Coastal Energy Company 2009 Annual Report CREATING VALUE THROUGH ORGANIC GROWTH

Transcription

1 2009 Annual Report CREATING VALUE THROUGH ORGANIC GROWTH

2 In 2010, Coastal Energy will begin exploring its 340 mmbbl of prospective resources in the Gulf of Thailand TABLE OF CONTENTS 01 President s Report to the Shareholders Management s Discussion and Analysis Consolidated Financial Statements

3 is an international oil and gas exploration and production company with assets in Thailand. The Company s shares are dual listed on the TSX Venture Exchange (Symbol: CEN) and the London Stock Exchange's AIM (Symbol: CEO). Organic Growth, Unlocking Value Coastal Energy s story began three years ago with a unique asset base consisting of two million acres in the Gulf of Thailand and a 12% interest in the Sinphuhorm gas field onshore Thailand. Through a cost-effective offshore development program, we have grown production from our offshore Songkhla oil field to 9,500 bopd in the second quarter of 2010, increasing overall company production rates to approximately 11,500 boe/d. At the same time, we have also embarked on a program to test the potential of our 324 mmbbl of offshore prospective resources. We continue to own 100% of the offshore acreage in the Gulf, maximizing our exposure to additional production adds from our second proven field, Bua Ban, as well as increasing the potential for successful exploration. To date, we have only evaluated one of 17 mapped prospects on the southern million acres and have recently shot a dense 2-D seismic program on the northern million acres of the Company s holdings. Given our ability to execute cost effectively and leverage offshore infrastructure, additional developments will give rise to improved economics and greater value for our shareholders and investors in the years to come. Production Goes Up and Debt Goes Down Our balanced and cost-effective execution model is best illustrated by the following graphs. Steady gains in production have been made since the company s inception, while leverage has remained conservative. Investing in Our Communities Just as we reinvest in our existing portfolio, we also reinvest in the communities in which we operate by providing employment opportunities wherever possible and supporting local initiatives. We are always looking for new ways in which we as a Company can make a difference and will continue to contribute to the people in the areas in which we live and work. Moving Forward Coastal Energy endeavors to grow reserves and production primarily through the drill bit and deliver solid shareholder returns. Read on to learn more about what we accomplished this past year.

4 2009 was a landmark year for Coastal Energy. The Company was successful in bringing production online at the Songkhla A oil field in the Gulf of Thailand in the first quarter. Offshore production averaged 5,534 bbl/d for the full year. Combined with our share of production of 1,828 boe/d from the Sinphuhorm gas field onshore Thailand, Coastal s total production averaged 7,362 boe/d for the full year. In September 2009, the Company recommenced development of its offshore assets. Two development wells were drilled on Songkhla A, both of which encountered oil in the Lower Oligocene reservoir. Production from these wells (A-04 and A-08) was tied into existing production facilities in Q4. The Company also drilled three water injection wells at Songkhla A, enabling it to reinject produced water into the formation. This eliminated water disposal costs going forward, thus lowering lease operating expenses, and will also help increase ultimate recovery from the field. Coastal s offshore program has continued in the first quarter of The Company has completed workover operations on three wells at Songkhla A, repairing a submersible pump on the A-04 well and installing larger submersible pumps on the A-01 and A-03 wells. Offshore production for Q1 10 averaged approximately 7,100 bbl/d, up nearly 30% from Q4 09 levels. Following the conclusion of workover operations, including the installation of larger submersible pumps on the A-01 and A-03 wells, current offshore production rates are approximately 9,500 bbl/d. Following the completion of development work at Songkhla A, the Company embarked on its offshore exploration program. While the Songkhla B exploration wells were disappointing, it is likely that the discovery could be tied into our existing facilities at Songkhla A. The Benjarong prospect is currently being drilled and has been more successful. The first exploration well at Benjarong encountered two intervals with pay. The main interval encountered had 83.5 feet of net pay with 11.9% porosity. The well also encountered a shallower zone with 16.5 feet of net pay and approximately 15.1% porosity. A long-term flow test will be conducted once the drilling of the Benjarong A-02 well is complete. The Company plans to drill at least three exploration wells at Benjarong. Following drilling at Benjarong, the Company plans to move to the Bua Ban field and continue developing its proved reserve base. Production facilities were installed at Bua Ban in Q1 10, facilitating rapid development of the field. During 2009, the Company completed two successful equity offerings, selling a total of million common shares and raising gross proceeds of C$52.9 million. The proceeds of these offerings were used to fund the Company s offshore development program. Proceeds were also used to delever the Company s balance sheet and enhance its working capital position. The Company is now in a stronger cash flow position and is conservatively leveraged. This was an important year in the history of the Company and management is looking forward to another year of success and growth for Coastal Energy. On behalf of the Board of Directors, Randy L. Bartley President and Chief Executive Officer April 16, 2010 President s Report to the Shareholders 1

5 Coastal Energy s Oil & Gas interests Management s Discussion and Analysis 2

6 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) The following is Management s Discussion and Analysis ( MD&A ) of the results and financial condition of Coastal Energy Company ( Coastal or the Company ). This MD&A, dated April 16, 2010, should be read in conjunction with the accompanying audited consolidated financial statements for the years ended December 31, 2009 and 2008 and related notes thereto. Additional information related to the Company is available on SEDAR at Overview The Company was incorporated in the Cayman Islands under the Companies Law of the Cayman Islands on May 26, The Company is engaged in the acquisition and exploration of petroleum and natural gas properties. The functional and reporting currency of the Company and its subsidiaries is the US dollar. The Company s trading symbols are CEN on the TSX-V and CEO on the AIM exchange. The Company s oil and gas properties and assets consists of the following ownerships interests in petroleum concessions awarded by the Kingdom of Thailand: Petroleum Concession Coastal Gulf of Thailand Block G5/ % Block G5/50 (within the boundaries of Block G5/43) 100.0% Onshore Thailand (via the Company s 36.1% ownership of Apico LLC ( Apico )) Blocks EU-1 and E-5N containing the Sinphuhorm gas field 12.6% Block L15/43 (surrounding the Sinphuhorm gas field) 36.1% Block L27/43 (southeast of the Sinphuhorm gas field) 36.1% Block L13/48 (immediately east of the Sinphuhorm gas field) 21.7% Fourth Quarter 2009 Highlights Total Company production averaged 7,391 boe/d for the fourth quarter. The Company s fourth quarter EBITDAX was $12.5 million. The Company drilled two development wells and three water injection wells on the Songkhla A field. Both development wells, Songkhla A-04 and Songkhla A-08, encountered oil in the Lower Oligocene reservoir and logged 100 feet and 92 feet of net pay with 20% and 18% porosity, respectively. On November 5, 2009, the Company announced the completion of an equity offering, selling 6.9 million common shares at a price of Cdn $5.00 per share and raising gross proceeds of Cdn $34.5 million. The proceeds were used to fund development of its offshore assets, reduce short-term debt and for general corporate working capital. Management s Discussion and Analysis 3

7 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Other 2009 Highlights Total Company production averaged 7,362 boe/d for the full year of The Company s total year EBITDAX was $37.9 million. On May 28, 2009 the Company announced the completion of an equity offering, selling 5 million common shares at a price of Cdn $3.20 per share and raising gross proceeds of Cdn $16 million. On June 17, 2009 the Company announced that the underwriters had exercised their overallotment option to purchase an additional 750,000 common shares at a price of Cdn $3.20, resulting in additional gross proceeds to the Company of Cdn $2.4 million. The Company completed a 2-D seismic acquisition on a 4,000 sq. km area in the northern part of its G5/43 concession, including the G5/50 concession in its entirety. The area surveyed contains the Nakhon and Ko Kra basins. The interpreted data is being analyzed to identify exploration prospects. Production Summary Average daily BOE production 3 months ended December 31, Years ended December 31, Change Change Songkhla A field, Gulf of Thailand (b) 5,509 3,012 83% 5, Sinphuhorm field, Onshore Thailand (a) 1,882 1,468 28% 1,828 1,785 2% Total average daily BOE production 7,391 4,480 65% 7,362 2, % Note (a) These amounts represent the Company s net 12.5% held though the Company s 36.1% ownership of Apico, LLC. This ownership is accounted for using the equity method of accounting as opposed to a pro rata consolidation. Note (b) The Company achieved first production in the Songkhla field during Q and had test production for the last 57 days of the quarter. The average volume production for the year ended December 31, 2008 was determined by annualizing the 57 days of test production during Q The Company s 2009 production increase is primarily attributable to drilling success in the Songkhla A field and the first full year of production in this field. Forward Looking Statements Certain information included in this discussion may constitute forward-looking statements. Forward looking statements are based on current expectations, estimates, and projections that involve various risks and uncertainties. These risks and uncertainties could cause or contribute to actual results that are materially different from those expressed or implied. Management s Discussion and Analysis 4

8 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Non-GAAP Measures This report contains financial terms that are not considered measures under Canadian generally accepted accounting principles ( GAAP ), such as funds flow from operations, funds flow per share, EBITDA, EBITDAX, net debt, operating netback and working capital. These measures are commonly utilized in the oil and gas industry and are considered informative for management and shareholders. Specifically, funds flow from operations and funds flow per share reflect cash generated from operating activities before changes in non-cash working capital. Management considers funds flow from operations and funds flow per share important as they help evaluate performance and demonstrate the Company s ability to generate sufficient cash to fund future growth opportunities and repay debt. EBITDA is defined as earnings before interest, taxes, depreciation, amortization and earnings from significantly influenced investee adjusted for non-cash items such as unrealized gains and losses on risk management contracts, unrealized foreign exchange gains or losses and stockbased compensation. EBITDAX is an industry measure equivalent to EBITDA but for the fact that it neutralizes the impact of some companies expensing rather than capitalizing exploration costs. Net debt includes short term and revolving credit facilities less cash and cash equivalents and restricted cash, and is used to evaluate the Company s financial leverage. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Working capital represents current assets less current liabilities. Funds flow from operations, funds flow per share, EBITDA, EBITDAX, net debt, operating netbacks and working capital are not defined by GAAP, and consequently are referred to as non-gaap measures. Accordingly, these amounts may not be compatible to those reported by other companies where similar terminology is used, nor should they be viewed as an alternative to cash flow from operations, net income or other measures of financial performance calculated in accordance with GAAP. Oil & Gas Reserves The Company s reserves were evaluated by Huddleston & Co., Inc. effective December 31, 2009 and are all in Thailand. Selected data from their report follows. Their report, dated March 17, 2010, is incorporated in our 2009 Annual Information Form ( AIF ) which is available on SEDAR at Natural gas is converted to equivalent barrels ( BOE ) at the energy equivalent conversion rate of six thousand cubic feet (6mcf) to one barrel ( 1bbl ) of crude oil, reflecting the approximate relative energy content. Management s Discussion and Analysis 5

9 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) The following consolidated reserve figures, before royalties for 2009 and 2008 reflect Coastal Energy s 100% interest in its Gulf of Thailand concessions (Block G5/43 and G5/50) and 36.1% interest in APICO as if the Company directly owned the onshore properties. Oil and Gas Reserves (Gross) December 31, 2009 December 31, 2008 Oil Gas BOE Oil Gas (Mbbls) (MMcf) (Mbbls) (Mbbls) (MMcf) BOE (Mbbls) Proved Reserves Gulf of Thailand developed producing 5,191-5,191 6,574-6,574 Gulf of Thailand developed non- 2,794-2, producing Gulf of Thailand undeveloped 7,183-7,183 11,154-11,154 Subtotal Proved Gulf of Thailand 15,168-15,168 18,085-18,085 Onshore developed producing ,219 7, ,468 8,509 Onshore undeveloped Subtotal Proved Onshore ,219 7, ,468 8,509 Total Proved 15,411 46,219 23,114 18,349 49,468 26,594 Probable Reserves Gulf of Thailand 17,701-17,701 23,371-23,371 Onshore ,778 13, ,088 12,228 Total Probable 18,126 80,778 31,589 23,751 71,088 35,599 Proved Plus Probable Reserves Gulf of Thailand 32,869-32,869 41,456-41,456 Onshore ,997 21, ,556 20,737 Total Proved Plus Probable 33, ,997 54,703 42, ,556 62,193 Management s Discussion and Analysis 6

10 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) The forecasted prices used by Huddleston & Co., Inc. in their evaluation for December 31, 2009 and 2008 were taken from the Gilbert Lausten Jung ( GLJ ) Petroleum Consultants website ( GLJ projected prices through 2018, and Huddleston & Co. Inc. then applied a 2% per year escalation for the life of the properties. Forecasted prices as at December 31, 2009 and 2008 are as follows: As at December 31, 2009 As at December 31, 2008 Year Oil ($/bbl) Condensate ($/bbl) Gas ($/Mcf) Oil ($/bbl) Condensate ($/bbl) Gas ($/Mcf) 2009 n/a n/a n/a n/a n/a n/a thereafter 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% The following table summarizes the present value of future net revenues discounted at 10% before income taxes: US $ millions based on forecasted prices at December 31, Proved Reserves Gulf of Thailand developed producing $191.0 $195.8 Gulf of Thailand developed non-producing Gulf of Thailand undeveloped Subtotal Proved Gulf of Thailand Onshore developed producing Onshore undeveloped - - Subtotal Proved Onshore Total Proved $763.9 $646.8 Probable Reserves Gulf of Thailand $845.5 $680.6 Onshore Total Probable $990.1 $791.5 Proved Plus Probable Gulf of Thailand $1,454.8 $1,173.5 Onshore Total Proved Plus Probable $1,754.0 $1,438.3 Management s Discussion and Analysis 7

11 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Oil & Gas Properties Summary of Oil & Gas Properties Thailand Onshore Gulf of Thailand Totals Balance, December 31, 2007 $53,188 $75,687 $128,875 Additions during the period, net of disposals: Exploration & development ,411 77,314 Equity earnings in Apico, net of distributions (2,656) - (2,656) Depletion - (1,655) (1,655) Amortization of excess basis in Apico (1,059) - (1,059) Balance, December 31, 2008 $50,376 $150,443 $200,819 Additions during the period, net of disposals: Exploration & development 4,516 62,980 67, 496 Equity earnings in Apico, net of distributions 1,415-1,415 Depletion - (25,939) (25,939) Amortization of excess basis in Apico (1,082) - (1,082) Balance, December 31, 2009 $55,225 $187,484 $242,709 (a) Gulf of Thailand Properties The Company holds a 100% working interest in Blocks G5/43 and G5/50 (the Blocks ) in the Gulf of Thailand. The current combined area of the Blocks is approximately 5,021 square kilometres and average water depths are approximately 70 feet. Block G5/50 contains approximately 554 square kilometres of acreage within the boundaries of Block G5/43. Management s Discussion and Analysis 8

12 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Songkhla Field The Company has drilled five wells (four development and one exploration) on the Songkhla A field of Block G5/43, all of which have proved successful. The Songkhla A-01 and A-03 development wells were drilled in the fourth quarter of 2008 and both encountered oil in the Lower Oligocene primary reservoir. The Songkhla A-07 exploration well was also drilled in Q and encountered oil in the deeper Eocene reservoir. All three wells were completed in Q The installation of dedicated production facilities in February 2009 enabled full production operations to commence. The Company re-commenced its development drilling program at Songkhla A in September The Company drilled two development wells (A-04 and A-08) and three injection wells (A-02, A-05 and A-06) in the fourth quarter of Both development wells encountered oil in the Lower Oligocene reservoir. The Company s offshore production from Songkhla A averaged 5,509 bbl/d in the fourth quarter of 2009 and 5,534 bbl/d for the full year. During the first quarter of 2010 the Company completed the workover operations on certain wells at Songkhla A and Coastal s production averaged approximately 7,100 bbl/d. The Company has received approval of its Production Area Application ( PAA ) and Environmental Impact Assessment ( EIA ) for the Songkhla field, which will allow it to proceed in developing numerous satellite structures which have been identified within the 75 square kilometre area around Songkhla A without further government approval. As of December 31, 2009, Songkhla A has proved and probable ( 2P ) reserves of approximately 11,070 mbbls (before royalties). Bua Ban Field In August 2005 three successful wells were drilled by the Company on the Bua Ban oil field ( Bua Ban ). The three well program encountered oil in the Lower Oligocene reservoir. The Company plans to commence development drilling on the Bua Ban field in late second quarter The Bua Ban wellhead and production platforms have been installed during the first quarter of 2010 and the Company s 50% owned floating storage and offloading vessel ( FSO ) is scheduled to be on location concurrent with commencement of the drilling program in late second quarter The Company has received approval of its Production Area Application and Environmental Impact Assessment for the Bua Ban field. The Bua Ban PAA covers an area of 282 square kilometres, which includes the Bua Ban field and numerous satellite structures. As of December 31, 2009, Bua Ban had 2P oil reserves of 21,800 mbbls (before royalties). Under the terms of the concession agreement and the Thai Petroleum Act B.E. 2514, the Company is required to periodically relinquish a portion of its concession which is not protected under the Company s production licenses. The following table shows the size of the initial concession, all relinquishments made by the Company and the remaining size with respect to Block G5/43. Activity Date Size in Square Kilometers Initial grant of the concession 17 July ,110 End of concession s first exploration period (~50%) 17 July 2007 (8,615) End of concession s second exploration period (~25%) 17 July 2009 (4,028) 4,467 Company management used available seismic and technical data to determine the less prospective acreage which was relinquished. As a result, under full cost accounting, the Company has incurred no financial impact related to these relinquishments. At December 31, 2009, total Gulf of Thailand (including the Songkhla and Bua Ban fields) 2P reserves are 32,869 mbbls (before royalties). Management s Discussion and Analysis 9

13 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) (b) Thailand Onshore The Company s Thailand onshore interests are held indirectly through its equity investment in Apico. Apico is considered a significantly influenced investee. Apico s petroleum concessions are located in the Khorat Plateau in north eastern Thailand. Apico s results of operations for the years ended December 31, 2009 and 2008 and its financial position are as follows: Apico Results for the year ended December 31, Total revenue $55,161 $80,313 Total expenses 12,507 14,231 Income tax expense 16,240 27,443 Net Income $26,414 $38,639 Apico Balance Sheet as of December 31, Current assets $24,293 $19,823 Property, plant and equipment 113, ,882 Other assets 2,707 2,743 Total assets $140,622 $128,448 Current liabilities 22,776 $29,240 Non-current liabilities 7,276 5,052 Members equity 110,570 94,156 Total liabilities and equity $140,622 $128,448 Management s Discussion and Analysis 10

14 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Coastal holds a net working interest of 12.6% in Blocks EU-1 and E-5N onshore Thailand through its 36.1% equity investment in Apico, LLC, which holds a 35% non-operated working interest in the Blocks. Blocks EU-1 and E-5N contain the Sinphuhorm gas field. Production at Sinphuhorm commenced on November 30, 2006 to supply the Nam Phong power plant with over 500 billion cubic feet of gas, plus condensate, under a 15 year Gas Sales Agreement with PTT Public Company Limited. During 2009, the Sinphuhorm field delivered approximately 85 mmcf/d (11 mmcf/d net to Coastal) to Nam Phong. The field also produced in excess of 446 bbl/d (56 bbl/d net to Coastal) of condensate. As of December 31, 2009, Sinphuhorm had 2P reserves of 1,016 billion cubic feet ( bcf ) of natural gas (127 bcf net to Coastal) and 5,344 mbbls of oil (668 mbbls net to Coastal), before royalties. Coastal also holds a net 36.1% working interest in Block L27/43 (operated by Apico), which is located southeast of the L15/43 concession. The Phu Kheng-1 exploration well was spudded in July 2009 and encountered Jurassic and Triassic sandstones in the Phu Kradung and Nam Phong formations. Following the hydraulic fracturing tests, no gas flow as seen in either interval and this well was plugged and abandoned. Coastal holds a net 21.7% working interest in Block L13/48 (operated by Apico), which is located 40km east of the Sinphuhorm gas field. The L13 concession contains the Si That discovery which tested gas in both the Si That 1 & 2 wells. The Si That-3 appraisal well spudded in September 2009 and was subsequently tested. Test results show no free gas in the formation. The operator is currently evaluating the remaining prospectivity of the L13/48 concession. The Company has a net 36.1% working interest in Block L15/43 (operated by Apico), which surrounds the Sinphuhorm gas field. Summary of Annual Results Years ended December 31, Revenue $78,530 $7,313 $ - Expenses 86,496 22,112 12,900 Share of (earnings) loss of Apico, LLC (8,462) (12,904) (7,679) Income taxes ,862 Non-controlling interest (127) - - Net loss and comprehensive loss attributable to shareholders $(115) $(2,561) $(9,095) Basic and diluted loss per share $0.00 $(0.03) $(0.12) Working capital (deficit) $(32,782) $(43,232) $914 Capital expenditures $67,893 $103,982 $21,945 Total assets $325,609 $258,463 $157,654 Common shares outstanding, end of year 108,276,725 93,630,720 76,983,220 Management s Discussion and Analysis 11

15 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) The following tables are analysis of the line items in the Company s Consolidated Statements of Operations and Comprehensive Loss: Revenue and Production 3 months ended December 31, Years ended December 31, Change Change Gross oil revenue $28,926 $4,098 - $86,348 $4,098 - Average daily oil production 5,509 3,012 83% 5, Realized price per bbl ($/bbl) $66.26 $ % $54.06 $ % The Company commenced production from the Songkhla field in the Gulf of Thailand on February 23, 2009 following installation of dedicated production facilities. Average production for the three and twelve month periods ended December 31, 2009 was 5,509 bbl/d and 5,534 bbl/d, respectively. Production volumes were affected by pump failures on the A-04, A-07 and A-08 wells. These wells have since been worked over and full production has been restored. Royalties 3 months ended December 31, Years ended December 31, Change Change Royalties $2,027 $214 - $5,878 $214 - $ per bbl $4.64 $ $ Royalties as a percent of revenue 7.0% 5.2% - 7.0% 5.2% - Royalties on the Gulf of Thailand assets are paid to the Kingdom of Thailand as a percentage of revenue based on a sliding scale tied to monthly production. Fourth quarter royalty per barrel was higher than the full year average as fourth quarter realized price per barrel was higher. Gain (loss) on Derivative 3 months ended December 31, Years ended December 31, Change Change Unrealized gain (loss) on mark-to-market $(282) $1,983 - $(1,950) $2,015 - Realized gains (losses) (127) Gain (loss) on Derivative $(282) $2,415 - $(2,077) $2,447 - The Company is required by the lenders in its revolving credit facility to hedge approximately 50% of its onshore gas production. The Company purchased a put option under which the Company has the right to sell 4,000 metric tons per month of Singapore fuel oil at a price of $ per metric ton. The Company adjusts the fair value of this risk management contract (mark to market) every quarter with the changes in fair value recognized in net earnings. Management s Discussion and Analysis 12

16 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) The Company s original contract ran from July 1, 2007 through June 30, During 2009, the Company recognized $439,000 in gains on this contract from sales proceeds (during Q1 09) and realized losses on mark-to-market adjustments of $2,016,000 on this contract ($1,526,000 in Q1 09 and $490,000 in Q2 09). The Company entered into a new contract beginning June 6, 2009 and expiring June 30, The Company has unrealized losses on this contract of $500,000, of which $282,000 loss was recorded in the current quarter. Interest Income 3 months ended December 31, Years ended December 31, Change Change Interest income $5 $151 - $27 $982 - Interest income is the result of the Company investing cash in highly liquid investments and holding restricted cash in interest bearing accounts. During the year ended December 31, 2008, the Company had higher cash balances as a result of its equity issuance during the year, the proceeds of which was held in interest bearing accounts. This cash was subsequently used to fund development activity. Other Income 3 months ended December 31, Years ended December 31, Change Change Other income $110 $- - $110 $- - Other income was generated by the Company sub-leasing excess capacity at the Company s Songkhla port operations to an unrelated third party Production Expenses 3 months ended December 31, Years ended December 31, Change Change Production expenses $9,271 $1,905 - $35,778 $1,905 - Effects of changes in inventory 418 (308) - (2,301) (308) - $9,689 $1,597 - $33,477 $1,597 - $ per bbl $22.19 $ % $20.96 $ % Production costs for the fourth quarter of 2009 declined on a per barrel basis from Q owing to a reduction in water disposal costs and renegotiations of certain fixed cost contracts at lower rates. Total operating costs increased substantially year over year because the Company s 2008 production which began in Q4 was performed during its drilling operations and utilized the drilling rig as production facilities. In February 2009, the Company installed production facilities and began standalone production at Songkhla A resulting in higher operating expense. Management s Discussion and Analysis 13

17 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) General and Administrative 3 months ended December 31, Years ended December 31, Expenses Change Change Salaries and benefits $6,201 $2, % $13,929 $7,722 80% Professional fees % 1,510 1,783-15% Office and general % 2,121 1,787 19% Travel and entertainment % 1, % Regulatory and transfer fees % % Total general and administrative expenses $8,144 $4,114 98% $19,576 $12,824 53% In general, the 2009 increase over 2008 is attributable to the growth and increased activities of the Company. The largest driver of general and administrative expenses is personnel costs. Included in the salaries and benefits for 2009 and 2008 is non-cash, stock based compensation of $1.96 million and $1.75 million, respectively for the 12 months ended December 31. During 2009, the Company granted Stock Appreciation Rights ( SARs ) for which the Company initially recorded expense of $1.69 million upon grant. During 2009 the Company s stock price appreciated 256%. Due to the requirement to mark to market these SARs at each quarter point, the Company incurred an additional $3.90 million of salary expense in 2009 thus our overall 2009 salary expense related to the SARs grants was $5.59 million. At December 31, 2009 and 2008, the Company had 44 and 32 full-time employees, respectively; and 16 and 24 full time contractors, respectively. The Company had an office in England which was closed in December The Company continued to incur expenses in 2009 as a result of commitments and non-cancellable leases. These leases have since expired in General and administrative expenses for this office totalled $0.52 million and $2.27 million for the years ended December 31, 2009 and 2008, respectively. Foreign Exchange Loss 3 months ended December 31, Years ended December 31, Change Change Total foreign exchange loss $304 $820 $1,941 $3,869 The foreign exchange loss is a result of the Company carrying out transactions and maintaining certain financial assets and liabilities in currencies other than the US Dollar, including the Canadian Dollar, the British Pound, the Euro and the Thai Baht. On September 25, 2006, the Company acquired all of the issued and outstanding shares of NuCoastal (Thailand) Limited in a transaction accounted for as a reverse takeover ( RTO ). As part of this RTO, the purchase price allocation included the establishment of a future income tax liability on assets located in Thailand. This liability relates to Thai taxes and is denominated in Thai Baht. At each quarter period end this future income tax liability is re-valued and the corresponding non-cash gain/loss is recognized in net earnings. Of the 2009 total year exchange loss, $1.011 million is attributable to this non-cash re-valuation. Management s Discussion and Analysis 14

18 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Interest Expense 3 months ended December 31, Years ended December 31, Change Change Interest Expense $677 $844-20% $3,839 2,146 79% Interest expense includes interest on the Company s notes payable, amounts due to shareholder and long-term debt. Interest expense was higher in 2009 as the Company had higher average balances throughout the year than in The Company also issued notes payable at higher fixed coupon rates in 2009, all of which was repaid by December 31, The Company s average interest rate was 6.75% and 5.12% for the years ended December 31, 2009 and 2008, respectively. Depletion, Depreciation and 3 months ended December 31, Years ended December 31, Accretion Expense Change Change Oil and gas depreciation & depletion $8,670 $1,655 - $25,939 $1,655 - Effect of change in inventory (1,438) - - (2,701) - - Oil and gas accretion % Corporate depreciation % % Depletion, depreciation and accretion expense $7,457 $1, % $23,695 $1,893 1,152% $ per bbl $16.70 $ % $14.62 $ % Depletion and accretion expenses were recorded in 2009 due to the Company achieving first production in Q and having significantly higher production in Prior to this, the Company primarily incurred depreciation on corporate assets. Depreciation of corporate assets also increased due to the increase in corporate assets necessary to support increased headcount. Income Taxes 3 months ended December 31, Years ended December 31, Change Change Current taxes $ $38 $2,484 - Future income taxes (1,818) - Income taxes $ $738 $666 - The Company s pre tax income is subject to tax in several jurisdictions including Thailand, the United Kingdom and the United States. Prior to 2009, all taxable operating loss carry forwards in all taxing jurisdictions were fully reserved because there was no presumption that the Company would be able to actually utilize these taxable losses to offset future taxable income. It now appears that the Company will be in a position to utilize the operating loss carry forwards in future years in Thailand. Management s Discussion and Analysis 15

19 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) The Company held 25.5% of Apico in its Thai subsidiary and therefore accrued income tax expense on its equity pick up of Apico s book earnings at an investment tax rate of 30%. Effective April 1, 2008, it transferred this 25.5% interest in Apico, LLC (Note 7) at its net book value to one the Company s Cayman Island subsidiaries. This transfer triggered the filing of an investment tax return, which turned the cumulative non-current tax liability of $2.484 million into a current tax liability. In Q3 2008, the Company made a $1.232 million estimated tax payment toward this tax liability. In Q2 2009, the Company filed the required tax return and made the final tax payment satisfying this liability completely. The Cayman Island subsidiary is not currently subject to income taxes. Earnings from Significantly Influenced Investee, net of taxes 3 months ended December 31, Years ended December 31, Change Change Coastal s 36.1% of Apico s net income $2,858 $2,398 19% $9,544 $13,963-32% Amortization of Coastal s excess basis (281) (219) 28% (1,082) (1,059) 2% Earnings from Significantly Influenced Investee, net of taxes $2,577 $2,179 18% $8,462 $12,904-34% 100% Field Production volumes (mmcf/d) % % 12.6% net to Coastal (mmcf/d) % % Under the equity method of accounting, the Company records its share of net income of Apico based on the reported quarterly net income of Apico. Apico experienced slightly higher revenue in the fourth quarter of 2009 over the prior quarter due to higher realized commodity pricing. Earnings from Apico for the year ended December 31, 2009 were lower than the prior year due to lower commodity prices being slightly offset by higher production volumes. On September 25, 2006, the Company acquired an additional interest in Apico for an amount greater than its proportionate share of net assets of Apico ( excess basis ). The excess basis was allocated to Apico s oil & gas properties and is being amortized using the units of production method beginning in Q Net Income (Loss) 3 months ended December 31, Years ended December 31, Change Change Net income (loss) and comprehensive income (loss) attributable to shareholders 2,009 (413) - (115) (2,561) - Income (loss) per share, basic and diluted $0.02 $(0.01) - $0.00 $(0.03) - Management s Discussion and Analysis 16

20 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Summary of Quarterly Results Q4 Q3 Q2 Q1 Q4 Q3 Q2(a) Q1(a) Oil revenues, net of royalties $26,899 $19,775 $26,137 $7,659 $3,884 $ - $ - $ - Gain (loss) on derivative (282) 128 (836) (1,087) 2, (8) 27 Interest income Other income Total revenues 26,732 19,909 25,306 6,583 6, Production expenses 9,689 10,936 9,532 3,320 1, General and administrative expenses 8,144 5,029 3,210 3,193 4,114 3,053 2,209 3,447 Foreign exchange (gain) loss ,765 (368) 820 1,440 (1,773) 3,382 Interest expense ,347 1, Debt financing fees (Gain) loss on sale of assets (95) (122) - - Depletion, depreciation and accretion 7,457 5,382 7,698 3,158 1, Settlement and asset impairment - - 2, Total operating expenses 26,624 22,706 25,943 11,222 9,042 5, ,101 Income tax expense Share of earnings (loss) of Apico LLC 2,577 2,621 1,854 1,410 2,179 4,250 3,607 2,868 Net income (loss) before noncontrolling interest 1,947 (176) 1,217 (3,229) (413) (476) 2,955 (4,627) Non-controlling interest Net income (loss) and comprehensive income (loss) attributable to shareholders 2,009 (111) 1,217 (3,229) (413) (476) 2,955 (4,627) EBITDAX (b) 12,520 6,820 14,968 3,557 (264) 1,680 5,664 (1,155) Basic and diluted earnings (loss) per share $0.02 $0.00 $0.01 $(0.03) $(0.01) $(0.00) $0.03 $(0.05) Note (a) The quarterly information for Q1 and Q was restated to correct an error on recording the future income tax liability and expense and associated foreign exchange loss associated with the outside basis difference between the carrying amount of the investment in Apico LLC and the Company s tax basis. Note (b) EBITDAX is a non-gaap measure and is defined as earnings before interest, financing fees, taxes, depreciation, amortization, exploration costs and other one-time items adjusted for non-cash items such as unrealized gains and losses on risk management contracts, unrealized foreign exchange gains or losses and stock-based compensation (see reconciliation below.) Management s Discussion and Analysis 17

21 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Significant factors influencing Quarterly Results include The Company began standalone production from its Songkhla A field in February This resulted in nearly a full year of revenue, operating expense and DD&A expense. The volatility of global crude oil prices has a direct effect on the Company s revenue and its unrealized (gain) loss on its derivative instrument. The Company incurred higher G&A expense related to a full year of operations as well as recognition of non-cash equity-based compensation expense. The Company transacts business in multiple currencies; therefore the volatility of global currency exchange rates has a direct effect on the Company s foreign exchange (gains) losses EBITDAX Computation Q4 Q3 Q2 Q1 Q4 Q3 Q2(a) Q1(a) Net income (loss) attributable to shareholders $2,009 $(111) $1,217 $(3,229) $(413) $(476) $2,955 $(4,627) Add Back: Unrealized (gain) loss on derivative 284 (128) 836 1,526 (1,983) (13) 8 (27) Interest income (5) (6) (5) (11) (151) (316) (270) (245) Stock option expense Unrealized foreign exchange (gain)/loss 1, ,069 (382) (604) 1,482 2,036 2,000 Interest expense ,347 1, Debt financing fees (Gain) loss on sale of assets (95) (122) - - Depletion, depreciation and accretion 7,457 5,382 7,698 3,158 1, Settlement expense - - 2, Income tax expense EBITDAX $12,520 $6,820 $14,968 $3,557 $(264) $1,680 $5,664 $(1,155) Note (a) The quarterly information for Q1 and Q was restated to correct an error on recording the future income tax liability and expense and associated foreign exchange loss associated with the outside basis difference between the carrying amount of the investment in Apico LLC and the Company s tax basis. Note (b) The unrealized foreign exchange adjustment relates to a tax liability in Thailand, recorded for book purposes only. As such, this liability will be amortized over time but does not represent a future cash commitment. Management s Discussion and Analysis 18

22 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Cash Flow Analysis The Company s cash and cash equivalents at December 31, 2009 were $21.2 million, an increase of $14.8 million from $6.4 million at December 31, The Company s primary source of funds during the year came from net proceeds of $49.3 million from stock issuance; net borrowings of $1.6 million under its revolving debt facilities; $15.0 million of notes payable; borrowings of $1.0 million from its amounts due to shareholder; $8.1 million net distributions from Apico; $5.7 million from a non-controlling interest; increase in accounts payables and accrued liabilities of $4.2m million; cash advances of $23.1 million for prepaid oil contracts and cash inflows from operating activities. Cash and cash equivalents were primarily used to invest $77.5 million in property, plant and equipment; provide advances of $4.5 million to its significantly influenced investee, APICO; pay income taxes of $1.3 million; repay $15.0 million of notes payable, $3.0 million of amounts due to shareholders and $11.1 million of bank debt. Cash inflows were also used to fund operating expenses of $86.3 million and to support other current assets as can be seen from the increase in accounts receivable by $3.7 million and crude oil inventory of $5.0 million; Capital Expenditures Capital expenditures (including cash payments and amounts included in accounts payable) amounted to $67.9 million in 2009 compared to $104.0 million in The decrease in expenditures was mainly the result of lower oilfield service rates. The following table sets forth a summary of the Company s capital expenditures incurred: Capital Expenditures Seismic, geological and geophysical studies $7,577 $2,295 Other Drilling and completions 39,507 46,990 Lease and well equipment 13,882 4,876 Construction in progress (platforms, FSO, processing equipment) 6,722 48,543 Administrative assets Total Capital Expenditures $67,893 $103,982 Equity Capital a) Share Capital Authorized 250,000,000 common shares with par value of $0.04 each; As of the date of this report, the Company had 109,512,791 common shares outstanding. b) Stock Options During the year ended December 31, 2009, the Company granted 6,125,599 stock options with a weighted average exercise price of $2.71. In addition, options exercised and forfeited were 1,106,750 and 190,250 respectively. Subsequent to December 31, 2009, 778,412 options were exercised. Management s Discussion and Analysis 19

23 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) The following table summarizes the outstanding and exercisable options as of the date of this report: Grant Date Number Outstanding Remaining Contractual Life Exercise Price Expiry Date Number Exercisable Jul. 06, , years $2.26 ( 1.40) Jul. 06, ,000 Dec. 27, ,925, years $2.10 (C$2.20) Dec. 27, ,925,000 Jun. 15, , years $2.83 (C$2.96) Jun. 16, Jan. 25, , years $3.76 (C$3.94) Jan. 26, ,750 May 05, , years $4.24 (C$4.44) May 06, ,500 Jul. 14, , years $3.45 (C$3.61) Jul. 15, ,500 Sep. 16, , years $2.17 (C$2.27) Sep. 16, ,000 Sep. 23, ,000, years $3.76 (C$3.94) Feb. 05, ,000 Jan. 02, ,127, years $1.29 (C$1.35) Jan. 01, ,997 Dec. 01, ,616, years $4.90 (C$5.13) Nov. 30, ,631,187 4,196,747 c) Warrants As of December 31, 2008, the Company had 2,343,745 warrants outstanding exercisable at $4.53 ( 2.80) per share and expiring on July 20, In connection with a public debt offering in January 2009, the Company issued 2,000,000 warrants for shares with an exercise price of $1.09 (Cdn $1.136.) The warrants will expire on January 23, During 2009, 1,097,500 of warrants were exercised resulting in the issuance of 889,175 common shares of the Company. As of December 31, 2009, the Company had 3,246,245 warrants outstanding at a weighted average exercise price of $3.42 per share. During 2010, an additional 563,867 warrants were exercised resulting in the issuance of 457,734 common shares of the Company. Off-Balance Sheet Arrangements The Company has no off-balance sheet arrangements. Management s Discussion and Analysis 20

24 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Related Party Transaction Effective September 25, 2006, the Company assumed a note payable to O.S. Wyatt, Jr., the shareholder of NuCoastal Thailand Limited ( NuCoastal ) for $4.6 million. The original note was unsecured, accrued interest at 4% and was set to mature on July 20, The note and its accrued interest have been periodically renegotiated and now mature on June 30, 2010 and bears interest at 12% per annum. The Company has periodically made interest payments against the note. During Q1 2010, the Company paid $1.75 million on the principal and accrued interest; and the face value of the note is now $3.5 million. In December 2008 and January 2009, the Company entered into unsecured loan agreements totaling $3 million bearing interest at 15% per annum and maturing on June 30, This debt was funded by related parties of the Company s primary shareholder, O. S. Wyatt, Jr. The Company has repaid all of this debt along with the accrued interest. See Note 11 to the Consolidated Financial Statements for the year ended December 31, 2009 for further details. Commitments and Contingencies All the Company s commitments and contingencies are described in Note 19 to the Consolidated Financial Statements for the year ended December 31, Subsequent Events During Q1 2010, the Company drilled three exploration wells on its Songkhla B prospect. Two of the three wells encountered oil; however, not in quantities large enough to justify standalone development. Management believes that it might be possible to reach the Songkhla B structure with a horizontal well from Songkhla A. The Company received EIA approval for the development of the Bua Ban field. Installation of the Bua Ban fixed platforms was completed in February 2010, expediting development of the field. During Q1 2010, the Company paid $1.75 million in principal and accrued interest on the amount due to shareholder leaving a balance as of the date of this report of $3.54 million. Financial Instruments The Company s financial instruments include cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities. The fair values of financial instruments approximate their carrying values due to their short term nature. The Company s derivative contract is considered held-for trading and it is adjusted to fair value every quarter as discussed below. Amounts due to shareholder and long-term debt are considered other financial liabilities and are recorded at amortized cost. The carrying value of amounts due to shareholder approximates the fair value. This is due to the short term nature of the liability. The fair value of the Company s long term debt as at December 31, 2009 and 2008 was $33.69 million and $42.71 million, respectively. As a condition of the Company s reserve based revolving debt facilities, the Company is required to hedge 50% of its commodity price exposure related to production on the Sinphuhorm Gas Field. The Company obtains 3rd party quotes in order to mark to market the gains and losses related to the commodity hedge. As of December 31, 2009, the market value of this option was $66,000. Management s Discussion and Analysis 21

25 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Critical Accounting Policies and Estimates The Company s financial statements are prepared in accordance with Canadian GAAP, which require management to make judgments, estimates and assumptions which may have a significant impact on the financial statements. A detailed summary of the Company s significant accounting policies is included in Note 2 to the Consolidated Financial Statements. The following is a discussion of those accounting policies and estimates that are considered critical in the determination of the Company s financial results. a) Capital Assets Full Cost Accounting The Company follows the full cost method of accounting as described in Note 2 to the Consolidated Financial Statements. Alternatively, the Company could follow the successful efforts method of Accounting whereby all costs related to non-productive wells are expensed in the period in which they are incurred. Under the full cost method of accounting, capitalized costs are subject to a country-by-country cost centre impairment test. Under the successful efforts method of accounting, the costs are aggregated on a property-by-property basis and the carrying value for each property is subject to an impairment test. These policies may result in a different carrying value for capital assets and a different net income. The Company has elected to follow the full cost method. Coastal assesses the carrying value of its property, plant and equipment for impairment annually or as circumstances dictate. Impairment is indicated when the carrying value of a cost centre exceeds the estimated undiscounted future net cash flows associated with the cost centre s proved reserves. Cash flows are calculated using expected future product prices and costs and are discounted using a risk-free interest rate. Any impairment is measured as the excess of the carrying amount over the estimated discounted future net cash flows associated with the Company s proved and probable reserves. Reserves are determined pursuant to Canadian Securities Administrators National Instrument , Standards of Disclosure of Oil and Gas Activities. Costs relating to undeveloped properties are subject to individual impairment assessments until it can be determined whether or not proved reserves exist. If impairment is determined to exist, the costs carried on the balance sheet in excess of the discounted future net cash flows associated with the cost centre s proved plus probable reserves are charged to earnings in the period the impairment occurs. As of December 31, 2009, the Company has one cost centre, Thailand. b) Depletion and Depreciation Oil and gas properties and equipment together with the estimated future costs to be incurred (other than future major development items such as production platforms) in developing proved reserves, are depleted or depreciated using the units of production method based on the proved reserves before royalties as estimated by independent engineers. Oil and gas reserves and production are converted into equivalent units based upon estimated relative energy content of six thousand cubic feet of gas to one barrel of oil (6 mcf = 1 bbl). The costs of undeveloped properties are excluded from the costs subject to depletion and depreciation until it is determined whether proved reserves are attributable to the properties or impairment occurs. In addition, certain major components of production equipment (such as a floating storage and off-loading vessel FSO ) have a life that is longer than the specific field to which it is currently assigned. These major production components are depreciated on a straight line basis over the estimated useful life of the asset which approximates the estimated production life of the Company s Gulf of Thailand concessions. Management s Discussion and Analysis 22

26 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Depreciation of office equipment, furniture and fixtures and leasehold improvements is calculated using the straight-line method over the estimated life of the asset or the life of the lease, if shorter. c) Reserve Estimates All of the Company s oil and gas reserves are evaluated and reported on by independent qualified reserve evaluators. Reserve estimates can have a significant impact on net income and the carrying value of capital assets. The process of estimating reserves requires significant judgment based on available geological, geophysical, engineering, and economic data, projected rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to interpretation and uncertainty. Reserve estimates impact net earnings through depletion expense and the application of impairment tests. Revisions or changes in reserve estimates can have either a positive or negative impact on net income and can impact the carrying amounts of capital assets. d) Asset Retirement Obligations The Company recognizes the estimated fair value of future retirement obligations associated with capital assets as a liability. The Company estimates the liability based on the estimated costs to abandon and reclaim its net ownership in tangible long-lived assets such as wells and facilities and the estimated timing of the costs to be incurred in future periods. Actual payments to settle the obligations may differ from estimated amounts. e) Revenue recognition Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized when the commodities are delivered and title passes to the customer. Revenues associated with the sale of crude oil, natural gas and natural gas liquids are recorded gross of royalties. f) Stock-based Compensation The Company has a share option plan and uses the fair value method of accounting for all stockbased awards to non-employees and employees, including those that are direct awards of stock. Under the fair value method, employee compensation expense attributed to direct awards of stock is measured at the fair value of the award at the grant date using the Black-Scholes optionpricing model and is recognized over the vesting period of the award. If and when the stock options are ultimately exercised, the applicable amounts of contributed surplus are credited to share capital. Option pricing models require the input of highly subjective assumptions regarding the expected volatility. Changes in assumptions can materially affect the fair value estimate, and therefore, the existing models do not necessarily provide a realistic measure of the fair value of the Company s stock options at the date of the grant or thereafter. During 2008, the Company introduced a cash-settled stock appreciation rights ( SARs ) plan; the Company awarded SARs in 2009 under this plan. The compensation cost for SARs granted to employees under this plan is accounted for using the intrinsic value method. Under this method, the Company accrues a liability for the SARs on the excess of the market price of the Company s common stock over the price of the SARs granted. The accrued liability is adjusted at each balance sheet date for the effect of SARs grants, vesting of SARs, SARs exercised, as well as the effect of changes in the underlying price of the Company s common shares. The net effect of these items is charged or credited to compensation expense and to the extent allocable, production expense and capitalized costs. Management s Discussion and Analysis 23

27 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) g) Income Taxes Future income taxes are recorded using the asset and liability method. Under the asset and liability method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future tax assets and liabilities are measured using the substantively enacted tax rates expected to apply when the asset is realized or the liability settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period that substantive enactment occurs. To the extent that the Company does not consider it more likely than not that a future tax asset will be recovered, it provides a valuation allowance against the excess. New Accounting Pronouncements The Company has adopted new accounting standards that were issued by the Canadian Institute of Chartered Accountants ( CICA ). The new standards and accounting policy changes and their effect on the Company s financial statements are discussed in Note 3 to the Consolidated Financial Statements. Also discussed in Note 3 are new accounting standards which will be adopted in future periods in accordance with the respective standard. International Financial Reporting Standards Update In February 2008, the Canadian Accounting Standards Board ( AcSB ) confirmed the convergence of Canadian GAAP with International Financial Reporting Standards ( IFRS ) will be required for interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011, including comparatives for 2010 for Canadian profit-oriented publicly accountable entities ( PAE s ) such as the Company. This also means that all opening balance sheet adjustments relating to the adoption of IFRS must be reflected in the January 2010 opening balance sheet which will be issued as part of the comparative financial information in the March 31, 2011 unaudited interim financial statements. The Company intends to adopt these requirements as set out by the AcSB and other regulatory bodies. The Company has established a project team that is led by its financial management, and includes representatives from various other areas of its organization to plan for and achieve a smooth transition to IFRS. External resources have also been engaged to assist under the direction of Company management with certain aspects of the project. The Audit Committee and the Company auditors are regularly updated as to the status of the IFRS implementation project. The implementation project consists of three primary phases: Phase 1 Initial Scoping and Diagnostic; Phase 2 Detailed Assessment and Design; and Phase 3 Implementation and Review. The Company has completed phase 1 and is now into phase 2. These phases are further broken down into key elements which are summarized in the following table. Management s Discussion and Analysis 24

28 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Key Activities Milestones Status Accounting Policies and Procedures: Identify differences between IFRS and the Company s existing policies and procedures Analysis and select ongoing policies where alternatives are permitted Analysis and determine which IFRS 1 exemptions will be taken upon transition to IFRS Implement provisions to accounting and procedures manuals Financial Presentation Preparation: Prepare financial statements and note disclosures in compliance with IFRS Quantify the effects of converting to IFRS Prepare first-time adoption reconciliations required under IFRS 1 Training and Communication: Provide topic specific training to key employees involved with implementation Develop awareness of the likely impacts of the transition throughout the Company Provide Company specific training on revised policies and procedures to affected personnel Provide timely communication of the impacts of converting to IFRS to our external stakeholders Senior management approval and audit committee review by Q Revised accounting policy and procedures manuals in place in Q Senior management approval and Audit Committee review of pro forma financial statements and disclosures by Q and Q4 2010, respectively In depth IFRS training provided to IFRS team members and key financial management Topic specific training for IFRS provided as work progresses on each IFRS topic Company specific training implemented prior to changeover date Impact of IFRS conversion to be communicated to external stakeholders prior to changeover White papers are being drafted on each specific area of the Company s financial statements and accounting policy recommendations are being drafted Key accounting policy decisions are expected to be approved by senior management and reviewed by the Audit Committee in Q Development of financial statement format has not yet started Preparation of draft note disclosures has not yet started The effects of the conversion will be quantified as each work stream progresses Key financial management and IFRS team members have completed in depth training Training modules have been made available to all financial employees on IFRS topic basis Company specific training will be developed as each work stream progresses Communication to external stakeholders has been ongoing though our MD&A disclosures. These disclosures will provide further details as we identify the impacts of the transition Management s Discussion and Analysis 25

29 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Key Activities Milestones Status Business Impacts: Identify impacts of conversion on contracts, including financial covenants and compensation arrangements Impacts on contracts identified by Q Taxation impacts identified by Q Identify impacts of conversion on taxation IT Systems: Identify changes required to IT systems and implement solutions Determine and implement solution for capturing financial information under Canadian GAAP, IFRS during the year of transition to IFRS (for comparative information) Control Environment: For all changes to policies and procedures identified, assess effectiveness of internal controls over financial reporting ( ICFR ) and disclosure controls and procedures ( DC&P ) and implement necessary changes, if any Design and implement internal controls over the IFRS changeover process Perform a needs assessment and identify needs in the Company s current IT systems by Q Ascertain a solution for capturing financial information under multiple sets of GAAP by Q Implement necessary changes to IT system by changeover date Senior Management is reviewing ICFR and DC&P and sign-off on effectiveness of these by Q Internal controls over IFRS changeover project in place by Q Identification of material contracts completed. Evaluation of impact on these contracts is in progress. Adoption of IFRS is not expected to have a material impact on the Company s contracts The Company has employed an external taxation resource to assist with this analysis and this work stream has just started Completed needs assessment and recommended changes to IT systems in Q Implemented new IT system during Q and running parallel system through Q Additional information gathering solutions are being developed as each work stream progresses Relevant internal controls are being assess and signed off on as each work stream progresses Specific controls have been established and documented in relation to the IFRS changeover project Many of the differences identified between IFRS and Canadian GAAP are not expected to have a material impact on our reported results and financial position. However, there may be significant changes as a result of IFRS accounting principles and provisions for first-time adoption. The Company has not yet determined the full accounting effects of adopting IFRS, since some key accounting policies alternatives and implementation decisions are still being evaluated. However the Company does not expect the adoption of IFRS to materially impact the underlying cash flows, profitability, trends in our operating performance, debt covenants or compensation arrangements. Management s Discussion and Analysis 26

30 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Most adjustments required on transition to IFRS will be made, retrospectively, against opening retained earnings as of the date of the first comparative balance sheet presented based on standards in effect at December 31, Transitional adjustments relating to those standards where comparative figures are not required to be restated will only be made prospectively as of the first day of the year of adoption. First-time adopters of IFRS The transition to IFRS requires the Company to apply IFRS 1, which prescribes requirements for preparing IFRS-compliant financial statements in the first reporting period after the changeover date (January 1, 2010). IFRS 1 includes a requirement for retrospective application of each IFRS as if they were always in effect. IFRS 1 also mandates certain exceptions for retrospective application and provides optional exemptions from retrospective application to ease the transition to IFRS in the transition year. In July 2009, the International Accounting Standards Board approved amendments and released additional exemptions to IFRS 1 Additional Exemptions for First-time Adopters which prescribes transitional exemptions for oil and gas companies following full cost accounting. The amendment allows an entity that used full cost accounting under its previous GAAP to elect, at its time of adoption, to measure exploration and evaluation assets at the amount determined under the entity s previous GAAP and to measure oil and natural gas assets in the development or production phases by allocating the amount determined under the entity s previous GAAP for those assets, to the underlying assets pro rata using reserve volumes or reserve values as of the date of transition, subject to an impairment test as prescribed under IFRS. This exemption will allow the Company to apply IFRS to its full cost pools on a prospective basis, from date of transition to IFRS. The Company is analyzing the various accounting policy choices available and will implement those determined to be most appropriate in our circumstances. We expect that key IFRS 1 exemption decisions will be approved by senior management and reviewed by the Audit Committee during Q The most significant IFRS1 exemptions for the Company are summarized in the follow table. Area of IFRS Business Combinations Property, Plant and Equipment Summary of Exception Available The Company may elect, on transition to IFRS, to either restate all past business combinations or to apply a more limited restatement approach. If a limited restatement approach is chosen, specific requirements must be met, such as maintaining the classification of the acquirer and the acquiree, recognizing or derecognizing certain acquired assets or liabilities as required under IFRS and remeasuring certain asset and liabilities at fair value. The Company may elect to report items of property, plant and equipment in its opening balance sheet on the transition date at a deemed cost instead of the actual cost that would be determined under IFRS. The deemed cost of an item may be either its fair value at the date of transition to IFRS or an amount determined by a previous revaluation under Canadian GAAP (as long as that amount was close to either its fair value or adjusted cost). The exemption can be applied on an asset-by-asset basis. Management s Discussion and Analysis 27

31 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Decommissioning In accounting for changes in obligations to dismantle, remove and Liabilities restore items of property, plant and equipment, the guidance in IFRS requires changes in such obligations to be added to or deducted from the cost of the asset to which it relates. The adjusted depreciable amount of the asset is then depreciated prospectively over its remaining useful life. Rather than recalculating the effect of all such changes throughout the life of the obligation, the Company may elect to measure the liability and the related depreciation effects at the date of transition to IFRS. Leases The Company may elect to not apply retroactively IFRIC 4 Determining whether an arrangement contains a lease. This allows the Company to determine at the date of transition whether an arrangement contains a lease based on the facts and circumstances at that date rather than the inception of the arrangement. In addition, the exemption allows a first-time adopter to not reassess its previous determination as to whether an arrangement contains a lease under Canadian GAAP if that previous determination would have given the same outcome under IAS 17 and IFRIC 4. Assets and liabilities of subsidiaries, associates and joint ventures Financial instruments designation Borrowing costs Compound financial instruments If a parent entity becomes a first-time adopter later than its subsidiary, the parent will in its consolidated financial statements, measure the assets and liabilities of its subsidiary, after adjusting for consolidation and equity accounting adjustments and for the effect of business combination in which the entity acquired the subsidiary. A similar election is available to a joint venture or associate that becomes a first-time adopter later than an entity that has joint control or significant influence over it. This election will allow the Company to review its financial instruments designations under Canadian GAAP and change these designations at the date of transition so long as the designation conforms to IAS 39. The Company may elect to apply IAS 23 (revised) Borrowing costs relating to qualifying assets for which the commencement date for capitalization is on or before the date of transition, and apply the Standard to borrowing costs related to all qualifying assets for which the commencement date for capitalization is on or after that date. The Company may elect to not split a compound financial instrument into separate liability and equity portions if the liability component is no longer outstanding at the date of transition. Without this election, IAS 32 Financial Instruments: Presentation would require the Company to retroactively apply this analysis to all financial instruments retrospectively and split the impact of previous financial instruments into two separate components of equity. Management s Discussion and Analysis 28

32 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Expected Areas of Significance The key areas where changes in accounting policies are expected that may impact the Company s consolidated financial statements (include: a) accounting for property, plant & equipment (PP&E), including exploration costs, b) depletion and depreciation, c) impairment testing, d) capitalized interest, e) asset retirement obligations and f) share-based payments) The list and related comments should not be regarded as a complete list of changes that will result from the Company s transition to IFRS. It is intended to highlight those areas we believe to be the most significant; however, our analysis of possible changes is still in process and not all decisions have been made where choices of accounting policies are available. We note that the standard-setting bodies that promulgate Canadian GAAP and IFRS have significant on-going projects that could affect differences between Canadian GAAP and IFRS and their impact on the Company s consolidated financial statements in future years. In particular, we expect that there may be additional new or revised IFRS in relation to consolidation, income taxes liabilities, discontinued operations, related party disclosures, financial instruments, employee benefits and joint ventures. We have processes in place to ensure that such potential changes are monitored and evaluated. The future impact of IFRS will also depend on the particular circumstances prevailing in those years. The differences described are those existing based on Canadian GAAP and IFRS today. Until our adoption is finalized, the Company is not able to reliably quantify the impacts expected on our consolidated financial statements for those differences. We expect to disclose our significant accounting policy choices as they are being made. Risks and Uncertainties Coastal has published its assessment of its business risks in the Risk Factor section of its Annual Information Form ( AIF ) dated April 16, 2010 (available on SEDAR at It is recommended that this document be reviewed for a thorough discussion of risks faced by the Company. The Company is subject to a number of risk factors due to the nature of the petroleum and gas business in which it is engaged, not the least of which are adverse movements in commodity prices, which are impossible to forecast. The Company is also subject to the oil and gas services sector which, at the present, has limited available capacity and therefore may demand premium rates. The Company seeks to counter these risks as far as possible by selecting exploration areas on the basis of their recognized geological potential to host economic returns. a) Industry The Company is engaged in the acquisition of petroleum and natural gas properties, an inherently risky business, and there is no assurance that an additional economic petroleum and natural gas deposit will ever be discovered and subsequently put into production. Most exploration projects do not result in the discovery of commercially viable petroleum and natural gas deposits. The geological focus of the Company is on areas in which the geological setting is well understood by management. Management s Discussion and Analysis 29

33 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) b) Petroleum and Gas Prices In recent years, the petroleum and natural gas exploration industry has seen significant growth, primarily as a result of increased global demand, led by India and China. During this period, prices for petroleum have steadily increased, resulting in multi-year price highs. Prior to this recent surge, large companies found it more feasible to grow their reserves and resources by purchasing companies or existing oilfields. However, with improving prices and increasing demand, a discernible need for the development of exploration projects has arisen. Junior companies have become key participants in identifying properties of merit to explore and develop. The price of petroleum and natural gas is affected by numerous factors beyond the control of the Company including global consumption and demand for petroleum and natural gas, international economic and political trends, fluctuations in the U.S. dollar and other currencies, interest rates, and inflation. Continued volatility in commodity prices may adversely effect the Company s operating cash flow. c) Operating Hazards and Risks Exploration for natural resources involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. Operations in which the Company has a direct or indirect interest will be subject to all the hazards and risk normally incidental to exploration, development and production of natural resources, any of which could result in work stoppages, damages to persons or property and possible environmental damage. Although the Company may obtain liability insurance in an amount which is expected to be adequate, the nature of these risks is such that liabilities might exceed policy limits, the liabilities and hazards might not be insurable, or the Company might not to elect to insure itself against such liabilities due to the high premium costs or other reasons, in which event the Company could incur significant costs that could have a material adverse effect upon its financial condition. d) Reserve Estimates Despite the fact that the Company has reviewed the estimates related to potential reserve evaluation and probabilities attached thereto and it is of the opinion that the methods used to appraise its estimates are adequate, these figures remain estimates, even though they have been calculated or validated by independent appraisers. The reserves disclosed by the Company should not be interpreted as assurances of property life or of the profitability of current or future operations given that there are numerous uncertainties inherent in the estimation of economically recoverable oil and natural gas reserves. e) Disruptions in Production Other factors affecting the production and sale of oil and natural gas that could result in decrease of profitability include: (i) expiration or termination of leases, permits or licenses, or sales price redeterminations or suspension of deliveries; (ii) future litigation; (iii) the timing and amount of insurance recoveries; (iv) work stoppages or other labor difficulties; (v) worker vacation schedules and related maintenance activities; and (v) changes in the market and general economic conditions. Weather conditions, equipment replacement or repair, fires, amounts of rock and other natural materials and other geological conditions can have a significant impact on operating results. Management s Discussion and Analysis 30

34 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) f) Cash Flows and Additional Funding Requirements The Company presently has revenue from its Gulf of Thailand production and earnings from its interest in Apico, which is accounted for under the equity method on the consolidated statement of operations. In order to further develop the Gulf of Thailand assets, substantial capital will be required. The sources of capital presently available to the Company for development are cash flow from production or the issuance of debt or equity. The Company has sufficient financial resources to undertake its firm obligations for the next 12 months. The Company is exposed to fluctuations in short-term interest rates on amounts drawn under its revolving credit facilities. The Company has not hedged these rates given the need to remain flexible in borrowing and repaying the outstanding balances. g) Environmental The Company s exploration activities are subject to extensive laws and regulations governing environmental protection. Although the Company closely follows and believes it is operating in compliance with all applicable environmental regulations, there can be no assurance that all future requirements will be achievable on reasonable terms. Failure to comply may result in enforcement actions causing operations to cease or be curtailed and may include corrective measures requiring capital expenditures. h) Laws and Regulations The Company s exploration activities are subject to local laws and regulations governing prospecting, drilling, development, exports, taxes, labour standards, occupational health and safety, and other matters. Such laws and regulations are subject to change, can become more stringent and compliance can therefore become more costly. There are also many risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil and natural gas taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations. These risks include: political and economic instability or war; the possibility that a foreign government may seize our property with or without compensation; confiscatory taxation; legal proceedings and claims arising from our foreign investments or operations; a foreign government attempting to renegotiate or revoke existing contractual arrangements, or failing to extend or renew such arrangements; fluctuating currency values and currency controls; and constrained natural gas markets dependent on demand in a single or limited geographical area. The Company applies the expertise of its management, its advisors, its employees and contractors to ensure compliance with current local laws. i) Title to Oil and Gas Properties While the Company has undertaken customary due diligence in the verification of title to its oil and gas properties, this should not be construed as a guarantee of title. The properties may be subject to prior unregistered Petroleum Agreements or transfers and title may be affected by undetected defects. j) Dependence on Management The Company strongly depends on the business and technical expertise of its senior management team and there is little possibility that this dependence will decrease in the near term. The loss of one or more of these individuals could have a material adverse effect on the Company. Management s Discussion and Analysis 31

35 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) k) Apico Financial Reporting The Company accounts for its 36.1% investment in Apico under the equity method whereby it records its share of Apico s earnings as earnings from a significantly influenced investee. Apico is required to provide the partners its financial statements under the Joint Venture Agreement on a timely basis. While the Company has a seat on the Board of Directors of Apico, it does not control the Board or the management of Apico. Therefore, the Company relies heavily on Apico management to provide timely and accurate financial information to the partners. Risk Management and Financial Instruments Coastal provides a risk management and financial instruments discussion as required by CICA handbook section 3862 Financial Instruments Disclosures on its exposure to and management of credit risk, liquidity risk and market risk in Note 17 to the audited financial statements as at and for the period ended December 31, 2009 and Management s Report on Internal Control over Financial Reporting In connection with Exemption Orders issued in November 2007 and revised in December 2008 by each of the securities commissions across Canada, the Chief Executive Officer and Chief Financial Officer of the Company will file a Venture Issuer Basic Certificate with respect to the financial information contained in the unaudited interim financial statements and the audited annual financial statements and respective accompanying Management s Discussion and Analysis. In contrast to the certificate under National Instrument ( NI ) (Certification of Disclosure in Issuer s Annual and Interim Filings), the Venture Issuer Basic Certification does not include representations relating to the establishment and maintenance of disclosure controls and procedures and internal control over financial reporting, as defined in NI Outlook The Company plans to continue operating its current Gulf of Thailand properties as well as pursuing additional development and exploration of its current concessions. Coastal anticipates using the proceeds from its current production at Songkhla and Sinphuhorm to enhance its liquidity position and fund further development and exploration of Blocks G5/43 and G5/50. Management s Discussion and Analysis 32

36 33

37 To the Shareholders of Coastal Energy Company: We have audited the consolidated balance sheets of Coastal Energy Company as at December 31, 2009 and 2008 and the consolidated statements of operations, comprehensive loss and deficit and cash flows for the years then ended. These financial statements are the responsibility of the Company s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2009 and 2008 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles. (signed) Deloitte & Touche LLP Calgary, Alberta April 16, 2010 Chartered Accountants Auditors Report 34

38 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE LOSS AND DEFICIT $ $ Revenues Oil and natural gas 86,348 4,098 Royalties (5,878) (214) (Loss) gain on derivative (Note 13) (2,077) 2,447 Interest income Other income ,530 7,313 Expenses and other Production 33,477 1,597 General and administrative 19,576 12,824 Foreign exchange loss 1,941 3,869 Interest 3,839 2,146 Debt financing fees (Note 12) 1,454 - Depletion, depreciation and accretion 23,695 1,893 Settlement (Note 8) 2,366 - Loss (gain) on sale of assets 148 (217) 86,496 22,112 Net loss before taxes, earnings from significantly influenced investee and non-controlling interest (7,966) (14,799) Income taxes (Note 18) Net loss before earnings from significantly influenced investee and non-controlling interests (8,704) (15,465) Earnings from significantly influenced investee (Note 7) 8,462 12,904 Net loss before non-controlling interests (242) (2,561) Non-controlling interest (Note 4) Net loss and comprehensive loss (115) (2,561) Deficit, beginning of year (16,587) (14,026) Deficit, end of year (16,702) (16,587) Basic and diluted loss per share (Note 15) 0.00 (0.03) Weighted average number of common shares outstanding 98,243,701 93,262,551 See Accompanying Notes to the Consolidated Financial Statements 35

39 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) CONSOLIDATED BALANCE SHEETS December 31, December 31, $ $ Assets Current assets Cash and cash equivalents 21,229 6,434 Restricted cash (Note 5) 3,829 4,146 Accounts receivable and other (Note 6) 6,111 2,391 Derivative asset (Note 13) 66 2,016 Crude oil inventory 5, Prepaids and other current assets ,071 15,566 Investment in and advances to Apico LLC (Note 7) 55,225 50,376 Property, plant and equipment, net (Note 8) 233, ,224 Other long-term assets Total Assets 325, ,463 Liabilities Current liabilities Accounts payable and accrued liabilities (Note 9) 31,325 35,536 Deferred income (Note 10) 23,060 - Income taxes payable (Note 18) 38 1,252 Amounts due to shareholder (Note 11) 5,164 6,761 Current portion of long-term debt (Note 13) 10,266 15,249 69,853 58,798 Long-term debt (Note 13) 24,284 28,751 Asset retirement obligations (Note 14) 2,809 1,354 Future income tax liability (Note 18) 27,695 25,984 Total Liabilities 124, ,887 Commitments and contingencies (Note 19) Non-controlling interests (Note 4) 5,617 - Shareholders' equity Share capital (Note 15) 198, ,938 Contributed surplus (Note 15) 13,779 13,225 Warrants (Note 15) Deficit (16,702) (16,587) 195, , , ,463 Approved by the Board /s/ Randy Bartley Randy L. Bartley, Director /s/ Benard de Combret Benard de Combret, Chairman See Accompanying Notes to the Consolidated Financial Statements 36

40 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) CONSOLIDATED STATEMENTS OF CASH FLOWS $ $ Operating activities Net loss for the year (115) (2,561) Earnings distributions from significantly influenced investee 8,129 16,619 Items not involving cash Depletion, depreciation and accretion 23,695 1,893 Impairment 1,765 Future income taxes 700 (1,818) Unrealized foreign exchange (loss) gain 909 (751) Loss applicable to non-controlling interest (127) - Stock based compensation 8,021 2,080 Issurance of warrants with notes payable Share of earnings of significantly influenced investee, net of taxes (8,462) (12,904) Unrealized (gain) loss on derivative instrument 1,950 (2,015) (Gain) loss on sale of assets 148 (217) Change in non-cash working capital (Note 20) 17,095 2,016 Cash provided by operating activities of continuing operations 54,002 2,342 Investing activities Investment in and advances to Apico LLC (4,516) (903) Increase in restricted cash 317 (2,098) Purchase of property, plant and equipment (77,671) (82,645) Proceeds from sale of property and equipment - 1,053 Proceeds from non-controlling interest 5,744 - Acquisition of other long-term assets (2) (241) Cash used in investing activities (76,128) (84,834) Financing activities Issuance of shares for cash 52,306 55,119 Transaction costs associatd with issuance of shares (2,984) (245) Borrowings under long-term debt 1,620 45,000 Repayments under long-term debt (11,070) (26,000) Borrowings under notes payable 15,000 - Repayments under notes payable (15,000) - Borrowings under amounts due to shareholder 1,000 2,000 Repayments under amounts due to shareholder (3,000) Cash provided by financing activities 37,872 75,874 Net effect of foreign exchange on cash held in foreign currencies (951) (97) Change in cash and cash equivalents 14,795 (6,715) Cash and cash equivalents, beginning of year 6,434 13,149 Cash and cash equivalents, end of year 21,229 6,434 Cash and cash equivalents consists of: Cash 21,229 5,606 Short-term money market instruments ,229 6,434 Supplemental cash flow information (Note 20) See Accompanying Notes to the Consolidated Financial Statements 37

41 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 1. Nature of operations Coastal Energy Company ( Coastal or the Company ) was incorporated on May 26, 2004 in the Cayman Islands. Coastal is a public company listed on the TSX Venture Exchange and the London AIM Exchange. The Company is involved in the exploration, development and production of crude oil in Thailand. These consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles ( GAAP ) as described in Note 2. Note 2. Significant accounting policies Basis of consolidation These consolidated financial statements include the accounts of the Company and all its subsidiaries. All significant inter-company transactions and balances have been eliminated. Variable interest entities ( VIE s ), which include, but are not limited to, special purpose entities, trusts, partnerships, and other legal structures, as defined by Canadian Institute of Chartered Accountants ( CICA ) Accounting Guideline 15, Consolidation of Variable Interest Entities, are subject to consolidation by the primary beneficiary who will absorb the majority of the entities expected losses and/or expected residual returns. The Company is a primary beneficiary in Viking Storage Solutions (Mauritius) Limited and has consolidated this entity. See Note 4. Measurement uncertainty The preparation of financial statements in accordance with Canadian GAAP necessitates the use of estimates when transactions affecting the current accounting period cannot be finalized until future periods. These estimates will affect assets, liabilities and the disclosures of contingent assets and liabilities at the date of the financial statements, as well as revenues and expenses during the reporting period. Such estimates are based on informed judgments made by management. Actual results could differ materially from those estimates. Amounts recorded for depletion, depreciation, asset retirement obligations and amounts used for ceiling test calculations are based on estimates of oil and natural gas reserves which include estimates of future commodity prices, future costs, inflation, timing of future costs and abandonments, as well as other relevant assumptions. The Company s reserves are estimated and evaluated, at a minimum, annually by an independent engineering firm. By their very nature, these estimates of reserves and the related cash flows are subject to measurement uncertainty. Changes in these estimates could materially impact the financial statements of future periods. Derivative instruments classified as held-for-trading are recorded at fair value at each reporting date. These fair value amounts are subject to measurement uncertainty. Income tax balances are based on estimates formulated by informed management judgments; actual settlement of taxes may differ from those estimates. Stockbased compensation is based upon volatility and expected life estimates that are also subject to measurement uncertainty. Cash and cash equivalents Cash and cash equivalents consists of cash and highly liquid investments with original maturities of three (3) months or less. Investments Investments in companies where the Company has the ability to exercise significant influence, which are generally where the Company has voting interests of 20% to 50%, are accounted for using the equity method. Under this method, the Company s share of the investees earnings and losses is included in operations and its investments therein are adjusted by a like amount. Dividends received are credited to the investment accounts. Notes to the Consolidated Financial Statements 38

42 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 2. Significant accounting policies (continued) Inventory Inventory consists of crude oil in storage at the balance sheet date and is valued at the lower of cost, using the weighted average cost method, or net realizable value. Costs include direct and indirect expenditures incurred in bringing the crude oil to its existing condition and location. Property, plant and equipment (a) Capitalized costs The Company follows the full cost method of accounting whereby all costs relating to the exploration, acquisition and development of oil and gas reserves are capitalized. Such costs include land and lease acquisition costs, annual charges on non-producing properties, geological and geophysical costs, and costs of drilling and equipping productive and non-productive wells. The Company does not capitalize indirect general and administrative overhead nor does it capitalize interest costs. Proceeds from the sale of oil and gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would alter the rate of depletion and depreciation by 20% or more. (b) Depletion and depreciation Capitalized costs are accumulated in cost centres on a country-by-country basis. As of December 31, 2009, the Company had one cost centre, Thailand. Depletion and depreciation of oil and gas properties and equipment together with the estimated future costs to be incurred (other than future major development items such as production platforms) in developing proved reserves, are depleted or depreciated using the units of production method based on the proved reserves before royalties as estimated by independent engineers. Oil and gas reserves and production are converted into equivalent units based upon estimated relative energy content of six thousand cubic feet of gas to one barrel of oil (6 mcf = 1 bbl). The costs of undeveloped properties are excluded from the costs subject to depletion and depreciation until it is determined whether proved reserves are attributable to the properties or impairment occurs. The impairment test is performed on an annual basis. However, where information arises that indicates an impairment review is warranted, additional tests may also be taken during the course of the year. In addition, certain major components of production equipment (such as a floating storage and off-loading vessel FSO ) have a life that is longer than the specific field to which it is currently assigned. These major production components are depreciated on a straight line basis over the estimated useful life of the asset, which approximates the estimated production life of the Company s Gulf of Thailand concessions. Depreciation of office equipment, furniture and fixtures and leasehold improvements is calculated using the straight-line method over the estimated life of the asset or the life of the lease, if shorter. The periods over which the Company s non-oil and gas assets are depreciated are as follows: - Furniture and fixtures 10 years - IT hardware and software 4 years - Leasehold improvements 3 years - Office equipment 10 years (c) Capitalization of costs and construction in progress Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Assets under construction are not subject to depreciation until they are put into use. Maintenance and repair costs are expensed as incurred. Notes to the Consolidated Financial Statements 39

43 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 2. Significant accounting policies (continued) (d) Impairment The Company assesses the carrying value of its property, plant and equipment for impairment annually or as circumstances dictate. Impairment is indicated when the carrying value of a cost centre exceeds the estimated undiscounted future net cash flows associated with the cost centre s proved reserves. Cash flows are calculated using expected future product prices and costs and are discounted using a risk-free interest rate. Any impairment is measured as the excess of the carrying amount over the estimated discounted future net cash flows associated with the Company s proved and probable reserves. Reserves are determined pursuant to Canadian Securities Administrators National Instrument , Standards of Disclosure of Oil and Gas Activities. Costs relating to undeveloped properties are subject to individual impairment assessments until it can be determined whether or not proved reserves exist. If impairment is determined to exist, the costs carried on the balance sheet in excess of the discounted future net cash flows associated with the cost centre s proved plus probable reserves are charged to earnings in the period the impairment occurs. Asset retirement obligation The Company recognizes the estimated fair value of future retirement obligations associated with property, plant and equipment as a liability in the period in which they are incurred, normally when the asset is purchased or developed. The fair value is capitalized and amortized over the same period as the underlying asset. The Company estimates the liability based on the estimated costs to abandon and reclaim the wells and well sites. Only wells and well sites that the Company has constructed, drilled, completed workovers on, or performed enhancements to, are included in the estimate. This estimate is evaluated on a periodic basis and any adjustment to the estimate is applied prospectively. The change in net present value of the future retirement obligation due to the passage of time is expensed as accretion. Actual retirement obligations settled during the period reduce the asset retirement liability. Revenue recognition Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized when the commodities are delivered and title passes to the customer. Revenues associated with the sale of crude oil, natural gas and natural gas liquids are recorded gross of royalties, transportation and marketing charges. Income per share The basic income per share is computed by dividing the net income for the year by the weighted average number of common shares outstanding during the year. The diluted income per share reflects the potential dilution of common share equivalents, such as outstanding stock options and warrants, in the weighted average number of common shares outstanding during the year, if dilutive. For this purpose, the treasury stock method is used for the assumed proceeds upon the exercise of stock options and warrants that are used to purchase common shares at the average market price during the year. Income taxes Future income taxes are recorded using the liability method. Under the liability method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future tax assets and liabilities are measured using substantively enacted tax rates expected to apply when the asset is realized or the liability settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period that substantive enactment occurs. To the extent that the Company does not consider it more likely than not that a future tax asset will be recovered, it provides a valuation allowance against that future income tax asset. Notes to the Consolidated Financial Statements 40

44 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 2. Significant accounting policies (continued) Stock-based compensation The Company has a share option plan as described in Note 15. The Company uses the fair value method of accounting for all stock-based awards to non-employees and employees, including those that are direct awards of stock. Under the fair value method, employee compensation expense attributed to direct awards of stock is measured at the fair value of the award at the grant date using the Black- Scholes option-pricing model and is recognized over the vesting period of the award. If and when the stock options are ultimately exercised, the applicable amounts of contributed surplus are credited to share capital. During 2008, the Company introduced a cash-settled stock appreciation right plan. The Company began awarding stock appreciation rights ( SARs ) under this plan during the year ended December 31, The compensation cost for SARs granted to employees under this plan is accounted for using the intrinsic value method. Under this method, the Company accrues a liability for the SARs on the excess of the market price of the Company s common shares over the price of the SARs granted. The accrued liability is adjusted at each balance sheet date for the effect of SAR grants, vesting of SARs, SARs exercised, as well as the effect of changes in the underlying price of the Company s common shares. The net effect of these items is charged or credited to compensation expense. Foreign currency translation The United States dollar is the functional currency of the Company and its subsidiaries. The Company translates foreign currency denominated monetary assets and liabilities of its integrated foreign subsidiaries at the exchange rate in effect at the balance sheet date and non-monetary assets and liabilities are translated at historical exchange rates. Revenues and expenses are translated at estimated transaction date exchange rates except depletion and depreciation expense, which is translated at the same historical rates as the related assets. Exchange gains or losses are included in the determination of net income as other items. Monetary assets and liabilities denominated in a currency other than the US dollar are translated at the rates of exchange in effect at the balance sheet date while revenues and expense are translated at transaction date exchange rates. Exchange gains and losses are included in determination of net income as foreign exchange gain or loss. Financial instruments Financial instruments are measured at fair value on initial recognition of the instrument, except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, available-for-sale, held-to-maturity, loans or receivables, or other financial liabilities. Financial assets and financial liabilities held-for-trading are measured at fair value with changes in those fair values recognized in net earnings. Financial assets available-for-sale are measured at fair value, with changes in those fair values recognized in Other Comprehensive Income ( OCI ). Financial assets heldto-maturity, loans and receivables, and other financial liabilities are measured at amortized cost using the effective interest method of amortization. Cash and cash equivalents and restricted cash are designated as held-for-trading. Accounts receivable and other are designated as loans and receivables. Accounts payable and accrued liabilities, amounts due to shareholder, and long-term debt are designated as other financial liabilities. The Company has a derivative agreement (Note 13) which has been classified as held-for-trading and as such is measured at fair value at the balance sheet date with the resulting change in value recognized in net earnings for the related period. The Company does not apply hedge accounting. The Company expenses debt financing costs when they are incurred Notes to the Consolidated Financial Statements 41

45 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 2. Significant accounting policies (continued) Joint interests Certain of the Company s exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company s proportionate interest in such activities. Amounts due from (to) joint interest partners arise from the timing of the receipt of funds from cash calls made by the Company or the joint interest partners together with the timing of exploration activities. Comparative figures Previously, the Company presented its income taxes using the income tax rate for the Cayman Islands, which is 0% as its statutory tax rate. Because the majority of the Company s operations are in Thailand, the Company now uses the Thailand petroleum income tax rate of 50% as its statutory tax rate. The 2008 income taxes have been recalculated based on the 50% statutory tax rate to conform to the current year presentation in Note 18. This recalculation has no impact to the Company s 2008 income tax expense or to the future net tax liability at December 31, Note 3. Changes in accounting policies Effective January 1, 2009, the Company has adopted new accounting standards that were issued by the Canadian Institute of Chartered Accountants ( CICA ). The new standards and accounting policy changes are as follows: Goodwill and Other Intangibles (CICA Handbook Section 3064) On January 1, 2009 the Company adopted the Canadian Institute of Chartered Accountants ( CICA ) Handbook Section 3064, Goodwill and Intangible Assets. The new section replaces the previous goodwill and intangible asset standard and revises the requirement for recognition, measurement, presentation and disclosure of intangible assets. The adoption of this standard had no impact on the Company s consolidated financial statements. Credit Risk and Fair Value of Financial Assets and Liabilities (CICA EIC-173) On January 1, 2009, the Company adopted the CICA s EIC-173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities. The EIC provides guidance on how to take into account credit risk of an entity and counterparty when determining the fair value of financial assets and financial liabilities, including derivative instruments. The adoption of this EIC had no significant impact on the Company s consolidated financial statements. Financial Instruments Recognition and Measurement (CICA Handbook section 3855) During 2009, the Company adopted the CICA amendments to section 3855, Financial Instruments Recognition and Measurement, in relation to the impairment of financial assets. Amendments to this section have revised the definition of loans and receivables and provided that certain conditions have been met, permits reclassification of financial assets from the held-for-trading and available-for-sale categories into the loans and receivables category. The amendments also provide one method of assessing impairment for all financial assets regardless of classification. These amendments are effective for the Company s annual financial statements relating to its fiscal year beginning on January 1, 2009; however, the Company has voluntary elected to apply these amendments to its September 30, 2009 interim financial statements as permitted by the transitional provisions of the amendments. The adoption of the amendments to this standard did not have an impact on the Company s financial statements. Financial Instruments Disclosures (CICA Handbook section 3862) Effective December 31, 2009, the Company adopted the CICA amendments to section 3862, Financial Instruments Disclosures. The amendments include enhanced disclosures related to the fair value of financial instruments and the liquidity risk associated with financial instruments. Section 3862 now requires that all financial instruments measured at fair value be categorized into one of three hierarchy levels. The amendments are consistent with recent amendments to financial instrument disclosure standards in IFRS. Notes to the Consolidated Financial Statements 42

46 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 3. Changes in accounting policies (continued) Recent and Pending Accounting Pronouncements In January 2009, the CICA issued Section 1582, Business Combinations, which will replace the former guidance on business combinations. Under the new standard, the purchase price used in a business combination is based on the fair value of consideration exchanged at the date of exchange. Currently the purchase price used is based on the fair value of the consideration for a reasonable period before and after the date of acquisition is agreed upon and announced. The new standard generally requires that acquisition costs be expensed, which are currently capitalized as part of the purchase price. In addition, the new standard modified the accounting for contingent consideration and negative goodwill. Section 1582 is effective for the Company on January 1, 2011 with prospective application and early adoption permitted. Once adopted, this standard will impact the accounting treatment of future business combinations. In January 2009, the CICA issued Sections 1601, Consolidated Financial Statements, and 1602, Noncontrolling Interests, which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated financial statements and Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary subsequent to a business combination. These sections are effective for the Company on January 1, 2011 with prospective application and early adoption permitted. The adoption of these standards is not expected to have a material impact on the Company s consolidated financial statements. The Canadian Accounting Standards Board has confirmed the convergence of Canadian GAAP with International Financial Reporting Standards ( IFRS ) will be effective January 1, The Company has developed a project plan in order to ensure successful implementation within the required timeframe. The impact on the Company s consolidated financial statements is not reasonably determinable at this time. Key information will be disclosed as it becomes available during the transition period. Note 4. Variable Interest Entity and Non-Controlling Interests The Company is the primary beneficiary in a variable interest entity ( VIE ) called Viking Storage Solutions (Mauritius) Limited ( VSS ) which was incorporated in August The Company contributed the Resolution vessel to VSS, owns 50% of the VSS common shares, and is entitled to 50% of the voting rights in VSS. The purpose of VSS is to legally own and charter the Resolution vessel for fixed periods of time. VSS has a five year bareboat charter / lease with a subsidiary of the Company; payments under this charter have been guaranteed by the Company. The cost of ensuring the vessel is ready for operational use lies with VSS. The day-to-day operational usage will be dictated by the Company. The relative proportion of future financing reflects the fact that the Company transferred the vessel to the entity. It is expected that the Company will experience greater variability in returns and losses than the other shareholder in VSS. The maximum loss the Company is exposed is its investment in the share capital of VSS. The effect of consolidating VSS has meant that assets of $24.4 million, liabilities of $0.1 million and minority interest of $5.6 million are included on the Company s balance sheet at December 31, The loss from the operations of VSS is $0.2 million offset by a credit from the non-controlling interest of $0.1 million. There is no recourse to other entities of the Company for losses and claims made against VSS. Notes to the Consolidated Financial Statements 43

47 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 5. Restricted cash The Company has cash balances which are restricted by the Company s banking institutions. following table summarizes the restricted cash as of December 31, 2009 and The December 31, Collateral in support of Corporate Letter of Credit 673 $726 (Note 19) Restricted in support of Corporate Long-term Debt 3,156 3,420 (Note 13) $3,829 $4,146 Note 6. Accounts receivable and other December 31, Refundable taxes 5,682 $1,389 Trade receivables Other receivables $6,111 $2,391 Note 7. Investment in and advances to Apico LLC The Company has an interest of approximately 36.1% of Apico, a limited liability company incorporated in the State of Delaware, USA. Apico s primary purpose is the acquisition, exploration and development of onshore petroleum interests in the Kingdom of Thailand. Apico has the following working interests in petroleum concessions located in the Khorat Plateau area in northeastern Thailand: Petroleum Concession Apico s interest net to Coastal Block EU-1 and E-5N in the Sinphuhorm gas field 35% % Block L15/43 - surrounding the Sinphuhorm gas field 100% % Block L27/43 southeast of the Sinphuhorm gas field 100% % Block 13/48 immediately east of the Sinphuhorm gas field 60% % The Company s investment in Apico exceeds its proportionate share of net assets of Apico ( excess basis ). This difference has been allocated to Apico s oil and gas properties and is being amortized using the units of production method. At December 31, 2009 and 2008, the remaining unamortized excess basis was $15.1 million and $16.1 million, respectively. The following table summarizes the Company s investments in and advances to Apico: Year ended December 31, Balance, beginning of year $50,376 $53,188 Advances during the year 4, Share of earnings of significantly influenced investee, net of taxes 9,544 13,963 Amortization of excess basis in Apico (1,082) (1,059) Earnings distributions (8,129) (16,619) Balance, end of year $55,225 $50,376 Notes to the Consolidated Financial Statements 44

48 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 8. Property plant and equipment, net December 31, 2009 December 31, 2008 Cost AD&D* Net Cost AD&D* Net Oil and gas properties Gulf of Thailand 215,078 (27,594) 187,484 $152,098 $(1,655) $150,443 Oil and gas production equipment 34,296-34,296 30,558-30,558 Construction in progress 10,605-10,605 10,462-10,462 Corporate assets 1,305 (676) 629 1,100 (339) ,284 (28,270) 233,014 $194,218 $(1,994) $192,224 * Accumulated depletion and depreciation Thailand The Company has a 100% working interest in Block G5/43 in the Gulf of Thailand which includes the Bua Ban and Songkhla oil fields and a 100% working interest Block G5/50 in the Gulf of Thailand. The Company began depleting its oil and gas properties in December 2008, following the commencement of production. At December 31, 2009 and 2008, oil and gas properties respectively included $44.9 million and $42 million of unproved properties that have been excluded from the depletion calculation. An impairment (ceiling) test was performed for the Thailand cost centre at December 31, 2009 in which the estimated undiscounted future net cash flows associated with the proved reserves exceeded the carrying amounts. In determining the undiscounted future net cash flows for this cost centre, the Company utilized benchmark pricing forecasts from its professional reserves evaluator. The benchmark prices used in their forecast at December 31, 2009 are outlined in the following table: Dubai Crude Oil (1) Condensate Natural Gas Year ($/bbl) ($/bbl) ($/Mcf) Thereafter inflation % change 2% 2% 2% (1) Actual prices used in the impairment tests were adjusted for crude oil quality differentials, natural gas heat content, transportation, and marketing expenses specific to the Company s operations. Based on these assumptions, management determined that there is no impairment of oil and gas properties and equipment as at December 31, Oil and gas production equipment The Company is acquiring equipment to be used in the production of the Company s interests in the Gulf of Thailand. Once these assets are put into service, the Company will commence depreciation using the straight line method over their respective useful lives. Notes to the Consolidated Financial Statements 45

49 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 8. Property plant and equipment, net (continued) Construction in progress Construction in progress relates to the acquisition and refurbishment of a mat-based jack-up rig which the Company intends to use in its development of its interests in the Gulf of Thailand. Once this asset is placed in service, the Company will commence depreciation using the straight line method over its useful life. During the year ended December 31, 2009, the Company elected to halt construction of the CALM buoy mooring system which it had ordered for the Songkhla field. Following a reevaluation study and taking into account the sharp decline in the pricing of marine assets, it was determined that halting construction and proceeding with an alternative mooring system would be the most cost effective decision. The decision to stop construction resulted in the Company forfeiting its $1.765 million deposit with the Contractor, and consequently required the Company to impair the asset by that amount. The Company also entered into an agreement to settle all disputes with the contractor for a one-time $0.6 million payment. The total settlement expense to the Company was $2.366 million. Note 9. Accounts payable and accrued liabilities December 31, Trade payables $21,087 $31,302 Payroll and other employee related liabilities 9,671 2,634 Other accrued expenses 567 1,600 $31,325 $35,536 Note 10. Deferred income Deferred income relates to cash advances received under arrangements for the Company to deliver 400,000 barrels to a third party customer within the next twelve months. Note 11. Amounts due to shareholder Effective September 25, 2006, the Company assumed a note payable to the shareholder of NuCoastal Thailand Limited ( NuCoastal ) for $4.6 million. The original note was unsecured, accrued interest at 4% and was set to mature on July 20, In January 2007, the note and its accrued interest were renegotiated to accrue interest at 4.5% per annum and mature on July 20, In July 2008, the note was renegotiated to mature on December 31, 2008 and the accrued interest through September 30, 2007 of $411,000 was paid to the shareholder in July Effective November 20, 2008 the note payable balance was renegotiated to mature on March 31, 2009 at an interest rate of 7% per annum. At each quarter end during 2009 the note was renegotiated such that it fell due at the subsequent quarter end. The interest rate at each renegotiation in 2009 was set at 12% per annum. Effective December 31, 2009 all accrued interest was paid and the note payable balance was renegotiated to mature on March 31, On December 30, 2008, the shareholder loaned the Company $2.0 million and accrued interest at 15% per annum. The Company repaid all outstanding amounts by September 30, On January 6, 2009, the Company entered into an unsecured loan agreement with an individual related to the Company s primary shareholder in the amount of $1 million bearing interest at 15% per annum and maturing on June 30, Effective June 29, 2009, the note was renegotiated to accrue interest at 15% per annum and mature on September 30, On September 30, 2009 the note was again renegotiated to mature on December 31, 2009, at which time the note balance and accrued interest was repaid in full. Notes to the Consolidated Financial Statements 46

50 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 12. Notes Payable On January 20, 2009, the Company closed a $5 million senior secured note with an unrelated private partnership bearing interest at 16% per annum and maturing on July 19, This note was secured by the Company s oil and gas production equipment. The Company had fully repaid all outstanding amounts by December 31, On January 23, 2009, the Company completed its offering of senior unsecured notes raising $10 million. The notes bore interest at 15% per annum and were due to mature on January 23, The Company had fully repaid all outstanding amounts by December 31, Each $100,000 note was issued with cashless warrants entitling the holder thereof to acquire 20,000 common shares of the Company at an exercise price of Cdn$ These warrants expire on January 23, Note 13. Long-term debt December 31, Revolving debt facility $34,400 $44,000 Less: current portion, excluding loan interest (10,116) (15,249) Long-term debt $24,284 $28,751 During the year ended December 31, 2007, the Company entered into a $50 million revolving debt facility (the Facility ), secured by the Company s investment in Apico, with a maturity date of December 31, The Facility, arranged by Sumitomo Mitsui Banking Corporation Europe Limited ( SMBC ), consists of a $42.5 million senior loan and a $7.5 million junior loan. The borrowing base of the facility and its availability are subject to recalculation every quarter. As of December 31, 2009, the amount available under the borrowing base was $34.4 million, under which the Company had drawn a total of $34.4 million comprised of a $29.9 million loan under the senior facility and a $4.5 million loan drawn under the junior facility. As a condition of the facility, the Company must maintain a debt service coverage ratio of 1.0, where debt service coverage ratio is defined as the proportion of the Company s share of cash flow from the borrowing base assets relative to the required principal and interest payments related to the credit facility. The Company was in compliance with this covenant as of December 31, Loans under this Facility bear interest at SMBC s LIBOR plus an applicable margin between 1.75% and 3.5%. The applicable LIBOR rate is determined by the length of the interest renewal period; and the margin is dependent upon whether the loan is drawn under the senior or junior loan terms and the aggregate amount of loans outstanding. The effective interest rate on the Facility for the twelve months ended December 31, 2009 and 2008 were 3.17% and 5.18%, respectively. The equivalent rates for the three months ended December 31, 2009 and 2008 were 3.32% and 4.93%, respectively. As part of the Facility, the Company is required to deposit funds into a bank collection account, which is restricted as to its availability (Note 5.) As a requirement of the Facility, the Company is required to hedge 50% of its onshore gas production. The Company entered into a derivative risk management contract with an affiliate of SMBC under which the Company has the right to sell 4,000 metric tons per month (up to a total of 96,000 metric tons) of Singapore fuel oil at a price of $ per metric ton commencing July 1, 2007 and expiring June 30, The Company paid $1.2 million for this contract. During 2009, the Company recognized $439,000 in proceeds from this contract and realized losses on mark-to-market adjustments of $2,016,000. Notes to the Consolidated Financial Statements 47

51 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 13. Long-term debt (continued) On June 5, 2009, the Company entered into a second derivative risk management contract with an affiliate of SMBC under which the Company has the right to sell 4,000 metric tons per month (up to a total of 48,000 metric tons) of Singapore fuel oil at a price of $ per metric ton commencing July 1, 2009 and expiring June 30, The Company paid $566,000 for this contract. As at December 31, 2009, the fair value of the risk management contract was $66,000. The Company recorded $500,000 of unrealized losses on this contract for the twelve months ended December 31, Long-term debt repayment Principal repayments on long-term debt in each of the next five years are as follows: 2010 $10, , , ,500 Note 14. Asset retirement obligations The Company s asset retirement obligations result from its ownership interest in oil and gas properties, including well sites, production and processing facilities. The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations at December 31, 2009 and 2008 to be approximately $6.0 million and $2.2 million, respectively which will be incurred approximately 12 years in the future, and are expected to be funded out of the Company s general resources available at the time of settlement. A credit adjusted risk free interest rate of 8.98% and an inflation rate of 2% were used to calculate the fair value of the asset retirement obligation in respect of the year ended December 31, 2009 whereas 6.45% and 2% respectively was used for year ended December 31, The following table provides a reconciliation of the asset retirement obligations: Balance, beginning of year $1,354 $ - Additions to future costs 1,521 1,340 Revisions in estimated cash flow (186) - Accretion expense Balance end of year $2,809 $1,354 Notes to the Consolidated Financial Statements 48

52 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 15. Share capital Common Stock Authorized 250,000,000 common shares with par value of $0.04 each; Issued and fully paid common shares Share Capital Shares Value Capital Total Surplus Balance, December 31, ,983,220 $3,079 $88,682 $91,761 $11,448 Shares issued pursuant to offering, net of issue costs 16,445, ,791 54,449 - Shares issued pursuant to exercise of stock options 202, (303) Stock-based compensation ,080 Balance, December 31, ,630,720 $3,745 $143,193 $146,938 $13,225 Shares issued pursuant to offering, net of issue costs 12,650, ,398 45,904 Shares issued pursuant to exercise of stock options 1,106, ,469 4,513 (1,720) Shares issued pursuant to exercise of warrants 889, Stock-based compensation ,274 Balance, December 31, ,276,645 $4,331 $193,790 $198,121 $13,779 On January 8, 2008, the Company completed a public offering of 16,445,000 common shares (including the over-allotment option of 2,145,000 common shares) of the Company at a price of $3.50 (Cdn $3.50) per common share, raising gross proceeds of $57.6 million (Cdn $57.6 million). Proceeds of the offering, net of issuance costs of approximately $3.1 million, were $54.5 million. On May 28, 2009, the Company completed a public offering of 5,000,000 common shares of the Company at a price of $2.87 (Cdn $3.20) per common share, raising gross proceeds of $14.5 million (Cdn $16.0 million). Proceeds net of issuance costs of approximately $0.9 million were $13.6 million. On June 17, 2009, the Underwriters of the May 2009 offering exercised the over-allotment option they were granted in connection with the offering. The Underwriters purchased an additional 750,000 common shares of the Company at a price of $2.83 (Cdn $3.20) per share, raising gross proceeds of $2.1 million (Cdn $2.4 million). Proceeds net of issuance costs of approximately $0.3 million were $1.8 million. On November 5, 2009, the Company completed an offering of 6,900,000 common shares (including the over-allotment option of 900,000 common shares) of the Company at a price of $4.70 (Cdn $5.00) per common share, raising gross proceeds of $32.4 million (Cdn $34.5 million). Proceeds of the offering, net of issuance costs of approximately $1.7 million, were $30.7 million. Notes to the Consolidated Financial Statements 49

53 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 15. Share capital (continued) Warrants At December 31, 2007 and 2008 the Company had 2,343,745 warrants outstanding, exercisable at 2.80 per share and expiring July 20, In January 2009, the Company issued 2,000,000 additional warrants in connection with a debt offering exercisable at Cdn $1.136 per share equivalent and expiring January 23, 2014 (see Note 22.). During 2009, 1,097,500 warrants were exercised in exchange for 889,175 common shares. The changes in warrants were as follows: Number of warrants Weighted average exercise price Number of warrants Weighted average exercise price Balance, beginning of 2,343,745 $4.09 2,343,745 $5.71 year Warrants issued 2,000,000 $ Warrants exercised (1,097,500) $ Warrants expired Balance, end of year 3,246,245 $3.42 2,343,745 $4.09 The fair value of each warrant granted is estimated at the time of the grant using the Black-Scholes option pricing model. The weighted average assumptions for grants and the weighted average fair value of warrants granted are as follows: Risk-free interest rate 1.75% - Expected life 2.5 years - Annualized volatility 30% - Dividend rate 0% - Weighted average grant date fair value per warrant $ Warrants discussed above are anti-dilutive and, therefore, have not been taken into account in the per share calculations. Stock options The Company has a stock option plan (the Plan ) in compliance with the TSX-V s policy for granting stock options. Under the Plan, the number of shares reserved for issuance may not exceed 15,000,000 shares. At December 31, 2008 there remained for issuance 9,419,000 stock options. The exercise price of each option shall not be less than the market price of the Company s stock at the date of grant. The vesting term of options under the Plan is determined by the Company s Board of Directors but options granted typically vest over a period of three years. Prior to the January 2009 grant, the options vested one-quarter on the date of the grant and one-quarter on each subsequent anniversary of the date of the grant. Beginning with the January 2009 grant, the options vest one-third on each subsequent anniversary of the date of grant. The maximum exercise period of options granted under the Plan is five years following the grant date. The changes in stock options were as follows: Number Weighted average Number Weighted average of options exercise price of options exercise price Balance, beginning of year 5,581,000 $2.41 3,700,000 $2.25 Options granted 6,125,599 $2.83 2,760,000 $3.19 Options exercised (1,106,750) $2.52 (202,500) $1.69 Options forfeited (190,250) $3.20 (676,500) $2.52 Balance, end of year 10,409,599 $2.85 5,581,000 $2.41 Notes to the Consolidated Financial Statements 50

54 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 15. Share capital (continued) The following table summarizes the outstanding and exercisable options at December 31, 2009: Grant Date Number Outstanding Remaining Contractual Life Exercise Price Expiry Date Number Exercisable Jul. 06, , years $2.26 ( 1.40) Jul. 06, ,000 Dec. 27, ,200, years $2.10 (Cdn$2.20) Dec. 27, ,200,000 Jun. 15, , years $2.83 (Cdn$2.96) Jun. 16, ,750 Jan. 25, , years $3.76 (Cdn$3.94) Jan. 26, ,500 May 05, , years $4.24 (Cdn$4.44) May 06, ,000 Jul. 14, , years $3.45 (Cdn$3.61) Jul. 15, ,500 Sep. 16, , years $2.17 (Cdn$2.27) Sep. 16, ,000 Sep. 23, ,000, years $3.76 (Cdn$3.94) Feb. 05, ,000 Jan. 02, ,506, years $1.29 (Cdn$1.35) Jan. 01, ,500 Dec. 01, ,616, years $4.90 (Cdn$5.13) Nov. 30, ,409,599 3,462,250 On January 2, 2009, 3,509,000 stock options were granted to directors, officers, employees and consultants with an exercise price of Cdn $ ,000 of these options vest 25% immediately upon the grant date and 25% on each of the three subsequent anniversaries of the grant date. The remaining 2,759,000 options were granted as part of the 2008 annual award and vest 33.3% on each of the three subsequent anniversaries of the grant date. On December 1, 2009, 2,616,599 stock options were granted to directors, officers, employees and consultants with an exercise price of Cdn $5.13. These options were granted as part of the 2009 annual award and vest 33.3% on each of the three subsequent anniversaries of the grant date. Options discussed above are anti-dilutive and, therefore, have not been taken into account in the per share calculations. The fair value of each option granted is estimated at the time of the grant using the Black-Scholes option pricing model. The weighted average assumptions for grants and the weighted average fair value of option awards granted are as follows: Risk-free interest rate 3.00% 3.00% Expected life 3 years 3 years Annualized volatility 38-60% 57% Dividend rate 0% 0% Weighted average grant date fair value per option $0.89 $1.18 Stock-based compensation For the years ended December 31, 2009 and 2008, the Company recorded stock-based compensation of $2.25 million and $2.08 million, respectively. The Company has capitalised $0.29 million of stock-based compensation incurred in In 2009, the Company awarded stock appreciation rights for the equivalent of approximately 2,993,079 common shares, of which approximately 398,568 shares are contingent upon the achievement of certain performance goals established by the Company. These awards vest and are cash-settled 33.3% on each of the subsequent anniversaries of the grant date. The full fair value of outstanding stock appreciation rights at December 31, 2009 is $14.58 million. During the year ended December 31, 2009 the Company accrued a liability of $6.87 million of which $0.83 million has been capitalised, $0.45 million has been expensed as a cost of production and $5.59 million is included in general and administrative expenses. Notes to the Consolidated Financial Statements 51

55 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 15. Share capital (continued) Earnings per share The following table summarizes the weighted average number of common shares used in calculating basic and diluted loss per share. No adjustments to income were required Weighted average common shares outstanding, basic 98,243,701 93,262,551 Effect of warrants and stock options - - Weighted average common shares outstanding, diluted 98,243,701 93,262,551 Because the Company incurred net losses for the twelve months ended December 31, 2009 and 2008, the effect of the stock options and warrants is anti-dilutive. Therefore the computation of diluted loss per share does not take into account the effect of these stock options and warrants. Note 16. Capital management The Company manages its capital structure and makes adjustments in response to changes in economic conditions and the risk characteristics of the underlying assets. The Company considers its capital structure to include common share capital, long-term debt and working capital (a non-gaap measure defined as current assets less current liabilities). In order to maintain or adjust the capital structure, from time to time the Company may issue common shares or other securities, incur debt, sell assets or adjust its capital spending to manage current and projected debt levels. The Company may also repurchase common shares when the Company believes the market price does not reflect the underlying values of the common shares. The Company s capital structure as of December, 31 is comprised as follows: Shareholders equity 195, ,576 Non-controlling interests 5,617 - Long-term debt 34,550 44,000 Notes payable 5,164 6,761 Working capital deficit 22,516 27, , ,320 The Company is in compliance with its debt covenants. See Note 13. Note 17. Financial instruments and risk management Financial risk management objectives Management co-ordinates access to financial markets, and monitors and manages financial risk. These financial risks include fair value risk, market risks (comprising currency, interest rate, commodity price and credit risk) and liquidity risk. Management seeks to adopt practicable yet effective approaches in a manner consistent with the current nature and scale of operations. This is manifested in procedures such as seeking to match currency inflows with currency outflows in the same currency, and by avoiding the use of derivative instruments where possible. The Company never undertakes derivative transactions for speculative trading purposes. Given the direct involvement of senior financial personnel in monitoring financial risks, it is not considered necessary at this time for any formalized reporting of financial risk sensitivity models to be prepared. This decision will be reassessed by management on an ongoing basis as part of wider assessments of the ongoing effectiveness of the treasury function. Notes to the Consolidated Financial Statements 52

56 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 17. Financial instruments and risk management (continued) Fair values The Company s financial instruments include cash and cash equivalents, derivatives, accounts receivable and other, and accounts payable. Cash and derivative contracts are carried at fair value. The Company considers that all other items have a carrying value that approximates their fair value due to their shortterm nature. The carrying value of the amounts due to shareholder approximates the fair value. This is due to the short-term nature of the liability. The fair value of the Company s long-term debt as at December 31, 2009 and 2008 was $33.69 million and $42.71 million, respectively. The Company classifies the fair value of the above transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument. Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2- Pricing inputs other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observables as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the market place. Level 3 Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. The Company s financial instruments have been assessed on the fair value hierarchy described above. Cash and cash equivalents and restricted cash are classified as Level 1. The fair value disclosure for the Company long-term debt is considered Level 2. The Company s derivative contracts at December 31, 2009 and 2008 are considered held-for-trading and their fair value is marked to market every quarter based on quoted market prices in the futures market on the balance sheet date. As discussed in Note 13, these derivative instruments are solely required for the SMBC debt facility. These contracts are considered to be Level 2. The Company considers its risks in relation to financial instruments in the following categories, of which management considers that no category has significantly worsened in 2009 relative to 2008 Credit risk Credit risk is the risk that a counterparty to a financial instrument will not discharge its obligations, resulting in a financial loss to the Company. The Company has procedures in place to minimize the credit risk it will assume. Coastal personnel evaluate credit risk on an ongoing basis including an evaluation of counterparty credit rating and counterparty concentrations measured by amount and percentage. The primary sources of credit risk for the Company arise from the following financial assets: (1) cash and cash equivalents and restricted cash; (2) accounts receivable and other; (3) derivative contract. The Company has not had any credit losses in the past beyond that described below. At December 31, 2009, the Company has no financial assets that are past due or impaired due to credit risk related defaults. Notes to the Consolidated Financial Statements 53

57 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 17. Financial instruments and risk management (continued) The Company s accounts receivable and other consists primarily of Value Added Tax ( VAT ) refunds from the governments of Great Britain and Thailand. The Company s maximum exposure to credit risk at the balance sheet date is as follows: December 31, Cash and cash equivalents 21,229 $6,434 Restricted cash 3,829 4,146 Accounts receivable from government entities (UK, Thailand) 5,682 1,389 Trade receivable Other accounts receivable Derivative asset 66 2,016 $31,235 $14,987 The Company s trade receivable at December 31, 2008 was from one customer, was less than 30 days aged and was fully collected in All revenues for the year ended December 31, 2009 and 2008 were from sales to three customers. Revenue for the year ended December 31, 2008 was split 71% / 29% between two customers. Revenue for the year ended December 31, 2009 was split 81% / 19% between two customers. In both 2008 and 2009 the larger revenue percentage was with the same customer. The respective credit ratings with Standard and Poors as at December 31, 2009 were BBB+ for the larger 2009 customer and AA for the smaller 2009 customer. Typically, the Company s maximum credit exposure to customers is revenue from one month s commodity sales. The Company s standard credit terms have been (receipt of) payment within 30 days of delivery or prepayment of crude oil sales. The Company s policy to mitigate credit risk associated with commodity sales is to establish relationships with credit worthy customers. The Company wrote off one accounts receivable balance for $150,000 during 2009 which related to a miscellaneous asset sale in This assertion is reconfirmed by the fact that no outstanding receivables are overdue as of the balance sheet date. No receivables are overdue as of December 31, 2009 and hence no allowance has been made for doubtful debts. Liquidity risk Liquidity risk is the risk that the Company will not be able to meet its obligations with respect to its financial liabilities. The Company s financial liabilities are comprised of accounts payable and accrued liabilities, long-term debt, obligations under operating leases and future contractual commitments. The Company frequently assesses its liquidity position and obligations under its financial liabilities by preparing financial forecasts. Coastal mitigates liquidity risks by maintaining a sufficient cash balance as well as maintaining a sufficient current and projected liquidity cushion to meet expected future payments. The Company s liquidity position has improved as a result of increased levels of production in the current year. Notes to the Consolidated Financial Statements 54

58 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 17. Financial instruments and risk management (continued) The Company s financial liabilities arose primarily from the development of its Thailand properties. Payment terms on the Company s accounts payable and accrued liabilities are typically 30 to 60 days from receipt of invoice and generally do not bear interest. At December 31, 2009 the Company had recorded all of the obligations associated with its financial liabilities. In the normal course of business, the Company enters into contracts that give rise to commitments for future minimum payments. The following table summarizes the remaining contractual maturities of the Company s financial liabilities and capital expenditures: December 31, Thereafter Total Total Accounts payable and accrued Liabilities $31,325 $- $- $- $31,325 $35,536 Income taxes payable Amounts due to shareholder 5, ,164 6,761 Long-term debt payment 10,266 8,732 8,052 7,500 34,550 44,000 $46,793 $8,732 $8,052 $7,500 $71,077 $86,297 As of December 31, 2009 the Company has fully utilized its available borrowing facilities. Management believes it can re-enter the credit market in the future should circumstances deem that necessary. Market risk Market risk is the risk that the fair value (for assets or liabilities considered to be held-for-trading and available-for-sale) or future cash flows (for assets or liabilities considered to be held-to-maturity, other financial liabilities, and loans or receivables) of a financial instrument will fluctuate because of changes in market prices. The Company evaluates market risk on an ongoing basis. Coastal assesses the impact of variability in identified market risk on its various assets and liabilities and has established policies and procedures to mitigate market risk on its foreign exchange, interest rates and derivative contract. (a) Currency risk Coastal operates internationally and therefore is exposed to the effects of changes in currency exchange rates. Although the functional currency of the Company is United States Dollars, it also transacts business in Thai baht, British Pounds, Canadian Dollars and Euros. The Company is subject to inflation in the countries in which it operates and fluctuations in the rate of currency exchange between the United States and these other countries. The Company does not currently use financial instruments or derivatives to hedge these currency risks. Exchange rate fluctuations may affect the costs that the Company incurs in its operations. The Company s costs are incurred principally in US dollar, Thai baht, UK Pounds and Canadian Dollars. The appreciation of non-us Dollar currencies against the US Dollar can increase the costs of operations and capital expenditures in US Dollar terms. Notes to the Consolidated Financial Statements 55

59 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 17. Financial instruments and risk management (continued) The Company is exposed to currency risk through the following US dollar equivalent of financial assets and liabilities denominated in currencies other than US Dollars: Cash and cash equivalents Accounts receivable Accounts payable and accrued liabilities Income taxes payable December 31, 2009 Thai Baht $3,561 $5,686 $(9,246) $(31) UK Pounds (105) (7) Canadian Dollars 6 - (317) - Singapore Dollars (272) - Euros 8 - (68) - Swiss Francs - - (11) - $4,317 $6,097 $(10,019) $(38) December 31, 2008 Thai Baht $158 $1,362 $(13,805) $(1,252) UK Pounds (282) - Canadian Dollars 4 - (123) - Singapore Dollars - - (2,520) - Euros 7 - (70) - $308 $1,389 $(16,800) $(1,252) Based on the above net exposures at December 31, 2009, a 10% depreciation or appreciation of the above currencies against the US dollar would result in a $0.036 million increase or decrease in the Company s after-tax earnings with the same impact on comprehensive income. The respective result at December 31, 2008 was $1.636 million based on a 10% movement. These movements are attributable to year-end payables and receivables denominated in currencies other than the US dollar. (b) Interest rate risk The Company is exposed to interest rate risk on its outstanding borrowings and short-term investments. Presently the majority of the Company s credit facilities are at floating interest rates. The Company monitors its exposure to interest rates and is comfortable with its exposures given the relatively short-term of the interest rates on long-term debt. The terms of the Company s long-term debt obligation is described in Note 12. The Company has met its obligations with respect to this liability. The Company accounts for its borrowings under the long-term debt on an amortized cost basis. The Company had borrowings totaling $39.7 million at December 31, 2009 and $50.8 million at December 31, 2008 respectively (see Notes 11, 12 and 13). A 100 basis point change in interest rates at the balance sheet date would result in a $0.397 million change in the Company s annual net income December 31, 2009 and $0.508 million at December 31, No derivative instruments have been taken out to date by the Company to specifically manage interest rate risk. The Company paid an average of 6.75% and 5.12% on its borrowings for the year ended December 31, 2009 and December 31, 2008, respectively. The Company paid an average of 5.75% and 4.93% on its borrowings for the three months ended December 31, 2009 and December 31, 2008, respectively. Notes to the Consolidated Financial Statements 56

60 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 17. Financial instruments and risk management (continued) The Company earned an average of 0.31% and 3.89% on its short-term investments for the year ended December 31, 2009 and December 31, 2008, respectively. The Company earned an average of 0.16% and 4.79% on its short-term investments for the three months ended December 31, 2009 and December 31, 2008, respectively. (c) Commodity price risk Profitability of the Company depends on market prices for petroleum and natural gas. Petroleum and natural gas prices are affected by numerous factors such as global consumption and demand for petroleum and natural gas, international economic and political trends, fluctuation in the US dollar and other currencies, interest rates, and inflation. The Company s long-term debt (Note 13) incorporates the reference price in its model to determine the effective borrowing base under which the Company may borrow. Thus a 10% decline in the reference price projection would reduce the availability under the borrowing base by approximately 10% or $3.430 million at December 31, 2009 and by approximately 4% or $1.8 million at December 31, As a requirement of the debt facilities, the Company entered into a derivative hedging agreement described in Note 13. Coastal s derivative contract was in place and the Company realized cash settled proceeds of $439,000 and $422,000 under it during the year ended December 31, 2009 and 2008 respectively. A 10% increase in prices as of December 31, 2009 would cause the derivative to be valued at $38,000, effectively a decline in value of $28,000 from what is recorded on the balance sheet. A 10% decrease in prices as of December 31, 2009 would cause the derivative to be valued at $118,000, effectively an increase in value of $52,000 from what its carrying value is at December 31, (d) Other price risk The Company is exposed to equity price risk in relation to stock appreciation rights granted to employees. For more detail, see Note 15. Note 18. Income taxes The Company has operations in Thailand, the Cayman Islands, the United Kingdom and United States. The provision for income taxes reported differs from the statutory tax rates in the jurisdictions of operations due to the following: Years ended December 31, Income before taxes after earnings from significantly influenced investee $623 $(1,895) Thailand petroleum income statutory tax rate 50% 50% Expected income tax expense (recovery) computed at standard rates 312 $(948) Effect of different tax rates in foreign jurisdictions 3,671 (1,692) Non-deductible and non-taxable items Valuation allowance 1,096 2,640 Benefit of income tax losses not previously recognized (5,227) - Outside basis difference on investment in Apico LLC Change in tax rates and other (88) - Future and current income tax expense $738 $666 Consisting of: Current income tax expense $38 $2,484 Future income tax expense 700 (1,818) $738 $666 Notes to the Consolidated Financial Statements 57

61 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 18. Income taxes (continued) There is presently no taxation imposed by the Government of the Cayman Islands on income or capital gains. If any form of taxation were to be enacted, the Company has been granted an exemption until May 26, The Company is subject to foreign withholding taxes on dividend and interest income paid by the Company s Thai subsidiary. In April 2008, the Company s Thai subsidiary sold its 25.5% interest in Apico, LLC at its net book value to the Company s Cayman Island subsidiary. The Company has recorded a current tax liability and related current tax expense of $2.484 million related to this sale during the quarter ended June 30, 2008, based on a corporate rate of 30%. In August, 2008, the Company made a $1.232 million estimated tax payment toward this tax liability, and the balance was paid in the quarter ended June 30, The components of the Company s future income tax assets and liabilities arising from temporary differences are all applicable to Thai PITA tax attributes and are as follows: Future Income Future Income Future Income Future Income Tax Asset Tax Liability Tax Asset Tax Liability Non capital loss carry forwards $29,878 $ - $17,302 $ - Capital assets - 56,400-37,255 Asset retirement obligations 1, ,282 56,400 17,979 37,255 Valuation allowance (2,577) - (6,708) - Net future tax asset (Liability) $ - $(27,695) $ - $(25,984) Under Thailand s Petroleum Income Tax Act ( PITA ), the Company was not required to file an income tax return until after its first production. All costs incurred in Thailand prior to first production were capitalized for income tax purposes and amortized over ten years beginning with first production. The Company has approximately $54.6 million of Thailand PITA tax losses to offset future taxable income that expire in 2018; approximately $5.0 million of United States tax losses to offset future taxable income that expire in 2027; and approximately $3.7 million of Mauritius tax losses to offset future taxable income that expire in The net future income tax liability is valued in the underlying currency of the related tax assets and liabilities. A portion of the change in this account was attributable to the currency valuation on these tax assets and liabilities and the effect of this change was included in the statement of operations, comprehensive loss and deficit under the foreign exchange loss. Note 19. Commitments and contingencies The Company has provided a Letter of Credit to the Thailand Customs Department for $0.7 million. This Letter of Credit is cash collateralized (see Note 5), has not been drawn on and remains outstanding as of December 31, Notes to the Consolidated Financial Statements 58

62 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 19. Commitments and contingencies (continued) The Company has entered into various commitments primarily related to the ongoing development of its Thailand G5/43 property (see Note 8). Coastal has secured equipment and work commitments in the Gulf of Thailand. In December 2007, the Company was awarded the G5/50 Concession in the Gulf of Thailand, within the boundaries of the Company s G5/43 Concession. In order to keep this Concession, the Company has various development obligations. The Company also has operating lease agreements for office space in the United Kingdom, Thailand and the United States. The following table summarizes the Company s outstanding contractual obligations: Year Drilling & Production G5/50 Other Total ,685 2, , , , The Company is from time to time involved in various claims, legal proceedings, complaints and disputes with governmental authorities arising in the ordinary course of business. The Company does not believe that adverse decisions in any pending or threatened proceedings related to any matter, or any amount which it may be required to pay by reason thereof, will have a material effect on the financial condition or future results of operations of the Company. Note 20. Supplemental cash flow information The following summarizes the changes in non-cash working capital for the years ended December 31, 2009 and 2008: Year ended December 31, Accounts receivable and other (3,720) $(2,520) Crude oil inventory (5,002) Prepaids and other current assets (255) Accounts payable and accrued liabilities 4,226 3,284 Deferred income 23,060 Current income taxes payable (1,214) 1,252 $17,095 $2,016 During the years ended December 31, 2009 and 2008, the Company made cash payments for income taxes and interest on long-term debt as follows: Year ended December 31, Interest on debt $3,589 $2,295 Income taxes $1,252 1,232 Note 21. Segmented information Operating segments The Company is involved in the acquisition, exploration and development of oil and gas properties in the Gulf of Thailand. The Company is also involved in the acquisition, exploration and development of onshore petroleum properties in Thailand. The onshore Thailand operations are owned through the Company s 36.1% interest in Apico which is accounted for using the equity method (Note 7). The Company s administrative office is located in the United States of America. Notes to the Consolidated Financial Statements 59

63 (All tabular amounts are expressed in US$000 s unless otherwise stated except share and per share amounts) Note 21. Segmented information (continued) Geographic segments The Company s revenues and expenses for years ended December 31, 2009 and 2008 and oil and gas assets as at December 31, 2009 and December 31, 2008 were as follows: Oil and gas assets as at Onshore Thailand December 31, 2009 December 31, 2008 Gulf of Onshore Gulf of Thailand Corporate Total Thailand Thailand Corporate Total Investment in Apico $55,225 $- $- $55,225 $50,376 $- $- $50,376 Property, plant and equipment, net - 232, , , ,224 Total Assets $55,225 $256,152 $14,232 $325,609 $50,376 $202,954 $5,133 $258,463 Onshore Thailand December 31, 2009 December 31, 2008 Gulf of Onshore Gulf of Thailand Corporate Total Thailand Thailand Corporate Total Twelve months ended Revenues Oil and gas revenues, $- $80,470 $- $80,470 $- $3,884 $- $3,884 net Gain (loss) on - - (2,077) (2,077) - - 2,447 2,447 derivative Interest income Other income ,580 (2,050) 78,530-3,850 3,423 7,313 Expenses Production expenses - 33,477-33,477-1,597-1,597 General and - 2,926 16,650 19,576-1,961 10,863 12,824 administrative Foreign exchange ,476 3,869 (gain) loss 1,051 1,941 Interest expense - - 3,839 3, ,715 2,146 Debt financing fees - - 1,454 1, Depletion, depreciation & accretion - 23, ,695-1, ,893 Settlement - 2,366-2,366 - Loss / (gain) on sale (217) (217) of assets Income taxes Share of Apico earnings 8, ,462 12, ,904 Net income (loss) before non-controlling interest $8,462 $16,952 $(25,656) $(242) $12,238 $(2,290) $(12,509) $(2,561) Capital Expenditures $- $67, 688 $205 $67,893 $ $103,429 $553 $103,982 Note 22. Subsequent events During Q1 2010, the Company paid $1.75 million in principal and accrued interest on the amount due to shareholder leaving a balance as of the date of this report of $3.54 million. Notes to the Consolidated Financial Statements 60

64 This was an important year in the history of the company - Randy L. Bartley President and CEO