Coastal Energy Announces 2012 Year End Financial Results & Operations Update HOUSTON, March 28, 2013 (GLOBE NEWSWIRE) -- Coastal Energy Company (the "Company" or "Coastal Energy") (TSX:CEN) (AIM:CEO), an independent exploration and production company with assets in Southeast Asia, announces the financial results for the year ended December 31, 2012. The functional and reporting currency of the Company is the United States dollar. 2012 Financial Highlights *Total Company production increased to 21,373 boe/d in the fourth quarter of 2012 from 14,508 boe/d in the same period last year. Year over year offshore production was bolstered by the inclusion of a full quarter of production at the Bua Ban North A platform. Sequential quarterly offshore production was impacted downwardly in the fourth quarter due to a production facilities swap out at Bua Ban North as well as downtime at the Bua Ban North B platform while the second rig was mobilized to that location in December. Average onshore production for the fourth quarter of 2012 was 2,419 boe/d compared to 1,122 boe/d in 2011. Total company production for the full year 2012 increased to 21,912 boe/d, a 90% increase from 2011 levels of 11,540 boe/d. *EBITDAX for the full year of 2012 was $494.9 million, 145% higher than the $201.7 million recorded in 2011. Revenue and EBITDAX were driven higher by increased production and commodity prices. Crude oil inventory was 503,594 barrels at year end, the revenue from which will be recognized in 2013. *The Company reported fully diluted EPS of $1.92, a 368% increase from 2011 fully diluted EPS of $0.41. *The Company reported fully diluted CFPS of $3.27, a 101% increase from 2011 fully diluted CFPS of $1.63. *Note: Per share calculations use weighted average fully diluted shares outstanding for the period *The Company released the results of its third-party reserve evaluation report prepared by RPS Energy, Ltd. dated March 20, 2013 (effective date December 31, 2012). The Company reported significant gains in its 1P, 2P and 3P reserve bases, with volumetric increases of 9%, 40% and 78%, respectively. The Company's 1P, 2P and 3P NAVs also increased significantly, rising by 21%, 43% and 62%, respectively. As of As of December December % After-Tax After-Tax % After-Tax 31, 2012 31, 2011 Change NPV 2012 NPV 2011 Change NPV per (mmboe) (mmboe) (US$MM) (US$MM) Share 2012 (US$) Proved Offshore 68.8 62.5 10% $1,832.1 $1,491.7 23% $15.64 Onshore 7.3 7.4 -1% $120.5 $126.5 -5% $1.03 Total 1P 76.1 69.9 9% $1,952.6 $1,618.2 21% $16.67 Proved + Probable Offshore 120.4 80.0 51% $2,475.2 $1,668.0 48% $21.13 Onshore 23.9 22.9 4% $237.9 $230.7 3% $2.03 Total 2P 144.3 102.9 40% $2,713.1 $1,898.7 43% $23.16 Proved + Probable + Possible Offshore 168.5 87.1 93% $2,919.0 $1,742.0 68% $24.92 Onshore 27.6 22.9 21% $275.9 $230.7 20% $2.36 Total 3P 196.1 110.0 78% $3,194.9 $1,972.7 62% $27.27 Note: Reserve figures are shown as net working interest before royalties (Thailand royalty regime is discussed in the MD&A of the Company's Annual Report dated December 31, 2012). After-tax NPV figures are defined as future net revenues discounted at 10%.Reserve numbers taken from the Company's competent person's report prepared by RPS Energy Ltd. dated as of December 31, 2012 (prepared in accordance with NI 51-101 and the COGE Handbook) which may be found on the Company's website at www.coastalenergy.com.Per share values are based on fully diluted shares outstanding as of December 31, 2012 Q1 2013 Operations Update The Company continued its development program at Bua Ban North and Songkhla A and also completed its pilot hydraulic fracturing program at Bua Ban South during the first quarter. Bua Ban North B The Company drilled a total of four development wells and one water injection well at Bua Ban North B during the first quarter. The Company has completed two horizontal wells with new "swelling packers" which are expected to minimize water production and increase ultimate recovery. This new completion methodology takes longer to initially come onstream than previous methods, however, provides greater long term benefits for production. One of these wells is currently producing and the other is expected to come onstream within the next three weeks. Two additional vertical development wells were drilled on the northeastern flank of Bua Ban North B. Bua Ban South The Company has completed its pilot hydraulic fracturing program of two wells at Bua Ban South. The Bua Ban South A-01 well was completed with a three stage frac in the Lower Oligocene and produced at an initial rate of 1,200 bopd and has stabilized at a rate of approximately 450 bopd for the past five weeks. The Bua Ban South A-03 well was completed with a six stage frac in the Eocene and initially produced at a rate of 1,450 bopd and has produced approximately at that level for two weeks. Initial production from these wells was delayed following the initial fracture stimulation due to mechanical issues with the retrievable bridge plugs used during the stimulation and completion process. The Company has identified an alternative completion methodology that should eliminate similar delays in future well stimulations. The A-04 Miocene producer has been completed and tied into production. The Company is going to reperforate the A-05 Miocene well and bring it onstream in the next two weeks. Songkhla A Two exploration wells were drilled into two previously untested fault blocks on the western side of the Songkhla A platform. The A-15 exploration well encountered 40 feet of net pay in the Eocene interval with 12% average porosity and the A-16 exploration well encountered 14 feet of net pay in the Lower Oligocene interval with 18% average porosity and 13 feet of net pay in the Eocene interval with 14% average porosity in a separate western fault block. The A-16 well has been fracked and will begin testing soon and the A-15 well is scheduled to be fracked once the frac equipment returns to the field in the third quarter. Additionally, two development wells and three water injection wells were drilled at Songkhla A during the quarter. The drilling rig that was at Songkhla A has mobilized to the Songkhla M prospect and will spud the M-01 exploration well by the end of this week. The Company has determined that to fully develop the northeastern fault block discovered by the A-13 well, an additional satellite platform will be required. Consequently, no appraisal or development wells have been drilled in this fault block subsequent to the A-13 discovery well. The Company's year-end 2012 2P reserves include 4.0 million barrels in this fault block. The A-10 producer was down for the majority of the first quarter awaiting pump replacement until the rig was moved off location. The Company's current offshore production rate is approximately 23,000 bopd. Total Company production, including onshore gas, is approximately 25,500 boepd. Randy Bartley, President and CEO of Coastal Energy, commented: "Coastal delivered record production and cash flow for the fourth year in a row. We also delivered another solid year of reserves increases with offshore 2P reserves increasing by 50% and total Company 2P reserves increasing by 40%. The Company realized substantial additions to its 3P reserve base as well, adding 41.0 mmbbl of offshore Possible reserves.We anticipate that some of those offshore Possible reserves will be reclassified to 2P following additional development drilling in 2013.In 2012 Coastal expanded its horizons by signing a contract to develop a cluster of three oil fields offshore Malaysia. "Coastal is poised for 2013 to be a solid year as well. We have added a second drilling rig so that we can continue our development programs at our existing fields while continuing to explore the prolific Songkhla basin. Two high-impact exploration prospects, the Bua Ban Terrace and Benjarong South, are scheduled to be tested in the second half of 2013. "We are very excited by the results of the pilot hydraulic fracturing program at Bua Ban South.Both wells have tested at stabilized production rates which are commercial.Our post frac analysis indicates there is room for optimization in our frac design and we believe we can improve both production rates and reduce frac costs. Following these excellent results we plan to move forward aggressively with our frac program to continue unlocking the potential of this substantial resource." The following financial statements for the Company are abbreviated versions. The Company's complete financial statements for the three and twelve months ended December 31, 2012 with the notes thereto and the related Management Discussion and Analysis can be found either on Coastal's website at www.CoastalEnergy.com or on SEDAR at www.sedar.com. All amounts are in US$ thousands, except share and per share amounts. Years Ended December 31, 2012 2011 Revenues and Other Income Oil sales 746,853 347,783 Royalties (79,280) (29,113) Oil sales, net of royalties 667,573 318,670 Reimbursement of expenses under Malaysia risk service 4,099 -- contract (Note 3) Other income (Note 16) (4,770) (21,566) 666,902 297,104 Expenses Production 149,999 99,263 Malaysia risk service contract (Note 3) 4,099 -- Depreciation and depletion (Note 8) 70,139 61,136 Net profits interest (Note 18) 1,041 -- General and administrative 39,696 31,453 Exploration (Note 7) 7,477 8,374 Debt financing fees 2,165 796 Finance (Note 15) 4,715 4,825 Gains on disposal of property, plant and equipment (252) (873) 279,079 204,974 Net income before income taxes and share of earnings from Apico LLC 387,823 92,130 Share of earnings from Apico LLC (Note 9) 19,110 14,527 Net income before income taxes 406,933 106,657 Income taxes (Note 21) Current 150,329 135 Deferred 28,656 57,882 178,985 58,017 Net loss from discontinued operations (Note 18) Net income and comprehensive income 227,948 48,640 Net income and comprehensive income attributable to: Shareholders of Coastal Energy 224,403 47,359 Non-controlling interests 3,545 1,281 227,948 48,640 Net income per share: Basic (Note 19) 1.98 0.42 Diluted (Note 19) 1.92 0.41 The accompanying notes are an integral part of these consolidated financial statements. December 31, December 31, As at 2012 2011 $ $ Assets Current Assets Cash 63,897 22,995 Restricted cash (Note 4) 6,452 28,447 Accounts receivable (Note 5) 56,848 16,939 Derivative asset (Note 12) 132 59 Inventories (Note 6) 20,856 14,161 Prepaids and other current assets 628 1,094 Total current assets 148,813 83,695 Non-Current Assets Exploration and evaluation assets (Note 7) 123,574 31,881 Property, plant and equipment (Note 8) 555,269 355,052 Investment in and advances to Apico LLC (Note 60,266 47,698 9) Deposits and other assets 6,271 405 Total non-current assets 745,380 435,036 Total Assets 894,193 518,731 Liabilities Current Liabilities Accounts payable and accrued liabilities (Note 131,005 59,392 10) Income taxes payable (Note 21) 86,752 79 Current portion of long-term debt (Note 12) 34 55,662 Current portion of derivative liabilities (Note 1,372 14,557 12) Total current liabilities 219,163 129,690 Non-Current Liabilities Long-term debt (Note 12) 95,066 22,156 Derivative liabilities (Note 12) 502 1,274 Derivative liability - Warrants (Note 11) 3,784 2,853 Deferred tax liabilities 98,423 69,767 Decommissioning liabilities (Note 13) 46,726 42,124 Total Non-Current Liabilities 244,501 138,174 Shareholders' Equity (Note 19) Common shares 213,260 211,554 Contributed surplus 18,940 16,401 Warrants -- Retained earnings 193,877 17,630 Total Shareholders' Equity 426,077 245,585 Non-controlling interests 4,452 5,282 Total equity 430,529 250,867 Total liabilities and equity 894,193 518,731 Commitments and contingencies (Note 20) The accompanying notes are an integral part of these consolidated financial statements. Years Ended December 31, 2012 2011 Operating activities Net income 227,948 48,640 Adjustments: Share of earnings from Apico LLC (19,110) (14,527) Unrealized gain on derivative financial instruments (14,030) (843) Depletion and depreciation 70,139 61,136 Finance expense 4,715 4,825 Amortisation of debt financing fees 1,322 786 Share-based compensation 14,190 15,185 Deferred income taxes 28,656 57,882 Unrealized foreign exchange (gain) loss (885) 388 Exploration expense 7,477 8,374 Gains on disposal of property, plant and equipment (252) (873) Income taxes paid (63,656) (86) Interest received 39 6 Interest paid (2,994) (4,022) Dividends received from Apico LLC 15,792 15,536 Change in non-cash working capital: Accounts receivable (39,909) (6,640) Inventory (6,695) (1,378) Prepaids and other curent assets 466 (488) Accounts payable and accrued liabilities 71,574 4,899 Current income taxes payable 86,673 48 Cash flow provided by operating activities 381,460 188,848 Financing Activities Issuance of common shares, net of issuance costs 3,314 7,907 Repurchase of common shares (18,753) -- Cash settlement of stock options (31,136) -- Cash settlement of restricted stock units (663) -- Borrowings under long-term debt 50,000 6,275 Repayment of long-term debt (30,000) -- Debt financing fees (4,074) (594) Payments to non-controlling interest (4,375) (2,558) Other -- (506) Cash flow (used) provided by financing activities (35,687) 10,524 Investing Activities Decrease (increase) in restricted cash 21,995 (12,078) Purchase of property, plant and equipment (309,599) (165,099) Acquisition of increased ownership interest in Apico (9,250) -- LLC Advances to Apico LLC -- (1,446) Proceeds from disposal of property, plant and 352 250 equipment Deposits and other assets - Payments (6,000) (116) Deposits and other assets - Refunds 134 -- Cash flow used in investing activities (302,368) (178,489) Effect of exchange rate changes on cash (2,503) (1,772) Increase in cash 40,902 19,111 Cash - Beginning of year 22,995 3,884 Cash - End of year 63,897 22,995 The accompanying notes are an integral part of these consolidated financial statements. Randy Bartley, President and Chief Executive Officer of the Company and a member of the Society of Petroleum Engineering and Jerry Moon, Vice President, Technical & Business Development, a member of the American Association of Petroleum Geologists, a Licensed Professional Geoscientist and a Certified Petroleum Geologist in the state of Texas, have reviewed the contents of this announcement. Additional information, including the Company's complete competent person's report may be found on the Company's website at www.CoastalEnergy.com or may be found in documents filed on SEDAR at www.sedar.com. This statement contains 'forward-looking statements' as defined by the applicable securities legislation. Statements relating to current and future drilling results, existence and recoverability of potential hydrocarbonreserves, production amounts or revenues, forward capital expenditures, operation costs, oil and gas price forecasts and similar matters are based on current data and information and should be viewed as forward-looking statements. Such statements are not guarantees of future results and are subject to risks and uncertainties beyond Coastal Energy's control. Actual results may differ substantially from the forward-looking statements. Enquiries: Coastal Energy Company Email: investor@CoastalEnergy.com +1 (713) 877-6793 Strand Hanson Limited (Nominated Adviser) +44 (0) 20 7409 3494 Rory Murphy / Andrew Emmott Macquarie Capital (Europe) Limited (Broker) +44 (0) 20 3037 2000 Paul Connolly / Jeffrey Auld FirstEnergy Capital LLP (Broker) Hugh Sanderson / Travis Inlow +44 (0) 20 7448 0200 Buchanan Tim Thompson / Ben Romney +44 (0) 20 7466 5000 Coastal Energy Company Logo
Coastal Energy Announces 2012 Year End Financial Results & Operations Update
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