EXHIBIT 99.1
EPL Announces Third Quarter and First Nine Months Results for 2013
First Nine Months Record Oil Production Drives EBITDAX to $384 million
EPL to Acquire New 3D Seismic Covering 200 GOM Shelf Blocks (~1 million acres)
HOUSTON, Oct. 31, 2013 (GLOBE NEWSWIRE) -- EPL Oil & Gas, Inc. (EPL or the Company) (NYSE:EPL) today reported financial and operational results for the third quarter and first nine months of 2013.
Highlights
- 3Q13 EBITDAX rose 144% versus 3Q12 to $127.5 million and adjusted non-GAAP net income rose 149% versus 3Q12 to $31.4 million, or $0.81 per diluted share (see reconciliation of EBITDAX and adjusted non-GAAP net income in the tables)
- 3Q13 discretionary cash flow rose 135% versus 3Q12 to $112.7 million, or $2.92 per share (see reconciliation of discretionary cash flow in the tables)
- 3Q13 oil production at 17,481 Bbls of oil per day, 96% higher than 3Q12
- 3Q13 total production at 23,097 Bbls of oil equivalent per day, 113% higher than 3Q12
- First nine months capital expenditures of $258.3 million; 32 successful projects to date (84% success rate)
- Production levels expected in 4Q13 primarily impacted by reduced production rates post storm of certain high-rate wells in the West Delta field area shut-in during Tropical Storm Karen. Rig sourced and mobilizing to area in mid-December to begin production uplift. Impact to forecasted 2013 oil production is approximately 7%
- Projected 2013 EBITDAX of $475 million (66% increase over 2012)
- Low leverage and ample liquidity: current net debt to projected 2013 EBITDAX estimated at 1.3x; liquidity in the form of cash plus undrawn revolver availability estimated at $303 million
- Efforts underway to unlock 3P resource potential: Recently signed seismic commitments totaling $45 million, including a multi-year commitment to acquire new 3D seismic covering 200 blocks (~1 million acres) within the shallow GOM. New 3D seismic acquisition to commence over core areas as early as 2Q14. The new 3D seismic combined with state of the art reprocessed datasets is expected to provide uplift necessary to exploit both the deep and shallow section of the Company's asset base
Financial Results
Revenue for the third quarter and first nine months of 2013 was $184.0 million and $550.4 million, respectively. Revenue for the third quarter and the first nine months of 2013 increased 112% and 93% respectively versus prior periods, driven by higher realized oil production from the Company's oil-weighted acquisitions and organic exploitation projects.
For the third quarter of 2013, EPL reported a net loss to common stockholders of $1.3 million, or $0.03 per diluted share, compared to a net loss of $2.2 million, or $0.06 per diluted share for the same period a year ago. The net loss for the quarter included $26.5 million of non-cash unrealized losses on derivative instruments and $24.9 million of costs primarily attributable to loss on abandonment activities. These abandonment costs include $21.8 million in abandonment costs related to four wellbores in our non-operated deepwater properties, which are related to investments made prior to the Company's reorganization in 2009. These increased deepwater abandonment costs are primarily attributable to changes in regulatory interpretations and enforcement by the federal regulators in the deepwater that increased the required scope of work. Excluding the impact of these items, EPL's adjusted third quarter net income, a non-GAAP measure, would have been $31.4 million, or $0.81 per diluted share, compared to $12.6 million, or $0.33 per diluted share, for the same period a year ago.
For the nine months ended September 30, 2013, net income was $97.3 million, or $2.48 per diluted share, compared to net income of $34.7 million, or $0.88 per diluted share for the same period a year ago. Net income for the first nine months of 2013 included $28.6 million total gains on sale of assets and $38.4 million of costs primarily attributable to loss on abandonment activities (including the increased deepwater costs described above for the third quarter). Excluding the impact of these items, EPL's adjusted net income for the first nine months of 2013, a non-GAAP measure, would have been net income of $103.6 million, or $2.64 per diluted share compared to $49.3 million, or $1.26 per diluted share, for the same period a year ago.
For the third quarter of 2013, EBITDAX was $127.5 million and discretionary cash flow was $112.7 million, or $2.92 per share (see reconciliation of EBITDAX and discretionary cash flow in the tables). Cash flow from operating activities in the third quarter of 2013 was $116.7 million, compared with cash flow from operating activities of $54.4 million in the same quarter a year ago.
For the first nine months of 2013, EBITDAX was $384.0 million and discretionary cash flow was $347.6 million, or $8.86 per share (see reconciliation of EBITDAX and discretionary cash flow in the tables). Cash flow from operating activities in the first nine months of 2013 was $309.2 million compared to $162.6 million for the same period a year ago.
Production and Price Realizations
Oil production for the third quarter of 2013 averaged 17,481 Barrels (Bbls) per day. Oil production volumes were 96% higher than in the comparable quarter last year, primarily as a result of organic oil production growth within EPL's existing core fields and the Hilcorp acquisition of oil-weighted properties that closed late last year.
Natural gas production averaged 33.7 million cubic feet (Mmcf) per day in the third quarter of 2013. Although EPL has continued its focus on oil development opportunities that have higher revenue generation potential than natural gas, with minimal expenditures, the Company has realized solid performance from its natural gas assets during the first nine months of this year.
Price realizations for the third quarter of 2013, all of which are stated before the impact of derivative instruments, averaged $110.88 per barrel for crude oil and $3.63 per thousand cubic feet (Mcf) of natural gas, compared to $105.35 per barrel of crude oil and $3.00 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 nine months of 2013 averaged 17,554 Bbls per day, which was 88% higher than the comparable period a year ago. Natural gas production averaged 34.1 Mmcf per day in the first nine months of 2013. Price realizations, all of which are stated before the impact of derivative instruments, averaged $110.02 per barrel for crude oil and $3.78 per Mcf of natural gas in the first nine months of 2013, compared to $110.25 per barrel of crude oil and $2.55 per Mcf of natural gas in the same period a year ago.
Operating Expenses
Lease operating expenses (LOE) for the third quarter of 2013 totaled $42.3 million, including approximately $2 million of non-routine workover expenses. General and administrative (G&A) expenses were $6.4 million during the third quarter of 2013. Reported expenses include non-cash stock based compensation recorded during the quarter of $1.9 million.
LOE for the first nine months of 2013 totaled $126.7 million, while G&A expenses were $20.9 million for the same period. Reported LOE and G&A increased over the same periods a year ago mainly due to costs associated with our expanded asset base. Reported expenses for the first nine months of 2013 include non-cash stock based compensation of $5.4 million.
Capital Expenditures and P&A Operations
During the first nine months of 2013, costs incurred for development and exploration activities totaled approximately $255.0 million, which combined with $3.3 million spent on seismic purchases, resulted in total expenditures of $258.3 million. So far to date this year, the Company has conducted 38 operations, including 14 successful sidetracks and drillwells and 18 successful workover and well reactivations, with an overall 84% success rate.
The Company currently expects capital expenditures to total approximately $335 million in 2013. Development and infield exploration spending is budgeted primarily in the West Delta, East Bay, South Timbalier, Ship Shoal, and South Pass core field areas. The Company has continued its active drilling and workover program with 5 rigs expected to be working within its core field areas during the remainder of the year. In addition, EPL expects to spend approximately $46 million for plugging and abandonment and other decommissioning activities. The Company spent approximately $36.8 million in the first nine months of 2013 on these activities.
EPL to Acquire New 3D Seismic Over Core Central GOM Shelf
EPL has recently signed 3D seismic commitments totaling approximately $45 million. These agreements include a commitment to acquire new 3D seismic using wide azimuth acquisition techniques covering a minimum of 200 blocks (~1 million acres) within the shallow water GOM. This new seismic acquisition, combined with state of the art 3D reprocessed datasets, are expected to enhance clarity and de-risk vast resources in the deep and shallow section of the Company's asset base. The new 3D Full Azimuth Nodal seismic data acquisition to be conducted by Fairfieldnodal is expected to commence late second quarter of 2014. During the fourth quarter of 2013, the Company expects to incur approximately $8 million of exploration expenses related to these seismic agreements.
Gary C. Hanna, the Company's Chairman, President and CEO, stated, "We have taken a measured step forward on our regional seismic and reprocessing efforts by becoming a major underwriter in new seismic acquisitions in the central GOM shelf. This new multi-year seismic commitment, covering a minimum of one million acres, will blanket our core areas and employ state of the art technology designed to image the deeper section while continuing to enhance the shallow. Additionally, we will also continue to utilize ever-improving reprocessing techniques, such as reverse time migration and inversion, to further drive our exploration and acquisition efforts both in the known producing pays and in the deeper, largely untested section."
Liquidity and Capital Resources
As of September 30, 2013, the Company had cash on hand of $2.9 million and long-term restricted cash of $6.0 million. EPL has a $750 million senior secured credit facility, with a current borrowing base of $425 million. As previously announced in April, 2013, we sold our Bay Marchand interests to the property operator for $51.5 million in cash and the buyer's assumption of liabilities recorded on our balance sheet of $11.3 million resulting in total consideration of $62.8 million, subject to customary adjustments to reflect the January 1, 2013 economic effective date. The cash proceeds from this sale of assets were deposited with a qualified intermediary in contemplation of a potential tax-deferred exchange of properties and classified as restricted cash at June 30, 2013. On September 26, 2013, $16.5 million of the proceeds were used to fund an acquisition of 100% of the working interest of certain Gulf of Mexico shelf oil and natural gas interests within the West Delta 29 field. On September 29, 2013, the underlying escrow agreement expired, and the remaining amount of the deposit became unrestricted. As a result, as of September 30, 2013, EPL had reduced its borrowings under its credit facility to $125 million, a reduction of $40 million since the prior quarter end.
EPL's current liquidity, in the form of cash plus undrawn revolver availability is approximately $303 million. Based on the solid performance of its assets, EPL's current leverage remains low, estimated at 1.3x net debt to projected 2013 EBITDAX using the midpoint of the guidance. (See the guidance section contained in this press release and the discussion of EBITDAX in the tables).
2013 and 2014 Hedge Position
The Company has layered in downside protection to protect its cash flow, mainly in the form of Louisiana Light Sweet (LLS) and Brent oil swaps. For the fourth quarter of 2013, EPL has a total of 8,045 Bbls of oil per day hedged, the majority of which is hedged using Brent swaps at a fixed price averaging $104.45 per Bbl. For full year 2014, EPL has a total of 10,996 Bbls of oil per day hedged, all of which is hedged using LLS and Brent swaps at a fixed price averaging $99.54 per Bbl. For the fourth quarter of 2013, EPL has a total of 7,332 Mcf per day of gas hedged, all of which is hedged using swaps at a fixed price averaging $3.68 per Mcf. For full year 2014, EPL has a total of 5,000 Mcf per day of gas hedged, all of which is hedged using swaps at a fixed price averaging $4.01 per Mcf.
Fourth Quarter and Full Year 2013 Guidance
Hanna concluded, "We are seeing some disruptions within this quarter, namely a week or so of downtime from tropical storm Karen and ongoing curtailed production from a third party pipeline shut-in that began last week. Additionally following the storm, as we worked to restore production, we have seen a significant performance drop off isolated to three high rate oil wells within our West Delta area shut-in during the event. Despite the drop, the wells are still highly economic, with production already exceeding our proved reserves to date and behind pipe opportunities we can recomplete to once the current zones deplete.
We have sourced a new rig to add to our active drilling program that is now set to mobilize to the West Delta field area as early as mid-December to begin executing projects within this prospect rich area. We are confident that this effort and our ongoing operations elsewhere will act to uplift our oil production. However, our fourth quarter oil production averages will suffer from this event and the other disruptions. Therefore, we are decreasing our 2013 annual forecasted oil production by roughly 7% to approximately 17,000 Bbls of oil per day, and we are forecasting our exit rate to be around 17,500 Bbls of oil per day. Despite this change and the recent decrease in oil prices, our projected 2013 EBITDAX remains high at approximately $475 million, up 66% from last year."
| ESTIMATED PRODUCTION & SWAP HEDGE VOLUMES | ||||||||
| Note: 4Q13/Full Yr 2013 production guidance impacted by the following: the downtime associated with fields shut-in during TS Karen, reduced rates post TS Karen isolated to the West Delta area, and 3rd party pipeline intregrity testing late Oct/early Nov affecting West Delta and South Pass field areas. | ||||||||
| Net Production (per day) | 4Q 2013 | Full Year 2013 | ||||||
| Oil, including NGLs (Bbls) | 14,750 | - | 15,750 | 16,850 | - | 17,100 | ||
| Natural gas (Mcf) | 24,000 | - | 30,000 | 31,500 | - | 33,000 | ||
| Boe | 18,750 | - | 20,750 | 22,100 | - | 22,600 | ||
| % Oil, including NGLs (using midpoint of guidance) | 77% | 76% | ||||||
| Swap Contracted Volume | ||||||||
| Oil (barrels) | 7,045 | 10,157 | ||||||
| % of Oil swap contracted | 46% | 60% | - | 59% | ||||
| % of Boe swap contracted | 36% | 46% | - | 45% | ||||
| Average Swap Price Level | $103.63 | $104.62 | ||||||
| ESTIMATED EXPENSES (in Millions, unless otherwise noted) | ||||||||
| Lease Operating (including energy insurance) | $ 41.0 | - | $ 44.0 | $ 168 | - | $ 171 | ||
| General & Administrative (cash and non-cash) | $ 7.0 | - | $ 7.5 | $ 28 | - | $ 29 | ||
| Taxes, other than on earnings | $ 2.5 | - | $ 3.5 | $ 11 | - | $ 12 | ||
| Exploration Expense | $ 11 | - | $ 13 | $ 21 | - | $ 23 | ||
| DD&A ($/Boe), excluding accretion | $ 25.50 | - | $ 27.00 | $ 25.50 | - | $ 27.00 | ||
| DD&A ($/Boe), including accretion | $ 28.50 | - | $ 30.00 | $ 28.50 | - | $ 30.00 | ||
| Interest Expense (including amortization of discount and deferred financing costs) | $ 12.5 | - | $ 13.5 | $ 51 | - | $ 53 | ||
| ESTIMATED EBITDAX: | $475 | Million | ||||||
| ESTIMATED FREE CASH FLOW: | $55 | Million | ||||||
Conference Call Information
EPL has scheduled a conference call for today, October 31, 2013, at 9:30 A.M. Central Time/10:30 A.M. Eastern Time to review results for the third quarter 2013 and to discuss its outlook for the remainder of the year. 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 88223861.
The call will be available for replay beginning two hours after the call is completed through midnight of November 14, 2013. 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 88223861.
The conference call will be webcast live as well as for on-demand listening at the Company's website, www.eplweb.com. Listeners may access the call through the "Events and Webcasts" link in the Investor Relations section of the site.
Description of the Company
Founded in 1998, EPL is an independent oil and natural gas exploration and production company headquartered in Houston, Texas with an office in New Orleans, Louisiana. 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.
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: 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; stock market conditions; the trading price of EPL's common stock; cash demands caused by planned and unplanned capital expenditures; changes in general economic conditions; uncertainties in reserve and production estimates, particularly with respect to internal estimates that are not prepared by independent reserve engineers; unanticipated recovery or production problems; changes in legislative and regulatory requirements concerning safety and the environment as they relate to operations and to abandonment of wells and production facilities; 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; drilling and operating risks; our ability to replace oil and gas reserves; risks and liabilities associated with properties acquired in acquisitions; integration of acquired assets; 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/)
| EPL OIL & GAS, INC. | ||||
| CONSOLIDATED STATEMENTS OF OPERATIONS | ||||
| (In thousands) | ||||
| (Unaudited) | ||||
| Three Months Ended | Nine Months Ended | |||
| September 30, | September 30, | |||
| 2013 | 2012 | 2013 | 2012 | |
| Revenue: | ||||
| Oil and natural gas | $ 183,114 | 86,645 | $ 547,099 | 284,666 |
| Other | 878 | 23 | 3,329 | 68 |
| 183,992 | 86,668 | 550,428 | 284,734 | |
| Costs and expenses: | ||||
| Lease operating | 42,291 | 24,995 | 126,663 | 62,067 |
| Transportation | 974 | 160 | 2,317 | 410 |
| Exploration expenditures and dry hole costs | 5,146 | 966 | 13,609 | 17,862 |
| Impairments | 12 | 498 | 2,183 | 6,206 |
| Depreciation, depletion and amortization | 53,989 | 27,106 | 153,847 | 78,932 |
| Accretion of liability for asset retirement obligations | 6,266 | 3,472 | 18,464 | 10,031 |
| General and administrative | 6,426 | 5,995 | 20,927 | 16,993 |
| Taxes, other than on earnings | 3,285 | 3,189 | 8,884 | 9,834 |
| Gain on sale of assets | (1,745) | - | (28,601) | - |
| Other | 26,534 | 998 | 33,077 | 4,616 |
| Total costs and expenses | 143,178 | 67,379 | 351,370 | 206,951 |
| Income from operations | 40,814 | 19,289 | 199,058 | 77,783 |
| Other income (expense): | ||||
| Interest income | 64 | 40 | 91 | 128 |
| Interest expense | (13,177) | (5,114) | (39,370) | (15,081) |
| Loss on derivative instruments | (30,012) | (22,108) | (7,033) | (11,865) |
| (43,125) | (27,182) | (46,312) | (26,818) | |
| Income (loss) before income taxes | (2,311) | (7,893) | 152,746 | 50,965 |
| Provision for Income taxes: | ||||
| Current | (25) | 126 | (175) | (174) |
| Deferred | 1,052 | 5,520 | (55,239) | (16,134) |
| Total provision for income taxes | 1,027 | 5,646 | (55,414) | (16,308) |
| Net income (loss) | $ (1,284) | (2,247) | $ 97,332 | 34,657 |
| Net income (loss), as reported | $ (1,284) | (2,247) | $ 97,332 | 34,657 |
| Add back: | ||||
| Unrealized loss (gain) due to the change in fair value of derivative instruments | 26,478 | 22,010 | (822) | 8,052 |
| Gain on sale of assets | (1,745) | - | (28,601) | - |
| Dry hole costs | 73 | (76) | 3,764 | 4,097 |
| Impairments | 12 | 498 | 2,183 | 6,206 |
| Loss on abandonment activities | 22,562 | 4 | 27,982 | 3,405 |
| Amortization of weather derivative premium | 4,022 | 1,029 | 5,333 | 1,371 |
| Deduct: | ||||
| Income tax adjustment for above items | (18,710) | (8,588) | (3,581) | (8,466) |
| Adjusted Non-GAAP net income | $ 31,408 | 12,630 | $ 103,590 | 49,322 |
| EBITDAX Reconciliation: | ||||
| Net income (loss), as reported | $ (1,284) | (2,247) | $ 97,332 | 34,657 |
| Add back: | ||||
| Income taxes | (1,027) | (5,646) | 55,414 | 16,308 |
| Net interest expense | 13,113 | 5,074 | 39,279 | 14,953 |
| Depreciation, depletion, amortization and accretion | 60,255 | 30,578 | 172,311 | 88,963 |
| Impairments | 12 | 498 | 2,183 | 6,206 |
| Exploration expenditures and dry hole costs | 5,146 | 966 | 13,609 | 17,862 |
| Loss on abandonment activities | 22,562 | 4 | 27,982 | 3,405 |
| Amortization of weather derivative premium | 4,022 | 1,029 | 5,333 | 1,371 |
| Gain on sale of assets | (1,745) | - | (28,601) | - |
| Less impact of: | ||||
| Unrealized loss (gain) due to the change in fair value of derivative instruments | 26,478 | 22,010 | (822) | 8,052 |
| EBITDAX | $ 127,532 | 52,266 | $ 384,020 | 191,777 |
| Weighted average dilutive common shares outstanding | 38,589 | 38,743 | 39,256 | 39,056 |
| EBITDAX is defined as net income (loss) before income taxes, net interest expense, depreciation, depletion, amortization and accretion, impairments, exploration expenditures and dry hole costs, loss on abandonment activities, amortization of weather derivative premium, and gain on sale of assets, and further deducts the unrealized gain or loss on our derivative instruments. 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. | ||||
| EPL OIL & GAS, INC. | ||||
| CONSOLIDATED STATEMENTS OF NET CASH PROVIDED BY | ||||
| OPERATING ACTIVITIES | ||||
| (In thousands) | ||||
| (Unaudited) | ||||
| Three Months Ended | Nine Months Ended | |||
| September 30, | September 30, | |||
| 2013 | 2012 | 2013 | 2012 | |
| Cash flows from operating activities: | ||||
| Net income (loss) | $ (1,284) | (2,247) | 97,332 | 34,657 |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||
| Depreciation, depletion and amortization | 53,989 | 27,106 | 153,847 | 78,932 |
| Accretion of liability for asset retirement obligations | 6,266 | 3,472 | 18,464 | 10,031 |
| Unrealized loss (gain) on derivative contracts | 26,478 | 22,010 | (822) | 8,052 |
| Non-cash compensation | 1,910 | 1,175 | 5,358 | 3,493 |
| Deferred income taxes | (1,052) | (5,520) | 55,239 | 16,134 |
| Exploration expenditures | 73 | (76) | 3,764 | 4,097 |
| Impairments | 12 | 498 | 2,183 | 6,206 |
| Amortization of deferred financing costs and discount on debt | 1,361 | 512 | 4,016 | 1,516 |
| Gain on sale of assets | (1,745) | - | (28,601) | - |
| Other | 22,562 | 4 | 27,982 | 3,405 |
| Changes in operating assets and liabilities: | ||||
| Trade accounts receivable | 8,542 | 4,270 | (1,718) | 5,171 |
| Prepaid expenses | 549 | 2,242 | (5,308) | 4,062 |
| Other assets | (1,361) | 440 | (1,077) | 362 |
| Accounts payable and accrued expenses | 10,457 | 8,852 | 15,345 | 14,149 |
| Asset retirement obligation settlements | (10,072) | (8,301) | (36,843) | (27,647) |
| Net cash provided by operating activities | $ 116,685 | 54,437 | 309,161 | 162,620 |
| Reconciliation of discretionary cash flow: | ||||
| Net cash provided by operating activities | 116,685 | 54,437 | 309,161 | 162,620 |
| Changes in working capital | (8,115) | (7,503) | 29,601 | 3,903 |
| Non-cash exploration expenditures and impairments | (85) | (422) | (5,947) | (10,303) |
| Total exploration expenditures, dry hole costs and impairments | 4,200 | 1,464 | 14,834 | 24,068 |
| Discretionary cash flow | $ 112,685 | 47,976 | 347,649 | 180,288 |
| 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. | ||||
| EPL OIL & GAS, INC | ||||
| SELECTED PRODUCTION, PRICING AND OPERATIONAL STATISTICS | ||||
| (Unaudited) | ||||
| Three Months Ended | Nine Months Ended | |||
| September 30, | September 30, | |||
| 2013 | 2012 | 2013 | 2012 | |
| PRODUCTION AND PRICING | ||||
| Net Production (per day): | ||||
| Crude Oil (Bbls) | 16,563 | 8,466 | 16,785 | 8,923 |
| Natural Gas Liquids (Bbls) | 918 | 435 | 769 | 427 |
| Oil (Bbls) | 17,481 | 8,901 | 17,554 | 9,350 |
| Natural gas (Mcf) | 33,696 | 11,558 | 34,130 | 14,378 |
| Total (Boe) | 23,097 | 10,827 | 23,242 | 11,746 |
| Average Sales Prices: | ||||
| Crude Oil (per Bbl) | $ 110.88 | 105.35 | $ 110.02 | 110.25 |
| Natural Gas Liquids (per Bbl) | 34.23 | 35.03 | 36.65 | 43.27 |
| Oil (per Bbl) | 106.85 | 101.91 | 106.81 | 107.19 |
| Natural gas (per Mcf) | 3.63 | 3.00 | 3.78 | 2.55 |
| Average (per Boe) | 86.17 | 86.98 | 86.22 | 88.44 |
| Oil and Natural Gas Revenues (in thousands): | ||||
| Crude Oil | $ 168,956 | 82,051 | $ 504,160 | 269,568 |
| Natural Gas Liquids | 2,891 | 1,402 | 7,690 | 5,061 |
| Oil | 171,847 | 83,453 | 511,850 | 274,629 |
| Natural gas | 11,267 | 3,192 | 35,249 | 10,037 |
| Total | 183,114 | 86,645 | 547,099 | 284,666 |
| Impact of derivative instruments settled during the period(1): | ||||
| Oil (per Bbl) | $ (2.18) | (0.11) | $ (1.53) | (1.49) |
| Natural gas (per Mcf) | (0.01) | (0.01) | (0.05) | - |
| OPERATIONAL STATISTICS | ||||
| Average Costs (per Boe): | ||||
| Lease operating expense | $ 19.90 | 25.09 | $ 19.96 | 19.28 |
| Depreciation, depletion and amortization | 25.41 | 27.21 | 24.25 | 24.52 |
| Accretion expense | 2.95 | 3.49 | 2.91 | 3.12 |
| Taxes, other than on earnings | 1.55 | 3.20 | 1.40 | 3.06 |
| General and administrative | 3.02 | 6.02 | 3.30 | 5.28 |
| (1)The derivative amounts represent the realized portion of gains or losses on derivative instruments settled during the period which are included in Other income (expense) in the consolidated statements of operations. | ||||
| EPL OIL & GAS, INC. | ||
| CONSOLIDATED BALANCE SHEETS | ||
| (In thousands, except share data) | ||
| (Unaudited) | ||
| September 30, | December 31, | |
| 2013 | 2012 | |
| ASSETS | ||
| Current assets: | ||
| Cash and cash equivalents | $ 2,939 | $ 1,521 |
| Trade accounts receivable - net | 68,748 | 67,991 |
| Fair value of commodity derivative instruments | 972 | 3,302 |
| Deferred tax asset | 4,414 | 3,322 |
| Prepaid expenses | 14,454 | 9,873 |
| Total current assets | 91,527 | 86,009 |
| Property and equipment | 2,299,323 | 2,025,647 |
| Less accumulated depreciation, depletion, amortization and impairments | (569,124) | (427,580) |
| Net property and equipment | 1,730,199 | 1,598,067 |
| Restricted cash | 6,023 | 6,023 |
| Fair value of commodity derivative instruments | 675 | 211 |
| Deferred financing costs --- net of accumulated amortization | 10,851 | 12,386 |
| Other assets | 4,023 | 2,931 |
| $ 1,843,298 | $ 1,705,627 | |
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||
| Current liabilities: | ||
| Accounts payable | $ 55,410 | $ 34,772 |
| Accrued expenses | 103,160 | 117,372 |
| Asset retirement obligations(1) | 47,482 | 30,179 |
| Fair value of commodity derivative instruments | 10,694 | 10,026 |
| Deferred tax liabilities | - | - |
| Total current liabilities | 216,746 | 192,349 |
| Long-term debt | 621,723 | 689,911 |
| Asset retirement obligations(1) | 240,288 | 204,931 |
| Deferred tax liabilities | 124,025 | 67,694 |
| Fair value of commodity derivative instruments | 281 | 3,637 |
| Other | 1,158 | 1,132 |
| 1,204,221 | 1,159,654 | |
| Commitments and contingencies | ||
| Stockholders' equity: | ||
| Preferred stock, $0.001 par value per share. Authorized 1,000,000 shares; no shares issued and outstanding at September 30, 2013 and December 31, 2012 | - | - |
| Common stock, $0.001 par value per share. Authorized 75,000,000 shares; shares issued 40,948,737 and 40,601,887 at September 30, 2013 and December 31, 2012, respectively; shares outstanding 39,083,424 and 39,103,203 at September 30, 2013 and December 31, 2012, respectively | 40 | 40 |
| Additional paid-in capital | 516,690 | 510,469 |
| Treasury stock, at cost, 1,865,313 and 1,498,684 shares at September 30, 2013 and December 31, 2012, respectively | (30,926) | (20,477) |
| Retained earnings | 153,273 | 55,941 |
| Total stockholders' equity | 639,077 | 545,973 |
| $ 1,843,298 | $ 1,705,627 | |
| (1)We revise our estimates of ARO as information about material changes to the liability becomes known. During the three months ended September 30, 2013, we recorded revisions to our ARO liability related to our shallower-water assets of $31.0 million. This does not affect current results of operations, but increases the carrying amount of the related assets and will result in higher DD&A including accretion expense in future periods. | ||
CONTACT: Investors/Media
T.J. Thom, Chief Financial Officer
713-228-0711
tthom@eplweb.com