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Press release from Marketwire

Niko Reports Results for the Quarter Ended June 30, 2010

Thursday, August 12, 2010

Niko Reports Results for the Quarter Ended June 30, 201006:00 EDT Thursday, August 12, 2010 CALGARY, ALBERTA--(Marketwire - Aug. 12, 2010) - Niko Resources Ltd. (TSX:NKO) ("Niko" or "the Company") is pleased to report its financial and operating results, including consolidated financial statements and notes thereto, as well as its managements' discussion and analysis, for the quarter ended June 30, 2010, the first quarter of Niko's fiscal year. The operating results are effective August 11, 2010. % Three months ending June 30, 2010 2009 Improvement ---------------------------------------------------------------------------- Oil production (bbls/d) 2,959 809 266 Gas production (mcf/d) 283,574 155,030 83 ---------------------------------------------------------------------------- Total production (mcfe/d) 301,330 159,884 88 ---------------------------------------------------------------------------- Operating netback ($/mcfe) 3.54 2.58 37 Funds from operations ($ thousands) 77,707 28,264 175 Net income ($ thousands) 39,756 20,441 94 ---------------------------------------------------------------------------- The Company experienced dramatic quarter-over-quarter performance improvements. The improvements relate almost entirely to volumes from D6 where oil production increased due to additional wells put on-stream and gas production started April 2009 and has ramped-up since that time. Operating netback increased as a result of the increase in oil production from the D6 Block, an increased average gas price, a low level profit sharing at D6 and decreased operating costs per mcfe as D6 production increased.EXPLORATION HIGHLIGHTS- Four new exploration blocks were added offshore Indonesia. Three of the blocks are adjacent to the Company's Cendrawasih block and the fourth is in the Sunda Strait which is in proximity to Jakarta.- Seismic acquisition activity continued at Indonesia and Madagascar and a 3D seismic contract has been awarded in Trinidad.- Drilling success continued at D6 where the Company continues to expect significant reserve additions once development plans are prepared and approved.- Like D6, drilling success continued at NEC-25 where development plans are expected once appraisal is completed.- At Hazira, two wells encountered a new oil bearing interval that awaits further evaluation.- Drilling continues at the Company's Kurdistan property.LOOKING FORWARDResults for the quarter are in line with expectations and the Company expects to meet volume, operating cashflow and capital projections included in its annual report.Actual activity for the quarter and planned seismic and drilling activity over the next seven quarters is reflected in the following link: http://media3.marketwire.com/docs/812nko_chart.pdfForward-Looking Information and Material AssumptionsThis report on results for the three months ended June 30, 2010 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", "should" 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 three months ended June 30, 2010 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.The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis and updates reserve estimates 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, 2010.MANAGEMENT'S DISCUSSION AND ANALYSISThis 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 quarter ended June 30, 2010 should be read in conjunction with the unaudited consolidated financial statements for the quarter ended June 30, 2010 and the MD&A and the audited consolidated financial statements as at and for the year ended March 31, 2010. This MD&A is effective August 11, 2010. Additional information relating to the Company, including the Company's Annual Information Form (AIF), is available on SEDAR at www.sedar.com.All financial information is presented in U.S. thousands of dollars unless otherwise indicated.The term "the quarter" is used throughout the MD&A and in all cases refers to the period from April 1, 2010 through June 30, 2010. The term "prior year's quarter" is used throughout the MD&A for comparative purposes and refers to the period from April 1, 2009 through June 30, 2009.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 term "Fiscal 2011" is used throughout this MD&A and in all cases refers to the period from April 1, 2010 through March 31, 2011. The term "Fiscal 2012" is used throughout this MD&A and in all cases refers to the period from April 1, 2011 through March 31, 2012. 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 up to 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 and Bangladeshi condensate. Therefore, the results from Canadian oil and Bangladeshi condensate production are not discussed separately.Forward-Looking Information and Material AssumptionsThis 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", "should" 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 necessarily 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.The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis and updates reserve estimates 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 MeasuresThe 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 and 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 and natural gas revenues less royalties, profit petroleum expenses, operating expenses, depletion, depreciation and accretion expense and current and future 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. OVERALL PERFORMANCE Funds from Operations ---------------------------------------------------------------------------- Three months ended June 30, 2010 2009 ---------------------------------------------------------------------------- Oil and natural gas revenues 116,501 53,853 Royalties (5,219) (2,521) Profit petroleum (6,863) (7,224) Operating expense (7,375) (6,607) Interest income and other (372) 85 Interest and financing expense (7,308) (3,367) General and administrative expense (1,428) (1,531) Realized foreign exchange gain (loss) 1,415 (627) Current income tax expense (11,644) (3,797) ---------------------------------------------------------------------------- Funds from operations(1) 77,707 28,264 ---------------------------------------------------------------------------- (1) Funds from operations is a non-GAAP measure as defined in Non-GAAP Measures in this MD&A. Natural gas production from the D6 Block has ramped-up since the commencement of production in April 2009 comprising the majority of the increase in revenues in the quarter. Oil sales from the D6 Block have also increased quarter-over-quarter. Maintenance was conducted on a pipeline in Block 9 and natural declines are continuing at Hazira and Surat decreasing revenues from the blocks.Royalties, operating expense and current income tax expense increased with the net increase in production described above.In spite of a significant increase in oil and gas revenue, profit petroleum was relatively constant quarter-over-quarter due to the positive impact of including the 36-inch pipeline for cost recovery at the Hazira field and also due to D6 revenues attracting a very low profit petroleum charge.Interest and financing expense relates to the lease of the Floating Production, Storage and Offloading vessel (FPSO) related to D6 oil production, interest expense on the long-term debt and interest and accretion expense on the convertible debentures, which were issued since the prior year's quarter.The Company's realized foreign exchange gain arose primarily on the settlement of Indian-rupee denominated working capital. Net Income ---------------------------------------------------------------------------- Three months ended June 30, 2010 2009 ---------------------------------------------------------------------------- Funds from operations (non-GAAP measure) 77,707 28,264 Unrealized foreign exchange loss (274) (3,582) (Loss) gain on short-term investments (7,826) 18,003 Interest and financing expense (1,083) (139) Stock-based compensation expense (7,368) (5,408) Depletion, depreciation and accretion (32,400) (16,697) Future income tax reduction 11,000 - ---------------------------------------------------------------------------- Net income 39,756 20,441 ---------------------------------------------------------------------------- The increase in net income in the quarter compared to the prior year's quarter is primarily a result of the increase in funds from operations as described above. Other factors affecting net income are explained below.The unrealized foreign exchange loss arose on the translation of the Indian-rupee denominated income tax receivable. This was partially offset by a foreign exchange gain on U.S. dollar cash held by the parent whose functional currency is the Canadian dollar. An offsetting entry to this gain decreases the accumulated other comprehensive income but does not flow through the income statement.The market value of the short-term investments decreased during the quarter compared to an increase in the prior year's quarter resulting in the reported loss and gain, respectively.The increase in stock-based compensation expense in the year is primarily a result of the increased fair value expense per stock option and an increase in the number of stock options being expensed.Depletion expense increased primarily due to the increased production from the D6 Block.The future income tax reduction is the result of a tax credit available for future years related to minimum alternative tax paid for the D6 Block in the current year.BACKGROUND ON PROPERTIESNiko Resources Ltd. is engaged in the exploration for and, where successful, the development and production of natural gas and oil in India, Bangladesh, Indonesia, the Kurdistan region of Iraq, Trinidad, Pakistan and Madagascar. The Company has agreements with the governments of these countries 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 or as specified in the production sharing contract (PSC). Where the Company is currently producing, 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.IndiaCauvery - The Company has a 100 percent working interest and operates the block, which covers 957 square kilometres. The Company has performed the seismic work and drilled four of the five wells required under the first exploration phase. The estimated cost of the remaining work commitment is $2.0 million. Wells drilled to date have been unsuccessful. The Company has received an extension to the exploration period to March 2011 in order to evaluate the technical merit of the block.D4 - The Company has a 15 percent interest in the D4 Block, located in the Mahanadi Basin offshore from 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 three exploration wells. Originally, the work commitment was to be completed by September 2009; however, the Government of India has approved a blanket extension to December 31, 2010 for this and other deepwater blocks. The Company expects to commence drilling later this year. The Company's share of the estimated cost of the remaining work commitment is $10 million.D6 - The Company has a 10 percent working interest in the 7,645-square-kilometre D6 Block. The D6 Block comprised 80 percent of the Company's oil and gas revenue during the quarter. 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 petroleum mining licences for the discoveries expiring in 2028 and 2025, respectively. 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 $4.20/MMBtu net and there is a marketing margin of $0.135/MMBtu earned in addition to the price formula. This equates to a sales price of approximately $3.95/Mcf. There have been several gas discoveries since Dhirubhai 1 and 3. A development plan for nine such discoveries was submitted to the Government of India in July 2008, however, based on the Government's advice, in December 2009 the plan was modified to include four rather than nine discoveries. Additional development plans will be considered for the remaining discoveries.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. As at June 30, 2010, the profit share was 10 percent.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. The Hazira Block comprised 5 percent of the Company's oil and gas revenues in the quarter. The Company has a petroleum mining licence that expires in September 2014, which can be extended. The Company has one significant contract for the sale of gas production from the field expiring in April 2016 at a current price of $4.86/Mcf.NEC-25 - The Company has a 10 percent working interest in the NEC-25 Block, which covers 9,461 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. Once appraisal drilling is concluded, the Company expects to submit a development plan to the Government of India.Surat - The Company holds a development area of 24 square kilometres containing the Bheema and NSA shallow natural gas fields. The block has been producing natural gas since April 2004 and comprised 3 percent of the Company's oil and gas revenue in the quarter. The Company has one contract for the sale of gas production at a price of $6.00/Mcf until March 31, 2011.BangladeshBlock 9 - The Company holds a 60 percent interest in this 6,880-square-kilometre onshore block that encompasses the capital city of Dhaka. Natural gas and condensate production from this field began in May 2006 and comprised 11 percent of the Company's oil and gas revenues for the quarter. 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 $2.34/MMBtu (approximately $2.33/Mcf) 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. 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. As at June 30, 2010, the profit share was 61 percent.IndonesiaThe Company holds interests in PSCs for 16 offshore exploration blocks covering 79,739 square kilometres. The chart below indicates the location, award date, the Company's working interest and the size of the block. Working Area (Square Block Name Offshore Area Award Date Interest Kilometres) ---------------------------------------------------------------------------- Bone Bay Sulewasi SW Nov. 2008 45% 4,969 South East Ganal(1) Makassar Strait Nov. 2008 100% 4,868 Seram(1) Seram North Nov. 2008 100% 4,991 South Matindok(1) Sulewasi NE Nov. 2008 100% 5,182 West Sageri(1) Makassar Strait Nov. 2008 100% 4,977 Cendrawasih Papua NW May 2009 45% 4,991 Kofiau(1) West Papua May 2009 100% 5,000 Kumawa Papua SW May 2009 45% 5,004 East Bula(1) Seram NE Nov. 2009 100% 6,029 Halmahera-Kofiau(1) Papua W Nov. 2009 80% 4,926 North Makassar Makassar Strait Nov. 2009 50% 1,787 West Papua IV(1) Papua SW Nov. 2009 80% 6,389 Cendrawasih II Papua NW May 2010 50% 5,073 Cendrawasih III(1) Papua NW May 2010 50% 4,689 Cendrawasih IV(1) Papua NW May 2010 50% 3,904 Sunda Strait I(1) Sunda Strait May 2010 100% 6,960 ---------------------------------------------------------------------------- (1) Operated by the Company. All of the blocks are in the first exploration period, which is a three-year period. Most of the blocks have a seismic commitment and a single well commitment. The Company's share of the remaining work commitments during the first exploration period is estimated at $130 million.KurdistanThe Company has a 37 percent interest and carries the proportionate cost for the regional government's interest, resulting in a 46 percent cost interest in the onshore Qara Dagh block. The block covers approximately 846 square kilometres, in the Sulaymaniyah Governorate of the Federal Region of Kurdistan in Iraq. 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 and interpretation of the seismic program is complete. The Company began drilling the exploratory well in May 2010. The Company's share of the estimated remaining costs under the first exploration phase is $11 million.TrinidadThe Company holds interests in five PSCs for three exploration areas covering 3,652 square kilometres. The Company has a 35.75 percent interest in Block 2AB; a 32.5 percent and 40 percent interest in the Shallow and Deep Horizon Central Range PSCs, respectively; and a 65 percent and 80 percent interest in the Shallow and Deep Horizon Guayaguayare PSCs, respectively. Block 2AB covers 1,605 square kilometres offshore Trinidad and the Company has minimum work commitments to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells by July 2012.The Central Range area covers an onshore area of 856 square kilometres spanning from the west to east coasts of Trinidad. The Company has remaining minimum work commitments to acquire 168 kilometres of 3D seismic and drill three wells by September 2012.The Guayaguayare area covers a 1,190 square-kilometre onshore and offshore area located on the southeast coast of Trinidad. The Company has minimum work commitments to acquire 130 square kilometres of 3D seismic onshore, acquire 200 square kilometres of 3D seismic offshore and two onshore wells and one offshore well by July 2013.The Company's share of the work commitments under the first exploration periods for the three blocks is estimated at $93 million.MadagascarThe Company has a 75 percent working interest in a PSC for a 16,845-square-kilometre block off the west coast of Madagascar with water depths ranging from shallow water to 1,500 metres. The Company completed a 31,944-line-kilometre aero-magnetic survey and a 10,000 square kilometre multi-beam survey. A 3,236-square-kilometre 3D survey was completed in July 2010. The 3D seismic will fulfill the Phase II work commitment.PakistanThe Company has production sharing agreements (PSAs) for four blocks in Pakistan. The blocks are located in the Arabian Sea offshore the city of Karachi and cover a combined area of almost 10,000 square kilometres. Each agreement is for a three-Phase exploration period that ends March 2013 and a further renewal of 2 years in the event of commercial production. Phase II of the exploration period ends March 2012 and the Company has substantially completed the commitments under this phase through seismic activity. The Company will be evaluating the seismic in order to select potential drilling locations. Capital Expenditures For the three months ended June 30, 2010 (millions of U.S. dollars) Exploration ---------------------------------------------------------------------------- Bangladesh - India 15 Indonesia 11 Kurdistan 5 Madagascar 19 Pakistan - Trinidad 1 ---------------------------------------------------------------------------- Total(1) 51 ---------------------------------------------------------------------------- (1) The amounts presented are the Company's share of expenditures. IndiaD6 Block exploration: There was drilling activity on three exploration wells during the quarter. The rig was released from one of the wells during the quarter, AW1, and was released from the other two wells, AR1 and AK3, during July 2010. The AW1 well was an appraisal of previous discoveries; the AR1 well was another "R-complex" appraisal well; and the AK3 well was a Cretaceous prospect. AR1 was a successful gas well and the AK3 well is currently being evaluated. Exploration drilling is expected to be ongoing on the D6 Block.NEC-25: During the quarter, the Company continued an appraisal drilling campaign near the AJ1 discovery in the southern part of the block with the AJ7 well. This well and four additional appraisal wells previously drilled in the area encountered gas bearing sands and confirmed significant hydrocarbon potential for NEC-25. A further three wells are planned in the AJ area and AJ9 is waiting for the return of the drilling rig.Hazira: The remaining two wells of the three-well drilling program in the Hazira block were drilled during the quarter. Two wells encountered a new oil bearing interval that awaits further evaluation.IndonesiaIn mid-October 2009, the Company commenced a large scale 2D seismic program. The program used one vessel that traveled from block-to-block in order to minimize costs and downtime and maximize seismic coverage. In the quarter, the vessel shot 2,100 kilometres of 2D seismic and by the end of June 2010, the program had accumulated over 17,000 kilometres covering eight blocks. In the quarter, 2,100 square kilometres of 3D seismic was acquired resulting in a cumulative total of 6,500 square kilometres of 3D seismic by the end of June 2010.In May 2010, the Company signed four new PSCs with the Government of Indonesia for the following blocks: Cendrawasih Bay II, Cendrawasih Bay III, Cendrawasih Bay IV and Sunda Strait. In Cendrawasih Bay II, III, and IV, Niko holds a 50 percent interest and will operate two of these blocks while a subsidiary of Repsol YPF, S.A. will operate the third. Niko holds a 100 percent participating interest in the Sunda Strait I block. KurdistanDrilling of an exploratory well in the Kurdistan region of Iraq on the Qara Dagh anticline commenced in May 2010 and drilling is expected to be completed in fourth quarter of calendar 2010. The well is currently at an approximate depth of 1,638 meters of a planned total depth of between 3,600 and 4,000 meters. Geologically, the well has penetrated an anomalously thick lower Tertiary interval containing potential light oil in sandstone reservoirs that displayed fluorescence and cut fluorescence. A significant increase in mudgas readings with free oil has also been observed in the drill mud while drilling through the lower Tertiary. Following the setting of the intermediate casing string, the plan is to drill ahead and evaluate the prospectively of the lower Tertiary sandstones and the deeper Cretaceous Shiranish, Kometan and Qamchuqa formations.MadagascarA 3,236-square-kilometre 3D survey began in April 2010 and was completed in July 2010. The 3D seismic will fulfill the Phase II work commitment. Drilling is expected to commence in the quarter beginning January 2012. SEGMENT PROFIT INDIA ---------------------------------------------------------------------------- Three months ended June 30, 2010 2009 ---------------------------------------------------------------------------- Natural gas revenue 83,463 35,376 Oil and condensate revenue(1) 19,347 4.212 Royalties (5,200) (2,508) Profit petroleum (2,319) (2,496) Operating expenses (5,239) (5,008) Depletion, depreciation and accretion (26,066) (10,111) Current income tax expense (11,632) (3,731) Future income tax recovery 11,000 - ---------------------------------------------------------------------------- Segment profit(2) 63,354 15,734 ---------------------------------------------------------------------------- Daily natural gas sales (Mcf/d) 225,599 89,704 Daily oil and condensate sales (bbls/d)(1) 2,755 711 Operating costs ($/Mcfe) 0.24 0.59 Depletion rate ($/Mcfe) 1.16 1.16 ---------------------------------------------------------------------------- (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. Segment profit from India includes the results from the Dhirubhai 1 and 3 gas field and the MA oil field in the D6 Block, the Hazira oil and gas field and the Surat gas field.Revenue and RoyaltiesNatural gas production from the D6 Block commenced in April 2009 and has steadily increased since that time. There were 16 wells producing from the Dhirubhai 1 and 3 gas fields and one well from the MA field by the end of the quarter compared to seven wells at the end of the prior year's quarter. The Company's gas production for the quarter from the D6 block averaged 210 MMcf/d compared to 66 MMcf/d in the prior year's quarter. The increase in volumes contributed to a $52 million increase in revenues. The price received for gas sales from the D6 Block was consistent quarter-over-quarter at $3.95/Mcf.Natural gas production from the Surat and Hazira fields decreased in the quarter due to natural declines in these fields for a decrease of $4 million in revenues.Crude oil and condensate production from the MA field in the D6 Block increased with three additional wells that were put on production since the prior year's quarter. One of the wells is a gas well that has been producing approximately 200 bbls/d of condensate. The Company's crude oil and condensate sales from the D6 block for the quarter averaged 2,586 bbls/d compared to 500 bbls/d in the prior year's quarter. The Company's oil sales from the Hazira block for the quarter averaged 170 bbls/d compared to 211 bbls/d in the prior year's quarter. The Company received a price of $77.11/bbl in the quarter compared to $65.22/bbl in the prior year's quarter. The net increase in sales volumes and the increase in sales price contributed to a $15 million increase in revenues.The increase in royalties is a result of the increase in revenues 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 gas royalties applicable to the Hazira and Surat fields are currently 10 percent of the sales price.Profit PetroleumPursuant 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. Profits are defined as revenue less royalties, operating expenses and capital expenditures.The net decrease in profit petroleum in the quarter was primarily a result of the inclusion of the 36-inch pipeline for cost recovery for the Hazira field. This was partially offset by profit petroleum payments on the increased revenues from the D6 block.For the D6 Block, the Company is able to use up to 90 percent of profits to recover costs. The government was entitled to 10 percent of the profits not used to recover costs during the year. Profit petroleum during the quarter with respect to the D6 Block was $0.9 million, which is one percent of revenues, and will continue at this level until the Company has recovered its costs.For Hazira, in the quarter and the prior year's quarter, the government was entitled to 25 percent of the profits.For Surat, the Company recovered its investment in the last quarter of the prior year and began sharing profits with the government at a rate of 20 percent.Operating ExpensesOperating expenses increased slightly in the quarter. On a unit-of-production basis, average operating expenses have decreased from the prior year's quarter as a significant portion of the operating costs for the D6 Block are fixed.Depletion, Depreciation and AccretionThe depletion rate for the quarter of $1.16/Mcfe is consistent with the depletion rate in the prior year's quarter.Income TaxesThe increase in current income tax expense is primarily a result of the current income tax expense related to minimum alternative tax on the profits from the D6 Block. Current income tax expense related to the Hazira block decreased due to reduced revenues in the period. Largely offsetting current taxes was a future income tax reduction for a tax credit available for future years related to minimum alternative tax paid for D6 in the current year.The Company has a contingency related to income taxes as at June 30, 2010. Refer to the consolidated financial statements and notes for the three months ended June 30, 2010 for a complete discussion of the contingency. BANGLADESH ---------------------------------------------------------------------------- Three months ended June 30, 2010 2009 ---------------------------------------------------------------------------- Natural gas and condensate revenue 13,477 14,159 Profit petroleum (4,544) (4,729) Operating and pipeline expenses (2,112) (1,574) Depletion, depreciation and accretion (5,875) (6,053) Current income tax expense (6) (10) ---------------------------------------------------------------------------- Segment profit(1) 940 1,793 ---------------------------------------------------------------------------- Daily natural gas sales (Mcf/d) 57,975 65,326 Operating costs ($/Mcfe) 0.39 0.26 Depletion rate ($/Mcfe) 1.09 1.01 ---------------------------------------------------------------------------- (1) Segment profit is a non-GAAP measure as calculated above. Segment profit includes the results from Block 9 and Feni in Bangladesh. Production and segment profit from Feni was not significant in the quarter or the prior year's quarter. Revenue, Profit Petroleum, Depletion and Operating ExpensesNatural gas revenue variance relates entirely to volumes. Volumes in the quarter of 58 MMcf/d were significantly impacted by pipeline maintenance that occurred in June 2010. April and May gas production averaged approximately 70 MMcf/d, but June production decreased to 30 MMcf/d. Natural gas production is now back to 70 MMcf/d. In the prior year's quarter, the Company received 66.67 percent of production from Block 9, however, the Government of Bangladesh's carried interest in the block has been repaid resulting in the Company's share of production now being 60 percent.Pursuant to the terms of the PSC for Block 9, the Government of Bangladesh was entitled to 61 percent of profit gas in the quarter and prior year's quarter. Profit petroleum expense decreased due to decreased revenues from Block 9.Operating costs increased as a result of the pipeline maintenance costs incurred in the quarter and are expected to decrease in subsequent quarters.Depletion expense decreased with the decrease in production from Block 9 and increased on a unit-of-production basis as a result of the change in estimate of future development costs.NETBACKSThe following tables outline the Company's operating, funds from operations and earnings netbacks (all of which are non-GAAP measures) for the quarters ended June 30, 2010 and 2009: ---------------------------------------------------------------------------- Three months ended June 30, 2010 ---------------------------------------------------------------------------- India Bangladesh Total ($/Mcfe) ($/Mcfe) ($/Mcfe) ---------------------------------------------------------------------------- Oil and natural gas revenue 4.67 2.51 4.25 Royalties (0.23) - (0.19) Profit petroleum (0.11) (0.85) (0.25) Operating expense (0.24) (0.39) (0.27) ---------------------------------------------------------------------------- Operating netback 4.09 1.27 3.54 ---------------------------------------------------------------------------- Interest income and other (0.01) Interest and financing expense (0.31) General and administrative expense (0.05) Realized foreign exchange gain (loss) 0.05 Current income tax expense (0.42) ---------------------------------------------------------------------------- Funds from operations netback 2.80 ---------------------------------------------------------------------------- Unrealized foreign exchange (loss) (0.01) Stock-based compensation expense (0.27) (Loss) gain on short-term investment (0.29) Future income tax reduction 0.40 Depletion, depreciation and accretion expense (1.18) ---------------------------------------------------------------------------- Earnings netback 1.45 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three months ended June 30, 2009 ---------------------------------------------------------------------------- India Bangladesh Total ($/Mcfe) ($/Mcfe) ($/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 expense (0.59) (0.26) (0.45) ---------------------------------------------------------------------------- Operating netback 3.46 1.32 2.58 ---------------------------------------------------------------------------- Interest income and other 0.01 Interest and financing expense (0.24) General and administrative expense (0.11) Realized foreign exchange gain (loss) (0.04) Current income tax expense (0.27) ---------------------------------------------------------------------------- Funds from operations netback 1.93 ---------------------------------------------------------------------------- Unrealized foreign exchange (loss) (0.25) Stock-based compensation expense (0.37) (Loss) gain on short-term investment 1.24 Future income tax reduction - Depletion, depreciation and accretion expense (1.15) ---------------------------------------------------------------------------- Earnings netback 1.40 ---------------------------------------------------------------------------- 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. CORPORATE ---------------------------------------------------------------------------- Three months ended June 30, 2010 2009 ---------------------------------------------------------------------------- Revenues Interest income and other (372) 85 Expenses Interest and financing 8,378 3,506 General and administrative 1,428 1,531 Foreign exchange (gain) loss (1,141) 4,209 Stock based-compensation 7,368 5,408 Loss (gain) on short-term investments 7,826 (18,003) Current income tax expense 6 56 ---------------------------------------------------------------------------- Interest Income and OtherInterest income of $0.3 million is more than offset by an adjustment of $0.7 million related to recording the award of the 36-inch pipeline. The results of the pipeline from inception to December 31, 2009 were audited and adjusted accordingly.Interest and FinancingInterest and financing expense includes the interest portion of payments for the lease of the FPSO of $1.4 million (prior year's quarter - $0.9 million); interest expense on the long-term debt of $2.1 million (prior year's quarter - $2.5 million); and interest and accretion expense on the convertible debentures of $4.9 million (prior year's quarter - nil). Foreign Exchange Three months ended June 30, 2010 2009 ---------------------------------------------------------------------------- Realized foreign exchange (gain) loss (1,415) 627 Unrealized foreign exchange loss 274 3,582 ---------------------------------------------------------------------------- Total foreign exchange (gain) loss (1,141) 4,209 ---------------------------------------------------------------------------- The Company's realized foreign exchange arises on the settlement of Indian-rupee denominated working capital. The gains and losses depend on the timing of settlement of individual accounts receivable and accounts payable as well as the movement in value of the Indian rupee against the U.S. dollar during the period.The unrealized foreign exchange loss arose on the translation of the Indian-rupee denominated income tax receivable to U.S. dollars as a result of the strengthening U.S. dollar against the Indian rupee. This was partially offset by a foreign exchange gain on U.S. dollar cash held by the parent whose functional currency is the Canadian dollar. An offsetting entry decreases the accumulated other comprehensive income but does not flow through the income statement.Stock-based CompensationThere was a net increase in stock-based compensation expense in the year. Stock-based compensation expense increased as a result of an increased number of options being expensed primarily due to the Company's expansion in Indonesia and the increased fair value expense per stock option due to the fluctuations in the Company's stock price.Short-term InvestmentsThe unrealized loss in the year was on marking the short-term investments to market value due. In the prior year, there was an unrealized gain as a result of the increase in market value.LIQUIDITY AND CAPITAL RESOURCESThe Company's financial condition has not changed significantly since March 31, 2010. At June 30, 2010, the Company had total restricted and unrestricted cash of $241 million (March 31, 2010 - $246 million). Of the restricted cash, $25 million will be available for use in the Fiscal 2011 and the remaining $48 million will be available thereafter. The Company has a working capital deficit of $1 million (March 31, 2010 - working capital surplus of $15 million), calculated as current assets less current liabilities.The cash that is currently restricted in accordance with the credit facility agreement is a provision for 30 days of capital and 45 days of operating costs for Hazira, Surat, Block 9 and the Dhirubhai 1 and 3 gas field in the D6 Block and a debt service reserve account. The Company has drawn the full amount available under the credit facility of $166 million and $128 million is expected to be repaid during Fiscal 2011 and the remaining $38 million during Fiscal 2012.On December 30, 2009, the Company entered into a Cdn$310 million convertible debenture credit facility (the "Debentures"). The Debentures bear a coupon rate of 5 percent and mature on December 30, 2012. The interest is paid semi-annually in arrears on January 1st and July 1st of each year. Debentures are convertible at the option of the holder into common shares of the Company at a conversion price of Cdn$110.50 per common share until 60 days prior to the maturity date. After December 30, 2010, the Company may elect to convert all of the debentures into common shares at the conversion price in effect on that date, provided that the weighted average trading price for the prior 21 trading days exceeds Cdn$143.65 per share.During the quarter, the Company made a principal repayment on the long-term debt of $26 million and did not have a significant change in work commitments. There were no other significant changes to the contractual obligations reported as at March 31, 2010.For Fiscal 2011 cash balances, cashflow from operations from the Company's existing producing properties is expected to be in excess of the operating costs, exploration costs, development costs and debt repayments. Cashflow from operations is affected by production levels by fluctuations in foreign exchange rates, changes in operating costs and the market price of oil. The Company has entered into gas contracts for production from the D6 Block with a gas price that is fixed for Fiscal 2011.SUMMARY OF QUARTERLY RESULTSThe following tables set forth selected financial information of the Company for the eight most recently completed quarters to June 30, 2010: Three months ended Sept. 30, Dec. 31, Mar. 31, June 30, 2009 2009 2010 2010 ---------------------------------------------------------------------------- Oil and natural gas revenue 77,879 91,757 110,622 116,501 Gain (loss) on short-term investments 19,685 (26,525) 3,391 (7,826) Net income (loss) 45,043 14,637 38,667 39,756 Per share Basic ($) 0.91 0.29 0.77 0.78 Diluted ($) 0.90 0.29 0.76 0.77 ---------------------------------------------------------------------------- Three months ended Sept. 30, Dec. 31, Mar. 31, June 30, 2008 2008 2009 2009 ---------------------------------------------------------------------------- Oil and natural gas revenue 24,064 28,045 28,503 53,853 Gain (loss) on short-term investment (22,046) (8,898) (311) 18,003 Net income (loss) (21,575) (1,164) (3,153) 20,441 Per share Basic ($) (0.44) (0.02) (0.06) 0.41 Diluted ($) (0.44) (0.02) (0.06) 0.41 ---------------------------------------------------------------------------- Net income has fluctuated over the quarters, due in part to changes in revenue, other income, operating expenses, depletion expense, interest expense, the value of investments and income taxes.In the quarter ended December 31, 2008, revenues increased due to an increase in production from Block 9 as a result of the completion of a plant upgrade as well as the first sale of oil from the D6 Block. Gas production from the D6 Block commenced in the quarter ended June 30, 2009 and ramped-up during the subsequent quarters, substantially increasing revenues in each quarter.Operating expense increased in the quarter ended December 31, 2008 as a result of increased production from Block 9 and the commencement of oil production from the D6 Block. Operating expense increased in the quarter ended June 30, 2009 with the commencement of gas production from the D6 block and did not significantly increase in subsequent quarters despite the increase in gas production from the D6 Block as a significant portion of the operating costs are fixed.There were increases in depletion expense and current income taxes as a result of the increases in production described above. Future income tax recoveries were recorded from the quarter ended June 30, 2010 as a result of minimum alternative tax paid in India for the D6 Block, which are expected to be deductible against current income tax in the future.Interest and other income in the quarter ended December 31, 2009 includes a $9.1 million adjustment related to a 36-inch pipeline that is connected to the Hazira facilities. Due to a dispute that was in arbitration, the Company had been assuming that it could not include the costs of the 36-inch pipeline for cost recovery, specifically, as a deduction in the calculation of profit petroleum. During the quarter, the Company was successful in arbitration and, as a result, pipeline costs will be eligible for cost recovery and the Company recognized the adjustment in the quarter.Interest expense on the long-term debt was capitalized until the commencement of gas production from the D6 Block. In the quarter ended June 30, 2009, interest expense on the long-term debt was expensed, decreasing net income. In the quarter ended March 31, 2010, interest and financing expense increased with interest paid and accretion on the convertible debentures.In the quarter ended December 31, 2008, net income was reduced by $4.2 million as the Company wrote-down the value of a long-term investment the Company held to the Company's share of the book value of the investee's net assets. The Company made purchases of securities throughout the quarters. The short-term investments are 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 magnitude of the gains and losses compared to net income by quarter is displayed in the table above.RELATED PARTIESThe 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. The transactions with the related party are measured at the exchange amount, which is the amount agreed to between related parties.FINANCIAL INSTRUMENTSFinancial instruments of the Company consist of short-term investments, accounts receivable, long-term accounts receivable, accounts payable and accrued liabilities, convertible debentures and long-term debt.The Company is exposed to fluctuations in the value of its cash, accounts receivable, short-term investments, 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 foreign exchange rates as the future interest payments on the convertible debentures are in Canadian dollars. The Company is exposed to changes in the market value of the short-term investments. 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 by entering into contracts with fixed gas prices. 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 accounts receivable, accounts payable and accrued liabilities approximate their carrying values due to their short periods to maturity. The fair value of the short-term investments is based on publicly quoted market values. An unrealized loss on the recognition of the short-term investments at fair value of $8 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 was not significant during the quarter and was recognized in other in income. The debt component of the convertible debentures has been recorded net of the fair value of the conversion feature. The fair value of the conversion feature of the debentures included in shareholders' equity at the date of issue was $15 million. The fair value of the conversion feature of the debentures was determine based on the discounted future payments using a discount rate of a similar financial instrument without a conversion feature compared to the fixed rate of interest on the debentures. Interest and financing expense of $5 million was recorded for interest paid and accretion of the discount on the convertible debentures during the quarter. The fair value of the long-term debt is the amount of funds received by the Company. Interest expense of $2 million was recorded on the long-term debt during the quarter.CRITICAL ACCOUNTING ESTIMATESThe 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 consolidated financial statements of the Company. The critical accounting estimates include oil and natural gas reserves, depletion, depreciation and amortization expense, asset impairment, asset retirement obligation, the amount and likelihood of contingent liabilities and income taxes. The critical accounting estimates are based on variable inputs including:- estimation of recoverable oil and natural gas reserves and future cash flows from the reserves;- geological interpretations, exploration activities and success or failure, and the Company's plans with respect to the property and financial ability to hold the property;- risk-free interest rates;- estimation of future abandonment costs;- facts and circumstances supporting the likelihood and amount of contingent liabilities; and- interpretation of income tax laws.A change in a critical accounting estimate can have a significant effect on net earnings as a result of their impact on the depletion rate, asset retirement provisions, asset impairments, losses and income taxes. A change in a critical accounting estimate can have a significant effect on the value of property, plant and equipment, the asset retirement obligations and accounts payable.For a complete discussion of the critical accounting estimates, please refer to the MD&A for the Company's fiscal year ended March 31, 2010, available at www.sedar.com.NEW ACCOUNTING STANDARDSEffective April 1, 2011, the Company will adopt new accounting standards issued by the Canadian Institute of Chartered Accountants including sections 1582 "Business Combinations", 1601 "Consolidated Financial Statements" and 1602 "Non-controlling interests". These standards replace the existing business combination guidance and section 1600 "Consolidated Financial Statements". Earlier adoption is permitted, provided all three standards are adopted simultaneously.Section 1582 requires equity instruments issued as part of the purchase consideration to be measured at the fair value of the shares at the acquisition date. In addition, the guidance generally requires all acquisition costs to be expensed whereas they could be capitalized as part of the purchase price under the previous standard. The new standard also requires non-controlling interests to be measured at fair value instead of carrying amounts as was the case under the previous standard. Section 1601 establishes the standards for the preparation of Consolidated Financial Statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The adoption of these recommendations is not expected to have a material impact on the Company's consolidated financial statements.FUTURE ACCOUNTING CHANGESInternational Financial Reporting Standards (IFRS)In February 2008, the Accounting Standards Board confirmed that IFRS will be required for interim and annual reporting by publicly accountable enterprises effective for January 1, 2011 including 2010 comparative information. IFRS will replace Canadian generally accepted accounting principles. The first interim consolidated financial statements reported under IFRS will be for the quarter ending June 30, 2011.The Company has developed a changeover plan to complete the transition to IFRS by April 1, 2011, which is the date of transition for the Company. The conversion plan includes the following phases:- Phase I Scoping and diagnostic - designating resources to the project, raising awareness and performing high level diagnostic assessments of accounting differences between IFRS and Canadian GAAP;- Phase II Detailed Assessment - based on items identified in Phase I, performance of systematic and detailed analysis of gaps between the application of current accounting policies and IFRS and consider transitional policy choices. Assessment of impacts on the Company's debt agreements, management reporting systems and business activities;- Phase III Design and implementation - implementation of all changes approved in the assessment phase. Parallel running of Fiscal 2011 financial results and the preparation of IFRS financial statements and disclosures; and- Phase V Evaluation - review of processes and controls to make any required changes.The Company has completed the scoping and diagnostic phase and has completed the analysis under Phase II, but has not selected from available accounting policy alternatives. As a result, management is unable to quantify the impact of adopting IFRS on its financial statements.IFRS 1, "First-Time Adoption of International Financial Reporting Standards" (IFRS1), provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions to the general requirement for full retrospective application of IFRS. The potentially relevant exemptions that are available to the Company are as follows:- an exemption from retroactively recognizing stock-based compensation expense in accordance with IFRS2 Share-based Payment on stock options that were granted on or before November 7, 2002 or those vesting prior to the date of transition to IFRSs. The Company has recognized stock-based compensation expense calculated in accordance with Canadian GAAP for options granted subsequent to April 1, 2003.- an exemption from retroactively restating the value of property, plant and equipment. An entity may elect to measure an item of property, plant and equipment at the date of transition at the value under its previous GAAP.- an exemption from applying IFRIC1 Changes in Existing Decommissioning, Restoration and Similar Liabilities for changes that occurred before the date of transition to IFRSs. Instead, the Company may measure the liability at the date of transition to IFRSs, discount the liability to date of inception and calculate the accumulated depreciation on that amount.The following major differences between Canadian GAAP and IFRS could be significant to the Company:- IFRS 2 Share-based Payment: Similar to Canadian GAAP, under IFRS2 the fair value of the compensation expense associated with the Company's stock option plan will be recognized as an expense with a corresponding increase in equity. The Company's stock options are equity settled. The Company currently estimates a forfeiture rate of nil percent and subsequently adjusts the expense as forfeitures occur. Under IFRS2, the Company will estimate a forfeiture rate that will be considered in the fair value of the stock options.- IFRS 6 Exploration for and Evaluation of Mineral Resources applies to the Company's exploration expenditures.The Company currently capitalizes expenditures prior to obtaining the legal right to explore under its Canadian GAAP policy while these costs will be expensed under IFRSs. In addition, there are options to capitalize or expense and amortize or not amortize exploration and evaluation costs.- IAS16 Property, Plant and Equipment applies to the Company's development and production assets. The Company currently capitalizes costs of development and production assets that meet the definition of an asset under Canadian GAAP and depletes these costs by cost centre, which is a country, based on total proved reserves. Under IFRS, the depletion rate will be calculated at the cash-generating-unit (CGU) level, which is the smallest group of assets capable of independently generating cash inflows. In addition, there are options to expense certain costs in the development and production phase and an option to use a different reserve base in the depletion calculation.- IAS 36 Impairment of Assets requires the Company to assess whether there is any indication that an asset may be impaired at the end of each reporting period. If any such indication exists, the Company will estimate the recoverable amount of the asset.Under Canadian GAAP, the impairment test is applied to the cost centre level, whereas it will be applied to CGUs under IFRS. In addition, the method of calculating the impairment differs.- IAS 37 Provisions, Contingent Liabilities & Contingent Assets indicates how to identify and calculate these items, including asset retirement obligations (ARO). The discount rates applied to estimate future cashflows differ under Canadian GAAP and IFRSs. In addition, ARO is required to be revalued each reporting period at the then prevailing interest rate.- IAS 12 Income Taxes differs from Canadian GAAP for purposes of recognizing deferred taxes, specifically in relation to intercompany transfers, asset acquisitions, foreign currency and other minor items.Other areas that the Company has determined may have different results in the financial statements under IFRSs than under Canadian GAAP include leases and employee benefits. This list of areas impacted by IFRS should not be regarded as a comprehensive list of changes that will result from the transition to IFRS. The Company continues to monitor the development of standards. At this time, the Company has not selected its accounting policies under IFRS.In addition to accounting policy differences, the Company's transition to IFRS will impact information technology and data systems; internal control over financial reporting, disclosure controls and procedures, financial reporting expertise, and business activities as follows:- IT systems - The Company's accounting software does not support the conversion to IFRS. The Company expects to maintain the accounts under Canadian GAAP and IFRS during the conversion process.- Internal control over financial reporting (ICOFR) - Once the accounting policy choices are selected and approved, the Company will assess the changes required for ICOFR. Some of the controls previously performed in Canada are expected to be performed in the branch offices and additional controls are expected to be implemented over the conversion process.- Disclosure controls and procedures (DCP) - The Company anticipates providing information to stakeholders as per the requirements and recommendations of the security regulators through regulatory documents including this and future MD&As.- Financial reporting expertise - The Company's staff responsible for financial reporting have been attending outside courses, seminars and updates on IFRS. The Company has completed in-house IFRS training for 2010 to update and augment the knowledge of key accounting and finance personnel. In addition, the Company attends an IFRS group with its peers to discuss accounting policy choices and implementation issues. Finally, the Company monitors exposure drafts and updates to IFRS on an ongoing basis.- Business activities - The Company has long-term debt and convertible debentures with financial covenants. Both agreements provide for the conversion to IFRS as acceptable accounting principles upon which to base the financial information used in the covenants and the financial information to be provided as per the agreements.DISCLOSURE CONTROLS AND PROCEDURESThe 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 REPORTINGThe 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, 2010 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. Due to the material weakness determined in preparation of the consolidated financial statements for the year ended March 31, 2010, the Company will consider additional controls required in the coming year.RISK FACTORSIn 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 impact the Company's non-U.S. dollar transactions; 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, 2010. Refer to the notes to the Company's consolidated financial statements for a complete list of the contingencies and any potential effects on the Company. OUTSTANDING SHARE DATA At August 10, 2010, the Company had the following outstanding shares: Number Cdn$ Amount (1) ---------------------------------------------------------------------------- Common shares 51,006,052 $1,304,783,000 Preferred shares nil nil Stock options 4,144,709 - ---------------------------------------------------------------------------- (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 10, 2010 is $1,149,272,000. INTERIM CONSOLIDATED BALANCE SHEETS ---------------------------------------------------------------------------- (thousands of U.S. dollars)(unaudited) As at As at June 30, 2010 March 31, 2010 ASSETS Current assets Cash and cash equivalents $ 168,169 $ 196,813 Restricted cash (note 2) 25,096 28,245 Short-term investment 25,705 32,081 Accounts receivable 48,923 47,706 Inventory 541 256 Prepaid expenses and deposits 1,685 724 ---------------------------------------------------------------------------- 270,119 305,825 Restricted cash (note 2) 47,549 21,026 Long-term accounts receivable 42,027 31,128 Income tax receivable 23,246 23,240 Future income tax asset (note 3) 31,410 20,410 Property, plant and equipment 1,864,699 1,844,826 ---------------------------------------------------------------------------- $ 2,279,050 $ 2,246,455 ---------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities Accounts payable and accrued liabilities $ 127,214 $ 123,547 Current tax payable 4,645 1,971 Current portion of capital lease obligation 10,757 10,757 Current portion of long-term debt 128,322 154,811 ---------------------------------------------------------------------------- 270,938 291,086 Asset retirement obligation 31,478 30,520 Capital lease obligation 51,784 53,072 Long-term debt 38,003 38,003 Convertible debentures 279,855 291,063 Future income tax liability 227,746 227,746 ---------------------------------------------------------------------------- 899,804 931,490 Shareholders' equity Share capital (note 4) 1,118,783 1,107,163 Contributed surplus (note 5) 53,806 48,397 Equity component of convertible debentures 14,765 14,765 Accumulated other comprehensive income (note 6) 21,215 12,220 Retained earnings 170,677 132,420 ---------------------------------------------------------------------------- 1,379,246 1,314,965 ---------------------------------------------------------------------------- $ 2,279,050 $ 2,246,455 ---------------------------------------------------------------------------- Segmented information (note 9) Guarantees (note 10) Contingencies (note 11) See accompanying Notes to Consolidated Financial Statements. INTERIM CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME (LOSS) AND RETAINED EARNINGS ---------------------------------------------------------------------------- (thousands of U.S. dollars)(unaudited) Three months ended June 30, 2010 June 30, 2009 Revenue Oil and natural gas $ 116,501 $ 53,853 Royalties (5,219) (2,521) Profit petroleum (6,863) (7,224) Interest income and other (372) 85 ---------------------------------------------------------------------------- 104,047 44,193 Expenses Operating and pipeline 7,375 6,607 Interest and financing (note 7) 8,391 3,506 General and administrative 1,428 1,531 Foreign exchange (gain) loss (1,141) 4,209 Stock-based compensation 7,368 5,408 Loss (gain) on short-term investment 7,826 (18,003) Depletion, depreciation and accretion 32,400 16,697 ---------------------------------------------------------------------------- 63,647 19,955 ---------------------------------------------------------------------------- Income before income taxes 40,400 24,238 ---------------------------------------------------------------------------- Income tax expense Current income tax expense 11,644 3,797 Future income tax reduction (note 3) (11,000) - ---------------------------------------------------------------------------- 644 3,797 ---------------------------------------------------------------------------- Net income $ 39,756 $ 20,441 ---------------------------------------------------------------------------- Net income per share (note 8) Basic $ 0.78 $ 0.41 Diluted $ 0.77 $ 0.41 ---------------------------------------------------------------------------- Comprehensive income: Net Income $ 39,756 $ 20,441 Foreign currency translation gain 8,995 7,198 ---------------------------------------------------------------------------- Comprehensive income $ 48,751 $ 27,639 ---------------------------------------------------------------------------- Retained earnings, beginning of period $ 132,420 $ 19,446 Net income 39,756 20,441 Dividends paid (1,499) (1,359) ---------------------------------------------------------------------------- Retained earnings, end of period $ 170,677 $ 38,528 ---------------------------------------------------------------------------- See accompanying Notes to Consolidated Financial Statements. INTERIM CONSOLIDATED STATEMENTS OF CASH FLOWS ---------------------------------------------------------------------------- (thousands of U.S. dollars)(unaudited) Three months ended, June 30, 2010 June 30, 2009 Cash provided by (used in): Operating activities Net income $ 39,756 $ 20,441 Add items not involving cash from operations: Unrealized foreign exchange loss 274 3,582 Unrealized loss (gain) on short-term investment 7,826 (18,003) Accretion of convertible debentures 1,070 - Stock-based compensation 7,368 5,408 Depletion, depreciation and accretion 32,400 16,697 Future income tax reduction (11,000) - Other 13 139 Change in non-cash working capital 9,886 (4,599) Change in long-term accounts receivable (8,561) (325) ---------------------------------------------------------------------------- 79,032 23,340 Financing activities Proceeds from issuance of shares, net of issuance costs (note 4) 9,023 13,637 Dividends paid (1,499) (1,359) Repayment of long-term debt (26,489) - ---------------------------------------------------------------------------- (18,965) 12,278 ---------------------------------------------------------------------------- Investing activities Addition of property, plant and equipment (51,154) (73,198) Reduction in capital lease obligations (1,249) (695) Restricted cash contributions (33,589) (6,419) Restricted cash released 10,215 73,800 Addition to short-term investment (2,698) - Change in non-cash working capital (3,007) (33,197) Change in cash call advances (5,817) 103 ---------------------------------------------------------------------------- (87,299) (39,606) ---------------------------------------------------------------------------- Decrease in cash and cash equivalents (27,232) (3,988) Effect of foreign currency translation on cash and cash equivalents (1,412) 1,101 Cash and cash equivalents, beginning of period 196,813 31,189 ---------------------------------------------------------------------------- Cash and cash equivalents, end of period $ 168,169 $ 28,302 ---------------------------------------------------------------------------- See accompanying Notes to Consolidated Financial Statements. NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTSFor the three months ended June 30, 2010 (unaudited). All tabular amounts are in thousands of U.S. dollars except per share amounts, numbers of shares and stock options, stock option and share prices, and certain other figures as indicated.1. BASIS OF PRESENTATIONThe interim consolidated financial statements include the accounts of Niko Resources Ltd. ("the Company") and all of its subsidiaries. The majority of the exploration, development and production activities of the Company are conducted jointly with others and, accordingly, these consolidated financial statements reflect only the Company's proportionate interest in such activities. The interim consolidated financial statements 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, 2010. 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, 2010. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto for the year ended March 31, 2010.Certain comparative figures have been reclassified to conform to the current year presentation. 2. RESTRICTED CASH ---------------------------------------------------------------------------- As at June As at March 30, 2010 31, 2010 ---------------------------------------------------------------------------- Current portion of restricted cash Guarantees(1) $ 18,688 $ 21,838 Funds restricted under the facility agreement(2) 6,408 6,407 ---------------------------------------------------------------------------- Total $ 25,096 $ 28,245 ---------------------------------------------------------------------------- Non-current portion of restricted cash Guarantees(1) $ 3,545 $ 1,500 Debt service reserve account(3) 39,132 14,489 Site restoration fund(4) 4,872 5,037 ---------------------------------------------------------------------------- Total $ 47,549 $ 21,026 ---------------------------------------------------------------------------- (1) The Company has performance security guarantees related to the work commitments for exploration blocks. The Company is required to provide funds to support the guarantees in the amounts indicated above. See note 10 for details of the guarantees. (2) The current portion of cash that is restricted under the facility agreement is restricted to payments of capital and operating costs for Hazira, Surat, Block 9 and the Dhirubhai 1 and 3 gas field in the D6 Block including amounts recorded in accounts payable and accrued liabilities and amounts to be incurred in the upcoming year. The amount of the cash that is restricted is a provision for 30 days of forecast capital costs and 45 days of forecast operating costs for these blocks. (3) The Company funds the debt service reserve account for 50 percent of the forecast interest payments and debt repayments in the upcoming 6-month period in accordance with the terms of the facility agreement. (4) In accordance with the Site Restoration Fund Scheme, 1999 in India, the Company is required to accumulate funds in a separate restricted account related to future asset retirement obligations. The funds may be used for site restoration on the expiry or termination of an agreement or relinquishment of part of the contract area. 3. FUTURE INCOME TAX ASSET ---------------------------------------------------------------------------- Three months ended Year ended June 30, 2010 March 31, 2010 ---------------------------------------------------------------------------- Future income tax asset, beginning of period $ 20,410 $ - Future income tax reduction(1) 11,000 20,410 ---------------------------------------------------------------------------- Future income tax asset, end of period $ 31,410 $ 20,410 ---------------------------------------------------------------------------- (1) The future income tax reduction is tax credit available for future years related to minimum alternative tax paid for D6 in the current period. 4. SHARE CAPITAL ---------------------------------------------------------------------------- (a) AUTHORIZED Unlimited number of common shares Unlimited number of preferred shares (b) ISSUED Three months ended Year ended June 30, 2010 March 31, 2010 ---------------------------------------------------------------------------- Number Amount Number Amount ---------------------------------------------------------------------------- Common shares Balance, beginning of period 50,818,110 $ 1,107,163 49,298,133 $ 997,189 Shares issued for property acquisition - - 397,379 39,691 Stock options exercised 150,437 9,023 1,122,598 54,997 Transferred from contributed surplus on exercise of stock options - 2,597 - 15,286 ---------------------------------------------------------------------------- Balance, end of period 50,968,547 $ 1,118,783 50,818,110 $ 1,107,163 ---------------------------------------------------------------------------- (c) STOCK OPTIONSThe Company has reserved for issue 5,096,854 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: Three months ended Year ended June 30, 2010 March 31, 2010 ---------------------------------------------------------------------------- Weighted Weighted Average Average Number Exercise Number Exercise of Options Price (Cdn$) of Options Price (Cdn$) ---------------------------------------------------------------------------- Outstanding, beginning of period 4,056,714 75.88 4,030,750 64.69 Granted 322,625 105.49 1,530,312 92.18 Forfeited (2,000) 96.61 (282,375) 90.25 Expired - - (99,375) 92.72 Exercised (150,437) 61.35 (1,122,598) 52.80 ---------------------------------------------------------------------------- Outstanding, end of period 4,226,902 78.65 4,056,714 75.88 ---------------------------------------------------------------------------- Exercisable, end of period 764,087 60.21 730,399 58.21 ---------------------------------------------------------------------------- The following table summarizes stock options outstanding and exercisable under the plan at June 30, 2010: Outstanding Options Exercisable Options ---------------------------------------------------------------------------- Remaining Weighted Weighted Exercise Life Average Average Price Options (Years) Price (Cdn$) Options Price (Cdn$) ---------------------------------------------------------------------------- $ 41.00 - $ 49.99 1,050,815 2.3 48.59 231,250 44.98 $ 50.00 - $ 59.99 251,687 0.7 53.68 235,312 53.70 $ 60.00 - $ 69.99 265,625 1.8 62.90 138,750 62.53 $ 70.00 - $ 79.99 70,000 3.0 75.72 5,000 79.69 $ 80.00 - $ 89.99 738,363 2.7 85.63 38,300 81.93 $ 90.00 - $ 99.99 1,230,325 2.5 95.51 115,325 93.15 $ 100.00 - $ 109.99 596,212 4.2 104.76 150 105.47 $ 110.00 - $112.64 23,875 3.7 111.30 - - ---------------------------------------------------------------------------- 4,226,902 2.6 78.65 764,087 60.21 ---------------------------------------------------------------------------- 5. CONTRIBUTED SURPLUS ---------------------------------------------------------------------------- Three months ended Year ended June 30, March 31, 2010 2010 ---------------------------------------------------------------------------- Contributed surplus, beginning of period $ 48,397 $ 41,494 Stock-based compensation 8,006 22,189 Stock options exercised (2,597) (15,286) ---------------------------------------------------------------------------- Contributed surplus, end of period $ 53,806 $ 48,397 ---------------------------------------------------------------------------- 6. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) ---------------------------------------------------------------------------- Three months ended Year ended June 30, 2010 March 31, 2010 ---------------------------------------------------------------------------- Accumulated other comprehensive income (loss), beginning of period $ 12,220 $ (2,406) Other comprehensive income: Foreign currency translation gain 8,995 14,626 ---------------------------------------------------------------------------- Accumulated other comprehensive income, end of period $ 21,215 $ 12,220 ---------------------------------------------------------------------------- 7. INTEREST AND FINANCING EXPENSE Three months ended June 30, 2010 2009 ---------------------------------------------------------------------------- Interest expense related to capital lease $ 1,351 $ 885 Interest expense on long-term debt 2,141 2,482 Interest expense on convertible debentures 3,816 - Accretion expense on convertible debentures 1,070 - Other 13 139 ---------------------------------------------------------------------------- Interest and financing expense $ 8,391 $ 3,506 ---------------------------------------------------------------------------- 8. 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, 2010 2009 ---------------------------------------------------------------------------- Weighted average number of common shares outstanding - basic 50,884,368 49,430,508 - diluted 51,412,517 49,701,037 ---------------------------------------------------------------------------- Options totaling 193,625 for the quarter ended June 30, 2010 (1,633,313 for the quarter ended June 30, 2009) were considered anti-dilutive as they were out-of-the money and were therefore excluded from the calculation of diluted per share amounts.The convertible debentures were anti-dilutive for the quarter ended June 30, 2010 and have been excluded from the calculation of diluted earnings per share above. The convertible debentures were issued during the year ended March 31, 2010.9. SEGMENTED INFORMATIONThe Company's operations are conducted in one business sector, the oil and natural gas industry. Geographical areas are used to identify the Company's reportable segments. A geographic segment is considered a reportable segment once its activities are regularly reviewed by the Company's management. The accounting policies used in the preparation of the information of the reportable segments are the same as those described in the summary of significant accounting policies. Revenues, segment profits and capital additions by reportable segments are as follows: ---------------------------------------------------------------------------- Three months ended June 30, 2010 ---------------------------------------------------------------------------- Segment Capital Segment Revenue Profit (Loss) Additions ---------------------------------------------------------------------------- Bangladesh $ 13,477 $ 940 $ (910) India 102,811 63,354 15,276 Indonesia - - 11,520 Kurdistan - - 4,760 Madagascar - - 19,467 Pakistan - - 610 Trinidad - - 1,030 All other(1) 213 (294) 139 ---------------------------------------------------------------------------- Total $ 116,501 $ 64,000 $ 51,892 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three months ended June 30, 2009 ---------------------------------------------------------------------------- Segment Capital Segment Revenue Profit (Loss) Additions ---------------------------------------------------------------------------- Bangladesh $ 14,159 $ 1,793 $ 7,863 India 39,588 15,734 52,352 Indonesia - - 5,587 Kurdistan - - 6,507 Madagascar - - 478 Pakistan - - 42 Trinidad - - - All other(1) 106 (520) 369 ---------------------------------------------------------------------------- Total $ 53,853 $ 17,007 $ 73,198 ---------------------------------------------------------------------------- (1) Revenues included in All other are from Canadian oil sales. As at June 30, 2010 As at March 31, 2010 ---------------------------------------------------------------------------- Property, Property, Plant and Plant and Segment Equipment Total Assets Equipment Total Assets ---------------------------------------------------------------------------- Bangladesh $ 115,765 $ 153,628 $ 122,536 $ 159,433 India 1,002,420 1,164,331 1,013,691 1,147,703 Indonesia 548,753 574,797 537,233 562,071 Kurdistan 72,352 73,111 67,592 68,433 Madagascar 28,957 29,018 9,490 9,584 Pakistan 25,257 25,322 24,647 24,665 Trinidad 66,173 68,110 65,143 67,706 All other 5,022 190,733 4,494 206,859 ---------------------------------------------------------------------------- Total $ 1,864,699 $ 2,279,050 $ 1,844,826 $ 2,246,454 ---------------------------------------------------------------------------- The reconciliation of the segment profit to net income as reported in the consolidated financial statements is as follows: Three months ended June 30, 2010 2009 ---------------------------------------------------------------------------- Segment profit $ 64,000 $ 17,007 Interest income and other (372) 85 Interest and financing expense (8,391) (3,506) General and administrative expenses (1,428) (1,531) Foreign exchange gain (loss) 1,141 (4,209) Stock-based compensation expense (7,368) (5,408) (Loss) gain on short-term investments (7,826) 18,003 ---------------------------------------------------------------------------- Net income $ 39,756 $ 20,441 ---------------------------------------------------------------------------- 10. GUARANTEES ---------------------------------------------------------------------------- As at As at June 30, 2010 March 31, 2010 ---------------------------------------------------------------------------- Performance security guarantees included in restricted cash(1) Cauvery - India $ 804 $ 804 D4 - India 3,234 984 Indonesia 18,195 21,550 Performance security guarantees not included in restricted cash(2) Indonesia 2,454 2,454 Madagascar 1,178 1,178 ---------------------------------------------------------------------------- Total Guarantees $ 25,865 $ 26,970 ---------------------------------------------------------------------------- (1) The Company is required to provide funds to support the guarantees in the amounts indicated above. (2) These performance security guarantees are not reflected on the balance sheet as they are supported by Export Development Canada. The Company has performance security guarantees related to the capital commitments for exploration blocks. The guarantees are cancelled when the Company completes the work required under the exploration period.11. CONTINGENCIES(a) During the year ended March 31, 2006, a group of petitioners in Bangladesh (the petitioners) filed a writ with the High Court Division of the Supreme Court of Bangladesh (the High Court) against various parties including Niko Resources (Bangladesh) Ltd. (NRBL), a subsidiary of the Company.In November 2009, the High Court ruled on the writ. Both the Company and the petitioners have the right to appeal the ruling to the Supreme Court. The ruling can be summarized as follows: ---------------------------------------------------------------------------- Petitioner Request High Court Ruling ---------------------------------------------------------------------------- That the Joint Venture Agreement The Joint Venture Agreement for Feni for the Feni and Chattak fields and Chattak fields is valid. be declared null and illegal. ---------------------------------------------------------------------------- That the government realize from The compensation claims should be the Company compensation for the decided by the lawsuit described natural gas lost as a result of in note (b) below or by mutual the uncontrolled flow problems agreement. as well as for damage to the surrounding area. ---------------------------------------------------------------------------- That Petrobangla withhold future Petrobangla to withhold future payments to the Company relating payments to the Company related to to production from the Feni production from the Feni field field ($27.9 million as at June until the lawsuit described in note 30, 2010). (b) below is resolved or both parties agree to a settlement. ---------------------------------------------------------------------------- That all bank accounts of the The ruling did not address this Company maintained in issue, therefore the previous Bangladesh be frozen. ruling stands. Funds in the Company's bank accounts maintained in Bangladesh cannot be repatriated pending resolution of the lawsuit the lawsuit described in note (b) below. ---------------------------------------------------------------------------- On January 7, 2010, NRBL requested an arbitration proceeding with the International Centre for the Settlement of Investment disputes (ICSID). The arbitration is between NRBL and three respondents: The People's Republic of Bangladesh; Bangladesh Oil, Gas & Mineral Corporation (Petrobangla); and Bangladesh Petroleum Exploration & Production Company Limited (Bapex). The arbitration hearing will attempt to settle all compensation claims described in this note and note (b). ICSID registered the request on May 24, 2010.In June 2010, the Company filed an additional proceeding with ICSID to resolve its claims for payment from Petrobangla in accordance with the Gas Purchase and Sale Agreement with Petrobangla to receive all amounts for previously delivered gas.(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 357,651,000 ($5.3 million) for 3 Bcf of free natural gas delivered from the Feni field as compensation for the burnt natural gas;(ii) taka 702,188,000 ($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 ($12.4 million) for environmental damages, an amount subject to be increased upon further assessment;(iv) taka 5,364,765,000 ($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.ICSID has registered the request for arbitration of the issues indicated above as discussed in note 11(a). In addition, the Company will actively defend itself against the lawsuit, which may take an extended period of time to settle. Alternatively, the Company may attempt to receive a stay order on the lawsuit pending either a settlement and/or results of ICSID arbitration.The Company believes that the outcome of the lawsuit and/or ICSID arbitration and the associated cost to the Company, if any, are not determinable. As such, no amounts have been recorded in these consolidated financial statements. Settlement costs, if any, will be recorded in the period of determination.(c) In accordance with natural gas sales contracts to customers of production from the Hazira field in India, the Company had committed to deliver certain minimum quantities and was unable to deliver the minimum quantities for a period ending December 31, 2007. The Company's partner in the Hazira field delivered the shortfall volumes in return for either (a) delivery of replacement volumes five times greater than the shortfall; (b) a cash payment; or (c) a combination of (a) and (b). The Company estimates the cash amount to settle the contingency at US$10 million. The Company believes that the outcome is not determinable.(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 interest, 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 profit petroleum expense. No amount has been recorded in these consolidated financial statements. Settlement costs, if any, will be recorded in the period of determination.(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 eligible undertakings related to the Hazira and Surat fields.The Company has received unfavourable tax assessments related to taxation years 1999 through 2006. The assessments contend the 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. The assessment for the 2007 taxation year is in progress.In India, there are potentially four levels of appeal related to tax assessments: Commissioner Income Tax - Appeals ("CIT-A"); the Income Tax Appellate tribunal ("ITAT"); the High Court; and the Supreme Court.For taxation years 1999 to 2004, the Company has received favourable rulings at ITAT and the revenue Department has appealed to the High Court. For the 2005 taxation year, the Company has received a favourable ruling at CITA and for the 2006 taxation year, the Company's CITA appeal is pending.In August 2009, the Government of India through the Finance (No.2) Act 2009 amended the tax holiday provisions in the Income Tax Act (Act).The amended Act provides that the blocks licensed under the NELP-VIII round of bidding and starting commercial production on or after April 1, 2009 are eligible for the tax holiday on production of natural gas. However, the budget did not address the issue of whether the tax holiday is applicable to natural gas production from blocks that have been awarded under previous rounds of bidding, which includes all of the Company's Indian blocks. The Company has previously filed and recorded its income taxes on the basis that natural gas will be eligible for the tax holiday.With respect to "undertakings" eligible for the tax holiday deduction, the Act was amended to include an "explanation" on how to determine undertakings. The Act now states that all blocks licensed under a single contract shall be treated as a single undertaking. The "explanation" is described in the amendment as having retrospective effect from April 1, 2000. Since tax holiday provisions became effective April 1, 1997, it is unclear as to why the "explanation" has effect from April 1, 2000. The Hazira production sharing contract (PSC) was signed in 1994 and commenced production prior to April 1, 2000. As a result, the Company is unable to apply the amended definition of "undertaking" to the Hazira PSC. The Company has previously filed and recorded its income taxes for the taxation years of 1999 to 2008 on the basis of multiple undertakings for the Hazira and Surat PSC.The Company will continue to pursue both issues through the appeal process. The Company has challenged the retrospective amendments to the undertakings definition and the lack of clarification of whether natural gas is eligible for the tax holiday with the Gujarat High Court. The Company was granted an interim relief by the High Court on March 12, 2010 instructing the Revenue Department to not give effect to the "explanation" referred to above retrospectively until the matter is clarified in the courts. Even if the Company receives favourable outcomes with respect to both issues discussed above, the Revenue Department can challenge other aspects of the Company's tax filings.For the taxation year ending March 31, 2009, the Company has filed its tax return assuming natural gas is eligible for the tax holiday at Hazira and Surat but, unlike all previous years, has filed its tax return based on Hazira and Surat each having a single undertaking. The Company has reserved its right, under Indian tax law, to claim the tax holiday with multiple undertakings. While the Company still believes that it is eligible for the tax holiday on multiple undertakings, the change in method of filing is because the legislative changes, referred to above, lead to ambiguity in the Act. More specifically, if the Company had filed its return in a manner that is deemed to be in violation of the current legislation, the Company can be liable for interest and penalties. Further, at the time of filing the tax return, the Company had not appealed the amendments brought out in the tax holiday provisions and did not have the benefit of the interim relief by the High Court. As a result, the Company has filed in a more conservative manner than its interpretation of tax law as described previously. Despite filing in a conservative manner, the Company will continue to pursue the tax holiday changes through the appeals process.Should the High Court overturn the rulings previously awarded in favour of the Company by the Tribunal court, and the Company either decides not to appeal to the Supreme Court or appeals to the Supreme Court and is unsuccessful, the Company would record a tax expense of approximately $63 million, pay additional taxes of $40 million and write off approximately $23 million of the net income tax receivable. In addition, the Company could be obligated to pay interest on taxes for the past periods related to the periods assessed up to and including fiscal 2006.(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, if any, to the Company are not determinable and no amounts have been recorded in these consolidated financial statements. Costs, if any, will be recorded in the period of determination.(g) In December 2009, the arbitration of ownership of a 36-inch pipeline that is connected to the Hazira facilities in India was ruled in favor of the Company and its joint venture partner. The Government of India has filed a writ with the High Court in Delhi challenging the arbitration decision. The High Court has issued notice to the Company that the hearing has not yet commenced. If the appeal is heard and the court rules against the Company and its joint venture partner, the Company will exclude the pipeline for cost recovery purposes in the calculation of profit petroleum and reverse the income and the capital asset recorded with respect to the pipeline. This would result in downward adjustments to net income of $12 million, to property, plant and equipment of $5 million, to accounts receivable of $17 million and to accounts payable of $10 million.FOR FURTHER INFORMATION PLEASE CONTACT: Niko Resources Ltd. Edward S. Sampson Chairman of the Board, President and Chief Executive Officer 403-262-1020 www.nikoresources.com