Niko Reports Results for the Year Ended March 31, 2012

CALGARY, ALBERTA--(Marketwire - June 27, 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 year ended March 31, 2012. The operating results are effective June 27, 2012. All amounts are in U.S. dollars unless otherwise indicated and all amounts are reported using International Financial Reporting Standards unless otherwise indicated.

PRESIDENT'S MESSAGE TO THE SHAREHOLDERS

Production targets and operating cash flow were very close or slightly higher than last year's forecast guidance. However, reservoir performance at our two producing gas fields in the D6 Block has given the Company a significant write down and this is reflected in our financial statements. On the positive side, at D6 alone, reserves are expected to more than double later this year when development plans are approved for existing discoveries.

Company-wide, reserve additions from 19 discovered fields where development plans have already been, or are about to be, submitted, are expected to increase reserves by approximately 260%.

Niko's business plan has continued to focus on Indonesia and Trinidad where massive land positions have been accumulated and major seismic programs completed. To date, Niko has invested approximately $750 million in these two countries. High quality impact prospects have been identified and drilling has commenced. World-wide, Niko has now accumulated 45 million gross acres of exploration holdings and ranks as one of the largest landholders when compared to other Canadian companies. The Company has contracted an ultra-deep water rig that will begin a four year continuous deep water exploration program, with a 5^th year option, commencing in September. This will be the largest deep water drilling campaign ever undertaken in Indonesia.

Niko has now farmed out and will be largely carried on a total of 11 deep water wells. The Company will continue with its business plan to accumulate and farm out additional acreage during the year. The current carried prospects will keep our rig drilling for close to two years.

In addition, during the current fiscal year the Company expects to fund its $210 million capital program using opening unrestricted cash of $64 million plus projected funds from operations of $150 million. Approval of increased gas prices in India would allow for incremental cash flow to these numbers.

I want to take this opportunity to congratulate our Indian staff for achieving the high water mark of crossing the 8 million man hours without a single lost time accident in Hazira and Surat. This is truly an amazing event for India operations.

Although with a current disappointing share price, I believe this will be the most exciting year in corporate history.

REVIEW OF OPERATIONS AND GUIDANCE

Sales Volumes and Operating Cashflow

The primary reason for the decline in production during fiscal 2012 was reduced production from the D6 block. Actual production in fiscal 2012 was approximately 3.6 percent lower than the guidance provided a year ago while actual operating cashflow of $283 million was slightly higher than guidance. Guidance for the fiscal 2013 is 175,000 Mcfe/d and is lower than last year due largely to D6 where production is expected to decline in fiscal 2013 and is expected continue to decline thereafter unless volumes are added from the development of contingent resources.

Funds from Operations

As with sales volumes, the primary reason for the variances relates to production from the D6 block.

Capital additions and expensed exploration

Costs in India in the year included drilling two wells and other field and plant related costs.

Spending in Indonesia included $13 million related to preparing for the upcoming deep-water drilling campaign and approximately $53 million was spent on geological and geophysical activity, multi-beam and new venture activity. The Company accumulated an additional 1.1 million acres of 3D seismic during the year and has now accumulated 3D seismic on over 4.2 million acres.

Kurdistan spending related to a well in the Company's Qara Dagh block. Spending on this well had commenced in the previous year.

In Trinidad the company spent approximately $96 million for signature bonuses on acquired blocks and the acquisition of the Block 5c. Approximately $78 million was spent on geological and geophysical costs and approximately $10 million related to annual payments specified in the Company's blocks. The company accumulated 3D seismic over 1.0 million acres during the year and now has 3D seismic over 1.1 million acres.

Guidance on F2013 Spending

The Company expects to spend approximately $160 million on exploration and approximately $50 million on development. The development spending relates to the D6 block in India where $16 million is planned for two recompletions at MA. A further $12 million is projected to tie-in an additional well at MA. The remaining development capital relates to water handling and compression.

Unlike last year when exploration spending focused on land acquisitions (including the Block 5c that held contingent resources at acquisition) and geological and geophysical spending the current year will focus on exploration drilling.

In Trinidad the Rowan Gorilla III rig has drilled the Stalin-1 prospect and is currently drilling at the offshore Shadow 1 prospect in Block 2AB and will drill a third well later in 2012. The well is currently drilling at a vertical depth of 1,275 metres. The current drilling plans are to set 13 3/8 inch casing at 1,480 metres. The planned total depth for the well is 2,893 metres. The primary targets are Oligocene age Angostura sands and Eocene as well as Cretaceous sands. During the current fiscal year a land rig will commence drilling at the Guayaguayayare Area.

In Indonesia, the Hercules 208 jack-up rig has drilled the Candralila well and is currently drilling the Ratnadewi-1 prospect at Lhokseumawe. The well is currently at 801 metres and 13 3/8 inch casing is being set. The total planned depth of the well is 1,800 metres and the primary target is in the 850 to 1,200 metre range. In August, the Discover Seven Seas rig is expected to begin drilling the Lebah #1 prospect in North Ganal and will potentially drill a second well. In September the Ocean Monarch ultra-deepwater rig will commence operations under a four year (option for a 5th year) contract. The wells planned to be drilled by the Ocean Monarch in the current fiscal year include Jayarani-1 at Lhokseumawe; Ajek-1 at Kofiau; and Cikal-1 at West Papua IV. In summary, seven to eight wells are expected to be drilled in Indonesia during the current fiscal year.

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis (MD&A) of the financial condition, results of operations and cash flows of Niko Resources Ltd. ("Niko" or the "Company") for the year ended March 31, 2012 should be read in conjunction with the audited consolidated financial statements for the year ended March 31, 2012. This MD&A is effective June 27, 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 January 1, 2012 through March 31, 2012. The term "prior year's quarter" is used throughout the MD&A for comparative purposes and refers to the period from January 1, 2011 through March 31, 2011.

The fiscal year for the Company is the 12-month period ended March 31. The terms "Fiscal 2011" and "prior year" is used throughout this MD&A and in all cases refers to the period from April 1, 2010 through March 31, 2011. The terms "Fiscal 2012", "current year" and "the year" are used throughout the MD&A and in all cases refer to the period from April 1, 2011 through March 31, 2012.

Mcfe (thousand cubic feet equivalent) is a measure used throughout the MD&A. Mcfe is derived by converting oil and condensate to natural gas in the ratio of 1 bbl:6 Mcf. Mcfe may be misleading, particularly if used in isolation. An Mcfe conversion ratio of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. MMBtu (million British thermal units) is a measure used in the MD&A. It refers to the energy content of natural gas (as well as other fuels) and is used for pricing purposes. One MMBtu is equivalent to 1 Mcfe plus or minus up to 20 percent, depending on the composition and heating value of the natural gas in question.

Less than 2 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 Assumptions

This MD&A contains forward-looking information including forward-looking information about Niko's operations, reserve estimates, production and capital spending. Forward-looking information is generally signified by words such as "forecast", "projected", "expect", "anticipate", believe", "will", "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 Measures

The 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 cash flows from operating activities prior to the change in operating non-cash working capital, the change in long-term accounts receivable and exploration and evaluation costs expensed to the statement of comprehensive income.

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 PERFORMANCE

International Financial Reporting Standards

For fiscal periods beginning on or after January 1, 2011, all Canadian publicly accountable enterprises are required to prepare their financial statements using International Financial Reporting Standards (IFRS). Accordingly, the Company has prepared its audited consolidated financial statements for the year ended March 31, 2012, under IFRS and has presented its audited consolidated financial statements for the comparative periods, the year ended March 31, 2011 to comply with IFRS. The financial information presented in this MD&A is derived directly from the Company's financial statements and as such certain comparative information may differ from what was originally prepared by the Company using previous Canadian generally accepted accounting principles. For further information on the Company's transition to IFRS and a reconciliation of the affected financial information for the year ended March 31, 2011, please refer to the Company's audited consolidated financial statements for the years ended March 31, 2012 and 2011 filed on SEDAR at www.sedar.com and available on the Company's website at www.nikoresources.com.

Funds from Operations

(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 in the year, primarily as a result of a decrease in gas production at the D6 Block. Declines are expected to continue unless volumes are added from new fields.

The Company farms-out a portion of its interest in various properties in Indonesia. Other income in the current year includes the proceeds from the farm-outs in excess of the recorded asset.

Production and operating expenses for the year increased primarily as a result of the write-down of inventory at the Company's Hazira and Surat blocks.

General and administrative expense decreased primarily due to overhead recoveries from the branch offices as a result of increased exploration activity in the branches.

Net finance expense for the year decreased as higher finance income and the absence of interest on long-term debt more than offset debt set-up costs associated with the Company's credit facility.

Other expense in the prior year is a fine related to the Company's guilty plea under the Corruption of Foreign Public Officials Act. Refer to the "Corporate" section in this MD&A for full details.

There were realized foreign exchange losses in the year as a result of the weakening of the Indian-Rupee against the U.S. dollar.

The current income tax expense is for Hazira increased as a result of adjustments related to prior year tax provisions.

The Company currently pays minimum alternate tax based on Indian-GAAP accounting profits for the D6 block. In the year, accounting income decreased due to decreased revenues and an increase in the depletion charge as a result of the change in the estimate of reserves in the fourth quarter. Minimum alternate tax expense decreased accordingly in the year.

Net Income (Loss)

The decrease in funds from operations is described above. Other items affecting the net income (loss) are described below.

Production and operating expenses: The non-cash portion of production and operating expense and other expense included above are for share-based compensation (refer to the corporate section of this MD&A for further details).

Depletion expense: Although production volumes are lower in the current year, depletion expense increased as a result of the revision to the reserve volumes included in the March 31, 2012 reserve report.

Exploration and evaluation expense: The Company expenses geological and geophysical costs, unsuccessful exploration costs and the costs of operating branch offices to exploration and evaluation expense. The expense in the year consists of $115 million related to: seismic programs in Indonesia on the Sunda Strait I, South Matindok and Obi blocks; seismic programs in Trinidad on the Guayaguayare area, both NCMA blocks and Block 2ab. Exploration and evaluation expense also includes $67 million related to unsuccessful wells in Kurdistan, Trinidad and India. The remainder of the costs in the year are comprised of branch office costs for all exploration properties, $11 million for annual payments that are specified in the various PSCs and a $4.5 million provision for exiting the D4 block in India. The prior year cost includes seismic in Indonesia, Madagascar and Trinidad as well as branch operating costs and annual payments that are specified in the various PSCs.

Loss on short-term investments: The mark-to-market loss on short-term investments also contributed to year-over-year variances.

Share-based compensation expense: Other expenses consist primarily of stock based compensation expense. Stock options were cancelled during the year and accounting rules require immediate expense recognition as if the cancelled options had vested immediately resulting in a $14 million charge to other expenses in the period.

Asset Impairment: As a result of reduced reserves volumes assigned to the D6 Block, the Company recognized a $133 million impairment related to the Company's producing assets in the D6 Block in India for the year ended March 31, 2012. The producing assets were written down to management's estimate of value in use and determined using proved reserves and forecast cash flows using escalated prices and estimates of future production, capital and operating expenses, discounted at 10 percent, obtained from the independent reserve report. The prices used are those forecast by management and included in the reserve report as described in note 4 to the consolidated financial statements. Due to the unique nature of the asset, lack of comparable fair value transactions, as well as the recent uncertainty surrounding the reserves for the D6 Block, the Company used its estimate of value in use to assess the recoverable amount, resulting in an impairment of $133 million.

Impairment of long-term receivable: The Company impaired a long-term gas revenue receivable (refer to Segment profit - Bangladesh of this MD&A for further details).

Finance expense: The non-cash portion of finance expense included above is for the accretion of the decommissioning obligations and accretion of the convertible debentures (refer to the finance expense section in this MD&A for further details).

Unrealized foreign exchange (loss) / gain: The Indian Rupee weakened against the U.S. dollar during the year. As a result, there was an unrealized foreign exchange loss in the year on revaluing the Indian-rupee based income tax receivable and site restoration deposit to U.S. dollars.

Deferred income tax reduction: A deferred tax asset or liability is calculated as the difference between the carrying amount and the remaining tax value of an item multiplied by the effective tax rate expected to be in effect when the differences between the carrying amount and the remaining tax value (temporary difference) reverse. For the Company, the effective tax rates used in the calculations vary by country and with the amount of temporary differences reversing during the tax holiday period in India as described below.

The Company does not make payments to the Government of Bangladesh for Block 9 or Government of the region of Kurdistan for Qara Dagh with respect to income tax.

In Madagascar and Pakistan, the tax values exceed the carrying amounts. The properties are unproved and there is no assurance of realizing the resulting deferred tax asset so the Company does not recognize the asset.

For both Indonesia and Trinidad, a deferred tax liability was recorded coincident with the Company's acquisition of certain entities. Because a deferred tax liability was recognized for these entities, expenditures for these unproven properties result in a deferred tax recovery. In the year, the Company recognized a deferred tax recovery of $9.3 million for Indonesia and $22.9 million for Trinidad assets. Expenditures related to unproved properties held in entities that were not purchased do not result in a deferred tax recovery because there is no assurance of realizing the deferred tax asset.

Two significant factors affecting the deferred taxes for the D6 Block in India are: minimum alternate tax paid is eligible for offset against future income tax payable resulting in a deferred tax recovery; and the effective tax rate fluctuates based on the amount of temporary differences reversing during the tax holiday period. The Company has four years remaining in the tax holiday period. The amount of temporary differences reversing during the tax holiday period changes depending on capital spending and the accounting depletion rate. Temporary differences reverse at a tax rate of nil during the tax holiday period rather than the 42% statutory rate. In the prior year, the Company recognized the full amount of the deferred tax asset for minimum alternate tax credits available for offset against future income taxes payable. The fourth quarter reduction in the estimate of proved reserves resulted in a significant increase in depletion rates, which significantly increases the portion of the temporary differences that reverse during the tax holiday period at an effective tax rate of nil. Primarily as a result of these two factors, the Company recognized a deferred tax recovery of $59 million.

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. Although the Company does not expect a change of this magnitude to occur in the future, there may be future changes in this estimate as the circumstances and facts surrounding this estimate change.

BACKGROUND ON PROPERTIES

Niko Resources Ltd. is engaged in the exploration for and, where successful, the development and production of natural gas and oil in India, Bangladesh, 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.

India

D6 - The Company has a 10 percent working interest in the 7,645-square-kilometre D6 Block. The D6 Block comprised 78 percent of the Company's oil and gas revenue during the year. 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 March 31, 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 4 percent of the Company's oil and gas revenues in the year.

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 year. 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.

D4 - The Company has a 15 percent interest in the D4 Block, located in the Mahanadi Basin offshore from the east coast of India. The Company has performed the seismic work and has a remaining commitment to drill three wells under the first exploration phase. As a result of the most current geological assessment related to the size and risk of the trapping mechanism and the current commercial environment in India, the Company intends to relinquish the block. Subsequent to March 31, 2012, the Company has paid the estimated exit costs of $4.5 million.

Cauvery - The Company has a 100 percent working interest and operates the block, which covers 957 square kilometres. The Company has performed the seismic work and drilled four of the five wells required under the first exploration phase. The estimated cost of the remaining work commitment is up to $2 million. Wells drilled to date have been unsuccessful. The Company intends to relinquish the block.

Bangladesh

Block 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 16 percent of the Company's oil and gas revenues for the year. 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 March 31, 2012, the profit share was 61 percent.

Indonesia

The Company holds interests in PSCs for 21 offshore exploration blocks covering 108,876 square kilometres. The chart below indicates the location, award date, the Company's working interest and the size of the block.

(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 to 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 has acquired a total of 29,570 kilometres of 2D seismic and 17,081 square kilometres of 3D seismic fulfilling the seismic work commitments on the blocks. Eleven of the blocks have a single well commitment. The Company has contracted a rig and the drilling program for the Company's operated blocks is expected to commence in 2012. The Company's share of the remaining minimum work commitments as specified in the PSCs for the exploration period is $92 million to be spent at various dates up to December 2014. 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.

Kurdistan

The 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.

Trinidad

The 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.

(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. The Stalin-1 well drilled on Block 2AB and the Cribho-1 and Mapepire 1 wells on the Central Range block were unsuccessful and have been abandoned. The Company's share of the remaining minimum work commitments as specified in the PSCs for the exploration period is $182 million to be spent by various dates up to April 2016.

The Company closed the acquisition of a 25 percent interest in Block 5(c) in June 2011 for a purchase price of $78.1 million. Block 5(c) is located 94 kilometres off the east coast of Trinidad and the development plan is awaiting government approval. The transfer of the Block MG license was also part of an agreement signed by the Company in December 2010.

Madagascar

The 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.

Pakistan

The 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 income

(1) Share-based compensation and other non-cash items are excluded. Includes additions in the year that were subsequently written off.

India: Spending in India related primarily to capital at the D6 gas plant.

Indonesia: Expenditures include $13 million related to preparing for the future deep-water drilling campaign and approximately $3 million related to signature bonuses for new blocks. In addition, approximately $53 million was spent on geological and geophysical activity at the Sunda Strait I, South Matindok and Obi blocks, operating the branch, multi-beam and new venture activity.

Kurdistan: Spending related primarily to completing the drilling of the Company's first well on the Qara Dagh block. Drilling of this well commenced in the prior year. The Company's share of total well costs was approximately $37 million including amounts spent in the prior year.

Trinidad: Expenditures include: signing bonuses of $18 million for the signing of production sharing contracts for three additional blocks; the purchase of Block 5(c) in June 2011 for $78 million; and $24 million for exploration wells on Block 2AB and the Central Range Area. In addition, approximately $74 million was spent on geological and geophysical activity for the Guayaguayare, 2AB and NCMA blocks, $10 million for annual payments that are specified in the various PSCs and $4 million for general office expenses.

SEGMENT PROFIT

INDIA

(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 Royalties

The Company's gas production for the year was 149 MMcf/d compared to 198 MMcf/d in the prior year's period. Declines are expected to continue unless production volumes are added from new fields in the D6 Block.

Oil and condensate sales decreased in the current year compared to the prior year. Oil production from the D6 Block decreased as five wells were producing in the periods compared to six wells for the majority of the prior year's periods and a decrease in production from the remaining wells. The decrease as a result of volumes was partially offset by an increase in realized oil price to $109/bbl in the year compared to $84/bbl in the prior year.

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 Petroleum

Pursuant to the terms of the PSCs the Government of India is entitled to a sliding scale share in the profits once the Company has recovered its investment. Profits are defined as revenue less royalties, operating expenses and capital expenditures. The decrease in profit petroleum is a result of the decreased revenues described above.

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.

Operating Expenses

Operating expenses increased for the year compared to the prior year primarily as a result of the write-down of inventory at the Company's Hazira and Surat blocks. Operating costs per Mcfe have increased as a result of decreased production with no corresponding decrease in operating costs as the majority of the operating costs are fixed.

Depletion, Depreciation and Accretion

The 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.

Asset Impairment

As a result of reduced reserves volumes assigned to the D6 Block, the Company recognized a $133 million impairment related to the Company's producing assets in the D6 Block in India for the year ended March 31, 2012. The producing assets were written down to management's estimate of value in use and determined using proved reserves and forecast cash flows using escalated prices and estimates of future production, capital and operating expenses, discounted at 10 percent, obtained from the independent reserve report. The prices used are those forecast by management and included in the reserve report as described in note 4 to the consolidated financial statements. Due to the unique nature of the asset, lack of comparable fair value transactions, as well as the recent uncertainty surrounding the reserves for the D6 Block, the Company used its estimate of value in use to assess the recoverable amount, resulting in an impairment of $133 million.

Income Taxes

Current income tax expense relates to the Hazira and Surat blocks. Current income tax expense has increased as a result of recognizing adjustments related to prior year tax provisions.

The Company pays minimum alternate tax (MAT) at a rate of 19 percent of accounting profits from the D6 block, calculated in accordance with Indian generally accepted accounting principles, and records this as MAT expense. MAT has decreased from the prior year as a result of decreased revenues and the change in estimate of reserves that resulted in increased depletion expense and therefore decreased accounting profits.

A deferred tax asset or liability is calculated as the difference between the carrying amount and the remaining tax value of an item multiplied by the effective tax rate expected to be in effect when the differences between the carrying amount and the remaining tax value (temporary difference) reverse. The effective tax rate used in the calculation for the D6 Block varies with the amount of temporary differences reversing during the tax holiday period as described below.

Two significant factors affecting the deferred taxes for the D6 Block in India are: minimum alternate tax paid is eligible for offset against future income tax payable resulting in a deferred tax recovery; and the effective tax rate fluctuates based on the amount of temporary differences reversing during the tax holiday period. The Company has four years remaining in the tax holiday period. The amount of temporary differences reversing during the tax holiday period changes depending on capital spending and the accounting depletion rate. Temporary differences reverse at a tax rate of nil during the tax holiday period rather than the 42% statutory rate. In the prior year, the Company recognized the full amount of the deferred tax asset for minimum alternate tax credits available for offset against future income taxes payable. The fourth quarter reduction in the estimate of proved reserves resulted in a significant increase in depletion rates, which significantly increases the portion of the temporary differences that reverse during the tax holiday period at an effective tax rate of nil. Primarily as a result of these two factors, the Company recognized a deferred tax recovery of $59 million.

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. Although the Company does not expect a change of this magnitude to occur in the future, there may be future changes in this estimate as the circumstances and facts surrounding this estimate change.

Contingencies

The Company has contingencies related to gas sales contracts, the profit petroleum calculation and ownership of the 36" pipeline for Hazira and related to income taxes for Hazira and Surat as at March 31, 2012. Refer to the consolidated financial statements and notes for the year ended March 31, 2012 for a complete discussion of the contingencies.

BANGLADESH

(1) Segment profit is a non-IFRS measure as calculated above. Segment profit includes the results from Block 9 and Feni in Bangladesh. Production from Feni ceased in April 2010.

Revenue, Profit Petroleum, Depletion and Operating Expenses

The Bangora-1 well is producing at a consistent level, which is lower than the prior year due to a mechanical problem that cannot be remedied in a cost-effective manner. Production from this well is expected to continue at no higher than current levels. Production from the remaining wells is consistent with the prior year. The decrease in production is the cause of the revenue decline as the gas price was consistent during the years at $2.32/Mcf.

Condensate production decreased as a result of the decrease in production from the Bangora-1 well. The effect of the decreased production on revenue was more than offset by increased price to $117.05/bbl in the year from $89.00/bbl in the prior year.

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 decreased due to decreased 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.

Impairment of long-term receivable and Contingencies

The Company has a gas revenue receivable of $27.9 million for the natural gas sales to Bangladesh Oil, Gas and Mineral Corporation (Petrobangla) for production from the Feni field in Bangladesh. The Company produced natural gas from the Feni field from November 2004 to April 2010 and delivered the natural gas to Petrobangla for the duration.

Although the Company expects to collect the full amount of the receivable, the timing of collection is uncertain as the Company will not collect the receivable until resolution of the various claims raised against the Company. Although the Company has a valid claim to receive payment for the gas delivered to Petrobangla and the Company will continue to pursue collection of the receivable, due to the continued uncertainty with respect to timing of resolution of the various claims raised against the Company, a provision has been recorded against the full amount of the receivable as at March 31, 2012 and recorded the previously discounted value of $23 million as an impairment. The various claims raised against the Company are described in notes 31(a) and (b) to the Company's consolidated financial statements.

INDONESIA, KURDISTAN, MADAGASCAR, PAKISTAN, TRINIDAD

Indonesia

The Company farms-out a portion of its interest in various properties. Other income in Indonesia in the year includes the proceeds from the farm-outs in excess of the recorded asset.

During the year, the Company spend $23 million on seismic costs in South Matindok and Sunda Strait I, $16 million of other geological and geophysical activity including processing and seismic on other blocks, $9 million on new ventures and $6 million to operate the branch office. In addition, the Company expensed $4 million of previously capitalized acquisition costs and $4 million of share-based compensation expense. The prior year expense relates primarily to seismic programs.

A deferred tax liability was recorded coincident with the Company's acquisition of Black Gold entities. Because a deferred tax liability was recognized for these entities, expenditures for these unproven properties result in a deferred tax recovery. In the year, the Company recognized a deferred tax recovery of $9.3 million. Expenditures related to unproved properties held in entities that were not purchased do not result in a deferred tax recovery because there is no assurance of realizing the deferred tax asset.

Kurdistan

The exploration and evaluation expense for Kurdistan is the cost to operate the branch office and the write-off of the QD-1 well in the Qara Dagh block. While this well may be re-entered at a later date, the timing thereof is uncertain. The prior year expense is primarily the cost to operate the branch office.

Madagascar

The exploration and evaluation expense in the year for Madagascar is the cost to operate the branch office. The prior year cost includes the cost of the seismic program.

Pakistan

The exploration and evaluation expense for Pakistan includes seismic processing and the cost to operate the branch office.

Trinidad

Trinidad exploration and evaluation expense includes $74 million for seismic programs on the Guayaguayare Area, Block 2AB, NCMA2, NCMA3 and the MG Block and $24 million for the unsuccessful Stalin-1 well on Block 2AB and Cribo and Mapepire on the Central Range Area. The prior year cost includes seismic on Block 2AB. The annual payments required as per the signed PSCs increased in the current year as a result of NCMA2, NCMA3 and Block 4b, which were signed in April 2011. The costs to operate the branch office were incurred in both years.

A deferred tax liability was recorded coincident with the Company's acquisition of Voyager Energy Ltd. Because a deferred tax liability was recognized, expenditures for these unproven properties result in a deferred tax recovery. In the year, the Company recognized a deferred tax recovery of $22.9 million. Expenditures related to unproved properties held in entities that were not purchased do not result in a deferred tax recovery because there is no assurance of realizing the deferred tax asset.

CORPORATE

General and administrative

In the current year, the general and administrative costs have decreased primarily as a result of increased overhead recoveries from the branch offices. The effect was partially offset by increased use of outside legal services.

Share-based compensation - impact of option cancellation

Stock options were cancelled during the year and accounting rules require immediate expense recognition as if the cancelled options had vested immediately resulting in a $14 million charge to other expense in the period.

Other Expense

In January 2009, the Company received confirmation from Canadian authorities that they were engaged in a formal investigation into allegations of improper payments in Bangladesh by either the Company or its subsidiary in Bangladesh. The Company cooperated in the investigation, which was concluded on June 24, 2011, and the Company pleaded guilty to one count of bribery under the Corruption of Foreign Public Officials Act. The charge refers to two specific incidents that occurred in 2005: the provision of a vehicle for the personal use of the then-Bangladeshi Energy minister, valued at Cdn$190,984; and the provision of travel costs to the same Minister to attend an Energy Expo in Calgary and a subsequent personal trip to New York, valued at Cdn$5,000. The sentence includes a find of Cdn$8,260,000 and an additional 15% Victim Fine Surcharge for a total amount of Cdn$9,499,000. Additionally, the sentence includes a probation order, which puts the Company under the Court's supervision for the next three years to ensure audits are done to ensure the Company's compliance with the Act. The costs of compliance with the Probation Order will be borne by the Company.

Finance expense

Interest expense decreased as a result of the repayment of the long-term debt in October 2010.

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. Other expense includes the costs of arranging financing.

Foreign Exchange

The 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 Investments

The loss on short-term investments for the year was a result of marking the short-term investments to market value. The Company sold investments during the year resulting in realized losses of $12 million. The majority of the losses had been included in income in prior periods as the investments have been marked to market since the time of purchase.

NETBACKS

The following tables outline the Company's operating, funds from operations and earnings netbacks (all of which are non-IFRS measures):

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 RESOURCES

At March 31, 2012, the Company had total restricted and unrestricted cash of $83 million (March 31, 2011 - $126 million). The Company's unrestricted cash position decreased by $44 million during the year. This decrease occurred primarily because capital spending and directly expensed exploration and evaluation costs of $343 million exceeded funds from operations of $234 million. This $109 million reduction in cash was partially offset by $40 million related to reduced non-cash working capital and realization of a long-term receivable and a $25 million draw on the Company's credit facility.

The Company had a working capital deficit of $270 million at March 31, 2012 ($119 million surplus - March 31, 2011), calculated as current assets less current liabilities. The Company collected $30 million during the period that had been advanced for a new venture with conditions precedent. The conditions were not met and the advance was returned to the Company during the year, reducing the account receivable balance. The accounts payable balance increased as a result of increased drilling and seismic activity in Trinidad during the period. The primary reason for the change from a surplus to a deficit is the inclusion of the convertible debentures (see next paragraph for a more detailed description) of $306 million in current liabilities as they are due within one year. While the Company has the right to settle the debentures with equity, the Company intends to pursue other options.

On December 30, 2009, the Company entered into a Cdn$310 million convertible debenture credit facility (the "Debentures"). The Debentures bear a coupon rate of 5 percent and mature on December 30, 2012. The interest is paid semi-annually in arrears on January 1st and July 1st of each year. Debentures are convertible at the option of the holder into common shares of the Company at a conversion price of Cdn$110.50 per common share until 60 days prior to the maturity date. In May 2011, the terms of the debentures were altered such that the Company now may elect 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.

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 $25 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's planned capital program for Fiscal 2013 is $210 million, which is comprised of $160 million for exploration and $50 million for development.

The Company expects that it will use its unrestricted cash on hand of $64 million as at March 31, 2012, funds from operations that are currently projected at approximately $150 million to fund its planned capital program for Fiscal 2013. 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 contractual obligations of the Company are as follows:

(1) Details of the work commitments by property are included in "Background on Properties" in this MD&A. The work commitments included in the above chart are based on the minimum costs specified in the PSC or in the Company's bid for the PSC. The commitments are included in the above chart based on the deadline for spending and are calculated based on the Company's working interest and are therefore prior to any promotes related to farm-ins or farm-outs. The Company may apply for extensions to exploration periods as required to complete the work commitment.

(2) Decommissioning obligations are based on the undiscounted estimated future liability of the Company as disclosed in the notes to the consolidated financial statements for the year ended March 31, 2012. They do not include wells or facilities that were not complete as at March 31, 2012.

(3) Finance lease obligation includes both the current and long-term portions.

(4) The contract commencement date for the lease of an operating rig is not fixed and the above table includes commitments based on estimated commencement date. The lease obligations included above are before reimbursement from partners and the Company expects a significant portion of this commitment to be funded by joint venture partners.

(5) The convertible debentures are recorded in the consolidated financial statements at a value of $306 million, which is a discounted value to reflect the fact that the interest rate is lower than the market interest rate on similar debentures without a conversion feature. The convertible debentures are included in the table based on the amount that would be required to repay the Cdn$310 million debentures converted at the year-end exchange rate.

SUMMARY OF QUARTERLY RESULTS

The 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 March 31, 2012:

(1) Oil and natural gas revenue is oil and natural gas sales less royalties and profit petroleum expense.

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.
• 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.

FOURTH QUARTER

Funds from Operations

(1) Funds from operations is a non-IFRS measure as defined under "Non-IFRS measures" in this MD&A.

The explanations provided in "Overall Performance" apply to the changes in the quarter ended March 31, 2012 compared to the quarter ended March 31, 2011 except as follows:

There was minimum alternate tax (MAT) expense in the prior year's quarter on Indian GAAP accounting profits from the D6 block. There was an adjustment to MAT expense in the current year's quarter as a result of the change in Indian GAAP accounting profits as due to the change in estimate of reserves and its effect on depletion expense.

Net Income (Loss)

The explanations provided in "Overall Performance" apply to the changes in the quarter ended March 31, 2012 compared to the quarter ended March 31, 2011 except as follows:

Exploration expense in the quarter is comprised of the unsuccessful exploration wells in Hazira, the costs to exit the D4 block, seismic for Guayaguayare and NCMA3 in Trinidad, the unsuccessful exploration wells in Block 2AB and the Central Range in Trinidad, branch operating costs and annual payments specified in the various PSCs. In the prior year's quarter, the expense is for seismic in Indonesia, Trinidad and Madagascar as well as branch operating costs and annual payments specified in the various PSCs.

The mark-to-market loss on short-term investments also contributed to year-over-year variances.

The Indian Rupee strengthened against the U.S. dollar during the quarter. As a result, there was an unrealized foreign exchange gain on revaluing the Indian-rupee based income tax receivable and site restoration deposit to U.S. dollars.

Deferred income tax reduction: A deferred tax asset or liability is calculated as the difference between the carrying amount and the remaining tax value of an item multiplied by the effective tax rate expected to be in effect when the differences between the carrying amount and the remaining tax value (temporary difference) reverse. For the Company, the effective tax rates used in the calculations vary by country and with the amount of temporary differences reversing during the tax holiday period in India as described below.

For both Indonesia and Trinidad, a deferred tax liability was recorded coincident with the Company's acquisition of certain entities. Because a deferred tax liability was recognized for these entities, expenditures for these unproven properties result in a deferred tax recovery. In the year, the Company recognized a deferred tax recovery of $9.3 million for Indonesian and $22.9 million for Trinidadian assets. Expenditures related to unproved properties held in entities that were not purchased do not result in a deferred tax recovery because there is no assurance of realizing the deferred tax asset.

Two significant factors affecting the deferred taxes for the D6 Block in India are: minimum alternate tax paid is eligible for offset against future income tax payable resulting in a deferred tax recovery; and the effective tax rate fluctuates based on the amount of temporary differences reversing during the tax holiday period. The Company has four years remaining in the tax holiday period. The amount of temporary differences reversing during the tax holiday period changes depending on capital spending and the accounting depletion rate. Temporary differences reverse at a tax rate of nil during the tax holiday period rather than the 42% statutory rate. In the prior year, the Company recognized the full amount of the deferred tax asset for minimum alternate tax credits available for offset against future income taxes payable. The fourth quarter reduction in the estimate of proved reserves resulted in a significant increase in depletion rates, which significantly increases the portion of the temporary differences that reverse during the tax holiday period at an effective tax rate of nil. Primarily as a result of these two factors, the Company recognized a deferred tax recovery of $66 million.

SELECTED ANNUAL INFORMATION

(1) The Fiscal 2010 comparative numbers are non-adjusted Canadian GAAP amounts.

(2) Oil and natural gas revenue is oil and natural gas sales less royalties and profit petroleum expense.

Natural gas production form the D6 Block commenced in April 2009 and production volumes were increasing over fiscal 2010. With 16 to 17 wells producing for most of fiscal 2011, natural gas sales increased by $86 million. The increase in revenues from D6 was partially offset by natural declines in production from Hazira and Surat. Oil and natural gas revenue has decreased in fiscal 2012 compared to fiscal 2011, primarily as a result of a decrease in gas production at the D6 Block. Declines are expected to continue unless production volumes are added from new fields in the D6 Block.

In addition to the changes in oil and natural gas revenues, the following items contributed to the changes in net income over the years:

• Proceeds of farm-out transactions in excess of recorded book value resulted in an increase of $6 million to the fiscal 2012 income.
• Operating expense increased in fiscal 2011 as operations including maintenance programs were established.
• Depletion expense increased in fiscal 2011 as a result of a revision to reserve volumes and future costs and again in fiscal 2012 as a result of a revision to reserve volumes.
• In fiscal 2011 and fiscal 2012, $97 million and $233 million of exploration and evaluation costs were expensed, whereas costs of the same nature were capitalized under Canadian GAAP policies applied for fiscal 2010. Exploration and evaluation expense in fiscal 2011 were primarily for seismic in Indonesia, Madagascar and Trinidad. Exploration and evaluation expense in fiscal 2012 were incurred for seismic and unsuccessful drilling in Trinidad, unsuccessful drilling in Kurdistan and seismic in Indonesia. The expense in both fiscal 2011 and fiscal 2012 includes carrying costs of the blocks and annual payments specified in the PSCs.
• There was a mark-to-market gain of $15 million in fiscal 2010, a loss of $13 million in fiscal 2011 and a loss of $6 million in fiscal 2012 as a result of the change in market value of the short-term investments.
• Stock options were cancelled during the fiscal 2012 and accounting rules require immediate expense recognition as if the cancelled options had vested immediately resulting in a $14 million charge to other expense in the period.
• Other income of $9 million was recognized in fiscal 2010 as the result of the award of ownership of the 36-inch pipeline to incorporate the results of the pipeline operations.
• Interest expense increased in fiscal 2011 as a result of the convertible debentures issued in December of 2009.
• There were foreign exchange losses in fiscal 2010 and fiscal 2012 as a result of the weakening of the INR against the U.S. dollar.
• The Company recorded an impairment of $23 million in fiscal 2012 against the receivable from Petrobangla for gas sales. Please refer to "Segment Profit - Bangladesh" in this MD&A for further details.
• The Company recorded an impairment of $133 million in fiscal 2012 against the D6 producing property.
• Minimum alternate tax (MAT) expense with respect to the D6 Block increased by $15 million in fiscal 2011 as a result of the increased accounting income for the block. In fiscal 2012, the decreased accounting income as a result of the decreased revenues and increased depletion expense resulted in a $26 million decrease in MAT expense.
• The deferred income tax recovery in fiscal 2011 offset the increase in the MAT expense. In fiscal 2012, there was an increase in the deferred income tax recovery due to: the change in value of the tax holiday for the D6 block as a result of the change in estimated reserves; and 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.

Total assets decreased in fiscal 2011 as a result of the conversion to International Financial Reporting Standards (IFRS) from Canadian GAAP applied to the financial statements in fiscal 2010. Items that are capitalized as assets under Canadian GAAP do not qualify for capitalization according to the accounting policies adopted by the Company under IFRS and therefore, total assets decreased. In fiscal 2012, total asset decreased as a result of the impairments of the long-term gas revenue receivable and the D6 producing property, the use of cash in operations, the net change in property, plant and equipment primarily as a result of depletion, partially offset by the net addition of exploration and evaluation assets.

Total long-term financial liabilities decreased in fiscal 2012 primarily as a result of the reclassification of the convertible debentures to current as they became due in less than one year.

RELATED PARTIES

The Company has a 45 percent interest in a Canadian property that is operated by a related party, a Company owned by the President and CEO of Niko Resources Ltd. This joint interest originated as a result of the related party buying the interest of the third-party operator of the property in 2002. The transactions with the related party are not significant to the operations or the consolidated financial statements. The transactions with the related party are measured at the exchange amount, which is the amount agreed to between related parties.

FINANCIAL INSTRUMENTS

Financial 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 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 $6 million was recognized in income for the year.

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 $21 million in the year was recorded for interest expense and accretion of the discount on the convertible debentures.

CRITICAL ACCOUNTING ESTIMATES

The Company makes assumptions in applying certain critical accounting estimates that are uncertain at the time the accounting estimate is made and may have a significant effect on the consolidated financial statements of the Company.

Oil and Natural Gas Reserves

Reserves estimated can have a significant effect on net earnings as a result of their impact on the depletion rate, provisions for decommissioning obligations and asset impairments. Independent qualified engineers in conjunction with the Company's reserve engineer estimate the value of oil and natural gas reserves on an annual basis. The estimation of reserves is an inherently complex process requiring significant judgement. Estimates of economically recoverable oil and gas reserves and future cash flows from those reserves are based upon a number of variables and assumptions such as geological interpretation, commodity prices, operation and capital costs and production forecasts, all of which may vary considerable from actual results. These estimates are expected to revised upward or downward over time, as additional information such as reservoir performance becomes available, or as economic conditions change.

Depletion and Impairment of Producing Assets

The net carrying value of producing asset is depleted using the unit-of-production method by reference to the ratio of production in the year to the related total proved reserves of oil and natural gas, taking into account estimated future development costs necessary to bring those reserves into production. Revisions to reserve estimates and the associated future cashflows could significantly increase or decrease depletion expense charged to net income and could result in an impairment of property, plant and equipment charged as an expense to net income.

Impairment of Tangible and Intangible Assets

At the end of each reporting period, the Company assesses whether there is any indication that an asset may be impaired. If any such indication exists, the Company estimates the recoverable amount of the asset. Indications include: a significant decline in market value of the asset; significant changes have taken or will take place in the technological; market, economic or legal environment in which the Company operates or in the market to which an asset is dedicated; a significant increase in market interest rates that would affect the discount rate and value of the asset; and the carrying amount of the net assets of the entity is more than its market capitalization. Irrespective of whether there is any indication of impairment, the Company tests intangible assets with an indefinite useful life and intangible assets not yet available for use for impairment annually by comparing its carrying amount with its recoverable amount. The recoverable amount requires the use of assumptions and estimates including quantities of recoverable resources, estimated production quantities, future commodity prices and further exploration, development and production costs. Changes in any of these assumptions, could impact the estimated recoverable amount and result in an impairment of exploration and evaluation assets, development assets, capital work-in-progress and other property, plant and equipment.

Decommissioning Obligations

Production sharing contracts that the Company has entered into indicate an obligation for abandonment of wells and facilities including removal of all equipment and installations and site restoration, collectively termed decommissioning obligations. Provision is made for the estimated cost of decommissioning obligations for a well that has been drilled and for equipment or installations upon completion. The provision is capitalized in the relevant asset category and a corresponding liability is recognized.

The provision for decommissioning obligations is calculated as the present value of the expenditures expected to be required to settle the obligation in the future. The present value is based on the best estimate of future costs and the economic lives of the wells, facilities and pipelines. There is uncertainty regarding both the amount and timing of incurring these costs and a change in either could result in an adjustment to the relevant capital asset and the decommissioning obligation.

Income Taxes

The Company estimates current and future income taxes based on its interpretation of tax laws in the various jurisdictions in which it operates and pays income taxes. The Company recorded its income tax expense including provisions that provide for a tax holiday deduction for various undertakings related to the Hazira and Surat properties for the taxation years 1998 to 2008. Should the tax authorities determine that the tax holiday deduction does not apply to natural gas, the Company would pay additional cash taxes, write-off the net income tax receivable on the statement of financial position and recognize additional income tax expense as a charge to net income. This may also impact the oil and natural gas reserves and asset impairment related to these properties. See note 31 to the consolidated financial statements for further discussion.

Share-Based Compensation

Compensation expense associated with the Company's share-based compensation plan is calculated and, recognized in net income or capitalized, over the vesting period of the stock option with a corresponding increase in contributed surplus. A forfeiture rate used in the calculation of compensation expense is estimated on the grant date and is adjusted to reflect the actual number of options that vest.

INITIAL ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS)

In February 2008, the Accounting Standards Board confirmed that IFRS will be required for interim and annual reporting by publicly accountable enterprises effective for January 1, 2011 including 2010 comparative information. The consolidated financial statements for the year ended March 31, 2012 have been prepared in accordance with IFRS applicable to the preparation of interim financial statements including International Accounts Standard (IAS) 34, "Interim Financial Reporting" and IFRS 1 "First-time Adoption of International Financial Reporting Standards".

The accounting policies adopted by the Company under IFRS are set out in note 2 to the consolidated financial statements for the year ended March 31, 2012. Note 27 to the same consolidated financial statements discloses the impact of the transition to IFRS on the Company's reported financial position, earnings and cash flows, including the nature and effect of certain transition elections and significant changes in accounting policies from those used in the Company's Canadian IFRS consolidated financial statements for fiscal 2011.

ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED

The 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 PROCEDURES

The Company's Chief Executive Officer and Chief Financial Officer are responsible for designing disclosure controls and procedures or causing them to be designed under their supervision and evaluating the effectiveness of the Company's disclosure controls and procedures. The Company's Chief Executive Officer and Chief Financial Officer oversee the design and evaluation process and have concluded that the design and operation of these disclosure controls and procedures were effective in ensuring material information relating to the Company required to be disclosed by the Company in its annual filings or other reports filed or submitted under applicable Canadian securities laws is made known to management on a timely basis to allow decisions regarding required disclosure.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

The Chief Executive Officer and Chief Financial Officer of the Company are responsible for designing internal controls over financial reporting or causing them to be designed under their supervision and evaluating the effectiveness of the Company's internal controls over financial reporting. The Chief Executive Officer and Chief Financial Officer have overseen the design and evaluation of internal controls over financial reporting and have concluded that the design and operation of these internal controls over financial reporting were effective in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with 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 year ended March 31, 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 FACTORS

In the normal course of business the Company is exposed to a variety of actual and potential events, uncertainties, trends and risks. In addition to the risks associated with the use of assumptions in the critical accounting estimates, financial instruments, the Company's commitments and actual and expected operating events, all of which are discussed above, the Company has identified the following events, uncertainties, trends and risks that could have a material adverse impact on the Company:

• The Company may not be able to find reserves at a reasonable cost, develop reserves within required time-frames or at a reasonable cost, or sell these reserves for a reasonable profit;
• Reserves may be revised due to economic and technical factors;
• The Company may not be able to obtain approval, or obtain approval on a timely basis for exploration and development activities;
• Changing governmental policies, social instability and other political, economic or diplomatic developments in the countries in which the Company operates;
• Changing taxation policies, taxation laws and interpretations thereof;
• 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 March 31, 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 DATA

At June 27, 2012, the Company had the following outstanding shares:

(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 June 27, 2012 is $1,171,439,000.

MANAGEMENT'S REPORT

The accompanying consolidated financial statements and all other information contained elsewhere in this report is the responsibility of the management of Niko Resources Ltd. The consolidated financial statements necessarily include amounts that are based on estimates, which have been objectively developed by management using all relevant information. The financial information contained elsewhere in this report has been reviewed to ensure consistency with the consolidated financial statements.

Management maintains and evaluates the effectiveness of disclosure controls and procedures and internal control over financial reporting for Niko Resources Ltd. Disclosure controls and procedures are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with International Financial Reporting Standards. The Company evaluates the effectiveness of internal controls over financial reporting at the financial year end and discloses its conclusions about the effectiveness in the Company's annual Management's Discussion and Analysis.

The Audit Committee of the Board of Directors, comprised of non-management directors, has reviewed the consolidated financial statements with management and the auditors. The consolidated financial statements have been approved by the Board of Directors on recommendation of the Audit Committee.

The consolidated financial statements have been audited by KPMG LLP, the external auditors, in accordance with auditing standards generally accepted in Canada on behalf of the shareholders.

(signed) Edward S. Sampson, President and CEO

(signed) Murray Hesje, Vice President, Finance and CFO

June 27, 2012

INDEPENDENT AUDITORS' REPORT

To the Shareholders of Niko Resources Ltd.

We have audited the accompanying consolidated financial statements of Niko Resources Ltd., which comprise the consolidated statements of financial position as at March 31, 2012, March 31, 2011 and April 1, 2010, the consolidated statements of comprehensive income (loss), changes in shareholders' equity and cash flows for the years ended March 31, 2012 and 2011, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management's responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Niko Resources Ltd. as at March 31, 2012, March 31, 2011 and April 1, 2010, and its consolidated financial performance and its consolidated cash flows for the years ended March 31, 2012 and 2011 in accordance with International Financial Reporting Standards.

(signed) KPMG LLP, Chartered Accountants

Calgary, Canada

June 27, 2012