Exhibit 99.1
EPL Announces Fourth Quarter and Year End Results for 2006
Reports Record 2006 Annual Production and Revenue
NEW ORLEANS--(BUSINESS WIRE)--March 1, 2007--Energy Partners, Ltd.
("EPL" or the "Company") (NYSE:EPL) today reported financial and
operational results for the fourth quarter of 2006 and the full year,
including year end 2006 proved reserves and reserve replacement. The
Company also noted that its Board of Directors has scheduled meetings
for the week of March 5, 2007 regarding its exploration of strategic
alternatives. The Company plans an announcement of the status or
recommendations as soon as possible thereafter.
Financial Results
For the fourth quarter of 2006, EPL reported a net loss to common
stockholders of $52.5 million, or $1.35 per diluted share, compared to
net income for the fourth quarter of 2005 of $28.1 million, or $0.69
per diluted share. While EPL's production and revenue were near record
highs, the Company said the majority of the net loss for the fourth
quarter of 2006 was attributable to $77.9 million of pre-tax, non-cash
costs associated with property impairments. The majority of the
impairments were associated with onshore South Louisiana properties
acquired in early 2005 and were due in large part to lower commodity
price forecasts as compared with the prior year. The remaining
impairment costs were mainly due to mechanical difficulties
encountered in one offshore well located in East Cameron 378. The
fourth quarter loss also included a total of $11.9 million of pre-tax
costs related to the termination of the merger agreement between EPL
and Stone Energy Corporation ("Stone") and legal and financial advisor
costs related to the Stone merger, unsolicited offer to acquire EPL by
ATS Inc. ("ATS"), a wholly-owned subsidiary of Woodside Petroleum,
Ltd. (ASX:WPL), and costs related to EPL's exploration of strategic
alternatives. Excluding the after-tax impact of $57.5 million of
impairment costs and the Stone, ATS and strategic alternatives costs,
EPL's adjusted fourth quarter net income, a non-GAAP measure, would
have been $4.9 million or $0.13 per basic share (see reconciliation of
adjusted net income in the appendix).
For the year 2006, the net loss to common stockholders was $50.4
million, or $1.32 per diluted share, compared to net income in 2005 of
$72.2 million, or $1.79 per diluted share. The benefit of record
annual production and revenue was offset by $84.7 million of non-cash,
pre-tax property impairment costs for the full year 2006. The net loss
for the year also included $51.5 million of pre-tax costs related to
the merger agreement between EPL and Stone and its subsequent
termination, and $15.0 million in legal and financial advisor costs
associated with the Stone merger, the unsolicited ATS offer, and EPL's
exploration of strategic alternatives. Excluding the after-tax impact
of $96.8 million of impairment costs, and the costs related to Stone,
ATS and strategic alternatives, EPL's adjusted 2006 net income, a
non-GAAP measure, would have been $46.4 million or $1.21 per basic
share (see reconciliation of adjusted net income in the appendix).
Revenue for the fourth quarter of 2006 was $111.6 million, up 4%
compared to fourth quarter 2005 revenues of $107.3 million. Revenue
for the year 2006 was $449.6 million, a 12% increase over 2005
revenues of $402.9 million. Discretionary cash flow, which is cash
flow from operations before changes in working capital and exploration
expenditures, totaled $65.0 million in the fourth quarter of 2006,
versus $98.6 million in the fourth quarter last year. For the full
year, discretionary cash flow was $279.1 million compared to $308.8
million in 2005 (see reconciliation of discretionary cash flow in
appendix). Cash flow from operations in the most recent quarter was
$86.7 million, compared to $16.3 million in the fourth quarter of
2005. Cash flow from operations for 2006 totaled $272.1 million
compared to $270.0 million in 2005.
In the fourth quarter of 2006, production averaged 27,080 barrels
of oil equivalent (Boe) per day, compared to 18,583 Boe per day in the
fourth quarter of 2005. While the daily average for the fourth quarter
of 27,080 Boe per day was up significantly from the third quarter
average of 25,421 Boe per day, it was below the Company's guidance
range of 28,500 to 30,500 Boe per day. This was due primarily to
production start-up delays and higher than anticipated downtime, due
to inclement weather and mechanical problems, of which the majority
have since been resolved. Natural gas production in the fourth quarter
of 2006 averaged 105.7 million cubic feet (Mmcf) per day and oil
production averaged 9,465 barrels per day.
Production for 2006 averaged 25,912 Boe per day, a record high for
the Company and a 14% increase over the 2005 average of 22,722 Boe per
day. Natural gas production averaged 106.0 Mmcf per day in 2006, and
oil production averaged 8,238 barrels per day.
Price realizations, all of which are stated net of hedging impact,
averaged $53.64 per barrel for oil and $6.67 per thousand cubic feet
(Mcf) of natural gas in the fourth quarter of 2006, compared to $45.16
per barrel and $11.39 per Mcf in the fourth quarter of 2005. For 2006,
oil price realizations averaged $59.78 per barrel and natural gas
averaged $6.96 per Mcf compared to $46.45 per barrel and $8.26 per Mcf
in 2005.
As of December 31, 2006, the Company had cash on hand of $3.2
million, total debt of $317.0 million, and a debt to total
capitalization ratio of 46%. The Company also had $83.0 million of
remaining capacity available under its bank facility at year-end 2006.
Richard A. Bachmann, EPL's Chairman and CEO, commented, "Our
fourth quarter results were clearly overshadowed by the impairments of
properties, in large part related to properties purchased in 2005 in
our onshore South Louisiana acquisition. The exploratory success we
have enjoyed onshore over the last two years has been offset by the
significant negative reserve revisions we took at the end of 2005 on
the reserves we acquired and the subsequent impairment of properties
this year due in large part to lower price forecasts as compared to
the prior year. In addition, our overall 2006 financial results were
negatively impacted by the considerable expenses associated with the
Stone merger agreement and its subsequent termination, the legal and
financial costs associated with the unsolicited offer by ATS, and the
additional costs incurred in the exploration of strategic
alternatives."
Reserve Replacement and Costs
EPL's proved reserves at year end 2006 stood at 29.9 million
barrels of oil and 170.1 billion cubic feet of natural gas, or 58.3
million Boe, down 2% from 59.3 million Boe at year end 2005. EPL's
proved reserves at year-end 2006 were 49% natural gas and 51% oil, and
76% were classified as proved developed. In 2006, the Company replaced
92% of its 2006 production at an average cost of $45.97 per Boe, based
on total finding and development costs of $398.9 million (see
reconciliation in the appendix). EPL added 8.4 million Boe from its
exploration and development program. The Company recorded 0.2 million
Boe in revisions to its proved reserves in 2006, reflecting overall
positive revisions from year-end 2005 reserves for both its Gulf of
Mexico ("GOM") Shelf asset base and its onshore South Louisiana asset
base. All of the Company's proved reserve figures are based upon third
party engineering estimates prepared by Ryder Scott Company, L.P. and
Netherland, Sewell & Associates, Inc.
Bachmann continued, "Our 76% exploratory drilling success rate in
2006 was back to our historical track record, but the percentage
replacement of 2006 production was below our expectations. While we
had a number of good discoveries during the year, we did not have a
sizable success in our high potential, high risk exploratory program.
The majority of our discoveries were made on the Shelf and onshore,
and were moderate in size. The full reserve potential of these wells
was not booked as proved reserves in 2006. With the benefit of more
production history in the wells drilled in 2006, we would expect to
see significant additions to our proved reserve base in the future
from our internal estimates of approximately 5 million Boe of probable
reserves associated with those wells, or 9% of our end of year proved
reserves. In 2007, we expect to conclude the evaluation of the wells
drilled in the deepwater GOM in 2006, and also to drill more moderate
risk, high potential wells, with a focus on those around our existing
fields in the South Timbalier area."
Operational Highlights
EPL drilled 27 exploratory wells in 2006 on the GOM Shelf, in the
deepwater GOM and onshore in South Louisiana. At year end, the Company
had decisioned 25 of those wells with 16 discoveries in 20 wells
offshore and three discoveries in five wells onshore for an overall
exploratory success rate of 76%. Overall, EPL experienced an
exploratory success rate of 76% in 2006, within the Company's
historical success range, and an improvement over the 2005 success
rate of 64%. Two additional wells in the deepwater GOM that also
encountered hydrocarbons are still being evaluated. A table of EPL's
2006 exploratory wells is available in the appendix.
In addition to exploratory drilling, EPL drilled two successful
development wells, and completed 35 workovers and recompletions in
2006. Three exploratory wells also successfully found the intended
development objectives. Overall, EPL was 100% successful in its low
risk drillwell program.
At year end, undeveloped gross acres stood at 387,938, a 68%
increase over the year end 2005 undeveloped acreage of 231,547. Total
gross undeveloped and developed acreage at year end 2006 was 607,444
acres.
Deepwater
In the first quarter of 2006, EPL entered the deepwater GOM
through a 25% working interest in 23 undeveloped leases from Noble
Energy, Inc. (NYSE:NBL). Currently EPL has ownership in 24 leases.
During the year, three deepwater wells were drilled in Mississippi
Canyon 204 (Redrock), 248 (Raton), and 292 (Raton South), all of which
found hydrocarbons. The first production planned in this area will be
from a natural gas interval discovered in the Raton well last year,
with production commencing in late 2007 or early 2008. The other two
wells in Mississippi Canyon 204 and 292 are under evaluation. The
Company currently has ten identified prospects in the deepwater GOM
with over 380 million Boe of net unrisked potential reserves on
acreage located in the Mississippi Canyon, Garden Banks, Green Canyon,
Atwater Valley, and Vioska Knoll areas.
2007 Operational Update
Year to date in 2007, EPL has decisioned one well offshore at
South Marsh Island 79 #2. The moderate risk, moderate potential well,
which reached its intended depth of 11,296 feet, was a dryhole. EPL
had a 100% working interest in the well. The Company will recognize
dry hole expense of $5.3 million in the first quarter of 2007 in
connection with the well.
The Company currently has four exploratory wells underway,
including the moderate risk, high potential South Timbalier 46 #3 well
located on the Shelf, two moderate risk, moderate potential wells
located in South Timbalier 26 and South Pass 38 on the Shelf, and one
high risk, high potential prospect called Barracuda located onshore in
Terrebonne Parish.
EPL's total budget for its 2007 exploration and development
program is $300 million and expected to be funded entirely through
internally generated cash flow. The Company does not budget for
acquisitions. The Company is currently scheduled to drill 17
exploratory wells offshore in 2007 along with six exploratory wells
onshore. The exploratory program consists of 23 wells with net
unrisked potential reserves of 47 million Boe. Approximately 70% of
the exploration budget is dedicated to moderate to high potential
prospects in legacy assets and areas with recent discoveries, such as
the South Timbalier, East Cameron and Vermilion areas on the Shelf.
The budget currently includes seven high potential prospects, with
five of the seven wells in the moderate risk category.
The Company expects 2007 production to average between 26,000 to
28,000 Boe/day, representing an increase at the upper end of the range
of approximately 8% over 2006 annual production of 25,912 Boe/day.
EPL has scheduled a conference call to review fourth quarter and
year end 2006 results this morning, March 1, 2007, at 8:30 A.M.
central time. To participate in the EPL conference call, callers in
the United States and Canada can dial (877) 612-5303 and international
callers can dial (706) 634-0487. The Conference I.D. for callers is
9215033.
The call will be available for replay beginning two hours after
the call is completed through midnight of March 6, 2007. For callers
in the United States and Canada, the toll-free number for the replay
is (800) 642-1687. For international callers the number is (706)
645-9291. The Conference I.D. for all callers to access the replay is
9215033.
The conference call will be webcast live as well as for on-demand
listening at the Company's web site, www.eplweb.com. Listeners may
access the call through the "Conference Calls" link in the Investor
Relations section of the site. The call will also be available through
the CCBN Investor Network.
Founded in 1998, EPL is an independent oil and natural gas
exploration and production company based in New Orleans, Louisiana.
The Company's operations are focused along the U. S. Gulf Coast, both
onshore in south Louisiana and offshore in the Gulf of Mexico.
Forward-Looking Statements
This press release contains forward-looking information regarding
EPL that is intended to be covered by the safe harbor "forward-looking
statements" provided by the Private Securities Litigation Reform Act
of 1995. All statements included in this press release that address
activities, events or developments that EPL expects, believes or
anticipates will or may occur in the future are forward-looking
statements. These include statements regarding:
-- reserve and production estimates,
-- oil and natural gas prices,
-- the impact of derivative positions,
-- production expense estimates,
-- cash flow estimates,
-- future financial performance,
-- planned capital expenditures,
-- the completion of any transaction; and
-- other matters that are discussed in EPL's filings with the
Securities and Exchange Commission (SEC).
These statements are based on current expectations and projections
about future events and involve known and unknown risks,
uncertainties, and other factors that may cause actual results and
performance to be materially different from any future results or
performance expressed or implied by these forward-looking statements.
There is no assurance that the exploration of strategic alternatives
will result in any agreements or transactions. Please refer to EPL's
filings with the SEC, including Form 10-K for the year ended December
31, 2006 to be filed shortly, for a discussion of these risks.
The documents filed with the SEC by EPL may be obtained free of
charge from EPL's website at www.eplweb.com or by directing a request
to: Energy Partners, Ltd. 201 St. Charles Avenue, Suite 3400, New
Orleans, Louisiana 70170, Attn: Secretary, (504) 569-1875.
Appendix
2006 Exploratory Wells
EPL
Working
Lease Well Number Interest Risk Result Region
- ---------------------- ------------ -------- ---- ---------- ---------
West Cameron 98 (1) #3st 100% Mod Success Shelf
West Cameron 3 #1 25% Mod Success Shelf
West Cameron 176 #1 25% Mod Success Shelf
Vermilion 101 #1 75% Mod Success Shelf
South Timbalier 46 (1) #3 100% Mod Success Shelf
South Timbalier 42 (1) #2 60% Mod Success Shelf
South Marsh Island 79 #1 100% Mod Success Shelf
Eugene Island 312 #1 40% Mod Success Shelf
East Cameron 46 #A-6 25% Mod Success Shelf
East Cameron 268 #1 50% Mod Success Shelf
East Cameron 109 #5 75% Mod Success Shelf
East Cameron 109 #A-6 50% Mod Success Shelf
South Timbalier 23 #CM-2st 27% Mod Success Shelf
South Timbalier 23 #SB-15st3 27% Low Success Shelf
South Timbalier 23 #CC-4st 27% Low Success Shelf
West Cameron 202 #1 25% High Dryhole Shelf
South Pass 26 #1 (Denali) 40% High Dryhole Shelf
West Cameron 25 #1 100% High Dryhole Shelf
Grand Island 66 #1 50% Mod Dryhole Shelf
Lakeside Dixie Rice#1 45% High Success Onshore
Little Lake #3 50% Mod Success Onshore
Little Lake S/L 18143 #1 50% Mod Success Onshore
Bay Batiste #1 25% Mod Dryhole Onshore
Four Rivers #1 33% Mod Dryhole Onshore
Mississippi Canyon 248 #1 25% Mod Success Deepwater
Mississippi Canyon 204 #1 25% Mod Evaluating Deepwater
Mississippi Canyon 292 #5 25% Mod Evaluating Deepwater
(1) Wells with development sands.
ENERGY PARTNERS, LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, except per share data)
Three Months Ended Years Ended
December 31, December 31,
------------------- ---------------------
2006 2005 2006 2005
--------- --------- ----------- ---------
(Unaudited) (Unaudited)
Revenues:
Oil and natural gas $111,592 $106,345 $449,186 $402,005
Other 42 919 364 942
--------- --------- ----------- ---------
111,634 107,264 449,550 402,947
--------- --------- ----------- ---------
Costs and expenses:
Lease operating 14,092 9,711 58,808 50,431
Transportation expense 490 258 2,028 1,051
Taxes, other than on
earnings 2,684 2,114 13,632 10,372
Exploration expenditures,
dry hole costs and
impairments 81,934 29,904 136,425 82,844
Depreciation, depletion
and amortization 58,996 23,148 198,162 99,524
Accretion expense 1,322 1,071 4,572 4,125
General and administrative 26,919 12,922 120,113 43,205
Other expense 1,478 - 4,022 -
--------- --------- ----------- ---------
Total costs and
expenses 187,915 79,128 537,762 291,552
--------- --------- ----------- ---------
Business interruption
recovery 1,293 20,632 32,869 20,632
Income (loss) from
operations (74,988) 48,768 (55,343) 132,027
--------- --------- ----------- ---------
Other income (expense):
Interest income 348 263 1,428 781
Interest expense (7,380) (4,809) (24,570) (18,121)
--------- --------- ----------- ---------
(7,032) (4,546) (23,142) (17,340)
--------- --------- ----------- ---------
Income (loss) before income
taxes (82,020) 44,222 (78,485) 114,687
Income taxes 29,474 (16,118) 28,085 (41,592)
--------- --------- ----------- ---------
Net income (loss) (52,546) 28,104 (50,400) 73,095
Less dividends earned on
preferred stock and
accretion of discount - - - (944)
--------- --------- ----------- ---------
Net income (loss) available
to common stockholders $(52,546) $28,104 $(50,400) $72,151
========= ========= =========== =========
Basic earnings (loss) per
share $(1.35) $0.74 $(1.32) $1.94
========= ========= =========== =========
Diluted earnings (loss) per
share $(1.35) $0.69 $(1.32) $1.79
========= ========= =========== =========
Weighted average common
shares used in computing
income (loss) per share:
Basic 38,947 37,984 38,313 37,097
Incremental common
shares - 2,877 - 3,662
--------- --------- ----------- ---------
Diluted 38,947 40,861 38,313 40,759
========= ========= =========== =========
Net income (loss) available
to common stockholders, as
reported: $(52,546) $28,104 $(50,400) $72,151
Add back:
Impact of property
impairments on the
periods presented 77,939 7,968 84,680 17,907
Impact of merger and
acquisition costs on
the periods presented 11,873 - 66,520 -
Deduct:
Impact of income taxes
on impairments and
merger and
acquisition costs at
a rate of 36% (32,332) (2,868) (54,432) (6,447)
--------- --------- ----------- ---------
Adjusted Non-GAAP net income
(Unaudited) $4,934 $33,204 $46,368 $83,611
========= ========= =========== =========
The table above reconciles net income (loss) as reported to an
adjusted non-GAAP amount and is provided as supplemental information,
and should not be relied upon as alternative measures to GAAP. The
Company's management utilizes both the GAAP and the non-GAAP results,
calculated above, to evaluate the Company's performance and believes
that comparative analysis of results can be enhanced by excluding the
impact of the certain items. Management believes in certain cases,
the Company's GAAP results are not indicative of the Company's
operating performance for the applicable period, nor should they be
considered in developing trend analysis for future periods.
Specifically, the Company believes that it is useful to provide
investors with information regarding the impact of merger and
acquisition costs as well as property impairments on the periods
presented because these items are not typical and are not expected to
be reoccuring at these levels.
ENERGY PARTNERS, LTD.
CONSOLIDATED STATEMENTS OF NET CASH PROVIDED BY
OPERATING ACTIVITIES
(In Thousands)
Three Months Ended Years Ended
December 31, December 31,
------------------- ---------------------
2006 2005 2006 2005
--------- --------- ----------- ---------
(Unaudited) (Unaudited)
Cash flows from operating
activities:
Net income (loss) $(52,546) $28,104 $(50,400) $73,095
Adjustments to reconcile
net income (loss) to net
cash provided by
operating activities:
Depreciation,
depletion and
amortization 60,318 24,219 202,734 103,649
(Gain) loss on sale of
oil and natural gas
assets 550 (869) 4,047 (777)
Stock-based
compensation 3,070 550 11,038 6,817
Deferred income taxes (29,124) 16,114 (27,452) 41,242
Exploration
expenditures 80,341 28,718 122,449 69,926
Amortization of
deferred financing
costs 429 249 1,133 995
Other 392 292 1,587 966
Changes in operating
assets and liabilities:
Trade accounts
receivable (1,582) (32,572) 2,390 (18,985)
Other receivables 35,111 (36,881) (8,966) (43,703)
Prepaid expenses (1,770) 1,282 (391) (894)
Other assets (419) (607) 283 (2,338)
Accounts payable and
accrued expenses (8,977) (12,318) 13,599 40,073
Other liabilities 897 17 23 (97)
--------- --------- ----------- ---------
Net cash provided by
operating activities $86,690 $16,298 $272,074 $269,969
========= ========= =========== =========
Reconciliation of
discretionary cash flow:
Net cash provided by
operating activities 86,690 16,298 272,074 269,969
Changes in working
capital (23,260) 81,079 (6,938) 25,944
Non-cash exploration
expenditures (80,341) (28,718) (122,449) (69,926)
Total exploration
expenditures 81,934 29,904 136,425 82,844
--------- --------- ----------- ---------
Discretionary cash flow
(Unaudited) $65,023 $98,563 $279,112 $308,831
========= ========= =========== =========
The table above reconciles discretionary cash flow to net cash
provided by operating activities. Discretionary cash flow is defined
as cash flow from operations before changes in working capital and
exploration expenditures. Discretionary cash flow is widely accepted
as a financial indicator of an oil and natural gas company's ability
to generate cash which is used to internally fund exploration and
development activities, pay dividends and service debt. Discretionary
cash flow is presented based on management's belief that this non-
GAAP financial measure is useful information to investors because it
is widely used by professional research analysts in the valuation,
comparison, rating and investment recommendations of companies within
the oil and natural gas exploration and production industry. Many
investors use the published research of these analysts in making
their investment decisions. Discretionary cash flow is not a measure
of financial performance under GAAP and should not be considered as
an alternative to cash flows from operating activities, as defined by
GAAP, or as a measure of liquidity, or an alternative to net income.
Investors should be cautioned that discretionary cash flow as
reported by us may not be comparable in all instances to
discretionary cash flow as reported by other companies.
ENERGY PARTNERS, LTD.
SELECTED PRODUCTION, PRICING AND OPERATIONAL STATISTICS
(Unaudited)
Three Months Ended Years Ended
December 31, December 31,
------------------- -------------------
2006 2005 2006 2005
--------- --------- --------- ---------
PRODUCTION AND PRICING
- ------------------------------
Net Production (per day):
Oil (Bbls) 9,465 4,916 8,238 7,984
Natural gas (Mcf) 105,687 82,001 106,042 88,430
Total (Boe) 27,080 18,583 25,912 22,722
Oil and Natural Gas Revenues
(in thousands):
Oil $46,705 $20,423 $179,752 $135,359
Natural gas 64,887 85,922 269,434 266,646
Total 111,592 106,345 449,186 402,005
Average Sales Prices:
Oil (per Bbl) $53.64 $45.16 $59.78 $46.45
Natural gas (per Mcf) 6.67 11.39 6.96 8.26
Average (per Boe) 44.79 62.20 47.49 48.47
Impact of hedging:
Oil (per Bbl) $- $(6.50) $- $(3.15)
Natural gas (per Mcf) 0.03 (1.03) (0.02) (0.24)
OPERATIONAL STATISTICS
- ------------------------------
Average Costs (per Boe):
Lease operating expense $5.66 $5.68 $6.22 $6.08
Taxes, other than on
earnings 1.08 1.24 1.41 1.25
Depreciation, depletion and
amortization 23.68 13.54 20.95 12.00
Accretion expense 0.53 0.63 0.48 0.50
ENERGY PARTNERS, LTD.
CONSOLIDATED BALANCE SHEETS
(In Thousands, except share data)
December 31, December 31,
2006 2005
------------ ------------
(Unaudited)
ASSETS
- --------------------------------------------
Current assets:
Cash and cash equivalents $3,214 $6,789
Trade accounts receivable 74,132 78,326
Other receivables 58,269 49,303
Deferred tax asset 1,387 5,582
Prepaid expenses 3,570 3,179
------------ ------------
Total current assets 140,572 143,179
Property and equipment, at cost under the
successful efforts method of accounting for
oil and natural gas properties 1,527,304 1,189,078
Less accumulated depreciation, depletion and
amortization (680,845) (418,347)
------------ ------------
Net property and equipment 846,459 770,731
Other assets 13,029 13,284
Deferred financing costs -- net of
accumulated amortization 3,785 4,091
------------ ------------
$1,003,845 $931,285
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
- --------------------------------------------
Current liabilities:
Accounts payable $47,154 $28,810
Accrued expenses 133,198 108,087
Fair value of commodity derivative
instruments 1,552 9,875
Current maturities of long-term debt - 109
------------ ------------
Total current liabilities 181,904 146,881
Long-term debt 317,000 235,000
Deferred income taxes 62,451 87,559
Asset retirement obligation 68,767 56,039
Other 1,453 11,213
------------ ------------
631,575 536,692
Stockholders' equity:
Preferred stock, $1 par value, authorized
1,700,000 shares; no shares issued and
outstanding - -
Common stock, par value $0.01 per share.
Authorized 100,000,000 shares; issued and
outstanding: 2006 - 42,501,726 shares;
2005 - 41,468,093 shares 425 415
Additional paid-in capital 365,313 348,863
Accumulated other comprehensive loss (994) (12,619)
Retained earnings 64,966 115,366
Treasury stock, at cost. 2006 - 3,479,814
and 2005 - 3,474,208 shares (57,440) (57,432)
------------ ------------
Total stockholders' equity 372,270 394,593
Commitments and contingencies
------------ ------------
$1,003,845 $931,285
============ ============
ENERGY PARTNERS, LTD.
SUPPLEMENTAL OIL & NATURAL GAS DISCLOSURE
(Unaudited)
Crude Oil Natural Gas Equivalents
(Mbbl) (Mmcf) (Mboe)
----------- ----------- -----------
Proved developed and undeveloped
reserves:
December 31, 2003 27,414 134,404 49,815
Extensions, discoveries and
other additions 3,232 67,049 14,407
Revisions 1,295 (21,570) (2,300)
Production (3,171) (30,048) (8,179)
----------- ----------- -----------
December 31, 2004 28,770 149,835 53,743
Purchases of reserves in place 3,949 52,690 12,731
Extensions, discoveries and
other additions 1,086 24,490 5,168
Revisions 587 (27,789) (4,045)
Production (2,914) (32,277) (8,294)
----------- ----------- -----------
December 31, 2005 31,478 166,949 59,303
Sales of reserves in place (129) (750) (254)
Extensions, discoveries and
other additions 1,057 44,336 8,446
Revisions 515 (1,704) 231
Production (3,007) (38,708) (9,458)
----------- ----------- -----------
December 31, 2006 29,914 170,123 58,268
Proved developed reserves:
December 31, 2004 24,737 102,760 41,864
December 31, 2005 25,646 103,627 42,917
December 31, 2006 24,811 117,392 44,376
Costs incurred for oil and natural gas property acquisition,
exploration and development activities for the three-years ended
December 31 are as follows (in Thousands):
2006 2005 2004
----------- ----------- -----------
Business combinations 420 171,358 2,166
Lease acquisitions 15,896 27,622 6,551
Exploration 224,147 171,859 113,278
Development 158,837 107,910 72,235
----------- ----------- -----------
Total finding and development
costs 398,880 307,391 192,064
----------- ----------- -----------
Total finding, development and
acquisition costs 399,300 478,749 194,230
----------- ----------- -----------
Asset retirement liabilities
incurred 5,947 7,151 3,686
Asset retirement revisions 2,562 (247) (189)
----------- ----------- -----------
Total cost incurred $407,809 $485,653 $197,727
All of the amounts reflected as business combinations in 2006 and 2004
and $0.9 million in 2005 relate to the contingent consideration
payments made to former Hall-Houston shareholders.
CONTACT: Energy Partners, Ltd., New Orleans
Investors:
T.J. Thom, 504-799-4830
or
Al Petrie, 504-799-1953
or
Media:
Joele Frank, Wilkinson Brimmer Katcher
Steve Frankel or Jeremy Jacobs, 212-355-4449