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 $1.63.  
  • Note: Per share calculations use weighted average fully diluted shares outstanding for the period
  • The Company released the results of its third-party reserve evaluation report prepared by RPS Energy, Ltd. dated March 20, 2013 (effective date December 31, 2012). The Company reported significant gains in its 1P, 2P and 3P reserve bases, with volumetric increases of 9%, 40% and 78%, respectively. The Company's 1P, 2P and 3P NAVs also increased significantly, rising by 21%, 43% and 62%, respectively.
  As of December 31, 2012 (mmboe) As of December 31, 2011 (mmboe) % Change After-Tax NPV 2012 (US$MM) After-Tax NPV 2011 (US$MM) % Change   After-Tax NPV per Share 2012 (US$)
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 contract (Note 3)  4,099  --
Other income (Note 16)  (4,770)  (21,566)
   666,902  297,104
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
   $   $ 
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 9)  60,266  47,698
Deposits and other assets  6,271  405
Total non-current assets  745,380  435,036
Total Assets  894,193  518,731
Current Liabilities    
Accounts payable and accrued liabilities (Note 10)  131,005  59,392
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 12)  1,372  14,557
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
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 LLC  (9,250)  --
Advances to Apico LLC  --  (1,446)
Proceeds from disposal of property, plant and equipment  352  250
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 hydrocarbon reserves, 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.
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
Tim Thompson / Ben Romney  +44 (0) 20 7466 5000

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