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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER: 001-16179
ENERGY PARTNERS, LTD.
(Exact name of registrant as specified in its charter)
DELAWARE 72-1409562
(State or other jurisdiction of (I.R.S. Employer identification No.)
incorporation or organization)
201 ST. CHARLES AVENUE, SUITE 3400
NEW ORLEANS, LOUISIANA 70170
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
504-569-1875
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, Par Value $0.01 per Share New York Stock Exchange
Securities registered Pursuant to Section 12(g) of the Act: NONE
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. [X] Yes [ ] No
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 registrant's 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. [ ]
The aggregate market value of the voting stock held by non-affiliates of
the registrant at March 5, 2001 based on the closing price of such stock as
quoted on the New York Stock Exchange on that date was $85,591,528.
As of March 5, 2001 there were 26,737,542 shares of the registrant's common
stock, par value $0.01 per share, outstanding.
Documents incorporated by reference: Portions of the registrant's
definitive proxy statement for its 2001 Annual Meeting of Stockholders have been
incorporated by reference into Part III of this Form 10-K.
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TABLE OF CONTENTS
PAGE
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PART I
Items 1 & 2. Business and Properties..................................... 2
Item 3. Legal Proceedings........................................... 17
Item 4. Submission of Matters to a Vote of Security Holders......... 18
Item 4A. Executive Officers of the Registrant........................ 18
PART II
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters....................................... 19
Item 6. Selected Financial Data..................................... 20
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 20
Item 7A. Quantitative and Qualitative Disclosures about Market
Risk...................................................... 26
Item 8. Financial Statements and Supplementary Data................. 28
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 48
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 48
Item 11. Executive Compensation...................................... 48
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 48
Item 13. Certain Relationships and Related Transactions.............. 48
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 48
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FORWARD LOOKING STATEMENTS
All statements other than statements of historical fact contained in this
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 1 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 document are expressly qualified in their
entirety by the cautionary statements in this paragraph.
PART I
ITEMS 1 & 2. BUSINESS AND PROPERTIES
We are an independent oil and natural gas exploration and production
company concentrated in the shallow to moderate depth waters of the central
region of the Gulf of Mexico Shelf. We have focused on the Central Gulf of
Mexico Shelf area because it provides us with favorable economic and geologic
conditions, including multiple reservoir formations, regional economies of
scale, extensive infrastructure and comprehensive geologic databases. We believe
that the large, established fields in this region offer a balanced and ample
inventory of existing and prospective exploitation and development
opportunities, as well as the long-term potential for reserve additions and
production increases from deeper geologic formations. Most of our properties are
located in the Terrebonne Trough area of this region. As of December 31, 2000,
we had estimated proved reserves of approximately 49,150 Mmcf of natural gas and
27,521 Mbbls of oil, or an aggregate of approximately 35.7 million Boe, with a
present value of estimated pre-tax future net cash flows of $489.9 million
(based upon year-end 2000 prices and a discount rate of 10%).
We were incorporated in January 1998 by Richard A. Bachmann, our founder,
chairman, president and chief executive officer. Mr. Bachmann, the former
president and chief operating officer of The Louisiana Land and Exploration
Company, assembled a team of geoscientists and management professionals with
considerable region-specific geological, geophysical, technical and operational
experience to form the foundation of our company. The industry relationships of
Mr. Bachmann and the rest of our team provide us with access to the operators of
the Gulf of Mexico Shelf fields that we target for redevelopment. Our management
team has an average of 25 years of energy industry experience, many with large
energy companies.
We have grown our company through a combination of multi-year, multi-well
drill-to-earn programs and strategic acquisitions. Under our drill-to-earn
programs, we use our personnel and capital to identify and pursue additional
drilling opportunities on properties previously developed by our drill-to-earn
partners and recover our investment through sharing revenue from the new
production we establish. After successful drilling of wells, we earn an interest
in the reserves we find and develop. We generally operate the properties during
the drilling phase of these programs and seek to reduce costs and improve
reservoir recovery efficiencies through our geophysical, technical and
operational expertise.
Our capital expenditures for 2000 totaled $63.1 million for exploration and
development activities and $119.9 million in proved property acquisitions. For
2001, we have budgeted exploration and development expenditures of approximately
$120 million which includes plans to drill 40 new wells or sidetracks, conduct
69 workovers or recompletions on existing wells and compressor and facility
upgrades.
On November 1, 2000, we priced our initial public offering of 5.75 million
shares of common stock, raising $80.2 million after underwriting discounts and
commissions. Our common shares are traded on the New York Stock Exchange under
the symbol "EPL."
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OUR PROPERTIES
Currently, we have three specific project areas: East Bay Field, Greater
Bay Marchand, and Main Pass 122/133. The Greater Bay Marchand area is comprised
of three fields, South Timbalier 26, Bay Marchand and South Timbalier 22, 23 and
27. The fields are contiguous and together cover most of the Bay Marchand salt
dome located in state and federal waters offshore Louisiana.
East Bay Field
In March 2000, we acquired the East Bay Field (East Bay), and related
production, compression and storage facilities for $72.3 million, net of
purchase price adjustments. East Bay is located 89 miles southeast of New
Orleans near the mouth of the Mississippi River and contains producing wells
located onshore along the coastline to water depths of approximately 85 feet.
The field encompasses nearly 48 square miles and is comprised of three oil and
natural gas fields, South Pass 24, 27 and 39. We are the operator of these
fields and own an average 96.1% working interest. Our net revenue interest
ranges from 82% to 86%. Our lease area covers 33,735 gross acres (32,509 net
acres) of which 4,330 gross and net acres are under federal jurisdiction while
29,405 gross acres (28,179 net acres) are under the jurisdiction of the State of
Louisiana. The State of Louisiana acreage includes 823 gross and net unproved
acres adjacent to East Bay in Louisiana state waters acquired in November 2000
and 1,316 acres acquired in February 2001.
During 2000, we invested a total of $24 million in the drilling or
sidetracking of four wells, three of which were successful, and the workover or
recompletion of 60 wells, 57 of which were successful. As a result of these
activities, we increased our net average production 37% from 8,555 Boe per day
in April 2000 to 11,761 Boe per day in December 2000. East Bay production
accounted for approximately 72% of our net daily production during 2000.
In November 2000, East Bay production was interrupted by an underwater
mudslide, which severed an 18-inch high-pressure natural gas transfer line.
Extensive effort was required to bypass the severed line and partially restore
production until the line could be returned to service. The repairs were
completed and the line was returned to service in February 2001.
In addition, during 2000, we reprocessed the existing 3-D seismic surveys
covering East Bay by applying new seismic velocity data and advanced seismic
data technology. We will also be increasing our seismic coverage in the area in
2001 and merging the various surveys covering East Bay. We believe that the new
3-D data set will allow improved structural and stratigraphic interpretation for
upcoming drilling activity. Total expenditures for facility improvements,
compressor upgrades and seismic and lease acquisitions at East Bay totaled $1.1
million in 2000.
Under our 2001 exploration and development program, 51% of planned
expenditures, or $61 million, has been earmarked for East Bay projects. The
budget includes 64 workovers or recompletions and 10 new wells or sidetracks of
existing wells totaling $47 million; compressor and facilities upgrades totaling
$11 million; and seismic and lease acquisition expenditures totaling $3 million.
The Greater Bay Marchand Area
The Greater Bay Marchand area is located in state and federal waters off
the coast of Louisiana approximately 60 miles south of New Orleans in water
depths of 60 feet or less and encompasses nearly 100 square miles. We acquired
our interests in the area in six separate transactions.
SOUTH TIMBALIER 26
In June 1998, we purchased our initial 20% working interest in the South
Timbalier 26 field for approximately $9 million and assumed operatorship of the
field. In March 2000, we acquired our partner's 80% interest in the field, and
in April 2000, we sold 50% of our interest in the field to Vastar Resources,
Inc. Our net cash outflow related to these two transactions was $8.3 million. We
continue to serve as operator of the field with a 50% working interest.
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BAY MARCHAND DRILL-TO-EARN AGREEMENTS WITH CHEVRON
In August 1998, we entered into a drill-to-earn agreement with Chevron
U.S.A. covering the federal outer continental shelf acreage in the Bay Marchand
field. As of December 31, 2000, we owned an 80% gross working interest in the
drill-to-earn agreement, with the working interest in a particular operation
contingent upon the nature of the operation, its success and the price of oil at
the time the operation is commenced. To date, our well cost participation has
ranged from 22.5% to 80%; our working interest from 19.1% to 68%; and our net
revenue interest from 15.6% to 55.4% (before payout). We are the operator of the
drilling and completion of wells under our program and Chevron serves as
operator of production operations.
In May 2000, we expanded our presence in Bay Marchand by executing a
separate drill-to-earn agreement with Chevron covering their Louisiana state
water bottom acreage. We are the operator of the drilling and completion of
wells covered under this program and own an 80% gross working interest in the
drill-to-earn agreement. To date, our well cost participation has ranged from
16.7% to 40%; our working interest from 12.5% to 34%; and our net revenue
interest from 10.3% to 28.1% (before payout). Chevron serves as operator of
production operations.
In February 2001 we negotiated an extension of these drill-to-earn
agreements through the end of 2002, which will also require our participation in
a minimum of 16 major operations per calendar year. This agreement consolidated
the drilling obligations under the outer continental shelf and state water
bottom agreements described above. As of the end of February 2001 we were
completing our fifth well under this program.
SOUTH TIMBALIER 22, 23 AND 27
In October 1999, we acquired a 12.5% working interest in South Timbalier
22, the south half of South Timbalier 23 and the northeast quarter of South
Timbalier 27 for $1.4 million. In September 2000, we exercised a preferential
right to purchase an additional 14.5% working interest from Texaco for $2.2
million increasing our interest in the field to approximately 27.1%.
During 2000, we invested a total of $39 million in the Greater Bay Marchand
area. Our investments included the drilling or sidetracking of 26 wells, 24 of
which were successful, and the workover or recompletion of 18 wells, 14 of which
were successful. As a result of these activities and our larger interest in the
field, we increased our net average production 336% to 4,274 Boe per day in
December 2000 compared to 980 Boe per day for 1999. Production from this area
accounted for approximately 24% of our net daily production in 2000.
Under our 2001 exploration and development program, 41% of planned
expenditures, or $49 million, has been earmarked for Greater Bay Marchand
projects. The budget includes 5 workovers or recompletions and 30 new wells or
sidetracks of existing wells totaling $48 million and facilities upgrades
totaling $1 million.
Main Pass 122/133
In June 1998, we commenced our first drill-to-earn program with Chevron
covering Main Pass 122/133. All four wells drilled under this agreement were
successful and encountered multiple reservoirs. We have completed this
drill-to-earn program and do not expect any further drilling activity in this
field. Chevron currently operates all of the wells. Our net production averaged
281 Boe per day in December 2000 and accounted for approximately 4% of our net
daily production in 2000.
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, 2000, 1999 and
1998. The December 31, 2000 estimates of proved reserves are based on a reserve
report prepared by Netherland, Sewell & Associates, Inc., independent petroleum
engineers. The present values, discounted at 10% per annum, of estimated future
net cash flows before income taxes
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shown in the table are not intended to represent the current market value of the
estimated oil and natural gas reserves we own.
AS OF DECEMBER 31,
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2000 1999 1998
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Total estimated net proved reserves:
Oil (Mbbls).......................................... 27,521 3,824 2,861
Natural gas (Mmcf)................................... 49,150 12,752 12,534
Total (Mboe)................................. 35,712 5,949 4,950
Net proved developed reserves(4):
Oil (Mbbls).......................................... 25,024 2,715 2,467
Natural gas (Mmcf)................................... 39,522 7,631 10,859
Total (Mboe)................................. 31,611 3,987 4,277
Estimated future net revenues before income taxes (in
thousands)........................................... $641,241 $76,999 $41,051
Present value of estimated future net revenues before
income taxes (in thousands)(1)(2).................... $489,945 $54,819 $27,533
Standardized measure of discounted future net cash
flows (in thousands)(3).............................. $348,102 $47,177 $24,889
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(1) 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.
(2) The December 31, 2000 amount was calculated using a period end oil price of
$25.84 per barrel and a period end natural gas price of $9.97 per Mcf.
(3) The standardized measure of discounted future net cash flows represents the
present value of future cash flows after income tax discounted at 10%.
(4) Net proved developed non-producing reserves as of December 31, 2000 were
8,929 Mbbls and 23,076 Mmcf.
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting future rates of production and
timing of development expenditures. For a discussion of these uncertainties, see
"Risk Factors."
COSTS INCURRED IN OIL AND GAS ACTIVITIES
The following table sets forth certain information regarding the costs
incurred associated with finding, acquiring, and developing our proved oil and
gas reserves:
YEARS ENDED DECEMBER 31,
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2000 1999 1998
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(IN THOUSANDS)
Oil and gas property acquisition....................... $119,872 $ 1,410 $ 9,045
Exploration............................................ 18,053 1,508 249
Development............................................ 45,063 15,604 17,282
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Total costs incurred......................... $182,988 $18,522 $26,576
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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, 2000:
TOTAL
PRODUCTIVE
WELLS
-----------
GROSS NET
----- ---
Oil......................................................... 409 375
Natural gas................................................. 43 39
--- ---
Total............................................. 452 414
=== ===
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.
ACREAGE
The following table sets forth information as of December 31, 2000 relating
to acreage held by us. Developed acreage is assigned to producing wells.
GROSS NET
ACREAGE ACREAGE
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Developed:
East Bay.................................................. 31,596 30,370
Greater Bay Marchand Area:
Bay Marchand........................................... 880 310
South Timbalier 26..................................... 5,000 2,500
South Timbalier 22, 23 and 27.......................... 8,750 1,094
Main Pass 122/133......................................... 312 163
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Total............................................. 46,538 34,437
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Undeveloped:
East Bay.................................................. 823 823
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WELL ACTIVITY
The following table shows our well activity for the years ended December
31, 2000 and 1999 and the period ended December 31, 1998. 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.
JANUARY 29, 1998
YEAR ENDED YEAR ENDED (INCEPTION) TO
DECEMBER 31, 2000 DECEMBER 31, 1999 DECEMBER 31, 1998
----------------- ----------------- -----------------
GROSS NET GROSS NET GROSS NET
------ ---- ------ ---- ------ ----
Development Wells:
Productive....................... 9.0 5.7 3.0 0.6 -- --
Non-Productive................... 2.0 1.5 -- -- -- --
---- --- --- --- --- ---
Total.................... 11.0 7.2 3.0 0.6 -- --
==== === === === === ===
Exploration Wells:
Productive....................... 18.0 6.5 2.0 0.6 6.0 4.0
Non-Productive................... 1.0 0.3 1.0 0.3 -- --
---- --- --- --- --- ---
Total.................... 19.0 6.8 3.0 0.9 6.0 4.0
==== === === === === ===
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TITLE TO PROPERTIES
Our properties are subject to customary royalty interests, liens under
indebtedness, liens incident to operating agreements, liens for current taxes
and other burdens, including other mineral encumbrances and restrictions. We do
not believe that any of these burdens materially interferes with the use of our
properties in the operation of our business.
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 and obtain title opinions from counsel only
before commencement of drilling operations. We believe that title issues
generally are not as likely to arise on offshore oil and natural gas properties
as on onshore properties.
RISK FACTORS
Exploration and Drilling Risks
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:
- pressure or irregularities in geological formations;
- shortages of or delays in obtaining equipment and qualified personnel;
- equipment failures or accidents;
- adverse weather conditions, such as hurricanes and tropical storms;
- reductions in oil and natural gas prices;
- title problems; and
- limitations in the market for oil and natural gas.
Liability Risks
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 are
subject to all of the operating risks associated with drilling for and producing
oil and natural gas, including the possibility of:
- 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;
- abnormally pressured formations;
- mechanical difficulties, stuck oil field drilling and service tools and
casing collapse;
- fires and explosions;
- personal injuries and death; and
- natural disasters.
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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, but we are not fully
insured against all risks. We may elect not to obtain insurance if we believe
that the cost of available insurance is excessive relative to the risks
presented. 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 us.
Volatility of Oil and Natural Gas Prices
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 global supply of and demand for oil and natural gas;
- the actions of the Organization of Petroleum Exporting Countries, or
OPEC;
- the price and quantity of foreign imports of oil;
- political conditions, including embargoes, in or affecting other
oil-producing countries;
- the level of worldwide oil and natural gas exploration and production
activity;
- the level of global oil and natural gas inventories;
- weather 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 or ability to finance planned
capital expenditures. Further, oil prices and natural gas prices do not
necessarily move together.
Oil and Natural Gas Property Impairments
Accounting rules require that we review periodically the carrying value of
our oil and natural gas properties for possible impairment. Based on specific
market factors and circumstances at the time of prospective impairment reviews,
and the continuing evaluation of development plans, production data, economics
and other factors, we may be required to write down the carrying value of our
oil and natural gas properties. A write-down constitutes a non-cash charge to
earnings, which reduces our equity. We may incur impairment charges in the
future, which could have a material adverse effect on our results of operations
in the period taken.
Uncertainty of Estimates of Oil and Natural Gas 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 prepare our estimates we must project production rates and
timing of development expenditures. We must also analyze available geological,
geophysical, production and engineering data. The
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extent, quality and reliability of this 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
generally 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.
Marketability of 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 materially harm our business. We may be
required to shut in wells for lack of a market or because of inadequacy or
unavailability of 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.
Our Limited Operating History
We have only a limited operating history upon which you can evaluate our
business and prospects. Because of our limited operating history, our future
results of operations are difficult to estimate accurately. We also completed
two acquisitions in 2000, which have significantly changed our company.
A Significant Part of the Value of Our Production and Reserves is Concentrated
in One Property
During the month of December 2000, 72% of our net daily production came
from our East Bay field. If mechanical problems, storms or other events curtail
a substantial portion of this production, our cash flow would be affected
adversely. Also, at December 31, 2000, approximately 75% of our proved reserves
were located on this property. If the actual reserves associated with this
property are less than our estimated reserves, our business, financial condition
or results of operations could be adversely affected.
Relatively Short Production Periods for Gulf of Mexico Properties Subject 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, and, as a result, our reserve replacement needs from new
investments are relatively greater. All of our operations are in the Gulf of
Mexico Shelf. Production from reserves in reservoirs in the Gulf of Mexico
generally declines more rapidly than from reservoirs in many other producing
regions of the world. 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.
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Rapid Growth May Place Significant Demands on Our Resources
We have experienced rapid growth in our operations and expect that
significant 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;
- the need to train and manage a growing 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 this expansion or if our systems, procedures or controls are not adequate
to support our operations, our business could be harmed.
Acquisition of Additional Reserves
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;
- 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 assessment will not reveal all existing or potential problems, nor will
it permit us to become familiar enough with the properties to assess fully their
deficiencies and capabilities. In the course of our due diligence, we 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 made. 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.
Capital Requirements
In order to finance acquisitions of additional producing properties or
enter into significant drill-to-earn programs, we may need to alter or increase
our capitalization substantially through the issuance of 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, drill-to-earn programs 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
acquisitions, drill-to-earn programs or other transactions or to obtain external
funding on terms acceptable to us.
Control by Principal Stockholder
Our principal stockholder, Evercore, together with its affiliates,
beneficially owns approximately 35% of our outstanding shares of common stock
and Evercore is entitled to nominate four of our eight directors. Evercore's
consent is required to take a number of corporate actions, including making
acquisitions, selling assets, adopting or amending capital and operating
budgets, incurring indebtedness, increasing compensation, issuing our stock,
declaring dividends, engaging in hedging transactions and entering joint
ventures, and
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Evercore may terminate the employment of Mr. Bachmann, our chairman, president
and chief executive officer. As a result, Evercore is in a position to control
or influence substantially the manner in which our business is operated and the
outcome of stockholder votes on the election of directors and other matters.
Availability and Costs of Resources
All of our operations are in the Gulf of Mexico Shelf. Shortages or the
high cost of drilling rigs, equipment, supplies or personnel could delay or
adversely affect our development and exploration operations, which could have a
material adverse effect on our business, financial condition or results of
operations. Recently, drilling activity in the Gulf of Mexico has increased, and
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 also decreases the availability of offshore rigs. We cannot assure you
that costs will not increase further or that necessary equipment and services
will be available to us at economical prices.
Risks of Hedging Transactions
We entered 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 of financially settled forward sales
contracts and zero-cost collars with major financial institutions as required by
our bank facility entered into in connection with the acquisitions of the East
Bay field and additional interests in the South Timbalier 26 field.
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. Additionally, hedging
transactions may expose us to cash margin requirements.
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 stockholder approval;
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. Evercore is generally exempted from these provisions
and will have special rights so long as it owns at least a majority of our
outstanding common stock.
Reliance on Key Personnel
To a large extent, we depend on the services of our founder and chairman,
president and chief executive officer, Richard A. Bachmann, and other senior
management personnel. The loss of the services of
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Mr. Bachmann or other senior management personnel could have a material adverse
effect on our operations. We do not maintain any insurance against the loss of
any of these individuals.
The Gulf of Mexico area is highly competitive, and our success there will
depend on our ability to attract and retain experienced geoscientists and other
professional staff.
Marketing
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
Equiva Trading Company expiring June 2003 and assumed under the East Bay field
purchase agreement with Ocean Energy. Our oil, condensate and natural gas
production is sold to a variety of purchasers, typically at market-sensitive
prices. Our purchasers of oil and condensate include Chevron, Shell, Williams
Energy Marketing & Trading Company and Williams-Gulfmark Energy Company.
Currently, most of our natural gas production is sold to Duke Energy Trading and
Marketing, L.L.C. We believe that the prices for liquids and natural gas are
comparable to market prices in the areas where we have production. We also have
natural gas processing agreements for our production at our Bay Marchand and
East Bay fields with Dynegy Midstream Services, L.P. and Enterprise Gas
Processing, L.L.C.
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.
Competition
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 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 assure you 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.
REGULATION
Regulation of Transportation and Sale of Natural Gas
The Federal Energy Regulatory Commission ("FERC"), pursuant to the Natural
Gas Act and the Natural Gas Policy Act, regulates interstate natural gas
pipeline transportation rates and service conditions, both of which affect the
marketing of natural gas we produce, as well as the revenues received for sales
of such natural gas. Since the latter part of 1985, the FERC has endeavored to
make natural gas transportation more accessible to natural gas buyers and
sellers on an open and non-discriminatory basis. The 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 to implement its open access
policies. As a result of the Order No. 636 program, the marketing and pricing of
natural gas has been significantly altered. The interstate pipelines'
traditional role as wholesalers of natural gas has been terminated and replaced
by a structure under which pipelines provide transportation and storage service
on an open basis to others who buy and sell natural gas. Although the FERC's
orders do not directly regulate natural gas producers, they are intended to
foster increased competition within all phases of the natural gas industry.
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The courts have largely affirmed the significant features of Order No. 636
and the numerous related orders pertaining to individual pipelines. However,
FERC continues to review and modify its regulations regarding the transportation
of natural gas. For example, FERC recently issued Order Nos. 637 and 637-A
which, among other things, (i) lift the cost-based cap on pipeline
transportation rates in the capacity release market until September 30, 2002,
for releases of pipeline capacity of less than one year, (ii) require pipelines
to provide shippers with more opportunities to use capacity for which they pay
by increasing rights to capacity segmentation and equalizing nomination
procedures, (iii) permit pipelines to charge different maximum, cost-based rates
for peak and off-peak periods and for different contract terms, (iv) permit, but
do not mandate, auctions for pipeline capacity, (v) require pipelines to
implement imbalance management services and to permit third-parties to provide
such services in competition with the pipeline's own service, (vi) restrict the
ability of pipelines to impose penalties for imbalances, overruns and
non-compliance with operational flow orders, and (vii) implement a number of new
pipeline reporting requirements intended to increase transparency in the market.
In addition, FERC recently implemented new regulations governing the procedure
for obtaining authorization to construct new pipeline facilities and has issued
a policy statement establishing a presumption in favor of requiring owners of
new pipeline facilities to charge rates based solely on the costs associated
with such new pipeline facilities.
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 provide open-access, non-discriminatory
service. FERC recently issued Order No. 639, requiring that virtually all non-
proprietary pipeline transporters of natural gas on the outer continental shelf
report information on their affiliations, rates and conditions of service. Among
FERC's purposes in issuing such rules was the desire to increase transparency in
the market to provide producers and shippers on the outer continental shelf with
greater assurance of open-access services on pipelines located on the outer
continental shelf and non-discriminatory rates and conditions of service on such
pipelines.
We cannot accurately predict whether the FERC's 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. 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 affect equally all
intrastate natural gas shippers within the state, we believe that the regulation
of intrastate natural gas transportation in any states in which we operate and
ship natural gas on an intrastate basis will not affect our operations any
differently than those of our competitors.
Regulation of Transportation of Oil
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.
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 shippers, we believe that the
regulation of oil transportation rates will not affect our operations any
differently than those of 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
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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 interest in an approximately
12-mile oil pipeline, which transports oil produced from South Timbalier 26 on
the Gulf of Mexico Shelf to Bayou Forchon, Louisiana. Production transported on
this pipeline includes oil produced by us and the pipeline's co-owner, Vastar.
EPL Pipeline, L.L.C. has on file with the Louisiana Public Service Commission
and the Federal Energy Regulatory Commission a tariff for this transportation
services and offers non-discriminatory transportation for any willing shipper.
Regulation of Production
The production of oil and natural gas is subject to regulation under a wide
range of state and federal statutes, rules, orders and regulations. Federal,
state and local statutes and regulations require permits for drilling
operations, drilling bonds and reports concerning operations. Most states in
which we own and operate properties have regulations governing conservation
matters, including provisions for the unitization or pooling of oil and natural
gas properties, the establishment of maximum rates of production from oil and
natural gas wells and the regulation of the spacing, plugging and abandonment of
wells. Many states also restrict production to the market demand for oil and
natural gas, and several 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 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 the MMS and are required to comply with the regulations and
orders promulgated by MMS. Among other things, we would be required to obtain
prior MMS approval for any exploration plans we pursued and our development and
production plans for these leases. The 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, the 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
due under state oil and natural gas leases. The basis for royalty established by
MMS and the state regulatory authorities is generally applicable to all 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. However, 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 discharge of materials into the environment, or otherwise relating to the
protection of the environment, 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 are subject to stringent environment regulation. As with the
industry generally, compliance with existing regulations increases our overall
cost of business. The areas affected include:
- 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 resulting from
expenses primarily related to the management and disposal of drilling
fluids and other oil and natural gas exploration wastes; and
- capital costs to construct, maintain and upgrade equipment and
facilities.
Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended ("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 the 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. In the course of our ordinary operations, we may
generate waste that may fall within CERCLA's 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:
- to remove or remediate previously disposed wastes, including wastes
disposed or released by prior owners or operators;
- to clean up contaminated property, including contaminated groundwater; or
- to perform remedial operations to prevent future contamination.
At this time, we do not believe that we are associated with any Superfund
site and we are unaware of any liability under CERCLA for any costs and damages
resulting from hazardous substances released into the environment.
Oil Pollution Act of 1990. The Oil Pollution Act of 1990 (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 the 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 with the OPA's 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 the OPA, and we believe that compliance with the OPA's
financial responsibility and other operating requirements will not have a
material adverse effect on us.
Clean Water Act. The Federal Water Pollution Control Act of 1972, as
amended (the "Clean Water Act"), imposes restrictions and controls on the
discharge of produced waters and other wastes into navigable
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waters. Permits must be obtained to discharge pollutants into state and federal
waters. Certain state regulations and the general permits issued under the
Federal National Pollutant Discharge Elimination System 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 water. The Clean Water Act and comparable state
statutes provide for civil, criminal and administrative penalties for
unauthorized discharges for oil and other pollutants and imposes liability on
parties responsible for those discharges for the costs of cleaning up any
environmental damage caused by the release and for natural resource damages
resulting from the release. 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.
Resources Conservation Recovery Act. The Resource Conservation and
Recovery Act of 1976, as amended ("RCRA"), is the principle 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 RCRA's 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.
Marine Protected Areas. Executive Order 13158, issued on May 26, 2000,
directs federal agencies to safeguard existing Marine Protected Areas ("MPAs")
in the United States and establish new MPAs. The order requires federal agencies
to avoid harm to MPAs to the extent permitted by law and to the maximum extent
practicable. It also directs the EPA to propose new regulations under the Clean
Water Act to ensure appropriate levels of protection for the marine environment.
Although at this time we cannot accurately assess the order's impact, it has the
potential to adversely affect our operations by restricting areas in which we
may carry out future development and exploration projects and/or causing us to
incur increased operating expenses.
Consideration of Environmental Issues in Connection with Governmental
Approvals. Our operations frequently require licenses, permits and/or other
governmental approvals. Several federal statutes, including the 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 the MMS to
ensure worker safety during paint removal.
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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 Permit at East Bay. In July 2000, we notified the Louisiana Department
of Environmental Quality ("DEQ") of our discovery of a potential non-compliance
with certain air emission requirements contained in an air permit issued for the
East Bay Central Field Facility. The air permit was issued to the previous owner
in 1997 and transferred to us when we acquired the East Bay field in April 2000.
Following meetings with DEQ, we entered into an Environmental Compliance
Order authorizing us to seek a modification of the permit which, among other
things, would allow us to achieve compliance with the modified permit's air
emission requirements within 18 months of issuance of the permit modification.
The final modified air permit was issued to us in February 2001. Non-compliance
with the prior air permit potentially subjects us to civil penalties. Under the
Environmental Compliance Order to achieve compliance with the modified permit,
we have agreed to install control technology designed to achieve compliance with
the existing permit. Most of the costs associated with achieving compliance with
the permit were already incorporated in our budget as part of our production
plans for the field and are, therefore, not expected to have a material adverse
impact on our financial condition or results of operations. Based on available
information, we do not believe that our operations will be adversely affected by
the ongoing permit and enforcement proceedings.
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 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.
Safe Drinking Water Act. Underground injection is the subsurface placement
of fluid through a well or dug-hole whose depth is greater than its width. It
can include placement through the reinjection of brine from oil and gas
production. The Safe Drinking Water Act established 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, 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 all applicable requirements of the state underground
injection control program and our permits.
EMPLOYEES
As of December 31, 2000, we had approximately 127 full-time employees,
including 38 geoscientists, engineers and technicians and 65 field personnel.
Our employees are not represented by any labor union. We consider relations with
our employees to be satisfactory. We have never experienced a work stoppage or
strike.
ITEM 3. LEGAL PROCEEDINGS
In the ordinary course of business, we are 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 the financial position,
results of operations or liquidity of our company.
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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................... 56 Chairman, President and Chief
Executive Officer
Suzanne V. Baer....................... 53 Vice President, Chief Financial
Officer
Clinton W. Coldren.................... 45 Vice President
Wayne A. Greenwalt.................... 52 Vice President
John H. McCandless.................... 52 Vice President
James E. Orth......................... 49 Vice President
Maureen O'Connor Sullivan............. 51 Vice President, General Counsel and
Corporate Secretary
Richard A. Bachmann has been president and chief executive officer and
chairman of the board of directors since our inception in January 1998. Mr.
Bachmann began organizing our company in February 1997. From 1995 to January
1997, he served as director, president and chief operating officer of The
Louisiana Land and Exploration Company (LL&E), an independent oil and 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. Mr. Bachmann is also a director of Penn Virginia Corporation,
Superior Energy Services, Inc. and First Bank and Trust.
Suzanne V. Baer joined us in April 2000 as vice president and chief
financial officer. Ms. Baer has 30 years of financial management, investor
relations and treasury experience in the energy industry. From July 1998 until
March 2000, Ms. Baer was vice president and treasurer of Burlington Resources
Inc. and, from October 1997 to July 1998, was vice president and assistant
treasurer of Burlington Resources. Prior to the merger of LL&E with Burlington
Resources in 1997, Ms. Baer was vice president and treasurer of LL&E since 1995.
Clinton W. Coldren joined us in March 1998 as vice president overseeing
various operating activities. Mr. Coldren has 24 years experience in the energy
industry. Immediately prior to joining us, Mr. Coldren operated a small,
family-owned project management company, Cenergy Corporation, since 1992. Mr.
Coldren managed drilling and completion operations for Consolidated Natural Gas
Company and participated in the establishment of Gulf Oil's Drilling Technology
Center. He began his career as a field production engineer, focused on domestic
operating bases, specifically the Louisiana and Texas Gulf Coast.
Wayne A. Greenwalt joined us as vice president in August 1999 overseeing
various operating activities. Mr. Greenwalt has 28 years of experience in the
energy industry. He worked in domestic and international assignments at Pennzoil
from 1992 to August 1999. Mr. Greenwalt was with LL&E from 1977 until joining
Pennzoil in 1992. Mr. Greenwalt began his career with Shell Oil as an operations
and reservoir engineer.
John H. McCandless joined us as vice president in January 1998 overseeing
various operating activities. Mr. McCandless has 30 years of diversified
professional experience in petroleum geology. From 1976 until joining us in
1998, he was a self-employed sole proprietor, originating and evaluating oil and
gas prospects, developing producing properties and creating and executing 3-D
seismic exploration and exploitation projects in the U.S. Gulf Coast area. He
served in various geological positions with Texaco and Southland Royalty Company
from 1970 to 1976, when he established his independent practice.
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James E. Orth joined us as vice president in January 1998 overseeing
various operating activities. Prior to joining us, Mr. Orth served with LL&E and
its successor corporation, Burlington Resources, in various positions from 1980
to January 1998, including vice president of acquisitions and divestitures and
vice president of worldwide production. Prior to being named vice president, Mr.
Orth was general manager of LL&E's Rocky Mountain operations. Mr. Orth began his
career with Texaco as a field engineer and engineering supervisor for Gulf Coast
operations and has over 27 years of industry experience.
Maureen O'Connor Sullivan joined us as vice president, general counsel and
corporate secretary in October 2000. Beginning in August 1997, Ms. Sullivan
served as senior vice president, general counsel and secretary of Halter Marine
Group, Inc., a firm engaged in engineering and construction for the offshore
energy sector, until its merger with Friede Goldman International, Inc. in
November 1999, at which time Ms. Sullivan was appointed senior vice president,
general counsel and secretary of the combined company, Friede Goldman Halter,
Inc. From 1979 through August 1997, Ms. Sullivan was in private practice with
the McGlinchey Stafford law firm, where she was a partner specializing in
business law and complex commercial litigation from 1984, the founder and
manager of the firm's Dallas office from 1989, and a member of its management
committee from 1990.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Concurrent with the pricing of our initial public offering on November 1,
2000, our common stock was 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
----- -----
2000
First Quarter............................................. -- --
Second Quarter............................................ -- --
Third Quarter............................................. -- --
Fourth Quarter............................................ 15.38 10.00
2001
First Quarter (through March 5, 2001)..................... 13.19 10.25
On March 5, 2001, the last reported sale price of our common stock on the
New York Stock Exchange Composite Tape was $11.00 per share.
As of March 5, 2001, there were approximately 79 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 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.
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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 "Management's Discussion and
Analysis of Financial Condition and Results of Operations" in Item 7 of this
Report.
JANUARY 29, 1998
YEARS ENDED DECEMBER 31, (INCEPTION) TO
------------------------ DECEMBER 31,
2000 1999 1998
----------- ---------- ----------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Statement of Operations Data:
Revenue............................................... $ 103,072 $ 9,509 $ 1,966
Loss from operations(1)............................... (8,721) (835) (311)
Net loss.............................................. $ (18,684) $ (2,284) $ (705)
========= ======== ========
Net loss available to common stockholders(2).......... $ (25,387) $ (3,120) $ (705)
========= ======== ========
Basic net loss per common share....................... $ (2.27) $ (0.22) $ (0.09)
========= ======== ========
Diluted net loss per common share..................... $ (2.27) $ (0.22) $ (0.09)
========= ======== ========
Cash flows provided by (used in):
Operating activities.................................. $ 50,703 $ (4,594) $ 8,044
Investing activities.................................. (130,378) (19,233) (27,081)
Financing activities.................................. 60,742 45,457 19,689
AS OF DECEMBER 31,
----------------------------
2000 1999 1998
-------- ------- -------
(IN THOUSANDS)
Balance Sheet Data:
Total assets.............................................. $208,149 $69,276 $40,015
Long-term debt, excluding current maturities.............. 100 10,150 20,000
Redeemable preferred stock................................ -- 56,475 --
Stockholders' equity...................................... 150,591 (3,815) (694)
- ---------------
(1) The 2000 loss from operations includes a one time non-cash stock
compensation charge for shares released from escrow to management and
director stockholders of $38.2 million and a non-cash charge of $2.1 million
for bonus shares awarded to employees at the time of the initial public
offering. The after-tax amount of these charges totaled $39.5 million.
Although these charges reduced our net income they increased
paid-in-capital, and thus did not result in a net reduction of total
stockholders' equity.
(2) Net loss available to common stockholders is computed by subtracting
preferred stock dividends and accretion of issuance costs for the years
ended December 31, 2000 of $6.7 million and December 31, 1999 of $0.8
million.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
We are an independent oil and natural gas exploration and production
company concentrated in the shallow to moderate depth waters of the central
region of the Gulf of Mexico Shelf. We were incorporated in January 1998.
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.
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In March 2000, we acquired Unocal Corporation's 80% interest in South
Timbalier 26 for approximately $44.9 million. In April 2000, we sold to Vastar
Resources, Inc. 50% of our working interest in South Timbalier 26 for
approximately $36.6 million. Additionally, on March 31, 2000, we closed the
purchase of an average 96.1% working interest in the East Bay field from Ocean
Energy, Inc. for $72.3 million.
We have experienced substantial revenue and production growth as a result
of the East Bay and South Timbalier 26 acquisitions. Although the East Bay and
South Timbalier 26 acquisitions had an effective date of January 1, 2000, we
reduced our purchase price on March 31, 2000, by the net cash flows collected by
the sellers (Unocal and Ocean Energy) during the period from January 1, 2000
through March 31, 2000. Accordingly, we did not include the results of
operations from these acquisitions in our operational or financial results prior
to March 31, 2000.
In September 2000, we closed the acquisition of Texaco Inc.'s 14.5% working
interest in South Timbalier 22, 23 and 27. We acquired this interest effective
January 1, 2000 for a cash price of approximately $2.2 million, net of closing
adjustments.
For the foregoing reasons, the East Bay, South Timbalier 26 and South
Timbalier 22, 23 and 27 acquisitions will affect the comparability of our
historical results of operations with results of operations in 2000 and future
periods.
On November 1, 2000, we priced our initial public offering of 5.75 million
shares of common stock and commenced trading the following day. After payment of
underwriting discounts and commissions, we received net proceeds of $80.2
million on November 7, 2000. With the proceeds, we retired outstanding debt of
$73.9 million and paid approximately $5.1 million to redeem outstanding Series C
Preferred Stock.
Our revenue, profitability and future growth rate depend substantially on
factors beyond our control, such as 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 1 for a more detailed
discussion of these risks.
RESULTS OF OPERATIONS
The following table presents information about our oil and gas operations.
YEARS ENDED JANUARY 29, 1998
DECEMBER 31, (INCEPTION) TO
----------------- DECEMBER 31,
2000 1999 1998
-------- ------ ----------------
Net Production (per day):
Oil (Bbls)....................................... 7,622 1,051 534
Natural gas (Mcf)................................ 15,781 2,277 1,311
Total (Boe).............................. 10,252 1,431 753
Oil & Gas Revenues (in thousands):
Oil.............................................. $ 71,977 $6,678 $1,268
Natural Gas...................................... 28,751 1,806 524
Total.................................... 100,728 8,484 1,792
Average Sales Prices:
Oil (per Bbl)(1)................................. $ 25.80 $17.39 $13.21
Natural gas (per Mcf)............................ 4.98 2.17 2.20
Total (per Boe).......................... 26.84 16.22 13.18
Average Costs (per Boe):
Lease operating expense.......................... $ 6.42 $ 3.14 $ 2.64
Taxes, other than on earnings.................... 1.69 -- --
Depreciation, depletion, and amortization........ 6.82 8.65 9.58
General and administrative expense (exclusive of
stock-based compensation)..................... 2.95 4.99 4.52
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- ---------------
(1) Net of the effect of hedging transactions, which reduced oil prices realized
by $3.80 per barrel in 2000.
Production
Crude Oil and Condensate. Our net oil production for 2000 increased to
7,622 Bbls per day from 1,051 Bbls per day in 1999. The increase was the result
of the acquisitions combined with 98 successful well operations, which commenced
production in 2000, and was partially offset by natural declines from other
producing wells.
Our net oil production for 1999 increased 517 Bbls per day from 534 Bbls
per day in 1998. The increase was the result of 14 successful well operations,
which commenced production during 1999.
Natural Gas. Our net natural gas production for 2000 increased to 15,781
Mcf per day from 2,277 Mcf per day in 1999. The increase was the result of the
acquisitions combined with 98 successful well operations, which commenced
production in 2000 and was partially offset by natural declines from other
producing wells.
Our net natural gas production for 1999 increased 966 Mcf per day from
1,311 Mcf per day in 1998. The increase was the result of 14 successful well
operations, which commenced production in 1999.
Realized Prices
Crude Oil and Condensate. Our average realized oil price in 2000 was
$25.80 per Bbl, an increase of 48% over an average realized price of $17.39 per
Bbl in 1999. Hedging activities in 2000 reduced oil price realizations by $3.80
per Bbl or 13% from the $29.60 per Bbl that would have otherwise been received.
We did not have any hedging contracts in place in 1999.
Our average realized oil price in 1999 of $17.39 per Bbl increased 32% over
an average realized price of $13.21 per Bbl in 1998. We did not have any hedging
contracts in place in 1999 or 1998.
Natural Gas. Our average realized natural gas price in 2000 was $4.98 per
Mcf, an increase of 130% over an average realized price of $2.17 per Mcf in
1999. We did not have hedging positions for natural gas related to 2000 or 1999
production.
Our average realized gas price in 1999 of $2.17 per Mcf decreased 1% from
an average realized price of $2.20 per Mcf in 1998. We did not have hedging
positions for natural gas related to 1999 or 1998 production.
Net Income and Revenues
We recognized a net loss of $18.7 million in 2000 compared to a net loss of
$2.3 million in 1999. The net loss in 2000 is attributed to one-time non-cash
stock compensation charges related to the initial public offering. The Company
recognized charges of $38.2 million related to the release to management and
director stockholders of shares placed in escrow in 1999 and $2.1 million
related to bonus shares awarded to employees. After tax, these charges totaled
$39.5 million. Although these charges reduced our net income, they increased
paid-in-capital and thus did not result in a net reduction of total
stockholders' equity. Excluding the effect of the charges, we had net income of
$20.8 million in 2000.
Our oil and natural gas revenues increased to $100.7 million in 2000, from
$8.5 million in 1999. The increase in revenues was primarily due to sharp
increases in commodity prices coupled with higher production volumes resulting
from acquisitions and drilling activities. The impact of these increases was
partially offset by higher costs associated with increased production volumes.
We recognized a net loss of $2.3 million in 1999 compared to a net loss of
$0.7 million in 1998. Our oil and natural gas revenues increased to $8.5 million
in 1999, an increase from $1.8 million in 1998. The increases in revenues and
net loss in 1999 were primarily due to the fact that our operations did not
commence until June of 1998, combined with increases in oil prices.
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Operating Expenses
Operating expenses were impacted by the following:
- Lease operating expense increased $22.5 million to $24.1 million in 2000.
The increase was primarily attributable to the acquisitions and the
additional production from 98 successful well operations, which commenced
production in 2000.
Lease operating expense increased $1.2 million in 1999 to $1.6 million.
The increase was primarily attributable to the additional production from
14 successful well operations, which commenced production during 1999.
- Production taxes were $6.3 million in 2000. The production taxes are
attributable to the acquisition of the East Bay field where a portion of
the production is subject to Louisiana severance taxes and property taxes
and to the expansion of our drill-to-earn activities at Greater Bay
Marchand to areas located in Louisiana state waters, which are also
subject to severance taxes. There were no such taxes in 1999 and 1998.
- Depreciation, depletion and amortization increased $21.1 million to $25.6
million in 2000. The increase was primarily due to increased production
volumes and an increased depreciable asset base resulting from the
acquisitions.
Depreciation, depletion and amortization increased $3.2 million to $4.5
million in 1999. The increase was primarily due to a substantial increase
in production volumes during 1999.
- Other general and administrative expenses increased $8.5 million to $11.1
million in 2000. The increase was primarily due to the hiring of
additional personnel ($4.0 million), increased consultant fees ($2.4
million), increased insurance costs ($1.4 million) and other costs
associated with our acquisition of the East Bay field and the additional
interest in the South Timbalier 26 field on March 31, 2000.
Other general and administrative expenses increased $2.0 million to $2.6
million in 1999. The increase was primarily related to employment-related
costs associated with an increase in personnel in late 1998 and 1999.
- Non-cash stock-based compensation expense of $43.0 million was recognized
in 2000. Of this expense, $2.8 million related to restricted stock and
stock option grants made in April and November 2000, $38.2 million
related to the release, at the completion of the initial public offering,
to management and director stockholders shares placed in escrow in 1999
and $2.1 million related to bonus shares awarded to employees upon
completion of the initial public offering.
Other Income and Expense
Interest. Interest expense increased $4.5 million to $7.4 million in 2000.
The increase in interest expense is a result of an increase in long-term debt
outstanding during 2000 related to our acquisitions.
Interest expense increased $2.1 million to $2.9 million in 1999 as a result
of additional borrowings under our credit agreement during 1999.
Gain on Sale of Oil and Gas Assets. On April 20, 2000, we sold 50% of our
working interest in the South Timbalier 26 field, resulting in a gain of
approximately $7.8 million. There were no sales in 1999 or 1998.
LIQUIDITY AND CAPITAL RESOURCES
We intend to use cash flows from operations and our revolving line of
credit to fund our future development, exploration and acquisition activities.
Our recent acquisitions of the East Bay field, the South Timbalier 22, 23 and 27
interests and the additional interest in South Timbalier 26 field significantly
impacted our cash flows from operations. Our future cash flow from operations
will depend on our ability to maintain
23
25
and increase production through our development and exploration drilling
program, as well as the prices of oil and natural gas.
Our credit facility consists of a $65 million revolving line of credit with
a group of banks available through March 30, 2003 (bank facility). The bank
facility bears interest at LIBOR plus 1.25% to 2.25%, based on the level of and
utilization of the line of credit.
At December 31, 2000, we had $64.9 million of credit capacity available
under this bank facility. The weighted average interest rate at December 31,
2000 was 9.5%. The bank facility is secured by substantially all of our assets.
Net cash of $130 million used in investing activities in 2000 included oil
and gas property capital and exploration expenditures of $45.5 million and the
East Bay, South Timbalier 26 and South Timbalier 22, 23 and 27 acquisitions
(prior to the sale to Vastar) of $119.9 million. Exploration expenditures
resulting from dry holes are excluded from operating cash flows and included in
investing activities. These capital expenditures were partially offset by $36.6
million in proceeds from the sale of a 50% interest in South Timbalier 26.
During 2000, we completed 30 drilling projects and 78 recompletion/workover
projects, of which 98 were successful. During 1999, we completed six drilling
projects and 14 recompletion/workover projects, 14 of which were successful.
Cash and cash equivalents at December 31, 2000 were $3.3 million.
Our 2001 capital expenditure budget is focused on exploitation activities
on prospects with multiple reservoirs, which we expect to increase our
probability of success and to lead to accelerated payback of our investment.
These exploitation activities also provide exploratory potential in deeper
geologic formations. Our capital expenditure plans for 2001 are currently
estimated to be approximately $120 million. Actual levels of capital
expenditures may vary significantly due to many factors, including drilling
results, oil and natural gas prices, industry conditions, participation by other
working interest owners and the prices of drilling rigs and other oilfield goods
and services.
We have experienced and expect to continue to experience substantial
working capital requirements, primarily due to our active capital expenditure
program. We believe that the proceeds from working capital, cash flows from
operations and borrowings under our bank facility will be sufficient to meet our
capital requirements through the end of 2001. However, additional financing may
be required in the future to fund our growth and capital expenditures.
HEDGING ACTIVITIES
We have entered into hedging transactions for our oil and natural gas
production to reduce our exposure to fluctuations in the price of oil and
natural gas. Through December 2000, our hedging transactions for oil consisted
of financially-settled crude oil forward sales contracts with major financial
institutions as required by our bank facility entered into in connection with
the acquisitions of the East Bay field and additional interests in the South
Timbalier 26 field.
We financially settle our crude oil forward sales contracts based on the
average of the reported settlement prices for West Texas Intermediate crude on
the NYMEX for each month. With our hedges, 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.
In October and November 2000, we entered into financially settled zero-cost
collar contracts with major financial institutions maturing monthly from January
2001 through December 2001 related to the net sale of 3,650,000 mmbtu of natural
gas with a floor of $3.00 per mmbtu and a cap of $9.00 per mmbtu. Had these
contracts been terminated at December 31, 2000, we estimate the loss would have
been $1.3 million. We will financially settle our natural gas collar contracts
based on the average of the reported settlement prices for Henry Hub natural gas
on the NYMEX for the last three trading days of each month. With our hedges, 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 for the collar.
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26
To qualify as a hedge, these contracts must correlate to anticipated future
production such that our exposure to the effects of commodity price changes is
reduced. The gains and losses related to these hedging transactions are
recognized as adjustments to the revenue recorded for the related production. We
use the accrual method of accounting for derivative commodity instruments. At
inception, any contract premiums paid are recorded as prepaid expenses and, upon
settlement of the hedged production month, are included with the gains and
losses on the contracts in the oil and natural gas revenues.
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.
Additionally, hedging transactions may expose us to cash margin
requirements. We use primarily over-the-counter hedge instruments with major
financial institutions where margin requirements have been negotiated.
Typically, we have negotiated volumetrically based credit limits where no cash
margin is required.
As of December 31, 2000, we had contracts maturing monthly through May 2001
related to the sale of 923,000 barrels of oil at an average price of $22.95 per
barrel. Had these contracts been terminated at December 31, 2000, we estimate
the loss would have been $2.5 million.
As of December 31, 2000, the hedged oil and natural gas volume approximated
26% of our estimated production from proved reserves through 2001.
NEW ACCOUNTING POLICIES
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 (Statement 133), "Accounting for
Derivative Instruments and Hedging Activities." Statement 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
Statement 133 requires that all derivatives be recognized as either assets or
liabilities in the balance sheet and measured at fair value. The accounting for
changes in the fair value of a derivative (that is, gains or losses) depends on
the intended use of the derivative and resulting designation. If certain
conditions are met, a derivative may be specifically designated as a "fair value
hedge," "cash flow hedge," or a hedge of the foreign currency exposure of a net
investment in a foreign operation. Statement 133 amends and supersedes a number
of existing Statements of Financial Accounting Standards, and nullifies or
modifies the consensus reached in a number of issues addressed by the Emerging
Issues Task Force. Statement 133, as amended, is effective for all fiscal
quarters of fiscal years beginning after June 15, 2000.
We adopted Statement 133 effective January 1, 2001. Our oil and natural gas
derivative contracts qualify for hedge accounting treatment under Statement 133,
whereby changes in fair value will be recognized in other comprehensive income
(a component of stockholders' equity) until settled, when the resulting gains
and losses will be recorded in earnings. Any hedge ineffectiveness will be
charged currently to earnings; however, we believe that any ineffectiveness will
be immaterial. The effect on our earnings and other comprehensive income as the
result of the adoption of Statement 133 will vary from period to period and will
be dependent upon prevailing oil and gas prices, the volatility of forward
prices for oil and gas, the volumes of production hedged, and the time periods
covered by such hedges. We estimate that our transition adjustment resulting
from the new accounting treatment is a liability of approximately $3.8 million
and a corresponding debit of approximately $2.4 million, net of income tax, in
other comprehensive income. We do not expect Statement 133 to have a material
impact on the financial statements as a result of other contractual arrangements
that we are subject to.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 credit facility. Under our current policies,
we do not use interest rate derivative instruments to manage exposure to
interest rate changes. At December 31, 2000, all of our long-term debt had
variable interest rates.
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 commodity instruments to manage commodity price risks
associated with future oil and natural gas production. Our crude oil commodity
price hedging program uses financially settled crude oil forward sales contracts
and we do not use them for speculative purposes. As of December 31, 2000, we had
contracts maturing monthly through May 2001 related to the sale of 923,000
barrels of oil at an average price of $22.95 per barrel. Had these contracts
been terminated at December 31, 2000, we estimate the loss would have been $2.5
million.
In October and November 2000, we expanded our commodity price hedging
program to include natural gas hedging positions, which utilizes zero-cost
collar contracts and we do not use them for speculative purposes. As of December
31, 2000, we had contracts maturing monthly from January 2001 through December
2001 related to the net sale of 3,650,000 mmbtu of natural gas with a floor of
$3.00 per mmbtu and a cap of $9.00 per mmbtu. Had these contracts been
terminated at December 31, 2000, we estimate the loss would have been $1.3
million.
As of December 31, 2000, the hedged oil and natural gas volume approximated
26% of our estimated production from proved reserves through 2001.
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, 2000, the potential change
in the fair value of commodity derivative instruments assuming a 10% adverse
movement in the underlying commodity price is a $2.9 million increase in the
combined estimated loss.
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.
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GLOSSARY OF OIL AND NATURAL GAS TERMS
"3-D seismic" Geophysical data that depict the subsurface strata in three
dimensions. 3-D seismic typically provides a more detailed and accurate
interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
"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.
"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.
"Mmbtu" One million British Thermal Units.
"Mmcf" One million cubic feet of natural gas.
"payout" Generally refers to the recovery by the incurring party of its
costs of drilling, completing, equipping and operating a well before another
party's participation in the benefits of the well commences or is increased to a
new level.
"plugging and abandonment" Refers to the sealing off of fluids in the
strata penetrated by a well so that the fluids from one stratum will not escape
into another or to the surface. Regulations of many states require plugging of
abandoned wells.
"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.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF MANAGEMENT
The consolidated financial statements of Energy Partners, Ltd. and
subsidiary and the related information included in this Annual Report have been
prepared by management in conformity with accounting principles generally
accepted in the United States of America. The financial statements include
amounts that are management's best estimates and judgments.
Management maintains a system of internal control including internal
accounting control that provides management with reasonable assurance that our
assets are protected and that published financial statements are reliable and
free of material misstatement. Management is responsible for the effectiveness
of internal controls. This is accomplished through established codes of conduct,
accounting and other control systems, policies and procedures, employee
selection and training, appropriate delegation of authority and segregation of
responsibilities.
The Audit Committee of the Board of Directors, composed solely of directors
who are not officers or employees, meets regularly with the independent
certified public accountants, financial management and counsel. To ensure
complete independence, the certified public accountants have full and free
access to the Audit Committee to discuss the results of their audits, the
adequacy of internal controls and the quality of financial reporting.
Our independent certified public accountants provide an objective
independent review by their audit of the Company's financial statements. Their
audit is conducted in accordance with generally accepted auditing standards and
includes a review of internal accounting controls to the extent deemed necessary
for the purposes of their audit.
/s/ RICHARD A. BACHMANN /s/ SUZANNE V. BAER
- --------------------------------------------- ---------------------------------------------
Richard A. Bachmann Suzanne V. Baer
Chairman, President and Vice President and
Chief Executive Officer Chief Financial Officer
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INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Energy Partners, Ltd.:
We have audited the accompanying consolidated balance sheets of Energy
Partners, Ltd. and subsidiary as of December 31, 2000 and 1999, and the related
consolidated statements of operations, changes in stockholders' equity, and cash
flows for the two years ended December 31, 2000 and the period from January 29,
1998 (inception) to December 31, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audits 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 subsidiary as of December 31, 2000 and 1999, and the results
of their operations and their cash flows for the two years ended December 31,
2000 and the period from January 29, 1998 (inception) to December 31, 1998, in
conformity with accounting principles generally accepted in the United States of
America.
KPMG LLP
New Orleans, Louisiana
February 9, 2001
29
31
ENERGY PARTNERS, LTD. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2000 AND 1999
(IN THOUSANDS, EXCEPT SHARE DATA)
ASSETS
2000 1999
-------- -------
Current assets:
Cash and cash equivalents................................. $ 3,349 $22,282
Trade accounts receivable................................. 28,930 7,971
Prepaid expenses.......................................... 1,465 301
-------- -------
Total current assets.............................. 33,744 30,554
Property and equipment, at cost under the successful efforts
method of accounting for oil and gas properties........... 195,714 42,241
Less accumulated depreciation, depletion and amortization... (24,927) (5,627)
-------- -------
Net property and equipment........................ 170,787 36,614
Other assets................................................ 1,357 --
Deferred income taxes....................................... -- 1,545
Deferred financing costs -- net of accumulated amortization
of $1,027 in 2000 and $108 in 1999........................ 2,261 563
-------- -------
$208,149 $69,276
======== =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 17,322 $ 4,215
Accrued expenses.......................................... 24,639 1,794
-------- -------
Total current liabilities......................... 41,961 6,009
Long-term debt.............................................. 100 10,150
Deferred income taxes....................................... 9,207 --
Other....................................................... 6,290 457
-------- -------
57,558 16,616
-------- -------
Redeemable Preferred Stock, $1 par value, authorized
1,700,000 shares; issued and outstanding: 2000 -- no
shares; 1999 -- 600,000 shares;........................... -- 56,475
Stockholders' equity:
Common stock, par value $0.01 per share. Authorized
50,000,000 shares; issued and outstanding:
2000 -- 26,400,147 shares; 1999 -- 11,768,280
shares;................................................ 264 118
Additional paid-in capital................................ 179,679 32
Accumulated deficit....................................... (29,352) (3,965)
-------- -------
Total stockholders' equity........................ 150,591 (3,815)
-------- -------
$208,149 $69,276
======== =======
See accompanying notes to consolidated financial statements.
30
32
ENERGY PARTNERS, LTD. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2000 AND 1999 AND THE PERIOD FROM JANUARY 29, 1998
(INCEPTION) TO DECEMBER 31, 1998
(IN THOUSANDS, EXCEPT PER SHARE DATA)
2000 1999 1998
-------- ------- -------
Revenue:
Oil and gas............................................... $100,728 $ 8,484 $ 1,792
Other..................................................... 2,344 1,025 174
-------- ------- -------
103,072 9,509 1,966
-------- ------- -------
Costs and expenses:
Lease operating........................................... 24,077 1,640 359
Taxes, other than on earnings............................. 6,327 -- --
Exploration expenditures and dry hole costs............... 1,703 1,570 --
Depreciation, depletion and amortization.................. 25,595 4,525 1,303
General and administrative:
Stock-based compensation............................... 2,757 -- --
Other general and administrative....................... 11,058 2,609 615
Stock-based compensation related to public offering.... 40,276 -- --
-------- ------- -------
Total costs and expenses.......................... 111,793 10,344 2,277
-------- ------- -------
Loss from operations........................................ (8,721) (835) (311)
-------- ------- -------
Other income (expense):
Interest income........................................... 596 312 49
Interest expense.......................................... (7,438) (2,947) (802)
Gain on sale of oil and gas assets........................ 7,781 -- --
-------- ------- -------
939 (2,635) (753)
-------- ------- -------
Loss before income taxes.......................... (7,782) (3,470) (1,064)
Income taxes................................................ (10,902) 1,186 359
-------- ------- -------
Net loss.......................................... (18,684) (2,284) (705)
Less dividends earned on Preferred Stock and accretion of
issuance costs............................................ (6,703) (836) --
-------- ------- -------
Net loss available to common stockholders......... $(25,387) $(3,120) $ (705)
======== ======= =======
Basic loss per share........................................ $ (2.27) $ (0.22) $ (0.09)
======== ======= =======
Diluted loss per share...................................... $ (2.27) $ (0.22) $ (0.09)
======== ======= =======
Weighted average common shares used in computing loss per
share:
Basic..................................................... 11,160 14,247 7,427
======== ======= =======
Diluted................................................... 11,160 14,247 7,427
======== ======= =======
See accompanying notes to consolidated financial statements.
31
33
ENERGY PARTNERS, LTD. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2000 AND 1999 AND THE PERIOD FROM JANUARY 29, 1998
(INCEPTION) TO DECEMBER 31, 1998
(IN THOUSANDS)
ADDITIONAL
COMMON COMMON PAID-IN ACCUMULATED
STOCK SHARES STOCK CAPITAL DEFICIT TOTAL
------------ ------ ---------- ----------- --------
Balance at inception................... -- $ -- $ -- $ -- $ --
Stock issued for cash................ 15,060 10 -- -- 10
Establishment of $0.01 par value..... -- 140 -- (140) --
Net loss............................. -- -- -- (705) (705)
------ ---- -------- -------- --------
Balance at December 31, 1998........... 15,060 150 -- (845) (695)
EIF Shares cancelled................. (3,292) (32) 32 -- --
Dividends earned on Preferred
Stock............................. -- -- -- (800) (800)
Accretion of Preferred Stock issuance
costs............................. -- -- -- (36) (36)
Net loss............................. -- -- -- (2,284) (2,284)
------ ---- -------- -------- --------
Balance at December 31, 1999........... 11,768 118 32 (3,965) (3,815)
Dividends earned on Preferred
Stock............................. -- -- -- (6,340) (6,340)
Accretion of Preferred Stock issuance
costs............................. -- -- -- (363) (363)
Stock issued for cash................ 5,750 58 78,623 -- 78,681
Conversion of Preferred Stock........ 9,388 94 57,985 -- 58,079
Stock-based compensation............. 113 1 2,756 -- 2,757
Stock-based compensation related to
public offering................... 140 1 40,275 -- 40,276
Shares cancelled..................... (759) (8) 8 -- --
Net loss............................. -- -- -- (18,684) (18,684)
------ ---- -------- -------- --------
Balance at December 31, 2000........... 26,400 $264 $179,679 $(29,352) $150,591
====== ==== ======== ======== ========
See accompanying notes to consolidated financial statements.
32
34
ENERGY PARTNERS, LTD. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2000 AND 1999 AND THE PERIOD FROM JANUARY 29, 1998
(INCEPTION) TO DECEMBER 31, 1998
(IN THOUSANDS)
2000 1999 1998
--------- -------- --------
Cash flows from operating activities:
Net loss.................................................. $ (18,684) $ (2,284) $ (705)
Adjustments to reconcile net loss to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization............... 25,595 4,525 1,303
Gain on sale of oil and gas assets..................... (7,781) -- --
Stock-based compensation............................... 43,033 -- --
Deferred income taxes.................................. 10,752 (1,186) (359)
Dry hole costs......................................... 1,657 1,570 --
Amortization of deferred financing costs............... 1,090 91 --
--------- -------- --------
55,662 2,716 239
Changes in operating assets and liabilities:
Trade accounts receivable............................ (20,960) 4,782 (12,753)
Prepaid expenses..................................... (1,164) (216) (85)
Other assets......................................... (1,357) -- --
Accounts payable and accrued expenses................ 18,264 (12,133) 20,643
Other liabilities.................................... 258 257 --
--------- -------- --------
Net cash provided by (used in) operating
activities...................................... 50,703 (4,594) 8,044
--------- -------- --------
Cash flows used in investing activities
Property acquisitions..................................... (119,872) (1,410) (9,045)
Exploration and development expenditures.................. (45,488) (17,823) (18,036)
Other property and equipment additions.................... (1,628) -- --
Proceeds from sale of oil and gas assets.................. 36,610 -- --
--------- -------- --------
Net cash used in investing activities............. (130,378) (19,233) (27,081)
--------- -------- --------
Cash flows from financing activities:
Deferred financing costs.................................. (2,836) (332) (321)
Repayments of long-term debt.............................. (118,050) (30,300) --
Proceeds from long-term debt.............................. 108,000 20,450 20,000
Net proceeds from issuance of common stock................ 78,681 -- 10
Net payment of Preferred Stock dividends.................. (5,053) -- --
Net proceeds from issuance of Preferred Stock............. -- 55,639 --
--------- -------- --------
Net cash provided by financing activities......... 60,742 45,457 19,689
--------- -------- --------
Net (decrease) increase in cash and cash
equivalents..................................... (18,933) 21,630 652
Cash and cash equivalents at beginning of period............ 22,282 652 --
--------- -------- --------
Cash and cash equivalents at end of period.................. $ 3,349 $ 22,282 $ 652
========= ======== ========
Supplemental cash flow information:
Interest paid, net of amounts capitalized................. $ 6,534 $ 3,192 $ 983
========= ======== ========
Income taxes paid......................................... $ 150 $ -- $ --
========= ======== ========
Supplemental disclosures of non-cash financing activities:
Dividends earned on Preferred Stock....................... $ 6,340 $ 800 $ --
========= ======== ========
Conversion of Preferred Stock............................. $ 58,079 $ -- $ --
========= ======== ========
See accompanying notes to consolidated financial statements.
33
35
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION
Energy Partners, Ltd. was incorporated on January 29, 1998 and is an
independent oil and natural gas exploration and production company concentrated
in the shallow to moderate depth waters in the central region of the Gulf of
Mexico Shelf; therefore, operations are directly affected by fluctuating
economic conditions of the domestic oil and natural gas industry.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Basis of Presentation
The consolidated financial statements include the accounts of Energy
Partners, Ltd., and EPL Pipeline L.L.C. (a wholly-owned subsidiary of Energy
Partners, Ltd.), collectively "the Company." EPL Pipeline L.L.C. was formed on
February 3, 2000 to own and operate pipeline assets acquired from Unocal
Corporation (Unocal) on March 31, 2000. All significant intercompany accounts
and transactions are eliminated in consolidation.
(b) Property and Equipment
The Company uses the successful efforts method of accounting for oil and
gas producing activities. Costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that find proved reserves, and
to drill and equip development wells are capitalized. Costs to drill exploratory
wells that do not find proved reserves, and geological and geophysical costs are
expensed.
Unproved oil and gas properties are periodically assessed on a
property-by-property basis, and a loss is recognized to the extent, if any, that
the cost of the property has been impaired. Capitalized costs of producing oil
and gas properties are depreciated and depleted by the units-of-production
method.
The Company assesses the impairment of capitalized costs of proved oil and
gas properties 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.
The estimated costs of dismantling and abandoning offshore oil and gas
properties are provided currently using the unit-of-production method. Such
provision is included in depletion, depreciation and amortization in the
accompanying statements of operations. As of December 31, 2000, such costs are
expected to be approximately $54.1 million. To date, $5.8 million has been
accrued and is included in other liabilities in the accompanying consolidated
balance sheets.
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.
(c) 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.
34
36
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(d) Other Revenue
The Company earned a management fee for its service as the operator of
South Timbalier 26 in which it held a 20% working interest through April 2000
and currently holds a 50% working interest. The management fee revenue was
recorded as the services were performed. Management fee revenue was $0.3
million, $0.8 million and $0.1 million in 2000, 1999 and 1998, respectively.
(e) Deferred Financing Costs
Costs incurred to obtain financing were deferred and are being 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
exercise of convertible preferred stock shares, the warrant and escrow shares
and the potential 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
revenues. Under this method of accounting, revenue is recorded based on the
Company's net working interest in field production. Deliveries of natural gas in
excess of the Company's working interest are recorded as liabilities and
under-deliveries are recorded as receivables. These amounts are not material at
December 31, 2000 and 1999.
(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, 2000 and 1999, interest-bearing cash equivalents
were approximately $7.6 million and $23.2 million, respectively. Exploration
expenditures incurred are excluded from operating cash flows and included in
investing activities.
(i) Hedging Activities and New Accounting Pronouncement
The Company uses derivative commodity instruments to manage commodity price
risks associated with future natural gas and crude oil production but does not
use them for speculative purposes. The Company's commodity price hedging program
utilizes forward sales contracts and zero-cost collars. To qualify as a hedge,
these contracts must correlate to anticipated future production such that the
Company's exposure to the effects of commodity price changes is reduced. The
gains and losses related to these hedging transactions are recognized as
adjustments to the revenue recorded for the related production. The Company uses
the accrual method of accounting for derivative commodity instruments. At
inception, any contract premiums paid are recorded as prepaid expenses and, upon
settlement of the hedged production month, are included with the gains and
losses on the contracts in oil and gas revenues.
In June of 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133 (Statement 133), "Accounting for
Derivative Instruments and Hedging Activities." Statement 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
Statement 133 requires that all derivatives be recognized as either assets or
liabilities in the balance sheet and measured at fair value. The accounting for
changes in the fair value of a derivative (that is, gains or losses) depends on
the intended use of
35
37
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the derivative and resulting designation. If certain conditions are met, a
derivative may be specifically designated as a "fair value hedge," "cash flow
hedge," or a hedge of the foreign currency exposure of a net investment in a
foreign operation. Statement 133 amends and supersedes a number of existing
Statements of Financial Accounting Standards, and nullifies or modifies the
consensus reached in a number of issues addressed by the Emerging Issues Task
Force. Statement 133, as amended, is effective for all fiscal quarters of fiscal
years beginning after June 15, 2000.
The Company adopted Statement 133 effective January 1, 2001. The Company's
oil and natural gas derivative contracts qualify for hedge accounting treatment
under Statement 133, whereby changes in fair value will be recognized in other
comprehensive income (a component of stockholders' equity) until settled, when
the resulting gains and losses will be recorded in earnings. Any hedge
ineffectiveness will be charged currently to earnings; however, the Company
believes that any ineffectiveness will be immaterial. The effect on earnings and
other comprehensive income as the result of the adoption of Statement 133 will
vary from period to period and will be dependent upon prevailing oil and gas
prices, the volatility of forward prices for oil and gas, the volumes of
production hedged, and the time periods covered by such hedges. The Company
estimates that our transition adjustment resulting from the new accounting
treatment is a liability of approximately $3.8 million and a corresponding debit
of approximately $2.4 million, net of income tax, in other comprehensive income.
The Company does not expect Statement 133 to have a material impact on the
financial statements as a result of other contractual arrangements that the
Company is subject to.
(j) 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.
(k) Reclassifications
Certain reclassifications have been made to the prior period financial
statements in order to conform to the classification adopted for reporting in
fiscal 2000.
(3) INITIAL PUBLIC OFFERING
On November 1, 2000, the Company priced its initial public offering of 5.75
million shares of common stock and commenced trading the following day. After
payment of underwriting discounts and commissions, the Company received net
proceeds of $80.2 million on November 7, 2000. With the proceeds, the Company
retired outstanding debt of $73.9 million and paid approximately $5.1 million to
redeem outstanding Series C Preferred Stock. In connection with the initial
public offering, the Company converted all outstanding Preferred Stock shares
into 9,388,367 shares of common stock.
In November 1999, as a requirement to complete the Preferred Stock
transaction discussed in note 5, management and director stockholders placed in
escrow 3,304,830 shares of common stock. These common shares were originally
issued for cash in early 1998, as part of the initial capitalization of the
Company, prior to the commencement of any significant operations by the Company.
All or a portion of these shares were to be released from escrow only upon the
attainment of specified reserve replacement targets or upon completion of a
qualifying public offering. On November 7, 2000, 2,545,500 shares were released
as a result of the initial public offering and the remaining shares were
cancelled. Non-cash compensation expense in the fourth quarter for the shares
released was approximately $38.2 million. In addition, at the time of the
initial public offering, the Company awarded 139,500 bonus shares to employees
and recognized non-cash compensation expense of approximately $2.1 million
related to these shares. Compensation expense was calculated using $15.00 per
share, the offering price for the Company's common stock.
36
38
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(4) PROPERTY AND EQUIPMENT
The following is a summary of property and equipment at December 31, 2000
and 1999:
2000 1999
-------- -------
(IN THOUSANDS)
Proved oil and gas properties............................... $193,001 $41,467
Unproved oil and gas properties............................. 289 --
Other....................................................... 2,424 774
-------- -------
195,714 42,241
Less accumulated depreciation, depletion and amortization... (24,927) (5,627)
-------- -------
Net property and equipment........................ $170,787 $36,614
======== =======
In June 1998, the Company commenced a drill-to-earn program with Chevron
covering Main Pass 122/133. It was a four-well drilling commitment. Under the
terms of the agreement, the Company retained 100% of Chevron's working interest
in the wells (Chevron's interests were 100% in two wells and 69% in the other
two wells). The Company is entitled to recoup its investment plus a specified
return through 75% of the production stream. Chevron is responsible for lease
operating costs out of their retained 25% production interest. At December 31,
2000, the Company's net investment was approximately $9.6 million and revenue
was approximately $4.1 million for the year ended December 31, 2000. Following
payout, which has not yet occurred, the Company's interest will decrease to 1%.
All oil and gas properties are collateral for long-term debt.
(5) REDEEMABLE PREFERRED STOCK
In 1999, the Company authorized 1,700,000 shares of preferred stock
(Preferred Stock) having a par value of $1.00 per share, of which 1,550,000
shares are designated as Series A and Series B Redeemable Cumulative Convertible
Preferred Stock and Series C Redeemable Cumulative Preferred Stock. The
remaining 150,000 shares are undesignated. In November 1999, the Company entered
into a stock purchase agreement whereby 600,000 shares of Series A and B
Preferred Stock were sold to Evercore Capital Partners L.P. (Evercore) for $60.0
million excluding issuance costs.
The Preferred Stock earned cumulative dividends of 10% annually on the
liquidation value of the Series A and B Preferred Stock plus dividends in
arrears. The dividends on the Series A Preferred Stock were payable in
additional fully paid and non-assessable shares (no further investment is
required by the stockholders) of Series C Preferred Stock, the dividends on the
Series B Preferred Stock were payable in additional fully paid and
non-assessable shares of Series B Preferred Stock and the dividends on the
Series C Preferred Stock were payable in cash. All accrued dividends were
recorded as an increase to the carrying value of the Preferred Stock. Through
November 7, 2000, there were $7.1 million of Preferred Stock dividends in
arrears, of which approximately $2.0 million or 155,470 shares were Series B
Preferred Stock recorded at fair value. These shares were converted to common
stock at the time of the public offering and the Series C preferred stock
dividends of approximately $5.1 million were paid in cash.
(6) ACQUISITIONS AND DISPOSITION
On March 31, 2000, the Company purchased an 80% working interest in South
Timbalier 26 from Unocal for approximately $44.9 million, which included $1.25
million for pipeline assets discussed in note 2. Additionally, on March 31,
2000, the Company purchased an average 96.1% working interest in East Bay Field
(East Bay) from Ocean Energy, Inc. for approximately $72.3 million. The entire
purchase price for both
37
39
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
acquisitions was allocated to property and equipment. The terms of the
acquisitions did not contain any contingent consideration, options or future
commitments.
On April 20, 2000, the Company sold 50% of its working interest in South
Timbalier 26 for approximately $36.6 million, resulting in a gain of
approximately $7.8 million. The proceeds from this sale were used to reduce the
borrowings under the reducing revolving line of credit.
The unaudited pro forma results of operations, assuming that such
acquisitions and disposition occurred on January 1 of the respective periods,
are as follows (in thousands, except per share amounts):
2000 1999
-------- -------
(UNAUDITED)
Pro forma:
Revenue................................................... $129,117 $78,719
Income from operations.................................... 11,162 22,489
Net income (loss)......................................... (4,790) 8,208
Basic earnings (loss) per common share.................... $ (1.03) $ 0.52
Diluted earnings (loss) per common share.................. $ (1.03) $ 0.35
The pro forma financial information does not purport to be indicative of
the results of operations that would have occurred had the acquisitions and
disposition taken place at the beginning of the periods presented or future
results of operations.
(7) LONG-TERM DEBT
In June 1999, the Company entered into a reducing revolving line of credit
with a group of banks (bank facility). In order to finance the acquisitions
discussed in note 6, the Company amended its bank facility. The bank facility,
as amended, provided for a $90.0 million reducing revolving line of credit with
interest at LIBOR plus 3.0% and a $25.0 million reducing bridge financing with
interest at LIBOR plus 5.5%. As stipulated in the bank facility, the proceeds
from the asset sale of $36.6 million were used to reduce the outstanding
borrowings to approximately $71.8 million. The bank facility provided for
monthly borrowing base reductions and for monthly principal payments to the
extent that the outstanding balance exceeded the borrowing base. In conjunction
with the initial public offering described in note 3, the outstanding borrowings
were repaid. The bank facility currently has a borrowing base of $65 million and
is available through March 31, 2003 with interest at LIBOR plus 1.25% to 2.25%.
The amount outstanding at December 31, 2000 was $0.1 million, which approximates
fair value.
On April 15, 1998, the Company entered into a $20.0 million financing
agreement with Energy Income Fund, L.P. (EIF). On February 10, 1999, the
financing agreement was amended to increase the facility to $25.0 million. On
November 17, 1999, in conjunction with the Preferred Stock transaction described
in note 5, the financing agreement was reduced to $10.0 million. The Company
used $15.0 million of the proceeds from the Preferred Stock transaction to pay
down the debt due to EIF. The remaining $10.0 million was repaid in November
2000 using proceeds from the initial public offering.
On November 17, 1999, EIF returned 3,291,720 shares of common stock as
required by the Preferred Stock transaction discussed in note 5 which were
cancelled. The amount originally paid by EIF for these shares of $32,377 was
reclassified to additional paid-in capital in 1999.
Also, on November 17, 1999, the Company issued a warrant to EIF to purchase
928,050 shares of common stock as required by the Preferred Stock transaction
discussed in note 5. The warrant was exercisable at approximately $6.50 per
share or through cashless exercise, subject to adjustment as specified in the
agreement, in whole or in part at any time for a period of 60 days after a
qualifying public offering. The
38
40
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
warrant was assigned no value at the date of issuance. EIF exercised its option
to convert the warrant in January 2001, receiving 466,245 shares of common
stock.
(8) 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. On November 17, 1999, as required by the Preferred Stock transaction
discussed in note 5, management and director stockholders placed in escrow
3,304,830 shares of common stock. These shares could not be voted by the
management and director stockholders and all or a portion would only be released
from escrow upon the attainment of specified reserve replacement targets or upon
the completion of a qualified public offering. Also, as a requirement of this
transaction, EIF returned 3,291,720 shares of common stock, which were
cancelled. All of these shares have been excluded from the calculation of
weighted average common shares from November 17, 1999. On November 7, 2000, as a
result of the initial public offering, 2,545,500 of the escrow shares were
returned to management and director stockholders and have been included in the
calculation of weighted average common shares from that date. The effect of the
preferred stock dividends and accretion of issuance costs on arriving at income
available to common stockholders was $6.7 million in 2000 and $0.8 million in
1999 and none in 1998.
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 exercise
of stock options and convertible preferred stock shares and the potential shares
that would have a dilutive effect on earnings per share. The number of dilutive
convertible preferred stock shares and stock awards used in computing diluted
earnings per share were none in 2000 and 1999 as these securities were
antidilutive.
On July 12, 2000, the Board of Directors approved a fifteen hundred-for-one
stock split on the Company's common stock to be effected by the distribution of
fifteen hundred shares for each share outstanding. On September 15, 2000, the
Company increased the number of authorized common shares from 20,000 to
50,000,000 and established a par value of $0.01 per share. All shares
outstanding, per share amounts and par value have been restated to reflect the
stock split and the establishment of a par value.
(9) HEDGING ACTIVITIES
The Company enters into hedging transactions with major financial
institutions to reduce exposure to fluctuations in the price of oil and natural
gas. Crude oil forward sales contracts are settled based on the average of the
reported settlement prices for West Texas Intermediate crude on the NYMEX for
each month. 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. As of December 31, 2000, the Company had contracts maturing
monthly through May 2001 related to the sale of 923,000 barrels of oil at an
average price of $22.95 per barrel. Had these contracts been terminated at
December 31, 2000, the estimated loss would have been $2.5 million.
In October and November 2000, the Company entered into financially settled
zero-cost collar contracts with major financial institutions maturing monthly
from January 2001 through December 2001 related to the net sale of 3,650,000
mmbtu of natural gas with a floor of $3.00 per mmbtu and a cap of $9.00 per
mmbtu. The Company will financially settle the natural gas collar contracts
based on the average of the reported settlement prices for Henry Hub natural gas
on the NYMEX for the last three trading days of each month. 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
39
41
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the settlement price for any settlement period is above the cap price for the
collar. Had these contracts been terminated at December 31, 2000, the estimated
the loss would have been $1.3 million.
For the year ended December 31, 2000, hedging activities reduced revenues
by $10.6 million. The Company did not have any hedging activities in 1999 and
1998.
(10) INCOME TAXES
Components of income tax expense (benefit) for the years ended December 31,
2000 and 1999 and the period ended December 31, 1998 are as follows:
CURRENT DEFERRED TOTAL
------- -------- -------
(IN THOUSANDS)
2000:
Federal................................................ $150 $10,230 $10,380
State.................................................. -- 522 522
---- ------- -------
$150 $10,752 $10,902
==== ======= =======
1999:
Federal................................................ $ -- $(1,186) $(1,186)
State.................................................. -- -- --
---- ------- -------
$ -- $(1,186) $(1,186)
==== ======= =======
1998:
Federal................................................ $ -- $ (359) $ (359)
State.................................................. -- -- --
---- ------- -------
$ -- $ (359) $ (359)
==== ======= =======
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
-----------------------------
2000 1999 1998
------- ------- -------
Expected tax rate........................................... (34.0)% (34.0)% (34.0)%
Stock-based compensation.................................... 168.3 -- --
State taxes................................................. 6.7 -- --
Other....................................................... (0.9) (0.2) 0.2
----- ----- -----
140.1% (34.2)% (33.8)%
===== ===== =====
40
42
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The tax effects of temporary differences that give rise to significant
portions of the net deferred tax asset (liability) at December 31, 2000 and 1999
are presented below:
2000 1999
-------- -------
(IN THOUSANDS)
Deferred tax assets:
Restricted stock awards and options....................... $ 1,504 --
Federal and state net operating loss carryforwards........ 9,792 7,529
Other..................................................... 185 --
Deferred tax liabilities:
Property, plant and equipment, principally due to
differences in depreciation............................ (20,688) (5,984)
-------- -------
Net deferred tax asset (liability)................ $ (9,207) $ 1,545
======== =======
At December 31, 2000, the Company had a net operating loss carryforward of
approximately $27.2 million, which is available to reduce future federal taxable
income through 2020. 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, reversal of taxable temporary differences and tax
planning strategies. As a result, no valuation allowance has been provided.
(11) EMPLOYEE BENEFIT PLANS
In April 2000, an employee, pursuant to her employment agreement, was
granted 90,000 shares of restricted stock and stock options to purchase 375,000
shares of common stock. One-third of the restricted stock granted vested upon
the execution of the employment agreement and one-third will vest on the first
and second anniversary of the agreement. The stock options vest and are
exercisable at the prices as follows: 150,000 shares at $7.67 per share after
one year, 150,000 shares at $8.82 per share after two years and the remaining
shares at $10.14 after three years. The grant date fair value of the restricted
stock and options was $17.00. In addition, pursuant to her employment agreement,
a second employee was granted 23,334 shares of restricted stock upon closing of
the initial public offering, 6,667 of which will vest on the second anniversary
of the employment agreement and the remainder of which will vest on the third
anniversary of the employment agreement. The Company has recognized non-cash
compensation expense in 2000 of $2.8 million related to the restricted stock and
stock option grants. At December 31, 2000, there was $2.3 million of deferred
stock based compensation expense related to these awards, which will be
recognized over the remaining vesting period.
The board of directors adopted the 2000 Long Term Stock Incentive Plan on
September 12, 2000, and the stockholders approved the plan on September 15,
2000. The plan provides for awards of options to purchase shares of the
Company's common stock and performance shares. The plan 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 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 is 2,627,130 and includes the grant of options discussed
above.
The board of directors also adopted the 2000 stock option plan for
non-employee directors on September 12, 2000, and the stockholders approved the
plan on September 15, 2000. The plan provides for automatic grants of stock
options to members of the board of directors who are not employees of the
Company or any subsidiary. An initial grant of a stock option to purchase 4,000
shares of our common stock was made to each non-employee director upon
consummation of the public offering. An initial grant of a stock option to
purchase 2,000 shares will also be made to each person who becomes a
non-employee director after the
41
43
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
effective date upon his or her initial election or appointment. After the
initial grant, each non-employee director will receive an additional grant of a
stock option to purchase 4,000 shares of our common stock immediately following
each subsequent annual meeting. All stock options granted under the plan will
have a per share exercise price equal to the fair market value of a share of
common stock on the date of grant (as determined by the committee appointed to
administer the plan), will be fully vested and immediately exercisable, and will
expire on the earlier of (i) ten years from the date of grant or (ii) 36 months
after the optionee ceases to be a director for any reason. For initial grants,
fair market value will be the public offering price. The total number of shares
of our common stock that may be issued under the plan is 250,000, subject to
adjustment in the case of certain corporate transactions and events.
A summary of stock options granted under the incentive plans for the year
ended December 31, 2000 is as follows:
WEIGHTED WEIGHTED
AVERAGE AVERAGE
NUMBER OF EXERCISE GRANT DATE
SHARES PRICE FAIR VALUE
--------- -------- ----------
Outstanding at beginning of year..................... -- $ -- $ --
Granted.............................................. 568,097 $10.77 $16.30
Exercised............................................ -- $ -- $ --
Forfeited............................................ -- $ -- $ --
--------- ------ ------
Outstanding at end of year........................... 568,097 $10.77 $16.30
========= ====== ======
Exercisable at end of year........................... 28,000 $15.00 $15.00
========= ====== ======
Available for future grants.......................... 2,309,033
=========
A summary of information regarding stock options outstanding at December
31, 2000 is as follows:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
---------------------- -------------------
RANGE OF REMAINING WEIGHTED WEIGHTED
EXERCISE CONTRACTUAL AVERAGE AVERAGE
PRICES SHARES LIFE PRICE SHARES PRICE
- -------- ------- ----------- -------- ------- ---------
$7.67-$8.82......................... 300,000 5 years $ 8.25 -- --
$10.14-$15.00....................... 268,097 5-10 years $13.60 28,000 $15.00
The Company accounts for its stock-based compensation in accordance with
Accounting Principles Board's Opinion No. 25, "Accounting For Stock Issued To
Employees" (Opinion No. 25). However, Statement of Financial Accounting
Standards No. 123 (Statement 123), "Accounting For Stock-Based Compensation"
permits the continued use of the intrinsic value-based method prescribed by
Opinion No. 25 but requires additional disclosures, including pro forma
calculations of earnings and net earnings per share as if the fair value method
of accounting prescribed by FAS No. 123 had been applied. (in thousands, except
per share amounts).
AS REPORTED PRO FORMA
----------- ---------
2000 2000
----------- ---------
Net loss.................................................... $(18,684) $(18,872)
Basic loss per share........................................ $ (2.27) $ (2.29)
Diluted loss per share...................................... $ (2.27) $ (2.29)
Average fair value of grants during the year................ $ -- $ 4.68
Black-Scholes option pricing model assumptions:
Risk free interest rate................................... 5.00%
Expected life (years)..................................... 2.5 to 7
Volatility................................................ 41.00%
Dividend yield............................................ --
42
44
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(12) COMMITMENTS AND CONTINGENCIES
The Company has operating leases for office space and equipment, which
expire on various dates through 2011.
Future minimum lease commitments as of December 31, 2000 under these
operating leases are as follows (in thousands):
2001........................................................ $ 880
2002........................................................ 1,010
2003........................................................ 1,007
2004........................................................ 1,061
2005........................................................ 1,055
Thereafter.................................................. 6,410
-------
$11,423
=======
Rent expense for the years ended December 31, 2000 and 1999 and the period
ended December 31, 1998 was $0.9 million, $0.4 million and $0.1 million,
respectively.
From time to time, the Company is involved in litigation arising out of
operations in the normal course of business. In management's 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.
(13) RELATED PARTY
The Company's President and Chief Executive Officer serves on the board of
directors of a company that provides contract operations and other production
services to the Company. The Company incurred expenses from this service
provider of $4.4 million, $4.7 million and $3.2 million in 2000, 1999 and 1998,
respectively. Loss of this service provider would not have a material adverse
effect on the operations of the Company.
Pursuant to the Company's stockholder agreement with Evercore, the Company
paid an affiliate of Evercore a monitoring fee of $250,000 in 2000. This fee
will be paid annually until Evercore beneficially owns less than 10% of the
Company.
On January 21, 1999, the Board of Directors approved the establishment of a
3% overriding royalty fund for executive stockholders. The royalty was to be
paid based on revenue on all existing properties to the extent that funds were
available from net operating income. A formal plan was not developed, however at
the time of the Preferred Stock transaction described in note 5, the Board of
Directors approved a payment to the executive stockholders approximating the 3%
override as if the plan had been formalized. The charge of approximately
$490,000 has been recorded in the 1999 statement of operations. The Company no
longer has any obligation for the overriding royalty fund.
43
45
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(14) INTERIM FINANCIAL INFORMATION (UNAUDITED)
The following is a summary of consolidated unaudited interim financial
information for the years ended December 31, 2000 and 1999 (in thousands, except
per share data):
THREE MONTHS ENDED
----------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- --------
2000
Revenues..................................... $ 4,243 $26,113 $30,734 $ 41,982
Costs and Expenses........................... 4,009 18,671 19,717 69,396(2)
------- ------- ------- --------
Income (loss) from operations................ 234 7,442 11,017 (27,414)
Net income (loss)............................ 60 8,195(1) 5,191 (32,130)(2)
Net income (loss) available to common
stockholders............................... (1,586) 5,609 3,448 (32,858)
Earnings (loss)per share:
Basic................................... $ (0.13) $ 0.66 $ 0.40 $ (1.73)
Diluted................................. (0.13) 0.46 0.29 (1.73)
THREE MONTHS ENDED
----------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- --------
1999
Revenues..................................... $ 1,335 $ 2,445 $ 2,860 $ 2,869
Costs and Expenses........................... 1,950 1,707 2,287 4,400
------- ------- ------- --------
Income (loss) from operations................ (615) 738 573 (1,531)
Net income (loss)............................ (783) 64 (215) (1,350)
Net income (loss) available to common
stockholders............................... (783) 64 (215) (2,186)
Earnings (loss) per share:
Basic...................................... $ (0.05) $ 0.00 $ (0.01) $ (0.18)
Diluted.................................... (0.05) 0.00 (0.01) (0.18)
- ---------------
(1) Includes the effect of a gain of $7.8 million from the sale of oil and gas
assets.
(2) Includes a one time non-cash stock compensation charge for shares released
from escrow to management and director stockholders of $38.2 million and a
non-cash charge of $2.1 million for bonus shares awarded to employees at the
time of the initial public offering. The after-tax amount of these charges
totaled $39.5 million.
(15) SUPPLEMENTARY OIL AND GAS DISCLOSURES -(UNAUDITED)
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 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
44
46
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 Company's net proved reserves, including
the changes therein, and proved developed reserves:
CRUDE OIL NATURAL GAS
(MBBLS) (MMCF)
--------- -----------
Proved developed and undeveloped reserves:
January 29, 1998.......................................... -- --
Purchase of reserves in place.......................... 1,995 5,335
Extensions, discoveries and other additions............ 962 7,437
Production............................................. (96) (238)
------ -------
December 31, 1998......................................... 2,861 12,534
Extensions, discoveries and other additions............ 1,079 267
Purchase of reserves in place.......................... 268 782
Production............................................. (384) (831)
------ -------
December 31, 1999......................................... 3,824 12,752
Purchase of reserves in place.......................... 27,021 41,869
Sale of reserves....................................... (3,535) (10,673)
Extensions, discoveries and other additions............ 3,001 10,978
Production............................................. (2,790) (5,776)
------ -------
December 31, 2000......................................... 27,521 49,150
====== =======
Proved developed reserves:
December 31, 1998...................................... 2,467 10,859
December 31, 1999...................................... 2,715 7,631
December 31, 2000...................................... 25,024 39,522
Capitalized costs for oil and gas producing activities consist of the
following:
2000 1999
-------- -------
(IN THOUSANDS)
Proved properties........................................... $193,001 $41,467
Unproved properties......................................... 289 --
Accumulated depreciation, depletion and amortization........ (24,253) (5,362)
-------- -------
Net capitalized costs............................. $169,037 $36,105
======== =======
Costs incurred for oil and gas property acquisition, exploration and
development activities for the years ended December 31, 2000 and 1999 and the
period ended December 31, 1998 are as follows:
2000 1999 1998
-------- ------- -------
(IN THOUSANDS)
Oil and gas property acquisition....................... $119,872 $ 1,410 $ 9,045
Exploration............................................ 18,053 1,508 249
Development............................................ 45,063 15,604 17,282
-------- ------- -------
Total costs incurred......................... $182,988 $18,522 $26,576
======== ======= =======
45
47
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO RESERVES
The following information has been developed utilizing procedures
prescribed by Statement of Financial Accounting Standards No. 69 (Statement 69),
"Disclosures about Oil and Gas Producing Activities." It may be useful for
certain comparative purposes, but should not be solely relied upon in evaluating
the Company or its performance. Further, information contained in the following
table should not be considered as representative of realistic assessments of
future cash flows, nor should the Standardized Measure of Discounted Future Net
Cash Flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into
account in reviewing the following information: (1) future costs and selling
prices will probably differ from those required to be used in these
calculations; (2) due to future market conditions and governmental regulations,
actual rates of production achieved in future years may vary significantly from
the rate of production assumed in the calculations; (3) selection of a 10%
discount rate is arbitrary and may not be reasonable as a measure of the
relative risk inherent in realizing future net oil and gas revenues; and (4)
future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by
applying period end oil and gas prices adjusted for field and determinable
escalations to the estimated future production of period-end proved reserves.
Future cash inflows were reduced by estimated future development, abandonment
and production costs based on period-end costs in order to arrive at net cash
flow before tax. Future income tax expense has been computed by applying
period-end statutory tax rates to aggregate future net cash flows, reduced by
the tax basis of the properties involved and tax carryforwards. Use of a 10%
discount rate is required by Statement 69.
Management does not rely solely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as proved reserves and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows:
2000 1999 1998
---------- -------- --------
(IN THOUSANDS)
Future cash inflows................................. $1,200,880 $125,038 $ 61,483
Future production costs........................... (391,698) (29,036) (9,900)
Future development and abandonment costs.......... (167,941) (19,003) (10,532)
Future income tax expense......................... (183,901) (12,906) (5,434)
---------- -------- --------
Future net cash flows after income taxes............ 457,340 64,093 35,617
10% annual discount for estimated timing of cash
flows............................................. (109,238) (16,916) (10,728)
---------- -------- --------
Standardized measure of discounted future net cash
flows............................................. $ 348,102 $ 47,177 $ 24,889
========== ======== ========
46
48
ENERGY PARTNERS, LTD. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil and gas reserves for the years ended
December 31, 2000 and 1999 and the period ended December 31, 1998 is as follows:
2000 1999 1998
--------- -------- --------
(IN THOUSANDS)
Beginning of the period............................. $ 47,177 $ 24,889 $ --
Sales and transfers of oil and gas produced, net of
production costs.................................. (70,324) (6,843) (1,433)
Net changes in prices and production costs.......... 58,169 13,232 (18,469)
Extensions, discoveries and improved recoveries, net
of future production costs........................ 23,992 18,130 23,649
Previously estimated development costs incurred
during the period................................. 7,341 18,141 17,531
Purchase and sales of reserves in place............. 419,376 1,410 9,045
Changes in estimated future development costs....... (8,910) (14,352) --
Accretion of discount............................... 5,482 42 --
Net change in income taxes.......................... (134,201) (7,472) (5,434)
--------- -------- --------
Net increase........................................ 300,925 22,288 24,889
--------- -------- --------
End of period....................................... $ 348,102 $ 47,177 $ 24,889
========= ======== ========
The computation of the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves at December 31, 2000 was based on
period end prices which approximated $9.97 per mcf for natural gas and $25.84
per barrel for crude oil. Prices received in February 2001 approximated $5.76
per mcf for natural gas and $26.03 per barrel for crude oil. Had these prices
been used, the present value of future net revenues relating to proved reserves
would have been reduced.
47
49
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
For information concerning Item 10 -- Directors and Executive Officers of
the Registrant, Item 11 -- Executive Compensation, Item 12 -- Security Ownership
of Certain Beneficial Owners and Management and Item 13 -- Certain Relationships
and Related Transactions, see the definitive Proxy Statement of Energy Partners,
Ltd. for the Annual Meeting of Stockholders to be held on May 2, 2001, which
will be filed with the Securities and Exchange Commission and is incorporated
herein by reference, and "Part I -- Item 4A. Executive Officers."
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) 1. Financial Statements:
The following financial statements are included in Part II of this Report:
Independent Auditor's Report
Consolidated Balance Sheets as of December 31, 2000 and 1999
Consolidated Statements of Operations for the years ended December 31,
2000 and 1999 and the period from January 29, 1998 (inception) to
December 31, 1998
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 2000 and 1999 and the period from January 29, 1998
(inception) to December 31, 1998
Consolidated Statements of Cash Flows for the years ended December 31,
2000 and 1999 and the period from January 29, 1998 (inception) to
December 31, 1998
Notes to Consolidated Financial Statements
48
50
2. Exhibits
EXHIBIT
NUMBER TITLE
------- -----
3.1 -- Restated Certificate of Incorporation of Energy Partners,
Ltd. dated as of November 16, 1999 (incorporated by
reference to Exhibit 3.1 to the Company's registration
statement on Form S-1 (File No. 333-42876)).
3.2 -- Amendment to Restated Certificate of Incorporation of
Energy Partners, Ltd. dated as of September 15, 2000
(incorporated by reference to Exhibit 3.2 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
3.3 -- Amended and Restated Bylaws of Energy Partners, Ltd.
dated as of September 12, 2000 (incorporated by reference
to Exhibit 3.3 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
4.1 -- Stockholder Agreement by and among Energy Partners, Ltd.,
Evercore Capital Partners L.P., Evercore Capital Partners
(NQ) L.P., Evercore Capital Offshore Partners L.P.,
Energy Income Fund, L.P. and the Individual Shareholders
of the Company Signatories thereto dated as of November
17, 1999 (incorporated by reference to Exhibit 4.4 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
4.2 -- Form of First Amendment to Stockholder Agreement by and
among Energy Partners, Ltd., Evercore Capital Partners
L.P., Evercore Capital Partners (NQ) L.P., Evercore
Capital Offshore Partners L.P., Energy Income Fund, L.P.
and the Individual Shareholders of the Company
signatories thereto dated September 29, 2000
(incorporated by reference to Exhibit 4.7 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
4.3 -- Registration Rights Agreement by and between Energy
Partners, Ltd., Evercore Capital Partners L.P., Evercore
Capital Partners (NQ) L.P., Evercore Capital Offshore
Partners L.P., Energy Income Fund, L.P. and the
Individual Shareholders of the Company signatories
thereto dated as of November 17, 1999 (incorporated by
reference to Exhibit 4.5 to the Company's registration
statement on Form S-1 (File No. 333-42876)).
10.1 -- Stock Purchase Agreement by and among Energy Partners,
Ltd., Evercore Capital Partners L.P., Evercore Capital
Partners (NQ) L.P. and Evercore Capital Offshore Partners
L.P. dated as of October 26, 1999 (incorporated by
reference to Exhibit 10.8 to the Company's registration
statement on Form S-1 (File No. 333-42876)).
49
51
EXHIBIT
NUMBER TITLE
------- -----
10.2 -- Patent License Agreement between VTV, Incorporated and
Energy Partners, Ltd. dated as of May 16, 1998
(incorporated by reference to Exhibit 10.9 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.3 -- 2000 Long Term Stock Incentive Plan (incorporated by
reference to Exhibit 99.1 to the Company's registration
statement on Form S-8 (File No. 333-55940)).
10.4 -- 2000 Stock Option Plan for Non-Employee Directors
(incorporated by reference to Exhibit 10.26 to the
Company's registration statement on Form S-1 (File No.
333-55940)).
10.4 -- Stock and Deferral Plan for Non-Employee Directors
(incorporated by reference to Exhibit 99.3 to the
Company's registration statement on Form S-8 (File No.
333-42876)).
10.6 -- Employment and Stock Ownership Agreement by and between
Energy Partners, Ltd. and Richard A. Bachmann dated as of
June 5, 1998 (incorporated by reference to Exhibit 10.10
to the Company's registration statement on Form S-1 (File
No. 333-42876)).
10.7 -- First Amendment to Employment and Stock Ownership
Agreement by and between Energy Partners, Ltd. and
Richard A. Bachmann dated as of November 17, 1999
(incorporated by reference to Exhibit 10.11 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.8 -- Employment and Stock Ownership Agreement by and between
Energy Partners, Ltd. and Suzanne V. Baer dated as of
March 18, 2000 (incorporated by reference to Exhibit
10.12 to the Company's registration statement on Form S-1
(File No. 333-42876)).
10.9 -- Employment and Stock Ownership Agreement by and between
Energy Partners, Ltd. and Maureen O'Connor Sullivan dated
as of October 2, 2000 (incorporated by reference to
Exhibit 10.31 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
10.10 -- Form of Employment and Stock Ownership Agreement by and
between Energy Partners, Ltd. and Clinton W. Coldren,
Wayne A. Greenwalt, John H. McCandless and James E. Orth
dated as of June 5, 1998 (incorporated by reference to
Exhibit 10.13 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
50
52
EXHIBIT
NUMBER TITLE
------- -----
10.11 -- Amendment to Employment and Stock Ownership Agreement by
and between Energy Partners, Ltd. and Wayne A. Greenwalt
dated as of March 4, 1999 (incorporated by reference to
Exhibit 10.14 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
10.12 -- Form of First Amendment to Employment and Stock Ownership
Agreement by and between Energy Partners, Ltd. and
Clinton W. Coldren, Wayne A. Greenwalt, John H.
McCandless and James E. Orth dated as of November 17,
1999 (incorporated by reference to Exhibit 10.15 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.13 -- Form of Second Amendment to Employment and Stock
Ownership Agreement by and between Energy Partners, Ltd.
and Richard A. Bachmann, Clinton W. Coldren, Wayne A.
Greenwalt, John H. McCandless and James E. Orth dated as
of September 29, 2000 (incorporated by reference to
Exhibit 10.30 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
10.14 -- Form of Stock Ownership Agreement by and between Energy
Partners, Ltd. and Harold D. Carter, Eamon Kelly and John
G. Phillips dated as of June 5, 1998 (incorporated by
reference to Exhibit 10.16 to the Company's registration
statement on Form S-1 (File No. 333-42876)).
10.15 -- Reducing Revolving Credit Agreement among Energy
Partners, Ltd., Bank One Texas, N.A. and the several
banks and financial institutions from time to time
parties thereto dated as of March 30, 2000 (incorporated
by reference to Exhibit 10.17 to the Company's
registration statement on Form S-1 (File No. 333-42876)).
10.16 -- First Amendment to Reducing Revolving Credit Agreement
among Energy Partners, Ltd., Bank One, Texas, N.A., The
Chase Manhattan Bank, BNP Paribas and Whitney National
Bank dated as of August 10, 2000 (incorporated by
reference to Exhibit 10.28 to the Company's registration
statement on Form S-1 (File No. 333-42876)).
10.17 -- Second Amendment to Reducing Revolving Credit Agreement
by and among Energy Partners, Ltd., the banks and
financial institutions party thereto, Bank One, Texas,
N.A. dated March 30, 2000 (incorporated by reference to
Exhibit 10.37 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
51
53
EXHIBIT
NUMBER TITLE
------- -----
10.18 -- Purchase and Sale Agreement by and between Ocean Energy,
Inc. and Energy Partners, Ltd. dated as of January 26,
2000 (incorporated by reference to Exhibit 10.18 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.19 -- Farmout Agreement by and between Chevron U.S.A. Inc.,
Kewanee Industries, Inc. and Energy Partners, Ltd. dated
as of June 9, 1998 (incorporated by reference to Exhibit
10.19 to the Company's registration statement on Form S-1
(File No. 333-42876)).
10.20 -- Purchase and Sale Agreement between Union Oil Company of
California and Energy Partners, Ltd. dated as of March
31, 2000 (incorporated by reference to Exhibit 10.20 to
the Company's registration statement on Form S-1 (File
No. 333-42876)).
10.21 -- Asset Purchase Agreement by and between Shell Offshore
Inc., Shell Oil & Gas Investment Limited Partnership,
Shell Consolidated Energy Resources Inc., Shell Frontier
Oil & Gas Inc., Energy Partners, Ltd. and Union Oil
Company of California, dated as of June 23, 1998
(incorporated by reference to Exhibit 10.21 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.22 -- Purchase and Sale Agreement between Energy Partners Ltd.
and Vastar Resources, Inc. dated as of April 20, 2000
(incorporated by reference to Exhibit 10.22 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.23 -- Alliance Agreement, Production Operations and Maintenance
Services, by and between Production Management
Corporation and Energy Partners, Ltd. dated as of June 4,
1998 (incorporated by reference to Exhibit 10.23 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.24 -- Amendment to Alliance Agreement, Production Operations
and Maintenance Services, by and between Production
Management Corporation and Energy Partners, Ltd. dated as
of May 17, 2000 (incorporated by reference to Exhibit
10.24 to the Company's registration statement on Form S-1
(File No. 333-42876)).
10.25 -- Letter of Intent between Energy Partners, Ltd. and Brown
& Root Energy Services dated as of August 4, 2000
(incorporated by reference to Exhibit 10.29 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
52
54
EXHIBIT
NUMBER TITLE
------- -----
10.26 -- Purchase and Sale Agreement by and between Texaco
Exploration and Production Inc. and Energy Partners, Ltd.
dated as of September 7, 2000 (incorporated by reference
to Exhibit 10.32 to the Company's registration statement
on Form S-1 (File No. 333-42876)).
10.27 -- Purchase and Sale Agreement by and between Online
Resources, Inc. and Energy Partners, Ltd. dated as of
October 29, 1999 (incorporated by reference to Exhibit
10.33 to the Company's registration statement on Form S-1
(File No. 333-42876)).
10.28 -- Farmout Partners, Ltd. and Wheless Anderson L.L.C. dated
as of August 21, 2000 covering the North Flank of Bay
Marchand (incorporated by reference to Exhibit 10.34 to
the Company's registration statement on Form S-1 (File
No. 333-42876)).
10.29 -- Exploration Agreement and Agreement to Assign between
Hughes-Rawls, L.L.C. and Energy Partners, Ltd. dated
August 25, 1998 covering the OCS -- Gulf of Mexico in the
Bay Marchand Field (incorporated by reference to Exhibit
10.35 to the Company's registration statement on Form S-1
(File No. 333-42876)).
10.30 -- Farmout Agreement by and between Chevron U.S.A. and
Hughes-Rawls, L.L.C. dated as of August 15, 1998 covering
the OCS -- Gulf of Mexico in the Bay Marchand Field
(incorporated by reference to Exhibit 10.36 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.31 -- Assignment and Bill of Sale between Hughes-Rawls, L.L.C.
and Energy Partners, Ltd. dated as of August 25, 1998
(incorporated by reference to Exhibit 10.38 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
21.1 -- Subsidiaries of Energy Partners, Ltd.
23.1 -- Consent of KPMG LLP.
23.2 -- Consent of Netherland, Sewell & Associates, Inc.
99.1 -- Report of Independent Petroleum Engineers dated as of
February 20, 2001.
(B) Reports on Form 8-K
No reports on Form 8-K were filed by the Company during the fourth quarter
of fiscal 2000.
53
55
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Act
of 1934, the Registrant has duly caused this report to be signed on its behalf
on March 15, 2001, by the undersigned, thereunto duly authorized.
ENERGY PARTNERS, LTD.
By: /s/ RICHARD A. BACHMANN
----------------------------------
Richard A. Bachmann
Chairman, President and
Chief Executive Officer
Pursuant to the requirements of section 13 or 15 (d) of the Securities Act
of 1934, this report has been signed by the following persons on behalf of the
registrant in the capacities and on the date indicated.
SIGNATURE TITLE >DATE
--------- ----- -----
/s/ RICHARD A. BACHMANN Chairman, President and Chief March 15, 2001
- ----------------------------------------------------- Executive Officer (Principal
Richard A. Bachmann Executive Officer)
/s/ SUZANNE V. BAER Chief Financial Officer March 15, 2001
- ----------------------------------------------------- (Principal Financial and
Suzanne V. Baer Accounting Officer)
/s/ AUSTIN M. BEUTNER Director March 15, 2001
- -----------------------------------------------------
Austin M. Beutner
/s/ JOHN C. BUMGARNER, JR. Director March 15, 2001
- -----------------------------------------------------
John C. Bumgarner, Jr.
/s/ HAROLD D. CARTER Director March 15, 2001
- -----------------------------------------------------
Harold D. Carter
/s/ ROBERT D. GERSHEN Director March 15, 2001
- -----------------------------------------------------
Robert D. Gershen
/s/ WILLIAM O. HILTZ Director March 15, 2001
- -----------------------------------------------------
William O. Hiltz
/s/ EAMON M. KELLY Director March 15, 2001
- -----------------------------------------------------
Eamon M. Kelly
/s/ JOHN G. PHILLIPS Director March 15, 2001
- -----------------------------------------------------
John G. Phillips
54
56
EXHIBIT
NUMBER TITLE
------- -----
3.1 -- Restated Certificate of Incorporation of Energy Partners,
Ltd. dated as of November 16, 1999 (incorporated by
reference to Exhibit 3.1 to the Company's registration
statement on Form S-1 (File No. 333-42876)).
3.2 -- Amendment to Restated Certificate of Incorporation of
Energy Partners, Ltd. dated as of September 15, 2000
(incorporated by reference to Exhibit 3.2 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
3.3 -- Amended and Restated Bylaws of Energy Partners, Ltd.
dated as of September 12, 2000 (incorporated by reference
to Exhibit 3.3 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
4.1 -- Stockholder Agreement by and among Energy Partners, Ltd.,
Evercore Capital Partners L.P., Evercore Capital Partners
(NQ) L.P., Evercore Capital Offshore Partners L.P.,
Energy Income Fund, L.P. and the Individual Shareholders
of the Company Signatories thereto dated as of November
17, 1999 (incorporated by reference to Exhibit 4.4 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
4.2 -- Form of First Amendment to Stockholder Agreement by and
among Energy Partners, Ltd., Evercore Capital Partners
L.P., Evercore Capital Partners (NQ) L.P., Evercore
Capital Offshore Partners L.P., Energy Income Fund, L.P.
and the Individual Shareholders of the Company
signatories thereto dated September 29, 2000
(incorporated by reference to Exhibit 4.7 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
4.3 -- Registration Rights Agreement by and between Energy
Partners, Ltd., Evercore Capital Partners L.P., Evercore
Capital Partners (NQ) L.P., Evercore Capital Offshore
Partners L.P., Energy Income Fund, L.P. and the
Individual Shareholders of the Company signatories
thereto dated as of November 17, 1999 (incorporated by
reference to Exhibit 4.5 to the Company's registration
statement on Form S-1 (File No. 333-42876)).
10.1 -- Stock Purchase Agreement by and among Energy Partners,
Ltd., Evercore Capital Partners L.P., Evercore Capital
Partners (NQ) L.P. and Evercore Capital Offshore Partners
L.P. dated as of October 26, 1999 (incorporated by
reference to Exhibit 10.8 to the Company's registration
statement on Form S-1 (File No. 333-42876)).
57
EXHIBIT
NUMBER TITLE
------- -----
10.2 -- Patent License Agreement between VTV, Incorporated and
Energy Partners, Ltd. dated as of May 16, 1998
(incorporated by reference to Exhibit 10.9 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.3 -- 2000 Long Term Stock Incentive Plan (incorporated by
reference to Exhibit 99.1 to the Company's registration
statement on Form S-8 (File No. 333-55940)).
10.4 -- 2000 Stock Option Plan for Non-Employee Directors
(incorporated by reference to Exhibit 10.26 to the
Company's registration statement on Form S-1 (File No.
333-55940)).
10.4 -- Stock and Deferral Plan for Non-Employee Directors
(incorporated by reference to Exhibit 99.3 to the
Company's registration statement on Form S-8 (File No.
333-42876)).
10.6 -- Employment and Stock Ownership Agreement by and between
Energy Partners, Ltd. and Richard A. Bachmann dated as of
June 5, 1998 (incorporated by reference to Exhibit 10.10
to the Company's registration statement on Form S-1 (File
No. 333-42876)).
10.7 -- First Amendment to Employment and Stock Ownership
Agreement by and between Energy Partners, Ltd. and
Richard A. Bachmann dated as of November 17, 1999
(incorporated by reference to Exhibit 10.11 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.8 -- Employment and Stock Ownership Agreement by and between
Energy Partners, Ltd. and Suzanne V. Baer dated as of
March 18, 2000 (incorporated by reference to Exhibit
10.12 to the Company's registration statement on Form S-1
(File No. 333-42876)).
10.9 -- Employment and Stock Ownership Agreement by and between
Energy Partners, Ltd. and Maureen O'Connor Sullivan dated
as of October 2, 2000 (incorporated by reference to
Exhibit 10.31 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
10.10 -- Form of Employment and Stock Ownership Agreement by and
between Energy Partners, Ltd. and Clinton W. Coldren,
Wayne A. Greenwalt, John H. McCandless and James E. Orth
dated as of June 5, 1998 (incorporated by reference to
Exhibit 10.13 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
58
EXHIBIT
NUMBER TITLE
------- -----
10.11 -- Amendment to Employment and Stock Ownership Agreement by
and between Energy Partners, Ltd. and Wayne A. Greenwalt
dated as of March 4, 1999 (incorporated by reference to
Exhibit 10.14 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
10.12 -- Form of First Amendment to Employment and Stock Ownership
Agreement by and between Energy Partners, Ltd. and
Clinton W. Coldren, Wayne A. Greenwalt, John H.
McCandless and James E. Orth dated as of November 17,
1999 (incorporated by reference to Exhibit 10.15 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.13 -- Form of Second Amendment to Employment and Stock
Ownership Agreement by and between Energy Partners, Ltd.
and Richard A. Bachmann, Clinton W. Coldren, Wayne A.
Greenwalt, John H. McCandless and James E. Orth dated as
of September 29, 2000 (incorporated by reference to
Exhibit 10.30 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
10.14 -- Form of Stock Ownership Agreement by and between Energy
Partners, Ltd. and Harold D. Carter, Eamon Kelly and John
G. Phillips dated as of June 5, 1998 (incorporated by
reference to Exhibit 10.16 to the Company's registration
statement on Form S-1 (File No. 333-42876)).
10.15 -- Reducing Revolving Credit Agreement among Energy
Partners, Ltd., Bank One Texas, N.A. and the several
banks and financial institutions from time to time
parties thereto dated as of March 30, 2000 (incorporated
by reference to Exhibit 10.17 to the Company's
registration statement on Form S-1 (File No. 333-42876)).
10.16 -- First Amendment to Reducing Revolving Credit Agreement
among Energy Partners, Ltd., Bank One, Texas, N.A., The
Chase Manhattan Bank, BNP Paribas and Whitney National
Bank dated as of August 10, 2000 (incorporated by
reference to Exhibit 10.28 to the Company's registration
statement on Form S-1 (File No. 333-42876)).
10.17 -- Second Amendment to Reducing Revolving Credit Agreement
by and among Energy Partners, Ltd., the banks and
financial institutions party thereto, Bank One, Texas,
N.A. dated March 30, 2000 (incorporated by reference to
Exhibit 10.37 to the Company's registration statement on
Form S-1 (File No. 333-42876)).
59
EXHIBIT
NUMBER TITLE
------- -----
10.18 -- Purchase and Sale Agreement by and between Ocean Energy,
Inc. and Energy Partners, Ltd. dated as of January 26,
2000 (incorporated by reference to Exhibit 10.18 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.19 -- Farmout Agreement by and between Chevron U.S.A. Inc.,
Kewanee Industries, Inc. and Energy Partners, Ltd. dated
as of June 9, 1998 (incorporated by reference to Exhibit
10.19 to the Company's registration statement on Form S-1
(File No. 333-42876)).
10.20 -- Purchase and Sale Agreement between Union Oil Company of
California and Energy Partners, Ltd. dated as of March
31, 2000 (incorporated by reference to Exhibit 10.20 to
the Company's registration statement on Form S-1 (File
No. 333-42876)).
10.21 -- Asset Purchase Agreement by and between Shell Offshore
Inc., Shell Oil & Gas Investment Limited Partnership,
Shell Consolidated Energy Resources Inc., Shell Frontier
Oil & Gas Inc., Energy Partners, Ltd. and Union Oil
Company of California, dated as of June 23, 1998
(incorporated by reference to Exhibit 10.21 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.22 -- Purchase and Sale Agreement between Energy Partners Ltd.
and Vastar Resources, Inc. dated as of April 20, 2000
(incorporated by reference to Exhibit 10.22 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.23 -- Alliance Agreement, Production Operations and Maintenance
Services, by and between Production Management
Corporation and Energy Partners, Ltd. dated as of June 4,
1998 (incorporated by reference to Exhibit 10.23 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.24 -- Amendment to Alliance Agreement, Production Operations
and Maintenance Services, by and between Production
Management Corporation and Energy Partners, Ltd. dated as
of May 17, 2000 (incorporated by reference to Exhibit
10.24 to the Company's registration statement on Form S-1
(File No. 333-42876)).
10.25 -- Letter of Intent between Energy Partners, Ltd. and Brown
& Root Energy Services dated as of August 4, 2000
(incorporated by reference to Exhibit 10.29 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
60
EXHIBIT
NUMBER TITLE
------- -----
10.26 -- Purchase and Sale Agreement by and between Texaco
Exploration and Production Inc. and Energy Partners, Ltd.
dated as of September 7, 2000 (incorporated by reference
to Exhibit 10.32 to the Company's registration statement
on Form S-1 (File No. 333-42876)).
10.27 -- Purchase and Sale Agreement by and between Online
Resources, Inc. and Energy Partners, Ltd. dated as of
October 29, 1999 (incorporated by reference to Exhibit
10.33 to the Company's registration statement on Form S-1
(File No. 333-42876)).
10.28 -- Farmout Partners, Ltd. and Wheless Anderson L.L.C. dated
as of August 21, 2000 covering the North Flank of Bay
Marchand (incorporated by reference to Exhibit 10.34 to
the Company's registration statement on Form S-1 (File
No. 333-42876)).
10.29 -- Exploration Agreement and Agreement to Assign between
Hughes-Rawls, L.L.C. and Energy Partners, Ltd. dated
August 25, 1998 covering the OCS -- Gulf of Mexico in the
Bay Marchand Field (incorporated by reference to Exhibit
10.35 to the Company's registration statement on Form S-1
(File No. 333-42876)).
10.30 -- Farmout Agreement by and between Chevron U.S.A. and
Hughes-Rawls, L.L.C. dated as of August 15, 1998 covering
the OCS -- Gulf of Mexico in the Bay Marchand Field
(incorporated by reference to Exhibit 10.36 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
10.31 -- Assignment and Bill of Sale between Hughes-Rawls, L.L.C.
and Energy Partners, Ltd. dated as of August 25, 1998
(incorporated by reference to Exhibit 10.38 to the
Company's registration statement on Form S-1 (File No.
333-42876)).
21.1 -- Subsidiaries of Energy Partners, Ltd.
23.1 -- Consent of KPMG LLP.
23.2 -- Consent of Netherland, Sewell & Associates, Inc.
99.1 -- Report of Independent Petroleum Engineers dated as of
February 20, 2001.