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EPL Announces Year-End Results for 2013

EPL Oil & Gas, Inc. Logo

2013 Oil Production Up 63% Over 2012

148% Organic Reserve Replacement

Recent EI Acquisition Drives 1P Reserves to 84 Mmboe

Proved + Probable Reserves Estimated at 114 Mmboe, $3.2 Billion PV10

Additional Drilling Inventory Increases 54% to 100 Mmboe

Deep Oil Sand Discovery in Ship Shoal Set to Production Test at End of 1Q14

HOUSTON, Feb. 27, 2014 (GLOBE NEWSWIRE) -- EPL Oil & Gas, Inc. (EPL or the Company) (NYSE:EPL) today reported financial and operational results for the fourth quarter and full year 2013.

Highlights

  • 2013 EBITDAX of $472.8 million (64% increase over 2012) and adjusted net income of $108.1 million, or $2.76 per diluted share (see EBITDAX reconciliation in the tables)
  • Estimated proved reserves of 80.4 Mmboe and PV10 of $2.1 Billion as of December 31, 2013, representing organic production replacement of 148% (see discussion of PV10 in the appendix)
  • Year-end 2013 proved reserve values exclude the recently closed acquisition of Eugene Island 258/259 field which currently are estimated at 3.6 Mmboe, 96% oil (up 39% since first announcement)
  • Estimated probable reserves of 29.8 Mmboe (68% oil) as of December 31, 2013, with PV10 of $1.0 Billion (see discussion of PV10 in the appendix)
  • Additional internally evaluated drilling inventory grows 54% to 100 Mmboe since last updated in 3Q13, representing 109 projects within the shallow sections of EPL's core fields
  • Deep oil sand discovery from the 4Q13 exploratory drillwell at SS208 set to production test end of 1Q14

Financial Results

For full year 2013, revenues increased 64% to $693 million versus $423.6 million for full year 2012, mainly attributable to a 63% increase in 2013 annual oil production. A large portion of this oil production increase resulted from the Hilcorp acquisition in November 2012 and organic development activities. For full year 2013, net income was $85.3 million, or $2.15 per diluted share, compared to net income of $58.8 million, or $1.50 per diluted share for full year 2012. The net income for 2013 included $20.9 million of non-cash losses on derivative instruments, $27.2 million of losses on abandonment activities related mainly to non-operated deepwater properties and a $28.7 million gain on the sale of assets. Excluding the impact of these items, EPL's 2013 adjusted net income, a non-GAAP measure, would have been $108.1 million, or $2.76 per diluted share.

Revenue for the fourth quarter of 2013 was $142.6 million, compared to $138.9 million for the same period a year ago. For the fourth quarter of 2013, EPL reported net loss to common stockholders of $12.1 million, or $0.31 per diluted share, compared to a net income of $24.2 million, or $0.61 per diluted share, for the same period a year ago. The net loss for the fourth quarter of 2013 included $26.0 million of items, mainly comprised of $21.7 million of non-cash losses on derivative instruments. Excluding the impact of these items, EPL's adjusted fourth quarter net income, a non-GAAP measure, would have been $4.5 million, or $0.12 per diluted share.

For full year 2013, EBITDAX was $472.8 million and discretionary cash flow was $423.9 million, or $10.80 per share (see reconciliation to GAAP of EBITDAX and discretionary cash flow in the tables). Cash flow from operating activities in 2013 was $387.6 million, an 81% increase over cash flow from operating activities for 2012.

For the fourth quarter of 2013, EBITDAX was $88.8 million and discretionary cash flow was $76.3 million, or $1.97 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 2013 was $78.4 million, a 53% increase compared to cash flow from operating activities for the same quarter a year ago.

Gary C. Hanna, the Company's Chairman, President and CEO, stated, "2013 was a transformational year that delivered on all of our stated goals as we continued our focus on implementing our acquire and exploit strategy. With six acquisitions under our belt since 2011 including the recently closed Eugene Island 258/259 field, we are focused squarely on the future upside potential of our current asset base. With our regional expertise, we will continue to focus on operational and technical excellence as we continue to extract shallow and deep organic production and reserve growth from our high quality acreage.

"Our portfolio in the shallow section has grown to 214 Mmboe, consisting of 114 Mmboe of proved and probable reserves fully engineered by NSAI plus our additional internally evaluated drilling portfolio, which we currently estimate to be at 100 Mmboe. This is outside of our 3P inventory in the deeper section, which is conservatively estimated at 150 to 300 Mmboe. All of these estimates are before the added benefit of new 3D seismic and reprocessed datasets expected to start coming in house late this year from our $45 million multi-year seismic commitments."

Production and Price Realizations

Oil production for 2013 averaged 16,938 barrels (Bbls) per day, up 63% from 2012. Oil production for 2013 was within the Company's guidance range and a new record annual high for the Company. Natural gas production for 2013 averaged 32.9 million cubic feet (Mmcf) per day, on the highside of the Company's guidance. Price realizations for full year 2013, all of which are stated before the impact of derivative instruments, averaged $107.32 per barrel for crude oil and $3.81 per thousand cubic feet (Mcf) of natural gas, compared to $108.88 per barrel of crude oil and $2.89 per Mcf of natural gas in 2012.

Oil production for the fourth quarter of 2013 averaged 15,109 Bbls per day and natural gas production averaged 29.1 Mmcf per day, both solidly within the Company's guidance range. Price realizations for the fourth quarter of 2013, all of which are stated before the impact of derivative instruments, averaged $97.82 per barrel for crude oil and $3.91 per Mcf of natural gas, compared to $106.07 per barrel of crude oil and $3.40 per Mcf of natural gas in the same quarter a year ago.

Operating Expenses

Lease operating expenses (LOE) and general and administrative expenses (G&A) for full year and fourth quarter 2013 came in on the low end of, or favorably below, Company guidance ranges previously provided.

LOE for 2013 totaled $165.8 million and G&A expenses were $28.1 million. LOE for the fourth quarter of 2013 totaled $39.2 million and G&A expenses were $7.2 million. Expenses included non-cash stock based compensation recorded in the full year and fourth quarter 2013 of $7.3 million and $2.0 million, respectively.

Capital Expenditures and P&A Operations

For full year 2013, costs incurred for development and exploration activities totaled approximately $335.9 million and $12.3 million on seismic purchases. During the year, the Company completed 44 major operations, including 14 successful sidetracks and drillwells and 22 successful workovers and well reactivations, with an overall 82% success rate. Additionally, the Company spent $2.1 million on 5 bid leases comprising 13,892 acres in the shallow Gulf of Mexico shelf.

In addition, the Company spent approximately $53.3 million in 2013 for plugging and abandonment and other decommissioning activities performed during the year, which will serve to reduce future maintenance and insurance costs. In total, since the Company began focusing its efforts to reduce its idle iron in late 2009, the Company has plugged and abandoned 509 wells and decommissioned 153 jackets and platforms.

Year-End 2013 Proved & Probable Reserves + Subsequent Additions from 2014 EI Asset Acquisition

The Company's estimated proved reserves as of December 31, 2013 were 80.4 Mmboe (64% oil). At year-end 2013, 57.4 Mmboe (or 71%) of these proved reserves were proved developed reserves, 69% of which were oil. Estimated proved undeveloped reserves (PUDs) at year-end 2013 were 23.1 Mmboe, 52% of which were oil. The year-end 2013 proved reserves of 80.4 Mmboe excludes an additional 3.6 Mmboe of estimated proved reserves from the recently closed acquisition of the Eugene Island (EI) 258/259 field that closed in January 2014.

The net increase in total estimated proved reserves for year-end 2013 was the result of 10.7 Mmboe of organic reserve additions from extensions and discoveries, positive revisions of 2.3 Mmboe, acquisitions of 0.4 Mmboe, offset by 8.8 Mmboe of net production and 1.6 Mmboe of asset sales. Organic additions and revisions replaced 148% of 2013 net production. EPL's focus on oil activities led to an oil reserve replacement of 183% for 2013, which has been consistently in this same range over the last three years. (See the Supplemental Oil & Gas Disclosure table for details).

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 2013 using a discount rate of 10% (PV10) was approximately $2.1 billion as calculated consistent with SEC guidelines and pricing. All development, P&A and decommissioning costs are included in the calculation of PV10. (PV10 is a non-GAAP measure; see table below and discussion of PV10 in the appendix).

The Company's estimated probable reserves as of December 31, 2013 were 29.8 Mmboe, 68% of which were oil. 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 2013 using a discount rate of 10% (PV10) was approximately $1.0 billion as calculated consistent with SEC guidelines and pricing. (PV10 is a non-GAAP measure; see table below and discussion of PV10 in the appendix).

All of the Company's 2013 proved and probable reserve figures are based upon third party engineering estimates prepared by Netherland, Sewell & Associates, Inc.

1P & 2P RESERVES AND PV10 VALUES
Reserve Category Oil (Mmbo) Gas (Bcf) Mmboe % Oil PV10 YE ($Billion)(1)
Proved Developed 39.4 107.7 57.4 69% 1.4
Proved Undeveloped 12.1 65.9 23.0 53% 0.7
2013 Proved (1P) 51.5 173.6 80.4 64% 2.1
2014 Proved (1P) EI asset acq 3.4 1.2 3.6 96% 0.1
2013 Probables 20.2 57.8 29.8 68% 1.0
Proved + Probables 75.1 232.6 113.8 66% 3.2
(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 2013 using a discount rate of 10% (PV10) as calculated consistent with SEC guidelines and 2013 pricing of $105.30 per barrel of oil and $3.73 per Mcf of natural gas.

Acreage

At year-end 2013, EPL's gross and net leasehold acreage totaled 422,065 and 309,468, respectively. Of the net leasehold acreage 77% was developed. Ninety-six percent of the total net leasehold acreage is located on the GOM shelf, and the remaining 4% is primarily undeveloped deepwater GOM acreage.

Liquidity and Capital Resources

As of December 31, 2013, the Company had unrestricted cash on hand of $8.8 million and restricted cash of $6.0 million. During the year ended December 31, 2013, EPL reduced its borrowings under its senior credit facility to $130 million, a reduction of $65 million since December 31, 2012. Of the net proceeds of $52 million from the sale of certain interests within Bay Marchand, approximately $17 million was used to fund the West Delta 29 acquisition and approximately $35 million was used in this reduction of borrowings.

EPL recently completed its acquisition of the EI 258/259 field for $70.4 million in January, 2014, subject to customary adjustments to reflect the September 1, 2013 economic effective date. The acquisition was financed with borrowings under EPL's senior credit facility. In January 2014, EPL's lenders approved a $50 million increase in the Company's borrowing base from $425 million to $475 million. As of February 21, 2014, the Company had $265 million available under its senior credit facility. EPL currently has $210 million outstanding under its senior credit facility, and its leverage remains low at 1.6x net debt to projected 2014 EBITDAX using the midpoint of the guidance. (See the guidance section contained in this press release and the discussion of EBITDAX in the tables.)

2014 Initial Capital Budget and Current Operations

The Company's previously announced initial capital budget remains at $360 million, dominated by oily, lower-risk development activities in 2014. This initial budget will primarily fund the exploitation of the shallow section within EPL's Ship Shoal, West Delta, South Timbalier, and Main Pass core field areas. Capital spending is still expected to be front loaded, intended to drive production growth and organic reserve replacement. Roughly 70% of the capital budget is expected to be spent on drillwells and sidetrack operations, 17% on major rig workovers and waterflood opportunities intended to drive oil production increases for select reservoirs within core field areas, and the remaining 13% of the budget consists primarily of facility projects.

This initial budget has been conservatively designed to measure results in the first half of 2014, commodity prices, and free cash flow generation. Based on these factors, this initial budget could be modified up or down during 2014. Increases to the budget could include allocating capital to projects designed to test the deeper section of the Company's core field areas as high-quality reprocessed and new seismic data becomes available throughout the coming year. In addition, the Company plans to spend approximately $50 million in 2014 on plugging and abandonment and other decommissioning activities. This initial budget does not include any future acquisitions or stock repurchases under EPL's previously authorized program.

The Company has continued its active drilling program from the fourth quarter of 2013, with 7 rigs currently working within its core field areas. EPL has secured the rigs necessary to execute its capital plans, mainly consisting of jack-up and hydraulic workover rigs necessary to execute its capital program.

New 3D Seismic and Deeper Drilling Update

In addition to its ongoing development activities in the shallow section of its core areas, the Company concluded an initial deeper test of moderate potential within its Ship Shoal 208 field area that began late 2013. The Company has made an apparent oil sand discovery within the exploratory well at approximately 15,300 feet subsea, which is set to production test at the end of the first quarter 2014. EPL is the operator and has a 50% working interest in the well. This initial test discovering apparent deep oil sand potential is encouraging. EPL is preparing for additional deeper exploratory testing of larger potential in depths from 12,000 to 20,000 feet throughout Ship Shoal 208 and its other core areas once new 3D seismic and state of the art reprocessing comes in house beginning late this year.

To aid in unlocking this deeper potential, EPL signed new 3D seismic commitments totaling approximately $45 million in late 2013. These agreements include a commitment to purchase new 3D seismic datasets using new 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 sections of the Company's asset base. The new 3D Full Azimuth Nodal (FAN) seismic data acquisition is being conducted by Fairfieldnodal. The first survey covering the Company's recently acquired EI 258/259 field is expected to be delivered late 2014. Additional 3D FAN seismic data acquisitions are still expected to commence within areas inclusive of EPL's other core fields late in the second quarter of 2014. During 2014, the Company expects to incur approximately $15 million of exploration expenses related to seismic agreements.

2014 Hedging

The Company has layered in downside protection to protect its cash flow for 2014, in the form of Louisiana Light Sweet (LLS) swaps. EPL has a total of 12,996 Bbls of oil per day hedged, or 67% hedged using the midpoint of oil guidance at a fixed price averaging $93.67 per Bbl. 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.

2014 Guidance

EPL's annual 2014 guidance remains unchanged and is inclusive of the effects of the acquisition of the EI 258/259 field. Due to oil focused drilling activities plus new oil production from the EI 258/259 field, EPL expects its March oil exit rate at 18,500 Bbls of oil per day and continued ramping of oil production throughout the remainder of the year.

ESTIMATED PRODUCTION & SWAP HEDGE VOLUMES
Net Production (per day) Full Year 2014 1Q 2014 Mar '14 Exit Rate
Oil, including NGLs (Bbls) 18,500 - 20,500 15,500 - 16,500 18,500
Natural gas (Mcf) 27,000 - 33,000 23,000 - 25,000 25,000
Boe 23,000 - 26,000 19,333 - 20,667 22,667
% Oil, including NGLs (using midpoint of guidance) 80% 80% 82%
ESTIMATED EXPENSES (in Millions, unless otherwise noted)
Lease Operating (including energy insurance) $180 - $200 $45.0 - $50.0
General & Administrative (cash and non-cash) $34 - $38 $8.5 - $9.5
Taxes, other than on earnings $9 - $11 $2.3 - $2.8
Exploration Expense $23 - $25 $5.8 - $6.3
DD&A ($/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 $54 - $56 $13.5 - $14.0
of discount and deferred financing costs)
2014 EBITDAX ESTIMATES AT VAROUS PRODUCTION AND REALIZED PRICES
Est. Production Rate
18,500 Bopd/27 Mmcf/d 19,500 Bopd/30 Mmcf/d 20,500 Bopd/33 Mmcf/d
Realized Prices($Bbl/$Mcf)
$105/$4.25 $440 $475 $510
$100/$4.25 $430 $465 $500
$95/$4.25 $420 $455 $490
(1) All EBITDAX figures are approximate using production ranges and midpoint of expense guidance with estimated realized hedging impacts
2014 INITIAL 2P CAPITAL BUDGET: $360 million
2014 P&A BUDGET: $50 million

Conference Call Information

EPL has scheduled a conference call for today, February 27, 2014, at 9:30 A.M. Central Time/10:30 A.M. Eastern Time to review results for the fourth quarter and full year 2013 and to discuss its outlook for 2014. 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 33396854.

The call will be available for replay beginning two hours after the call is completed through midnight of March 13, 2014. 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 33396854.

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 "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/)

Appendix

PV10 Definition and Discussion

PV10 may be considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of PV10 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, PV10 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.

EPL OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)
(Unaudited)
Three Months Ended Twelve Months Ended
December 31, December 31,
2013 2012 2013 2012
Revenue:
Oil and natural gas $ 141,644 137,863 $ 688,743 422,529
Other 966 1,036 4,295 1,104
142,610 138,899 693,038 423,633
Costs and expenses:
Lease operating 39,178 32,783 165,841 94,850
Transportation 1,251 205 3,568 615
Exploration expenditures and dry hole costs 12,946 937 26,555 18,799
Impairments 754 2,677 2,937 8,883
Depreciation, depletion and amortization 46,512 34,649 200,359 113,581
Accretion of liability for asset retirement obligations 9,835 5,534 28,299 15,565
General and administrative 7,210 6,215 28,137 23,208
Taxes, other than on earnings 2,606 3,173 11,490 13,007
Gain on sale of assets (80) -- (28,681) --
Other 1,865 62 34,942 4,678
Total costs and expenses 122,077 86,235 473,447 293,186
Income from operations 20,533 52,664 219,591 130,447
Other income (expense):
Interest income 8 8 99 136
Interest expense (12,998) (13,487) (52,368) (28,568)
Loss on derivative instruments (25,328) (1,440) (32,361) (13,305)
(38,318) (14,919) (84,630) (41,737)
Income (loss) before income taxes (17,785) 37,745 134,961 88,710
Provision for Income taxes:
Current 175 174 -- --
Deferred 5,552 (13,766) (49,687) (29,900)
Total provision for income taxes 5,727 (13,592) (49,687) (29,900)
Net income (loss) $ (12,058) 24,153 $ 85,274 58,810
Net income (loss), as reported $ (12,058) 24,153 $ 85,274 58,810
Add back:
Change in fair value of derivative instruments 21,706 1,439 20,884 9,491
Gain on sale of assets (80) -- (28,681) --
Dry hole costs 1,756 130 5,520 4,227
Impairments 754 2,677 2,937 8,883
Loss (gain) on abandonment activities (747) (957) 27,235 2,448
Amortization of weather derivative premium 2,667 1,029 8,000 2,400
Deduct:
Income tax adjustment for above items (9,484) (1,572) (13,066) (9,991)
Adjusted Non-GAAP net income $ 4,514 26,899 $ 108,103 76,268
EBITDAX Reconciliation:
Net income (loss), as reported $ (12,058) 24,153 $ 85,274 58,810
Add back:
Income taxes (5,727) 13,592 49,687 29,900
Net interest expense 12,990 13,479 52,269 28,432
Depreciation, depletion, amortization and accretion 56,347 40,183 228,658 129,146
Impairments 754 2,677 2,937 8,883
Exploration expenditures and dry hole costs 12,946 937 26,555 18,799
Loss (gain) on abandonment activities (747) (957) 27,235 2,448
Amortization of weather derivative premium 2,667 1,029 8,000 2,400
Gain on sale of assets (80) -- (28,681) --
Less impact of:
Change in fair value of derivative instruments 21,706 1,439 20,884 9,491
EBITDAX $ 88,798 96,532 $ 472,818 288,309
Weighted average dilutive common shares outstanding 38,641 38,998 39,236 39,034
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 Twelve Months Ended
December 31, December 31,
2013 2012 2013 2012
Cash flows from operating activities:
Net income (loss) $ (12,058) 24,153 85,274 58,810
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 46,512 34,649 200,359 113,581
Accretion of liability for asset retirement obligations 9,835 5,534 28,299 15,565
Change in fair value of derivative contracts 21,706 1,439 20,884 9,491
Non-cash compensation 1,986 1,224 7,344 4,717
Deferred income taxes (5,552) 13,766 49,687 29,900
Exploration expenditures 1,756 130 5,520 4,227
Impairments 754 2,677 2,937 8,883
Amortization of deferred financing costs and discount on debt 1,380 1,040 5,396 2,556
Gain on sale of assets (80) -- (28,681) --
Other (747) (957) 27,235 2,448
Changes in operating assets and liabilities:
Trade accounts receivable (198) (38,718) (1,916) (33,547)
Prepaid expenses 7,389 (3,015) 2,081 1,047
Other assets 1,867 (217) 790 145
Accounts payable and accrued expenses 20,313 17,328 35,658 31,477
Asset retirement obligation settlements (16,465) (7,782) (53,308) (35,429)
Net cash provided by operating activities $ 78,398 51,251 387,559 213,871
Reconciliation of discretionary cash flow:
Net cash provided by operating activities 78,398 51,251 387,559 213,871
Changes in working capital (12,906) 32,404 16,695 36,307
Non-cash exploration expenditures and impairments (2,510) (2,807) (8,457) (13,110)
Total exploration expenditures, dry hole costs and impairments 13,303 3,614 28,137 27,682
Discretionary cash flow $ 76,285 84,462 423,934 264,750
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 Twelve Months Ended
December 31, December 31,
2013 2012 2013 2012
PRODUCTION AND PRICING
Net Production (per day):
Crude Oil (Bbls) 14,185 13,057 16,130 9,963
Natural Gas Liquids (Bbls) 924 459 808 435
Oil (Bbls) 15,109 13,516 16,938 10,398
Natural gas (Mcf) 29,101 28,198 32,863 17,852
Total (Boe) 19,959 18,216 22,415 13,373
Average Sales Prices:
Crude Oil (per Bbl) $ 97.82 106.07 $ 107.32 108.88
Natural Gas Liquids (per Bbl) 41.46 38.21 38.04 41.93
Oil (per Bbl) 94.37 103.77 104.01 106.08
Natural gas (per Mcf) 3.91 3.40 3.81 2.89
Average (per Boe) 77.14 82.27 84.18 86.33
Oil and Natural Gas Revenues (in thousands):
Crude Oil $ 127,657 127,422 $ 631,817 396,989
Natural Gas Liquids 3,526 1,613 11,216 6,674
Oil 131,183 129,035 643,033 403,663
Natural gas 10,462 8,828 45,710 18,866
Total 141,645 137,863 688,743 422,529
Impact of derivative instruments settled during the period(1):
Oil (per Bbl) $ (2.65) 0.37 $ (1.78) (0.88)
Natural gas (per Mcf) 0.02 (0.18) (0.04) (0.07)
OPERATIONAL STATISTICS
Average Costs (per Boe):
Lease operating expense $ 21.34 19.56 $ 20.27 19.38
Depreciation, depletion and amortization 25.33 20.68 24.49 23.21
Accretion expense 5.36 3.30 3.46 3.18
Taxes, other than on earnings 1.42 1.89 1.40 2.66
General and administrative 3.93 3.71 3.44 4.74
(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)
December 31, December 31,
2013 2012
ASSETS
Current assets:
Cash and cash equivalents $ 8,812 $ 1,521
Trade accounts receivable - net 70,707 67,991
Fair value of commodity derivative instruments 501 3,302
Deferred tax asset 8,949 3,322
Prepaid expenses 6,868 9,873
Total current assets 95,837 86,009
Property and equipment 2,355,219 2,025,647
Less accumulated depreciation, depletion, amortization and impairments (618,788) (427,580)
Net property and equipment 1,736,431 1,598,067
Deposit for Nexen Acquisition 7,040 -
Restricted cash 6,023 6,023
Fair value of commodity derivative instruments 238 211
Deferred financing costs --- net of accumulated amortization 10,106 12,386
Other assets 2,156 2,931
$ 1,857,831 $ 1,705,627
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 59,431 $ 34,772
Accrued expenses 131,125 117,372
Asset retirement obligations 51,601 30,179
Fair value of commodity derivative instruments 29,636 10,026
Total current liabilities 271,793 192,349
Long-term debt 627,355 689,911
Asset retirement obligations 203,849 204,931
Deferred tax liabilities 122,812 67,694
Fair value of commodity derivative instruments 2,136 3,637
Other 673 1,132
1,228,618 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 December 31, 2013 and 2012 - -
Common stock, $0.001 par value per share. Authorized 75,000,000 shares; shares issued 40,970,137 and 40,601,887 at December 31, 2013 and 2012, respectively; shares outstanding 39,097,394 and 39,103,203 at December 31, 2013 and 2012, respectively 41 40
Additional paid-in capital 519,114 510,469
Treasury stock, at cost, 1,872,743 and 1,498,684 shares at December 31, 2013 and 2012, respectively (31,157) (20,477)
Retained earnings 141,215 55,941
Total stockholders' equity 629,213 545,973
$ 1,857,831 $ 1,705,627
EPL OIL & GAS, INC.
SUPPLEMENTAL OIL & GAS DISCLOSURE
(Unaudited)
Oil Natural Gas Equivalents
(Mbbl) (Mmcf) (Mboe)
Proved developed and undeveloped reserves:
December 31, 2011 27,301 58,785 37,099
Acquisitions 16,430 115,876 35,742
Extensions and discoveries 6,388 10,241 8,095
Revisions 1,128 4,033 1,800
Production (3,805) (8,996) (5,304)
December 31, 2012 47,442 179,939 77,432
Acquisitions 366 209 401
Sales (1,415) (916) (1,568)
Extensions and discoveries 7,354 20,247 10,729
Revisions 3,952 (10,128) 2,264
Production (6,182) (15,767) (8,810)
December 31, 2013 51,517 173,584 80,448
Proved developed reserves:
December 31, 2011 24,791 52,739 33,581
December 31, 2012 37,908 120,687 58,022
December 31, 2013 39,439 107,687 57,387
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):
2013 2012
Acquisitions:
Proved 23,895 706,322
Unproved 2,200 7,496
Exploration 46,100 43,338
Development 302,058 179,728
Total finding and development costs 348,158 223,066
Total finding, development and acquisition costs 374,253 936,884
Asset retirement liabilities incurred and acquired 23,339 1,210
Total cost incurred $ 397,592 $ 938,094

CONTACT: Investors/Media T.J. Thom Executive Vice President and Chief Financial Officer 713-228-0711 tthom@eplweb.com

Source:EPL Oil & Gas, Inc.