Exhibit 99.1
EPL Announces Fourth Quarter and Year-End Results for 2011
New Orleans, Louisiana, March 8, 2012…Energy Partners, Ltd. (EPL or the Company) (NYSE:EPL) today reported financial and operational results for the fourth quarter and full year 2011.
Highlights
| • | 2011 EBITDAX of $224.1 million and net income of $26.6 million ($0.66 per share) respectively (see EBITDAX reconciliation in the tables) |
| • | 2011 revenue increased to $348.3 million, up 45% from full year 2010, aided by a 26% increase in oil production in 2011 versus 2010 |
| • | Proved reserves of 37.1 Mmboe (74% oil) at year-end 2011, a 35% increase over year-end 2010 and a 59% increase in oil reserves driven by a combination of acquisitions and organic growth |
| • | Probable reserves of 14.0 Mmboe (67% oil) at year-end 2011, a 15% increase over year-end 2010 |
| • | PV10 estimated at $1.1 billion for 1P and $1.6 billion for 2P reserves using SEC prices |
| • | 2012 capital budget of $168 million, up 67% over 2010 and dominated by oil projects intended to drive both production and organic reserve growth |
Financial Results
Revenue for the fourth quarter of 2011 was $103.4 million, compared to $54.7 million for the same period a year ago, driven by higher realized oil production and oil prices from the Company’s focus on oil-weighted development projects. This benefit, coupled with increased oil prices, resulted in full year 2011 revenues increasing 45% to $348.3 million versus $239.9 million for full year 2010.
For the fourth quarter of 2011, EPL reported a net loss to common stockholders of $7.3 million, or $0.19 per diluted share, compared to a net loss of $1.1 million, or $0.03 per diluted share for the same period a year ago. The net loss for the fourth quarter of 2011 was attributable to $19.6 million of non-cash unrealized losses on derivative instruments, $13.3 million of non-cash costs attributable to property impairments, and a $2.4 million loss on abandonment activities. The majority of these latter two items related to gas properties outside of the Company’s focus areas. Excluding the impact of these non-cash items, EPL’s adjusted fourth quarter net income, a non-GAAP measure, would have been $15.0 million, or $0.38 per diluted share.
For full year 2011, net income was $26.6 million, or $0.66 per diluted share, compared to a net loss of $8.5 million, or $0.21 per diluted share for full year 2010. The net income for 2011 was impacted by $11.5 million of non-cash unrealized gains on derivative instruments offset by $32.5 million of non-cash costs attributable to property impairments and a $7.0 million loss on abandonment activities related mainly to gas properties, and a $2.4 million non-cash loss due to early extinguishment of debt. Excluding the impact of these non-cash items, EPL’s adjusted 2011 net income, a non-GAAP measure, would have been $45.6 million, or $1.14 per diluted share.
For the fourth quarter of 2011, EBITDAX was $74.9 million and discretionary cash flow was $71.1 million, or $1.79 per share (see reconciliation to GAAP of EBITDAX and discretionary cash flow in the tables). Cash flow from operating activities in the fourth quarter of 2011 was $65.3 million, a 115% increase over cash flow from operating activities for the same quarter a year ago.
For full year 2011, EBITDAX was $224.1 million and discretionary cash flow was $210.8 million, or $5.26 per share (see reconciliation to GAAP of EBITDAX and discretionary cash flow in the tables). Cash flow from operating activities in 2011 was $171.3 million, a 34% increase over cash flow from operating activities for 2010.
Gary C. Hanna, the Company’s President and CEO, stated, “I am pleased with our execution on our stated goals for 2011 which focused on our oil operations and the execution of two targeted acquisitions, both of which provided prudent growth for our Company. In just a few short years, we have turned the corner on a host of operational initiatives, including transforming from a gas driven company into being oil-rich in terms of production, reserves, and upside opportunities. 2012 is a pivotal year for our Company as we continue to implement our organic and acquisition growth strategy. We have increased our capital budget by 67% this year to $168 million to allow us to exploit oil opportunities within our focus areas through capital efficient development and infield exploration. With our substantial liquidity and continued free cash flow generation, we also intend to execute on prudent acquisition targets to accelerate our growth and provide additional opportunity sets.”
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Production and Price Realizations
Oil production for the fourth quarter of 2011 averaged 9,440 Barrels (Bbls) per day, which was in the upper end of the Company’s guidance range and a new record high for the Company. Fourth quarter 2011 oil production volumes were 64% higher than in the comparable quarter last year, primarily as a result of the two acquisitions of oil-weighted properties during the year and the continued focus on oil-weighted projects.
Natural gas production averaged 15.2 million cubic feet (Mmcf) per day in the fourth quarter of 2011, which was slightly above the Company’s guidance range. Natural gas production has declined sequentially in recent periods as the Company has continued its focus on oil development opportunities which have higher revenue generation capability.
Price realizations for the fourth quarter of 2011, all of which are stated before the impact of derivative instruments, averaged $116.40 per barrel for crude oil and $3.19 per thousand cubic feet (Mcf) of natural gas, compared to $85.39 per barrel of crude oil and $3.81 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 2011 averaged 8,089 Bbls per day and natural gas production averaged 18.0 Mmcf per day. Price realizations for the full year, all of which are stated before the impact of derivative instruments, averaged $110.82 per barrel for crude oil and $4.11 per Mcf of natural gas, compared to $78.24 per barrel of crude oil and $4.49 per Mcf of natural gas in 2010.
Operating Expenses
Lease operating expenses (LOE) for the fourth quarter of 2011 totaled $17.8 million, while general and administrative (G&A) expenses were $4.2 million. LOE for 2011 totaled $70.3 million, while G&A expenses were $18.7 million for the same period. Reported LOE increased over the same periods a year ago mainly due to two property acquisitions concluded during the year while G&A was essentially flat versus the comparable periods. G&A expenses included non-cash stock based compensation recorded in the fourth quarter and full year 2011 of $0.7 million and $2.5 million, respectively.
Capital Expenditures and P&A Operations
For full year 2011, costs incurred for development and exploration activities totaled approximately $101 million and was predominately expenditures on oil projects. During the year, the Company completed 39 operations, including 8 successful sidetracks and drillwells and 23 successful workovers, with an overall 80% success rate.
The Company had drill-bit additions from seven successful oil wells (a 70% success rate) totaling 1.2 million barrels of oil equivalent (Mmboe) of proved reserves, and 0.6 Mmboe of probable reserves. The probable reserves are expected to contribute through further production performance. 2011 finding and development costs associated with drill-bit activities were approximately $23.17 per Boe on a 1P basis and $14.93 per Boe on a 2P basis. The successful oil wells, all of which have been brought on line, include two wells in the Company’s East Bay field, two in its Main Pass area, and three within the Ship Shoal 72 field.
In addition, the Company spent approximately $32 million in 2011 for largely discretionary plugging and abandonment and other decommissioning activities performed during the year, which will serve to reduce future maintenance and insurance costs.
Liquidity and Capital Resources
As of December 31, 2011, the Company had unrestricted cash on hand of $80.1 million and restricted cash of $6.0 million. In February 2011, EPL closed on its acquisition of producing Gulf of Mexico (GOM) shelf properties from Anglo-Suisse Offshore Partners, LLC for $200.7 million in cash, subject to customary adjustments to reflect the January 1, 2011 economic effective date (the ASOP Acquisition). In order to finance the ASOP Acquisition, the Company also closed its offering of $210 million aggregate principal amount of 8.25% Senior Notes due 2018. Concurrently, the Company entered into a new $250 million credit facility, which currently has $200 million of undrawn revolving capacity, none of which has been drawn since the establishment of the facility. In November 2011, the Company closed on its acquisition of certain interests in its Main Pass area of operations for $38.6 million in cash subject to customary adjustments to reflect the November 1, 2011 economic effective date (the MP Acquisition). The MP Acquisition was funded with cash on hand. At year end 2011, the Company had substantial liquidity of $280 million (the undrawn revolver capacity of $200 million combined with $80.1 million of cash on hand) and its net debt level remained low at $3.50 per Boe, on a 1P basis, a non-GAAP measure.
Year-End 2011 Proved Reserves
As previously released, EPL’s estimated proved reserves as of December 31, 2011 were 37.1 million barrels of oil equivalent (Mmboe) (74% oil), representing an increase of 35% compared to estimated proved reserves of 27.4 Mmboe (63% oil) as of December 31, 2010. The net increase in estimated proved reserves was the result of increases from drilling additions of 1.2 Mmboe, additions from development activities of 1.8 Mmboe, revisions of 1.7 Mmboe and acquisitions of 9.4 Mmboe, offset by 4.5 Mmboe of net production. The additions, revisions and acquisitions replaced 316% of 2011 net production.
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The estimated proved reserve growth was weighted towards oil, adding 13.0 million barrels. The year-end 2011 estimated proved reserves of 37.1 Mmboe include estimated proved developed reserves of 33.6 Mmboe (74% oil) and estimated proved undeveloped (PUDs) reserves of 3.5 Mmboe (71% oil).
The present value of the future net cash flows before income taxes of the Company’s estimated proved oil and natural gas reserves at the end of 2011 using a discount rate of 10% (PV-10) was approximately $1.1 billion as calculated consistent with SEC guidelines and pricing (PV-10 is a non-GAAP measure; see table below and discussion of PV-10 in the appendix).
Year-End 2011 Probable Reserves
As of December 31, 2011, EPL estimated probable reserves associated with its proven reserve base at year-end 2011 of 14.0 million Boe, up 15% from year-end 2010. The estimated probable reserves are comprised of 67% oil and 38% are related to performance of the proved producing reserves and therefore have no associated capital requirements.
The present value of the future net cash flows before income taxes of the Company’s estimated probable oil and natural gas reserves at the end of 2011 using a discount rate of 10% (PV-10) was approximately $0.5 billion as calculated consistent with SEC guidelines and pricing (calculation excludes any probability weighting; PV-10 is a non-GAAP measure; see table below and discussion of PV-10 in the appendix).
All of the Company’s proved and probable reserve figures are based upon third party engineering estimates prepared by Netherland, Sewell & Associates, Inc. and Ryder Scott Company, L.P.
2P RESERVES AND PV-10 VALUES
Reserve Category | Oil (Mmbo) | Gas (Bcf) | Mmboe | PV10 YE ($Mm)(1) | ||||||||||||
Proved Developed | 24.8 | 52.7 | 33.6 | 976 | ||||||||||||
Proved Undeveloped | 2.5 | 6.1 | 3.5 | 129 | ||||||||||||
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Proved (1P) | 27.3 | 58.8 | 37.1 | 1,105 | ||||||||||||
Probables | 9.3 | 28 | 14 | 452 | ||||||||||||
Proved + Probables (2P) | 36.6 | 86.8 | 51.1 | 1,557 | ||||||||||||
| (1) | The present value of the future net cash flows before income taxes of the Company’s estimated proved oil and natural gas reserves at the end of 2011 using a discount rate of 10% (PV-10) as calculated consistent with SEC guidelines and 2011 pricing of $108.48 per barrel of oil and $4.16 per Mcf of natural gas. |
Acreage
At year-end 2011, EPL’s gross developed leasehold acreage totaled 143,444 acres and gross acreage totaled 334,501 acres. Net developed leasehold acreage and total net leasehold acreage were 102,699 and 212,719 acres, respectively. Eighty-seven percent of the combined undeveloped and developed net leasehold acreage is located on the GOM shelf, and the remaining 13% is primarily undeveloped deepwater GOM acreage.
2012 Capital Budget and Current Operations
The Company currently plans to spend approximately $168 million on oil-dominated development and exploration activities in 2012. Within the current budget, $110 million is allocated to development activities, $50 million towards oily infield exploration projects located within existing core field areas, and $8 million on regional seismic purchases surrounding EPL’s focus areas from Main Pass to West Delta. Development and infield exploration spending is budgeted primarily in the West Delta, East Bay, South Timbalier, and Main Pass field areas. In addition, the Company plans to spend approximately $27 million in 2012 on mainly discretionary plugging and abandonment and other decommissioning activities.
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The Company currently has 5 rigs contracted for the year, including barge, platform and jack-up rigs necessary to execute its capital program. The Company has continued its active drilling program from fourth quarter last year, with 3 rigs currently running operations in the West Delta and East Bay areas. Capital spending is expected to be front-loaded this year, intended to drive both production and organic reserve replacement.
First Quarter and Full Year 2012 Guidance
ESTIMATED EBITDAX RANGES
2012 EBITDAX Estimates Using the Production Guidance and Various Realized Prices(1)
| Est. Production Rates | ||||||||||||
| 9000 Bopd/11 Mmcf/d | 9500 Bopd/13 Mmcf/d | 10,000 Bopd/15 Mmcf/d | ||||||||||
Realized Prices ($Bbl/$Mcf) | ||||||||||||
$100/$2.50 | $ | 240 | $ | 260 | $ | 280 | ||||||
$110/$2.50 | $ | 270 | $ | 285 | $ | 300 | ||||||
$120/$2.50 | $ | 285 | $ | 305 | $ | 325 | ||||||
| (1) | All EBITDAX figures are approximate using production and expense guidance and estimated realized hedging impacts |
ESTIMATED PRODUCTION & SWAP HEDGE VOLUMES
| 1Q 2012 | Full Year 2012 | |||
Net Production (per day) | ||||
Oil, including NGLs (Bbls) | 9,000 - 9,500 | 9,000 - 10,000 | ||
Natural gas (Mcf) | 11,000 - 15,000 | 11,000 - 15,000 | ||
% Oil, including NGLs (using midpoint of guidance) | 81% | 81% | ||
Swap Contracted Volume | ||||
Oil (barrels) | 4,088 | 3,433 | ||
% of Oil swap contracted | 45% - 43% | 38% - 34% | ||
% of Boe swap contracted | 38% - 34% | 32% - 27% | ||
Average Swap Price Level | $100.99 | $101.48 | ||
ESTIMATED EXPENSES (in Millions, unless otherwise noted) | ||||
Lease Operating (including energy insurance) | $17.5 - $19.5 | $70.0 - $78.0 | ||
General & Administrative (cash and non-cash) | $4.5 - $5.5 | $18 - $23 | ||
Taxes, other than on earnings (% of revenue) | 3% - 5% | 3% - 5% | ||
Exploration Expense | $8 - $12 | $10 - $14 | ||
DD&A ($/Boe) | $20.00 - $26.00 | $20.00 - $26.00 | ||
Interest Expense (including amortization of discount and deferred financing costs) | $5 - $6 | $20 - $24 | ||
Conference Call Information
EPL has scheduled a conference call for today, March 8, 2012, at 9:00 A.M. Central Time/10:00 A.M. Eastern Time to review results for the fourth quarter and full year 2011 and to discuss its outlook for 2012. 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 52455198.
The call will be available for replay beginning two hours after the call is completed through midnight of March 22, 2012. 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 52455198.
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.
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
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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 properties acquired in acquisitions; 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/).
Appendix
PV-10 Definition and Discussion
PV-10 may be considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. Because the standardized measure is dependent on the unique tax situation of each company, our calculation may not be comparable to those of our competitors. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis.
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ENERGY PARTNERS, LTD.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
| December 31, | ||||||||
| 2011 | 2010 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 80,128 | $ | 33,553 | ||||
Trade accounts receivable - net | 31,817 | 21,443 | ||||||
Receivables from insurance | — | 2,088 | ||||||
Fair value of commodity derivative instruments | 587 | 186 | ||||||
Deferred tax assets | — | 2,693 | ||||||
Prepaid expenses | 11,046 | 3,303 | ||||||
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Total current assets | 123,578 | 63,266 | ||||||
Property and equipment | 1,082,248 | 719,147 | ||||||
Less accumulated depreciation, depletion and amortization | (305,110 | ) | (168,055 | ) | ||||
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Net property and equipment | 777,138 | 551,092 | ||||||
Restricted cash | 6,023 | 8,489 | ||||||
Other assets | 3,029 | 1,814 | ||||||
Deferred financing costs — net of accumulated amortization | 5,452 | 2,245 | ||||||
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| $ | 915,220 | $ | 626,906 | |||||
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LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 25,393 | $ | 18,358 | ||||
Accrued expenses | 58,538 | 28,394 | ||||||
Asset retirement obligations | 25,578 | 16,902 | ||||||
Fair value of commodity derivative instruments | 1,056 | 12,320 | ||||||
Deferred tax liabilities | 2,823 | — | ||||||
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Total current liabilities | 113,388 | 75,974 | ||||||
Long-term debt | 204,390 | — | ||||||
Asset retirement obligations | 73,769 | 54,681 | ||||||
Deferred tax liabilities | 31,775 | 22,469 | ||||||
Fair value of commodity derivative instruments | 190 | — | ||||||
Other | 663 | 666 | ||||||
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| 424,175 | 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 December 31, 2011 and 2010 | — | — | ||||||
Common stock, $0.001 par value per share. Authorized 75,000,000 shares; shares issued 40,326,451 and 40,091,664 at December 31, 2011 and 2010, respectively; shares outstanding 39,404,106 and 40,091,664 at December 31, 2011 and 2010, respectively | 40 | 40 | ||||||
Additional paid-in capital | 505,235 | 502,556 | ||||||
Treasury stock, at cost, 922,345 shares at December 31, 2011 | (11,361 | ) | — | |||||
Accumulated deficit | (2,869 | ) | (29,480 | ) | ||||
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Total stockholders’ equity | 491,045 | 473,116 | ||||||
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| $ | 915,220 | $ | 626,906 | |||||
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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.
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ENERGY PARTNERS, LTD.
CONSOLIDATED STATEMENTS OF NET CASH PROVIDED BY
OPERATING ACTIVITIES
(In thousands)
(Unaudited)
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income (loss) | $ | (7,341 | ) | (1,128 | ) | 26,611 | (8,468 | ) | ||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||
Depreciation, depletion and amortization | 31,543 | 23,277 | 104,624 | 104,561 | ||||||||||||
Accretion of liability for asset retirement obligations | 3,770 | 3,201 | 15,942 | 12,845 | ||||||||||||
Unrealized loss (gain) on derivative contracts | 19,647 | 4,798 | (11,475 | ) | (3,500 | ) | ||||||||||
Non-cash compensation | 676 | 260 | 2,509 | 1,255 | ||||||||||||
Repayment of PIK Notes issued for payment of in-kind interest | — | — | — | (3,395 | ) | |||||||||||
Deferred income taxes | (5,295 | ) | (717 | ) | 14,822 | (4,409 | ) | |||||||||
Exploration expenditures | 11,092 | 2,290 | 11,239 | 5,103 | ||||||||||||
Impairments | 13,269 | 2,122 | 32,466 | 26,142 | ||||||||||||
Amortization of deferred financing costs and discount on debt | 505 | 382 | 1,657 | 1,130 | ||||||||||||
Loss on early extinguishment of debt | — | — | 2,377 | — | ||||||||||||
Other | 2,373 | (943 | ) | 6,984 | (90 | ) | ||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||
Trade accounts receivable | (3,607 | ) | 1,928 | (10,037 | ) | 6,515 | ||||||||||
Other receivables | 805 | — | 2,088 | 3,376 | ||||||||||||
Prepaid expenses | (2,416 | ) | 1,170 | (7,623 | ) | (363 | ) | |||||||||
Other assets | (353 | ) | 276 | (1,215 | ) | 618 | ||||||||||
Accounts payable and accrued expenses | 7,087 | (1,300 | ) | 12,650 | 2,361 | |||||||||||
Other liabilities | (6,438 | ) | (5,228 | ) | (32,367 | ) | (16,301 | ) | ||||||||
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Net cash provided by operating activities | $ | 65,317 | 30,388 | 171,252 | 127,380 | |||||||||||
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Reconciliation of discretionary cash flow: | ||||||||||||||||
Net cash provided by operating activities | 65,317 | 30,388 | 171,252 | 127,380 | ||||||||||||
Changes in working capital | 4,922 | 3,154 | 36,504 | 3,794 | ||||||||||||
Non-cash exploration expenditures and impairments | (24,361 | ) | (4,412 | ) | (43,705 | ) | (31,245 | ) | ||||||||
Total exploration expenditures, dry hole costs and impairments | 25,194 | 4,635 | 46,734 | 32,583 | ||||||||||||
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Discretionary cash flow | $ | 71,072 | $ | 33,765 | $ | 210,785 | $ | 132,512 | ||||||||
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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.
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ENERGY PARTNERS, LTD.
SELECTED PRODUCTION, PRICING AND OPERATIONAL STATISTICS
(Unaudited)
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
PRODUCTION AND PRICING | ||||||||||||||||
Net Production (per day): | ||||||||||||||||
Crude Oil (Bbls) | 9,041 | 5,094 | 7,796 | 5,473 | ||||||||||||
Natural gas liquids (Bbls) | 399 | 670 | 293 | 928 | ||||||||||||
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Oil (Bbls) | 9,440 | 5,764 | 8,089 | 6,401 | ||||||||||||
Natural gas (Mcf) | 15,239 | 34,564 | 17,968 | 42,488 | ||||||||||||
Total (Boe) | 11,980 | 11,524 | 11,084 | 13,482 | ||||||||||||
Average Sales Prices: | ||||||||||||||||
Crude Oil (Bbls) | $ | 116.40 | 85.39 | 110.82 | 78.24 | |||||||||||
Natural gas liquids (Bbls) | 55.68 | 41.47 | 55.40 | 40.71 | ||||||||||||
Oil (Bbls) | 113.84 | 80.28 | 108.81 | 72.80 | ||||||||||||
Natural gas (per Mcf) | 3.19 | 3.81 | 4.11 | 4.49 | ||||||||||||
Average (per Boe) | 93.76 | 51.58 | 86.07 | 48.72 | ||||||||||||
Oil and Natural Gas Revenues (in thousands): | ||||||||||||||||
Crude Oil | $ | 96,823 | 40,016 | 315,347 | 156,297 | |||||||||||
Natural gas liquids | 2,043 | 2,555 | 5,928 | 13,782 | ||||||||||||
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Oil | 98,866 | 42,571 | 321,275 | 170,079 | ||||||||||||
Natural gas | 4,476 | 12,116 | 26,932 | 69,691 | ||||||||||||
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Total | 103,342 | 54,687 | 348,207 | 239,770 | ||||||||||||
Impact of derivatives settled during the period (1): | ||||||||||||||||
Oil (per Bbl) | $ | (1.27 | ) | (2.23 | ) | (5.87 | ) | (3.62 | ) | |||||||
Natural gas (per Mcf) | — | — | — | 0.01 | ||||||||||||
OPERATIONAL STATISTICS | ||||||||||||||||
Average Costs (per Boe): | ||||||||||||||||
Lease operating expense | $ | 16.13 | 10.74 | 17.37 | 10.64 | |||||||||||
Depreciation, depletion and amortization | 28.62 | 21.95 | 25.86 | 21.25 | ||||||||||||
Accretion expense | 3.42 | 3.02 | 3.94 | 2.61 | ||||||||||||
Taxes, other than on earnings | 3.50 | 2.56 | 3.55 | 2.06 | ||||||||||||
General and administrative | 3.81 | 3.97 | 4.63 | 3.67 | ||||||||||||
| (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. |
Page 8 of 10
ENERGY PARTNERS, LTD.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
| December 31, | ||||||||
| 2011 | 2010 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 80,128 | $ | 33,553 | ||||
Trade accounts receivable - net | 31,817 | 21,443 | ||||||
Receivables from insurance | — | 2,088 | ||||||
Fair value of commodity derivative instruments | 587 | 186 | ||||||
Deferred tax assets | — | 2,693 | ||||||
Prepaid expenses | 11,046 | 3,303 | ||||||
|
|
|
| |||||
Total current assets | 123,578 | 63,266 | ||||||
Property and equipment | 1,082,248 | 719,147 | ||||||
Less accumulated depreciation, depletion and amortization | (305,110 | ) | (168,055 | ) | ||||
|
|
|
| |||||
Net property and equipment | 777,138 | 551,092 | ||||||
Restricted cash | 6,023 | 8,489 | ||||||
Other assets | 3,029 | 1,814 | ||||||
Deferred financing costs — net of accumulated amortization | 5,452 | 2,245 | ||||||
|
|
|
| |||||
| $ | 915,220 | $ | 626,906 | |||||
|
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|
| |||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 25,393 | $ | 18,358 | ||||
Accrued expenses | 58,538 | 28,394 | ||||||
Asset retirement obligations | 25,578 | 16,902 | ||||||
Fair value of commodity derivative instruments | 1,056 | 12,320 | ||||||
Deferred tax liabilities | 2,823 | — | ||||||
|
|
|
| |||||
Total current liabilities | 113,388 | 75,974 | ||||||
Long-term debt | 204,390 | — | ||||||
Asset retirement obligations | 73,769 | 54,681 | ||||||
Deferred tax liabilities | 31,775 | 22,469 | ||||||
Fair value of commodity derivative instruments | 190 | — | ||||||
Other | 663 | 666 | ||||||
|
|
|
| |||||
| 424,175 | 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 December 31, 2011 and 2010 | — | — | ||||||
Common stock, $0.001 par value per share. Authorized 75,000,000 shares; shares issued 40,326,451 and 40,091,664 at December 31, 2011 and 2010, respectively; shares outstanding 39,404,106 and 40,091,664 at December 31, 2011 and 2010, respectively | 40 | 40 | ||||||
Additional paid-in capital | 505,235 | 502,556 | ||||||
Treasury stock, at cost, 922,345 shares at December 31, 2011 | (11,361 | ) | — | |||||
Accumulated deficit | (2,869 | ) | (29,480 | ) | ||||
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|
|
| |||||
Total stockholders’ equity | 491,045 | 473,116 | ||||||
|
|
|
| |||||
| $ | 915,220 | $ | 626,906 | |||||
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| |||||
Page 9 of 10
ENERGY PARTNERS, LTD.
SUPPLEMENTAL OIL & GAS DISCLOSURE
(Unaudited)
| Crude Oil (Mbbl) | Natural Gas (Mmcf) | Equivalents (Mboe) | ||||||||||
Proved developed and undeveloped reserves: | ||||||||||||
December 31, 2009 | 19,923 | 67,378 | 31,153 | |||||||||
Extensions, discoveries and other additions | 652 | 489 | 733 | |||||||||
Revisions | (1,016 | ) | 8,892 | 466 | ||||||||
Production | (2,336 | ) | (15,508 | ) | (4,921 | ) | ||||||
|
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|
|
|
| |||||||
December 31, 2010 | 17,223 | 61,251 | 27,431 | |||||||||
Acquisitions | 7,987 | 8,640 | 9,427 | |||||||||
Extensions, discoveries and other additions | 2,266 | 4,664 | 3,043 | |||||||||
Revisions | 2,778 | (6,678 | ) | 1,666 | ||||||||
Production | (2,953 | ) | (9,092 | ) | (4,468 | ) | ||||||
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|
|
|
| |||||||
December 31, 2011 | 27,301 | 58,785 | 37,099 | |||||||||
Proved developed reserves: | ||||||||||||
December 31, 2009 | 15,026 | 57,139 | 24,549 | |||||||||
December 31, 2010 | 15,974 | 56,410 | 25,376 | |||||||||
December 31, 2011 | 24,791 | 52,739 | 33,581 | |||||||||
Costs incurred for oil and natural gas property acquisition, exploration and development activities for the two-years ended December 31 are as follows (in thousands):
| 2011 | 2010 | |||||||
Acquisitions: | ||||||||
Proved | 261,812 | — | ||||||
Unproved | 14 | 623 | ||||||
Exploration | 17,129 | 31,463 | ||||||
Development | 83,420 | 25,514 | ||||||
|
|
|
| |||||
Total finding and development costs | 100,549 | 56,977 | ||||||
|
|
|
| |||||
Total finding, development and acquisition costs | 362,375 | 57,600 | ||||||
|
|
|
| |||||
Asset retirement liabilities incurred | 157 | 129 | ||||||
Total cost incurred | $ | 362,532 | $ | 57,729 | ||||
Page 10 of 10