EPL Epl Oil & Gas

Energy Partners, Ltd. (EPL or the Company) (NYSE:EPL) today reported financial and operational results for the second quarter and first half of 2011.

Highlights

• Second quarter 2011 revenue of $92.8 million, up 60% from the second quarter 2010, aided by a 48% increase in crude oil production and 51% increase in realized crude oil prices versus that same period
• Second quarter 2011 EBITDAX of $56.4 million and net income of $25.0 million ($0.62 per share) respectively (see EBITDAX reconciliation in the tables)
• Oil production increased to 8,286 barrels (Bbls) per day with solid performance from EPL's existing assets and a full quarter production impact from properties acquired mid-February
• Liquidity continuing to build, with current cash estimated at $80 million and liquidity (cash on hand plus undrawn availability on the Company's revolver) of $230 million. Credit metrics remain strong with net debt per barrel of oil equivalent (Boe) down to $3.66
• 2011 operational results to date include 15 successful development projects for an 83% success rate year to date. P&A program continues ahead of schedule and has been expanded
• Numerous additional rig activities on the expanded asset base planned to begin late third quarter, which is projected to lead to a ramp up in oil production in the fourth quarter
• A dozen oil leads identified to date on the newly acquired properties, with targeted execution of this upside drilling potential planned to begin early 2012

Financial Results

Revenue for the second quarter and first half of 2011 was $92.8 million and $160.0 million, respectively. Revenue for the second quarter and first half of 2011 increased 60% and 24% versus prior periods, respectively, resulting from significantly higher oil production averages and realized oil prices.

For the second quarter of 2011, EPL reported net income to common stockholders of $25.0 million, or $0.62 per diluted share. The net income for the second quarter of 2011 included $18.9 million ($11.7 million, net of deferred income taxes) of non-cash or non-recurring items, primarily non-cash unrealized gains on derivative instruments of $23.3 million ($14.5 million, net of deferred income taxes). Excluding the impact of these items, EPL's adjusted second quarter net income, a non-GAAP measure, would have been net income of $13.3 million, or $0.33 per diluted share.

For the six months ended June 30, 2011, net income was $10.5 million, or $0.26 per diluted share. The net income for the first half of 2011 included $14.7 million ($9.2 million, net of deferred income taxes) of non-cash and non-recurring items, mainly comprised of $13.7 million of non-cash impairments ($8.5 million, net of deferred income taxes). The majority of the property impairments for the first half of the year occurred as a result of mechanical and performance issues with gas wells outside of the Company's focus areas. Excluding the impact of these items, EPL's adjusted net income for the first half of 2011, a non-GAAP measure, would have been net income of $19.7 million, or $0.49 per diluted share.

For the second quarter of 2011, EBITDAX was $56.4 million and discretionary cash flow was $52.6 million, or $1.31 per share (see reconciliation of EBITDAX and discretionary cash flow in the tables). Cash flow from operating activities in the second quarter of 2011 was $47.4 million, compared with cash flow from operating activities of $28.0 million in the same quarter a year ago.

For the first half of 2011, EBITDAX and discretionary cash flow totaled $94.3 million and $88.8 million, respectively (see reconciliation of EBITDAX and discretionary cash flow in the tables). Cash flow from operating activities in the first half of 2011 was $62.2 million compared to $67.5 million in 2010.

Gary C. Hanna, the Company's President and CEO, stated, "Our results for the second quarter of this year reflect the full integration of our property acquisition that closed mid-February and continuing execution of oil-focused development activities within our expanded asset base. With oil comprising 75% of our forecasted production for this year, we are positioned in this commodity market to provide substantial value to our stakeholders.

Production and Price Realizations

Oil production for the second quarter of 2011 averaged 8,286 Bbls per day, comprised of 98% crude oil production and 2% natural gas liquids. Natural gas production averaged 17.4 million cubic feet (Mmcf) per day. Second quarter 2011 crude oil production volumes were 48% higher than in the comparable quarter last year, primarily as a result of the recent acquisition of oil-weighted properties which closed mid-first quarter and the continued focus on oil-weighted projects. Natural gas production has declined sequentially in recent periods as the Company has continued its focus on the oil development opportunities which have higher revenue generation capability. Price realizations, all of which are stated before the impact of derivative instruments, averaged $114.52 per barrel for crude oil and $4.74 per thousand cubic feet (Mcf) of natural gas in the second quarter of 2011, compared to $75.87 per barrel of crude oil and $4.29 per Mcf of natural gas in the same quarter a year ago. The Company's crude oil is advantaged by receiving Heavy Louisiana Sweet and Light Louisiana Sweet crude oil basis differentials. 

Oil production for the first half of 2011 averaged 7,431 Bbls per day, comprised of 97% crude oil production and 3% natural gas liquids. Natural gas production averaged 20.2 Mmcf per day. Price realizations, all of which are stated before the impact of derivative instruments, averaged $108.80 per barrel for crude oil and $4.41 per Mcf of natural gas in the first half of 2011, compared to $76.54 per barrel of crude oil and $4.82 per Mcf of natural gas in the same period a year ago. 

Hanna commented, "As projected, we delivered a material increase in our oil production this past quarter. Additionally, our oil-weighted capital program will continue to ramp up significantly within the last four months of this year. This should allow us to reach new oil production highs as we exit the year and provide good momentum into 2012, whereby we plan to keep operations very active weather permitting."

Operating Expenses

Lease operating expenses (LOE) for the second quarter of 2011 totaled $17.9 million, while general and administrative (G&A) expenses were $4.8 million. Reported G&A expenses include non-cash stock based compensation recorded in the second quarter of 2011 of $0.8 million.

LOE for the first half of 2011 totaled $33.2 million, while G&A expenses were $10.1 million for the same period. Reported G&A expenses for the first half of 2011 include non-cash stock based compensation of $1.3 million. 

Liquidity and Capital Resources

As of June 30, 2011, the Company had unrestricted cash on hand of $76.2 million and $6.0 million of restricted cash. As announced in February of this year, EPL closed on its acquisition of producing Gulf of Mexico shelf properties (the Acquisition). At that same time, the Company issued $210 million aggregate principal amount of 8.25% Senior Notes due 2018 and entered into a new $250 million credit facility with $150 million of undrawn revolving capacity. Currently, EPL estimates unrestricted cash on hand of approximately $80 million for total estimated liquidity of $230 million and net debt of $3.66 per Boe using 2010 year-end proved reserves pro forma for the Acquisition.

Hanna commented, "Post transaction, our credit profile and liquidity remain very strong, with our already low net debt per Boe, currently estimated at $3.66, being driven lower due to our continuing cash build. Our cost of capital is attractive and we have enhanced our growing liquidity through our expanded but unused credit facility. We have the technical capability and financial flexibility to be acquisitive, with our eye squarely on aggregating additional oil-weighted shallow water GOM properties while maintaining a conservative balance sheet."

Capital Expenditures and Operations Update

During the first half of 2011, capital expenditures on exploration and development activities totaled approximately $27.9 million. In addition, the Company spent approximately $17.4 million in the first half of 2011 on plugging and abandonment and other decommissioning activities. 2011 operational results to date include 15 successful development projects for an 83% success rate year to date.

The Company's 2011 planned activities, predominately being executed within the third and fourth quarters this year, include major rig programs within its oily focus areas of East Bay, South Timbalier and West Delta. EPL's budget for 2011 includes $90 to $105 million of development activities, primarily in the East Bay, South Timbalier, West Delta, and Main Pass field areas, as well as an additional $20 million for exploration projects. The Company has expanded its proactive abandonment and decommissioning program, resulting in an increase of the 2011 budget for this program from approximately $17 million to $24 million. The program is ahead of schedule with 121 wells plugged and abandoned and 33 jacket and 2 platform removals completed. With this expanded budget, the Company plans to plug up to 163 wells and remove 53 jackets and 3 platforms in total for the year. By the end of 2011, EPL expects to have plugged over 325 wells since the start of the program in 2009, predominately within its East Bay field.

Hanna continued, "We remain encouraged by the performance of our first quarter acquisition. Now fully integrated, our initial well reactivation program has increased our production estimates for the acquired assets by upwards of 15% and we have reached our goal of decreasing LOE by approximately 15% in the operated properties. Our first workover program is now underway in the West Delta area. This development activity is comprised of high quality, low cost recompletion and sidetrack opportunities that are complementary to our other ongoing exploitation work within our existing East Bay and South Timbalier areas. Additionally, this acquisition has added at least a dozen drilling opportunities and has greatly expanded our upside portfolio targeting oil reserves. We should begin unlocking this potential as we head into next year."

Third Quarter and Full Year 2011 Guidance

Hanna concluded, "Given our current production guidance, our EBITDAX should range between $225 to $270 million, using forecast realized prices of $110 per Bbl for oil and $4.50 per Mcf for gas. These estimates are largely driven by our expected oil production guidance, which is unchanged at 8,000 to 9,000 Bbls per day. While we are not cash flow dependent on our gas production or devoting much of our capital resources to developing this side of our business due to weak prevailing gas prices, it is worth noting our gas production is expected to range from 13 to 18 Mmcf per day for the year. We have recently been informed by the operator of our one deepwater gas well in MC 248 that production will be curtailed for extended periods during the second half of the year due to third party downstream facility modifications. Since we are anticipating realizing around 25 times the revenue for every barrel of crude oil produced versus Mcf of gas produced, this development has not materially impacted our projected revenue or cash flow growth for the year." 

ESTIMATED EBITDAX RANGES
2011 EBITDAX Estimates Using the Production Guidance and Various Realized Prices (1)
	Full Year 2011 Production Rate
	8000 Bopd/13 Mmcf/d	8500 Bopd/15.5 Mmcf/d	9000 Bopd/18 Mmcf/d
Realized Prices($Bbl/$Mcf)
$100/$4.50	$210	$230	$250
$110/$4.50	$225	$245	$270
$120/$4.50	$240	$265	$290
(1) All EBITDAX figures are approximate using production and expense guidance and estimated realized hedging impacts.

ESTIMATED PRODUCTION & SWAP HEDGE VOLUMES
Net Production (per day)	3Q 2011			Full Year 2011
Oil, including NGLs (Bbls)	8,000	-	8,500	8,000	-	9,000
Natural gas (Mcf)	10,000	-	15,000	13,000	-	18,000
% Oil, including NGLs (using midpoint of guidance)		80%			77%
Swap Contracted Volume
Oil (barrels)		3,051			3,561
% of Oil swap contracted	38%	-	36%	45%	-	40%
% of Boe swap contracted	32%	-	28%	35%	-	30%
Average Swap Price Level		$87.44			$84.41
ESTIMATED EXPENSES (in Millions, unless otherwise noted)
Lease Operating (including energy insurance)	$ 18.0	-	21.0	$ 64.5	-	69.5
General & Administrative (cash and non-cash)	$ 4.5	-	5.3	$ 19.0	-	21.0
Taxes, other than on earnings (% of revenue)	3%	-	5%	3%	-	5%
Exploration Expense	$ 1.0	-	3.0	$ 2.0	-	5.0
DD&A ($/Boe)	$ 22.00	-	26.00	$ 21.00	-	25.00
Interest Expense (including amortization	$ 4.5	-	5.5	$ 17.5	-	18.5
of discount and deferred financing costs)

Conference Call Information

EPL has scheduled a conference call for today, August 3, 2011 at 9:00 A.M. Central Time/10:00 A.M. Eastern Time, to review results for the second quarter of 2011. To participate in the EPL conference call, callers in the United States and Canada can dial (866) 845-8624 and international callers can dial (706) 634-0487. The Conference I.D. for callers is 85141849.

The call will be available for replay beginning two hours after the call is completed through midnight of August 17, 2011. For callers in the United States and Canada, the toll-free number for the replay is (855) 859-2056. For international callers the number is (404) 537-3406. The Conference I.D. for all callers to access the replay is 85141849.

The conference call will be webcast live and 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.

Description of the Company

Founded in 1998, EPL is an independent oil and natural gas exploration and production company based in New Orleans, Louisiana, and Houston, Texas. The Company's operations are concentrated in the U.S. Gulf of Mexico shelf, focusing on the state and federal waters offshore Louisiana. For more information, please visit www.eplweb.com.

Investors/Media

T.J. Thom, Chief Financial Officer 504-799-1902 tthom@eplweb.com

Forward-Looking Statements

This press release may contain forward-looking information and statements regarding EPL. Any statements included in this press release that address activities, events or developments that EPL "expects," "believes," "plans," "projects," "estimates" or "anticipates" will or may occur in the future are forward-looking statements. We believe these judgments are reasonable, but actual results may differ materially due to a variety of important factors. Among other items, such factors might include: changes in general economic conditions; uncertainties in reserve and production estimates; unanticipated recovery or production problems; hurricane and other weather-related interference with business operations; the effects of delays in completion of, or shut-ins of, gas gathering systems, pipelines and processing facilities; changes in legislative and regulatory requirements concerning safety and the environment as they relate to operations; oil and natural gas prices and competition; the impact of derivative positions; production expenses and expense estimates; cash flow and cash flow estimates; future financial performance; planned and unplanned capital expenditures; drilling and operating risks; our ability to replace oil and gas reserves; risks and liabilities associated with the properties acquired in the acquisition; volatility in the financial and credit markets or in oil and natural gas prices; and other matters that are discussed in EPL's filings with the Securities and Exchange Commission. (http://www.sec.gov/).

ENERGY PARTNERS, LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)
(Unaudited)
	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2011	2010	2011	2010
Revenues:
Oil and natural gas	$ 92,798	$ 58,163	$ 160,013	$ 128,846
Other	32	34	66	70
	92,830	58,197	160,079	128,916
Costs and expenses:
Lease operating	17,908	13,675	33,239	28,117
Transportation expense	236	312	371	802
Exploration expenditures and dry hole costs	822	783	1,370	2,637
Impairments	2,886	10,885	13,674	11,654
Depreciation, depletion and amortization	25,522	26,106	46,585	55,961
Accretion of liability for asset retirement obligations	3,804	3,222	7,379	6,444
General and administrative	4,796	4,875	10,083	9,063
Taxes, other than on earnings	3,695	2,276	7,013	4,313
Other	1,902	740	2,032	491
Total costs and expenses	61,571	62,874	121,746	119,482
Income (loss) from operations	31,259	(4,677)	38,333	9,434
Other income (expense):
Interest income	17	88	27	97
Interest expense	(4,974)	(3,945)	(7,444)	(8,147)
Gain (loss) on derivative instruments	13,831	6,957	(11,694)	5,033
Loss on early extinguishment of debt	-	(5,627)	(2,377)	(5,627)
	8,874	(2,527)	(21,488)	(8,644)
Income (loss) before income taxes	40,133	(7,204)	16,845	790
Deferred income tax benefit (expense)	(15,130)	2,594	(6,351)	(284)
Net income (loss)	$ 25,003	$ (4,610)	$ 10,494	$ 506
Net income (loss), as reported	$ 25,003	$ (4,610)	$ 10,494	$ 506
Add back:
Unrealized gain due to the change in fair
market value of derivative contracts	(23,297)	(9,580)	(3,063)	(11,316)
Impairments	2,886	10,885	13,674	11,654
Loss on early extinguishment of debt	-	5,627	2,377	5,627
Loss on abandonment activities	1,559	774	1,731	577
Deduct:
Income tax adjustment for above items	7,107	(2,774)	(5,549)	(2,355)
Adjusted Non-GAAP net income (loss)	$ 13,258	$ 322	$ 19,664	$ 4,693
EBITDAX Reconciliation:
Net income (loss), as reported	$ 25,003	$ (4,610)	$ 10,494	$ 506
Add back:
Income taxes	15,130	(2,594)	6,351	284
Net interest expense	4,957	3,857	7,417	8,050
Depreciation, depletion, amortization and accretion	29,326	29,328	53,964	62,405
Impairments	2,886	10,885	13,674	11,654
Loss on extinguishment of debt	-	5,627	2,377	5,627
Exploration expenditures and dry hole costs	822	783	1,370	2,637
Loss on abandonment activities	1,559	774	1,731	577
Less impact of:
Unrealized (gain) loss due to the change in fair   market value of derivative contracts
	(23,297)	(9,580)	(3,063)	(11,316)
EBITDAX	$ 56,386	$ 34,470	$ 94,315	$ 80,424

EBITDAX is defined as net income (loss) before income taxes, net interest expense, depreciation, depletion, amortization and accretion, impairments, loss on extinguishment of debt, exploration expenditures and dry hole costs, loss on abandonment activities and cumulative effect of change in accounting principle, and further deducts the unrealized gain or loss on our derivative contracts. We have reported EBITDAX because we believe EBITDAX is a measure commonly reported and widely used in our industry as an indicator of a company's ability to internally fund exploration and development activities and incur and service debt. EBITDAX is not a calculation based on generally accepted accounting principles (GAAP) in the United States and should not be considered in isolation from or as a substitute for net income, as an indication of operating performance or cash flows from operating activities or as a measure of liquidity. Investors should carefully consider the specific items included in our computation of EBITDAX. Investors should be cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. In addition, EBITDAX does not represent funds available for discretionary use.

ENERGY PARTNERS, LTD.
CONSOLIDATED STATEMENTS OF NET CASH PROVIDED BY
OPERATING ACTIVITIES
(In thousands)
(Unaudited)
	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2011	2010	2011	2010
Cash flows from operating activities:
Net income (loss)	$ 25,003	(4,610)	10,494	506
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	25,522	26,106	46,585	55,961
Accretion of liability for asset retirement obligations	3,804	3,222	7,379	6,444
Unrealized gain on derivative contracts	(23,297)	(9,580)	(3,063)	(11,316)
Non-cash compensation	774	574	1,276	739
Repayment of PIK Notes issued for payment of in-kind interest	-	(6,620)	-	(3,395)
Deferred income taxes	15,131	(2,594)	6,334	284
Exploration expenditures	16	71	131	1,827
Impairments	2,886	10,885	13,674	11,654
Amortization of deferred financing costs and discount on debt	443	(47)	689	457
Loss on early extinguishment of debt	-	-	2,377	-
Other	1,559	774	1,731	577
Changes in operating assets and liabilities:
Trade accounts receivable	2,884	4,886	(9,523)	4,249
Other receivables	-	288	1,283	1,701
Prepaid expenses	(5,712)	1,042	(4,814)	(830)
Other assets	(92)	693	(13)	622
Accounts payable and accrued expenses	8,771	6,659	5,011	3,003
Other liabilities	(10,329)	(3,732)	(17,362)	(4,995)
Net cash provided by operating activities	$ 47,363	28,017	62,189	67,488
Reconciliation of discretionary cash flow:
Net cash provided by operating activities	47,363	28,017	62,189	67,488
Changes in working capital	4,478	(9,836)	25,418	(3,750)
Non-cash exploration expenditures and impairments	(2,902)	(10,956)	(13,805)	(13,481)
Total exploration expenditures, dry hole costs and impairments	3,708	11,668	15,044	14,291
Discretionary cash flow	$ 52,647	$ 18,893	$ 88,846	$ 64,548
The table above reconciles discretionary cash flow to net cash provided by or used in 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 the Company 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		Six Months Ended
	June 30,		June 30,
	2011	2010	2011	2010
PRODUCTION AND PRICING
Net Production (per day):
Crude Oil (Bbls)	8,082	5,454	7,186	5,711
Natural gas liquids (Bbls)	204	957	245	1,106
Oil (Bbls)	8,286	6,411	7,431	6,817
Natural gas (Mcf)	17,383	43,549	20,174	47,220
Total (Boe)	11,183	13,669	10,793	14,687
Average Sales Prices:
Crude Oil (Bbls)	$ 114.52	75.87	108.80	76.54
Natural gas liquids (Bbls)	58.06	40.14	53.77	42.46
Oil (Bbls)	113.14	70.54	106.98	71.01
Natural gas (per Mcf)	4.74	4.29	4.41	4.82
Average (per Boe)	91.19	46.76	81.90	48.47
Oil and Natural Gas Revenues (in thousands):
Crude Oil	$ 84,231	37,652	141,502	79,117
Natural gas liquids	1,076	3,497	2,390	8,499
Oil	85,307	41,149	143,892	87,616
Natural gas	7,491	17,014	16,121	41,230
Total	92,798	58,163	160,013	128,846
Impact of derivatives settled during the period (1):
Oil (per Bbl)	$ (12.55)	(4.66)	(10.97)	(5.17)
Natural gas (per Mcf)	-	0.02	-	0.01
OPERATIONAL STATISTICS
Average Costs (per Boe):
Lease operating expense	$ 17.60	10.99	17.01	10.58
Depreciation, depletion and amortization	25.08	20.99	23.85	21.05
Accretion expense	3.74	2.59	3.78	2.42
Taxes, other than on earnings	3.63	1.83	3.59	1.62
General and administrative	4.71	3.92	5.16	3.41
(1) The derivative amounts represent the realized portion of gains or losses on derivative contracts settled during the period which are included in Other income (expense) in the consolidated statements of operations.

ENERGY PARTNERS, LTD.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
	June 30,	December 31,
	2011	2010
ASSETS
Current assets:
Cash and cash equivalents	$ 76,228	$ 33,553
Trade accounts receivable - net	30,357	21,443
Receivables from insurance	805	2,088
Fair value of commodity derivative instruments	127	186
Deferred tax assets	183	2,693
Prepaid expenses	8,622	3,303
Total current assets	116,322	63,266
Property and equipment	967,419	719,147
Less accumulated depreciation, depletion and amortization	(228,308)	(168,055)
Net property and equipment	739,111	551,092
Restricted cash	6,022	8,489
Other assets	1,877	1,814
Deferred financing costs --- net of accumulated amortization	5,620	2,245
	$ 868,952	$ 626,906
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$ 12,774	$ 18,358
Accrued expenses	43,892	28,394
Asset retirement obligations	12,034	16,902
Fair value of commodity derivative instruments	5,604	12,320
Total current liabilities	74,304	75,974
Long-term debt	204,046	-
Asset retirement obligations	74,991	54,681
Deferred tax liabilities	26,293	22,469
Fair value of commodity derivative instruments	3,644	-
Other	663	666
	383,941	153,790
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.001 par value per share. Authorized 1,000,000 shares; no shares issued   and outstanding at June 30, 2011 and December 31, 2010.	-	-
Common stock, $0.001 par value per share. Authorized 75,000,000 shares; shares issued and   outstanding 40,236,729 and 40,091,664 at June 30, 2011 and December 31, 2010, respectively.	40	40
Additional paid-in capital	503,965	502,556
Accumulated deficit	(18,986)	(29,480)
Treasury stock, at cost, 6,345 shares at June 30, 2011	(8)	-
Total stockholders' equity	485,011	473,116
	$ 868,952	$ 626,906