Niko Reports Results for the Three Months Ended June 30, 2009

CALGARY, ALBERTA--(Marketwire - Aug. 13, 2009) - Niko Resources Ltd. ("Niko" or "the Company")

is pleased to report its financial and operating results, including consolidated financial statements and notes thereto, as well as its management's discussion and analysis, for the quarter ended June 30, 2009, the first quarter of Niko's fiscal year. The operating results are effective August 12, 2009. PRESIDENT'S REPORT TO SHAREHOLDERS OPERATIONAL HIGHLIGHTS Development - Production from the D6 gas field began in April 2009 increasing Company-wide production in the quarter ended June 30, 2009 by 65 percent over the previous quarter to 160 MMcfe/d. Company-wide production is currently at 230 MMcfe/d. Exploration - At D6, the AR2 and AS1 gas discoveries were drilled in proximity to the previously announced R1 discovery. The BA2 well is currently being drilled. - The Khoja-1 well in Cauvery was unsuccessful, but had indications of gas and oil while drilling. Drilling of the Khoja-2 well commenced in July 2009. - At NEC-25, the AJ2 well discovered gas. - Processing of 3D seismic in Pakistan is continuing. - 2D seismic in Kurdistan was completed and processing has commenced. - Acquisition of 2,400 square kilometres of 3D seismic commenced in the Southeast Ganal Block in Indonesia in July 2009. New Ventures - In Indonesia, Niko acquired interests in three production sharing contracts in May 2009 resulting in an additional 15,000 square kilometres of gross acreage. Niko will operate and has a 67 percent working interest in one of the blocks and a non-operated 25 percent working interest in the other two blocks. - In Trinidad, Niko signed an agreement whereby it will have a 26 percent interest and operate the 2AB shallow water block offshore Trinidad. /T/ Three months ended June 30, 2009 2008 ---------------------------------------------------------------------------- Average daily sales volumes Oil and condensate (bbls/d) 809 252 Natural gas (Mcf/d) 155,030 77,044 ---------------------------------------------------------------------------- Total combined (Mcfe/d) 159,884 78,557 ---------------------------------------------------------------------------- Revenues, royalties and operating costs (US$/Mcfe) Oil and natural gas revenue 3.70 3.41 Royalties (0.17) (0.16) Profit petroleum (0.50) (0.77) Operating costs (0.45) (0.32) ---------------------------------------------------------------------------- Operating netback (US$/Mcfe) 2.58 2.16 ---------------------------------------------------------------------------- /T/ Sales The Company's production in MMcfe/d for the four quarters completed June 30, 2009 is displayed below: To view the Sales History chart, please click the following link: http://media3.marketwire.com/docs/813nko_sales.pdf Gas production from the D6 Block commenced in April 2009 and increased Niko's total production in the quarter ended June 30, 2009 by 65 percent from the previous quarter. Primarily as a result of D6 gas production, average Company production for the year ending March 31, 2010 is expected to increase to 269 MMcfe/d, which is a 216 percent increase over fiscal 2009. Production from the Dhirubhai 1 and 3 gas fields is currently in excess of 1,280 MMcf/d (128 MMcf/d working interest to the Company) and is targeted to reach 2,800 MMcf/d (280 MMcf/d working interest to the Company) before calendar year-end. Oil production from the MA field in the D6 Block remained shut down from March 22, 2009 to April 25, 2009 for the hook-up of the Phase II sub sea facility and connection to the floating production, storage and offloading vessel. Production averaged 8,500 bbls/d (850 bbls/d working interest to the Company) during the quarter and there was one sale resulting in sales during the quarter of 5,000 bbls/d (500 bbls/d working interest to the Company). Oil production is targeted to reach up to 35,000 bbls/d (3,500 bbls/d working interest to the Company) before March 31, 2010. Gas production from Block 9 in the quarter ended June 30, 2009 was 95 MMcf/d (63 MMcf/d working interest to the Company) and current production is in excess of 110 MMcf/d (73 MMcf/d working interest to the Company) including the addition of production from the Bangora-3, which was put on-stream in June 2009. Development D6 Block - Dhirubhai 1 and 3 Gas Development: Gas production commenced from the Dhirubhai 1 and 3 discoveries in April 2009. Additional wells in the Dhirubhai 1 and 3 gas fields were completed during the quarter for a total of 17 of the 18 wells being completed to date. Nine of the wells have been connected and eight tested with a combined productive capability of approximately 1,940 MMcf/d (194 MMcf/d working interest to the Company). Contracts have been signed for the equivalent of approximately 1,508 MMcf/d (151 MMcf/d working interest to the Company) and the customers are currently taking approximately 1,280 MMcf/d (128 MMcf/d working interest to the Company). Exploration India D6 Block: The AR2 and AS1 discoveries were drilled in proximity to the R1 well. These wells extended the gas accumulation originally discovered by the R1 well and as a result enhanced the potential natural gas resource in this area. The Company is currently drilling the BA2 well. The Company expects a continuous exploration drilling program to proceed on numerous prospects within the block. D4 Block: The initial interpretation of the data within the 3,600-square-kilometre 3D seismic survey acquired has identified several areas of interest, which will be fully analysed as part of the ongoing evaluation. Processing and interpretation of the data are expected to be completed in time for the Company to begin drilling in the second half of calendar 2010. Cauvery: The Khoja-1 well was drilled to a total vertical depth of 4,366 metres in June 2009. Indications of both oil and gas were encountered while drilling. Two drill stem tests were conducted, but both failed to recover a measurable flow of hydrocarbons to the surface and the well was abandoned. With the results of Khoja-1 confirming hydrocarbons in the area, the Company elected to drill the Khoja-2 well, which spudded in July 2009. The primary target of the well is the Cretaceous-Jurassic-Basement interval. Hazira Block: The 30-square-kilometre transition zone 3D seismic survey is designed to explore for deeper oil and gas targets in the eastern half of the Hazira block. The survey has been merged with the offshore 3D seismic previously acquired providing 3D seismic coverage of almost the entire Hazira block. Evaluation of results is well advanced and a multi-well drilling program will be proposed to commence in the first calendar quarter of 2010. NEC-25 Block: Approximately 1,000 square kilometres of 3D seismic have been acquired along the central portion of the northwest boundary of the previous 3D surveys. The AJ2 well finished drilling in July 2009 and discovered gas. Pakistan The 2,000-square-kilometre 3D seismic program acquired during fiscal 2009 is expected to identify stratigraphic potential, resolve structural complexity and indicate the presence of hydrocarbons. Processing of the 3D data should be completed in the third calendar quarter of 2009 with interpretation and selection of drilling locations to follow. Madagascar Interpretation of the 7,600 kilometres of reprocessed 2D seismic is continuing. Further evaluation of the block is planned including acquisition of a high-resolution multi-beam survey and a sea floor coring program intended to identify sea floor oil and gas seeps. Future work as prescribed in Phase II includes the acquisition of a 3D seismic program to be designed based on results of the 2D seismic reprocessing and the multi-beam survey. The Company expects to drill a well in the second calendar quarter of 2011. Kurdistan The 350 kilometre 2D seismic program has been completed covering the entire block including the surface structure that dominates the Qara Dagh block. Processing is nearing completion and interpretation has commenced. Interpretation will focus on resolving the sub-surface structural picture and characterizing potential reservoir sections leading to the selection of a drilling location. Drilling is expected to commence in the second calendar quarter of 2010. Indonesia Niko has acquired interests in several blocks in deepwater offshore Indonesia. Indonesia has long been a prolific oil and gas producing nation with very large reserves; however, its deepwater areas have remained essentially unexplored. All blocks have sea bottom oil and gas seeps and large structural features, and several have direct indication of hydrocarbons on seismic. The single well commitment for each block will follow seismic acquisition and interpretation. The seismic program planned for each block is outlined below: /T/ ---------------------------------------------------------------------------- Block Planned seismic ---------------------------------------------------------------------------- Bone Bay 3,000 kilometres of 2D ---------------------------------------------------------------------------- Cendrawasih 1,200 square kilometres of 3D ---------------------------------------------------------------------------- Kofiau 1,062 kilometres of 2D, 3,150 square kilometres of 3D ---------------------------------------------------------------------------- Kumawa 3,000 kilometres of 2D ---------------------------------------------------------------------------- Seram 3,500 kilometres of 2D ---------------------------------------------------------------------------- South Matindok 4,400 kilometres of 2D ---------------------------------------------------------------------------- Southeast Ganal 284 kilometres of 2D, 2,700 square kilometres of 3D ---------------------------------------------------------------------------- West Sageri 371 kilometres of 2D, 702 square kilometres of 3D ---------------------------------------------------------------------------- /T/ The Company has arranged for a major international seismic contractor to shoot a 3D spec survey in both the Southeast Ganal and West Sageri blocks, and this program commenced in July 2009. Additional 2D seismic surveys will also be acquired in these blocks and a contract for these surveys is expected to be signed in September 2009 with acquisition to commence prior to the end of 2009. This 2D vessel will also conduct new seismic surveys in the Bone Bay, South Matindok, Kofiau and Seram blocks. In the Kofiau Block, both a 2D and a major 3D seismic program are planned and acquisition of the 3D is expected to commence in the fourth quarter of calendar 2009. Trinidad In July 2009, the Company acquired the right to earn a 26 percent interest and operate the 1,605 square-kilometre shallow water block 2AB offshore Trinidad. Both the assignment of the interest and the operatorship are subject to approval from the government of Trinidad and Tobago. The Company has minimum work commitments to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells within three years. OPERATING EXPENSE During the three months ended June 30, 2009, operating expenses averaged US$0.45/Mcfe. Operating expenses increased during the quarter due to the start-up costs related to the commencement of D6 production while production rates were ramping up during the quarter and are anticipated to fall significantly on a unit-of-production basis once the D6 gas field is producing at designed capacity. Forward-Looking Information and Material Assumptions This report on results for the three months ended June 30, 2009 contains forward-looking information including forward-looking information about Niko's operations, reserve estimates, production and capital spending. Forward-looking information is generally signified by words such as "forecast", "projected", "expect", "anticipate", believe", "will" and similar expressions. This forward-looking information is based on assumptions that the Company believes were reasonable at the time such information was prepared, but assurance cannot be given that these assumptions will prove to be correct, and the forward-looking information in this report on results for the quarter ended June 30, 2009 should not be unduly relied upon. The forward-looking information and the Company's assumptions are subject to uncertainties and risks and are based on a number of assumptions made by the Company, any of which may prove to be incorrect. Forward-looking information in this report on the results ended June 30, 2009 includes, but is not limited to, the following: Forecast production rates: The Company prepares production forecasts taking into account historical and current production, actual and planned events that are expected to increase or decrease production and production levels indicated in the Company's reserve reports. Forecast capital spending and commitments: The Company prepares capital spending forecasts based on internal budgets for operated properties, budgets prepared by the Company's joint venture partners, when available, for non-operated properties, field development plans and actual and planned events that are expected to affect the timing or amount of the capital spending. Forecast operating expenses: The Company prepares operating expense forecasts based on historical and current levels of expenses and actual and planned events that are expected to increase or decrease production and/or the associated expenses. Timing of production increases, timing of commencement of production and timing of capital spending: The Company discloses the nature and timing of expected future events based on the Company's budgets, plans, intentions and expected future events for operated properties. The nature and timing of expected future events for non-operated properties are based on budgets and other communications received from the Company's joint venture partners, when available. The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis and updates reserves on an annual basis. Refer to "Risk Factors" contained in the Company's management's discussion and analysis for discussion of uncertainties and risks that may cause actual events to differ from forward-looking information provided in this report on results for the three months ended June 30, 2009. MANAGEMENT'S DISCUSSION AND ANALYSIS This Management's Discussion and Analysis (MD&A) of the financial condition, results of operations and cash flows of Niko Resources Ltd. ("Niko" or "the Company") for the three months ended June 30, 2009 should be read in conjunction with the audited consolidated financial statements and accompanying notes for the year ended March 31, 2009. This MD&A is effective August 12, 2009. Additional information relating to the Company, including the Company's Annual Information Form (AIF), is available on SEDAR at www.sedar.com. Effective March 31, 2009, the Company adopted the U.S. dollar as its reporting currency. All financial information is presented in U.S. dollars unless otherwise indicated. Certain prior-year amounts have been reclassified to conform to current-year presentation and to a U.S. dollar reporting currency. The term "the quarter" is used throughout the MD&A and in all cases refers to the period from April 1, 2009 through June 30, 2009. The term "prior year's quarter" is used throughout the MD&A for comparative purposes and refers to the period from April 1, 2008 through June 30, 2008. The fiscal year for the Company is the 12-month period ended March 31. The terms "fiscal 2010", "current year" and "the year" are used throughout the MD&A and in all cases refer to the period from April 1, 2009 through March 31, 2010. The terms "prior year" and "fiscal 2009" are used throughout the MD&A for comparative purposes and refer to the period from April 1, 2008 through March 31, 2009. The term "fiscal 2008" is used throughout the MD&A for comparative purposes and refers to the period from April 1, 2007 through March 31, 2008. Mcfe (thousand cubic feet equivalent) is a measure used throughout the MD&A. Mcfe is derived by converting oil and condensate to natural gas in the ratio of 1 bbl:6 Mcf. Mcfe may be misleading, particularly if used in isolation. An Mcfe conversion ratio of 1 bbl:6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. MMbtu (million British thermal units) is a measure used in the MD&A. It refers to the energy content of natural gas (as well as other fuels) and is used for pricing purposes. One MMbtu is equivalent to 1 Mcfe plus or minus 20 percent, depending on the composition and heating value of the natural gas in question. Less than 1 percent of total corporate volumes and total corporate revenue are from Canadian oil, Bangladeshi condensate and Hazira condensate production. Therefore, the results from Canadian oil, Bangladeshi condensate and Hazira condensate production are not discussed separately. Forward-Looking Information and Material Assumptions This MD&A contains forward-looking information including forward-looking information about Niko's operations, reserve estimates, production and capital spending. Forward-looking information is generally signified by words such as "forecast", "projected", "expect", "anticipate", believe", "will" and similar expressions. This forward-looking information is based on assumptions that the Company believes were reasonable at the time such information was prepared, but assurance cannot be given that these assumptions will prove to be correct, and the forward-looking information in this MD&A should not be unduly relied upon. The forward-looking information and the Company's assumptions are subject to uncertainties and risks and are based on a number of assumptions made by the Company, any of which may prove to be incorrect. Forward-looking information in this MD&A includes, but is not limited to, the following: Forecast production rates: The Company prepares production forecasts taking into account historical and current production, actual and planned events that are expected to increase or decrease production and production levels indicated in the Company's reserve reports. Forecast capital spending and commitments: The Company prepares capital spending forecasts based on internal budgets for operated properties, budgets prepared by the Company's joint venture partners, when available, for non-operated properties, field development plans and actual and planned events that are expected to affect the timing or amount of the capital spending. Forecast operating expenses: The Company prepares operating expense forecasts based on historical and current levels of expenses and actual and planned events that are expected to increase or decrease production and/or the associated expenses. Timing of production increases, timing of commencement of production and timing of capital spending: The Company discloses the nature and timing of expected future events based on the Company's budgets, plans, intentions and expected future events for operated properties. The nature and timing of expected future events for non-operated properties are based on budgets and other communications received from the Company's joint venture partners, when available. The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis and updates reserves on an annual basis. Refer to "Risk Factors" contained in this MD&A for discussion of uncertainties and risks that may cause actual events to differ from forward-looking information provided in this MD&A. Non -GAAP Measures The selected financial information presented throughout the MD&A is prepared in accordance with Canadian generally accepted accounting principles (GAAP), except for "funds from operations", "operating netback", "funds from operations netback", "earnings netback" and "segment profit", which are used by the Company to analyze the results of operations. By examining funds from operations, the Company is able to assess its past performance and to help determine its ability to fund future capital projects and investments. Funds from operations is calculated as cash flows from operating activities prior to the change in operating non-cash working capital and the change in long-term accounts receivable. By examining operating netback, funds from operations netback, earnings netback and segment profit, the Company is able to evaluate past performance by segment and overall. Operating netback is calculated as oil, natural gas revenues less royalties, profit petroleum expenses and operating expenses for a given reporting period, per thousand cubic feet equivalent (Mcfe) of production for the same period, and represents the before-tax cash margin for every Mcfe sold. Funds from operations netback is calculated as the funds from operations per Mcfe and represents the cash margin for every Mcfe sold. Earnings netback is calculated as net income per Mcfe and represents net income for every Mcfe sold. Segment profit is defined as oil, natural gas and pipeline revenues less royalties, profit petroleum expenses, operating and pipeline expenses, depletion, depreciation and accretion expense and current income taxes related to each business segment. The Company defines working capital as current assets less current liabilities and uses working capital as a measure of the Company's ability to fulfill obligations with current assets. These non-GAAP measures do not have any standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other companies. /T/ OVERALL PERFORMANCE Funds from Operations Three months ended June 30, (thousands of U.S. dollars) 2009 2008 ---------------------------------------------------------------------------- Oil and natural gas revenues $ 53,853 $ 24,381 Royalties (2,521) (1,155) Profit petroleum (7,224) (5,478) Operating and pipeline expense (6,607) (2,319) Interest income 85 4,235 Interest and financing (3,367) - General and administrative expense (1,531) (2,716) Realized foreign exchange (loss) gain (627) 663 Current income tax expense (3,797) (1,528) ---------------------------------------------------------------------------- Funds from operations (1) $ 28,264 $ 16,083 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Funds from operations is a non-GAAP measure as calculated above. /T/ Natural gas production from the Dhirubhai 1 and 3 gas fields in the D6 Block commenced in April 2009, resulting in a US$23.9 million increase in revenues. There was also an increase in Bangladesh revenue as a result of facility upgrades at Block 9. Royalties, operating expense and income tax expense increased with the addition of D6 gas production and profit petroleum increased as the Company shared profits from Surat with the Indian government during the quarter. Profit petroleum payable to the Indian government with respect to the D6 Block was US$0.3 million or one percent of revenues. Interest income decreased primarily due to lower average cash balances and lower rates of interest earned during the quarter. The interest expense relates to the lease of the Floating Production, Storage and Offloading vessel (FPSO) for D6 oil production and interest expense on the long-term debt. The net decrease in general and administrative expenses was attributable to lower employee bonuses and increased overhead recoveries. The realized foreign exchange loss in the quarter was a result of the weakening of the U.S. dollar against the Indian rupee. /T/ Net Income Three months ended June 30, (thousands of U.S. dollars) 2009 2008 ---------------------------------------------------------------------------- Funds from operations (non-GAAP measure) $ 28,264 $ 16,083 Unrealized foreign exchange (loss) (3,582) (2,275) Gain on short-term investment 18,003 6,875 Equity (loss) on long-term investment (91) - Gain on risk management contracts - 954 Discount of long-term account receivable (48) (100) Stock-based compensation expense (5,408) (4,403) Depletion, depreciation and accretion (16,697) (10,867) ---------------------------------------------------------------------------- Net income $ 20,441 $ 6,267 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Net income increased substantially in the quarter over the prior year's quarter. The main causes of the increase were the quarter-over-quarter increase in revenues, as discussed above, which resulted in higher funds from operations, and a gain on the short-term investment. The unrealized foreign exchange loss was primarily a result of the weakening of the U.S. dollar against the Canadian dollar. The gain on the short-term investment is a result in the change in market value. The equity loss on the long-term investment is related to the Company's investment in Vast Exploration Inc. The gain on risk management contracts in the prior year's quarter related to the Company's interest rate swaps. The Company continues to discount the long-term account receivable to fair value. The increase in stock-based compensation was attributable to both an increased number of options being expensed during the quarter and an increased fair value expense per stock option. Depletion expense increased primarily due to the commencement of gas production from the D6 Block. BACKGROUND ON PROPERTIES Niko Resources Ltd. is engaged in the exploration for and, where successful, the development and production of natural gas and oil in India, Bangladesh, Pakistan, the Kurdistan region of Iraq, Madagascar, Indonesia and Trinidad. The Company has agreements with the governments of these countries or with other companies operating in these countries and regions for rights to explore for and, if successful, produce natural gas and oil. The Company generally is granted an exploration licence to commence work. The agreements generally involve a number of exploration phases with specified minimum work commitments and the maximum number of years to complete the work. At the end of any exploration phase, the Company has the option of continuing to the next exploration phase and may be required to relinquish a portion of the non-development acreage to the respective government. If a commercial discovery is not made by the end of all the exploration phases, the Company's rights to explore the block generally terminate. In the event of a discovery that is determined to be commercial, the Company prepares a development plan and applies to the government for a petroleum mining licence. The petroleum mining licences are for a specified number of years and may be extended under certain circumstances. During the production phase, the Company is required to pay any royalties specified in the agreements and taxes applicable in the country. The Company pays to the government an increasing share of the profits based on an Investment Multiple (IM) or on production levels plus an IM, or a fixed share of profits, depending on the agreement. The IM is the number of times the Company has recovered its investment in the property from its share of profits from the property. At the end of the life of the field or the mining licence, the field and the assets revert to the government; however, the Company is responsible for the costs of abandonment and restoration. India Cauvery - The Company operates the block, which covers 957 square kilometres. The production exploration licence was granted for a period of 20 years; however, the exploration phases in the agreement cover seven years. The Company has performed the seismic work and drilled three of the five wells required under the first exploration phase. The Company is currently drilling the fourth exploration well. The Company has received a six-month extension to the exploration period to January 2010. Depending on exploration results, the Company will apply to the government for another extension to the first exploration period in order to have sufficient time to complete the work commitment and assess the potential of the block. The Indian government has historically granted extensions, when required; however, there is a risk that a further extension may not be granted to the Company and the rights to continue exploration on the block would cease. D4 - The Company has a 15 percent interest in the D4 Block, located in the Mahanadi Basin offshore the east coast of India. The block, which is currently in the exploration phase, encompasses more than 17,000 square kilometres. The commitment for Phase I exploration includes seismic work and drilling three exploration wells. Originally, the work commitment was to be completed by September 2009; however, the Government of India is in the process of approving a blanket extension of up to three years for this and other deepwater blocks, prompted by the shortage of deepwater drilling rigs. The seismic work has been completed and is ready for processing. D6 - The Company has a 10 percent working interest in the 7,645-square-kilometre D6 Block. In addition to continued exploration on the block there are two development projects: the MA oil discovery and the Dhirubhai 1 and 3 natural gas discoveries. Production from the MA discovery began in September 2008 and from the Dhirubhai 1 and 3 discoveries in April 2009. The Company has been granted a petroleum mining licence for a period of 20 years. Oil production is sold on the spot market at a price based on Bonny Light and adjusted for quality. Gas production is sold under long-term gas contracts using a pricing formula approved by the Government of India, which currently results in a price of US$4.20/MMbtu and there is a marketing margin of US$0.135/MMBtu earned in addition to the price formula. Net of adjustments for heating value, the sales price is approximately US$3.95/Mcf. The development plan for nine additional natural gas discoveries in the D6 Block was submitted to the Government of India in July 2008. The discoveries are adjacent to the Dhirubhai 1 and 3 gas fields that are currently producing. If the development plan is approved, it is intended that these satellite discoveries be tied back to the Dhirubhai 1 and 3 facilities. Under the terms of the production sharing contract (PSC) with the Government of India for the D6 block, the Company is required to pay the government a royalty of 5 percent of the well-head value of crude oil and natural gas for the first seven years from the commencement of commercial production in the field and thereafter to pay 10 percent. In addition, the Company pays a percentage of the profits from the block to the government, which varies with the Investment Multiple (IM). The Company pays 10 percent of profits when the IM is less than 1.5; 16 percent between 1.5 and 2; 28 percent between 2 and 2.5; and 85 percent thereafter. Hazira - The Company has a 33 percent working interest in the 50-square-kilometre Hazira onshore and offshore block on the west coast of India, which lies adjacent to a large industrial corridor about 25 kilometres southwest of the city of Surat. The Company has a petroleum mining licence that expires in September 2014. The Company has three contracts for the sale of gas production from the field expiring between October 2009 and April 2016 at current prices up to US$5.00/Mcf and sells any production in excess of contracted amounts to one of the contracted customers at a price of US$4.87/Mcf. In addition to the price indicated, the Company collects the 10 percent royalty, that is payable to the government, from the customer. The Company pays a percentage of the profits from the block to the government, which varies with the Investment Multiple (IM). The Company does not share profits when the IM is less than one; shares 10 percent of profits between one and 1.5; 20 percent between 1.5 and 2; 25 percent between 2 and 2.5; 35 percent between 2.5 and 3; and 40 percent thereafter. NEC-25 - The Company has a 10 percent working interest in the NEC-25 Block, which covers 10,755 square kilometres in the Mahanadi Basin off the east coast of India. The Company has fulfilled its capital commitments for the block and is currently drilling under an appraisal program. Development plans have been submitted for the six gas discoveries that have been declared commercial by the Indian regulatory authorities. Surat - The Company holds a development area of 24 square kilometres containing the Bheema and NSA shallow natural gas fields. These fields have been producing natural gas since April 2004. The Company has a petroleum mining licence that expires in September 2024. The Company has one contract for the sale of gas production from the field expiring on March 31, 2011 at a price of US$5.50/Mcf until March 31, 2010 and US$6.00/Mcf until expiry. In addition to the price indicated, the Company collects the 9 percent royalty, payable to the government, from the customer. In addition, the Company will pay a percentage of the profits from the block to the government, which varies with the Investment Multiple (IM). The Company shares 20 percent of profits when the IM is between one and 1.5; 30 percent between 1.5 and 2; 40 percent between 2 and 2.5; 50 percent between 2.5 and 3; and 60 percent thereafter. Bangladesh Block 9 - The Company holds a 60 percent interest in this 6,880-square-kilometre onshore block which encompasses the capital city of Dhaka. The Company has fulfilled its obligations under the exploration period for the block. Natural gas and condensate production from this field began in May 2006. As per the PSC, the Company has rights to produce for a period of 25 years and this arrangement is extendable if production continues beyond this period. The Company sells gas under a gas purchase and sales agreement (GPSA) at a current price of US$2.34/MMbtu for a period up to 25 years. The Company shares a percentage of the profits from the block with the government, which varies with production and whether or not the Company has recovered its investment. The Company pays to the government 61 percent and 66 percent of profits, respectively, before and after costs are recovered on natural gas production up to 150 MMcf/d; 66 percent and 72.5 percent on natural gas production between 150 MMcf/d and 300 MMcf/d; 72.5 percent and 78 percent on production between 300 MMcf/d and 450 MMcf/d; 75 percent and 82.5 percent on production between 450 MMcf/d and 600 MMcf/d; and 82 percent and 85 percent on production in excess of 600 MMcf/d. Profits on natural gas are calculated as the minimum of (i) 55 percent of revenue for the period and (ii) revenue less operating and capital costs incurred to date. Feni and Chattak - The Feni field covers 43 square kilometres and is located 6 kilometres west of the main natural gas line to Chittagong. The Chattak structure covers 376 square kilometres and rights to this block were obtained in October 2003. The Company has been producing natural gas from the Feni field since November 2004. As per the joint venture agreement (JVA), the Company has rights to produce until October 2023 and this arrangement can be extended if production continues beyond this period. The Company sells gas under a GPSA including a price of US$1.75 per Mcf, which expires in November 2009 and can be extended with mutual consent. Receipt of payment for the gas is being delayed as a result of various claims raised against the Company as described in note 11 to the unaudited consolidated financial statements for the three months ended June 30, 2009. The Company pays a percentage of the profits from the field to the government, which varies with the Investment Multiple (IM). The Company shares 20 percent of profits from the Feni field when the IM is less than one; 25 percent between 1 and 1.5; 32 percent between 1.5 and 2; 38 percent between 2 and 3; and 42 percent thereafter. Future drilling activities at Feni and Chattak have been postponed pending resolution of overdue payment for gas owed to the Company by the Government of Bangladesh. Pakistan Four production sharing agreements (PSAs) were signed in March 2008. The blocks are located in the Arabian Sea offshore the city of Karachi and cover an area of almost 10,000 square kilometres. Each agreement is for an initial exploration term of five years with two exploration renewal periods of two years each and further renewal in the event of commercial production. The blocks are currently in Phase I of the exploration period, which expires in March 2010, and have work commitments for a minimum of 200 square kilometres of 3D seismic in each block. A 2,000-square-kilometre 3D seismic program has been completed and, once processed, will fulfill the work commitment under Phase I. To retain the blocks for the full five-year exploration period, the Company will need to acquire additional seismic or drill one well. Kurdistan Region In May 2008 the Company signed a PSC for the onshore Qara Dagh block, which covers approximately 846 square kilometres, in the Sulaymaniyah Governorate of the Federal Region of Kurdistan in Iraq. The Company currently has a 36 percent interest and carries the proportionate cost for the regional government's interest, resulting in a 45 percent cost interest. The exploration period is for a term of five years and is extendable by two one-year terms. The first exploration phase is for three years expiring in May 2011 and the Company has commitments under this phase for seismic and drilling one exploratory well. Processing of the seismic program is nearing completion and interpretation has commenced. Madagascar In October 2008 the Company farmed-in to a PSC for a property off the west coast of Madagascar. The farm-in agreement and appointment of the Company as operator have been approved by the Office of National Mines and Strategic Industries, which acts on behalf of the Republic of Madagascar. The PSC covers 16,845 square kilometres in water depths ranging from shallow water to 1,500 metres. The Company completed a 31,944-line-kilometre aero-magnetic survey applicable to the Phase I work commitment. The Company has remaining work commitments under the first exploration phase for 2,000 kilometres of 2D seismic, which must be completed by June 2010. Indonesia As at March 31, 2009, the Company had acquired rights in PSCs for interests in five deep-water offshore exploration blocks covering almost 25,000 square kilometres. The Company will operate two of the blocks, South East Ganal and West Sageri, and will earn a 51 percent working interest. These blocks are located in the Makassar Strait. The Company will participate in the South Matindok, Seram and Bone Bay blocks and earn a 25 percent working interest therein. The South Matindok block is located in northeast Sulawesi, the Seram block is located in north Seram and the Bone Bay block is located in southwest Sulawesi. Each of the blocks is in the first exploration period, which expires in November 2011. The Company has minimum work commitments in this period to acquire and process 16,550 kilometres of 2D seismic in total for the five blocks and drill one well in each of the five blocks. In May 2009, the Company and its partners were awarded three additional offshore exploration blocks: Kofiau, Kumawa and Cendrawasih. The Company will operate the Kofiau block and will earn a 67 percent working interest. This block is located in west Papua. In the Kumawa and Cendrawasih blocks, which will not be operated by the Company, the Company will earn a 25 percent working interest. These blocks are located in southwest and northwest Papua, respectively. Each of these three Indonesian blocks is in the first exploration period, which expires in May 2012, and the Company has minimum work commitments for the acquisition of 4,042 kilometres of 2D seismic, 1,200 square kilometres of 3D seismic, drilling one well per block and various payments under the agreements. Trinidad In July 2009, the Company acquired the right to earn a 26 percent interest and operate the 1,605 square-kilometre shallow water block 2AB offshore Trinidad. Both the assignment of the interest and the operatorship are subject to approval from the government of Trinidad and Tobago. The Company has minimum work commitments to acquire and process 864 square kilometres of 3D seismic, acquire an aero-gravity survey on the block and drill three exploration wells within three years. /T/ CAPITAL EXPENDITURES Exploration Spending (Net to the Company) Actual spending for the Forecast spending three months ended for July 1, 2009 to (millions of U.S. dollars) June 30, 2009 (1) March 31, 2010 (2) ---------------------------------------------------------------------------- India 21.7 49 Indonesia 5.6 26 Kurdistan Region 6.5 9 Madagascar 0.5 6 Pakistan - 3 Trinidad - 7 ---------------------------------------------------------------------------- Total 34.3 100 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) The Company also spent US$0.4 million on new ventures and other. (2) Refer to "Forward-Looking Information and Material Assumptions" in this MD&A for a description of how forecast capital expenditures are estimated. /T/ Indian capital spending in the quarter included costs of drilling the Khoja-1 well in Cauvery (US$10.0 million), seismic work in the D4 block (US$0.2 million), costs of drilling the AJ2 well in NEC-25 (US$2.7 million) and exploratory drilling in the D6 Block (US$8.8 million). Forecast capital spending for India includes drilling the remaining wells under the work commitment for Cauvery, processing of the 3D seismic acquired in D4 and further exploratory drilling in the D6 Block. The Company paid a signing bonus with respect to the Kofiau block in Indonesia in the quarter. Forecast capital spending in Indonesia is for seismic. Costs of US$6.5 million were incurred in Kurdistan, primarily for seismic and various bonuses required as per the PSC. Costs of US$0.5 million were incurred in Madagascar for the acquisition and reprocessing of existing 2D seismic data. Expenditures are forecast for a multi-beam survey. Forecast expenditures in Pakistan are for processing of the seismic survey acquired in fiscal 2009. The forecast expenditure for Trinidad includes the signing bonus, other bonuses required as per the PSC and seismic. /T/ Development Spending (Net to the Company) Actual spending for the Forecast spending three months ended for July 1, 2009 to (millions of U.S. dollars) June 30, 2009 March 31, 2010 (1) ---------------------------------------------------------------------------- Bangladesh 7.8 3 India 30.7 164 (2) ---------------------------------------------------------------------------- Total 38.5 167 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Refer to "Forward-Looking Information and Material Assumptions" in this MD&A for a description of how forecast capital expenditures are estimated. (2) Includes payment of amounts accrued and included in accounts payable on the balance sheet of US$51 million. /T/ Bangladesh development was for the remaining costs of the facilities upgrades, well testing and payment of the guarantee associated with the work commitment for the block. Indian development spending was primarily for the D6 development including completion and tie-in of additional wells and construction of facilities for the Dhirubhai 1 and 3 gas fields and drilling of an additional well and tie-in of existing wells in the MA oil field. The development is to continue throughout fiscal 2010. /T/ SEGMENT PROFIT India Three months ended June 30, (thousands of U.S. dollars, except as indicated) 2009 2008 ---------------------------------------------------------------------------- Natural gas revenue 35,376 11,372 Oil revenue (1) 4,212 1,590 Royalties (2,508) (1,101) Profit petroleum (2,496) (1,811) Operating and pipeline expenses (5,008) (1,183) Depletion, depreciation and accretion (10,111) (6,108) Current income tax expense (3,731) (1,105) ---------------------------------------------------------------------------- Segment profit (2) 15,734 1,654 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Daily natural gas sales (Mcf/d) 89,704 26,238 Daily oil sales (bbls/d) (1) 711 162 Depletion rate (US$/Mcfe) 1.16 2.40 ---------------------------------------------------------------------------- (1) Production that is in inventory has not been included in the revenue or cost amounts indicated. (2) Segment profit is a non-GAAP measure as calculated above. /T/ Revenue and Royalties Natural gas production from the Dhirubhai 1 and 3 gas fields in the D6 Block commenced in April 2009, resulting in a US$23.9 million increase in revenues. Average sales volume for the period was 66 MMcf/d with an exit rate in excess of 100 MMcf/d. Production rates are expected to continue to ramp-up over the course of the year. The contracted sales price includes a gas price of US$4.20/MMBtu and a marketing margin earned of US$0.135/MMBtu, resulting in a sales price of US$3.95/Mcf. Oil production from the MA field in the D6 Block commenced in September 2008. Sales during the quarter averaged 500 bbls/d and increased revenues by US$3.1 million. Oil production from the Hazira block averaged 211 bbls/d in the quarter compared to 162 bbls/d in the prior year's quarter. The average oil sales price was US$65.22 in the quarter compared to US$112.96 in the prior year's quarter and moved in accordance with world market prices. The increase in royalties is a result of the commencement of oil and gas production from the D6 Block since the prior year's quarter. Royalties applicable to production from the D6 Block are 5 percent for the first seven years of production and royalties applicable to the Hazira and Surat fields are currently 10 and 9 percent, respectively. Profit Petroleum Pursuant to the terms of the PSCs the Government of India is entitled to a sliding scale share in the profits once the Company has recovered its investment. For Hazira, in the quarter and the prior year's quarter, the government was entitled to 25 percent of the cash flow, defined as revenue less royalties, operating expenses and capital expenditures. For Surat, the Company recovered its investment since the prior year's quarter and began sharing profits, defined as revenue less royalties, operating expenses and capital expenditures, with the government at a rate of 20 percent. For the D6 Block, the Company is able to use up to 90 percent of profits to recover costs including royalties, operating expenses and capital expenses. The government was entitled to 10 of the profits not used to recover costs during the quarter. Profit petroleum with respect to the D6 Block was US$0.3 million or one percent of revenues and will continue at this level until the Company has recovered its costs. The net increase in profit petroleum in the quarter was primarily a result of profit petroleum payments commencing for Surat and was partially offset by decreased profit petroleum payments for Hazira due to a lower oil price and lower gas production than in the prior year's quarter. Operating Expenses Operating expenses in the quarter increased due to the start-up costs related to the commencement of D6 production since the prior year's quarter. Operating expenses are expected to decrease on a unit-of-production basis as the production from the D6 gas field ramps up. Depletion, Depreciation and Accretion The depletion rate per Mcfe decreased in the quarter due to the inclusion of the capital costs and the reserves attributed to the D6 Block in the calculation for the Indian cost base. The undepleted capital costs per Mcfe are less for the D6 Block than for the Hazira and Surat fields. Income Taxes There was an increase in income tax expense in the quarter of US$2.7 million on the profits from the D6 Block, which commenced production since the prior year's quarter. The Company has a contingency related to income taxes as at June 30, 2009. Refer to the unaudited consolidated financial statements and notes for the three months ended June 30, 2009 for a complete discussion of the contingency. /T/ Bangladesh Three months ended June 30, (thousands of U.S. dollars, except as indicated) 2009 2008 ---------------------------------------------------------------------------- Natural gas revenue 13,765 10,469 Condensate revenue 394 613 Profit petroleum (4,729) (3,667) Operating expenses (1,574) (1,122) Depletion, depreciation and accretion (6,053) (4,599) Current income tax expense (10) (21) ---------------------------------------------------------------------------- Segment profit (1) 1,793 1,673 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Daily natural gas production (Mcf/d) 65,326 50,807 Depletion rate (US$/Mcfe) 1.01 1.00 ---------------------------------------------------------------------------- (1) Segment profit is a non-GAAP measure as calculated above. /T/ Revenue, Profit Petroleum, Depletion and Operating Expenses Overall, Bangladesh revenue increased as a result of facility upgrades at Block 9. The Company has been receiving its 60 percent share of production from Block 9 as well as 6.67 percent of production in order to recover amounts the Company paid in relation to the Government of Bangladesh's share of costs in the block prior to declaration of commerciality in accordance with the PSC. The Company expects that it will finish recovering the amounts paid on behalf of the Government's share in fiscal 2010 and its share of production will be 60 percent. Pursuant to the terms of the PSC for Block 9, the Government of Bangladesh was entitled to 61 percent of profit gas in the quarter and prior year's quarter. Profit petroleum expense increased due to increased revenues from Block 9. Operating costs and depletion expense increased primarily as a result of increased production from Block 9. Income Taxes The Company pays taxes for the Feni property in Bangladesh at a rate of 4.0 percent of revenues net of profit petroleum. The Company does not pay income taxes related to Block 9 production, as indicated in the PSC. The PSC indicates that the calculation of profit petroleum expense includes consideration of income taxes and, therefore, no income tax is assessed for Block 9. NETBACKS The following table outlines the Company's operating, funds from operations and earnings netbacks (all of which are non-GAAP measures) for the three months ended June 30, 2009 and 2008: /T/ Three months ended June 30, 2009 ---------------------------------------------------------------------------- India Bangladesh Total (US$/Mcfe) (US$/Mcfe) (US$/Mcfe) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Oil and natural gas revenue 4.63 2.37 3.70 Royalties (0.29) - (0.17) Profit petroleum (0.29) (0.79) (0.50) Operating and pipeline expense (0.59) (0.26) (0.45) ---------------------------------------------------------------------------- Operating netback 3.46 1.32 2.58 Interest income 0.01 Interest and financing expense (0.23) General and administrative expense (0.11) Realized foreign exchange gain (loss) (0.04) Current tax expense (0.27) ---------------------------------------------------------------------------- Funds from operations netback 1.94 Unrealized foreign exchange (loss) (0.25) Discount of long-term account receivable - Stock-based compensation expense (0.37) Gain on short-term investment 1.24 Equity loss on long-term investment (0.01) Gain on risk management contracts - Depletion, depreciation and accretion expense (1.15) ---------------------------------------------------------------------------- Earnings netback 1.40 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three months ended June 30, 2008 ---------------------------------------------------------------------------- India Bangladesh Total (US$/Mcfe) (US$/Mcfe) (US$/Mcfe) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Oil and natural gas revenue 5.24 2.38 3.41 Royalties (0.44) - (0.16) Profit petroleum (0.73) (0.79) (0.77) Operating and pipeline expense (0.48) (0.24) (0.32) ---------------------------------------------------------------------------- Operating netback 3.59 1.35 2.16 Interest income 0.59 Interest and financing expense - General and administrative expense (0.38) Realized foreign exchange gain (loss) 0.09 Current tax expense (0.21) ---------------------------------------------------------------------------- Funds from operations netback 2.25 Unrealized foreign exchange (loss) (0.32) Discount of long-term account receivable (0.01) Stock-based compensation expense (0.62) Gain on short-term investment 0.96 Equity loss on long-term investment - Gain on risk management contracts 0.13 Depletion, depreciation and accretion expense (1.51) ---------------------------------------------------------------------------- Earnings netback 0.88 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ The netback for India, Bangladesh and in total for the Company is a non-GAAP measure calculated by dividing the revenue and costs for each country and in total for the Company by the total sales volume for each country and in total for the Company measured in Mcfe. /T/ CORPORATE Three months ended June 30, (thousands of U.S. dollars) 2009 2008 ---------------------------------------------------------------------------- Revenues Interest income 85 4,235 Gain on short-term investment 18,003 6,875 Gain on risk management contracts - 954 Expenses Interest and financing 3,367 - General and administrative expenses 1,531 2,716 Foreign exchange loss 4,209 1,612 Stock based-compensation expense 5,408 4,403 Equity loss on long-term investment 91 - Current income tax expense 56 402 ---------------------------------------------------------------------------- /T/ Interest Income Interest income decreased primarily due to lower average cash balances and lower rates of interest earned during the quarter. Gain on Short-term Investment During the quarter, the Company held securities in an entity that represents a strategic opportunity. The unrealized gain on the investment during the quarter was a result of the change in market value. Gain on Risk Management Contracts There were no interest rate swaps outstanding during the quarter. In the prior year's quarter, the Company had a series of interest rate swaps to fix the floating interest rate on a portion of the long-term debt, as required by the credit facility. There was an unrealized gain in the prior year's quarter on the recognition of the fair value of the interest rate swaps due to the increase in forecast LIBOR rates during the period, which decreased the differential compared to the fixed interest rate. Interest and Financing The Company entered into a lease for the FPSO, which has been classified as a capital lease. As a result, the Company recognized US$0.9 million of lease payments as an interest cost. Interest expense on the long-term debt was US$2.5 million. General and Administrative Expense The net decrease in general and administrative expense in the quarter from the prior year's quarter was a result of lower employee bonuses and increased overhead recoveries as a result of increased capital activities in Cauvery, Kurdistan and Madagascar. The decrease was partially offset by a higher use of outside services as a result of increased Company activity. /T/ Foreign Exchange Three months ended June 30, (thousands of U.S. dollars) 2009 2008 ---------------------------------------------------------------------------- Realized foreign exchange loss (gain) 627 (663) Unrealized foreign exchange loss 3,582 2,275 ---------------------------------------------------------------------------- Total foreign exchange loss 4,209 1,612 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ There was a realized foreign exchange loss in the quarter primarily on the settlement of Indian rupee-denominated working capital created by the weakening U.S. dollar against the Indian rupee applied to the settlement of working capital during the quarter. The unrealized foreign exchange loss was primarily on the translation of U.S. dollar-held cash to Canadian dollars, partially offset by a gain on translating the Indian rupee-denominated income tax receivable to U.S. dollars as a result of the weakening of the U.S. dollar against the Canadian dollar and the Indian rupee, respectively. Stock-based Compensation The increase in stock-based compensation was attributable to both an increased number of options being expensed during the quarter and an increased fair value expense per stock option. Equity Loss on Long-term Investment The Company accounts for its investment in Vast Exploration Inc. using the equity method whereby the investment is initially recorded at cost and the carrying value is subsequently adjusted to include the Company's pro rata share of post-acquisition earnings of the investee. The Company recorded a loss of Cdn$0.1 million (US$0.1 million) calculated by the equity method during the quarter. The carrying value of the investment was Cdn$5.2 million (US$4.5 million) and the market value of the long-term investment at June 30, 2009 was Cdn$8.2 million (US$7.0 million). Income Taxes In Canada, there was an income tax adjustment related to the prior year tax return. In the prior year's quarter, there was income tax on interest income on cash balances outstanding. /T/ SUMMARY OF QUARTERLY RESULTS The following tables set forth selected financial information of the Company for the eight most recently completed quarters to June 30, 2009: (thousands of U.S. dollars, except per share amounts) Sept. 30, Dec. 31, Mar. 31, June 30, Three months ended 2008 2008 2009 2009 ---------------------------------------------------------------------------- Oil and natural gas revenue 24,064 28,045 28,503 53,853 Net income (loss) (22,420) (2,090) (4,319) 20,441 Per share Basic (US$) (0.46) (0.04) (0.09) 0.41 Diluted (US$) (0.46) (0.04) (0.09) 0.41 ---------------------------------------------------------------------------- (thousands of U.S. dollars, except per share amounts) Sept. 30, Dec. 31, Mar. 31, June 30, Three months ended 2007 2007 2008 2008 ---------------------------------------------------------------------------- Oil and natural gas revenue 27,875 22,467 23,576 24,381 Net income (loss) (16,573) 476 1,355 6,267 Per share Basic (US$) (0.37) 0.01 0.03 0.13 Diluted (US$) (0.37) 0.01 0.03 0.13 ---------------------------------------------------------------------------- /T/ Net income has fluctuated over the quarters, due in part to changes in net revenue, profit petroleum, discount on the long-term account receivable and the value of the short-term investment. There were forecast natural declines in production at the Hazira, Surat and Feni fields over the quarters, which were partially offset by increases in production from Block 9, both of which affected revenue. In the quarter ended December 31, 2007, there was a planned pressure survey in Block 9 resulting in decreased volumes in addition to the natural declines in the Hazira, Surat and Feni fields. In the quarter ended December 31, 2008, revenues increased due to an increase in production from Block 9 as a result of completion of a plant upgrade as well as the first sale of oil from the D6 block. In the quarter ended June 30, 2009, gas production from the D6 Block commenced, substantially increasing revenues. Profit petroleum expense increased in the quarter ended December 31, 2008 with the increase in revenues from Block 9. There was an asset impairment of US$22.8 million recognized in the quarter ended September 30, 2007 as a result of unsuccessful wells, workovers and associated costs in Thailand. In the quarter ended December 31, 2007, net income was reduced by US$4.3 million for a discount of the long-term account receivable to reflect the potential delay in collection as the account receivable may not be collected until resolution of various claims raised against the Company in Bangladesh. The Company occasionally purchases securities in entities that represent strategic opportunities and it made such purchases in fiscal 2008 and fiscal 2009. The short-term investment is recognized at fair value, which is the publicly quoted market value, and the Company recognizes gains and losses based on the changing market prices. The net income in the quarter ended June 30, 2008 and the net loss in the quarter ended September 30, 2008 are primarily a result of the gain and loss in the quarters, respectively. The losses continued through the quarter ended March 31, 2009. The net income in the quarter ended June 30, 2009 was primarily a result of the gain on the short-term investment in the quarter. LIQUIDITY AND CAPITAL RESOURCES At June 30, 2009, the Company had total restricted and unrestricted cash of US$170.4 million and a working capital surplus of US$106.8 million, calculated as current assets less current liabilities. The restricted portion of the cash balance was comprised of US$19.9 million of performance guarantees, US$3.5 million of cash restricted for future site restoration and US$118.7 million of cash restricted in accordance with the credit facility agreement. The cash that is currently restricted in accordance with the credit facility agreement may be used to fund development costs for Hazira, Surat, Block 9 and the D6 Block and the costs of operating the Hazira, Surat, Block 9 and the Dhirubhai 1 and 3 gas fields of the D6 Block. The Company has drawn US$192.8 million on its credit facility. No portion of the debt is due within the next 12 months. In April 2009, the credit facility was reduced to US$192.8 million. The Company plans to fulfill its planned capital spending including commitments and current liabilities with existing cash, future funds from operations and the permitted use of restricted cash, which is partially dependent on achieving project completion as defined in the facility agreement. The Company has a number of contingencies as at June 30, 2009. Refer to the unaudited consolidated financial statements and notes for the quarter for a complete list of the contingencies and the potential effects on the liquidity of the Company. The Company is able to make payments to Bangladesh vendors from its Feni and Chattak branch office, but is unable to repatriate funds from the Feni and Chattak branch office or to pay foreign vendors. The Company had the following work commitments under various agreements as at June 30, 2009: - D4 Block: The commitment for Phase I exploration includes seismic work and drilling three exploration wells. Originally, the work commitment was to be completed by September 2009; however, the Government of India is in the process of approving a blanket extension of up to three years for this and other deepwater blocks, prompted by the shortage of deepwater drilling rigs. The seismic work has been completed and is ready for processing and the cost of the remaining seismic-related work and drilling is estimated at US$77.4 million (US$11.6 million net to the Company). - Cauvery Block: The Phase I exploration period, which ends in 2009, includes commitments for seismic work and drilling five exploration wells. The Company has completed the seismic, has drilled three exploration wells and is currently drilling a fourth exploration well. The estimated cost of the remaining work commitment is US$12.3 million. - Pakistan: The Company has spent sufficient funds under Phase I of the initial term and processing of the seismic will fulfill the minimum work commitments. Phase I of the initial term expires in March 2010. To retain the blocks for the full five-year exploration period, the Company will need to acquire additional seismic or drill one well. - Kurdistan: The Company has minimum work commitments under Phase I of the exploration period for seismic and drilling an exploratory well, which must be completed by May 2011. The remaining capital expenditures related to the minimum work program are estimated at US$28.9 million (US$13.0 million net to the Company) and US$2.6 million (US$1.1 million net to the Company) for various payments under the agreement. - Madagascar: The Company has minimum work commitments for 2,000 kilometres of 2D seismic under Phase I of the exploration period, which expires in June 2010. - Indonesia: For the eight Indonesian blocks, the total remaining minimum work commitments, including seismic and one exploration well per block during the first exploration periods, are US$205.3 million (US$114.3 million net to the Company). This exploration period ends in November 2011 for five of the blocks and in May 2012 for the remaining three blocks. In July 2009, the Company signed an agreement to earn an interest in a block in Trinidad. The Company has minimum work commitments estimated to cost US$31.3 million to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells within three years. Although not committed, the Company has planned spending of US$97 million (net to the Company) and US$65 million (net to the Company) required to complete Phase I development of the Dhirubhai 1 and 3 gas fields and the MA oil field, respectively, and these costs are included in the capital forecast for fiscal 2010. RELATED PARTIES The Company has a 45 percent interest in a Canadian property that is operated by a related party, a Company owned by the President and CEO of Niko Resources Ltd. This joint interest originated as a result of the related party buying the interest of the third-party operator of the property in 2002. The transactions with the related party are not significant to the operations or the consolidated financial statements of the Company, are measured at the exchange amount, which is also considered to be the fair value, and are in the normal course of business. FINANCIAL INSTRUMENTS Financial instruments of the Company consist of cash, restricted cash, the short-term investment, accounts receivable, cash call advances, long-term accounts receivable, accounts payable and accrued liabilities and long-term debt. The Company is exposed to fluctuations in the value of its cash, accounts receivable, short-term investment, accounts payable and accrued liabilities due to changes in foreign exchange rates as these financial instruments are partially or wholly denominated in Canadian dollars, Indian rupees and Bangladeshi taka. The Company manages the risk by converting cash held in foreign currencies to U.S. dollars as required to fund forecast expenditures. The Company is exposed to changes in the market value of the short-term investment. The Company is exposed to changes in the LIBOR rate on the long-term debt. The Company is exposed to credit risk with respect to all of its financial instruments if a customer or counterparty fails to meet its contractual obligations. The Company has deposited the cash and restricted cash with reputable financial institutions, for which management believes the risk of loss to be remote. The Company takes measures in order to mitigate any risk of loss with respect to the accounts receivable, which may include obtaining guarantees. The Company is exposed to the risk of changes in market prices of commodities. The Company enters into physical commodity contracts for the sale of natural gas, which manages this risk. The Company does so in the normal course of business, including contracts with fixed terms. The contracts are not classified as financial instruments because the Company expects to deliver all required volumes under the contracts. No amounts are recognized in the consolidated financial statements related to the contracts until such time as the associated volumes are delivered. The Company is exposed to the change in the Brent crude price as the average Brent crude price from the preceding year is a variable in the gas price for the current year, calculated annually, for the D6 gas contracts. The fair values of cash, restricted cash, accounts receivable and accounts payable and accrued liabilities approximate their carrying values due to their short periods to maturity. The fair value of the short-term investment is based on publicly quoted market values. An unrealized gain on the recognition of the short-term investment at fair value of US$18.0 million in the quarter was recognized in income. The fair value of the long-term account receivable is calculated based on the amount receivable discounted at 6.5 percent for three years as collection is assumed in three years. The loss on recognition of the fair value of the long-term account receivable of US$0.05 million in the quarter was recognized in income. The fair value of the long-term debt is the amount of funds received by the Company. CRITICAL ACCOUNTING ESTIMATES The Company makes assumptions in applying certain critical accounting estimates that are uncertain at the time the accounting estimate is made and may have a significant effect on the financial statements of the Company. For a discussion of those critical accounting estimates, please refer to the MD&A for the Company's fiscal year ended March 31, 2009, available at www.sedar.com. ACCOUNTING CHANGES IN FISCAL 2009 Effective April 1, 2009, the Company adopted the new accounting standard, Section 3064 "Goodwill and Intangible Assets", issued by the Canadian Institute of Chartered Accountants (CICA), replacing Sections 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. Adoption of this section did not have an impact on the Company. FUTURE ACCOUNTING CHANGES Effective April 1, 2011, the Company will replace current Canadian accounting standards and interpretations, or GAAP, with International Financial Reporting Standards (IFRS) as required by the Canadian Accounting Standards Board. The employees of the Company participated in continuing education courses over the past year and consulted with a peer group to discuss implementation issues. The Company has prepared a planning and scoping document that identifies the differences between GAAP and IFRS that are applicable to the Company and sets out the steps to evaluate the differences and convert the financial statements prepared under Canadian GAAP to IFRS. DISCLOSURE CONTROLS AND PROCEDURES The Company's Chief Executive Officer and Chief Financial Officer are responsible for designing disclosure controls and procedures or causing them to be designed under their supervision and evaluating the effectiveness of the Company's disclosure controls and procedures. The Company's Chief Executive Officer and Chief Financial Officer oversee the design and evaluation process and have concluded that the design and operation of these disclosure controls and procedures were effective in ensuring material information relating to the Company required to be disclosed by the Company in its annual filings or other reports filed or submitted under applicable Canadian securities laws is made known to management on a timely basis to allow decisions regarding required disclosure. INTERNAL CONTROLS OVER FINANCIAL REPORTING The Chief Executive Officer and Chief Financial Officer of the Company are responsible for designing internal controls over financial reporting or causing them to be designed under their supervision and evaluating the effectiveness of the Company's internal controls over financial reporting. The Chief Executive Officer and Chief Financial Officer have overseen the design and evaluation of internal controls over financial reporting and have concluded that the design and operation of these internal controls over financial reporting were effective in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. Because of their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, errors or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. There were no changes in the internal controls over financial reporting during the quarter ended June 30, 2009 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. RISK FACTORS In the normal course of business the Company is exposed to a variety of actual and potential events, uncertainties, trends and risks. In addition to the risks associated with the use of assumptions in the critical accounting estimates, financial instruments, the Company's commitments and actual and expected operating events, all of which are discussed above, the Company has identified the following events, uncertainties, trends and risks that could have a material adverse impact on the Company: - The Company may not be able to find reserves at a reasonable cost, develop reserves within required time-frames or at a reasonable cost, or sell these reserves for a reasonable profit; - Reserves may be revised due to economic and technical factors; - The Company may not be able to obtain approval, or obtain approval on a timely basis, for exploration and development activities; - Changing governmental policies, social instability and other political, economic or diplomatic developments in the countries in which the Company operates; - Changing taxation policies, taxation laws and interpretations thereof; - Changes in the timing of future debt repayments based on provisions in the Company's loan agreement; - Adverse factors including climate and geographical conditions, weather conditions and labour disputes; - Changes in foreign exchange rates that in turn change the Company's future recorded revenues and expenses as the majority of sales and expenses are denominated in U.S. dollars; and - Changes in future oil and natural gas prices. For a comprehensive discussion of all identified risks, refer to the Company's Annual Information Form, which can be found at www.sedar.com. The Company has a number of contingencies as at June 30, 2009. Refer to the notes to the Company's unaudited consolidated financial statements for a complete list of the contingencies and any potential effects on the Company. /T/ OUTSTANDING SHARE DATA At August 12, 2009, the Company had the following outstanding shares: Number Cdn$ Amount(1) ---------------------------------------------------------------------------- Common shares 49,615,008 $1,199,743,000 Preferred shares nil nil Stock options 3,934,625 - ---------------------------------------------------------------------------- (1) This is the dollar amount received for common shares issued excluding share issue costs and is presented in Canadian dollars. The U.S. dollar equivalent at August 12, 2009 is US$1,048,068,000. /T/ OUTLOOK We expect to continue the ramp-up of D6 production volumes and achieve plateau rates of 2.8 Bcf/d (280 MMcf/d working interest to the Company) by calendar year-end. The Company will also continue exploration activity in all blocks within its expanded exploration portfolio. /T/ On behalf of the Board of Directors, (signed) "Edward S. Sampson" Edward S. Sampson Chairman of the Board, President and CEO August 12, 2009 CONSOLIDATED BALANCE SHEETS (thousands of U.S. dollars)(unaudited) As at As at June 30, March 31, 2009 2009 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ASSETS Current assets Cash and cash equivalents $ 28,302 $ 31,189 Restricted cash (note 3) 123,766 185,475 Short-term investment 27,283 9,067 Accounts receivable 26,013 20,287 Inventory 582 616 Prepaid expenses 1,103 1,494 ---------------------------------------------------------------------------- 207,049 248,128 ---------------------------------------------------------------------------- Restricted cash (note 3) 18,339 24,011 Cash call advance - 103 Long-term investment 4,482 4,216 Long-term accounts receivable 22,322 22,098 Income tax receivable 17,043 16,000 Property and equipment 1,211,931 1,154,074 ---------------------------------------------------------------------------- $ 1,481,166 $ 1,468,630 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities Accounts payable and accrued liabilities $ 85,758 $ 119,555 Current portion of capital lease obligation 10,752 10,752 Current tax payable 3,738 2,691 ---------------------------------------------------------------------------- 100,248 132,998 ---------------------------------------------------------------------------- Asset retirement obligation 28,040 27,544 Capital lease obligation 56,805 57,984 Long-term debt 192,814 192,814 ---------------------------------------------------------------------------- 377,907 411,340 ---------------------------------------------------------------------------- Shareholders' equity Share capital (note 4) 1,020,402 1,001,885 ---------------------------------------------------------------------------- Contributed surplus (note 5) 53,138 51,966 ---------------------------------------------------------------------------- Accumulated other comprehensive income (loss) (note 6) 4,792 (2,406) Retained earnings 24,927 5,845 ---------------------------------------------------------------------------- 29,719 3,439 ---------------------------------------------------------------------------- 1,103,259 1,057,290 ---------------------------------------------------------------------------- $ 1,481,166 $ 1,468,630 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Segmented information (note 8) Guarantees (note 9) Commitments and contractual obligations (note 10) Contingencies (note 11) See accompanying Notes to Consolidated Financial Statements. CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME AND RETAINED EARNINGS (thousands of U.S. dollars, except per share amounts) (unaudited) Three months ended June 30, 2009 2008 ---------------------------------------------------------------------------- Revenue Oil and natural gas $ 53,853 $ 24,381 Royalties (2,521) (1,155) Profit petroleum (7,224) (5,478) Gain on short-term investment 18,003 6,875 Interest 85 4,235 Gain on risk management contracts - 954 ---------------------------------------------------------------------------- 62,196 29,812 ---------------------------------------------------------------------------- Expenses Operating and pipeline 6,607 2,319 Interest and financing 3,367 - General and administrative 1,531 2,716 Foreign exchange loss 4,209 1,612 Discount of long-term account receivable 48 100 Stock-based compensation 5,408 4,403 Equity loss on long-term investment 91 - Depletion, depreciation and accretion 16,697 10,867 ---------------------------------------------------------------------------- 37,958 22,017 ---------------------------------------------------------------------------- Income before income taxes 24,238 7,795 Current income tax expense 3,797 1,528 ---------------------------------------------------------------------------- Net income $ 20,441 $ 6,267 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net income per share (note 7) Basic $ 0.41 $ 0.13 Diluted $ 0.41 $ 0.13 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net income 20,441 6,267 Foreign currency translation gain 7,198 4,176 ---------------------------------------------------------------------------- Comprehensive income (note 6) $ 27,639 $ 10,443 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Retained earnings, beginning of period 5,845 33,472 Net income 20,441 6,267 Dividends paid (1,359) (1,451) ---------------------------------------------------------------------------- Retained earnings, end of period $ 24,927 $ 38,288 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying Notes to Consolidated Financial Statements. CONSOLIDATED STATEMENTS OF CASH FLOWS (thousands of U.S. dollars) (unaudited) Three months ended June 30, 2009 2008 ---------------------------------------------------------------------------- Cash provided by (used in): Operating activities Net income $ 20,441 $ 6,266 Add items not involving cash from operations: Unrealized foreign exchange loss 3,582 2,275 Discount of long-term account receivable 48 100 Stock-based compensation 5,408 4,403 Unrealized (gain) on short-term investment (18,003) (6,875) Equity loss on long-term investment 91 - Unrealized (gain) on risk management contracts - (954) Depletion, depreciation and accretion 16,697 10,867 Change in non-cash working capital (4,599) (3,972) Change in long-term accounts receivable (325) (27) ---------------------------------------------------------------------------- 23,340 12,083 ---------------------------------------------------------------------------- Financing activities Proceeds from issuance of shares, net of issuance costs (note 4) 13,637 7,726 Dividends paid (1,359) (1,451) ---------------------------------------------------------------------------- 12,278 6,275 ---------------------------------------------------------------------------- Investing activities Addition of property and equipment (73,198) (110,184) Reduction in capital lease obligations (695) - Restricted cash contributions (47,987) (2,617) Restricted cash returned 115,368 8,104 Addition to short-term investment - (14,714) Addition to long-term investment - (11,378) Change in non-cash working capital (33,197) 2,361 Change in cash call advances 103 345 ---------------------------------------------------------------------------- (39,606) (128,083) ---------------------------------------------------------------------------- (Decrease) in cash (3,988) (109,725) Effect of foreign currency translation on cash and cash equivalents 1,101 3,664 Cash and cash equivalents, beginning of period 31,189 443,889 ---------------------------------------------------------------------------- Cash and cash equivalents, end of period $ 28,302 $ 337,828 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying Notes to Consolidated Financial Statements. /T/ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the three months ended June 30, 2009 (unaudited). All tabular amounts are in thousands of U.S. dollars except per share amounts, numbers of shares/stock options, stock option and share prices, and certain other figures as indicated. 1. BASIS OF PRESENTATION The interim consolidated financial statements of Niko Resources Ltd. (the "Company") have been prepared in accordance with Canadian generally accepted accounting principles. The interim consolidated financial statements have been prepared following the same accounting policies and methods of application as the audited consolidated financial statements for the fiscal year ended March 31, 2009, except as discussed in note 2. The disclosures provided herein are incremental to those included with the annual consolidated financial statements and the notes thereto for the year ended March 31, 2009. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto for the year ended March 31, 2009. Certain comparative figures have been reclassified to conform to the current period's presentation and to conform to the Company's use of the U.S. dollar as its reporting currency. 2. CHANGES IN ACCOUNTING POLICIES Effective April 1, 2009, the Company adopted the new accounting standard, Section 3064 "Goodwill and Intangible Assets", issued by the Canadian Institute of Chartered Accountants, replacing Sections 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. Adoption of this section did not have an impact on the Company. 3. RESTRICTED CASH The restricted cash balance included in current assets at June 30, 2009 is comprised of US$115.4 million that is restricted as per provisions of the credit facility (March 31, 2009 - US$185.5 million) and guarantees of US$8.4 million (March 31, 2009 - nil)(see note 9). The cash restricted under the credit facility may be used to fund development costs for Hazira, Surat, and D6 Blocks in India and Block 9 in Bangladesh and the costs of operating the Hazira, Surat, Block 9 and the Dhirubhai 1 and 3 gas fields of the D6 Block, including amounts included in accounts payable and accrued liabilities and amounts to be incurred in the upcoming year. The current portion of restricted cash will become unrestricted once the Dhirubhai 1 and 3 gas field project is complete as defined in the credit facility. The restricted cash balance included in non-current assets includes guarantees of US$11.5 million (March 31, 2009 - US$13.5 million) (see note 9), US$3.5 million (March 31, 2009 - US$3.5 million) of cash that is legally restricted for future site restoration in India and US$3.3 million (March 31, 2009 - US$7.0 million) that is restricted as per provisions of the credit facility and will continue to be restricted after the Dhirubhai 1 and 3 gas field project is complete as defined in the credit facility. Subsequent to project completion, cash will continue to be restricted in the amount of a debt service reserve account and a provision for 45 days of capital and 30 days operating costs for Hazira, Surat, Block 9 and the D6 Block. 4. SHARE CAPITAL (a) Authorized Unlimited number of common shares Unlimited number of preferred shares (b) Issued /T/ Three months ended Year ended June 30, 2009 March 31, 2009 ---------------------------------------------------------------------------- Amount Amount Number (US$000s) Number (US$000s) ---------------------------------------------------------------------------- Common shares Balance, beginning of period 49,298,133 1,001,885 49,054,408 986,050 Stock options exercised 313,875 13,637 243,725 11,615 Transferred from contributed surplus on exercise - 4,880 - 4,220 ---------------------------------------------------------------------------- Balance, end of period 49,612,008 1,020,402 49,298,133 1,001,885 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ (c) Stock Options The Company has reserved for issue 4,961,200 common shares for granting under stock options to directors, officers, and employees. The options become 100 percent vested one to four years after the date of grant and expire two to five years after the date of grant. Stock option transactions for the respective periods were as follows: /T/ Three months ended Year ended June 30, 2009 March 31, 2009 ---------------------------------------------------------------------------- Weighted Weighted Average Average Exercise Number Exercise Number Price of Price of Options (Cdn$) Options (Cdn$) ---------------------------------------------------------------------------- Outstanding, beginning of period 4,030,750 64.69 3,219,725 65.02 Granted 308,500 72.65 1,368,313 60.33 Forfeited (3,000) 80.11 (18,250) 83.11 Expired (8,250) 91.83 (295,313) 58.39 Exercised (313,875) 50.43 (243,725) 50.85 ---------------------------------------------------------------------------- Outstanding, end of period 4,014,125 66.35 4,030,750 64.69 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Exercisable, end of period 965,937 57.60 1,132,562 54.02 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- The following table summarizes stock options outstanding and exercisable under the plan at June 30, 2009: Outstanding Options Exercisable Options ---------------------------------------------------------------------------- Weighted Remaining Weighted Average Life Average Price Exercise Price Options (Years) Price (Cdn$) Options (Cdn$) ---------------------------------------------------------------------------- $ 39.30 3,000 - 39.30 3,000 39.30 $ 41.00 - $ 49.90 1,461,438 2.7 47.54 404,500 43.46 $ 50.15 - $ 59.87 571,374 1.2 53.71 255,937 53.70 $ 60.00 - $ 69.82 395,000 2.2 63.12 113,750 63.00 $ 71.13 - $ 79.69 74,000 3.2 76.95 11,250 79.69 $ 80.20 - $ 89.99 752,563 3.3 85.08 39,250 82.71 $ 90.40 - $ 99.68 755,000 2.5 94.31 138,000 93.17 $ 105.00 - $ 105.47 1,750 2.4 105.27 250 105.47 ---------------------------------------------------------------------------- 4,014,125 2.5 66.35 965,937 57.60 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 5. CONTRIBUTED SURPLUS Three months ended Year ended (thousands of U.S. dollars) June 30, 2009 March 31, 2009 ---------------------------------------------------------------------------- Contributed surplus, beginning of period $ 51,966 $ 34,952 Stock-based compensation 6,052 21,234 Stock options exercised (4,880) (4,220) ---------------------------------------------------------------------------- Contributed surplus, end of period $ 53,138 $ 51,966 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 6. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Three months ended Year ended (thousands of U.S. dollars) June 30, March 31, 2009 2009 ---------------------------------------------------------------------------- Accumulated other comprehensive income (loss), beginning of period $ (2,406) $ 40,989 Other comprehensive income (loss): Foreign currency translation gain (loss) 7,198 (43,395) ---------------------------------------------------------------------------- Accumulated other comprehensive income (loss), end of period $ 4,792 $ (2,406) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 7. EARNINGS PER SHARE The following table summarizes the weighted average number of common shares used in calculating basic and diluted earnings per share: Three months ended June 30, 2009 2008 ---------------------------------------------------------------------------- Weighted average number of common shares outstanding - basic 49,430,508 49,096,616 - diluted 49,430,508 49,756,618 ---------------------------------------------------------------------------- 8. SEGMENTED INFORMATION Three months ended Three months ended (thousands of U.S. dollars) June 30, 2009 June 30, 2008 ---------------------------------------------------------------------------- Segment Segment Profit Capital Profit Capital Segment Revenue (Loss) Additions Revenue (Loss) Additions ---------------------------------------------------------------------------- Bangladesh $ 14,159 $ 1,793 $ 7,863 $ 11,082 $ 1,673 $ 2,339 India 39,588 15,734 52,352 12,962 1,654 92,092 Indonesia - - 5,587 - - - Kurdistan - - 6,507 - - 14,850 Madagascar - - 478 - - - Pakistan - - 42 - - 594 All other (1) 106 (520) 369 337 (293) 309 ---------------------------------------------------------------------------- Total $ 53,853 $ 17,007 $ 73,198 $ 24,381 $ 3,034 $ 110,184 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (thousands of U.S. dollars) As at June 30, 2009 As at March 31, 2009 ---------------------------------------------------------------------------- Property and Property and Segment Equipment Total Assets Equipment Total Assets ---------------------------------------------------------------------------- Bangladesh $ 140,706 $ 206,902 $ 138,667 $ 170,405 India 987,112 1,108,343 944,881 1,170,524 Indonesia 21,678 33,963 15,896 28,181 Kurdistan 31,325 33,323 24,579 28,477 Madagascar 4,886 5,224 4,393 5,826 Pakistan 22,990 23,047 22,863 22,932 All other (1) 3,234 70,364 2,795 42,285 ---------------------------------------------------------------------------- Total $ 1,211,931 $ 1,481,166 $ 1,154,074 $ 1,468,630 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Revenues included in All other are from Canadian oil sales net of royalties. The reconciliation of the segment profit to net income as reported in the financial statements is as follows: Periods ended June 30, (thousands of U.S. dollars) 2009 2008 ---------------------------------------------------------------------------- Segment profit $ 17,007 $ 3,034 Interest income 85 4,235 Interest and financing (3,367) - General and administrative expenses (1,531) (2,716) Foreign exchange (loss) (4,209) (1,612) Discount of long-term account receivable (48) (100) Stock-based compensation expense (5,408) (4,403) Gain on short-term investment 18,003 6,875 Equity (loss) on long-term investment (91) - Gain on risk management contracts - 954 ---------------------------------------------------------------------------- Net income $ 20,441 $ 6,267 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ 9. GUARANTEES As at June 30, 2009, the Company had performance security guarantees of US$5.0 million for Indonesia and US$3.4 million for Cauvery, which are included in the current restricted cash balance, and US$0.6 million for the D4 block, US$9.7 million for Indonesia and US$1.2 million for Madagascar, which are included in the non-current restricted cash balance. 10. COMMITMENTS AND CONTRACTUAL OBLIGATIONS The Company has commitments for approved budgets and development plans under various joint venture agreements. The material commitments incurred since March 31, 2009: In May 2009 the Company acquired interests in three additional blocks in Indonesia. The Company has minimum work commitments under the first exploratory period, which expires in May 2012, of US$51.7 million related to acquisition of 4,042 kilometres of 2D seismic, 1,200 square kilometres of 3D seismic, drilling one well per block and various payments under the agreements. In July 2009, the Company signed an agreement to earn an interest in a block in Trinidad. The Company has minimum work commitments estimated to cost US$31.3 million to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells within three years. 11. CONTINGENCIES (a) During the year ended March 31, 2006, a group of petitioners in Bangladesh (the petitioners) filed a writ with the Supreme Court of Bangladesh (the Supreme Court) against various parties including Niko Resources (Bangladesh) Ltd., a subsidiary of the Company. The petitioners are requesting the following of the Supreme Court with respect to the Company: (i) that the Joint Venture Agreement for the Feni and Chattak fields be declared null and illegal; (ii) that the government realize from the Company compensation for the natural gas lost as a result of the uncontrolled flow problems as well as for damage to the surrounding area; (iii) that Petrobangla withhold future payments to the Company relating to production from the Feni field (US$27.1 million as at June 30, 2009); and (iv) that all bank accounts of the Company maintained in Bangladesh be frozen. The Company believes that the outcome of the writ with respect to the first two issues is not determinable. With respect to the third issue, Petrobangla is currently withholding payments to the Company relating to production from the Feni field. With respect to the fourth issue, the Company's Bangladesh branch has been permitted to make payments to Bangladesh vendors. However, payments to foreign vendors from the Bangladesh Feni and Chattak branch are not permitted. The Company's foreign vendors for the Feni and Chattak fields are being paid by Niko Resources (Bangladesh) Ltd., which is incorporated outside of Bangladesh. (b) During the year ended March 31, 2006, Niko Resources (Bangladesh) Ltd. received a letter from Petrobangla demanding compensation related to the uncontrolled flow problems that occurred in the Chattak field in January and June 2005. Subsequent to March 31, 2008, Niko Resources (Bangladesh) Ltd. was named as a defendant in a lawsuit that was filed in Bangladesh by Petrobangla and the Republic of Bangladesh demanding compensation as follows: (i) taka 368,813,000 (US$5.3 million) for 3 Bcf of free natural gas delivered from the Feni field as compensation for the burnt natural gas; (ii) taka 724,102,000 (US$10.3 million) for 5.89 Bcf of free natural gas delivered from the Feni field as compensation for the subsurface loss; (iii) taka 845,560,000 (US$12.0 million) for environmental damages, an amount subject to be increased upon further assessment; (iv) taka 5,532,189,000 (US$78.8 million) for 45 Bcf of natural gas as compensation for further subsurface loss; and (v) any other claims that arise from time to time. The Company and the Government of Bangladesh had previously agreed to settle the government's claims through arbitration conducted in Bangladesh based upon international rules. The Company will actively defend itself against the lawsuit. This process could take in excess of three years. The Company believes that the outcome of the lawsuit and the associated cost to the Company, if any, are not determinable. As such, no amounts have been recorded in these consolidated financial statements. (c) In accordance with natural gas sales contracts to customers in the vicinity of the Hazira field in India, the Company and its joint venture partner at Hazira have committed to certain minimum quantities. Should the Company fail to supply the minimum quantity of natural gas in any month as specified in the contract, the Company may be liable to pay the vendor an approximately equivalent amount. The Company was unable to deliver the minimum quantities up to December 31, 2007. The Company has agreed to provide five times the gas that the Company was unable to deliver from D6 volumes. In the event the Company is unable to deliver the volumes, the Company will have a potential liability, which is currently estimated at US$11.2 million. (d) The Company calculates and remits profit petroleum expense to the Government of India in accordance with the PSC. The profit petroleum expense calculation considers capital and other expenditures made by the joint venture, which reduce the profit petroleum expense. There are costs that the Company has included in the profit petroleum expense calculations that have been contested by the government. The Company believes that it is not determinable whether the above issue will result in additional petroleum expense. No amount has been recorded in these consolidated financial statements. (e) The Company has filed its income tax returns in India for the taxation years 1998 through 2008 under provisions that provide for a tax holiday deduction for production from the Hazira and Surat fields for eligible undertakings. As discussed below, the Company has received tax assessments related to several taxation years. The assessments contend that the Company is not eligible for the requested tax holiday because a) the holiday only applies to "mineral oil" which excludes natural gas; and/or b) the Company has inappropriately defined undertakings. However, for several taxation years the Company has successfully appealed these assessments. The Company received a favorable ruling with respect to the tax holiday at the third tax assessment level for the taxation years 1999 through 2004. The Company received US$12.8 million during fiscal 2009 with respect to the tribunal ruling on these years, excluding taxation year 2002, and US$2.4 million for interest on the balance received. The Income Tax Department has filed an appeal against the orders and the matter is currently pending with the High Court in India. The 2005 taxation year received a favorable ruling with respect to the tax holiday at the second tax assessment level. The Income Tax Department has filed an appeal against the order before the third tax assessment level. The taxation years 2006 through 2008 have been and the 2009 taxation year will be filed including a deduction for the tax holiday, but these have not yet been assessed. In July 2009, the Government of India presented a budget including certain relevant tax proposals. On the question of whether "mineral oil" includes natural gas the budget made it clear that, for the NELP-VIII round of bidding (expected later this year) natural gas will be eligible for the tax holiday. However, the budget did not address blocks that have been awarded under previous rounds of bidding which would include all of the Company's Indian blocks. With respect to "undertakings" eligible for the tax holiday deduction, the budget includes a proposal regarding how to determine undertakings. The proposal states that each production sharing contract shall be treated as a single undertaking. The Company has filed its income taxes on the basis of multiple undertakings within any single production sharing contract. Should the tax proposal related to undertakings be implemented without amendment by the Government of India or should natural gas production not be eligible for the tax holiday, the Company would record a tax expense of approximately US$65.6 million, pay additional taxes of approximately US$49.8 million and write off approximately US$15.8 million of the net income tax receivable. In addition, the Company would be obligated to return interest on tax refunds received of US$2.4 million and could be obligated to pay interest and penalties, the amounts of which are not determinable. (f) In January 2009, the Company received confirmation from Canadian authorities that they are engaged in a formal investigation into allegations of improper payments in Bangladesh by either the Company or its subsidiary in Bangladesh. No charges have been laid against either the Company or its subsidiary in Bangladesh. The Company believes that the outcome of the investigation and associated costs to the Company are not determinable and no amounts have been recorded in these consolidated financial statements.