The Globe and Mail

Go to the Globe and Mail homepage

Jump to main navigationJump to main content

Globe Investor

News Sources

Take control of your investments with the latest investing news and analysis

Press release from Marketwire

Niko Reports Results for the Quarter Ended June 30, 2012

Monday, August 13, 2012

Niko Reports Results for the Quarter Ended June 30, 201218:00 EDT Monday, August 13, 2012CALGARY, ALBERTA--(Marketwire - Aug. 13, 2012) - 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, 2012. The operating results are effective August 13, 2012. All amounts are in U.S. dollars unless otherwise indicated and all amounts are reported using International Financial Reporting Standards unless otherwise indicated.REVIEW OF OPERATIONS AND GUIDANCESales VolumesThree months ended June 30,Year ending March 31,201120122013ActualActualForecastOil and condensate (bbls/d)2,0201,3561,220Gas production (Mcf/d)234,261180,719168,000Total production (Mcfe/d)246,379188,854175,000The primary reason for the decline in sales volumes during the quarter was reduced volumes from the D6 block. Production in the three months ended June 30, 2012 averaged 189 MMcf/d compared to Niko's full year forecast of 175 MMcf/d. The Company's full year forecast is unchanged.Funds from OperationsThree months ended June 30,Year ending March 31,201120122013(millions of U.S. dollars)ActualActualForecastFunds from operations6040150As with sales volumes, the primary reason for the variance relates to production from the D6 block. Funds from operations for the three months ended June 30, 2012 were $40 million compared to the Company's full year forecast of $150 million. The Company's full year forecast is unchanged.Capital additions and expensed exploration(thousands of U.S. dollars)Three months ended June 30, 2012Indonesia35,651Trinidad19,065All other3,619Total58,335Spending in the first quarter totalled $58 million and was 28 percent of the Company's full year forecast of $210 million. The Company's full year forecast is unchanged.Indonesia: Spending includes two wells at Lhokseumawe. The first well costing $12 million was plugged and abandoned without reaching target depth due to mechanical problems and was subsequently expensed. Testing of the second well subsequent to the end of the quarter did not encounter commercial quantities of hydrocarbons and costs incurred to June 30, 2012 of $8 million included above will be expensed in the subsequent quarter. A further $5 million was spent on activities to prepare for the upcoming drilling campaign, $6 million for seismic and other exploration projects and $5 million for branch office costs.Trinidad: Spending includes $8 million for the Shadow-1 well being drilled in Block 2ab. A further $5 million was incurred for seismic costs for the Guayaguayare area and $5 million for payments that are specified in the various PSCs.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 three months ended June 30, 2012 should be read in conjunction with the audited consolidated financial statements for the year ended March 31, 2012. This MD&A is effective August 13, 2012. 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 thousands of U.S. 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, 2012 through June 30, 2012. The term "prior year's quarter" is used throughout the MD&A for comparative purposes and refers to the period from April 1, 2011 through June 30, 2011.The fiscal year for the Company is the 12-month period ended March 31. The terms "Fiscal 2012" and "prior year" is used throughout this MD&A and in all cases refers to the period from April 1, 2011 through March 31, 2012. The terms "Fiscal 2013", "current year" and "the year" are used throughout the MD&A and in all cases refer to the period from April 1, 2012 through March 31, 2013.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 3 percent of total corporate production volumes and total corporate revenue are from Canadian oil and Bangladesh condensate. Therefore, the results from Canadian oil and Bangladesh 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, and 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 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 when the change is material 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-IFRS MeasuresThe selected financial information presented throughout the MD&A is prepared in accordance with International Financial Reporting Standards (IFRS), 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 oil and natural gas revenue less: the cash portion of production and operating expenses, general and administrative expenses, the cash portion of net finance expense, realized foreign exchange gain/loss, current income tax expense/reduction and minimum alternate tax expense.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, production and operating expenses, depletion expense, exploration and evaluation expense and current and deferred 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-IFRS measures do not have any standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other companies.OVERALL PERFORMANCEFunds from OperationsThree months ended June 30,(thousands of U.S. dollars)20122011Oil and natural gas revenue55,09988,278Production and operating expenses(7,879)(9,031)General and administrative expenses(2,050)(2,158)Net finance expense(6,085)(5,799)Realized foreign exchange gain / (loss)345(151)Current income recovery / (expense)2,377(3,106)Minimum alternate tax expense(1,285)(7,881)Funds from operations (1)40,52260,152(1)Funds from operations is a non-IFRS measure as defined under "Non-IFRS measures" in this MD&A.Oil and natural gas revenue has decreased $33 million in the quarter compared to the prior year's quarter. The change is comprised of approximately 80 percent decrease related to gas production and oil sales at the D6 Block and the remaining 20 percent decrease related to an adjustment to profit petroleum expense at Hazira. Gas production from the D6 Block was 170 MMcf/d in the prior year's quarter and 114 MMcf/d in the quarter. Declines in production from the D6 Block are expected to continue unless volumes are added from new fields. D6 oil sales decreased from 1,644 Bbls/d at a price of $113.60/Bbl in the prior year's quarter to 1,015 Bbls/d at a price of $97.96/Bbl in the quarter. An additional $6 million of profit petroleum expense for the Hazira Field was recognized and reduced oil and natural gas revenue in the quarter. The adjustment related to oil and natural gas revenues of prior years' was the result of a court ruling received indicating that the 36-inch pipeline was not eligible for cost recovery.There was a current income tax recovery as a result of the adjustment to profit petroleum, which is deductible for tax purposes.Minimum alternate tax expense is calculated on accounting income from the D6 Block. Higher depletion rates reduced accounting income and minimum alternate tax expense.Net Income (Loss)Three months ended June 30,(thousands of U.S. dollars)20122011Funds from operations (non-IFRS measure)40,52260,152Production and operating expenses(307)(524)Depletion and depreciation expense(42,409)(31,193)Exploration and evaluation expense(36,429)(14,084)(Loss) / gain on short-term investments(245)1,215Asset impairment(39,101)-Share-based compensation expense(3,559)(6,196)Finance expense(1,996)(1,790)Unrealized foreign exchange (loss) / gain(5,136)89Deferred income tax expense(3,461)(4,787)(92,121)2,882Change in accounting estimate-deferred taxes-(57,865)Net income (loss)(92,121)(54,983)The decrease in funds from operations is described above. Other items affecting the net income (loss) are described below.Depletion expense for the D6 Block increased as a result of the revision to the reserve volumes and future costs included in the March 31, 2012 reserve report, partially offset by the effect of decreased production.Exploration and evaluation expense of $36 million is comprised of $12 million for an unsuccessful exploration well in Lhokseumawe in Indonesia, $7 million of seismic and other exploration projects for various blocks in Indonesia, $5 million of seismic costs for the Guayaguayare area in Trinidad, $5 million for quarterly payments that are specified in the various PSCs, $5 million for branch office costs for all exploration properties and $2 million for new venture activities.The Company estimated the recoverable amount of Kurdistan exploration and evaluation assets and recognized an impairment of $39 million.Share-based compensation expense decreased as a result of a decrease in the fair value per stock option granted as a result of the lower stock price in the quarter.The Indian Rupee weakened against the U.S. dollar during the quarter. As a result, there was an unrealized foreign exchange loss in the year on revaluing the Indian-rupee based income tax receivable to U.S. dollars.In the prior year's quarter, the change in accounting estimate is related to deferred income taxes as a result of estimating the amount of taxable temporary differences reversing during the tax holiday period.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.IndiaD6 - The Company has a 10 percent working interest in the 7,645-square-kilometre D6 Block. The D6 Block comprised 72 percent of the Company's oil and gas revenue during the quarter. Production of oil from the MA discovery began in September 2008 and production of gas 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. 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, 2012, 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.Surat - The Company holds a development area of 24 square kilometres containing the Bheema and NSA shallow natural gas fields. The block comprised 2 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, 2013.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 the exploration minimum work commitment for the block.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 21 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, 2012, the profit share was 61 percent.IndonesiaThe Company holds interests in PSCs for 22 offshore exploration blocks covering 116,930 square kilometres. The chart below indicates the location, award date, the Company's working interest and the size of the block.Block NameOffshore AreaAward DateWorking InterestArea (Square Kilometres)Bone BaySulawesi SWNov. 200845%4,969South East Ganal (1)Makassar StraitNov. 2008100%4,868Seram (1)Seram NorthNov. 200855%4,991South Matindok (1)Sulawesi NENov. 2008100%5,182West Sageri (1)Makassar StraitNov. 2008100%4,977CendrawasihPapua NWMay 200945%4,991Kofiau (1)West PapuaMay 200957.5%5,000KumawaPapua SWMay 200945%5,004East Bula (1)Seram NENov. 200955%6,029Halmahera-Kofiau (1)Papua WNov. 200951%(2)4,926North Makassar (1)Makassar StraitNov. 200930%1,787West Papua IV (1)Papua SWNov. 200951%(2)6,389Cendrawasih Bay IIPapua NWMay 201050%5,073Cendrawasih Bay III (1)Papua NWMay 201050%4,689Cendrawasih Bay IV (1)Papua NWMay 201050%3,904Sunda Strait I (1)Sunda StraitMay 2010100%6,960Obi (1)Papua WNov. 201151%(2)8,057North GanalMakasar StraitNov. 201131%2,432Halmahera IIPapua WDec. 201120%6,000South East Seram (1)Papua SWDec. 2011100%8,217Lhokseumawe (2)AcehOct. 200530%4,431AruPapua SWJuly 201260%8,054(1)Operated by the Company. (2)The Company has entered into a farmout and joint bidding agreement that, subject to government approval, will reduce its working interest to 42% in the Obi block. The Company has entered into a farmout agreement for the West Papua IV and Halmahera-Kofiau blocks whereby the farmee will obtain an additional working interest, subject to government approval, that would reduce the Company's working interest to 40%. The Company has entered in to a farmout agreement that, subject to government approval, it will acquire a 30% working interest in the Lhokseumawe block.All of the blocks are in the first exploration period with the exception of Lhokseumawe. The Company and its partners have fulfilled the seismic work commitments on the majority of the blocks. Eleven of the blocks have a single well commitment. The Company and its partner have drilled two wells in the Lhokseumawe PSC. The first well was plugged and abandoned without reaching target depth due to mechanical problems and testing of the second well did not encounter commercial quantities of hydrocarbons. Drilling has also commenced on the Company's non-operated North Ganal block. The Company has contracted a rig and the drilling program for the Company's operated blocks is expected to commence in September 2012. The Company's share of the remaining minimum work commitments as specified in the PSCs for the exploration period is $90 million to be spent at various dates up to June 2015. The Company is required to relinquish a portion of the exploration acreage after the first three years of the contract, however, the Company has received extensions in order to fulfill the well commitments on certain blocks.KurdistanThe onshore Qara Dagh block covers approximately 846 square kilometres, in the Sulaymaniyah Governorate of the Federal Region of Kurdistan in Iraq. The 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 block. In August 2011, the Company agreed to pay an additional cost interest related to a partner's cash call commitments. In return, in the event a commercial discovery is made, Niko will receive an amount equal to the net proceeds of sale associated with a 12 percent undivided interest in the block.The exploration period is for a term of five years and is extendable by two one-year terms. An exploratory well was drilled between May 2010 and October 2011 to a depth of 4,196 metres, which was the maximum depth possible with the drilling equipment. Multiple zones tested, however, not at commercial rates. The Company has left the well in such a condition that it retains the option to re-enter the well at a later date. The Company's share of the remaining minimum work commitment as specified in the PSC for the exploration period is $6 million to be spent by May 2013.TrinidadThe Company holds interests in ten PSCs/license for seven exploration areas and for one development area (Block 5(c)). The chart below indicates the location, PSC date, the Company's working interest and the size of the block.Exploration AreaLocationAward DateWorking interestArea (Square Kilometres)Block 2AB (1)OffshoreJuly 200935.75%1,605Guayaguayare-Shallow Horizon (1)Onshore/OffshoreJuly 200965%1,134Guayaguayare-Deep Horizon (1)Onshore/OffshoreJuly 200980%1,190Central Range-Shallow HorizonOnshoreSept. 200832.5%734Central Range-Deep HorizonOnshoreSept. 200840%856Block 4(b) (1)OffshoreApril 2011100%754NCMA2 (1)OffshoreApril 201156%1,020NCMA3 (1)OffshoreApril 201180%2,107Block 5(c)OffshoreJuly 200525%324MG Block(1)OffshoreJuly 200770%223(1)Operated by the Company.The Company has minimum exploration work commitments for the acquisition or reprocessing of seismic and to drill a total of 15 wells on the blocks. The seismic work commitment has been met for all of the areas. Three of the commitment wells have been drilled to date and the Shadow-1 commitment well is in progress. The Company's share of the remaining minimum work commitments as specified in the PSCs for the exploration period is $175 million to be spent by various dates up to April 2016.Block 5(c) is located 94 kilometres off the east coast of Trinidad and the development plan is awaiting government approval.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. The Company's share of the remaining minimum work commitment as specified in the PSC for the exploration period is $10 million to be spent by September 2015. A well location is expected to be selected after seismic interpretation.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. The Company has received a one-year extension to the Phase I exploration period, which now ends March 2014. The Company has substantially completed the commitments under this phase through seismic activity. The Company has evaluated the seismic and has selected drilling locations.Capital additions and exploration and evaluation costs expensed directly to incomeThree months ended June 30, 2012(thousands of U.S. dollars)Additions to exploration and evaluation asset(1)Directly expensed exploration and evaluation costs(1)Additions to property, plant and equipment(1)TotalIndonesia24,21011,441-35,651Trinidad8,46310,602-19,065All other4902,2688613,619Total33,16324,31186158,335(1)Share-based compensation and other non-cash items are excluded. Includes additions in the year that were subsequently written off.Indonesia: Additions to the exploration and evaluation asset for Indonesia are for two wells at Lhokseumawe. The first well costing $12 million was plugged and abandoned without reaching target depth due to mechanical problems and was subsequently expensed. Testing of the second well subsequent to the end of the quarter did not encounter commercial quantities of hydrocarbons and costs incurred to June 30, 2012 of $8 million included in additions to exploration and evaluation asset above will be expensed in the subsequent quarter. The remaining additions in Indonesia relate to activities to prepare for the upcoming drilling campaign. Exploration and evaluation costs expensed directly to income include $6 million for seismic and other exploration projects and $5 million for branch office costs.Trinidad: Additions to the exploration and evaluation asset for Trinidad are for the Shadow-1 well being drilled in Block 2ab. Exploration and evaluation costs expensed directly to income include $5 million of seismic costs for the Guayaguayare area and $5 million quarterly payments that are specified in the various PSCs.SEGMENT PROFITINDIAThree months ended June 30,(thousands of U.S. dollars)20122011Natural gas revenue45,11266,813Oil and condensate revenue (1)10,33318,769Royalties(2,853)(4,405)Profit petroleum(7,322)(1,923)Production and operating expenses(6,086)(7,453)Depletion expense(37,822)(27,508)Exploration and evaluation expenses60(457)Current income tax recovery / (expense)2,380(3,113)Minimum alternate tax expense(1,285)(7,881)Deferred income tax reduction(4,497)(4,787)Change in accounting estimate - deferred taxes-(57,865)Segment profit / (loss)(2)(1,980)(29,810)Daily natural gas sales (Mcf/d)120,459178,992Daily oil and condensate sales (bbls/d) (1)1,1481,819Operating costs ($/Mcfe)$0.50$0.43Depletion rate ($/Mcfe)$3.26$1.59(1)Production that is in inventory has not been included in the revenue or cost amounts indicated.(2)Segment profit / (loss) is a non-IFRS measure as calculated above.Segment profit from India includes the results from the Dhirubhai 1 and 3 gas fields and the MA oil field in the D6 Block, the Hazira oil and gas field and the Surat gas field.Revenue and RoyaltiesThe Company's gas production for the quarter was 120 MMcf/d compared to 179 MMcf/d in the prior year's quarter. The reduction in production was primarily due to reservoir complexity and natural decline at the D6 Block. Declines are expected to continue unless production volumes are added from new fields in the D6 Block.Oil production decreased due to a reduction in reservoir pressure associated with production from the MA field in the D6 Block. The realized price was $98.95/Bbl in the quarter compared to $113.41/Bbl in the prior year's quarter. Decreased production and sales price contributed to the decrease in oil and condensate revenue.The decrease in royalties is a result of the decreased revenues described above. Royalties applicable to production from the D6 Block are 5 percent for the first seven years of commercial 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. An additional $6 million of profit petroleum expense for the Hazira Field was recognized and reduced oil and natural gas revenue in the quarter. The adjustment, related to oil and natural gas revenues of prior years', was the result of a court ruling received indicating that the 36-inch pipeline was not eligible for cost recovery.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 expense will continue at this level until the Company has recovered its costs.The government was entitled to 25 percent and 20 percent of the profits from Hazira and Surat, respectively.Production and Operating ExpensesOperating costs at the D6 Block decreased as less maintenance was conducted during the quarter compared to the prior year's quarter.Depletion, Depreciation and AccretionThe depletion rate increased as a result of the revision to the reserve volumes and future costs included in the March 31, 2012 reserve report. The effect of the increased depletion rate on the depletion expense was partially offset by decreased production.Income TaxesThere was a current income tax recovery as a result of the adjustment to profit petroleum described above, which is deductible for tax purposes.Minimum alternate tax expense is calculated on accounting income from the D6 Block. Higher depletion rates reduced accounting income and minimum alternate tax expense.ContingenciesThe Company has contingencies related to gas sales contracts and the profit petroleum calculation for Hazira and related to income taxes for Hazira and Surat as at June 30, 2012. Refer to the consolidated financial statements and notes for the three months ended June 30, 2012 for a complete discussion of the contingencies.BANGLADESHThree months ended June 30,(thousands of U.S. dollars)20122011Natural gas revenue12,70611,617Condensate revenue1,9291,960Profit petroleum(4,956)(4,598)Production and operating expenses(2,009)(2,096)Depletion expense(3,793)(2,786)Exploration and evaluation expenses(180)(259)Segment profit / (loss)(1)3,6973,838Daily natural gas sales (Mcf/d)60,26055,269Daily condensate sales (bbls/d)190182Operating costs ($/Mcfe)$0.36$0.41Depletion rate ($/Mcfe)$0.68$0.54(1)Segment profit is a non-IFRS measure as calculated above.Revenue, Profit Petroleum, Depletion and Operating ExpensesBlock 9 experienced technical problems during the prior year's quarter. The gas price was consistent during the quarters at $2.32/Mcf.Pursuant to the terms of the PSC for Block 9, the Government of Bangladesh was entitled to 61 percent of profit gas in the year and prior year, which equates to 34 percent of revenues while the Company is recovering historical capital costs. Overall, profit petroleum expense increased due to increased revenues from Block 9.Depletion expense increased on a unit-of-production basis as a result of the addition of the dew-point control unit.ContingenciesThe Company has contingencies related to various claims raised against the Company with respect to the Feni property in Bangladesh as at June 30, 2012. Refer to the consolidated financial statements and notes for the three months ended June 30, 2012 for a complete discussion of the contingencies.INDONESIA, KURDISTAN AND TRINIDADExploration and evaluation expenseAsset impairmentIncome tax recoverySegment Profit(thousands ofThree months ended June 30,U.S. dollars)20122011201220112012201120122011Indonesia(23,345)(6,093)--1,035-(22,310)(6,093)Kurdistan(904)(918)(39,101)---(40,005)(918)Trinidad(11,112)(5,400)----(11,112)(5,400)Indonesia: Costs of the unsuccessful Candralila well in Lhokseumawe of $12 million were expensed in the quarter, seismic and other exploration projects totaling $6 million were incurred for various blocks, $1 million was spent on new ventures and $5 million to operate the branch office. The prior year expense relates primarily to seismic programs.Kurdistan: The Company estimated the recoverable amount of Kurdistan exploration and evaluation assets and recognized an impairment of $39 million.Trinidad: Exploration and evaluation costs expensed directly to income include $5 million of seismic costs for the Guayaguayare area and $5 million quarterly payments that are specified in the various PSCs.CORPORATEThree months ended June 30,(thousands of U.S. dollars)20122011Share-based compensation3,5596,196Finance expense8,3237,737Foreign exchange loss4,79162Loss / (gain) on short-term investments245(1,215)Share-based compensationThe fair value per stock option granted decreased in the quarter due to the decreased stock price in the quarter.Finance expenseThree months ended June 30,(thousands of U.S. dollars)20122011Interest expense6,2625,758Accretion expense1,9961,790Other65178Finance expense8,3237,726Interest expense increased as a result of the outstanding loan balance with no corresponding borrowings in the prior year's quarter. Accretion expense is on the Company's convertible debentures and decommissioning obligations. The recorded liability for the convertible debenture increases as time progresses to the maturity date resulting in a higher accretion expense than in the prior period.Foreign ExchangeThree months ended June 30,(thousands of U.S. dollars)20122011Realized foreign exchange (gain) / loss(345)151Unrealized foreign exchange loss / (gain)5,136(89)Total foreign exchange loss4,79162The Company's realized foreign exchange losses and gains arise primarily because of the difference between the Indian rupee to U.S. dollar exchange rate at the time of recording individual accounts receivable and accounts payable compared to the exchange rate at the time of receipt of funds to settle recorded accounts receivable and payment to settle recorded accounts payable.The unrealized foreign exchange loss in the year arose primarily on the translation of the Indian-rupee denominated income tax receivable and site restoration deposit to U.S. dollars as a result of the weakening of the rupee versus the U.S. dollar.There were additional foreign exchange gains in the year on U.S. dollar cash held by the parent whose functional currency is the Canadian dollar. An offsetting entry increases the accumulated other comprehensive income but does not flow through the income statement.Short-term InvestmentsThe loss on short-term investments for the year was a result of marking the short-term investments to market value.NETBACKSThe following tables outline the Company's operating, funds from operations and earnings netbacks (all of which are non-IFRS measures):Three months ended June 30, 2012Three months ended June 30, 2011($/Mcfe)IndiaBangladeshTotalIndiaBangladeshTotalOil and natural gas revenue4.782.624.094.952.654.42Royalties(0.25)-(0.17)(0.25)-(0.20)Profit petroleum(0.63)(0.89)(0.71)(0.11)(0.90)(0.29)Production and operating expense(0.50)(0.36)(0.46)(0.43)(0.41)(0.40)Operating netback3.401.372.754.161.343.53G&A(0.12)(0.10)Net finance expense(0.33)(0.27)Current income tax recovery / (expense)0.14(0.14)Minimum alternate tax(0.07)(0.35)Funds from operations netback2.372.67Production and operating expenses(0.02)(0.02)Exploration and evaluation costs(2.12)(0.63)Asset impairment(2.28)-Share-based compensation expense(0.21)(0.31)(Loss) / gain on short-term investment(0.01)0.05Deferred income tax expense(0.20)(0.21)Change in accounting estimate - deferred taxes-(2.57)Net finance expense(0.42)(0.08)Depletion and depreciation expense(2.47)(1.35)Earnings netback(5.36)(2.45)The netback for India, Bangladesh and in total for the Company is a non-IFRS 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. Mcfe is derived by converting oil and condensate to natural gas in the ratio of 1 bbl:6 Mcf.LIQUIDITY AND CAPITAL RESOURCESAt June 30, 2012, the Company had unrestricted cash of $50 million. The Company had a working capital deficit (current assets less current liabilities) of $275 million at June 30, 2012. The deficit includes $301 million related to convertible debentures that mature on December 30, 2012.The 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. The Company has the option to convert all of the Debentures at maturity into common shares at a 6 percent discount to the weighted average trading price for the 20 trading days prior to the election. The Company's preference is to not exercise this option, but rather to repay the holders with cash proceeds from other actions that could include high yield debt, proceeds from additional farm-outs, asset sales and other options.In January 2012, the Company entered into a three-year facility agreement for a $225 million credit facility and a $25 million operating facility for general corporate purposes and has borrowed $41 million against this facility. The maximum available credit under this facility is subject to review based on, among other things, updates to the Company's reserves. The Company has experienced a significant downward revision to its reserves and the syndicate of lenders are currently reviewing the reserve information to determine the impact, if any, on the maximum available credit under the facility. The Company expects that the maximum available under the facility will be reduced as a result of this review.The Company expects that it will use its unrestricted cash on hand of $50 million as at June 30, 2012 and remaining forecast funds from operations of $110 million for the fiscal period to fund the its remaining planned capital program for Fiscal 2013 of $152 million. The Company intends to use its credit facility, as necessary, to fund working capital or other needs that may arise during the year. Cashflow from operations is affected by production levels, by fluctuations in foreign exchange rates, changes in operating costs and the market price of oil.The Company has a number of contingencies as at June 30, 2012 that could significantly impact the liquidity of the Company. Refer to the notes to the Company's consolidated financial statements for a complete list of the contingencies and any potential effects on the Company.SUMMARY OF QUARTERLY RESULTSThe following tables set forth selected financial information of the Company, in thousands of U.S. dollars unless otherwise indicated, for the eight most recently completed quarters to June 30, 2012:Three months endedSept. 30, 2011Dec. 31, 2011Mar. 31, 2012June 30, 2012Oil and natural gas revenue (1)86,81074,78971,43455,099 (2)Net income (loss)(43,916)(40,405)(183,324)(92,121)Per shareBasic ($)(0.85)(0.78)(3.55)(1.78)Diluted ($)(0.85)(0.78)(3.55)(1.78)Three months endedSept. 30, 2010Dec. 31, 2010Mar. 31, 2011June 30, 2011Oil and natural gas revenue (1)105,78199,22094,16888,277Net income (loss)23,78525,8066,234(54,983)Per shareBasic ($)0.470.500.12(1.07)Diluted ($)0.460.500.12(1.07)(1)Oil and natural gas revenue is oil and natural gas sales less royalties and profit petroleum expense. (2)An additional $6 million of profit petroleum expense for the Hazira Field was recognized and reduced oil and natural gas revenue in the quarter. The adjustment related to oil and natural gas revenues of prior years' was the result of a court ruling received indicating that the 36-inch pipeline was not eligible for cost recovery. 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 to the quarter ended September 30, 2010. D6 gas production began to decline in the subsequent quarters due to well performance. Operating expense increased as additional wells in the D6 Block came on-stream and in 2010 when gas production commenced from the MA oil field.Net income in the quarters was affected by: The Company repaid its long-term debt in October 2010 decreasing finance expense, thereafter. The Company's short-term investments are valued at fair value, which is the quoted market price. Gains and losses are recognized throughout the quarters based on fluctuations in the market prices. The Company expensed a portion of the exploration and evaluation costs during the quarters and the level of activity varies over the periods. The Company impaired assets of $133 million and long term receivables of $23 million in the quarter ended March 31, 2012 and assets of $39 million in the quarter ended June 30, 2012. For the quarter ended June 30, 2011, there was a change in accounting estimate related to deferred income tax expense. There was a revision in the method of estimating the amount of taxable temporary differences reversing during the tax holiday period. For the quarter ended September 30, 2011, there was a $14 million expense upon cancellation of stock options to recognize the remainder of the expense associated with the options. Depletion expense increased in the quarter ended March 31, 2011 and again in the quarter ended March 31, 2012 as a result of revisions to the reserves and estimated future costs to develop the reserves. In the quarter ended March 31, 2011, $9.7 million fine was recorded related to the Company's guilty plea to one count of bribery under the Corruption of Foreign Public Officials Act relating to two specific instances that occurred in 2005. There was a deferred income tax recovery in the quarter ended March 31, 2012 related to the revision to the reserve estimate, which increased the value of the tax holiday for the D6 Block and there were deferred income tax recoveries related to spending in Indonesia and Trinidad applied against the deferred income tax liabilities recorded upon the acquisitions of Voyager Energy Ltd. and Black Gold Energy LLC. An additional $6 million of profit petroleum for the Hazira Field was recognized in the quarter ended June 30, 2012. The adjustment was the result of a court ruling received indicating that the 36-inch pipeline was not eligible for cost recovery. 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, borrowings and convertible debentures.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 and the local currencies of the countries in which the Company operates. 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 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 (to a defined maximum) 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. A loss on the recognition of the short-term investments at fair value of $0.2 million was recognized in income for the quarter.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 in the quarter was recorded for interest expense and accretion of the discount on the convertible debentures.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, decommissioning obligations, 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, decommissioning obligations, 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, decommissioning 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, 2012, available at www.sedar.com.ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIEDThe International Accounting Standards Board (IASB) has issued IFRS 9 "Financial Instruments" to replace IAS 39 "Financial Instruments: Recognition and Measurement". The new standard replaces the multiple classification and measurement models for financial assets and liabilities with a new model that has only two categories: amortized cost and fair value through profit and loss. Under IFRS 9, fair value changes due to credit risk for liabilities designated at fair value through profit and loss would generally be recorded in other comprehensive income. The Company is currently assessing the impact of the new standard on its consolidated financial statements.In May 2011, the IASB issued or amended a number of standards that will be effective for annual periods beginning on or after January 1, 2013. Three new standards are IFRS 10 "Consolidated Financial Statements", IFRS 11 "Joint Arrangements" and IFRS 12 "Disclosure of Interests in Other Entities". IFRS 10 establishes a single control model that applies to all entities and will require management to exercise judgment to determine which entities are controlled and need to be consolidated by the parent. The Company will continue to consolidate all of its wholly-owned subsidiaries and is currently assessing the accounting impact of its investments in other companies. IFRS 11 replaces IAS 31 "Interest in Joint Ventures" and SIC-13 "Jointly-controlled Entities - Non-monetary Contributions by Venturers". IFRS 11 identifies two forms of joint ventures when there is joint control: joint operations and joint ventures. Joint operations are accounted for using proportionate consolidation and joint ventures are accounted for using the equity method. IFRS 11 focuses on the nature of the rights and obligations associated with the joint arrangements and the Company is currently evaluating the effect of this standard on its joint arrangements. IFRS 12 introduces a number of new disclosures related to consolidated financial statements and interests in subsidiaries, joint arrangements, associates and structured entities. As a result of the new standards described above, the IAS has amended IAS 28 "Investments in Associates and Joint Ventures" to prescribe the accounting for investments in associates and to set out the requirements for the application of the equity method when accounting for investments in associates and joint ventures.The IASB published IFRS 13 "Fair Value Measurement" which provides a precise definition of fair value and a single source of fair value measurement disclosures requirements for use across IFRSs.The IASB issued amendments to IAS 1 Presentation of Financial Statements requiring companies preparing financial statements in accordance with IFRSs to group together items within other comprehensive income (OCI) that may be reclassified to the profit or loss section of the income statement. The amendments apply to annual periods beginning on or after July 1, 2012.The IASB reissued IAS 27 "Separate Financial Statements" to focus solely on accounting and disclosure requirements when an entity presents separate financial statements that are not consolidated financial statements.The Company is currently assessing the disclosure impact of the standards listed above on its consolidated financial statements.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 quarterly 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 International Financial Reporting Standards.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 internal controls over financial reporting during the quarter ended June 30, 2012. In August 2011, the Company hired a dedicated employee to function as the Chief Compliance Officer and perform the duties previously fulfilled by an existing officer. The Chief Compliance Officer reports to the Audit Committee.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; 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, 2012. 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 DATAAt August 13, 2012, the Company had the following outstanding shares:NumberCdn$ Amount (1)Common shares51,641,8451,325,403,000Preferred sharesNilNilStock options4,004,128-(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 13, 2012 is $1,171,439,000. CONDENSED INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION(unaudited) (thousands of U.S. dollars)As at June 30, 2012As at March 31, 2012Assets Current assetsCash and cash equivalents49,58764,495Restricted cash5,6376,790Accounts receivable (note 3)59,49461,247Short-term investment487748Inventories11,2779,961126,482143,241Restricted cash11,97111,283Long-term accounts receivable1,2762,202Long-term investment2,6982,752Exploration and evaluation assets (notes 4, 13)837,555856,880Property, plant and equipment (note 5, 13)469,476509,091Income tax receivable (note 14f)33,01534,724Deferred tax asset53,81758,3141,536,2901,618,487LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities94,238101,660Current tax payable1,2901,220Finance lease obligation4,8044,804Convertible debentures301,341306,052401,673413,736Decommissioning obligation40,52140,017Finance lease obligation42,38843,671Borrowings41,00025,000Deferred tax liabilities194,479195,515720,061717,939Shareholders' EquityShare capital (note 7)1,171,4391,171,439Contributed surplus110,632104,964Equity component of convertible debentures14,76514,765Currency translation reserve3,057(2,094)Deficit(483,664)(388,526)816,229900,5481,536,2901,618,487The accompanying notes are an integral part of these financial statements. CONDENSED INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)(unaudited)Three months ended June 30,(thousands of U.S. dollars, except per share amounts)20122011Oil and natural gas revenue (note 8)55,09988,278Production and operating expenses(8,186)(9,555)Depletion and depreciation expense (note 5)(42,409)(31,193)Exploration and evaluation expenses (note 9)(36,429)(14,084)(Loss) / gain on short-term investments(245)1,215Asset impairment (note 4)(39,101)-Share-based compensation expense (note 7)(3,559)(6,196)General and administrative expenses (note 10)(2,050)(2,158)(76,880)26,307Finance income242137Finance expense (note 11)(8,323)(7,726)Foreign exchange loss(4,791)(62)Net finance expense(12,872)(7,651)Income (loss) before income tax(89,752)18,656Current income tax recovery / (expense)2,377(3,106)Minimum alternate tax expense(1,285)(7,881)Deferred income tax expense(3,461)(62,652)Income tax (expense)(2,369)(73,639)Net loss(92,121)(54,983)Foreign currency translation gain / (loss)5,151(1,117)Comprehensive loss for the period(86,970)(56,100)Loss per share: (note 12)Basic$(1.78)$(1.07)Diluted$(1.78)$(1.07)The accompanying notes are an integral part of these financial statements.CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY(unaudited) (thousands of U.S. dollars, except number of common shares)Common shares (#)Share capitalContributed surplusCurrency translation reserveEquity component of convertible debenturesDeficitTotalBalance, March 31, 201151,526,9011,162,31963,037(8,344)14,765(53,392)1,178,385Options exercised1,570143(35)---108Share-based compensation expense--8,303---8,303Net loss for the period-----(54,983)(54,983)Payment of dividends(1)-----(3,225)(3,225)Foreign currency translation---(1,117)--(1,117)Balance, June 30, 201151,528,4711,162,46271,305(9,461)14,765(111,600)1,127,471Options exercised113,3748,977(2,253)---6,724Share-based compensation expense--35,912---35,912Net loss for the period-----(267,645)(267,645)Payment of dividends(1)-----(9,281)(9,281)Foreign currency translation---7,367--7,367Balance, March 31, 201251,641,8451,171,439104,964(2,094)14,765(388,526)900,548Options exercised-------Share-based compensation expense--5,668---5,668Net loss for the period-----(92,121)(92,121)Payment of dividends(1)-----(3,017)(3,017)Foreign currency translation---5,151--5,151Balance, June 30, 201251,641,8451,171,439110,6323,05714,765(483,664)816,229(1)The Company paid dividends of $0.06 per share in the three months ended June 30, 2011 and 2012.The accompanying notes are an integral part of these financial statements. CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CASHFLOWS(unaudited)Three months ended June 30,(thousands of U.S. dollars)20122011Cash flows from operating activities:Net loss(92,121)(54,983)Adjustments for:Depletion and depreciation expense42,40931,193Accretion expense1,9961,790Deferred income tax reduction3,46162,652Unrealized foreign exchange loss / (gain)5,136(89)Loss / (gain) on short-term investment245(1,215)Asset impairment39,101-Exploration and evaluation write-off12,46712,855Share-based compensation expense5,4027,949Change in non-cash working capital5,64216,741Change in long-term accounts receivable(1,782)27,390Net cash from operating activities21,956104,283Cash flows from investing activities:Exploration and evaluation expenditures(32,898)(115,583)Property, plant and equipment expenditures(3,194)(3,010)Restricted cash contributions(2,202)(600)Release of restricted cash2,0194,459Disposition of investments-1,106Change in non-cash working capital(12,216)(6,967)Net cash used in investing activities(48,491)(120,595)Cash flows from financing activities:Proceeds from issuance of share capital, net of issuance costs-109Change in loans and borrowings16,000-Reduction in finance lease liability(1,283)(1,141)Dividends paid(3,017)(3,225)Net cash from financing activities11,700(4,257)Change in cash and cash equivalents(14,835)(20,569)Effect of translation on foreign currency cash(73)1,413Cash and cash equivalents, beginning of period64,495108,342Cash and cash equivalents, end of period49,58789,186The accompanying notes are an integral part of these financial statements.NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS1. General InformationNiko Resources Ltd. (the "Company") is a limited company incorporated in Alberta, Canada. The addresses of its registered office and principal place of business is 4600, 400 - 3 Avenue SW, Calgary, AB, T2P4H2. The Company is engaged in the exploration for and development and production of oil and natural gas in the countries listed in note 13. The Company's common shares are traded on the Toronto Stock Exchange.2. Basis of PresentationThe condensed 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 financial statements reflect only the Company's proportionate interest in such activities. The condensed interim consolidated financial statements have been prepared in accordance with IAS 34 - Interim Financial Reporting using accounting policies consistent with International Financial Reporting Standards ("IFRS"). 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, 2012. 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, 2012. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto for the year ended March 31, 2012.The consolidated financial statements are presented in US dollars and all values are rounded to the nearest thousand dollars ($000), except where otherwise indicated.These financial statements were authorized for issue by the Board of Directors on August 13, 2012.3. Accounts receivable(thousands of U.S. dollars)As at June 30, 2012As at March 31, 2012Oil and gas revenues receivable24,62828,033Receivable from joint venture partners11,78513,004Advances to vendors2,0491,751Prepaid expenses and deposits5,6584,816VAT receivable11,4269,405Other receivables3,9484,23859,49461,2474.Exploration and evaluation assets(thousands of U.S. dollars)Three months ended June 30, 2012Year ended March 31, 2012Opening balance856,880762,221Additions (note 13)33,163164,976Transfers-5,354Expensed(12,418)(71,500)Asset impairment(38,801)-Disposals-(2,355)Foreign currency translation(1,269)(1,816)Closing balance837,555856,880The Company estimated the recoverable amount of Kurdistan exploration and evaluation assets and recognized an impairment of $39 million in the statement of comprehensive (loss). The Company expensed $12 million for an exploration well in Lhokseumawe in Indonesia that was plugged and abandoned without reaching target depth due to mechanical problems. Testing of a second well in Lhokseumawe subsequent to the end of the quarter did not encounter commercial quantities of hydrocarbons and costs included as additions above to June 30, 2012 of $8 million will be expensed in the subsequent quarter.5.Property, plant and equipmenta. Development assets(thousands of U.S. dollars)Three months ended June 30, 2012Year ended March 31, 2012Opening balance16,98818,421Additions8307,447Expensed(49)-Transfers to other asset categories-(8,880)Closing balance17,76916,988b. Producing assets(thousands of U.S. dollars)Three months ended June 30, 2012Year ended March 31, 2012CostOpening balance1,042,8691,019,696Additions-16,458Transfers from other asset categories-6,791Foreign currency translation494(76)Closing balance1,043,3631,042,869Accumulated depletionOpening balance(453,957)(312,767)Additions(41,615)(141,266)Foreign currency translation(494)76Closing balance(496,066)(453,957)Impairment(133,415)(133,415)Net producing assets413,882455,497c.Other Property, plant and equipment(thousands of U.S. dollars)Land and buildingsTransportation VehiclesOffice equipment, furniture and fittingsPipelinesTotalCostBalance, March 31, 201218,3462,3768,75410,77240,248Additions / Transfers3-26231Disposals-----Foreign currency translation--104-104Balance, June 30, 201218,3492,3768,88410,77440,383Accumulated depreciationBalance, March 31, 2012(6,127)(1,482)(4,449)(7,341)(19,399)Additions(252)(42)(356)(144)(794)Disposals-----Foreign currency translation--36-36Balance, June 30, 2012(6,379)(1,524)(4,769)(7,485)(20,157)Net book value, June 30, 201211,9708524,1153,28920,226(thousands of U.S. dollars)Land and buildingsTransportation VehiclesOffice equipment, furniture and fittingsPipelinesTotalCostBalance, March 31, 201118,1082,3955,97810,75237,233Additions238-2,907203,165Disposals-(19)(89)-(108)Foreign currency translation loss--(42)-(42)Balance, March 31, 201218,3462,3768,75410,77240,248Accumulated depreciationBalance, March 31, 2011(4,880)(1,148)(3,390)(6,738)(16,156)Additions(1,247)(352)(1,126)(603)(3,328)Disposals-1834-52Foreign currency translation gain--33-33Balance, March 31, 2012(6,127)(1,482)(4,449)(7,341)(19,399)Net book value, March 31, 201212,2198944,3053,43120,849d. Capital work-in-progress(thousands of U.S. dollars)As at June 30, 2012As at March 31, 2012Capital work-in-progress17,59915,7576.Convertible DebenturesThe Company issued Cdn$310 million, 5 percent convertible debentures (the "Debentures") on December 30, 2009. The Debentures mature on December 30, 2012 with interest paid semi-annually in arrears on January 1st and July 1st of each year. The Debentures are convertible at the option of the holder into common shares of the Company at a conversion price of Cdn$110.50 per common share until 60 days prior to the maturity date. The Company has the option to convert all of the Debentures at maturity into common shares at a 6 percent discount to the weighted average trading price for the 20 trading days prior to the election. The Company's preference is to not exercise this option, but rather to repay the holders with cash proceeds from other actions that could include high yield debt, proceeds from additional farm-outs, asset sales and other options.7. Share capitala. Fully paid ordinary sharesThe Company has authorized for issue an unlimited number of common shares and an unlimited number of preferred shares. The common shares issued are fully paid and the shares have no par value. No preferred shares have been issued.b. Share options granted under the employee share option planThe Company has reserved for issue 5,164,184 common shares for granting under stock options to directors, officers, and employees. The options become vested immediately to five years after the date of grant and expire one to six years after the date of grant. The stock options are settled in equity.Stock option transactions for the respective periods were as follows:Three months ended June 30, 2012Year ended March 31, 2012Number of optionsWeighted average exercise price (Cdn$)Number of optionsWeighted average exercise price (Cdn$)Opening balance3,978,00375.624,243,89785.37Granted132,12536.861,160,75055.70Forfeited(30,000)69.74(155,750)86.43Cancelled--(587,500)102.13Expired(87,500)89.14(568,450)80.97Exercised--(114,944)58.01Closing balance3,992,62874.093,978,00375.62Exercisable1,081,99986.50952,62485.19The following table summarizes stock options outstanding and exercisable under the plan at June 30, 2012:Outstanding OptionsExercisable OptionsExercise PriceOptionsRemaining life (years)Weighted average exercise price (Cdn$)OptionsWeighted average exercise price (Cdn$)31.32 - 39.99110,5004.036.22--40.00 - 49.991,214,0662.247.62154,81149.3550.00 - 59.99252,3753.652.04--60.00 - 69.99217,1252.863.6239,00063.6670.00 - 79.9967,2502.673.4350075.7580.00 - 89.99615,0631.486.23322,56388.8790.00 - 99.991,115,0001.595.99516,25095.95100.00 - 109.99376,4992.6104.3244,500106.47110.00 - 112.6424,7502.4111.094,375111.303,992,6282.174.091,081,99986.50The weighted average share price during the three months ended June 30, 2012 was $27.85 (2011 - $75.19).c. Fair value measure of equity instruments grantedThe fair value of each option granted was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average inputs:(thousands of U.S. dollars)Three months ended June 30, 2012Three months ended June 30, 2011Grant-date fair valueCdn$11.62Cdn$25.53Market price per shareCdn$36.86Cdn$76.93Exercise price per optionCdn$36.86Cdn$76.93Expected volatility42%41%Expected life (years)3.74.0Expected dividend rate0.6%0.3%Risk-free interest rate1.4%2.2%Expected forfeiture rate8.8%6.0%Expected volatility was determined based on the historical movements in the closing price of the Company's stock for a length of time equal to the expected life of each option. See note d. below for categorization of share-based payment expense during the period.d. Share-based compensation disclosureThe Company prepares its statement of comprehensive income (loss) classifying costs according to function as opposed to the nature of the costs. As a result, share-based compensation expense is charged to various other headings in the statement of comprehensive income (loss).(thousands of U.S. dollars)Three months ended June 30, 2012Three months ended June 30, 2011Share-based compensation expense included in:Exploration and evaluation assets266354Operating expense307524Exploration and evaluation expense1,5361,229Share-based compensation expense3,5596,196Total5,6688,3038.Revenue(thousands of U.S. dollars)Three months ended June 30, 2012Three months ended June 30, 2011Natural gas sales57,81978,430Oil and condensate sales12,40620,773Less:Royalties(2,848)(4,404)Government's share of profit petroleum(12,278)(6,521)Oil and natural gas revenue55,09988,278Revenues from oil and gas sales to Petrobangla comprised 21 percent of natural gas, oil and condensate sales for the three months ended June 30, 2012 (2011 - 14 percent).The Company recorded a $6 million adjustment to the Government's share of profit petroleum due to a court ruling indicating the 36-inch pipeline is not eligible for cost recovery. The Company has appealed the decision with division bench of Delhi High Court.9.Exploration and evaluation expenses(thousands of U.S. dollars)Three months ended June 30, 2012Three months ended June 30, 2011Geological and geophysical11,7194,199Exploration and evaluation12,03415General and administrative5,8423,442Production sharing contract annual payments4,8064,174New ventures4921,025Share-based compensation1,5361,229Exploration and evaluation36,42914,08410.General and administrative expense(thousands of U.S. dollars)Three months ended June 30, 2012Three months ended June 30, 2011Salaries1,127238Legal fees1032,036Consultants127160Rent138191Management fees142163Audit fees40113Insurance10-Office costs61-Other364(325)Head office costs reclassified according to function(62)(418)General and administrative expense2,0502,158The Company prepares its statement of comprehensive income (loss) classifying costs according to function as opposed to the nature of the costs. As a result, general and administrative expenses are charged to various other headings in the statement of comprehensive income. General and administrative expenses of $5.8 million for the three months ended June 30, 2012 (2011 - $3.7 million) are categorized as exploration and evaluation expenses and of $2.1 million for the three months ended June 30, 2012, (2011 - $2.7 million) are categorized as production and operating expenses. (thousands of U.S. dollars)Three months ended June 30, 2012Three months ended June 30, 2011Audit fees41163Management fees145166Legal fees1992,237Salary3,7011,917Insurance1,7601,584Security240221Rent514390Travel187198Consultants178212Non-operating and other2,660856Office costs238678Total9,8638,62211.Finance expense(thousands of U.S. dollars)Three months ended June 30, 2012Three months ended June 30, 2011Interest expense related to capital lease1,3991,540Interest expense on long-term debt1,028-Interest expense on convertible debentures3,8353,987Accretion expense on convertible debentures1,3061,266Accretion expense on decommissioning obligations690524Bank fees and charges and other finance costs65409Finance expense8,3237,72612.Earnings per shareThe earnings used in the calculation of basic and diluted per share amounts are as follows: (thousands of U.S. dollars)Three months ended June 30, 2012Three months ended June 30, 2011Net loss(92,121)(54,983)A reconciliation of the weighted average number of ordinary shares for the purpose of calculating basic earnings per share to the weighted average number of ordinary shares for the purpose of calculating diluted earnings per share is as follows: (thousands of U.S. dollars)Three months ended June 30, 2012Three months ended June 30, 2011Weighted average number of common shares used in the calculation of basic and diluted earnings per share51,641,84551,527,531As a result of the net loss in the quarters ended June 30, 2012 and 2011, the outstanding stock options of 3,992,628 and 4,512,752, respectively, and shares issuable upon conversion of the outstanding debentures of 2,805,430 as at June 30, 2012 and 2011 were considered anti-dilutive to the loss per share and were excluded from the weighted average number of common shares for the purposes of diluted earnings per share. The average market value of the Company's common shares for purposes of calculating the dilutive effect of stock options for the periods was based on quoted market prices for the periods that the options were outstanding. The number of shares issuable upon conversion of the outstanding debentures is based on the conversion price of Cdn$110.50 per common share, which is applicable to conversion at the option of the holder until 60 days prior to the maturity date.13. Segmented Informationa. Products and services from which reportable segments derive their revenuesThe Company's operations are conducted in one business sector, the oil and natural gas industry. All revenues are from external customers. All of Bangladesh sales are received from one customer and this customer accounted for 21 percent of sales during the three months ended June 30, 2012.b. Determination of reportable segmentsGeographical 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 of the information of the reportable segments are the same as those described in the summary of significant accounting policies.c. Segment assets and liabilities, revenues and resultsThree months ended June 30, 2012Year ended March 31, 2012Additions to:SegmentExploration and evaluation assets (E&E)Property, plant and equipment (PP&E) (1)Exploration and evaluation assetsProperty, plant and equipmentBangladesh-26363755India1045672,43223,144Indonesia24,210-16,676-Kurdistan386-24,795-Madagascar--9-Pakistan--248-Trinidad8,463-120,7536All other-31-3,165Total33,163861164,97627,070(1)Excludes changes in capital work-in-progress.As at June 30, 2012As at March 31, 2012SegmentTotal E&ETotal PP&ETotal assetsTotal E&ETotal PP&ETotal assetsBangladesh4,73728,07242,6914,73731,60546,617India136,203416,610684,739136,104454,421730,134Indonesia522,4642,278552,669510,161-534,923Kurdistan12,104-16,26850,51974954,573Madagascar1,211-1,2861,209-1,377Pakistan248-310248-310Trinidad160,5882,290190,600153,9021,467190,617All other-20,22647,727-20,84959,936Total837,555469,4761,536,290856,880509,0911,618,487To view the Segmented Table, please visit the following link: http://media3.marketwire.com/docs/NKOsegTAB813.pdf 14. Contingent Liabilitiesa. 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 RequestHigh Court RulingThat the Joint Venture Agreement for the Feni and Chattak fields be declared null and illegal.The Joint Venture Agreement for Feni and Chattak fields is valid.That the government realize from the Company compensation for the natural gas lost as a result of the uncontrolled flow problems as well as for damage to the surrounding area.The compensation claims should be decided by the lawsuit described in note (b) below or by mutual agreement.That Petrobangla withhold future payments to the Company relating to production from the Feni field ($27.9 million as at June 30, 2012).Petrobangla to withhold future payments to the Company related to production from the Feni field until the lawsuit described in note (b) below is resolved or both parties agree to a settlement.That all bank accounts of the Company maintained in Bangladesh be frozen.The ruling did not address this issue, therefore the previous ruling stands. Funds in the Company's bank accounts maintained in Bangladesh cannot be repatriated pending resolution of 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 422,026,000 ($5.3 million) for 3 Bcf of free natural gas delivered from the Feni field as compensation for the burnt natural gas;(ii)taka 828,579,000 ($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 ($10.5 million) for environmental damages, an amount subject to be increased upon further assessment;(iv)taka 6,330,398,000 ($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 14(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's partner has served a notice of arbitration as the Company is unable to supply gas from the D6 block to the partner and the arbitration process has commenced. The Company estimates the cash amount to settle the contingency at US$11.6 million. The Company believes that the agreement with its partner is not effective as the Government of India's gas utilization policy prevents the Company from supplying the gas to the partner. The Company believes that the outcome is not determinable.The Company may not be able to supply gas to a customer in Hazira whose contract runs until mid-2016. The Company had previously planned to supply gas from the D6 Block to the customer. Due to a change in the gas allocation policy by the Government of India, the Company may not be able to fulfill the contract with gas supply from the D6 Block. The Company has notified the customer that the underperformance of reservoir is a force majeure event. The customer does not agree with this position and has served a notice of arbitration on the Company. The matter is subjudice in a court of law. 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 Production Sharing Contract. 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 and a third party ("the Parties") have a contract with a service provider under which the Parties are jointly and severally liable for all work performed by the service provider and any early termination fee, if applicable. If the contract were terminated as at June 30, the Company would be liable to pay the service provider for the third party's share of the early termination fee, currently estimated at approximately $9 million. The Company has a separate agreement with the third party entitling it to recover the above amount. Any termination fee is reduced as the contract is fulfilled.f. 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 2008. The assessments contend that the Company is not eligible for the requested tax holiday because: a) the holiday only applies to "mineral oil" which excludes natural gas; and/or b) the Company has inappropriately defined undertakings.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. For the 2006, 2007 and 2008 taxation years, the Company has appealed to CITA, however, CITA has agreed to wait for the High Court ruling on previous years prior to their ruling. The taxation years 2009 and later have not yet been assessed by the tax authorities.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 years ended March 31, 2009 through March 31, 2011, 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 2009 and 2010 tax returns, 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 have to accordingly change its tax position and record a tax expense of approximately $53 million (comprised of additional taxes of $32 million and write off of approximately $21 million of the net income tax receivable). In addition, the Company could be obligated to pay interest on taxes for the past periods.g. The Cauvery and D4 Blocks in India are under relinquishment. The Company believes it has fulfilled all commitments for the Cauvery block while the Government of India contends that the Company has unfulfilled commitments of up to approximately $2 million. The Company believes the outcome is currently not determinable. The Company did not drill the three wells required under the minimum work commitment for the D4 block and has paid $4.5 million related to these commitments.h. Various lawsuits have been filed against the Company for incidents arising in the ordinary course of business. In the opinion of management, the outcome of the lawsuits, now pending, is not determinable or not material to the Company's operations. Should any loss result from the resolution of these claims, such loss will be charged to operations in the year of resolution.FOR FURTHER INFORMATION PLEASE CONTACT: Edward S. SampsonNiko Resources Ltd.Chairman of the Board, President & CEO(403) 262-1020ORMurray HesjeNiko Resources Ltd.VP Finance & CFO(403) 262-1020www.nikoresources.com