Proved reserves grew 38% to 246 MMBOE
Reserve replacement rate exceeded 510%
Fourth-quarter production volumes ahead of company guidance
Fiscal 2014 oil production grew 6%
Fiscal 2015 capital program focused on oil development
Fiscal 2015 production expected to grow more than 30%, oil more than 40%
HOUSTON, Aug. 13, 2014 (GLOBE NEWSWIRE) -- Energy XXI (Nasdaq:EXXI) (AIM:EXXI) today announced fiscal fourth-quarter and full-year financial and operating results for the period ending June 30, 2014, and provided fiscal 2015 guidance.
Highlights
- Fourth-quarter adjusted EBITDA was $194.3 million as production tops guidance, including a higher percentage of oil volumes
- Proved reserves reach 246 MMBOE, lifting PV-10 to $7.6 billion, while 3P reserves grow to 432 MMBOE, with a PV-10 of $14.6 billion
- Fiscal 2014 production rose 4% year over year, with oil up 6%, while fiscal 2015 production is expected to grow more than 37% at the guidance mid-point, and 48% for oil
- Acquisition of EPL adds locations to the drilling inventory and provides significant operational synergies, including cost savings exceeding initial targets
- Fiscal 2015 capital budget target of $875 million focused on development drilling, with 30 wells expected to be placed on production in fiscal 2015, compared with 17 wells in fiscal 2014
Fiscal 2014 Fourth-Quarter and Full-year Results
For the 2014 fiscal fourth quarter, adjusted earnings before non-recurring charges and interest, taxes, depreciation, depletion and amortization (adjusted EBITDA) was $194.3 million (a non-GAAP measure reconciled below) on revenues of $324.1 million. Volumes averaged 46,100 barrels of oil equivalent per day (BOE/d), 69 percent of which was oil. Due to non-recurring items associated with acquisition and divestiture activities, the company reported a net loss in the 2014 fiscal fourth quarter of $1.8 million, or $0.06 per diluted share.
For the fiscal year ended June 30, 2014, adjusted EBITDA was $754.2 million, compared to $768.9 million in fiscal 2013. Fiscal 2014 net income available for common shareholders was $47.6 million, or $0.64 per diluted share, on revenues of $1.2 billion. Net income available for common shareholders for fiscal 2013 was $150.6 million, or $1.86 per diluted share, on revenues of $1.2 billion. Fiscal 2014 production averaged 45,000 BOE/d, up four percent from production of 43,100 BOE/d the prior year, while the oil portion rose six percent, representing 67 percent of volumes compared with 66 percent in fiscal 2013.
Fiscal 2014 Year-end Reserves
The company's June 30, 2014 fiscal year-end proved reserves are estimated at 246 million barrels of oil equivalent (MMBOE), 75 percent liquids, up 38 percent from the June 30, 2013 year-end reserves, primarily due to the June 2014 acquisition of EPL Oil & Gas. Approximately 61 percent of proved reserves are proved developed. The tables set forth below provide additional information regarding the company's reserves and associated values.
| Oil | NGL | Gas | Equivalent | PV10% | |
| (MBBL) | (MBBL) | (MMCF) | (MBOE) | ($000)1 | |
| Proved Developed Producing | 87,609 | 3,368 | 132,106 | 112,994 | 3,362,983 |
| Proved Developed Non-Producing | 19,291 | 2,522 | 90,811 | 36,948 | 904,447 |
| Proved Undeveloped | 68,916 | 3,684 | 141,940 | 96,256 | 3,334,074 |
| Proved Reserves | 175,815 | 9,573 | 364,856 | 246,198 | 7,601,504 |
| Probable | 70,123 | 3,556 | 134,390 | 96,077 | 3,628,742 |
| Proved+Probable | 245,938 | 13,129 | 499,246 | 342,275 | 11,230,246 |
| Possible | 64,870 | 2,733 | 130,103 | 89,287 | 3,396,132 |
| Proved+Probable+Possible | 310,808 | 15,862 | 629,349 | 431,562 | 14,626,378 |
| 1Before tax, as of June 30, 2014, using prices of $103.63/per barrel of oil and $4.15/MCF ($96.75/per barrel of oil and $4.10/MMBTU base before differentials & BTU adjustment), based on the SEC-prescribed first-of-the-month average prices for the preceding 12 months | |||||
"Our reserves base has continued to grow, particularly the liquids portion, which has resulted in even higher increases in the reserves' value," Energy XXI Chairman and CEO John Schiller said. "In addition to growth from the EPL acquisition, we grew oil reserves organically, replacing 124 percent of our liquids production. We believe we can continue adding reserves organically as our teams apply technology to identify untapped reservoirs and increase recoveries of the oil in place."
Netherland, Sewell & Associates, Inc., independent oil and gas reserves consultants, audited the year-end reserves estimates. All of the company's reserves are in the United States Gulf of Mexico or Gulf Coast.
Capital Expenditures
The company's capital budget for fiscal year 2015, which began July 1, 2014, is estimated between $850 million and $950 million, with $875 million as the expected case and the higher end of the range primarily reliant on a successful test of the Lomond North well in the Highlander area. Development drilling, completions and recompletions account for approximately $475 million of planned spending, up approximately 26 percent from $378 million in fiscal 2014. This includes $38 million for non-operated projects in fiscal 2015, compared to $48 million in the prior year. The company currently is operating eight drilling rigs, and expects to complete 30 development wells in fiscal 2015, a 76 percent increase over fiscal 2014. The targeted $875 million budget would allow the company to operate an average of six rigs in fiscal 2015, with a majority of the capital being allocated to the first half of the year. Exploration drilling is budgeted at $33 million, down from approximately $112 million in the prior year. This includes $24 million for non-operated projects in fiscal 2015, compared to $42 million in the prior year. The bulk of the remaining capital budget for fiscal 2015 is allocated to facilities, general and administrative, land and abandonment costs. Fiscal 2014 capital spending totaled $814.9 million, including abandonment costs.
Guidance
First-quarter and full-year guidance is provided below.
| Results | FY 2015 Annual | FY 2015 Q1 | ||||
| Estimated Production | High | Mid | Low | High | Mid | Low |
| Liquids, MBOD | 47.0 | 44.5 | 42.0 | 43.0 | 41.5 | 40.0 |
| Equivalent, MBOED | 64.0 | 61.5 | 59.0 | 60.0 | 58.5 | 57.0 |
| % Oil Liquids | 73% | 72% | 71% | 72% | 71% | 70% |
| Adjusted EBITDA @ Various Prices | ||||||
| $110 Bbl/$4 Mcf | 1,359 | 1,258 | 1,157 | 313 | 298 | 283 |
| $100 Bbl/$4 Mcf | 1,187 | 1,096 | 1,004 | 274 | 261 | 247 |
| $95 Bbl/$4 Mcf | 1,101 | 1,015 | 928 | 255 | 242 | 229 |
Production and Operations Update
At the mid-point of guidance, fiscal 2015 production is expected to increase 37 percent over the prior year, with oil volumes 48 percent ahead of the prior year. July 2014 production approximated 59,000 BOE/d with 42,000 barrels per day of oil.
The company currently operates eight rigs in the shallow waters on the Gulf of Mexico shelf. Drilling is ongoing at West Delta 29/30 and 73, Main Pass, Ship Shoal 208/209, and South Timbalier.
In the non-operated joint venture with Freeport McMoRan Oil & Gas in the Inboard Lower Tertiary/Cretaceous trend, completion activity is ongoing at Lomond North in the Highlander area, located primarily in St. Martin Parish, Louisiana. The operator expects a flow test to be conducted in the second half of calendar year 2014.
Energy XXI was awarded 29 shallow-water blocks in the Central Gulf of Mexico lease sale #231 by the U.S. Bureau of Ocean Energy Management. Two additional blocks jointly bid with Fieldwood and Apache also were awarded.
| ENERGY XXI (BERMUDA) LIMITED | ||||
| RECONCILIATION OF GAAP TO NON-GAAP MEASURES | ||||
| (In Thousands, except per share information) | ||||
| (Unaudited) | ||||
| As required under Regulation G of the Securities Exchange Act of 1934, provided below are reconciliations of net income to the following non-GAAP financial measure: Adjusted EBITDA. The company uses this non-GAAP measure as a key metric for the management of the company and to demonstrate the company's ability to internally fund capital expenditures and service debt. | ||||
| Quarter Ended June 30, | Year Ended June 30, | |||
| 2014 | 2013 | 2014 | 2013 | |
| Net Income (Loss) as Reported | $(1,815) | $62,053 | $59,111 | $162,081 |
| Other expense | 49,962 | 28,479 | 164,211 | 113,091 |
| Depreciation, depletion and amortization | 119,691 | 96,846 | 423,319 | 376,224 |
| Income tax expense | 6,530 | 21,215 | 57,089 | 86,633 |
| EBITDA | 174,368 | 208,593 | 703,730 | 738,029 |
| Adjustments to EBITDA | ||||
| Accretion of asset retirement obligation | 9,366 | 7,828 | 30,183 | 30,885 |
| Acquisition and divestiture expenses | 10,610 | -- | 20,268 | -- |
| Adjusted EBITDA | $194,344 | $216,421 | $754,181 | $768,914 |
| Adjusted EBITDA Per Common Share | ||||
| Basic | $2.52 | $2.76 | $10.14 | $9.73 |
| Diluted | $2.51 | $2.76 | $10.13 | $9.71 |
| Weighted Average Number of Common Shares Outstanding | ||||
| Basic | 77,265 | 78,409 | 74,375 | 79,063 |
| Diluted | 77,326 | 78,477 | 74,445 | 79,166 |
| ENERGY XXI (BERMUDA) LIMITED | ||
| CONSOLIDATED BALANCE SHEETS | ||
| (In Thousands, except share information) | ||
| June 30, | ||
| ASSETS | 2014 | 2013 |
| Current Assets | ||
| Cash and cash equivalents | $145,806 | $— |
| Accounts receivable | ||
| Oil and natural gas sales | 167,075 | 132,521 |
| Joint interest billings | 12,898 | 9,505 |
| Insurance and other | 5,438 | 6,745 |
| Prepaid expenses and other current assets | 72,530 | 50,738 |
| Deferred income taxes | 52,587 | |
| Derivative financial instruments | 1,425 | 38,389 |
| Total Current Assets | 457,759 | 237,898 |
| Property and Equipment | ||
| Oil and natural gas properties - full cost method of accounting, including $1,165.7 million and $422.6 million of unevaluated properties not being amortized at June 30, 2014 and 2013, respectively | 6,524,602 | 3,289,505 |
| Other property and equipment | 19,760 | 17,003 |
| Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 6,544,362 | 3,306,508 |
| Other Assets | ||
| Goodwill | 327,235 | — |
| Derivative financial instruments | 3,035 | 21,926 |
| Equity investments | 40,643 | 12,799 |
| Restricted cash | 6,350 | — |
| Other assets and debt issuance costs, net of accumulated amortization | 57,394 | 32,580 |
| Total Other Assets | 434,657 | 67,305 |
| Total Assets | $7,436,778 | $3,611,711 |
| LIABILITIES | ||
| Current Liabilities | ||
| Accounts payable | $415,718 | $219,610 |
| Accrued liabilities | 133,526 | 105,192 |
| Notes payable | 21,967 | 22,524 |
| Deferred income taxes | — | 20,517 |
| Asset retirement obligations | 79,649 | 29,500 |
| Derivative financial instruments | 31,957 | 40 |
| Current maturities of long-term debt | 15,020 | 19,554 |
| Total Current Liabilities | 697,837 | 416,937 |
| Long-term debt, less current maturities | 3,744,624 | 1,350,491 |
| Deferred income taxes | 701,038 | 140,804 |
| Asset retirement obligations | 480,185 | 258,318 |
| Derivative financial instruments | 4,306 | — |
| Other liabilities | 10,958 | 7,915 |
| Total Liabilities | 5,638,948 | 2,174,465 |
| Stockholders' Equity | ||
| Preferred stock, $0.001 par value, 7,500,000 shares authorized at June 30, 2014 and 2013, respectively | ||
| 7.25% Convertible perpetual preferred stock, 8,000 shares issued and outstanding at June 30, 2014 and 2013, respectively | — | — |
| 5.625% Convertible perpetual preferred stock, 812,760 and 813,188 shares issued and outstanding at June 30, 2014 and 2013, respectively | 1 | 1 |
| Common stock, $0.005 par value, 200,000,000 shares authorized and 93,719,570 and 79,425,473 shares issued and 93,719,570 and 76,485,910 shares outstanding at June 30, 2014 and 2013, respectively | 468 | 397 |
| Additional paid-in capital | 1,837,462 | 1,512,311 |
| Accumulated deficit | (19,626) | (29,352) |
| Accumulated other comprehensive (loss) income, net of income taxes | (20,475) | 26,552 |
| Treasury stock, at cost, 2,938,900 shares at June 30, 2013 | — | (72,663) |
| Total Stockholders' Equity | 1,797,830 | 1,437,246 |
| Total Liabilities and Stockholders' Equity | $7,436,778 | $3,611,711 |
| See accompanying Notes to Consolidated Financial Statements | ||
| ENERGY XXI (BERMUDA) LIMITED | |||
| CONSOLIDATED STATEMENTS OF INCOME | |||
| (In Thousands, except per share information) | |||
| Year Ended June 30, | |||
| 2014 | 2013 | 2012 | |
| Revenues | |||
| Crude oil sales | $1,091,223 | $1,080,982 | $1,186,631 |
| Natural gas sales | 139,502 | 127,863 | 116,772 |
| Total Revenues | 1,230,725 | 1,208,845 | 1,303,403 |
| Costs and Expenses | |||
| Lease operating | 365,747 | 337,163 | 310,815 |
| Production taxes | 5,427 | 5,246 | 7,261 |
| Gathering and transportation | 23,532 | 24,168 | 16,371 |
| Depreciation, depletion and amortization | 423,319 | 376,224 | 367,463 |
| Accretion of asset retirement obligations | 30,183 | 30,885 | 39,161 |
| General and administrative expense | 96,402 | 71,598 | 86,276 |
| Loss (gain) on derivative financial instruments | 5,704 | 1,756 | (7,228) |
| Total Costs and Expenses | 950,314 | 847,040 | 820,119 |
| Operating Income | 280,411 | 361,805 | 483,284 |
| Other Income (Expense) | |||
| Loss from equity method investees | (4,781) | (6,397) | — |
| Other income - net | 3,298 | 1,965 | 71 |
| Interest expense | (162,728) | (108,659) | (108,882) |
| Total Other Expense | (164,211) | (113,091) | (108,811) |
| Income Before Income Taxes | 116,200 | 248,714 | 374,473 |
| Income Tax Expense | 57,089 | 86,633 | 38,646 |
| Net Income | 59,111 | 162,081 | 335,827 |
| Induced Conversion of Preferred Stock | — | — | 6,068 |
| Preferred Stock Dividends | 11,489 | 11,496 | 13,028 |
| Net Income Available for Common Stockholders | $47,622 | $150,585 | $316,731 |
| Earnings per Share | |||
| Basic | $0.64 | $1.90 | $4.10 |
| Diluted | $0.64 | $1.86 | $3.85 |
| Weighted Average Number of Common Shares Outstanding | |||
| Basic | 74,375 | 79,063 | 77,310 |
| Diluted | 74,445 | 87,263 | 87,208 |
| ENERGY XXI (BERMUDA) LIMITED | |||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |||
| (In Thousands) | |||
| Year Ended June 30, | |||
| 2014 | 2013 | 2012 | |
| Cash Flows From Operating Activities | |||
| Net income | $59,111 | $162,081 | $335,827 |
| Adjustments to reconcile net income to net cash provided by (used in) operating activities: | |||
| Depreciation, depletion and amortization | 423,319 | 376,224 | 367,463 |
| Deferred income tax expense | 53,448 | 73,761 | 38,796 |
| Change in derivative financial instruments | |||
| Proceeds from sale of derivative instruments | — | 760 | 66,522 |
| Other – net | (1,793) | (27,516) | (52,155) |
| Accretion of asset retirement obligations | 30,183 | 30,885 | 39,161 |
| Loss from equity method investees | 4,781 | 6,397 | — |
| Amortization and write-off of debt issuance costs and other | 13,774 | 6,898 | 7,559 |
| Stock-based compensation | 6,711 | 3,505 | 11,760 |
| Changes in operating assets and liabilities | |||
| Accounts receivable | 63,283 | 1,690 | (4,995) |
| Prepaid expenses and other current assets | 6,019 | 12,499 | (15,890) |
| Settlement of asset retirement obligations | (57,391) | (41,939) | (14,990) |
| Accounts payable and accrued liabilities | (55,985) | 32,903 | 6,456 |
| Net Cash Provided by Operating Activities | 545,460 | 638,148 | 785,514 |
| Cash Flows from Investing Activities | |||
| Acquisitions, net of cash acquired | (849,641) | (161,164) | (6,401) |
| Capital expenditures | (788,676) | (816,105) | (570,670) |
| Insurance payments received | 1,983 | — | 6,472 |
| Change in equity method investments | (34,294) | (16,693) | (2,201) |
| Proceeds from the sale of properties | 126,265 | — | 2,750 |
| Transfer to restricted cash | (325) | — | — |
| Other | 113 | (41) | 457 |
| Net Cash Used in Investing Activities | (1,544,575) | (994,003) | (569,593) |
| Cash Flows from Financing Activities | |||
| Proceeds from the issuance of common and preferred stock, net of offering costs | 3,994 | 7,021 | 9,839 |
| Discount on convertible debt allocated to additional paid-in capital | 63,432 | — | — |
| Conversion of preferred stock to common stock | — | — | (6,040) |
| Repurchase of company common stock | (184,263) | (58,666) | — |
| Dividends to shareholders - common | (34,680) | (25,992) | — |
| Dividends to shareholders - preferred | (11,489) | (11,496) | (18,682) |
| Proceeds from long-term debt | 3,420,873 | 1,576,551 | 896,717 |
| Payments on long-term debt | (2,079,485) | (1,243,848) | (1,008,300) |
| Debt issuance costs | (33,461) | (4,805) | — |
| Other | — | 3 | (775) |
| Net Cash Provided by (Used in) Financing Activities | 1,144,921 | 238,768 | (127,241) |
| Net Increase (Decrease) in Cash and Cash Equivalents | 145,806 | (117,087) | 88,680 |
| Cash and Cash Equivalents, beginning of year | — | 117,087 | 28,407 |
| Cash and Cash Equivalents, end of year | $145,806 | $— | $117,087 |
| Quarter Ended | |||||
| Operating Highlights |
June 30, 2014 |
Mar. 31, 2014 |
Dec. 31, 2013 |
Sept. 30, 2013 |
June 30, 2013 |
| (In Thousands, Except per Unit Amounts) | |||||
| Operating revenues | |||||
| Crude oil sales | $294,974 | $254,641 | $263,626 | $290,965 | $270,623 |
| Natural gas sales | 34,508 | 37,562 | 31,138 | 32,584 | 38,630 |
| Hedge gain (loss) | (5,348) | (7,020) | 2,052 | 1,043 | 5,072 |
| Total revenues | 324,134 | 285,183 | 296,816 | 324,592 | 314,325 |
| Percent of operating revenues from crude oil | |||||
| Prior to hedge gain (loss) | 90% | 87% | 89% | 90% | 88% |
| Including hedge gain (loss) | 89% | 88% | 88% | 89% | 87% |
| Operating expenses | |||||
| Lease operating expense | |||||
| Insurance expense | 8,357 | 6,410 | 7,920 | 8,496 | 7,462 |
| Workover and maintenance | 14,408 | 17,797 | 19,690 | 14,586 | 15,622 |
| Direct lease operating expense | 79,806 | 59,417 | 66,179 | 62,681 | 59,371 |
| Total lease operating expense | 102,571 | 83,624 | 93,789 | 85,763 | 82,455 |
| Production taxes | 1,750 | 1,090 | 1,189 | 1,398 | 1,481 |
| Gathering and transportation | 6,509 | 5,700 | 5,978 | 5,345 | 5,668 |
| DD&A | 119,691 | 99,899 | 103,513 | 100,216 | 96,846 |
| General and administrative | 30,824 | 24,208 | 17,698 | 23,672 | 12,299 |
| Other – net | 8,112 | 5,861 | 13,147 | 8,767 | 3,829 |
| Total operating expenses | 269,457 | 220,382 | 235,314 | 225,161 | 202,578 |
| Operating income | $54,677 | $64,801 | $61,502 | $99,431 | $111,747 |
| Sales volumes per day | |||||
| Natural gas (MMcf) | 84.8 | 83.7 | 89.3 | 100.8 | 107.4 |
| Crude oil (MBbls) | 32.0 | 28.4 | 30.2 | 29.7 | 28.9 |
| Total (MBOE) | 46.1 | 42.3 | 45.1 | 46.6 | 46.8 |
| Percent of sales volumes from crude oil | 69% | 67% | 67% | 64% | 62% |
| Average sales price | |||||
| Natural gas per Mcf | $4.47 | $4.98 | $3.79 | $3.51 | $3.95 |
| Hedge gain (loss) per Mcf | (0.02) | (0.31) | 0.42 | 0.30 | 0.23 |
| Total natural gas per Mcf | $4.45 | $4.67 | $4.21 | $3.81 | $4.18 |
| Crude oil per Bbl | $101.45 | $99.71 | $94.85 | $106.31 | $102.82 |
| Hedge gain (loss) per Bbl | (1.78) | (1.83) | (0.50) | (0.63) | 1.08 |
| Total crude oil per Bbl | $99.67 | $97.88 | $94.35 | $105.68 | $103.90 |
| Total hedge gain (loss) per BOE | $(1.28) | $(1.84) | $0.49 | $0.24 | $1.19 |
| Operating revenues per BOE | $77.28 | $74.85 | $71.54 | $75.78 | $73.78 |
| Operating expenses per BOE | |||||
| Lease operating expense | |||||
| Insurance expense | 1.99 | 1.68 | 1.91 | 1.98 | 1.75 |
| Workover and maintenance | 3.44 | 4.67 | 4.75 | 3.41 | 3.67 |
| Direct lease operating expense | 19.03 | 15.59 | 15.95 | 14.63 | 13.94 |
| Total lease operating expense per BOE | 24.46 | 21.94 | 22.61 | 20.02 | 19.36 |
| Production taxes | 0.42 | 0.29 | 0.29 | 0.33 | 0.35 |
| Gathering and transportation | 1.55 | 1.50 | 1.44 | 1.25 | 1.33 |
| DD&A | 28.54 | 26.22 | 24.95 | 23.40 | 22.73 |
| General and administrative | 7.35 | 6.35 | 4.27 | 5.53 | 2.89 |
| Other – net | 1.93 | 1.54 | 3.17 | 2.05 | 0.90 |
| Total operating expenses per BOE | 64.25 | 57.84 | 56.73 | 52.58 | 47.56 |
| Operating income per BOE | $13.03 | $17.01 | $14.81 | $23.20 | $26.22 |
| Year Ended June 30, | |||||
| Operating Highlights | 2014 | 2013 | 2012 | 2011 | 2010 |
| (In Thousands, Except per Unit Amounts) | |||||
| Operating revenues | |||||
| Crude oil sales | $1,104,206 | $1,067,686 | $1,186,193 | $777,869 | $383,928 |
| Natural gas sales | 135,792 | 112,753 | 88,608 | 101,815 | 69,399 |
| Hedge gain (loss) | (9,273) | 28,406 | 28,602 | (20,314) | 45,604 |
| Total revenues | 1,230,725 | 1,208,845 | 1,303,403 | 859,370 | 498,931 |
| Percent of operating revenues from crude oil | |||||
| Prior to hedge gain (loss) | 89% | 90% | 93% | 88% | 85% |
| Including hedge gain (loss) | 89% | 89% | 91% | 84% | 78% |
| Operating expenses | |||||
| Lease operating expense | |||||
| Insurance expense | 31,183 | 32,737 | 28,521 | 27,876 | 27,603 |
| Workover and maintenance | 66,481 | 65,118 | 56,413 | 33,095 | 19,630 |
| Direct lease operating expense | 268,083 | 239,308 | 225,881 | 178,507 | 95,379 |
| Total lease operating expense | 365,747 | 337,163 | 310,815 | 239,478 | 142,612 |
| Production taxes | 5,427 | 5,246 | 7,261 | 3,336 | 4,217 |
| Gathering and transportation | 23,532 | 24,168 | 16,371 | 12,499 | — |
| Depreciation, depletion and amortization | 423,319 | 376,224 | 367,463 | 293,479 | 181,640 |
| General and administrative | 96,402 | 71,598 | 86,276 | 75,091 | 49,667 |
| Other – net | 35,887 | 32,641 | 31,933 | 26,564 | 18,748 |
| Total operating expenses | 950,314 | 847,040 | 820,119 | 650,447 | 396,884 |
| Operating income | $280,411 | $361,805 | $483,284 | $208,923 | $102,047 |
| Sales volumes per day | |||||
| Natural gas (MMcf) | 89.7 | 88.6 | 81.5 | 67.2 | 42.6 |
| Crude oil (MBbls) | 30.1 | 28.3 | 30.5 | 23.4 | 14.7 |
| Total (MBOE) | 45.0 | 43.1 | 44.1 | 34.6 | 21.8 |
| Percent of sales volumes from crude oil | 67% | 66% | 69% | 68% | 67% |
| Average sales price | |||||
| Natural gas per Mcf | $4.15 | $3.48 | $2.97 | $4.15 | $4.47 |
| Hedge gain per Mcf | 0.11 | 0.47 | 0.94 | 1.54 | 2.68 |
| Total natural gas per Mcf | $4.26 | $3.95 | $3.91 | $5.69 | $7.15 |
| Crude oil per Bbl | $100.59 | $103.48 | $106.17 | $90.95 | $71.73 |
| Hedge gain (loss) per Bbl | (1.18) | 1.29 | 0.04 | (6.80) | 0.75 |
| Total crude oil per Bbl | $99.41 | $104.77 | $106.21 | $84.15 | $72.48 |
| Total hedge gain (loss) per BOE | $(0.56) | $1.81 | $1.77 | $(1.61) | $5.74 |
| Operating revenues per BOE | $74.88 | $76.95 | $80.74 | $67.98 | $62.83 |
| Operating expenses per BOE | |||||
| Lease operating expense | |||||
| Insurance expense | 1.90 | 2.08 | 1.77 | 2.21 | 3.48 |
| Workover and maintenance | 4.04 | 4.15 | 3.49 | 2.62 | 2.47 |
| Direct lease operating expense | 16.31 | 15.23 | 13.99 | 14.12 | 12.01 |
| Total lease operating expense per BOE | 22.25 | 21.46 | 19.25 | 18.95 | 17.96 |
| Production taxes | 0.33 | 0.33 | 0.45 | 0.26 | 0.53 |
| Gathering and transportation | 1.43 | 1.54 | 1.01 | 0.98 | — |
| Depreciation, depletion and amortization | 25.75 | 23.95 | 22.76 | 23.22 | 22.87 |
| General and administrative | 5.87 | 4.56 | 5.34 | 5.94 | 6.25 |
| Other – net | 2.19 | 2.08 | 1.98 | 2.10 | 2.36 |
| Total operating expenses per BOE | 57.82 | 53.92 | 50.79 | 51.45 | 49.97 |
| Operating income per BOE | $17.06 | $23.03 | $29.95 | $16.53 | $12.86 |
| The supplementary data presented reflects information for all of our oil and gas producing activities. Costs incurred for oil and gas property acquisition, exploration and development activities are as follows: | |||
| Year Ended June 30, | |||
| 2014 | 2013 | 2012 | |
| (In Thousands) | |||
| Property acquisitions | |||
| Proved | $2,046,879 | $108,825 | $6,401 |
| Unevaluated | 924,882 | 52,339 | — |
| Exploration costs | 153,136 | 168,512 | 183,397 |
| Development costs | 632,262 | 633,868 | 327,360 |
| Estimated quantities of proved domestic oil and gas reserves and changes in quantities of proved developed and undeveloped reserves in thousands of barrels ("MBbls") and millions of cubic feet ("MMcf") for each of the periods indicated were as follows: | |||
| Crude Oil | Natural Gas | Total | |
| (MBbls) | (MMcf) | (MBOE) | |
| Proved reserves at June 30, 2011 | 77,206 | 236,316 | 116,592 |
| Production | (11,172) | (29,824) | (16,143) |
| Extensions and discoveries | 11,444 | 27,821 | 16,081 |
| Revisions of previous estimates | 9,098 | (23,281) | 5,217 |
| Reclassification of proved undeveloped | (1,783) | (2,042) | (2,123) |
| Proved reserves at June 30, 2012 | 84,793 | 208,990 | 119,624 |
| Production | (10,318) | (32,354) | (15,710) |
| Extensions and discoveries | 40,690 | 40,714 | 47,476 |
| Revisions of previous estimates | 14,380 | 7,903 | 15,697 |
| Reclassification of proved undeveloped | (1,123) | (1,755) | (1,416) |
| Purchases of reserves | 5,225 | 45,623 | 12,829 |
| Proved reserves at June 30, 2013 | 133,647 | 269,121 | 178,500 |
| Production | (10,978) | (32,754) | (16,437) |
| Extensions and discoveries | 17,141 | 19,703 | 20,424 |
| Revisions of previous estimates | (3,567) | (29,822) | (8,537) |
| Sales of reserves | (4,159) | (3,378) | (4,722) |
| Purchases of reserves | 53,305 | 141,986 | 76,970 |
| Proved reserves at June 30, 2014 | 185,389 | 364,856 | 246,198 |
| Proved developed reserves | |||
| June 30, 2011 | 59,234 | 134,024 | 81,572 |
| June 30, 2012 | 63,308 | 110,310 | 81,693 |
| June 30, 2013 | 80,223 | 175,623 | 109,493 |
| June 30, 2014 | 112,789 | 222,916 | 149,942 |
| Proved undeveloped reserves | |||
| June 30, 2011 | 17,972 | 102,292 | 35,020 |
| June 30, 2012 | 21,485 | 98,680 | 37,931 |
| June 30, 2013 | 53,424 | 93,498 | 69,007 |
| June 30, 2014 | 72,600 | 141,940 | 96,256 |
Forward-Looking Statements
All statements included in this release relating to future plans, projects, events or conditions and all other statements other than statements of historical fact included in this release are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based upon current expectations and are subject to a number of risks, uncertainties and assumptions, including changes in long-term oil and gas prices or other market conditions affecting the oil and gas industry, reservoir performance, the outcome of commercial negotiations and changes in technical or operating conditions, our ability to integrate acquisitions, among others, that could cause actual results, including project plans and related expenditures and resource recoveries, to differ materially from those described in the forward-looking statements. Energy XXI assumes no obligation and expressly disclaims any duty to update the information contained herein except as required by law.
Competent Person Disclosure
The technical information contained in this announcement relating to resources and operations adheres to the standard set by the Society of Petroleum Engineers ("SPE"). Phil Kerig, Vice President of Corporate Development is the qualified person who has reviewed and approved the technical information contained in this announcement.
About the Company
Energy XXI is an independent oil and natural gas exploration and production company whose growth strategy emphasizes acquisitions, enhanced by its value-added organic drilling program. The company's properties are located in the U.S. Gulf of Mexico waters and the Gulf Coast onshore. Cantor Fitzgerald Europe is Energy XXI's listing broker in the United Kingdom. To learn more, visit the Energy XXI website at www.EnergyXXI.com.
GLOSSARY
Reserves:
Proved Oil and Gas Reserves -- Those quantities of crude oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible -- from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations -- prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. This definition has been abbreviated from the definition of "Proved oil and gas reserves" contained in Rule 4-10(a)(22) of SEC Regulation S-X.
Proved Developed Reserves -- Reserves are categorized as proved developed if they are expected to be recovered from existing wells.
Probable Reserves -- Those additional reserves that are less certain to be recovered than proved reserves but more certain to be recovered than possible reserves. This definition has been abbreviated from the applicable definition contained in Rule 4-10(a)(18) of SEC Regulation S-X.
Possible Reserves -- Those additional reserves that are less certain to be recovered than probable reserves. This definition has been abbreviated from the applicable definition contained in Rule 4-10(a)(17) of Regulation S-X.
Other terms:
Barrel – unit of measure for oil and petroleum products, equivalent to 42 U.S. gallons.
BOE – barrels of oil equivalent, used to equate natural gas volumes to liquid barrels at a general conversion rate of 6,000 cubic feet of gas per barrel.
BOE/d – barrels of oil equivalent per day.
Bbl/d – barrels per day of oil or condensate.
MMBTU – million British thermal units.
Mcf/d – thousand cubic feet of gas per day.
MD – total measured depth of a well.
Net Pay – cumulative hydrocarbon-bearing formations.
NRI, Net Revenue Interest – the percentage of production revenue allocated to the working interest after first deducting proceeds allocated to royalty and overriding interest.
TD – target total depth of a well.
TVD – true vertical depth of a well.
WI, Working Interest – the interest held in lands by virtue of a lease, operating agreement, fee title or otherwise, under which the owner of the interest is vested with the right to explore for, develop, produce and own oil, gas or other minerals and bears the proportional cost of such operations.
Workover / Recompletion – operations on a producing well to restore or increase production. A workover or recompletion may be performed to stimulate the well, remove sand or wax from the wellbore, to mechanically repair the well, or for other reasons.