 and Bay Marchand fields as well as currently undeveloped
reserves in the South Timbalier 46 field. Our Central
offshore area operations accounted for approximately 40% of our
net daily production during 2005.
In 2003, we drilled our initial discovery well in South
Timbalier 41 field on acreage acquired earlier that year in a
federal lease sale. Five follow up exploratory wells have been
drilled in the field and all have been successful. Four of these
wells have been brought on production and an additional
development well was drilled in early 2006. This field, in which
additional reserve potential is yet to be tested, represents the
most significant discovery in our
4
history. We acquired acreage in eight additional leases in the
vicinity of this field in the March 2005 federal lease sale.
In addition, we owned a 50% interest in the South Timbalier 26
field at the beginning of 2005. On March 8, 2005, we closed
the acquisition of the remaining 50% interest in South Timbalier
26 above 13,000 feet subsea for approximately
$19.6 million after closing adjustments. As a result of the
acquisition, we now own a 100% interest in the producing
horizons in this field. The acquisition expands our interest in
our core Greater Bay Marchand area and gives us additional
flexibility in undertaking the future development of the South
Timbalier 26 field. We have interests in 12 producing wells in
this field.
Western
Offshore Area
The properties in the Western offshore area are located in water
depths ranging from 20 to 476 feet with working interests
ranging from 17% to 100%. We owned interests in 25 fields in
this area at December 31, 2005, 21 of which were
producing fields with another four under development. Our
Western offshore area operations accounted for approximately 25%
of our net daily production during 2005.
Gulf
Coast Onshore Area
The properties in the Gulf Coast onshore area are located in
south Louisiana with working interests ranging from 8% to 100%.
We owned interests in nine producing fields in this area at
December 31, 2005. Our Gulf Coast onshore area operations
accounted for approximately 14% of our net daily production
during 2005.
Oil and
Natural Gas Reserves
The following table presents our estimated net proved oil and
natural gas reserves and the present value of our reserves at
December 31, 2005, 2004 and 2003. The December 31,
2005, 2004 and 2003 estimates of proved reserves are based on
reserve reports prepared by Netherland, Sewell &
Associates, Inc. and Ryder Scott Company, L.P., independent
petroleum engineers. Neither the present values, discounted at
10% per annum, of estimated future net cash flows before
income taxes, or the standardized measure of discounted future
net cash flows shown in the table are intended to represent the
current market value of the estimated oil and natural gas
reserves we own.
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As of
December 31,
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2005
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2004
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2003
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Total estimated net proved
reserves(1):
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Oil (Mbbls)
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31,478
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28,770
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27,414
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Natural gas (Mmcf)
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166,949
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149,835
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134,404
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Total (Mboe)
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59,303
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53,743
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49,815
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Net proved developed reserves(2):
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Oil (Mbbls)
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25,656
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24,737
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22,306
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Natural gas (Mmcf)
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103,627
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102,760
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71,531
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Total (Mboe)
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42,917
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41,864
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34,228
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Estimated future net revenues
before income taxes (in thousands)(3)
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$
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2,531,166
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$
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1,271,083
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$
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967,449
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Present value of estimated future
net revenues before income taxes (in thousands)(3) (4)
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$
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1,806,185
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$
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924,135
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$
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701,237
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Standardized measure of discounted
future net cash flows
(in thousands)(5)
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$
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1,261,246
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$
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667,668
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$
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529,415
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(1) |
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Approximately 82% of our total proved reserves were proved
undeveloped and proved developed non-producing at
December 31, 2005. |
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(2) |
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Net proved developed non-producing reserves as of
December 31, 2005 were 19,884 Mbbls and
72,420 Mmcf. |
5
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(3) |
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The December 31, 2005 amount was calculated using a
period-end oil price of $57.81 per barrel and a period-end
natural gas price of $10.31 per Mcf, while the
December 31, 2004 amount was calculated using a period-end
oil price of $41.84 per barrel and a period-end natural gas
price of $6.23 per Mcf and the December 31, 2003
amount was calculated using a period-end oil price of
$30.88 per barrel and a period-end natural gas price of
$6.15 per Mcf. |
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(4) |
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The present value of estimated future net revenues attributable
to our reserves was prepared using constant prices, as of the
calculation date, discounted at 10% per year on a pre-tax
basis. |
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(5) |
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The standardized measure of discounted future net cash flows
represents the present value of future cash flows after income
tax discounted at 10%. |
Costs
Incurred in Oil and Natural Gas Activities
The following table sets forth certain information regarding the
costs incurred that are associated with finding, acquiring, and
developing our proved oil and natural gas reserves:
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Years Ended
December 31,
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2005
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2004
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2003
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(In thousands)
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Business combinations:
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Proved properties
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$
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142,025
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$
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2,166
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$
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850
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Unproved properties
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29,333
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Total business combinations
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171,358
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2,166
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850
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Lease acquisitions
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27,622
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6,551
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6,030
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Exploration
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171,859
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113,278
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60,170
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Development(1)
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114,814
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75,732
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49,013
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Costs incurred
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$
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485,653
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$
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197,727
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$
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116,063
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(1) |
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Includes asset retirement obligations incurred of
$6.9 million, $3.5 million and $3.3 million for
the years ended December 31, 2005, 2004 and 2003,
respectively. |
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, 2005:
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Total
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Productive
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Wells
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Gross
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Net
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Oil
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266
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201
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Natural gas
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118
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58
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Total
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384
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259
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Productive wells consist of producing wells and wells capable of
production, including oil wells awaiting connection to
production facilities and natural gas wells awaiting pipeline
connections to commence deliveries. Seventeen gross oil wells
and eight gross natural gas wells have dual completions.
6
Acreage
The following table sets forth information as of
December 31, 2005 relating to acreage held by us. Developed
acreage is assigned to producing wells.
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Gross
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Net
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Acreage
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Acreage
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Developed:
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Eastern area
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32,229
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30,988
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Central area
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38,840
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24,206
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Western area
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131,214
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80,427
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Gulf Coast onshore area
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6,496
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2,786
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Total
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208,779
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138,407
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Undeveloped:
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Eastern area
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15,078
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14,415
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Central area
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39,240
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38,139
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Western area
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170,159
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123,110
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Gulf Coast onshore area
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7,070
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2,527
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Total
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231,547
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178,191
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Leases covering 12% of our undeveloped net acreage will expire
in 2006, approximately 6% in 2007, 5% in 2008, 24% in 2009, 46%
in 2010 and 7% thereafter.
Well
Activity
The following table shows our well activity for the years ended
December 31, 2005, 2004 and 2003. In the table,
gross refers to the total wells in which we have a
working interest and net refers to gross wells
multiplied by our working interest in these wells.
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Years Ended
December 31,
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2005
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2004
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2003
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Development Wells:
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Productive
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8.0
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4.7
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5.0
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3.2
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1.0
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0.3
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Non-productive
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3.0
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1.1
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2.0
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2.0
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1.0
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1.0
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Total
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11.0
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5.8
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7.0
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5.2
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2.0
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1.3
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Exploration Wells:
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Productive
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30.0
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15.3
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19.0
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12.3
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15.0
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8.4
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Non-productive
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17.0
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9.3
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5.0
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2.2
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4.0
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2.2
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Total
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47.0
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24.6
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24.0
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14.5
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19.0
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10.6
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Well activity refers to the number of wells completed at any
time during the fiscal years, regardless of when drilling was
initiated. For the purpose of this table, completed
refers to the installation of permanent equipment for the
production of oil or natural gas.
Title to
Properties
Our properties are subject to customary royalty interests, liens
under indebtedness, liens incident to operating agreements,
mechanics and materialman liens for current taxes and other
burdens, including other mineral encumbrances and restrictions.
We do not believe that any of these burdens materially interfere
with the use of our properties in the operation of our business.
7
We believe that we 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. We
investigate title prior to the consummation of an acquisition of
producing properties and before the commencement of drilling
operations on undeveloped properties. We have obtained or
conducted a thorough title review on substantially all of our
producing properties and believe that we have satisfactory title
to such properties in accordance with standards generally
accepted in the oil and natural gas industry.
Regulatory
Matters
Regulation
of Transportation and Sale of Natural Gas
Historically, the transportation and sale for resale of natural
gas in interstate commerce have been regulated pursuant to the
Natural Gas Act of 1938, as amended (NGA), the
Natural Gas Policy Act of 1978, as amended (NGPA),
and regulations promulgated thereunder by the Federal Energy
Regulatory Commission (FERC) and its predecessors.
In the past, the federal government has regulated the prices at
which natural gas could be sold. While sales by producers of
natural gas can currently be made at unregulated market prices,
Congress could reenact price controls in the future.
Deregulation of wellhead natural gas sales began with the
enactment of the NGPA. In 1989, Congress enacted the Natural Gas
Wellhead Decontrol Act, as amended (the Decontrol
Act). The Decontrol Act removed all NGA and NGPA price and
non-price controls affecting wellhead sales of natural gas
effective January 1, 1993.
Since 1985, FERC has endeavored to make natural gas
transportation more accessible to natural gas buyers and sellers
on an open and non-discriminatory basis. FERC has stated that
open access policies are necessary to improve the competitive
structure of the interstate natural gas pipeline industry and to
create a regulatory framework that will put natural gas sellers
into more direct contractual relations with natural gas buyers
by, among other things, unbundling the sale of natural gas from
the sale of transportation and storage services. Beginning in
1992, FERC issued Order No. 636 and a series of related
orders (collectively, Order No. 636) to
implement its open access policies. As a result of the Order
No. 636 program, the marketing and pricing of natural gas
have been significantly altered. The interstate pipelines
traditional role as wholesalers of natural gas has been
eliminated and replaced by a structure under which pipelines
provide transportation and storage service on an open access
basis to others who buy and sell natural gas. Although
FERCs orders do not directly regulate natural gas
producers, they are intended to foster increased competition
within all phases of the natural gas industry.
In 2000, FERC issued Order No. 637 and subsequent orders
(collectively, Order No. 637), which imposed a
number of additional reforms designed to enhance competition in
natural gas markets. Among other things, Order No. 637
revised FERC pricing policy by waiving price ceilings for
short-term released capacity for a two-year experimental period,
and effected changes in FERC regulations relating to scheduling
procedures, capacity segmentation, penalties, rights of first
refusal and information reporting. Most major aspects of Order
No. 637 have been upheld on judicial review, and most
pipelines tariff filings to implement the requirements of
Order No. 637 have been accepted by the FERC and placed
into effect.
The Outer Continental Shelf Lands Act (OCSLA), which
FERC implements as to transportation and pipeline issues,
requires that all pipelines operating on or across the outer
continental shelf (OCS) provide open access,
non-discriminatory transportation service. One of FERCs
principal goals in carrying out OCSLAs mandate is to
increase transparency in the market to provide producers and
shippers on the OCS with greater assurance of open access
service on pipelines located on the OCS and non-discriminatory
rates and conditions of service on such pipelines. The
U.S. Minerals Management Service (MMS) also has
jurisdiction under OCSLA to ensure that all shippers seeking
service on OCS pipelines transporting oil or gas pursuant to
MMS-granted easements or
rights-of-way
receive open and non-discriminatory access to such
transportation. In furtherance of this mandate, MMS currently is
contemplating rulemaking to amend its regulations to better
ensure such access for OCS shippers.
It should be noted that FERC currently is considering whether to
reformulate its test for defining non-jurisdictional gathering
in the shallow waters of the OCS and, if so, what form that new
test should take. The stated purpose of this initiative is to
devise an objective test that furthers the goals of the NGA by
protecting producers from the unregulated market power of
third-party transporters of gas, while providing incentives for
investment in production, gathering and transportation
infrastructure offshore. While we cannot predict whether
FERCs
8
gathering test ultimately will be revised and, if so, what form
such revised test will take, any test that refunctionalizes as
FERC-jurisdictional transmission facilities currently classified
as gathering would impose an increased regulatory burden on the
owner of those facilities by subjecting the facilities to NGA
certificate and abandonment requirements and rate regulation.
We cannot accurately predict whether FERCs (or MMSs)
actions will achieve the goal of increasing competition in
markets in which our natural gas is sold. Additional proposals
and proceedings that might affect the natural gas industry are
pending before FERC and the courts. For example, the Federal
Energy Policy Act, signed into law in August 2005, contains
various provisions designed to increase the level of competition
and transparency in FERC-regulated natural gas markets (e.g. one
such provision makes market-based rate authority generally
available to new interstate natural gas storage facilities),
those provisions are now in various stages of implementation by
FERC. The natural gas industry historically has been very
heavily regulated; therefore, there is no assurance that the
less stringent regulatory approach recently pursued by FERC will
continue. However, we do not believe that any action taken will
affect us in a way that materially differs from the way it
affects other natural gas producers, gatherers and marketers.
Intrastate natural gas transportation is subject to regulation
by state regulatory agencies. The basis for intrastate
regulation of natural gas transportation and the degree of
regulatory oversight and scrutiny given to intrastate natural
gas pipeline rates and services varies from state to state.
Insofar as such regulation within a particular state will
generally affect all intrastate natural gas shippers within the
state on a comparable basis, we believe that the regulation of
similarly situated intrastate natural gas transportation in any
states in which we operate and ship natural gas on an intrastate
basis will not affect our operations in any way that is
materially different from the effect of such regulation on our
competitors.
Regulation
of Transportation of Oil
Sales of crude oil, condensate and natural gas liquids are not
currently regulated and are made at negotiated prices. The
transportation of oil in common carrier pipelines is also
subject to rate regulation. FERC regulates interstate oil
pipeline transportation rates under the Interstate Commerce Act.
In general, interstate oil pipeline rates must be cost-based,
although settlement rates agreed to by all shippers are
permitted and market-based rates may be permitted in certain
circumstances. Effective January 1, 1995, FERC implemented
regulations establishing an indexing system (based on inflation)
for transportation rates for oil that allowed for an increase or
decrease in the cost of transporting oil to the purchaser. A
review of these regulations by the FERC in 2000 was successfully
challenged on appeal by an association of oil pipelines. On
remand, the FERC in February 2003 increased the index slightly,
effective July 2001. Intrastate oil pipeline transportation
rates are subject to regulation by state regulatory commissions.
The basis for intrastate oil pipeline regulation, and the degree
of regulatory oversight and scrutiny given to intrastate oil
pipeline rates, varies from state to state. Insofar as effective
interstate and intrastate rates are equally applicable to all
comparable shippers, we believe that the regulation of oil
transportation rates will not affect our operations in any way
that is materially different from the effect of such regulation
on our competitors.
Further, interstate and intrastate common carrier oil pipelines
must provide service on a non-discriminatory basis. Under this
open access standard, common carriers must offer service to all
shippers requesting service on the same terms and under the same
rates. When oil pipelines operate at full capacity, access is
governed by prorationing provisions set forth in the
pipelines published tariffs. Accordingly, we believe that
access to oil pipeline transportation services generally will be
available to us to the same extent as to our competitors.
Our subsidiary, EPL Pipeline, L.L.C., owns an approximately
12-mile oil
pipeline, which transports oil produced from South Timbalier 26
and a portion of South Timbalier 41 on the Gulf of Mexico OCS to
Bayou Fourchon, Louisiana. Production transported on this
pipeline includes oil produced by us and our working interest
partner in South Timbalier 26. EPL Pipeline, L.L.C. has on file
with the Louisiana Public Service Commission and FERC tariffs
for this transportation service and offers non-discriminatory
transportation for any willing shipper.
9
Regulation
of Production
The production of oil and natural gas is subject to regulation
under a wide range of local, state and federal statutes, rules,
orders and regulations. Federal, state and local statutes and
regulations require permits for drilling operations, drilling
and plugging and abandonment surety bonds and reports concerning
operations. 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 allowable rates of
production from oil and natural gas wells, the regulation of
well spacing, and plugging and abandonment of wells. Many states
also restrict production to the market demand for oil and
natural gas, and states have indicated interest in revising
applicable regulations. The effect of these regulations is to
limit the amount of oil and natural gas that we can produce from
our wells and to limit the number of wells or the locations at
which we can drill. Moreover, each state generally imposes a
production or severance tax with respect to the production and
sale of oil, natural gas and natural gas liquids within its
jurisdiction.
Some of our offshore operations are conducted on federal leases
that are administered by MMS and are required to comply with the
regulations and orders promulgated by MMS under OCSLA. Among
other things, we are required to obtain prior MMS approval for
any exploration plans we pursue and our development and
production plans for these leases. MMS regulations also
establish construction requirements for production facilities
located on our federal offshore leases and govern the plugging
and abandonment of wells and the removal of production
facilities from these leases. Under limited circumstances, MMS
could require us to suspend or terminate our operations on a
federal lease.
MMS also establishes the basis for royalty payments due under
federal oil and natural gas leases through regulations issued
under applicable statutory authority. State regulatory
authorities establish similar standards for royalty payments due
under state oil and natural gas leases. The basis for royalty
payments established by MMS and the state regulatory authorities
is generally applicable to all federal and state oil and natural
gas lessees. Accordingly, we believe that the impact of royalty
regulation on our operations should generally be the same as the
impact on our competitors.
The failure to comply with these 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. Our
competitors in the oil and natural gas industry are subject to
the same regulatory requirements and restrictions that affect
our operations.
Environmental
Regulations
General. Various federal, state and local laws
and regulations governing the protection of the environment,
such as the Comprehensive Environmental Response, Compensation
and Liability Act of 1980, as amended (CERCLA), the
Federal Water Pollution Control Act of 1972, as amended (the
Clean Water Act), and the Federal Clean Air Act, as
amended (the Clean Air Act), affect our operations
and costs. In particular, our exploration, development and
production operations, our activities in connection with storage
and transportation of oil and other hydrocarbons and our use of
facilities for treating, processing or otherwise handling
hydrocarbons and related wastes may be subject to regulation
under these and similar state legislation. These laws and
regulations:
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restrict the types, quantities and concentration of various
substances that can be released into the environment in
connection with drilling and production activities;
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limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands and other protected areas; and
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impose substantial liabilities for pollution resulting from our
operations.
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Failure to comply with these laws and regulations may result in
the assessment of administrative, civil and criminal fines and
penalties or the imposition of injunctive relief. Changes in
environmental laws and regulations occur regularly, and any
changes that result in more stringent and costly waste handling,
storage, transport, disposal or cleanup requirements could
materially adversely affect our operations and financial
position, as well as those in the oil and natural gas industry
in general. While we believe that we are in substantial
compliance with current
10
applicable environmental laws and regulations and that continued
compliance with existing requirements would not have a material
adverse impact on us, there is no assurance that this trend will
continue in the future.
As with the industry generally, compliance with existing
regulations increases our overall cost of business. The areas
affected include:
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unit production expenses primarily related to the control and
limitation of air emissions and the disposal of produced water;
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capital costs to drill exploration and development wells
primarily related to the management and disposal of drilling
fluids and other oil and natural gas exploration wastes; and
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capital costs to construct, maintain and upgrade equipment and
facilities.
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Superfund. CERCLA, also known as
Superfund, imposes liability for response costs and
damages to natural resources, without regard to fault or the
legality of the original act, on some classes of persons that
contributed to the release of a hazardous substance
into the environment. These persons include the
owner or operator of a disposal site and
entities that disposed or arranged for the disposal of the
hazardous substances found at the site. CERCLA also authorizes
the Environmental Protection Agency (EPA) and, in
some instances, third parties to act in response to threats to
the public health or the environment and to seek to recover from
the responsible classes of persons the costs they incur. It is
not uncommon for neighboring landowners and other third parties
to file claims for personal injury and property damage allegedly
caused by the hazardous substances released 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 may be jointly and
severally liable under CERCLA or comparable state statutes for
all or part of the costs required to clean up sites at which
these wastes have been disposed.
We currently own or lease properties that for many years have
been used for the exploration and production of oil and natural
gas. Although we and our predecessors have used operating and
disposal practices that were standard in the industry at the
time, hydrocarbons or other wastes may have been disposed or
released on, under or from the properties owned or leased by us
or on, under or from other locations where these wastes have
been taken for disposal. In addition, many of these properties
have been operated by third parties whose actions with respect
to the treatment and disposal or release of hydrocarbons or
other wastes were not under our control. These properties and
wastes disposed on these properties may be subject to CERCLA and
analogous state laws. Under these laws, we could be required:
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to remove or remediate previously disposed wastes, including
wastes disposed or released by prior owners or operators;
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to clean up contaminated property, including contaminated
groundwater; or
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to perform remedial operations to prevent future contamination.
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At this time, we do not believe that we are associated with any
Superfund site and we have not been notified of any claim,
liability or damages under CERCLA.
Oil Pollution Act of 1990. The Oil Pollution
Act of 1990, as amended (the OPA) and regulations
thereunder impose liability on responsible parties
for damages resulting from oil spills into or upon navigable
waters, adjoining shorelines or in the exclusive economic zone
of the United States. Liability under OPA is strict, and under
certain circumstances joint and several, and potentially
unlimited. 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 also
requires the lessee or permittee of the offshore area in which a
covered offshore facility is located to establish and maintain
evidence of financial responsibility in the amount of
$35.0 million ($10.0 million if the offshore facility
is located landward of the seaward boundary of a state) to cover
liabilities related to an oil spill for which such person is
statutorily responsible. The amount of required financial
responsibility may be increased above the minimum amounts to an
amount not exceeding $150.0 million depending on the risk
represented by the quantity or quality of oil that is handled by
the facility. We carry insurance coverage to meet these
obligations, which we believe is customary for comparable
companies in our industry. A failure to comply
11
with OPAs requirements or inadequate cooperation during a
spill response action may subject a responsible party to civil
or criminal enforcement actions. We are not aware of any action
or event that would subject us to liability under OPA, and we
believe that compliance with OPAs financial responsibility
and other operating requirements will not have a material
adverse effect on us.
U.S. Environmental Protection
Agency. U.S. Environmental Protection Agency
regulations address the disposal of oil and natural gas
operational wastes under three federal acts more fully discussed
in the paragraphs that follow. The Resource Conservation and
Recovery Act of 1976, as amended (RCRA), provides a
framework for the safe disposal of discarded materials and the
management of solid and hazardous wastes. The direct disposal of
operational wastes into offshore waters is also limited under
the authority of the Clean Water Act. When injected underground,
oil and natural gas wastes are regulated by the Underground
Injection Control program under Safe Drinking Water Act. If
wastes are classified as hazardous, they must be properly
transported, using a uniform hazardous waste manifest,
documented, and disposed at an approved hazardous waste
facility. We have coverage under the Clean Water Act permitting
requirements for discharges associated with exploration and
development activities. We take the necessary steps to ensure
all offshore discharges associated with a proposed operation,
including produced waters, will be conducted in accordance with
such requirements.
Resource Conservation Recovery Act. RCRA, is
the principal federal statute governing 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. At present, RCRA
includes a statutory exemption that allows most oil and natural
gas exploration and production waste to be classified as
nonhazardous waste. 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. At various times in the past, proposals have been made
to amend RCRA to rescind the exemption that excludes oil and
natural gas exploration and production wastes from regulation as
hazardous waste. Repeal or modification of the exemption by
administrative, legislative or judicial process, or modification
of similar exemptions in applicable state statutes, would
increase the volume of hazardous waste we are required to manage
and dispose of and would cause us to incur increased operating
expenses.
Clean Water Act. The Clean Water Act imposes
restrictions and controls on the discharge of produced waters
and other wastes into navigable waters. Permits must be obtained
to discharge pollutants into state and federal waters and to
conduct construction activities in waters and wetlands. Certain
state regulations and the general permits issued under the
Federal National Pollutant Discharge Elimination System program
prohibit the discharge of produced waters and sand, drilling
fluids, drill cuttings and certain other substances related to
the oil and natural gas industry into certain coastal and
offshore waters. Further, the EPA has adopted regulations
requiring certain oil and natural gas exploration and production
facilities to obtain permits for storm water discharges. Costs
may be associated with the treatment of wastewater or developing
and implementing storm water pollution prevention plans. The
Clean Water Act and comparable state statutes provide for civil,
criminal and administrative penalties for unauthorized
discharges for oil and other pollutants and impose 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. We
believe that our operations comply in all material respects with
the requirements of the Clean Water Act and state statutes
enacted to control water pollution.
Safe Drinking Water Act. Underground injection
is the subsurface placement of fluid through a well, such as the
reinjection of brine produced and separated from oil and natural
gas production. The Safe Drinking Water Act of 1974, as amended
establishes a regulatory framework for underground injection,
with the main goal being the protection of usable aquifers. The
primary objective of injection well operating requirements is to
ensure the mechanical integrity of the injection apparatus and
to prevent migration of fluids from the injection zone into
underground sources of drinking water. Hazardous-waste injection
well operations are strictly controlled, and certain wastes,
absent an exemption, cannot be injected into underground
injection control wells. In Louisiana and Texas, no underground
injection may take place except as authorized by permit or rule.
We currently own and operate various underground injection
wells. Failure to abide by our permits could subject us to civil
and/or
criminal enforcement. We believe that we are in compliance in
all material respects with the requirements of applicable state
underground injection control programs and our permits.
12
Marine Mammal and Endangered Species. Federal
Lease Stipulations Executive Order 13158 (Marine Protected
Areas) address the protection of marine areas and the reduction
of potential taking of protected marine species (sea turtles,
marine mammals, Gulf Sturgen and other listed marine species).
MMS permit approvals will be conditioned on collection and
removal of debris resulting from activities related to
exploration, development and production of offshore leases. MMS
has issued Notices to Lessees and Operators (NTL)
2003-G06 advising of requirements for posting of signs in
prominent places on all vessels and structures and of an
observing training program.
Consideration of Environmental Issues in Connection with
Governmental Approvals. Our operations frequently
require licenses, permits
and/or other
governmental approvals. Several federal statutes, including
OCSLA, the National Environmental Policy Act (NEPA),
and the Coastal Zone Management Act (CZMA) require
federal agencies to evaluate environmental issues in connection
with granting such approvals
and/or
taking other major agency actions. OCSLA, for instance, requires
the U.S. Department of Interior (DOI) to
evaluate whether certain proposed activities would cause serious
harm or damage to the marine, coastal or human environment.
Similarly, NEPA requires DOI and other federal agencies to
evaluate major agency actions having the potential to
significantly impact the environment. In the course of such
evaluations, an agency would have to prepare an environmental
assessment and, potentially, an environmental impact statement.
CZMA, on the other hand, aids states in developing a coastal
management program to protect the coastal environment from
growing demands associated with various uses, including offshore
oil and natural gas development. In obtaining various approvals
from the DOI, we must certify that we will conduct our
activities in a manner consistent with an applicable program.
Lead-Based Paints. Various pieces of equipment
and structures owned by us have been coated with lead-based
paints as was customary in the industry at the time these pieces
of equipment were fabricated and constructed. These paints may
contain lead at a concentration high enough to be considered a
regulated hazardous waste when removed. If we need to remove
such paints in connection with maintenance or other activities
and they qualify as a regulated hazardous waste, this would
increase the cost of disposal. High lead levels in the paint
might also require us to institute certain administrative
and/or
engineering controls required by the Occupational Safety and
Health Act and MMS to ensure worker safety during paint removal.
Air Pollution Control. The Clean Air Act and
state air pollution laws adopted to fulfill its mandates provide
a framework for national, state and local efforts to protect air
quality. Our operations utilize equipment that emits air
pollutants subject to federal and state air pollution control
laws. These laws require utilization of air emissions abatement
equipment to achieve prescribed emissions limitations and
ambient air quality standards, as well as operating permits for
existing equipment and construction permits for new and modified
equipment. Air emissions associated with offshore activities are
projected using a matrix and formula supplied by MMS, which has
primacy from the Environmental Protection Agency for regulating
such emissions.
Naturally Occurring Radioactive Materials
(NORM). NORM are materials not
covered by the Atomic Energy Act, whose radioactivity is
enhanced by technological processing such as mineral extraction
or processing through exploration and production conducted by
the oil and natural gas industry. NORM wastes are regulated
under the RCRA framework, but primary responsibility for NORM
regulation has been a state function. Standards have been
developed for worker protection; treatment, storage and disposal
of NORM waste; management of waste piles, containers and tanks;
and limitations upon the release of NORM contaminated land for
unrestricted use. We believe that our operations are in material
compliance with all applicable NORM standards established by the
State of Louisiana or the State of Texas, as applicable.
Abandonment Costs. One of the responsibilities
of owning and operating oil and natural gas properties is paying
for the cost of abandonment. Companies are required to reflect
abandonment costs as a liability on their balance sheets in the
period in which it is incurred. We may incur significant
abandonment costs in the future which could adversely affect our
financial results.
Significant
Customers
We market substantially all of the oil and natural gas from
properties we operate and from properties others operate where
our interest is significant. A majority of oil production from
the East Bay field is sold under a contract with Shell Trading
(US) Company (Shell). The contract has a 60 day
cancellation provision and can be terminated
13
by either party. In the event that the contract is cancelled by
us, Shell has the right through 2007 to match any other offers
we receive for the purchase of this oil production. Our oil,
condensate and natural gas production is sold to a variety of
purchasers, which has historically been at market-sensitive
prices. Our purchasers of oil and condensate include Chevron
Products Company (Chevron) and Shell. Currently, the
most significant purchaser of our natural gas production is
Louis Dreyfus Energy Services, L.P. (Dreyfus). We
believe that the prices for liquids and natural gas are
comparable to market prices in the areas where we have
production. Of our total oil and natural gas revenues in 2005,
Dreyfus accounted for approximately 18%, Shell 16%, Bridgeline
Holdings, L.P. 15% and Chevron 10%.
Due to the nature of the markets for oil and natural gas, we do
not believe that the loss of any one of these customers would
have a material adverse effect on our financial condition or
results of operation although a temporary disruption in
production revenues could occur.
Employees
As of December 31, 2005, we had 170 full-time
employees, including 45 geoscientists, engineers and technicians
and 63 field personnel. Our employees are not represented by any
labor union. We consider relations with our employees to be
satisfactory and we have never experienced a work stoppage or
strike.
Risks
Relating to the Oil and Natural Gas Industry
Exploring
for and producing oil and natural gas are high-risk activities
with many uncertainties that could adversely affect our
business, financial condition or results of
operations.
Our future success will depend on the success of our exploration
and production activities. Our oil and natural gas exploration
and production activities are subject to numerous risks beyond
our control, including the risk that drilling will not result in
commercially viable oil or natural gas production. Our decisions
to purchase, explore, develop or otherwise exploit prospects or
properties will depend in part on the evaluation of data
obtained through geophysical and geological analyses, production
data and engineering studies, the results of which are often
inconclusive or subject to varying interpretations. Our cost of
drilling, completing and operating wells is often uncertain
before drilling commences. Overruns in budgeted expenditures are
common risks that can make a particular project uneconomical.
Further, many factors may curtail, delay or cancel drilling,
including the following:
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining equipment and qualified
personnel;
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equipment failures or accidents;
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adverse weather conditions, such as hurricanes and tropical
storms;
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reductions in oil and natural gas prices;
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title problems;
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limitations in the market for oil and natural gas; and
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cost of services to drill wells.
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We may
incur substantial losses and be subject to substantial liability
claims as a result of our oil and natural gas
operations.
Losses and liabilities arising from uninsured and underinsured
events could materially and adversely affect our business,
financial condition or results of operations. Our oil and
natural gas exploration and production activities
14
are subject to all of the operating risks associated with
drilling for and producing oil and natural gas, including the
possibility of:
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environmental hazards, such as uncontrollable flows of oil,
natural gas, brine, well fluids, toxic gas or other pollution
into the environment, including groundwater and shoreline
contamination;
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abnormally pressured formations;
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mechanical difficulties, such as stuck oil field drilling and
service tools and casing collapse;
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fires and explosions;
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personal injuries and death; and
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natural disasters, especially hurricanes and tropical storms in
the Gulf of Mexico.
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Offshore operations are also subject to a variety of operating
risks peculiar to the marine environment, such as capsizing,
collisions and damage or loss from hurricanes, tropical storms
or other adverse weather conditions. These conditions can cause
substantial damage to facilities and interrupt production.
Any of these risks could adversely affect our ability to conduct
operations or result in substantial losses to our company. We
maintain insurance at levels that we believe are consistent with
industry practices and our particular needs, but we are not
fully insured against all risks. We may elect not to obtain
insurance for certain risks or to limit levels of coverage if we
believe that the cost of available insurance is excessive
relative to the risks involved. In this regard, the cost of
available coverage has increased significantly as a result of
losses experienced by third party insurers in the 2005 hurricane
season in the Gulf of Mexico, in particular those resulting from
Hurricanes Katrina and Rita. In addition, pollution and
environmental risks generally are not fully insurable. If a
significant accident or other event occurs and is not fully
covered by insurance, it could adversely affect our cash flow
and net income and could reduce or eliminate the funds available
for exploration, exploitation and acquisitions or result in loss
of equipment and properties.
A
substantial or extended decline in oil and natural gas prices
may adversely affect our business, financial condition or
results of operations and our ability to meet our capital
expenditure requirements and financial
commitments.
The price we receive for our oil and natural gas production
heavily influences our revenue, profitability, access to capital
and future rate of growth. Oil and natural gas are commodities
and, therefore, their prices are subject to wide fluctuations in
response to relatively minor changes in supply and demand.
Historically, the markets for oil and natural gas have been
volatile. These markets will likely continue to be volatile in
the future. The prices we receive for our production, and the
levels of our production, depend on numerous factors beyond our
control. These factors include:
|
|
|
|
|
changes in the global supply, demand and inventories of oil;
|
|
|
|
domestic natural gas supply, demand and inventories;
|
|
|
|
the actions of the Organization of Petroleum Exporting
Countries, or OPEC;
|
|
|
|
the price and quantity of foreign imports of oil;
|
|
|
|
the price and availability of liquefied natural gas imports;
|
|
|
|
political conditions, including embargoes, in or affecting other
oil-producing countries;
|
|
|
|
economic and energy infrastructure disruptions caused by actual
or threatened acts of war, or terrorist activities, or national
security measures deployed to protect the United States from
such actual or threatened acts or activities;
|
|
|
|
economic stability of major oil and natural gas companies and
the interdependence of oil and natural gas and energy trading
companies;
|
|
|
|
the level of worldwide oil and natural gas exploration and
production activity;
|
15
|
|
|
|
|
weather conditions, including energy infrastructure disruptions
resulting from those conditions;
|
|
|
|
technological advances affecting energy consumption; and
|
|
|
|
the price and availability of alternative fuels.
|
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. A
substantial or extended decline in oil and natural gas prices
may materially and adversely affect our future business,
financial condition, results of operations, liquidity, ability
to finance planned capital expenditures or ability to pursue
acquisitions. Further, oil prices and natural gas prices do not
necessarily move together.
Reserve
estimates depend on many assumptions that may prove to be
inaccurate. Any material inaccuracies in these reserve estimates
or underlying assumptions will materially affect the quantities
and present value of our reserves.
The process of estimating oil and natural gas reserves is
complex. It requires interpretations of available technical data
and many assumptions, including assumptions relating to economic
factors. Any significant inaccuracies in these interpretations
or assumptions could materially affect the estimated quantities
and present value of reserves shown in this Report.
In order to assist in the preparation of our estimates, we must
project production rates and timing of development expenditures.
We must also analyze available geological, geophysical,
production and engineering data. The extent, quality and
reliability of these data can vary. The 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. Therefore, estimates of oil and
natural gas reserves are inherently imprecise.
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.
It cannot be assumed that the present value of future net
revenues from our proved reserves referred to in this Report is
the current market value of our estimated oil and natural gas
reserves. In accordance with SEC requirements, we base the
estimated discounted future net cash flows from our proved
reserves on prices and costs on the date of the estimate. Actual
future prices and costs may differ materially from those used in
the present-value estimate.
Market
conditions or operational impediments may hinder our access to
oil and natural gas markets or delay our
production.
Market conditions or the unavailability of satisfactory oil and
natural gas transportation arrangements may hinder our access to
oil and natural gas markets or delay our production. The
availability of a ready market for our oil and natural gas
production depends on a number of factors, including the demand
for and supply of oil and natural gas and the proximity of
reserves to pipelines and terminal facilities. Our ability to
market our production depends in substantial part on the
availability and capacity of gathering systems, pipelines and
processing facilities owned and operated by third parties. Our
failure to obtain such services on acceptable terms could harm
our business. We may be required to shut in wells for lack of a
market or because of inadequacy or unavailability of oil or
natural gas pipeline or gathering system capacity. If that were
to occur, we would be unable to realize revenue from those wells
until production arrangements were made to deliver to market.
Risks
Relating to Energy Partners,
Ltd.
A
significant part of the value of our production and reserves is
concentrated in two areas. Because of this concentration, any
production problems or inaccuracies in reserve estimates related
to these areas could impact our business
adversely.
During 2005, 39% of our net daily production came from our
Greater Bay Marchand area and approximately 40% of our proved
reserves were located in the fields that comprise this area. In
addition, 20% of our net daily production came from our East Bay
field and approximately 34% of our proved reserves were located
on this
16
property. If mechanical problems, storms or other events were to
curtail a substantial portion of this production, our cash flow
could be affected adversely. If the actual reserves associated
with these properties are less than our estimated reserves, our
business, financial condition or results of operations could be
adversely affected.
Relatively
short production life for Gulf of Mexico and Gulf Coast onshore
regions properties subjects us to higher reserve replacement
needs.
Producing oil and natural gas reservoirs generally are
characterized by declining production rates that vary depending
upon 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. All of our operations are presently in
the Gulf of Mexico and Gulf Coast onshore regions. Production
from reservoirs in the Gulf of Mexico region generally declines
more rapidly than from reservoirs in many other producing
regions of the world. As of December 31, 2005, our
independent petroleum engineers estimate, on average, 65% of our
total proved reserves will be produced within 5 years. As a
result, our reserve replacement needs from new investments are
relatively greater than those of producers who recover lower
percentages of their reserves over a similar time period, such
as producers who have a portion of their reserves outside the
Gulf of Mexico in areas where the rate of reserve production is
lower. We may not be able to develop, exploit, find or acquire
additional reserves to sustain our current production levels or
to grow. There can be no assurance that we will be able to grow
production at rates we have experienced in the past. Our future
oil and natural gas reserves and production, and, therefore, our
cash flow and income, are highly dependent on our success in
efficiently developing and exploiting our current reserves and
economically finding or acquiring additional recoverable
reserves.
Rapid
growth may place significant demands on our
resources.
We have experienced rapid growth in our operations and expect
that expansion of our operations will continue. Our rapid growth
has placed, and our anticipated future growth will continue to
place, a significant demand on our managerial, operational and
financial resources due to:
|
|
|
|
|
the need to manage relationships with various strategic partners
and other third parties;
|
|
|
|
difficulties in hiring and retaining skilled personnel necessary
to support our business;
|
|
|
|
complexities in integrating acquired businesses and personnel;
|
|
|
|
the need to train and manage our employee base; and
|
|
|
|
pressures for the continued development of our financial and
information management systems.
|
If we have not made adequate allowances for the costs and risks
associated with these demands or if our systems, procedures or
controls are not adequate to support our operations, our
business could be harmed.
Properties
that we buy may not produce as projected, and we may be unable
to fully identify liabilities associated with the properties or
obtain protection from sellers against them.
Our strategy includes acquisitions. The successful acquisition
of producing properties requires assessments of many factors,
which are inherently inexact and may be inaccurate, including:
|
|
|
|
|
the amount of recoverable reserves and the rates at which those
reserves will be produced;
|
|
|
|
future oil and natural gas prices;
|
|
|
|
estimates of operating costs;
|
|
|
|
estimates of future development costs;
|
|
|
|
estimates of the costs and timing of plugging and
abandonment; and
|
|
|
|
potential environmental and other liabilities.
|
Our assessments will not reveal all existing or potential
problems, nor will they permit us to become familiar enough with
the properties to evaluate fully their deficiencies and
capabilities. In the course of our due diligence, we
17
may not inspect every well, platform or pipeline. We cannot
necessarily observe structural and environmental problems, such
as pipeline corrosion or groundwater contamination, when an
inspection is conducted. We may not be able to obtain
contractual indemnities from the seller for liabilities that it
created. We may be required to assume the risk of the physical
condition of the properties in addition to the risk that the
properties may not perform in accordance with our expectations.
Substantial
acquisitions, development programs or other transactions could
require significant external capital and could change our risk
and property profile.
In order to finance acquisitions of additional producing
properties or finance the development of any discoveries made
through any expanded exploratory program that might be
undertaken, we may need to alter or increase our capitalization
substantially through the issuance of additional debt or equity
securities, the sale of production payments or other means.
These changes in capitalization may significantly affect our
risk profile. Additionally, significant acquisitions or other
transactions can change the character of our operations and
business. The character of the new properties may be
substantially different in operating or geological
characteristics or geographic location than our existing
properties. Furthermore, we may not be able to obtain external
funding for any such transactions or to obtain additional
external funding on terms acceptable to us.
The
unavailability or high cost of drilling rigs, equipment,
supplies, personnel and oilfield services could adversely affect
our ability to execute on a timely basis our exploration and
development plans within our budget.
All of our operations are in the Gulf of Mexico and Gulf Coast
onshore regions. Shortages or the high cost of drilling rigs,
equipment, supplies or personnel could delay or adversely affect
our exploration and development plans, which could have a
material adverse effect on our business, financial condition or
results of operations. Periodically, as a result of increased
drilling activity or a decrease in the supply of equipment,
materials and services, we have experienced increases in
associated costs, including those related to drilling rigs,
equipment, supplies and personnel and the services and products
of other vendors to the industry. Increased drilling activity in
the Gulf of Mexico and in other offshore areas around the world
also decreases the availability of offshore rigs in the Gulf of
Mexico. We cannot offer assurance that costs will not increase
again or that necessary equipment and services will be available
to us at economical prices.
Provisions
in our organizational documents and under Delaware law could
delay or prevent a change in control of our company, which could
adversely affect the price of our common stock.
The existence of some provisions in our organizational documents
and under Delaware law could delay or prevent a change in
control of our company, which could adversely affect the price
of our common stock. The provisions in our certificate of
incorporation and bylaws that could delay or prevent an
unsolicited change in control of our company include:
|
|
|
|
|
the board of directors ability to issue shares of
preferred stock and determine the terms of the preferred stock
without approval of common stockholders; and
|
|
|
|
a prohibition on the right of stockholders to call meetings and
a limitation on the right of stockholders to act by written
consent and to present proposals or make nominations at
stockholder meetings.
|
In addition, Delaware law imposes some restrictions on mergers
and other business combinations between us and any holder of 15%
or more of our outstanding common stock.
The
loss of key personnel could adversely affect us.
To a large extent, we depend on the services of our chairman and
chief executive officer, Richard A. Bachmann, our president
and chief operating officer, Phillip A. Gobe, and other senior
management personnel. The loss of the services of
Messrs. Bachmann or Gobe or other senior management
personnel could have an adverse effect on our operations. We do
not maintain any insurance against the loss of any of these
individuals.
18
The exploration and production business is highly competitive,
and our success will depend largely on our ability to attract
and retain experienced geoscientists and other professional
staff.
Competition
in the oil and natural gas industry is intense, which may
adversely affect us.
We operate in a highly competitive environment for acquiring oil
and natural gas properties, marketing oil and natural gas and
securing trained personnel. Many of our competitors possess and
employ financial, technical and personnel resources
substantially greater than ours, which can be particularly
important in Gulf of Mexico and Gulf Coast onshore activities.
Those 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 to discover
reserves in the future will depend on our ability to evaluate
and select suitable properties and to consummate transactions in
a highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and
natural gas industry. We cannot make assurances that we will 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. If we are unable to compete
successfully in these areas in the future, our future revenues
and growth may be diminished or restricted.
|
|
Item 1B.
|
Unresolved
Staff Comments
|
None.
|
|
Item 3.
|
Legal
Proceedings
|
In the ordinary course of business, we are a defendant in
various legal proceedings. We do not expect our exposure in
these proceedings, individually or in the aggregate, to have a
material adverse effect on our financial position, results of
operations or liquidity.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
None
|
|
Item 4A.
|
Executive
Officers of the Registrant
|
The following table sets forth certain information regarding our
executive officers:
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position
|
|
Richard A. Bachmann
|
|
|
61
|
|
|
Chairman and Chief Executive
Officer
|
Phillip A. Gobe
|
|
|
53
|
|
|
Director, President and Chief
Operating Officer
|
David R. Looney
|
|
|
49
|
|
|
Executive Vice President and Chief
Financial Officer
|
John H. Peper
|
|
|
53
|
|
|
Executive Vice President, General
Counsel and Corporate Secretary
|
T. Rodney Dykes
|
|
|
49
|
|
|
Senior Vice
President Production
|
Richard A. Bachmann has been chief executive officer and
chairman of the board of directors since our incorporation in
January 1998 and also served as our president until May 2005.
Mr. Bachmann began organizing our company in February 1997.
From 1995 to January 1997, he served as director, president and
chief operating officer of LL&E, an independent oil and
natural gas exploration company. From 1982 to 1995,
Mr. Bachmann held various positions with LL&E,
including director, executive vice president, chief financial
officer and senior vice president of finance and administration.
From 1978 to 1981, Mr. Bachmann was treasurer of Itel
Corporation. Prior to 1978, Mr. Bachmann served with Exxon
International, Esso Central America, Esso InterAmerica and
Standard Oil of New Jersey. He also serves as a director of
Trico Marine Services, Inc.
Phillip A. Gobe joined us in December 2004 as chief operating
officer and was elected president in May 2005 and appointed a
director in November 2005. Mr. Gobe has over 29 years
of energy industry experience and was with
19
Nuevo Energy Company as chief operating officer from February
2001 until its acquisition by Plains Exploration &
Production Company in May 2004. Mr. Gobes primary
responsibilities were managing Nuevos domestic and
international exploitation and exploration operations. Prior to
his position with Nuevo, Mr. Gobe had been the Senior Vice
President of Production for Vastar Resources, Inc. since 1997.
From 1976 to 1997, Mr. Gobe worked for Atlantic Richfield
Company and its subsidiaries in positions of increasing
responsibility, primarily in the Gulf of Mexico and Alaska.
David R. Looney joined us in February 2005 and was elected
executive vice president and chief financial officer in March
2005. Prior to joining us Mr. Looney had been with EOG Resources
Inc. (EOG), where he served as Vice President,
Finance, a position he had held since 1999. In that role his
responsibilities included all finance and treasury functions
including managing external relationships with investment banks,
commercial banks and the rating agencies. Mr. Looney joined
EOG in 1998 as Assistant Treasurer after holding a variety of
financial roles at firms including Toronto-Dominion Bank and
Chase Manhattan Bank.
John H. Peper joined us in January 2002 as executive vice
president, general counsel and corporate secretary. Prior to
joining us, Mr. Peper had been senior vice president,
general counsel and secretary of Hall Houston Oil Company
(HHOC) since February 1993. Mr. Peper also
served as a director of HHOC from October 1991 until we acquired
HHOC in January 2002. For more than five years prior to joining
HHOC, Mr. Peper was a partner in the law firm of Jackson
Walker, L.L.P., where he continued to serve in an of counsel
capacity through 2001.
T. Rodney Dykes joined us in April 2001 as general manager
of operations and was elected vice president of operations in
July 2001. He served as our vice president of exploitation for
the period from March 2002 through July 2003 and was elected
senior vice president production in July 2003.
Mr. Dykes has over 25 years experience in the energy
industry. Immediately prior to joining us, Mr. Dykes worked
as an independent consultant. From 1994 to 1999, Mr. Dykes
held various positions with CMS Oil and Gas Company, including
divisional operations manager, vice president of operations and
vice president of business development. From 1980 to 1994, he
held various technical, drilling and production management
positions with Maxus Energy. Prior to 1980, Mr. Dykes was a
petroleum engineer with Kerr McGee.
PART II
|
|
Item 5.
|
Market
for Registrants Common Stock and Related Stockholder
Matters
|
Our common stock is listed on the New York Stock Exchange under
the symbol EPL. The following table sets forth, for
the periods indicated, the range of the high and low sales
prices of our common stock as reported by the New York Stock
Exchange.
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
Low
|
|
|
2004
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
14.81
|
|
|
$
|
12.60
|
|
Second Quarter
|
|
|
15.45
|
|
|
|
12.60
|
|
Third Quarter
|
|
|
16.59
|
|
|
|
14.00
|
|
Fourth Quarter
|
|
|
20.91
|
|
|
|
16.07
|
|
2005
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
27.97
|
|
|
|
18.38
|
|
Second Quarter
|
|
|
28.63
|
|
|
|
19.06
|
|
Third Quarter
|
|
|
32.98
|
|
|
|
22.20
|
|
Fourth Quarter
|
|
|
32.30
|
|
|
|
21.25
|
|
2006
|
|
|
|
|
|
|
|
|
First Quarter (through
February 22, 2006)
|
|
|
28.68
|
|
|
|
22.00
|
|
On February 22, 2006 the last reported sale price of our
common stock on the New York Stock Exchange was $23.89 per share.
20
As of February 22, 2006 there were approximately 125
holders of record of our common stock.
We have not paid any cash dividends in the past on our common
stock and do not intend to pay cash dividends on our common
stock in the foreseeable future. We intend to retain earnings
for the future operation and development of our business. Any
future cash dividends to holders of common stock would depend on
future earnings, capital requirements, our financial condition
and other factors determined by our board of directors.
|
|
Item 6.
|
Selected
Financial Data
|
The following table shows selected consolidated financial data
derived from our consolidated financial statements which are set
forth in Item 8 of this Report. The data should be read in
conjunction with Managements Discussion and Analysis
of Financial Condition and Results of Operations in
Item 7 of this Report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In thousands, except per share
data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
402,947
|
|
|
$
|
295,210
|
|
|
$
|
230,187
|
|
|
$
|
133,788
|
|
|
$
|
146,240
|
|
Income (loss) from operations(1)
|
|
|
132,027
|
|
|
|
86,068
|
|
|
|
58,560
|
|
|
|
(6,600
|
)
|
|
|
20,663
|
|
Net income (loss)(2)
|
|
|
73,095
|
|
|
|
46,416
|
|
|
|
33,250
|
|
|
|
(8,799
|
)
|
|
|
11,974
|
|
Net income (loss) available to
common stockholders(3)
|
|
|
72,151
|
|
|
|
43,017
|
|
|
|
29,705
|
|
|
|
(12,129
|
)
|
|
|
11,974
|
|
Basic net income (loss) per common
share
|
|
$
|
1.94
|
|
|
$
|
1.31
|
|
|
$
|
0.96
|
|
|
$
|
(0.44
|
)
|
|
$
|
0.45
|
|
Diluted net income (loss) per
common share
|
|
$
|
1.79
|
|
|
$
|
1.20
|
|
|
$
|
0.93
|
|
|
$
|
(0.44
|
)
|
|
$
|
0.44
|
|
Cash flows provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
269,969
|
|
|
$
|
165,074
|
|
|
$
|
136,702
|
|
|
$
|
25,417
|
|
|
$
|
91,847
|
|
Investing activities
|
|
|
(449,159
|
)
|
|
|
(176,713
|
)
|
|
|
(110,057
|
)
|
|
|
(54,380
|
)
|
|
|
(121,067
|
)
|
Financing activities
|
|
|
92,442
|
|
|
|
784
|
|
|
|
77,631
|
|
|
|
29,079
|
|
|
|
25,871
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
2001
|
|
|
|
(In thousands)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
931,285
|
|
|
$
|
647,678
|
|
|
$
|
544,181
|
|
|
$
|
384,220
|
|
|
$
|
242,777
|
|
Long-term debt, excluding current
maturities
|
|
|
235,000
|
|
|
|
150,109
|
|
|
|
150,317
|
|
|
|
103,687
|
|
|
|
25,408
|
|
Stockholders equity
|
|
|
394,593
|
|
|
|
315,049
|
|
|
|
261,485
|
|
|
|
191,922
|
|
|
|
164,867
|
|
Cash dividends per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The 2005 income from operations includes accrued business
interruption insurance recoveries of $20.6 million from
deferred production at four of our fields resulting form
Hurricanes Katrina and Rita. |
|
(2) |
|
The 2003 net income includes a cumulative effect of change
in accounting principle resulting from the adoption of
Statement 143, which increased net income
$2.3 million, net of deferred income taxes of
$1.3 million. |
|
(3) |
|
Net income (loss) available to common stockholders is computed
by subtracting preferred stock dividends and accretion of
discount of $0.9 million, $3.4 million,
$3.5 million and $3.3 million from net income (loss)
for the years ended December 31, 2005, 2004, 2003 and 2002,
respectively. |
21
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
Overview
We were incorporated in January 1998 and operate in a single
segment as an independent oil and natural gas exploration and
production company. Our current operations are concentrated in
the shallow to moderate depth waters of the Gulf of Mexico Shelf
and contiguous Gulf Coast onshore region.
While the impacts of Hurricanes Katrina, Rita, Cindy, Dennis and
Emily (the Tropical Weather) were significant to
2005, we still made progress toward implementing our long-term
growth strategy to increase our oil and natural gas reserves and
production while keeping our finding and development costs and
operating costs competitive with our industry peers. Our strong
cash flow provided us the flexibility to make necessary and
appropriate investments to continue this growth strategy. We
will implement this strategy through drilling exploratory and
development wells from our inventory of available prospects that
we have evaluated for geologic and mechanical risk and future
reserve or resource potential and by making acquisitions,
including acquisitions in our core focus area which includes the
Gulf of Mexico Shelf and onshore Gulf Coast regions and, as a
result of an acquisition of undeveloped acreage in early 2006,
the deepwater Gulf of Mexico. We also evaluate acquisition
opportunities outside of our core focus area as a complement to
the drilling and development activities we have budgeted for
that area. Our drilling program will contain some higher risk,
higher reserve potential opportunities as well as some lower
risk, lower reserve potential opportunities, in order to achieve
a balanced program of reserve and production growth.
We use the successful efforts method of accounting for our
investment in oil and natural gas properties. Under this method,
we capitalize lease acquisition costs, costs to drill and
complete exploration wells in which proven reserves are
discovered and costs to drill and complete development wells.
Seismic, geological and geophysical, and delay rental
expenditures are expensed as incurred. We conduct many of our
exploration and development activities jointly with others and,
accordingly, recorded amounts for our oil and natural gas
properties reflect only our proportionate interest in such
activities.
In connection with the acquisition of a company in January 2002,
its former preferred stockholders have the right to receive
contingent consideration based upon a percentage of the amount
by which the before tax net present value of proved reserves
related, in general, to exploratory prospect acreage held by the
acquired company as of the closing date exceeds a net present
value discounted at 30%. The contingent consideration may be
paid in our common stock or cash at our option (with a minimum
of 20% paid in cash for each payment) and in no event will
exceed a value of $50 million. Due to the uncertainty
inherent in estimating the value of the contingent
consideration, total final consideration will not be determined
until March 1, 2007. The contingent consideration paid will
be capitalized as additional purchase price.
On April 16, 2003, we completed the public offering of
approximately 4.2 million shares of our common stock priced
at $9.50 per share. The equity offering also included
shares offered by our then principal stockholder, Evercore
Capital Partners, L.P. and certain of its affiliates
(Evercore), and by Energy Income Fund, L.P.
(EIF). After payment of underwriting discounts and
commissions, the offering generated net proceeds to us of
approximately $38.0 million. After expenses of
approximately $0.5 million, the proceeds were used to repay
a portion of outstanding borrowings under our bank credit
facility.
On August 5, 2003, we issued $150 million of
8.75% Senior Notes due 2010 (the Senior Notes)
in a Rule 144A private offering (the Debt
Offering) which allows unregistered transactions with
qualified institutional and
non-U.S. purchasers.
After discounts and commissions and all offering expenses, we
received $145.3 million, which was used to redeem all of
our outstanding 11% Senior Subordinated Notes due 2009 (the
11% Notes) and to repay substantially all of
the borrowings outstanding under our bank credit facility. The
remainder of the net proceeds was set aside for general
corporate purposes, including acquisitions. In October 2003, we
consummated an exchange offer pursuant to which we exchanged
registered Senior Notes having substantially identical terms as
the Senior Notes for the privately placed Senior Notes.
On July 16, 2004, we filed a universal shelf registration
statement (the Registration Statement) which allows
us to issue an aggregate of $300 million in common stock,
preferred stock, senior debt and subordinated debt in one or
more separate offerings with the size, price and terms to be
determined at the time of the sale. On November 10, 2004 we
sold approximately 3.5 million shares of our common stock
to the public pursuant to the Registration
22
Statement. Concurrent with this offering, we entered into a
stock purchase agreement with EIF pursuant to which we purchased
an equal number of shares of common stock owned by EIF at a
price per share equal to the proceeds per share received in the
offering, before expenses. We did not retain any of the proceeds
from the offering and the shares are now held as treasury
shares, at cost. We restored the Registration Statement to
$300 million in May 2005. We have no immediate plans to
enter into any additional transactions under the Registration
Statement, but plan to use the proceeds of any future offering
under the Registration Statement for general corporate purposes,
which may include debt repayment, acquisitions, expansion and
working capital.
On August 3, 2004 we amended and extended to August 3,
2008 our bank credit facility. The borrowing base was increased
to $150 million at the time of our purchase of south
Louisiana properties and reserves in January 2005. At
December 31, 2005 we had $85 million outstanding under
our bank credit facility. The borrowing base remains subject to
redetermination based on the proved reserves of the oil and
natural gas properties that serve as collateral for the bank
credit facility. Our borrowing base was reaffirmed effective
November 1, 2005.
On January 20, 2005, we closed an acquisition of properties
and reserves in south Louisiana for $149.6 million in cash,
after adjustments for the exercise of preferential rights by
third parties and closing adjustments. The acquisition was
composed of nine fields, four of which were producing at the
time of the closing through 14 wells, with estimated
acquisition date proved reserves of 51.2 billion cubic feet
equivalent. Also included were interests in 22 exploratory
prospects. The transaction expanded the exploration
opportunities in our expanded focus area. Upon the signing of
the purchase agreement, we paid a $5.0 million deposit in
2004 toward the purchase price which was recorded as other
assets in the year-end 2004 consolidated balance sheet, and
concurrent with the closing, the borrowing base under our bank
credit facility was increased to $150 million, of which
$60 million was drawn to fund the acquisition. In
connection with the acquisition, we also entered into a two-year
agreement with the seller of the properties that defined an area
of mutual interest (AMI) encompassing over one
million acres. We intend to continue to explore and develop oil
and natural gas reserves in the AMI over the two year term
jointly with the seller. The proved reserves, prospects and the
AMI are in the southern portions of Terrebone, Lafourche and
Jefferson Parishes in Louisiana.
On March 8, 2005, we closed the acquisition of the
remaining 50% gross working interest in South Timbalier 26 above
approximately 13,000 feet subsea that we did not already
own for approximately $19.6 million after closing
adjustments. As a result of the acquisition, we now own a 100%
gross working interest in the producing horizons in this field.
The acquisition expands our interest in our core Greater Bay
Marchand area and has given us additional flexibility in
undertaking the future development of the South Timbalier 26
field.
We have included the results of operations from the acquisitions
discussed above from their respective closing dates. We had
experienced substantial revenue and production growth as a
result of these acquisitions through the period prior to the
tropical weather discussed below. For the foregoing reasons
these acquisitions will affect the comparability of our
historical results of operations with future periods.
On August 29, 2005 Hurricane Katrina made landfall south of
New Orleans causing catastrophic damage throughout portions of
the Gulf of Mexico and to portions of Alabama, Louisiana and
Mississippi, including New Orleans. As a result of the
devastating effects of the storm on New Orleans and surrounding
areas, we announced on August 30 that we had elected to
establish temporary headquarters at our Houston, Texas office. A
satellite office was also established in Baton Rouge, Louisiana.
On September 24, 2005 Hurricane Rita made landfall in the
United States on the Texas/Louisiana border between Sabine Pass,
Texas and Johnsons Bayou, Louisiana. This hurricane caused
extensive damage throughout portions of the region, particularly
to third party infrastructure such as pipelines and processing
plants.
As a result of these two major hurricanes and other Tropical
Weather, nearly all of our production was shut in at one time or
another during the third quarter of 2005 and a portion of that
production had not yet been restored by the end of the fourth
quarter of 2005. We are continuing to work to bring operations
back to pre-storm levels, but are subject to constraints due to
damage to third party infrastructure. During 2005 we maintained
business interruption insurance on our significant properties,
including our East Bay field. Recovery of lost revenue for our
East Bay field and two other fields began accruing in October
while recovery on a fourth field began accruing in December.
Through December 31, 2005 we had accrued $20.6 million
for business interruption. Production was fully restored
23
in three of these fields in 2005, at which time coverage ceased,
and recoveries will continue to accrue on one other until
production is fully restored, subject to policy limits that we
do not expect, at this time, to be reached.
Our revenue, profitability and future growth rate depend on a
number of factors beyond our control, such as tropical weather,
economic, political and regulatory developments and competition
from other sources of energy. Oil and natural gas prices
historically have been volatile and may fluctuate widely in the
future. Sustained periods of low prices for oil and natural gas
could materially and adversely affect our financial position,
our results of operations, the quantities of oil and natural gas
reserves that we can economically produce and our access to
capital. See Risk Factors in Item 1A for a more
detailed discussion of these risks.
We currently have an extensive inventory of drillable prospects
in-house, we are generating more internally and we are being
exposed to new opportunities through relationships with industry
partners. Despite our expanded budget of $360 million in
2006, strong commodity prices, together with growing production
volumes, should enable us to adhere to our policy of funding our
exploration and development expenditures with internally
generated cash flow. This strategy allows us to preserve our
strong balance sheet to finance acquisitions and other capital
intensive projects that might result from our exploration and
development activities. We believe that the near term may
provide us with further opportunities to acquire targeted
properties, including those within our focus area.
Results
of Operations
The following table presents information about our oil and
natural gas operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Net production (per day):
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
7,984
|
|
|
|
8,663
|
|
|
|
7,978
|
|
Natural gas (Mcf)
|
|
|
88,430
|
|
|
|
82,098
|
|
|
|
78,596
|
|
Total (Boe)
|
|
|
22,722
|
|
|
|
22,346
|
|
|
|
21,077
|
|
Oil & natural gas
revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
135,359
|
|
|
$
|
111,006
|
|
|
$
|
81,599
|
|
Natural gas
|
|
|
266,646
|
|
|
|
183,525
|
|
|
|
148,104
|
|
Total
|
|
|
402,005
|
|
|
|
294,531
|
|
|
|
229,703
|
|
Average sales prices, net of
hedging:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
46.45
|
|
|
$
|
35.01
|
|
|
$
|
28.02
|
|
Natural gas (per Mcf)
|
|
|
8.26
|
|
|
|
6.11
|
|
|
|
5.16
|
|
Total (per Boe)
|
|
|
48.47
|
|
|
|
36.01
|
|
|
|
29.86
|
|
Impact of hedging:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
(3.15
|
)
|
|
$
|
(4.40
|
)
|
|
$
|
(1.67
|
)
|
Natural gas (per Mcf)
|
|
|
(0.24
|
)
|
|
|
(0.04
|
)
|
|
|
(0.23
|
)
|
Average costs (per Boe):
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
6.08
|
|
|
$
|
4.93
|
|
|
$
|
4.76
|
|
Taxes, other than on earnings
|
|
|
1.25
|
|
|
|
1.13
|
|
|
|
0.99
|
|
Depreciation, depletion and
amortization
|
|
|
12.50
|
|
|
|
11.29
|
|
|
|
10.65
|
|
Increase in oil and natural gas
revenue (net of hedging) due to:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in prices of oil
|
|
$
|
35,863
|
|
|
$
|
22,160
|
|
|
|
|
|
Change in production volumes of oil
|
|
|
(11,510
|
)
|
|
|
7,247
|
|
|
|
|
|
Total increase in oil sales
|
|
|
24,353
|
|
|
|
29,407
|
|
|
|
|
|
Change in prices of natural gas
|
|
$
|
64,006
|
|
|
$
|
28,396
|
|
|
|
|
|
Change in production volumes of
natural gas
|
|
|
19,115
|
|
|
|
7,025
|
|
|
|
|
|
Total increase in natural gas sales
|
|
|
83,121
|
|
|
|
35,421
|
|
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Total estimated net proved
reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbls)
|
|
|
31,478
|
|
|
|
28,770
|
|
|
|
27,414
|
|
Natural gas (Mmcf)
|
|
|
166,949
|
|
|
|
149,835
|
|
|
|
134,404
|
|
Total (Mboe)
|
|
|
59,303
|
|
|
|
53,743
|
|
|
|
49,815
|
|
Present value of estimated future
net cash flows before income taxes (in thousands)
|
|
$
|
1,806,185
|
|
|
$
|
924,135
|
|
|
$
|
701,237
|
|
Standardized measure of discounted
future net cash flows (in thousands)
|
|
$
|
1,261,246
|
|
|
$
|
667,668
|
|
|
$
|
529,415
|
|
Revenues
and Net Income
Our oil and natural gas revenues increased to
$402.0 million in 2005 from $294.5 million in 2004.
The increase in revenue for this period is in large part the
result of sharply increased natural gas and oil prices which
were driven even higher in the aftermath of Hurricanes Katrina
and Rita. The increase was also attributable to increased
production, despite the storms, resulting primarily from the
commencement of production from 26 new wells brought on
production since year end 2004, 23 of which were natural gas. In
addition, our acquisitions in the first quarter of 2005 of the
south Louisiana properties and the additional interest in South
Timbalier 26 added incremental production compared to 2004.
However, the foregoing increases were adversely impacted by an
estimated 5,490 Boe per day of deferred production for the full
year of 2005 from production shut-ins resulting from the
Tropical Weather compared to deferred production of 597 Boe per
day in 2004 from Hurricane Ivan and Tropical Storm Matthew. Also
included in 2005 income from operations is $20.6 million of
accrued business interruption insurance recoveries from deferred
production at four of our fields resulting from Hurricanes
Katrina and Rita.
Our oil and natural gas revenues increased to
$294.5 million in 2004 from $229.7 million in 2003. In
2004, the oil and natural gas industry experienced then record
high oil prices as well as sustained high natural gas prices.
The increase in revenue for this period is the result of these
significantly increased natural gas and oil prices combined with
increased production resulting primarily from the commencement
of production from 20 new wells brought on production since year
end 2003, 16 of which were natural gas. These increases were
partially offset by natural reservoir declines. In addition,
volumes were negatively affected by Hurricane Ivan and Tropical
Storm Matthew.
We recognized net income of $73.1 million in 2005 compared
to net income of $46.4 million in 2004. The increase was
primarily a result of the increase in oil and natural gas
revenue and business interruption recovery previously discussed,
which was offset by our increased operating costs, as discussed
below. We recognized net income of $46.4 million in 2004
compared to net income of $33.3 million in 2003. The
increase in net income in 2004 was primarily due to the increase
in oil and natural gas revenues previously discussed and
partially offset by higher operating costs, as discussed below.
While our 2005 results were strong, we did not achieve the
sequential growth in volumes that we anticipated due to downtime
from the Tropical Weather during the second half of the year.
Operating
Expenses
Operating expenses were impacted by the following:
|
|
|
|
|
Lease operating expense increased $10.1 million to
$50.4 million in 2005. The increase is a result of the
uninsured portion of repairs due to the Tropical Weather of
$2.7 million, and was also affected by new wells coming on
stream in new fields, acquisitions during the first quarter of
2005 and workovers, as well as a general increase in the cost of
oilfield industry services.
|
Lease operating expense increased $3.6 million to
$40.3 million in 2004. This is a result of the addition of
production from new fields and $1.0 million related to the
retained loss portion of repairs due to Hurricane Ivan.
25
|
|
|
|
|
Taxes, other than on earnings, increased $1.1 million to
$10.4 million in 2005. This increase was due to the
increase in commodity prices and production from the acreage
acquired in the south Louisiana property acquisition. These
taxes are expected to fluctuate from period to period depending
on our production volumes from non-federal leases and the
commodity prices received.
|
Taxes, other than on earnings increased $1.6 million to
$9.3 million in 2004. This increase was due to the increase
in commodity prices received for our oil and natural gas
production on state leases, primarily at East Bay and Bay
Marchand, which are subject to Louisiana severance taxes. These
taxes are expected to fluctuate from period to period depending
on our production volumes from state leases and the commodity
prices received.
|
|
|
|
|
Exploration expenditures and dry hole costs, increased
$35.9 million to $64.9 million in 2005. The increase
is primarily due to the increase in our exploratory drilling
program from 25 exploratory wells drilled in 2004, to 45
exploratory wells drilled in 2005. The expense in 2005 is
comprised of $52.0 million of costs for exploratory wells
or portions thereof which were found to be not commercially
productive and $12.9 million of seismic expenditures and
delay rentals.
|
Exploration expenditures increased $14.4 million to
$29.0 million in 2004. The expense in 2004 was comprised of
$21.0 million of costs for exploratory wells or portions
thereof which were found to be not commercially productive and
seismic expenditures and delay rentals of $8.0 million.
Our exploration expenditures, including dry hole charges, will
vary depending on the amount of our capital budget dedicated to
exploration activities and the level of success we achieve in
exploratory drilling activities.
|
|
|
|
|
Impairment of properties increased $11.0 million to
$17.9 million in 2005. The increase is due to impairments
taken at six fields which would need significant capital to
extend their economic lives. We decided to deploy the capital to
projects with more potential, therefore impairing the assets. We
also had two fields with partial impairments due to insufficient
cash flow from reserves.
|
Impairment of properties increased $4.1 million to
$6.9 million in 2004. The expense in 2004 was comprised of
a property impairment at our East Cameron 378 field.
|
|
|
|
|
Depreciation, depletion and amortization increased
$11.2 million to $103.6 million in 2005. The increase
was in part a result of higher production in 2005. In addition,
the shift in the production contribution amongst our various
fields increased our total expense as well as our expense per
Boe. Some fields carry a higher depreciation burden than others,
therefore, changes in the mix of our production among the
various fields will directly impact this expense.
|
Depreciation, depletion and amortization increased
$10.5 million to $92.4 million in 2004. The increase
was due to the increased depreciable asset base combined with
higher production and a shift in the production contribution
from our various fields. This expense includes $6.6 million
of amortization for our asset retirement obligation for 2004 as
compared to $5.2 million in 2003. In addition, the shift in
the production contribution amongst our various fields increased
our expense per Boe. Some fields carry a higher depreciation
burden than others, therefore, changes in the mix of our
production among the various fields will directly impact this
expense.
|
|
|
|
|
Other general and administrative expenses increased
$8.5 million to $36.4 million in 2005. The increase
was due to the provision for a contractual dispute of
$3.4 million as well as the costs associated with
temporarily relocating our personnel and headquarters to Houston
and opening a Baton Rouge office in the wake of Hurricane
Katrina. Costs incurred of approximately $1.6 million
included employee relocation allowances and housing, temporary
office space and furniture rental as well as the purchase of
computer equipment. In addition, the increase was due to
increased personnel costs resulting from our overall increased
level of activity and expanded asset base as well as increased
cost of insurance.
|
Other general and administrative expenses increased
$1.2 million to $27.9 million in 2004. The increase
was primarily due to increased consulting costs of
$1.9 million, of which $0.4 million was increased
costs paid to our internal audit service provider and external
auditors to implement the requirements of Section 404 of
the
26
Sarbanes-Oxley Act of 2002. The remainder included increased
human resources, land and engineering consulting costs which was
offset by decreased casualty insurance and technology costs.
|
|
|
|
|
Non-cash stock-based compensation expense of $6.8 million
was recognized in 2005, an increase of $3.7 million from
2004. The increased expense relates to the increased
amortization of new restricted share units and performance share
awards made to employees in late 2004 and in 2005 as well as the
impact of the increased stock price throughout most of the year
on our variable awards and accelerated vesting of stock awards
for two former employees.
|
Non-cash stock-based compensation expense of $3.1 million
was recognized in 2004, an increase of $1.8 million from
2003. This expense has increased due to additional grants of
restricted share units and performance share awards to
employees. The level of expense for these awards is also
affected by the increased stock price in 2004.
Other
Income and Expense
Interest expense increased $3.7 million to
$18.1 million in 2005. The increase was a result of
interest expense on borrowings under our bank credit facility to
finance acquisitions and for short-term fluctuations in working
capital.
Interest expense increased $4.2 million to
$14.4 million in 2004. The increase was a result of
interest expense on the Senior Notes issued in August 2003
partially offset by the interest savings from the redemption of
the 11% Notes and the repayment of borrowings under the bank
facility in 2003.
Financial
Condition, Liquidity and Capital Resources
The trend of increased revenues we have experienced in 2005 has
continued to provide strong cash flows from operations, which
totaled $270.0 million. We intend to fund our exploration
and development expenditures from internally generated cash
flows, which we define as cash flows from operations before
consideration of changes in working capital plus total
exploration expenditures. Our cash on hand at December 31,
2005 was $6.8 million. Our future internally generated cash
flows will depend on our ability to maintain and increase
production through our exploration and development drilling
program, as well as the prices of oil and natural gas. We may
from time to time use the availability of our bank credit
facility to balance working capital needs.
Our bank credit facility, as amended on August 3, 2004,
consists of a revolving line of credit with a group of banks
available through August 3, 2008 (the bank credit
facility). The bank credit facility currently has a
borrowing base of $150 million that is subject to
redetermination based on the proved reserves of the oil and
natural gas properties that serve as collateral for the bank
credit facility as set out in the reserve report delivered to
the banks each April 1 and October 1. The bank credit
facility permits both prime rate borrowings and London interbank
offered rate (LIBOR) borrowings plus a floating
spread. The spread will float up or down based on our
utilization of the bank credit facility. The spread can range
from 1.25% to 2.00% above LIBOR and 0% to 0.75% above prime. The
borrowing base under the bank credit facility is secured by
substantially all of our assets. We used our bank credit
facility to fund a portion of the purchase of the south
Louisiana properties in January 2005 and the acquisition of the
additional interest in South Timbalier 26 in March 2005. At
February 22, 2006, we had $95 million outstanding and
$55 million of credit capacity available under the bank
credit facility. In addition, we pay an annual fee on the unused
portion of the bank credit facility ranging between 0.375% to
0.5% based on utilization. The bank credit facility contains
customary events of default and various financial covenants,
which require us to: (i) maintain a minimum current ratio,
as defined by our bank credit facility, of 1.0 and
(ii) maintain a minimum EBITDAX to interest ratio, as
defined by our bank credit facility, of 3.5 times. We were in
compliance with these covenants as of December 31, 2005.
On August 5, 2003, we issued $150 million of
8.75% senior notes due 2010 which were exchanged in October
2003 for registered 8.75% senior notes due 2010 (the
Registered Senior Notes) with substantially the same
terms. The Registered Senior Notes bear interest at a rate of
8.75% per annum with interest payable semi-annually on
February 1 and August 1, beginning February 1,
2004. We may redeem the Senior Notes at our option, in whole or
in part, at any time on or after August 1, 2007 at a price
equal to 100% of the principal amount plus accrued and
27
unpaid interest, if any, plus a specified premium which
decreases yearly from 4.375% in 2007 to 0% in 2009 and
thereafter. In addition, at any time prior to August 1,
2006, we may redeem up to a maximum of 35% of the aggregate
principal amount with the net proceeds of certain equity
offerings at a price equal to 108.75% of the principal amount,
plus accrued and unpaid interest. The notes are unsecured
obligations and rank equal in right of payment to all existing
and future senior debt, including the bank credit facility, and
will rank senior or equal in right of payment to all existing
and future subordinated indebtedness. The indenture relating to
the Registered Senior Notes contains certain restrictions on our
ability to incur additional debt, pay dividends on our common
stock, make investments, create liens on our assets, engage in
transactions with our affiliates, transfer or sell assets and
consolidate or merge substantially all of our assets. The
Registered Senior Notes are not subject to any sinking fund
requirements.
Upon closing on the Senior Notes on August 5, 2003, we
called our 11% Notes due 2009 for redemption. The redemption of
the 11% Notes in aggregate principal and accrued interest
was funded with a portion of the proceeds received from the
Senior Notes and was completed in August 2003. The
11% Notes were issued on January 15, 2002 as part of
the financing of an acquisition. In addition, $39.9 million
of the proceeds from the Senior Notes were used to re-pay
substantially all of the borrowings under the bank credit
facility. As a result of the issuance of the Senior Notes, our
bank credit facility borrowing base was reduced from
$100 million to $60 million requiring a non-cash
charge of $0.3 million for the write-off of the pro rata
remaining balance of unamortized issue costs.
Net cash of $449.2 million used in investing activities in
2005 primarily included $254.9 million of oil and natural
gas property capital and exploration expenditures and
$193.1 million for property acquisitions which included the
acquisitions of properties and reserves onshore in south
Louisiana, the acquisition of the remaining 50% gross working
interest in South Timbalier 26 and $27.6 million of lease
acquisitions. Exploration expenditures incurred are excluded
from operating cash flows and included in investing activities.
During 2005, we completed 56 drilling projects and 32
recompletion/workover projects, 60 of which were successful.
During 2004, we completed 31 drilling projects and 21
recompletion/workover projects, 41 of which were successful.
Our 2006 capital exploration and development budget is focused
on exploration, exploitation and development activities on our
proved properties combined with moderate and higher risk
exploratory activities on undeveloped leases and does not
include acquisitions. We continue to manage our portfolio in
order to maintain an appropriate risk balance between low risk
development and exploitation activities, moderate risk
exploration opportunities and higher risk, higher potential
exploration opportunities. Our exploration and development
budget for 2006 is currently $360 million. We do not budget
for acquisitions. During 2005, capital and exploration
expenditures were approximately $485.7 million inclusive of
a $0.9 million contingent consideration payment resulting
from an acquisition completed during 2002, $170.5 million
related to acquisitions in 2005 and $6.9 million in asset
retirement obligations. The level of our budget is based on many
factors, including results of our drilling program, oil and
natural gas prices, industry conditions, participation by other
working interest owners and the costs of drilling rigs and other
oilfield goods and services. Should actual conditions differ
materially from expectations, some projects may be accelerated
or deferred and, consequently, may increase or decrease total
2006 capital expenditures.
We have experienced and expect to continue to experience
substantial working capital requirements, primarily due to our
active exploration and development program. We believe that
internally generated cash flows will be sufficient to meet our
budgeted capital requirements for at least the next twelve
months. Availability under the bank facility will be used to
balance short-term fluctuations in working capital requirements.
However, additional financing may be required in the future to
fund our growth.
28
Disclosures
about Contractual Obligations and Commercial
Commitments
The following table aggregates the contractual commitments and
commercial obligations that affect our financial condition and
liquidity position as of December 31, 2005:
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Payments Due by Period
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Less Than
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Total
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1 Year
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1-3 Years
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3-5 Years
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Thereafter
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(In thousands)
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Long-term debt
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$
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235,109
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$
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109
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$
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85,000
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$
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150,000
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$
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Interest attributable to all
long-term debt
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68,231
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18,282
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29,258
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20,781
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Operating leases
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17,764
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3,074
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4,161
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2,826
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7,703
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Unconditional purchase
obligations(1)
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58,367
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52,367
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6,000
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Other long-term liabilities
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11,213
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9,842
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1,371
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Total contractual obligations
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$
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390,684
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$
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73,832
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$
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134,261
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$
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173,607
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$
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9,074
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(1) |
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Consists of commitments to purchase seismic related services and
drilling rig commitments. |
Off-Balance
Sheet Transactions
We do not maintain any off-balance sheet transactions,
arrangements, obligations or other relationships with
unconsolidated entities or others that are reasonably likely to
have a material current or future effect on our financial
condition, changes in financial condition, revenues or expenses,
results of operations, liquidity, capital expenditures or
capital resources.
Hedging
Activities
We enter into hedging transactions with major financial
institutions to reduce exposure to fluctuations in the price of
oil and natural gas. We also distribute our hedging transactions
to a variety of financial institutions to reduce our exposure to
counterparty credit risk. Our hedging program uses
financially-settled crude oil and natural gas swaps and
zero-cost collars to provide floor prices with varying upside
price participation. Our hedges are benchmarked to the New York
Mercantile Exchange (NYMEX) West Texas Intermediate
crude oil contracts and Henry Hub natural gas contracts. With a
financially-settled swap, the counterparty is required to make a
payment to us if the settlement price for any settlement period
is below the hedged price for the transaction, and we are
required to make a payment to the counterparty if the settlement
price for any settlement period is above the hedged price for
the transaction. With a zero-cost collar, the counterparty is
required to make a payment to us if the settlement price for any
settlement period is below the floor price of the collar, and we
are required to make a payment to the counterparty if the
settlement price for any settlement period is above the cap
price of the collar. In some hedges, we may modify our collar to
provide full upside participation after a limited
non-participation range. We had no crude oil positions and the
following natural gas contracts as of December 31, 2005:
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Natural Gas Positions
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Strike Price
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Volume (Mmbtu)
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Remaining Contract
Term
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Contract Type
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($/Mmbtu)
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Daily
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Total
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01/06 - 12/06
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Collar
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$
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5.00/$9.51
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15,000
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5,475,000
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01/07 - 12/07
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Collar
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$
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5.00/$8.00
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10,000
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3,650,000
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Accounting and reporting standards require that derivative
instruments, including certain derivative instruments embedded
in other contracts, be recorded at fair market value and
included as either assets or liabilities in the balance sheet.
The accounting for changes in fair value depends on the intended
use of the derivative and the resulting designation, which is
established at the inception of the derivative. Special
accounting for qualifying hedges allows a derivatives
gains and losses to offset related results on the hedged item in
the statement of operations. For derivative instruments
designated as cash-flow hedges, changes in fair value, to the
extent the hedge
29
is effective, will be recognized in other comprehensive income
(a component of stockholders equity) until the forecasted
transaction is settled, when the resulting gains and losses will
be recorded in oil and natural gas revenue. Hedge
ineffectiveness is measured at least quarterly based on the
changes in fair value between the derivative contract and the
hedged item. Any change in fair value resulting from
ineffectiveness is charged currently to other revenue.
Our hedged volume as of December 31, 2005 approximated 8%
of our estimated production from proved reserves through the
balance of the terms of the contracts.
We may in the future enter into these and other types of hedging
arrangements to reduce our exposure to fluctuations in the
market prices of oil and natural gas. Hedging transactions
expose us to risk of financial loss in some circumstances,
including if production is less than expected, the other party
to the contract defaults on its obligations, or there is a
change in the expected differential between the underlying price
in the hedging agreement and actual prices received. Hedging
transactions may limit the benefit we would have otherwise
received from increases in the prices for oil and natural gas.
Furthermore, if we do not engage in hedging transactions, we may
be more adversely affected by declines in oil and natural gas
prices than our competitors who engage in hedging transactions.
Discussion
of Critical Accounting Policies
In preparing our financial statements in accordance with
accounting principles generally accepted in the United States,
management must make a number of estimates and assumptions
related to the reporting of assets, liabilities, revenues, and
expenses and the disclosure of contingent assets and
liabilities. Application of certain of our accounting policies
requires a significant number of estimates. These accounting
policies are described below.
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Successful Efforts Method of
Accounting Oil and natural gas exploration
and production companies choose one of two acceptable accounting
methods, successful-efforts or full cost. The most significant
difference between the two methods relates to the accounting
treatment of drilling costs for unsuccessful exploration wells
(dry holes) and exploration costs. Under the
successful-efforts method, we recognize exploration costs and
dry hole costs as an expense on the income statement when
incurred and capitalize the costs of successful exploration
wells as oil and natural gas properties. Companies that follow
the full cost method capitalize all drilling and exploration
costs including dry hole costs into one pool of total oil and
natural gas property costs.
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We use the successful-efforts method because we believe that it
more conservatively reflects, on our balance sheet, the
historical costs that have future value. However, using
successful-efforts often causes our income to fluctuate
significantly between reporting periods based on our drilling
success or failure during the periods.
It is typical for companies that have an active exploratory
drilling program, as we do, to incur dry hole costs. During the
last three years we have drilled 91 exploration wells, of which
26 were considered dry holes. Our dry hole costs charged to
expense during this period totaled $82.9 million out of
total exploratory drilling costs of $345.3 million. It is
impossible to predict future dry holes; however we expect to
continue to have dry hole costs in the future which will vary
depending on the amount of our capital dedicated to exploration
activities and on the level of success of our exploratory
program.
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Proved Reserve Estimates Evaluations of
oil and natural gas reserves are important to the effective
management of our producing assets. They are integral to making
investment decisions and are also used as a basis of calculating
the units of production rates for depletion, depreciation and
amortization and evaluating capitalized costs for impairment.
Proved reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of
the date the estimate is made.
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Our independent reserve engineers prepare our oil and natural
gas reserve estimates using guidelines established by the
U.S. Securities and Exchange Commission and
U.S. generally accepted accounting principles. The quality
and quantity of data, the interpretation of the data, and the
accuracy of mandated
30
economic assumptions combined with the judgment exercised by the
independent reserve engineers affect the accuracy of the
estimated reserves. In addition, drilling or production results
after the date of the estimate may cause material revisions to
the reserve estimates in subsequent periods.
At December 31, 2005, proved oil and natural gas reserves
were 59.3 million barrels of oil-equivalent
(Mmboe). Approximately 82% of our proved reserves
are classified as either proved undeveloped or proved developed
non-producing reserves. Most of our proved developed
non-producing reserves are behind pipe and will be
produced after depletion of another horizon in the same well.
Approximately 28% of total proved reserves are categorized as
proved undeveloped reserves. As of December 31, 2005, 47%
of our proved undeveloped reserves were under development and
expected to become proved developed within one year.
You should not assume that the present value of the future net
cash flow disclosed in this report reflects the current market
value of the oil and natural gas reserves. In accordance with
the U.S. Securities and Exchange Commissions
guidelines, we use prices and costs determined on the date of
the estimate and a 10% discount rate to determine the present
value of future net cash flow. Actual costs incurred and prices
received in the future may vary significantly and the discount
rate may or may not be appropriate based on outside economic
conditions.
The computation of the standardized measure of discounted future
net cash flows relating to proved oil and natural gas reserves
at December 31, 2005 was based on period-end prices of
$10.31 per Mcf for natural gas and $57.81 per barrel
for crude after adjusting the West Texas Intermediate posted
price per barrel and the Gulf Coast spot market price per Mmbtu
for energy content, quality, transportation fees, and regional
price differentials for each property. We estimated the costs
based on the current year costs incurred for individual
properties or similar properties if a particular property did
not have production during the prior year.
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Depletion, Depreciation, and Amortization of Oil and Natural
Gas Properties We calculate depletion,
depreciation, and amortization expense (DD&A)
using the estimates of proved oil and natural gas reserves
previously discussed in these critical accounting policies. We
segregate the costs for individual or contiguous properties or
projects and record DD&A for these property costs separately
using the units of production method. The units of production
method is calculated as the ratio of (1) actual volumes
produced to (2) total proved developed reserves (those
proved reserves recoverable through existing wells with existing
equipment and operating methods) applied to (3) asset cost.
The volumes produced and asset cost are known, and while proved
developed reserves are reasonably certain, they are based on
estimates that are subject to some variability. This variability
can result in net upward or downward revisions of proved
developed reserves in existing fields, as more information
becomes available through research and production and as a
result of changes in economic conditions. Our revisions over the
three years prior to the 2005 fiscal year, in each case either
positive or negative, had been less than 5% of total proved
reserves on a barrel of oil equivalent basis, however in 2005
our negative revisions of 4,045 Mboe represented 7.5% of our
total reserves. These revisions included a downward revision of
5,351 Mboe primarily related to the proved undeveloped reserves
acquired in the South Louisiana onshore acquisition in January
2005. Such revisions were derived primarily from the results of
actual drilling activity in 2005. While the revisions we have
made in the past are an indicator of variability, they have had
a minimal impact on the units of production rates because they
have been low compared to our reserve base or relate to fields
just coming on production. Actual historical revisions are not
necessarily indicative of future variability.
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Impairment of Oil and Natural Gas
Properties We continually monitor our
long-lived assets recorded in property and equipment in our
consolidated balance sheet to make sure that they are fairly
presented. We must evaluate our properties for potential
impairment when circumstances indicate that the carrying value
of an asset may not be recoverable. Because we account for our
proved oil and natural gas properties separately under the
successful efforts method of accounting, we assess our assets
for impairment property by property rather than in one pool of
total oil and natural gas property costs. A significant amount
of judgment is involved in performing these evaluations since
the amount is based on estimated future events. Such events
include a projection of future oil and natural gas sales prices,
an estimate of the ultimate amount of recoverable oil and
natural gas reserves that will be produced from a field, the
timing of this future
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production, future costs to produce the oil and natural gas, and
future inflation levels. The need to test a property for
impairment can be based on several factors, including a
significant reduction in sales prices for oil
and/or
natural gas, unfavorable adjustments to reserve volumes, or
other changes to contracts, environmental regulations or tax
laws. In general, we do not view temporarily low oil or natural
gas prices as a triggering event for conducting impairment
tests. The markets for crude oil and natural gas have a history
of significant price volatility. Although prices will
occasionally drop precipitously, industry prices over the
long-term are driven by market supply and demand. Accordingly,
any impairment tests that we perform make use of our long-term
price assumptions for the crude oil and natural gas markets.
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We base our assessment of possible impairment using our best
estimate of future prices, costs and expected net cash flow
generated by a property. We estimate future prices based on
managements expectations and escalate both the prices and
the costs for inflation if appropriate. If these undiscounted
estimates indicate an impairment, we measure the impairment
expense as the difference between the net book value of the
asset and its estimated fair value measured by discounting the
future net cash flow from the property at an appropriate rate.
Actual prices, costs, discount rates, and net cash flow may vary
from our estimates. An estimate as to the sensitivity to
earnings resulting from impairment reviews and impairment
calculations is not practicable, given the broad range in the
cost structure of our oil and natural gas assets and the number
of assumptions involved in the estimates. That is, favorable
changes to some assumptions may avoid the need to impair any
assets, whereas unfavorable changes might cause some assets to
become impaired but not others. We recognized impairment expense
of $17.9 million, $6.9 million and $2.8 million
in the years ending December 31, 2005, 2004 and 2003. The
impairment in 2005 consisted of full impairment at six fields
which we determined would need significant capital to extend
their economic lives. We decided that the capital would be
deployed to projects with more potential and therefore impaired
the assets. Additionally, we had two fields with partial
impairments due to insufficient cash flow from reserves. The
impairment in 2004 consisted of one field which incurred
significant capital costs in excess of those anticipated. Two
fields were fully impaired in 2003 due to mechanical problems.
We estimate the amount of capitalized costs of unproved
properties which will prove unproductive by amortizing the
balance of the unproved property costs (adjusted by an
anticipated rate of future successful development) over an
average lease term. We will transfer the original cost of an
unproved property to proved properties when we find commercial
oil and natural gas reserves sufficient to justify full
development of the property. If we do not find commercial oil
and natural gas reserves, the related unamortized capitalized
costs will be charged to earnings when the determination is made.
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Asset retirement obligation We adopted
Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations
(Statement 143) on January 1, 2003. We
have significant obligations to plug and abandon oil and natural
gas wells and related equipment as well as to dismantle and
abandon facilities at the end of oil and natural gas production
operations. We record the fair value of a liability for an Asset
Retirement Obligation (ARO) in the period in which
it is incurred and a corresponding increase in the carrying
amount of the related asset. Subsequently, the ARO included in
the carrying amount of the related asset are allocated to
expense using the
units-of-production
method. In addition, accretion of the discount related to the
ARO liability resulting from the passage of time is reflected as
additional depreciation, depletion and amortization expense in
the Consolidated Statement of Operations.
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Inherent in the fair value calculation of the ARO are numerous
assumptions and judgments including the ultimate settlement
amounts, inflation factors, credit adjusted discount rates,
timing of settlement, and changes in the legal, regulatory,
environmental and political environments. To the extent future
revisions to these assumptions impact the present value of the
existing ARO liability, a corresponding adjustment will be
required to be made to the oil and natural gas property balance.
This adjustment may then have a positive or negative impact on
the associated depreciation expense and accretion expense
depending on the nature of the revision.
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Derivative instruments and hedging
activities We enter into hedging
transactions for our oil and natural gas production to reduce
our exposure to fluctuations in the price of oil and natural
gas. Our hedging transactions have to date consisted primarily
of financially-settled swaps and zero-cost collars. We may in
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the future enter into these and other types of hedging
arrangements to reduce our exposure to fluctuations in the
market prices of oil and natural gas. We are required to record
our derivative instruments at fair market value as either assets
or liabilities in our consolidated balance sheet. The fair value
recorded is an estimate based on future commodity prices
available at the time of the calculation. The fair market value
could differ from actual settlements if market prices change,
the other party to the contract defaults on its obligations or
there is a change in the expected differential between the
underlying price in the hedging agreement and actual prices
received.
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Under the above critical accounting policies our net income can
vary significantly from period to period because events or
circumstances which trigger recognition as an expense for
unsuccessful wells or impaired properties cannot be accurately
forecast. In addition, selling prices for our oil and natural
gas fluctuate significantly. Therefore we focus more on cash
flow from operations and on controlling our finding and
development, operating, administration and financing costs.
New
Accounting Policies
In November 2004, the FASB issued Statement of Financial
Accounting Standards No. 151 Inventory Costs, an
amendment of ARB No. 43, Chapter 4
(Statement 151). The amendments made by
Statement 151 clarify that abnormal amounts of idle
facility expense, freight, handling costs, and wasted materials
(spoilage) should be recognized as current-period charges and
require the allocation of fixed production overheads to
inventory based on the normal capacity of the production
facilities. The guidance is effective for inventory costs
incurred during fiscal years beginning after June 15, 2005.
Earlier application is permitted for inventory costs incurred
during fiscal years beginning after November 23, 2004. Our
assessment of Statement 151 is that it is not expected to
have an impact on our financial position, results of operations
or cash flows.
In December 2004, the FASB issued Statement of Financial
Accounting Standards No. 153 Exchanges of
Non-monetary assets an amendment of APB Opinion
No. 29 (Statement 153).
Statement 153 amends Accounting Principles Board
(APB) Opinion 29 to eliminate the exception for
nonmonetary exchanges of similar productive assets and replaces
it with a general exception for exchanges of nonmonetary assets
that do not have commercial substance. A nonmonetary exchange
has commercial substance if the future cash flows of the entity
are expected to change significantly as a result of the
exchange. Statement 153 does not apply to a pooling of
assets in a joint undertaking intended to fund, develop, or
produce oil or natural gas from a particular property or group
of properties. The provisions of Statement 153 shall be
effective for nonmonetary asset exchanges occurring in fiscal
periods beginning after June 15, 2005. Early adoption is
permitted and the provisions of Statement 153 should be
applied prospectively. Our assessment of Statement 153 is
that it is not expected to have an impact on our financial
position, results of operations or cash flows.
In December 2004, the FASB issued Statement of Financial
Accounting Standards
No. 123-Revised
2004, Share-Based Payment,
(Statement 123R). This is a revision of
Statement of Financial Accounting Standards No. 123,
Accounting for Stock-Based Compensation, and
supersedes APB No. 25, Accounting for Stock Issued to
Employees. We currently account for stock-based
compensation under the provisions of APB 25. Under
Statement 123R, we will be required to measure the cost of
employee services received in exchange for stock, based on the
grant-date fair value (with limited exceptions). That cost will
be recognized as expense over the period during which an
employee is required to provide service in exchange for the
award (usually the vesting period). The fair value will be
estimated using an option-pricing model. Excess tax benefits, as
defined in Statement 123R, will be recognized as an
addition to paid-in capital. This will be effective for us as of
the beginning of the first annual reporting period that begins
after June 15, 2005. We are currently in the process
of evaluating the impact of Statement 123R on our financial
statements. Based on options outstanding at the effective date,
we expect the pre-tax impact to be less than $2.5 million
for 2006. this does not contemplate 2006 award grants. Note
(2) of the Notes to Consolidated Financial Statements
illustrates the current effect on net income and earnings per
share if we had applied the fair value recognition provisions of
Statement 123.
In May 2005, the FASB issued Statement of Financial Accounting
Standards No. 154, Accounting Changes and Error
Corrections a replacement of APB Opinion
No. 20 and FASB Statement No. 3,
(Statement 154). Statement 154 provides
guidance on the accounting for and reporting of accounting
changes and error corrections. It
33
establishes, unless impracticable, retrospective application as
the required method for reporting a change in accounting
principle in the absence of explicit transition requirements
specific to Statement 154. The provisions of
Statement 154 shall be effective for accounting changes and
corrections of errors made in fiscal years beginning after
December 15, 2005.
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Item 7A.
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Quantitative
and Qualitative Disclosures about Market Risk
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Interest
Rate Risk
We are exposed to changes in interest rates. Changes in interest
rates affect the interest earned on our cash and cash
equivalents and the interest rate paid on borrowings under our
bank facility. Currently, we do not use interest rate derivative
instruments to manage exposure to interest rate changes. At
December 31, 2005, $85.0 million of our long-term debt
had variable interest rates while the remaining long-term debt
had fixed interest expense. If the market interest rates had
averaged 1% higher during 2005, interest rates for the period on
variable rate debt outstanding during the period would have
increased, and net income before income taxes would have
decreased by approximately $0.7 million based on total
variable debt outstanding during the period. If market interest
rates had averaged 1% lower during 2005, interest expense for
the period on variable rate debt would have decreased, and net
income before income taxes would have increased by approximately
$0.7 million.
Commodity
Price Risk
Our revenues, profitability and future growth depend
substantially on prevailing prices for oil and natural gas.
Prices also affect the amount of cash flow available for capital
expenditures and our ability to borrow and raise additional
capital. The amount we can borrow under the bank facility is
subject to periodic redetermination based in part on changing
expectations of future prices. Lower prices may also reduce the
amount of oil and natural gas that we can economically produce.
We currently sell all of our oil and natural gas production
under price sensitive or market price contracts.
We use derivative instruments to manage commodity price risks
associated with future oil and natural gas production. As of
December 31, 2005, we had no crude oil positions and the
following natural gas contracts in place:
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|
|
Natural Gas Positions
|
|
|
|
|
|
|
Strike Price
|
|
|
Volume (Mmbtu)
|
|
Remaining Contract
Term
|
|
Contract Type
|
|
|
($/Mmbtu)
|
|
|
Daily
|
|
|
Total
|
|
|
01/06 - 12/06
|
|
|
Collar
|
|
|
$
|
5.00/$9.51
|
|
|
|
15,000
|
|
|
|
5,475,000
|
|
01/07 - 12/07
|
|
|
Collar
|
|
|
$
|
5.00/$8.00
|
|
|
|
10,000
|
|
|
|
3,650,000
|
|
Our hedged volume as of December 31, 2005 approximated 8%
of our estimated production from proved reserves through the
balance of the terms of the contracts. Had these contracts been
terminated at December 31, 2005, we estimate the loss would
have been $19.7 million.
We use a sensitivity analysis technique to evaluate the
hypothetical effect that changes in the market value of crude
oil and natural gas may have on fair value of our derivative
instruments. At December 31, 2005 and 2004, the potential
change in the fair value of commodity derivative instruments
assuming a 10% increase in the underlying commodity price was a
$6.7 million and $4.1 million increase in the combined
estimated loss, respectively.
For purposes of calculating the hypothetical change in fair
value, the relevant variables are the type of commodity (crude
oil or natural gas), the commodities futures prices and
volatility of commodity prices. The hypothetical fair value is
calculated by multiplying the difference between the
hypothetical price and the contractual price by the contractual
volumes.
34
GLOSSARY
OF OIL AND NATURAL GAS TERMS
Bbl One stock tank barrel, or 42
U.S. gallons liquid volume, used in this Report in
reference to oil and other liquid hydrocarbons.
Boe Barrels of oil equivalent, with six
thousand cubic feet of natural gas being equivalent to one
barrel of oil.
Bcf One billion cubic feet.
Bcfe One billion cubic feet equivalent, with
one barrel of oil being equivalent to six thousand cubic feet of
natural gas.
completion The installation of permanent
equipment for the production of oil or natural gas, or in the
case of a dry hole, the reporting of abandonment to the
appropriate agency.
Mbbls One thousand barrels of oil or other
liquid hydrocarbons.
Mboe One thousand barrels of oil equivalent.
Mcf One thousand cubic feet of natural gas.
Mmbbls One million barrels of oil or other
liquid hydrocarbons
Mmboe One million barrels of oil equivalent
Mmbtu One million British Thermal Units.
Mmcf One million cubic feet of natural gas.
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.
proved undeveloped reserves Proved reserves
that are expected to be recovered from new wells on undrilled
acreage or from existing wells where a relatively major
expenditure is required for recompletion.
reservoir A porous and permeable underground
formation containing a natural accumulation of producible oil
and/or
natural gas that is confined by impermeable rock or water
barriers and is individual and separate from other reservoirs.
working interest The interest in an oil and
natural gas property (normally a leasehold interest) that gives
the owner the right to drill, produce and conduct operations on
the property and a share of production, subject to all
royalties, overriding royalties and other burdens and to all
costs of exploration, development and operations and all risks
in connection therewith.
EBITDAX Net income (loss) before interest
expense, income taxes, depreciation, depletion and amortization,
exploration expenditures and cumulative effect of change in
accounting principle.
35
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
MANAGEMENTS
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Board of Directors and Stockholders
Energy Partners, Ltd.
Our management is responsible for establishing and maintaining
adequate internal control over financial reporting, as such term
is defined in Exchange Act
Rule 13a-15(f).
Our internal control system was designed to provide reasonable
assurance to the Companys management and Board of
Directors regarding the reliability of financial reporting and
the presentation of financial statements for external purposes
in accordance with U.S. generally accepted accounting
principles. Under the supervision and with the participation of
our management, we conducted an evaluation of the effectiveness
of our internal control over financial reporting based on the
framework in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (COSO).
Based on our evaluation under the COSO framework, our management
concluded that our internal control over financial reporting was
effective as of December 31, 2005. No matter how well
designed, there are inherent limitations in all systems of
internal control. 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 the policies or procedures
may deteriorate. Our managements assessment of the
effectiveness of our internal control over financial reporting
as of December 31, 2005 has been audited by KPMG LLP,
an independent registered public accounting firm, as stated in
their report which is included herein, which expresses an
unqualified opinion on managements assessment and on the
effectiveness of our internal control over financial reporting
as of December 31, 2005.
|
|
|
|
|
|
Richard A. Bachmann
|
|
David R. Looney
|
Chairman and Chief
Executive Officer
|
|
Executive Vice President
and Chief Financial Officer
|
36
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Energy Partners, Ltd.:
We have audited managements assessment, included in the
accompanying Managements Report on Internal Control Over
Financial Reporting, that Energy Partners, Ltd.
maintained effective internal control over financial reporting
as of December 31, 2005, based on criteria established in
Internal Control Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). Energy Partners, Ltd.s management is
responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness
of internal control over financial reporting. Our responsibility
is to express an opinion on managements assessment and an
opinion on the effectiveness of the Companys internal
control over financial reporting based on our audit.
We conducted our audit 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 effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, evaluating
managements assessment, testing and evaluating the design
and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A companys internal control over financial reporting is a
process designed 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 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 the policies or procedures may deteriorate.
In our opinion, managements assessment that Energy
Partners, Ltd. maintained effective internal control over
financial reporting as of December 31, 2005, is fairly
stated, in all material respects, based on criteria established
in Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). Also, in our opinion, Energy Partners, Ltd.
maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2005, based on
criteria established in Internal
Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO).
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Energy Partners Ltd. and
subsidiaries as of December 31, 2005 and 2004, and the
related consolidated statements of operations, changes in
stockholders equity, and cash flows for each of the years
in the three-year period ended December 31, 2005. In
connection with our audits of the consolidated financial
statements, we also have audited the accompanying financial
statement schedule, Valuation and Qualifying
Accounts, for the years ended December 31, 2005,
2004, and 2003. Our report dated February 22, 2006
expressed an unqualified opinion on those consolidated financial
statements and schedule.
New Orleans, Louisiana
February 22, 2006
37
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Energy Partners, Ltd.:
We have audited the accompanying consolidated balance sheets of
Energy Partners, Ltd. and subsidiaries as of December 31,
2005 and 2004, and the related consolidated statement of
operations, changes in stockholders equity, and cash flows
for each of the years in the three-year period ended
December 31, 2005. In connection with our audits of the
consolidated financial statements, we also have audited the
accompanying financial statement schedule, Valuation and
Qualifying Accounts, for the years ended December 31,
2005, 2004, and 2003. These consolidated financial statements
and financial statement schedule are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these consolidated financial statements and financial
statement schedule 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. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Energy Partners, Ltd. and subsidiaries as of
December 31, 2005 and 2004, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2005, in conformity
with U.S. generally accepted accounting principles. Also,
in our opinion, the related financial statement schedule, when
considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly, in all material
respects, the information set forth therein.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of Energy Partners, Ltd.s internal control
over financial reporting as of December 31, 2005, based on
criteria established in Internal
Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO), and our report dated February 22, 2006 expressed an
unqualified opinion on managements assessment of, and the
effective operation of, internal control over financial
reporting.
New Orleans, Louisiana
February 22, 2006
38
ENERGY
PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
December 31,
2005 and 2004
(In thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
6,789
|
|
|
$
|
93,537
|
|
Trade accounts receivable
|
|
|
78,326
|
|
|
|
59,341
|
|
Other receivables
|
|
|
49,303
|
|
|
|
5,600
|
|
Deferred tax assets
|
|
|
5,582
|
|
|
|
1,906
|
|
Prepaid expenses
|
|
|
3,179
|
|
|
|
2,285
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
143,179
|
|
|
|
162,669
|
|
Property and equipment, at cost
under the successful efforts method of accounting for oil and
natural gas properties
|
|
|
1,189,078
|
|
|
|
769,331
|
|
Less accumulated depreciation,
depletion and amortization
|
|
|
(418,347
|
)
|
|
|
(304,997
|
)
|
|
|
|
|
|
|
|
|
|
Net property and equipment
|
|
|
770,731
|
|
|
|
464,334
|
|
Other assets
|
|
|
13,284
|
|
|
|
15,970
|
|
Deferred financing
costs net of accumulated amortization of $5,169
in 2005 and $4,174 in 2004
|
|
|
4,091
|
|
|
|
4,705
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
931,285
|
|
|
$
|
647,678
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
28,810
|
|
|
$
|
21,255
|
|
Accrued expenses
|
|
|
108,087
|
|
|
|
59,387
|
|
Fair value of commodity derivative
instruments
|
|
|
9,875
|
|
|
|
1,749
|
|
Current maturities of long-term debt
|
|
|
109
|
|
|
|
108
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
146,881
|
|
|
|
82,499
|
|
Long-term debt
|
|
|
235,000
|
|
|
|
150,109
|
|
Deferred tax liabilities
|
|
|
87,559
|
|
|
|
53,686
|
|
Asset retirement obligation
|
|
|
56,039
|
|
|
|
45,064
|
|
Other
|
|
|
11,213
|
|
|
|
1,271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
536,692
|
|
|
|
332,629
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $1 par value.
Authorized 1,700,000 shares; issued and outstanding:
2005 no shares;
2004 344,399 shares. Aggregate liquidation
value: 2004 $34,440
|
|
|
|
|
|
|
33,504
|
|
Common stock, par value
$0.01 per share. Authorized 50,000,000 shares; issued
and outstanding: 2005 41,468,093 shares;
2004 36,618,084 shares
|
|
|
415
|
|
|
|
367
|
|
Additional paid-in capital
|
|
|
348,863
|
|
|
|
296,460
|
|
Accumulated other comprehensive
loss net of deferred taxes of $7,098 in 2005
and $630 in 2004
|
|
|
(12,619
|
)
|
|
|
(1,119
|
)
|
Retained earnings
|
|
|
115,366
|
|
|
|
43,215
|
|
Treasury stock, at cost.
2005 3,474,208 shares;
2004 3,480,441 shares
|
|
|
(57,432
|
)
|
|
|
(57,378
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
394,593
|
|
|
|
315,049
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
931,285
|
|
|
$
|
647,678
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
39
ENERGY
PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
Years
Ended December 31, 2005, 2004 and 2003
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
402,005
|
|
|
$
|
294,531
|
|
|
$
|
229,703
|
|
Other
|
|
|
942
|
|
|
|
679
|
|
|
|
484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
402,947
|
|
|
|
295,210
|
|
|
|
230,187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
50,431
|
|
|
|
40,328
|
|
|
|
36,656
|
|
Transportation expense
|
|
|
1,051
|
|
|
|
289
|
|
|
|
37
|
|
Taxes, other than on earnings
|
|
|
10,372
|
|
|
|
9,263
|
|
|
|
7,650
|
|
Exploration expenditures and dry
hole costs
|
|
|
64,937
|
|
|
|
28,999
|
|
|
|
14,561
|
|
Impairment of properties
|
|
|
17,907
|
|
|
|
6,936
|
|
|
|
2,792
|
|
Depreciation, depletion and
amortization
|
|
|
103,649
|
|
|
|
92,353
|
|
|
|
81,927
|
|
General and administrative:
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
|
6,767
|
|
|
|
3,050
|
|
|
|
1,285
|
|
Other general and administrative
|
|
|
36,438
|
|
|
|
27,924
|
|
|
|
26,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
291,552
|
|
|
|
209,142
|
|
|
|
171,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business interruption recovery
|
|
|
20,632
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
132,027
|
|
|
|
86,068
|
|
|
|
58,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
781
|
|
|
|
1,219
|
|
|
|
380
|
|
Interest expense
|
|
|
(18,121
|
)
|
|
|
(14,355
|
)
|
|
|
(10,174
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17,340
|
)
|
|
|
(13,136
|
)
|
|
|
(9,794
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes and
cumulative effect of change in accounting principle
|
|
|
114,687
|
|
|
|
72,932
|
|
|
|
48,766
|
|
Income taxes
|
|
|
(41,592
|
)
|
|
|
(26,516
|
)
|
|
|
(17,784
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative effect
of change in accounting principle
|
|
|
73,095
|
|
|
|
46,416
|
|
|
|
30,982
|
|
Cumulative effect of change in
accounting principle, net of income taxes of $1,276
|
|
|
|
|
|
|
|
|
|
|
2,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
73,095
|
|
|
|
46,416
|
|
|
|
33,250
|
|
Less dividends earned on preferred
stock and accretion of discount and issuanced costs
|
|
|
(944
|
)
|
|
|
(3,399
|
)
|
|
|
(3,545
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common
stockholders
|
|
$
|
72,151
|
|
|
$
|
43,017
|
|
|
$
|
29,705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Before cumulative effect of change
in accounting principle
|
|
$
|
1.94
|
|
|
$
|
1.31
|
|
|
$
|
0.89
|
|
Cumulative effect of change in
accounting principle
|
|
|
|
|
|
|
|
|
|
|
0.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share
|
|
$
|
1.94
|
|
|
$
|
1.31
|
|
|
$
|
0.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Before cumulative effect of change
in accounting principle
|
|
$
|
1.79
|
|
|
$
|
1.20
|
|
|
$
|
0.87
|
|
Cumulative effect of change in
accounting principle
|
|
|
|
|
|
|
|
|
|
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share
|
|
$
|
1.79
|
|
|
$
|
1.20
|
|
|
$
|
0.93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares used
in computing income per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
37,097
|
|
|
|
32,861
|
|
|
|
30,822
|
|
Incremental common shares
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock
|
|
|
544
|
|
|
|
4,033
|
|
|
|
4,310
|
|
Stock options
|
|
|
852
|
|
|
|
638
|
|
|
|
235
|
|
Warrants
|
|
|
1,954
|
|
|
|
1,057
|
|
|
|
208
|
|
Restricted share units
|
|
|
257
|
|
|
|
60
|
|
|
|
|
|
Performance shares
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
40,759
|
|
|
|
38,649
|
|
|
|
35,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
40
ENERGY
PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS
EQUITY
Years Ended December 31, 2005, 2004 and 2003
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Other
|
|
|
Retained
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
Preferred
|
|
|
Treasury
|
|
|
Treasury
|
|
|
Common
|
|
|
Common
|
|
|
Paid-In
|
|
|
Comprehensive
|
|
|
Earnings
|
|
|
|
|
|
|
|
|
|
Stock Shares
|
|
|
Stock
|
|
|
Stock Shares
|
|
|
Stock
|
|
|
Stock Shares
|
|
|
Stock
|
|
|
Capital
|
|
|
Income
|
|
|
(Deficit)
|
|
|
Total
|
|
|
|
|
|
Balance at December 31, 2002
|
|
|
382
|
|
|
$
|
35,359
|
|
|
|
|
|
|
$
|
|
|
|
|
27,550
|
|
|
$
|
276
|
|
|
$
|
187,965
|
|
|
$
|
(2,171
|
)
|
|
$
|
(29,507
|
)
|
|
$
|
191,922
|
|
|
|
|
|
Stock purchase, compensation and
incentive plans, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42
|
|
|
|
|
|
|
|
(758
|
)
|
|
|
|
|
|
|
|
|
|
|
(758
|
)
|
|
|
|
|
Proceeds from public offering, net
of costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,211
|
|
|
|
42
|
|
|
|
37,535
|
|
|
|
|
|
|
|
|
|
|
|
37,577
|
|
|
|
|
|
Exercise of common stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
167
|
|
|
|
2
|
|
|
|
2,148
|
|
|
|
|
|
|
|
|
|
|
|
2,150
|
|
|
|
|
|
Conversion of warrants into common
stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
|
|
|
|
|
|
|
|
102
|
|
|
|
|
|
|
|
|
|
|
|
102
|
|
|
|
|
|
Conversion of preferred stock
|
|
|
(14
|
)
|
|
|
(1,418
|
)
|
|
|
|
|
|
|
|
|
|
|
232
|
|
|
|
3
|
|
|
|
1,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends on preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,592
|
)
|
|
|
(2,592
|
)
|
|
|
|
|
Accretion of discount on preferred
stock
|
|
|
|
|
|
|
953
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(953
|
)
|
|
|
|
|
|
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,250
|
|
|
|
33,250
|
|
|
|
|
|
Fair value of commodity derivative
instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(270
|
)
|
|
|
|
|
|
|
(270
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32,980
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
104
|
|
|
|
|
|
|
|
|
|
|
|
104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2003
|
|
|
368
|
|
|
|
34,894
|
|
|
|
|
|
|
|
|
|
|
|
32,242
|
|
|
|
323
|
|
|
|
228,511
|
|
|
|
(2,441
|
)
|
|
|
198
|
|
|
|
261,485
|
|
|
|
|
|
Stock purchase, compensation and
incentive plans, net
|
|
|
|
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
(22
|
)
|
|
|
|
|
|
|
1,842
|
|
|
|
|
|
|
|
|
|
|
|
1,842
|
|
|
|
|
|
Proceeds from public offering, net
of costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,467
|
|
|
|
35
|
|
|
|
57,343
|
|
|
|
|
|
|
|
|
|
|
|
57,378
|
|
|
|
|
|
Exercise of common stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
453
|
|
|
|
5
|
|
|
|
3,906
|
|
|
|
|
|
|
|
|
|
|
|
3,911
|
|
|
|
|
|
Tax impact of exercise of stock
options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,974
|
|
|
|
|
|
|
|
|
|
|
|
1,974
|
|
|
|
|
|
Equity offering costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(106
|
)
|
|
|
|
|
|
|
|
|
|
|
(106
|
)
|
|
|
|
|
Purchase of shares into treasury
|
|
|
|
|
|
|
|
|
|
|
3,467
|
|
|
|
(57,378
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(57,378
|
)
|
|
|
|
|
Conversion of warrants into common
stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
175
|
|
|
|
1
|
|
|
|
319
|
|
|
|
|
|
|
|
|
|
|
|
320
|
|
|
|
|
|
Conversion of preferred stock
|
|
|
(24
|
)
|
|
|
(2,368
|
)
|
|
|
|
|
|
|
|
|
|
|
277
|
|
|
|
2
|
|
|
|
2,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends on preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,421
|
)
|
|
|
(2,421
|
)
|
|
|
|
|
Accretion of discount on preferred
stock
|
|
|
|
|
|
|
978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(978
|
)
|
|
|
|
|
|
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46,416
|
|
|
|
46,416
|
|
|
|
|
|
Fair value of commodity derivative
instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,322
|
|
|
|
|
|
|
|
1,322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
|
|
|
|
1
|
|
|
|
305
|
|
|
|
|
|
|
|
|
|
|
|
306
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2004
|
|
|
344
|
|
|
|
33,504
|
|
|
|
3,480
|
|
|
|
(57,378
|
)
|
|
|
36,618
|
|
|
|
367
|
|
|
|
296,460
|
|
|
|
(1,119
|
)
|
|
|
43,215
|
|
|
|
315,049
|
|
|
|
|
|
Stock purchase, compensation and
incentive plans, net
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
|
|
(54
|
)
|
|
|
28
|
|
|
|
|
|
|
|
9,720
|
|
|
|
|
|
|
|
|
|
|
|
9,666
|
|
|
|
|
|
Exercise of common stock options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
761
|
|
|
|
8
|
|
|
|
7,966
|
|
|
|
|
|
|
|
|
|
|
|
7,974
|
|
|
|
|
|
Equity offering costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(87
|
)
|
|
|
|
|
|
|
|
|
|
|
(87
|
)
|
|
|
|
|
Conversion of warrants into common
stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
Conversion of preferred stock
|
|
|
(344
|
)
|
|
|
(34,448
|
)
|
|
|
|
|
|
|
|
|
|
|
4,033
|
|
|
|
40
|
|
|
|
34,408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount on preferred
stock
|
|
|
|
|
|
|
944
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(944
|
)
|
|
|
|
|
|
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73,095
|
|
|
|
73,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of commodity derivative
instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,500
|
)
|
|
|
|
|
|
|
(11,500
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61,595
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
377
|
|
|
|
|
|
|
|
|
|
|
|
377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2005
|
|
|
|
|
|
$
|
|
|
|
|
3,474
|
|
|
$
|
(57,432
|
)
|
|
|
41,467
|
|
|
$
|
415
|
|
|
$
|
348,863
|
|
|
$
|
(12,619
|
)
|
|
$
|
115,366
|
|
|
$
|
394,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
41
ENERGY
PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2005, 2004 and 2003
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
73,095
|
|
|
$
|
46,416
|
|
|
$
|
33,250
|
|
Adjustments to reconcile net income
to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in
accounting principle, net of tax
|
|
|
|
|
|
|
|
|
|
|
(2,268
|
)
|
Depreciation, depletion and
amortization
|
|
|
103,649
|
|
|
|
92,353
|
|
|
|
81,927
|
|
Gain on disposal of assets
|
|
|
(777
|
)
|
|
|
(282
|
)
|
|
|
(207
|
)
|
Non cash-based compensation
|
|
|
6,817
|
|
|
|
3,100
|
|
|
|
1,285
|
|
Deferred income taxes
|
|
|
41,242
|
|
|
|
26,365
|
|
|
|
17,708
|
|
Exploration expenditures
|
|
|
69,926
|
|
|
|
26,730
|
|
|
|
12,810
|
|
Amortization of deferred financing
costs
|
|
|
995
|
|
|
|
907
|
|
|
|
902
|
|
Other
|
|
|
966
|
|
|
|
293
|
|
|
|
271
|
|
Changes in operating assets and
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade accounts receivable
|
|
|
(18,985
|
)
|
|
|
(24,931
|
)
|
|
|
(9,490
|
)
|
Other receivables
|
|
|
(43,703
|
)
|
|
|
(5,600
|
)
|
|
|
|
|
Prepaid expenses
|
|
|
(894
|
)
|
|
|
(179
|
)
|
|
|
(239
|
)
|
Other assets
|
|
|
(2,338
|
)
|
|
|
(4,522
|
)
|
|
|
(3,112
|
)
|
Accounts payable and accrued
expenses
|
|
|
40,073
|
|
|
|
6,180
|
|
|
|
4,814
|
|
Other liabilities
|
|
|
(97
|
)
|
|
|
(1,756
|
)
|
|
|
(949
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
269,969
|
|
|
|
165,074
|
|
|
|
136,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows used in investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of business, net of
cash acquired
|
|
|
(863
|
)
|
|
|
(2,166
|
)
|
|
|
(850
|
)
|
Property acquisitions
|
|
|
(193,115
|
)
|
|
|
(6,551
|
)
|
|
|
(6,030
|
)
|
Deposit paid on purchase of
properties
|
|
|
|
|
|
|
(5,000
|
)
|
|
|
|
|
Exploration and development
expenditures
|
|
|
(254,900
|
)
|
|
|
(163,019
|
)
|
|
|
(103,148
|
)
|
Other property and equipment
additions
|
|
|
(1,723
|
)
|
|
|
(562
|
)
|
|
|
(608
|
)
|
Proceeds from sale of oil and gas
assets
|
|
|
1,442
|
|
|
|
585
|
|
|
|
579
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(449,159
|
)
|
|
|
(176,713
|
)
|
|
|
(110,057
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred financing costs
|
|
|
(357
|
)
|
|
|
(721
|
)
|
|
|
(4,746
|
)
|
Repayments of long-term debt
|
|
|
(63,108
|
)
|
|
|
(199
|
)
|
|
|
(118,362
|
)
|
Proceeds from long-term debt
|
|
|
148,000
|
|
|
|
|
|
|
|
15,000
|
|
Proceeds from senior notes offering
|
|
|
|
|
|
|
|
|
|
|
150,000
|
|
Proceeds from public stock
offering, net of commissions
|
|
|
|
|
|
|
57,378
|
|
|
|
38,000
|
|
Purchase of shares into treasury
|
|
|
|
|
|
|
(57,378
|
)
|
|
|
|
|
Equity offering costs
|
|
|
(87
|
)
|
|
|
(106
|
)
|
|
|
(479
|
)
|
Payment of preferred stock dividends
|
|
|
|
|
|
|
(2,421
|
)
|
|
|
(2,592
|
)
|
Exercise of stock options and
warrants
|
|
|
7,994
|
|
|
|
4,231
|
|
|
|
810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
92,442
|
|
|
|
784
|
|
|
|
77,631
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and
cash equivalents
|
|
|
(86,748
|
)
|
|
|
(10,855
|
)
|
|
|
104,276
|
|
Cash and cash equivalents at
beginning of year
|
|
|
93,537
|
|
|
|
104,392
|
|
|
|
116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of
year
|
|
$
|
6,789
|
|
|
$
|
93,537
|
|
|
$
|
104,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
42
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
Energy Partners, Ltd. was incorporated on January 29, 1998
and is an independent oil and natural gas exploration and
production company with operations concentrated in the shallow
to moderate depth waters of the Gulf of Mexico Shelf and the
Gulf Coast onshore regions and, as a result of an acquisition of
undeveloped acreage in early 2006, the deepwater Gulf of Mexico.
The Companys future financial condition and results of
operations will depend primarily upon prices received for its
oil and natural gas production and the costs of finding,
acquiring, developing and producing reserves.
|
|
(2)
|
Summary
of Significant Accounting Policies
|
(a) Basis
of Presentation
The consolidated financial statements include the accounts of
Energy Partners, Ltd., and its wholly-owned subsidiaries
(collectively, the Company). All significant intercompany
accounts and transactions are eliminated in consolidation. The
Companys interests in oil and natural gas exploration and
production ventures and partnerships are proportionately
consolidated.
(b) Property
and Equipment
The Company uses the successful efforts method of accounting for
oil and natural gas producing activities. Costs to acquire
mineral interests in oil and natural gas properties, to drill
and equip exploratory wells that find proved reserves, and to
drill and equip development wells are capitalized. Exploratory
drilling costs are initially capitalized, but charged to expense
if and when the well is determined not to have found reserves in
commercial quantities. Effective July 1, 2005, the Company
adopted Financial Accounting Standards Board Staff Position
FAS 19-1,
Accounting for Suspended Well Costs (FSP 19-1). FSP
19-1 amended Statement of Financial Accounting Standards
No. 19, Financial Accounting and Reporting by Oil and
Gas Producing Companies (Statement 19), to permit the
continued capitalization of exploratory well costs beyond one
year if (a) the well found a sufficient quantity of
reserves to justify its completion as a producing well and
(b) the entity is making sufficient progress assessing the
reserves and the economic and operating viability of the
project. During the year ended December 31, 2005, the
Company adopted the requirements of FSP 19-1. During the
Companys limited operating history it has not, and does
not currently, drill in areas that require major capital
expenditures before production can begin. Therefore, upon
adoption, the Company evaluated all existing capitalized well
costs under the provisions of FSP 19-1 and determined there was
no impact to the Companys consolidated financial
statements. Geological and geophysical costs are charged to
expense as incurred.
Leasehold acquisition costs are capitalized. If proved reserves
are found on an undeveloped property, leasehold costs are
transferred to proved properties. Costs of undeveloped leases
are expensed over the life of the leases. Capitalized costs of
producing oil and natural gas properties are depreciated and
depleted by the
units-of-production
method.
The Company assesses the impairment of capitalized costs of
proved oil and natural gas properties when circumstances
indicate that the carrying value may not be recoverable. The
need to test a property for impairment can be based on several
factors, including a significant reduction in sales prices for
oil and/or natural gas, unfavorable adjustments to reserve
volumes, or other changes to contracts, environmental
regulations or tax laws. The calculation is performed on a
field-by-field
basis, utilizing its current estimate of future revenues and
operating expenses. In the event net undiscounted cash flow is
less than the carrying value, an impairment loss is recorded
based on the present value of expected future net cash flows
over the economic lives of the reserves.
On the sale or retirement of a complete unit of a proved
property, the cost and related accumulated depletion,
depreciation and amortization are eliminated from the property
accounts, and the resulting gain or loss is recognized.
43
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(c) Asset
Retirement Obligation
The Company accounts for its Asset Retirement Obligations in
accordance with Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations
(Statement 143). Statement 143 requires companies to
record the present value of obligations associated with the
retirement of tangible long-lived assets in the period in which
it is incurred. The liability is capitalized as part of the
related long-lived assets carrying amount. Over time,
accretion of the liability is recognized as an operating expense
and the capitalized cost is depreciated over the expected useful
life of the related asset. The Companys asset retirement
obligations relate primarily to the plugging, dismantlement,
removal, site reclamation and similar activities of its oil and
gas properties.
(d) Income
Taxes
The Company accounts for income taxes under the asset and
liability method, which requires that deferred tax assets and
liabilities are recognized for the future tax consequences
attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their
respective tax bases. 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 are
expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in the tax rates is
recognized in income in the period that includes the enactment
date.
(e) Deferred
Financing Costs
Costs incurred to obtain debt financing are deferred and are
amortized as additional interest expense over the maturity
period of the related debt.
(f) Earnings
Per Share
Basic earnings per share is computed by dividing income
available to common stockholders by the weighted average number
of common shares outstanding during the period. Diluted earnings
per share is computed in the same manner as basic earnings per
share except that the denominator is increased to include the
number of additional common shares that could have been
outstanding assuming the conversion of convertible preferred
stock shares, the exercise of stock option awards and warrants
and the potential shares associated with restricted share units
and performance shares that would have a dilutive effect on
earnings per share.
(g) Revenue
Recognition
The Company uses the entitlement method for recording natural
gas sales revenue. Under this method of accounting, revenue is
recorded based on the Companys net working interest in
field production. Deliveries of natural gas in excess of the
Companys working interest are recorded as liabilities and
under-deliveries are recorded as receivables. The Company had
natural gas imbalance receivables of $0.2 million and
$1.4 million at December 31, 2005 and 2004,
respectively and had liabilities of $0.5 million at
December 31, 2005 and 2004.
(h) Statements
of Cash Flows
For purposes of the statements of cash flows, highly-liquid
investments with original maturities of three months or less are
considered cash equivalents. At December 31, 2005 and 2004,
interest-bearing cash equivalents were approximately
$25.8 million and $99.9 million, respectively.
Expenditures for exploratory dry holes incurred are excluded
from operating cash flows and included in investing activities.
(i) Hedging
Activities
The Company uses derivative instruments to manage commodity
price risks associated with future crude oil and natural gas
production, but does not use them for speculative purposes. The
Companys commodity price hedging program has utilized
financially-settled zero-cost collar contracts to establish
floor and ceiling prices on anticipated future crude oil and
natural gas production and oil and natural gas swaps to fix the
price of anticipated
44
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
future crude oil and natural gas production. Accounting and
reporting standards require that derivative instruments,
including certain derivative instruments embedded in other
contracts, be recorded at fair market value and included as
either assets or liabilities in the balance sheet. The
accounting for changes in fair value depends on the intended use
of the derivative and the resulting designation, which is
established at the inception of the derivative. Special
accounting for qualifying hedges allows a derivatives
gains and losses to offset related results on the hedged item in
the statement of operations. For derivative instruments
designated as cash-flow hedges, changes in fair value, to the
extent the hedge is effective, will be recognized in other
comprehensive income (a component of stockholders equity)
until the forecasted transaction is settled, when the resulting
gains and losses will be recorded in oil and natural gas
revenue. Hedge ineffectiveness is measured at least quarterly
based on the changes in fair value between the derivative
contract and the hedged item. Any change in fair value resulting
from ineffectiveness, will be charged currently to other revenue.
(j) Stock-Based
Compensation
The Company has two stock award plans, the Amended and Restated
2000 Long Term Stock Incentive Plan and the Amended and Restated
2000 Stock Incentive Plan for Non-Employee Directors (the
Plans). The Company accounts for its stock-based compensation in
accordance with Accounting Principles Boards Opinion
No. 25, Accounting For Stock Issued To
Employees (Opinion No. 25). Statement of Financial
Accounting Standards No. 123 (Statement 123),
Accounting For Stock-Based Compensation and
Statement of Financial Accounting Standards No. 148,
Accounting for Stock-Based
Compensation Transition and Disclosure,
(Statement 148) permit the continued use of the intrinsic
value-based method prescribed by Opinion No. 25, but
require additional disclosures, including pro-forma calculations
of earnings and net earnings per share as if the fair value
method of accounting prescribed by Statement 123 had been
applied. Effective January 1, 2006 the Company will adopt
the provisions of Statement of Financial Accounting Standards
No. 123-Revised
2004, Share-Based Payment,
(Statement 123R). If compensation expense for
the Plans had been determined using the fair-value method in
Statement 123, the Companys net income (loss) and
earnings (loss) per share would have been as shown in the pro
forma amounts below (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Net income available to common
stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
72,151
|
|
|
$
|
43,017
|
|
|
$
|
29,705
|
|
Less: Pro forma stock based
employee compensation cost, after tax
|
|
|
1,140
|
|
|
|
2,179
|
|
|
|
1,002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma
|
|
$
|
71,011
|
|
|
$
|
40,838
|
|
|
$
|
28,703
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
1.94
|
|
|
$
|
1.31
|
|
|
$
|
0.96
|
|
Pro forma
|
|
$
|
1.91
|
|
|
$
|
1.24
|
|
|
$
|
0.93
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
1.79
|
|
|
$
|
1.20
|
|
|
$
|
0.93
|
|
Pro forma
|
|
$
|
1.77
|
|
|
$
|
1.14
|
|
|
$
|
0.91
|
|
Average fair value of grants
during the year
|
|
$
|
6.86
|
|
|
$
|
6.19
|
|
|
$
|
4.67
|
|
Black-Scholes option pricing model
assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk free interest rate
|
|
|
4.5
|
%
|
|
|
4.5
|
%
|
|
|
4.5
|
%
|
Expected life (years)
|
|
|
5
|
|
|
|
5
|
|
|
|
5
|
|
Volatility
|
|
|
42.0 to 43.0
|
%
|
|
|
43.0 to 45.0
|
%
|
|
|
47.0 to 49.0
|
%
|
Dividend yield
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based employee compensation
cost, net of tax, included in net income as reported
|
|
$
|
468
|
|
|
$
|
340
|
|
|
$
|
28
|
|
45
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(k) Allowance
for Doubtful Accounts
The Company routinely assesses the recoverability of all
material trade and other receivables to determine their
collectibility. Many of the Companys receivables are from
joint interest owners on properties of which the Company is the
operator. Thus, the Company may have the ability to withhold
future revenue disbursements to recover any non-payment of joint
interest billings. The Companys crude oil and natural gas
receivables are typically collected within two months. The
Company accrues an allowance on a receivable when, based on the
judgment of management, it is probable that a receivable will
not be collected and the amount of any allowance may be
reasonably estimated. As of December 31, 2005 and 2004, the
Company had no allowance for doubtful accounts balances.
(l) Use
of Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities at
the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual
results could differ from those estimates. Certain accounting
policies involve judgments and uncertainties to such an extent
that there is reasonable likelihood that materially different
amounts could have been reported under different conditions, or
if different assumptions had been used. The Company evaluates
its estimates and assumptions on a regular basis. The Company
uses historical experience and various other assumptions that
are believed to be reasonable under the circumstances to form
the basis for making judgments about carrying values of assets
and liabilities that are not readily apparent fromother sources.
The Companys actual results may differ from these
estimates and assumptions used in preparation of its financial
statements. Significant estimates with regard to these financial
statements and related unaudited disclosures include the
estimate of proved oil and natural gas reserve quantities and
the related present value of estimated future net cash flows
there-from disclosed in note 20.
(m) Reclassifications
Certain reclassifications have been made to the prior period
financial statements in order to conform to the classification
adopted for reporting in fiscal 2005.
On April 16, 2003, the Company completed the public
offering of approximately 6.8 million shares of its common
stock (the Equity Offering), which was priced at $9.50 per
share. The Equity Offering included 4.2 million shares
offered by the Company, 1.7 million shares offered by the
Companys then principal stockholders, Evercore Capital
Partners L.P. and certain of its affiliates (Evercore), and
0.9 million shares offered by Energy Income Fund, L.P.
(EIF). In addition, the underwriters exercised their option to
purchase 1.0 million additional shares to cover
over-allotments, the proceeds from which went to selling
shareholders and not to the Company. After payment of
underwriting discounts and commissions, the offering generated
net proceeds to the Company of approximately $38.0 million.
After expenses of approximately $0.5 million, the proceeds
were used to repay a portion of outstanding borrowings under the
Companys bank credit facility.
On July 16, 2004 the Company filed a universal shelf
registration statement (the Registration Statement) which allows
the Company to issue an aggregate of $300 million in common
stock, preferred stock, senior debt and subordinated debt in one
or more separate offerings with the size, price and terms to be
determined at the time of the sale. On November 10, 2004
the Company sold approximately 3.5 million shares of its
common stock to the public pursuant to the Registration
Statement. Concurrent with this offering, the Company entered
into a stock purchase agreement with EIF pursuant to which it
purchased an equal number of shares of common stock owned by EIF
at a price per share equal to the proceeds per share received in
the offering, before expenses. The Company did not retain any of
the proceeds from this offering and the stock has been recorded
as treasury stock on the consolidated balance sheet at cost. The
Company restored the Registration Statement to $300 million
in May 2005. The Company has no
46
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
immediate plans to enter into any additional transactions under
the Registration Statement, but plans to use the proceeds for
general corporate purposes, which may include debt repayment,
acquisitions, expansion and working capital.
|
|
(4)
|
Supplemental
Cash Flow Information
|
The following is supplemental cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
|
Interest paid
|
|
$
|
18,121
|
|
|
$
|
14,323
|
|
|
$
|
5,877
|
|
Income taxes paid, net of refunds
|
|
$
|
350
|
|
|
$
|
151
|
|
|
$
|
76
|
|
The following is supplemental disclosure of non-cash financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In thousands)
|
|
|
Accretion of preferred stock
|
|
$
|
944
|
|
|
$
|
978
|
|
|
$
|
953
|
|
Conversion of preferred stock
|
|
$
|
34,448
|
|
|
$
|
2,368
|
|
|
$
|
1,418
|
|
Restricted share units
|
|
$
|
805
|
|
|
$
|
|
|
|
$
|
|
|
Exercise of options
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,442
|
|
In connection with an acquisition in 2002, the Company issued
among other things, 383,707 shares of $38.4 million
liquidation preference of newly authorized and issued
Series D Exchangeable Convertible Preferred Stock
(Series D Preferred Stock) with an issue date fair value of
$34.7 million discounted to give effect to the increasing
dividend rate from 7% in June 2002 to 10% in June 2007. On
February 28, 2005, the Company gave notice of the
redemption of all of the Series D Preferred Stock issued in
connection with the acquisition that remained outstanding on the
redemption date of March 21, 2005. The redemption price was
$100 per share plus accrued and unpaid dividends to the
redemption date. Holders of record had the right to convert
their shares into shares of common stock through the close of
business on March 18, 2005. All holders exercised their
right to convert their shares and there were no preferred shares
outstanding as of the close of business on March 18, 2005.
The Company also issued $38.4 million of 11% Senior
Subordinated Notes (the Notes), due 2009 (immediately callable
at par) which were redeemed in August 2003 utilizing proceeds
from the 8.75% Senior Notes due 2010 issuance (see
note 9) and warrants to purchase four million shares
of the Companys common stock in the same acquisition. Of
the warrants, one million had a strike price of $9.00 and three
million had a strike price of $11.00 per share. The
warrants became exercisable on January 15, 2003 and expire
on January 15, 2007. At December 31, 2005 there were
754,981 warrants outstanding with a strike price of
$9.00 per share and 2,661,457 warrants outstanding
with a strike price of $11.00 per share.
In addition, former preferred stockholders of the acquired
company have the right to receive contingent consideration based
upon a percentage of the amount by which the before tax net
present value of proved reserves related, in general, to
exploratory prospect acreage held by the acquired company as of
the closing date of the acquisition (the Ring-Fenced Properties)
exceeds the net present value discounted at 30%. The potential
consideration is determined annually from March 3, 2003
until March 1, 2007. The cumulative percentage remitted to
the participants was 20% for the March 3, 2003, 30% for the
March 1, 2004 and 35% for the March 1, 2005
determination dates and is 40% for the March 1, 2006 and
50% for the March 1, 2007 determination dates. The
contingent consideration, if any, may be paid in the
Companys common stock or cash at the Companys option
(with a minimum of 20% in cash) and in no event will exceed a
value of $50 million. In 2005, 2004 and 2003, the Company
capitalized, as additional purchase price, and paid additional
consideration in cash, of $0.9 million,
47
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
$2.2 million and $0.9 million related to the
March 1, 2005 and 2004 and the March 3, 2003
contingent consideration determination dates, respectively. The
Company does not expect the 2006 contingent consideration
payment to exceed $1.0 million. Due to the uncertainty inherent
in estimating the value of future contingent consideration which
includes annual valuations based upon, among other things,
drilling results from the date of the prior revaluation, and
development, operating and abandonment costs and production
revenues (actual historical and future projected, as
contractually defined, as of each revaluation date) for the
Ring-Fenced Properties, total final consideration will not be
determined until March 1, 2007. All additional contingent
consideration will be capitalized as additional purchase price.
On January 20, 2005, the Company closed an acquisition of
properties and reserves in south Louisiana for approximately
$149.6 million in cash, after adjustments for the exercise
of preferential rights by third parties and closing adjustments.
The entire purchase price was allocated to property and
equipment. The terms of the acquisition did not contain any
contingent consideration, options or future commitments. The
acquisition was composed of nine fields, four of which were
producing at the time of the closing through 14 wells, with
estimated acquisition date proved reserves of 51.2 billion
cubic feet equivalent. Also included were interests in 22
exploratory prospects. The transaction expands the
Companys exploration opportunities in its expanded focus
area and further reduces the concentration of its reserves and
production. Upon the signing of the purchase agreement in
December 2004, the Company paid a $5.0 million deposit
toward the purchase price which was recorded as other assets in
the consolidated balance sheet at December 31, 2004.
Concurrent with the closing, the borrowing base under the
Companys bank credit facility was increased to
$150 million, of which $60 million was drawn to fund
the acquisition. In connection with the acquisition, the Company
has also entered into a two-year agreement with the seller of
the properties that defines an area of mutual interest (AMI)
encompassing over one million acres. The Company intends to
continue to explore and develop oil and natural gas reserves in
the AMI over that two year period jointly with the seller. The
proved reserves, prospects and AMI are in the southern portions
of Terrebone, Lafourche and Jefferson Parishes in Louisiana.
The following unaudited pro forma information for the year ended
December 31, 2004 presents a summary of the consolidated
results of operations as if the acquisition occurred on
January 1, 2004 with pro forma adjustments to give effect
to depreciation, depletion and amortization, interest expense
and related income tax effects.
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2004
|
|
|
|
(Unaudited, in thousands,
|
|
|
|
except per share
amounts)
|
|
|
Pro forma:
|
|
|
|
|
Revenue
|
|
$
|
315,413
|
|
Income from operations
|
|
|
94,487
|
|
Net income
|
|
|
51,241
|
|
Basic income per common share
|
|
$
|
1.46
|
|
Diluted income per common share
|
|
$
|
1.33
|
|
On March 8, 2005, the Company closed the acquisition of the
remaining 50% gross working interest in South Timbalier 26
above approximately 13,000 feet subsea that it did not
already own for approximately $19.6 million after closing
adjustments from the effective date of December 1, 2004.
The entire purchase price was allocated to property and
equipment. The terms of the acquisition did not contain any
contingent consideration, options or future commitments. As a
result of the acquisition, the Company now owns a 100% gross
working interest in the producing horizons in this field. The
acquisition expands the Companys interest in its core
Greater Bay Marchand area and gives the Company additional
flexibility in undertaking the future development of the South
Timbalier 26 field.
The Company has included the results of operations from the
acquisitions discussed above from their respective closing
dates. The Company has experienced substantial revenue and
production growth as a result of
48
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
these acquisitions. For the foregoing reasons these acquisitions
will affect the comparability of the Companys historical
results of operations with future periods.
|
|
(6)
|
Property
and Equipment
|
The following is a summary of property and equipment at
December 31, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Proved oil and natural gas
properties
|
|
$
|
1,128,498
|
|
|
$
|
750,850
|
|
Unproved oil and natural gas
properties
|
|
|
53,676
|
|
|
|
13,275
|
|
Other
|
|
|
6,904
|
|
|
|
5,206
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,189,078
|
|
|
$
|
769,331
|
|
|
|
|
|
|
|
|
|
|
We analyze proved properties for impairment based on the
reserves as determined by our independent reserve engineers. We
recognized impairment expense of $17.9 million,
$6.9 million and $2.8 million in the years ending
December 31, 2005, 2004 and 2003, respectively. The
impairment expense in 2005 was related to full impairments at
six fields which would need significant capital to extend their
economic lives and the Company decided to deploy the capital to
projects with more potential and therefore impaired the assets.
The Company also had two fields with partial impairments due to
insufficient cash flow from reserves. The impairment expense in
2004 was related to our East Cameron 378 field and in 2003 was
related to our Ship Shoal 133 and West Cameron 149 fields.
Substantially all of the Companys oil and natural gas
properties serve as collateral for its bank facility.
On August 29, 2005 Hurricane Katrina made landfall in the
United States south of New Orleans causing catastrophic damage
throughout portions of the Gulf of Mexico and to portions of
Alabama, Louisiana and Mississippi, including New Orleans. As a
result of the devastating effects of the storm on New Orleans
and surrounding areas, the Company announced on August 30
that it had elected to establish temporary headquarters at its
Houston, Texas office. A satellite office was also established
in Baton Rouge, Louisiana. General and administrative costs
associated with moving offices as well as relocation allowances
paid to employees approximated $1.6 million during 2005 and
are recorded in other general and administrative expenses in the
consolidated statement of operations.
On September 24, 2005 Hurricane Rita made landfall in the
United States on the Texas/Louisiana border. This hurricane
caused extensive damage throughout portions of the Gulf of
Mexico region particularly to third party infrastructure such as
pipelines and processing plants.
As a result of these two major hurricanes and three other
hurricanes that traversed the Gulf of Mexico and adjacent land
areas in July 2005, nearly all of the Companys production
was shut in at one time or another during the third quarter of
2005 and a portion of that production had not yet been restored
at the end of the fourth quarter of 2005. The Company is
continuing to work to bring production back to pre-storm levels,
but is subject to constraints due to damage to third party
infrastructure. In 2005 the Company maintained business
interruption insurance on its significant properties, including
its East Bay field. Recovery of lost revenue for the East Bay
field and two other fields began accruing in October and
recovery on a fourth field began accruing in November. Recovery
ceased for three of the fields in 2005, but will continue,
including situations where production is shut-in due to third
party constraints, until production is restored to pre-storm
levels on the other field, subject to policy limits that the
Company does not expect at this time to be reached. Through
December 31, 2005, the total business interruption claim on
these fields was $20.6 million, of which $20.4 million
had not been collected and is recorded in other receivables on
the Companys consolidated balance sheet. As of
February 22, 2006 an additional $7.3 million had been
collected. Total offshore repair costs expended as of
December 31, 2005 for Hurricanes Katrina, Rita and Cindy
were $27.3 million. Of this amount $2.7 million
represents uninsured amounts that are reflected in lease
49
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
operating expenses and the remaining $24.6 million is
recorded in other receivables on the Companys consolidated
balance sheet.
|
|
(8)
|
Asset
Retirement Obligation
|
In 2001, the FASB issued Statement 143. Statement 143
requires entities to record the fair value of a liability for an
asset retirement obligation in the period in which it is
incurred, a corresponding increase in the carrying amount of the
related long-lived asset and was effective for fiscal years
beginning after June 15, 2002. The Company adopted
Statement 143 effective January 1, 2003, using the
cumulative effect approach to recognize transition amounts for
asset retirement obligations, asset retirement costs and
accumulated depreciation. The Company previously recorded
estimated costs of dismantlement, removal, site restoration and
similar activities as part of its depreciation, depletion and
amortization for oil and natural gas properties and recorded a
separate liability for such amounts in other liabilities. The
effect of adopting Statement 143 on the Companys 2003
results of operations and financial condition included a net
increase in long-term liabilities of $14.2 million; an
increase in net property, plant and equipment of
$17.8 million; a cumulative effect of adoption income of
$2.3 million, net of deferred income taxes of
$1.3 million.
The following table reconciles the beginning and ending
aggregate recorded amount of the asset retirement obligation for
the year ended December 31, 2005 (in thousands):
|
|
|
|
|
|
|
Asset
|
|
|
|
Retirement
|
|
|
|
Obligation
|
|
|
December 31, 2004
|
|
$
|
45,064
|
|
Accretion expense
|
|
|
4,125
|
|
Liabilities incurred
|
|
|
7,151
|
|
Liabilities settled
|
|
|
(54
|
)
|
Revisions in estimated cash flows
|
|
|
(247
|
)
|
|
|
|
|
|
December 31, 2005
|
|
$
|
56,039
|
|
|
|
|
|
|
On August 5, 2003, the Company issued $150 million of
8.75% Senior Notes due 2010 (the Senior Notes) in a
Rule 144A private offering (the Debt Offering) which allows
unregistered transactions with qualified institutional buyers.
In October 2003, the Company consummated an exchange offer
pursuant to which it exchanged registered Senior Notes (the
Registered Senior Notes) having substantially identical terms as
the Senior Notes for the privately placed Senior Notes. After
discounts and commissions and all offering expenses, the Company
received $145.3 million, which was used to redeem all of
the outstanding 11% Senior Subordinated Notes Due 2009 (see
note 6) and to repay substantially all of the
borrowings outstanding under the Companys bank credit
facility. In January 2005, the remainder of the net proceeds
were used to purchase properties in south Louisiana as discussed
in note 5.
The Registered Senior Notes mature on August 1, 2010 with
interest payable each February 1 and August 1, commencing
February 1, 2004. The Company may redeem the notes at its
option, in whole or in part, at any time on or after
August 1, 2007 at a price equal to 100% of the principal
amount plus accrued and unpaid interest, if any, plus a
specified premium which decreases yearly from 4.375% in 2007 to
0% in 2009 and thereafter. In addition, at any time prior to
August 1, 2006, the Company may redeem up to a maximum of
35% of the aggregate principal amount with the net proceeds of
certain equity offerings at a price equal to 108.75% of the
principal amount, plus accrued and unpaid interest. The notes
are unsecured obligations and rank equal in right of payment to
all existing and future senior debt, including the bank credit
facility, and will rank senior or equal in right of payment to
all existing and future subordinated indebtedness. The indenture
relating to the Registered Senior Notes contains certain
restrictions on the Companys ability to incur additional
debt, pay dividends on its common stock, make investments,
create
50
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
liens on its assets, engage in transactions with its affiliates,
transfer or sell assets and consolidate or merge substantially
all of its assets. The Registered Senior Notes are not subject
to any sinking fund requirements.
On August 3, 2004 the Company amended and extended to
August 3, 2008 its bank credit facility. The borrowing base
was increased to $150 million at the time of our purchase
of south Louisiana properties and reserves in January 2005 (see
note 5). The borrowing base is subject to redetermination
semiannually based on the proved reserves of the oil and natural
gas properties that serve as collateral for the bank credit
facility as set out in the reserve report delivered to the banks
each April 1 and October 1. The bank credit facility
permits both prime rate based borrowings and London interbank
offered rate (LIBOR) borrowings plus a floating spread. The
spread will float up or down based on the Companys
utilization of the bank credit facility. The spread can range
from 1.25% to 2.00% above LIBOR and 0% to 0.75% above prime. The
borrowing base under the bank credit facility is secured by
substantially all of the assets of the Company. In addition, the
Company pays an annual fee on the unused portion of the bank
credit facility ranging between 0.375% to 0.5% based on
utilization. The bank credit facility contains customary events
of default and various financial covenants, which require the
Company to: (i) maintain a minimum current ratio, as
defined in the bank credit facility, of 1.0 and
(ii) maintain a minimum EBITDAX to interest ratio, as
defined in the bank credit facility, of 3.5 times. The Company
was in compliance with its bank facility covenants as of
December 31, 2005.
Total long-term debt outstanding at December 31, 2005 and
2004 was as follows:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Senior Notes, annual interest of
8.75%, payable August 1, 2010
|
|
$
|
150,000
|
|
|
$
|
150,000
|
|
Bank facility, interest rate based
on LIBOR borrowing rates plus a floating spread payable
August 3, 2008, with weighted average interest on
December 31, 2005 of 6.07%
|
|
|
85,000
|
|
|
|
|
|
Financing note payable, annual
interest of 7.99%, equal monthly payments, maturing February 2006
|
|
|
109
|
|
|
|
217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
235,109
|
|
|
|
150,217
|
|
Less: Current maturities
|
|
|
109
|
|
|
|
108
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
235,000
|
|
|
$
|
150,109
|
|
|
|
|
|
|
|
|
|
|
Maturities of long-term debt as of December 31, 2005 were
as follows (in thousands):
|
|
|
|
|
2006
|
|
$
|
109
|
|
2007
|
|
|
|
|
2008
|
|
|
85,000
|
|
2009
|
|
|
|
|
2010
|
|
|
150,000
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
$
|
235,109
|
|
|
|
|
|
|
|
|
(10)
|
Significant
Customers
|
The Company had oil and natural gas sales to four customers
accounting for 18%, 16%, 15% and 10%, respectively, of total oil
and natural gas revenues, excluding the effects of hedging
activities, for the year ended December 31, 2005. The
Company had oil and natural gas sales to three customers
accounting for approximately 22%, 14% and 13%, respectively, of
total oil and natural gas revenues, excluding the effects of
hedging activities, for the year ended December 31, 2004.
The Company had oil and natural gas sales to two customers
accounting for approximately 30% and 10%, respectively, of total
oil and natural gas revenues, excluding the effects of hedging
activities, for the year ended December 31, 2003.
51
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company uses financially-settled crude oil and natural gas
swaps and zero-cost collars. The Company enters into hedging
transactions with major financial institutions to reduce
exposure to fluctuations in the price of oil and natural gas.
Any gains or losses resulting from the change in fair value from
hedging transactions that are determined to be ineffective are
recorded in other revenue, whereas gains and losses from the
settlement of hedging contracts are recorded in oil and natural
gas revenue. Crude oil hedges are settled based on the average
of the reported settlement prices for West Texas Intermediate
crude on the NYMEX for each month. Natural gas hedges are
settled based on the average of the last three days of trading
of the NYMEX Henry Hub natural gas contract for each month.
With a financially-settled swap, the counterparty is required to
make a payment to the Company if the settlement price for any
settlement period is below the hedged price for the transaction,
and the Company is required to make a payment to the
counterparty if the settlement price for any settlement period
is above the hedged price for the transaction. With a zero-cost
collar, the counterparty is required to make a payment to the
Company if the settlement price for any settlement period is
below the floor price of the collar, and the Company is required
to make a payment to the counterparty if the settlement price
for any settlement period is above the cap price for the collar.
The Company had no crude oil contracts and the following natural
gas hedging contracts as of December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Positions
|
|
|
|
|
|
|
Strike Price
|
|
|
Volume (Mmbtu)
|
|
Remaining Contract
Term
|
|
Contract Type
|
|
|
($/Mmbtu)
|
|
|
Daily
|
|
|
Total
|
|
|
01/06 - 12/06
|
|
|
Collar
|
|
|
$
|
5.00/$9.51
|
|
|
|
15,000
|
|
|
|
5,475,000
|
|
01/07 - 12/07
|
|
|
Collar
|
|
|
$
|
5.00/$8.00
|
|
|
|
10,000
|
|
|
|
3,650,000
|
|
For the years ended December 31, 2005, 2004 and 2003,
settlements of hedging contracts reduced oil and gas revenues by
$17.0 million, $15.2 million and $11.5 million,
respectively. The Company has not discontinued hedge accounting
treatment in the years presented, and therefore, has not
reclassified any gains or losses into earnings as a result.
The following table reconciles the change in accumulated other
comprehensive income for the years ended December 31, 2005
and 2004:
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2005
|
|
|
|
(In thousands)
|
|
|
Accumulated other comprehensive
loss as of December 31, 2004 net of taxes
of $630
|
|
|
|
|
|
$
|
(1,119
|
)
|
Net income
|
|
$
|
73,095
|
|
|
|
|
|
Other comprehensive
income net of tax
|
|
|
|
|
|
|
|
|
Hedging activities
|
|
|
|
|
|
|
|
|
Reclassification adjustments for
settled contracts net of taxes of $(6,126)
|
|
|
10,890
|
|
|
|
|
|
Changes in fair value of
outstanding hedging positions net of taxes of
$12,595
|
|
|
(22,390
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income
|
|
|
(11,500
|
)
|
|
|
(11,500
|
)
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
61,595
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive
loss as of December 31, 2005 net of taxes
of $7,098
|
|
|
|
|
|
$
|
(12,619
|
)
|
|
|
|
|
|
|
|
|
|
52
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2004
|
|
|
|
(In thousands)
|
|
|
Accumulated other comprehensive
loss as of December 31, 2003 net of taxes
of $1,373
|
|
|
|
|
|
$
|
(2,441
|
)
|
Net income
|
|
$
|
46,416
|
|
|
|
|
|
Other comprehensive
loss net of tax
|
|
|
|
|
|
|
|
|
Hedging activities
|
|
|
|
|
|
|
|
|
Reclassification adjustments for
settled contracts net of taxes of $(5,475)
|
|
|
9,734
|
|
|
|
|
|
Changes in fair value of
outstanding hedging positions net of taxes of
$4,732
|
|
|
(8,412
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive loss
|
|
|
1,322
|
|
|
|
1,322
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
47,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive
loss as of December 31, 2004 net of taxes
of $630
|
|
|
|
|
|
$
|
(1,119
|
)
|
|
|
|
|
|
|
|
|
|
Based upon current prices, the Company expects to transfer
approximately $9.9 million of pretax net deferred losses in
accumulated other comprehensive income as of December 31,
2005 to earnings during 2006 when the forecasted transactions
actually occur.
|
|
(12)
|
Fair
Value of Financial Instruments
|
The following table presents the carrying amounts and estimated
fair values of financial instruments held by the Company at
December 31, 2005 and 2004. The fair value of a financial
instrument is the amount at which the instrument could be
exchanged in a current transaction between willing parties. The
table excludes cash and cash equivalents, trade accounts
receivable, noncurrent assets, trade accounts payable and
accrued expenses and derivative instruments, all of which had
fair values approximating carrying amounts. The fair value of
current and long-term debt is estimated based on current rates
offered the Company for debt of the same maturities. The Company
has off-balance sheet exposures relating to certain financial
guarantees and letters of credit. The fair value of these, which
represents fees associated with obtaining the instruments, was
nominal.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
|
Carrying
|
|
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
Financial liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current and long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Senior Notes
|
|
$
|
150,000
|
|
|
$
|
155,250
|
|
|
$
|
150,000
|
|
|
$
|
163,500
|
|
Bank credit facility
|
|
|
85,000
|
|
|
|
85,000
|
|
|
|
|
|
|
|
|
|
Financing note payable
|
|
|
109
|
|
|
|
109
|
|
|
|
217
|
|
|
|
217
|
|
53
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Components of income tax expense for the years ended
December 31, 2005, 2004 and 2003 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
Deferred
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
350
|
|
|
$
|
38,931
|
|
|
$
|
39,281
|
|
State
|
|
|
|
|
|
|
2,311
|
|
|
|
2,311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
350
|
|
|
$
|
41,242
|
|
|
$
|
41,592
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
151
|
|
|
$
|
24,904
|
|
|
$
|
25,055
|
|
State
|
|
|
|
|
|
|
1,461
|
|
|
|
1,461
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
151
|
|
|
$
|
26,365
|
|
|
$
|
26,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
76
|
|
|
$
|
16,701
|
|
|
$
|
16,777
|
|
State
|
|
|
|
|
|
|
1,007
|
|
|
|
1,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
76
|
|
|
$
|
17,708
|
|
|
$
|
17,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The reasons for the differences between the effective tax rates
and the expected corporate federal income tax rate
of 34% is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of
|
|
|
|
Pretax Earnings
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Expected tax rate
|
|
|
34.0
|
%
|
|
|
34.0
|
%
|
|
|
34.0
|
%
|
Stock-based compensation
|
|
|
0.0
|
|
|
|
0.0
|
|
|
|
0.6
|
|
State taxes
|
|
|
2.0
|
|
|
|
2.0
|
|
|
|
2.1
|
|
Other
|
|
|
0.3
|
|
|
|
0.4
|
|
|
|
(0.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36.3
|
%
|
|
|
36.4
|
%
|
|
|
36.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The tax effects of temporary differences that give rise to
significant portions of the current tax asset and net deferred
tax liability at December 31, 2005 and 2004 are presented
below:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Current deferred tax assets:
|
|
|
|
|
|
|
|
|
Fair value of commodity derivative
instruments
|
|
$
|
3,555
|
|
|
$
|
630
|
|
Accrued bonus compensation
|
|
|
821
|
|
|
|
1,276
|
|
Accrued legal provision
|
|
|
1,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current deferred tax assets
|
|
$
|
5,582
|
|
|
$
|
1,906
|
|
|
|
|
|
|
|
|
|
|
Non-Current Deferred tax assets:
|
|
|
|
|
|
|
|
|
Restricted stock awards and options
|
|
$
|
3,339
|
|
|
$
|
1,531
|
|
Federal and state net operating
loss carryforwards
|
|
|
11,480
|
|
|
|
15,916
|
|
Fair market value of commodity
derivative instruments
|
|
|
3,543
|
|
|
|
|
|
Other
|
|
|
1,274
|
|
|
|
498
|
|
|
|
|
|
|
|
|
|
|
Non-Current Deferred tax liability:
|
|
|
|
|
|
|
|
|
Property, plant and equipment,
principally due to differences in depreciation
|
|
|
(107,195
|
)
|
|
|
(71,631
|
)
|
|
|
|
|
|
|
|
|
|
Net non-current deferred tax
liability
|
|
$
|
(87,559
|
)
|
|
$
|
(53,686
|
)
|
|
|
|
|
|
|
|
|
|
At December 31, 2005, the Company had net operating loss
carryforwards of approximately $31.9 million, which are
available to reduce future federal taxable income. The net
operating loss carryforwards begin expiring in the years 2018
through 2023. Although realization is not assured, management
believes it is more likely than not that all of the deferred tax
assets will be realized through future earnings and reversal of
taxable temporary differences. As a result, no valuation
allowance has been provided at December 31, 2005 and 2004.
The 2005 tax provision includes the use of $12.3 million of
net operating loss carryforwards.
|
|
(14)
|
Employee
Benefit Plans
|
The Company has a long term incentive plan authorizing various
types of market and performance based incentive awards which may
be granted to officers and employees. The Amended and Restated
2000 Long Term Stock Incentive Plan (the Plan) provides for the
grant of stock options for which the exercise price, set at the
time of the grant, is not less than the fair market value per
share at the date of grant. The options have a term of
10 years and generally vest over 3 years. The Plan
also provides for restricted stock, restricted share units and
performance share awards. The amended plan was approved by
stockholders on May 9, 2002 and is administered by the
Compensation Committee of the board of directors or such other
committee as may be designated by the board of directors. The
Compensation Committee is authorized to select the employees of
the Company and its subsidiaries and affiliates who will receive
awards, to determine the types of awards to be granted to each
person, and to establish the terms of each award. The total
number of shares that may be issued under the plan for all types
of awards is 4,800,000.
The Company issued restricted stock and restricted share unit
awards to employees and officers in the amount of 460,710 in
2005, 333,759 in 2004 and 131,754 in 2003. The restrictions on
this stock generally lapse on the first, second and third
anniversary of the date of grant and require that the employee
remain employed by the Company during the vesting period. Some
grants carry restrictions that lapse on the fourth and sixth
anniversary of the date of grant. The weighted average
grant-date fair value of restricted shares granted in the years
ended December 31, 2005, 2004 and 2003 was approximately
$24.72, $15.23 and $10.12, respectively.
The Company has recognized non-cash compensation expense of
$4.6 million, $1.8 million and $0.8 million in
2005, 2004 and 2003, respectively, related to the restricted
share and stock option grants. At December 31, 2005,
55
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
there was $10.5 million of deferred stock based
compensation expense related to the restricted share awards,
which will be recognized over the remaining vesting periods.
In 2005, 2004 and 2003, respectively, 73,617, 137,000 and
141,500 performance shares were awarded of which 28,155, 54,167
and 13,333 were forfeited in 2005, 2004 and 2003, respectively,
leaving 256,462 performance shares outstanding at
December 31, 2005. These shares cliff vest at the end of
three years and are based on the attainment of certain
performance goals. The expected fair value of the shares on the
vesting date is charged to expense ratably over the vesting
period unless it is determined that the performance goals will
not be met. The Company recognized non-cash compensation expense
of $1.4 million, $1.3 million and $0.5 million
related to these awards in 2005, 2004 and 2003, respectively.
The 2000 Stock Incentive Plan for Non-Employee Directors was
approved by the Board of Directors and our stockholders in
September 2000. In May 2005, the Companys stockholders
approved an amendment and restatement of the Plan to permit the
use of restricted share units in addition to stock options, to
provide flexibility to adjust grants to maintain a competitive
equity component for non-employee directors and to increase the
number of shares authorized for issuance under the Plan by
250,000 to 500,000. The size of any grants of stock options and
restricted share units to non-employee directors, including to
new directors, will be determined annually, based on the advice
of an independent compensation consultant. The option exercise
price for an option granted under the Plan shall be the fair
market value of the shares covered by the option at the time the
option is granted. Options become fully exercisable on the first
anniversary of the date of the grant. Prior to the one-year
anniversary, the options shall be exercisable as to a number of
shares covered by the option determined by pro-rating the number
of shares covered by the option based on the number of days
elapsed since the date of the grant. Any portion of an option
that has not become exercisable prior to the cessation of the
optionees service as a director for any reason shall not
thereafter become exercisable. Each option shall expire on the
earlier of (i) ten (10) years from the date of the
granting thereof, or (ii) thirty-six (36) months after
the date the optionee ceases to be a director of the Company for
any reason. Each restricted share unit represents the right to
receive one share of Common Stock upon the earlier to occur of:
(i) the cessation of the eligible directors service
as a director of the Company for any reason, or (ii) the
occurrence of a change of control of the Company. An eligible
director shall become 100% vested in a grant of restricted share
units on the first anniversary of the date of grant. Prior to
the first anniversary of the grant, an eligible director shall
be vested in a number of restricted share units determined by
pro-rating the grant based on the number of days elapsed since
the date of the grant. If the service of an eligible director
ceases for any reason prior to the first anniversary of the
grant, the director shall forfeit any unvested restricted share
units.
A summary of stock options granted under the incentive plans for
the years ended December 31, 2005, 2004 and 2003 is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Exercise
|
|
|
Number of
|
|
|
Exercise
|
|
|
Number of
|
|
|
Exercise
|
|
|
|
Shares
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
|
Outstanding at beginning of year
|
|
|
2,032,329
|
|
|
$
|
11.09
|
|
|
|
2,009,282
|
|
|
$
|
9.68
|
|
|
|
1,997,965
|
|
|
$
|
9.30
|
|
Granted
|
|
|
595,300
|
|
|
$
|
26.07
|
|
|
|
637,000
|
|
|
$
|
14.01
|
|
|
|
519,200
|
|
|
$
|
10.18
|
|
Exercised
|
|
|
(759,288
|
)
|
|
$
|
10.50
|
|
|
|
(453,492
|
)
|
|
$
|
8.73
|
|
|
|
(232,871
|
)
|
|
$
|
7.98
|
|
Forfeited
|
|
|
(40,232
|
)
|
|
$
|
14.82
|
|
|
|
(160,461
|
)
|
|
$
|
11.75
|
|
|
|
(275,012
|
)
|
|
$
|
8.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of year
|
|
|
1,828,109
|
|
|
$
|
16.13
|
|
|
|
2,032,329
|
|
|
$
|
11.09
|
|
|
|
2,009,282
|
|
|
$
|
9.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of year
|
|
|
1,012,220
|
|
|
$
|
11.08
|
|
|
|
1,247,964
|
|
|
$
|
10.78
|
|
|
|
840,027
|
|
|
$
|
10.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available for future grants
|
|
|
666,357
|
|
|
|
|
|
|
|
1,508,851
|
|
|
|
|
|
|
|
2,584,978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A summary of information regarding stock options outstanding at
December 31, 2005 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
Options Exercisable
|
|
|
|
|
|
|
Remaining
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Contractual
|
|
|
Average
|
|
|
|
|
|
Average
|
|
Range of Exercise
Prices
|
|
Shares
|
|
|
Life
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
|
$ 7.00 - $14.00
|
|
|
1,113,709
|
|
|
|
6.9 years
|
|
|
$
|
10.85
|
|
|
|
919,453
|
|
|
$
|
10.62
|
|
$14.01 - $21.00
|
|
|
126,100
|
|
|
|
6.5 years
|
|
|
$
|
16.56
|
|
|
|
33,333
|
|
|
$
|
15.70
|
|
$21.01 - $28.00
|
|
|
588,300
|
|
|
|
7.7 years
|
|
|
$
|
26.05
|
|
|
|
|
|
|
$
|
|
|
The Company also has a 401(k) Plan that covers all employees.
The 401(k) Plan was amended in 2002 such that, commencing in
July 1, 2002 the Company matched 50% of each individual
participants contribution not to exceed 2% of the
participants compensation. By a subsequent amendment in
November 2004, the Company match was increased, effective
January 1, 2005, to 100% of each individual
participants contribution not to exceed 6% of the
participants compensation. The contributions may be in the
form of cash or the Companys common stock. The Company
made matching contributions to the 401(k) Plan of 30,586, 13,210
and 15,343 shares of common stock in 2005, 2004 and 2003
valued at approximately $786,000, $207,000 and $175,000,
respectively.
|
|
(15)
|
Commitments
and Contingencies
|
The Company has operating leases for office space and equipment,
which expire on various dates through 2011. In addition, the
Company has agreed to purchase seismic-related services and
drilling rig commitments which expire on various dates through
2007.
Future minimum commitments as of December 31, 2005 under
these operating obligations are as follows (in thousands):
|
|
|
|
|
2006
|
|
$
|
55,441
|
|
2007
|
|
|
8,086
|
|
2008
|
|
|
2,075
|
|
2009
|
|
|
1,542
|
|
2010
|
|
|
1,284
|
|
Thereafter
|
|
|
7,703
|
|
|
|
|
|
|
|
|
$
|
76,131
|
|
|
|
|
|
|
Expense relating to operating obligations for the years ended
December 31, 2005, 2004 and 2003 was $4.8 million,
$6.3 million and $3.7 million, respectively.
Commencing January 1, 2002, the Company was required to
make monthly deposits of $250,000 into a trust for future
abandonment costs at East Bay. The Company was not entitled to
access the trust fund in order to draw funds for abandonment
purposes prior to December 31, 2003. Monthly deposits were
not required to be made for fiscal year 2004 but resumed
January 1, 2005. Beginning December 31, 2003 the
minimum balance in the trust must be maintained at
$6.0 million (with a maximum balance not to exceed
$15.0 million) until such time that the remaining
abandonment obligation is less than that amount. Therefore if
funds are drawn to pay for ongoing abandonment activities,
deposits may be necessary. These deposits are classified as
other assets in the accompanying consolidated balance sheets.
From time to time, the Company is involved in litigation arising
out of operations in the normal course of business. In
managements opinion, the Company is not involved in any
litigation, the outcome of which would have a material effect on
the financial position, results of operations or liquidity of
the Company.
57
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Pursuant to the Companys stockholder agreement with
Evercore, the Company paid an affiliate of Evercore a monitoring
fee of $250,000 in 2003. The requirement to pay this fee ceased
in November 2003 when Evercores beneficial ownership of
the Companys stock became less than 10% and the
stockholder agreement terminated by its terms.
|
|
(17)
|
Interim
Financial Information (Unaudited)
|
The following is a summary of consolidated unaudited interim
financial information for the years ended December 31, 2005
and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
|
December 31
|
|
|
|
(In thousands, except per share
data)
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
97,478
|
|
|
$
|
106,156
|
|
|
$
|
92,049
|
|
|
$
|
107,264
|
|
Costs and expenses
|
|
|
61,535
|
|
|
|
73,790
|
|
|
|
77,099
|
|
|
|
79,128
|
|
Business interruption recovery
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,632
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
35,943
|
|
|
|
32,366
|
|
|
|
14,950
|
|
|
|
48,768
|
|
Net income
|
|
|
20,421
|
|
|
|
18,050
|
|
|
|
6,520
|
|
|
|
28,104
|
|
Net income available to common
stockholders
|
|
|
19,477
|
|
|
|
18,050
|
|
|
|
6,520
|
|
|
|
28,104
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.56
|
|
|
$
|
0.48
|
|
|
$
|
0.17
|
|
|
$
|
0.74
|
|
Diluted
|
|
|
0.51
|
|
|
|
0.45
|
|
|
|
0.16
|
|
|
|
0.69
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
63,472
|
|
|
$
|
75,067
|
|
|
$
|
74,117
|
|
|
$
|
82,554
|
|
Costs and expenses
|
|
|
48,391
|
|
|
|
48,658
|
|
|
|
55,736
|
|
|
|
56,357
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
15,081
|
|
|
|
26,409
|
|
|
|
18,381
|
|
|
|
26,197
|
|
Net income
|
|
|
7,446
|
|
|
|
14,656
|
|
|
|
9,569
|
|
|
|
14,745
|
|
Net income available to common
stockholders
|
|
|
6,517
|
|
|
|
13,835
|
|
|
|
8,746
|
|
|
|
13,919
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.20
|
|
|
$
|
0.42
|
|
|
$
|
0.27
|
|
|
$
|
0.42
|
|
Diluted
|
|
|
0.20
|
|
|
|
0.38
|
|
|
|
0.25
|
|
|
|
0.37
|
|
|
|
(18)
|
Supplemental
Condensed Consolidating Financial Information
|
In connection with the Debt Offering, discussed above, all of
the Companys current active subsidiaries (the Guarantor
Subsidiaries) jointly, severally and unconditionally guaranteed
the payment obligations under the Debt Offering. The following
supplemental financial information sets forth, on a
consolidating basis, the balance sheet, statement of operations
and cash flow information for Energy Partners, Ltd. (Parent
Company Only) and for the Guarantor Subsidiaries. The Company
has not presented separate financial statements and other
disclosures concerning the Guarantor Subsidiaries because
management has determined that such information is not material
to investors.
The supplemental condensed consolidating financial information
has been prepared pursuant to the rules and regulations for
condensed financial information and does not include all
disclosures included in annual financial statements, although
the Company believes that the disclosures made are adequate to
make the information presented not misleading. Certain
reclassifications were made to conform all of the financial
information to the
58
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
financial presentation on a consolidated basis. The principal
eliminating entries eliminate investments in subsidiaries,
intercompany balances and intercompany revenues and expenses.
Supplemental
Condensed Consolidating Balance Sheet
As of December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
|
Only
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
6,789
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6,789
|
|
Accounts receivable
|
|
|
147,110
|
|
|
|
(19,481
|
)
|
|
|
|
|
|
|
127,629
|
|
Other current assets
|
|
|
8,670
|
|
|
|
91
|
|
|
|
|
|
|
|
8,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
162,569
|
|
|
|
(19,390
|
)
|
|
|
|
|
|
|
143,179
|
|
Property and equipment
|
|
|
775,274
|
|
|
|
413,804
|
|
|
|
|
|
|
|
1,189,078
|
|
Less accumulated depreciation,
depletion and amortization
|
|
|
(303,290
|
)
|
|
|
(115,057
|
)
|
|
|
|
|
|
|
(418,347
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property and equipment
|
|
|
471,984
|
|
|
|
298,747
|
|
|
|
|
|
|
|
770,731
|
|
Investment in affiliates
|
|
|
238,988
|
|
|
|
|
|
|
|
(238,988
|
)
|
|
|
|
|
Notes receivable, long-term
|
|
|
|
|
|
|
216,370
|
|
|
|
(216,370
|
)
|
|
|
|
|
Other assets
|
|
|
17,396
|
|
|
|
(21
|
)
|
|
|
|
|
|
|
17,375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
890,937
|
|
|
$
|
495,706
|
|
|
$
|
(455,358
|
)
|
|
$
|
931,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued
expenses
|
|
$
|
135,367
|
|
|
$
|
1,530
|
|
|
$
|
|
|
|
$
|
136,897
|
|
Fair value of commodity derivative
instruments
|
|
|
9,875
|
|
|
|
|
|
|
|
|
|
|
|
9,875
|
|
Current maturities of long-term
debt
|
|
|
|
|
|
|
109
|
|
|
|
|
|
|
|
109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
145,242
|
|
|
|
1,639
|
|
|
|
|
|
|
|
146,881
|
|
Long-term debt
|
|
|
235,000
|
|
|
|
216,370
|
|
|
|
(216,370
|
)
|
|
|
235,000
|
|
Other liabilities
|
|
|
116,102
|
|
|
|
38,709
|
|
|
|
|
|
|
|
154,811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
496,344
|
|
|
|
256,718
|
|
|
|
(216,370
|
)
|
|
|
536,692
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
415
|
|
|
|
|
|
|
|
|
|
|
|
415
|
|
Additional paid-in capital
|
|
|
348,863
|
|
|
|
|
|
|
|
|
|
|
|
348,863
|
|
Accumulated other comprehensive
loss
|
|
|
(12,619
|
)
|
|
|
|
|
|
|
|
|
|
|
(12,619
|
)
|
Retained earnings
|
|
|
115,366
|
|
|
|
238,988
|
|
|
|
(238,988
|
)
|
|
|
115,366
|
|
Treasury stock
|
|
|
(57,432
|
)
|
|
|
|
|
|
|
|
|
|
|
(57,432
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
394,593
|
|
|
|
238,988
|
|
|
|
(238,988
|
)
|
|
|
394,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
890,937
|
|
|
$
|
495,706
|
|
|
$
|
(455,358
|
)
|
|
$
|
931,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Supplemental
Condensed Consolidating Statement of Operations
Year Ended December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
|
Only
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas
|
|
$
|
276,257
|
|
|
$
|
125,748
|
|
|
$
|
|
|
|
$
|
402,005
|
|
Other
|
|
|
29,566
|
|
|
|
328
|
|
|
|
(28,952
|
)
|
|
|
942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
305,823
|
|
|
|
126,076
|
|
|
|
(28,952
|
)
|
|
|
402,947
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
29,843
|
|
|
|
21,639
|
|
|
|
|
|
|
|
51,482
|
|
Taxes, other than on earnings
|
|
|
1,803
|
|
|
|
8,569
|
|
|
|
|
|
|
|
10,372
|
|
Exploration expenditures
|
|
|
54,598
|
|
|
|
28,246
|
|
|
|
|
|
|
|
82,844
|
|
Depreciation, depletion and
amortization
|
|
|
66,306
|
|
|
|
37,343
|
|
|
|
|
|
|
|
103,649
|
|
General and administrative
|
|
|
41,891
|
|
|
|
16,314
|
|
|
|
(15,000
|
)
|
|
|
43,205
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
194,441
|
|
|
|
112,111
|
|
|
|
(15,000
|
)
|
|
|
291,552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business interruption recovery
|
|
|
20,632
|
|
|
|
|
|
|
|
|
|
|
|
20,632
|
|
Income from operations
|
|
|
132,014
|
|
|
|
13,965
|
|
|
|
(13,952
|
)
|
|
|
132,027
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(17,327
|
)
|
|
|
(13
|
)
|
|
|
|
|
|
|
(17,340
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
114,687
|
|
|
|
13,952
|
|
|
|
(13,952
|
)
|
|
|
114,687
|
|
Income taxes
|
|
|
(41,592
|
)
|
|
|
|
|
|
|
|
|
|
|
(41,592
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
73,095
|
|
|
$
|
13,952
|
|
|
$
|
(13,952
|
)
|
|
$
|
73,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
|
Only
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
$
|
32,227
|
|
|
$
|
237,742
|
|
|
$
|
|
|
|
$
|
269,969
|
|
Cash flows used in investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of business, net of
cash acquired
|
|
|
(863
|
)
|
|
|
|
|
|
|
|
|
|
|
(863
|
)
|
Property acquisitions
|
|
|
(48,544
|
)
|
|
|
(144,571
|
)
|
|
|
|
|
|
|
(193,115
|
)
|
Exploration and development
expenditures
|
|
|
(161,837
|
)
|
|
|
(93,063
|
)
|
|
|
|
|
|
|
(254,900
|
)
|
Other property and equipment
additions
|
|
|
(1,723
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,723
|
)
|
Proceeds from the sale of oil and
natural gas assets
|
|
|
1,442
|
|
|
|
|
|
|
|
|
|
|
|
1,442
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(211,525
|
)
|
|
|
(237,634
|
)
|
|
|
|
|
|
|
(449,159
|
)
|
Cash flows provided by (used in)
financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred financing costs
|
|
|
(357
|
)
|
|
|
|
|
|
|
|
|
|
|
(357
|
)
|
Repayments of long-term debt
|
|
|
(63,000
|
)
|
|
|
(108
|
)
|
|
|
|
|
|
|
(63,108
|
)
|
Equity offering costs
|
|
|
(87
|
)
|
|
|
|
|
|
|
|
|
|
|
(87
|
)
|
Proceeds from public offering net
of commissions
|
|
|
148,000
|
|
|
|
|
|
|
|
|
|
|
|
148,000
|
|
Exercise of stock options and
warrants
|
|
|
7,994
|
|
|
|
|
|
|
|
|
|
|
|
7,994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
financing activities
|
|
|
92,550
|
|
|
|
(108
|
)
|
|
|
|
|
|
|
92,442
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash
equivalents
|
|
|
(86,748
|
)
|
|
|
|
|
|
|
|
|
|
|
(86,748
|
)
|
Cash and cash equivalents at the
beginning of the period
|
|
|
93,537
|
|
|
|
|
|
|
|
|
|
|
|
93,537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at the
end of the period
|
|
$
|
6,789
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(19)
|
New
Accounting Pronouncements
|
In November 2004, the FASB issued Statement of Financial
Accounting Standards No. 151 Inventory Costs, an
amendment of ARB No. 43, Chapter 4
(Statement 151). The amendments made by
Statement 151 clarify that abnormal amounts of idle
facility expense, freight, handling costs, and wasted materials
(spoilage) should be recognized as current-period charges and
require the allocation of fixed production overheads to
inventory based on the normal capacity of the production
facilities. The guidance is effective for inventory costs
incurred during fiscal years beginning after June 15, 2005.
Earlier application is permitted for inventory costs incurred
during fiscal years beginning after November 23, 2004. The
Company has assessed the impact of Statement 151, which
will not have an impact on the financial position, results of
operations or cash flows of the Company.
In December 2004, the FASB issued Statement of Financial
Accounting Standards No. 153 Exchanges of
Non-monetary assets an amendment of APB Opinion
No. 29 (Statement 153).
Statement 153 amends Accounting Principles Board
(APB) Opinion 29 to eliminate the exception for
nonmonetary exchanges of similar productive assets and replaces
it with a general exception for exchanges of nonmonetary assets
that do not have commercial substance. A nonmonetary exchange
has commercial substance if the future cash flows of the entity
are expected to change significantly as a result of the
exchange. Statement 153 does not apply to a pooling of
assets in a joint undertaking intended to fund, develop, or
produce oil or natural gas from a particular property or group
of properties. The provisions of Statement 153 shall be
effective for nonmonetary asset exchanges occurring in fiscal
periods beginning after June 15, 2005. Early adoption is
permitted and the provisions of Statement 153 should be
applied prospectively. The Company has assessed the impact of
Statement 153, which will not have an impact on the
financial position, results of operations or cash flows of the
Company.
In December 2004, the FASB issued Statement of Financial
Accounting Standards
No. 123-Revised
2004, Share-Based Payment,
(Statement 123R). This is a revision of
Statement of Financial Accounting Standards No. 123,
Accounting for Stock-Based Compensation, and
supersedes APB No. 25, Accounting for Stock Issued to
Employees. The Company currently accounts for stock-based
compensation under the provisions of APB 25. Under
Statement 123R, the Company will be required to measure the
cost of employee services received in exchange for stock, based
on the grant-date fair value (with limited exceptions). That
cost will be recognized as expense over the period during which
an employee is required to provide service in exchange for the
award (usually the vesting period). The fair value will be
estimated using an option-pricing model. Excess tax benefits, as
defined in Statement 123R, will be recognized as an
addition to paid-in capital. This will be effective for us as of
the beginning of the first annual reporting period that begins
after June 15, 2005. The Company is currently in the
process of evaluating the impact of Statement 123R on its
financial statements. Based on options outstanding at the
effective date, the Company expects the pre-tax impact to be
less than $2.5 million for 2006. This does not contemplate
2006 award grants. Note (2) of the Notes to Consolidated
Financial Statements illustrates the current effect on net
income and earnings per share if we had applied the fair value
recognition provisions of Statement 123.
In May 2005, the FASB issued Statement of Financial Accounting
Standards No. 154, Accounting Changes and Error
Corrections a replacement of APB Opinion
No. 20 and FASB Statement No. 3,
(Statement 154). Statement 154 provides
guidance on the accounting for and reporting of accounting
changes and error corrections. It establishes, unless
impracticable, retrospective application as the required method
for reporting a change in accounting principle in the absence of
explicit transition requirements specific to Statement 154.
The provisions of Statement 154 shall be effective for
accounting changes and corrections of errors made in fiscal
years beginning after December 15, 2005.
|
|
(20)
|
Supplementary
Oil and Natural Gas
Disclosures (Unaudited)
|
Our December 31, 2005, 2004 and 2003 estimates of proved
reserves are based on reserve reports prepared by Netherland,
Sewell & Associates, Inc. and Ryder Scott Company,
L.P., independent petroleum engineers. Users of this information
should be aware that the process of estimating quantities of
proved and proved developed natural gas
and crude oil reserves is very complex, requiring significant
subjective decisions in the evaluation of all available
geological, engineering and economic data for each reservoir.
The data for a given reservoir may also
61
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
change substantially over time as a result of numerous factors
including, but not limited to, additional development activity,
evolving production history and continual reassessment of the
viability of production under varying economic conditions.
Consequently, material revisions to existing reserve estimates
occur from time to time. Although every reasonable effort is
made to ensure that reserve estimates reported represent the
most accurate assessments possible, the significance of the
subjective decisions required and variances in available data
for various reservoirs make these estimates generally less
precise than other estimates presented in connection with
financial statement disclosures. Proved reserves are estimated
quantities of natural gas, crude oil and condensate that
geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
Proved-developed reserves are proved reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods.
The following table sets forth the Companys net proved
reserves, including the changes therein, and proved-developed
reserves:
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
|
|
|
Natural Gas
|
|
|
|
(Mbbls)
|
|
|
(Mmcf)
|
|
|
Proved-developed and undeveloped
reserves:
|
|
|
|
|
|
|
|
|
December 31, 2002
|
|
|