Niko Resources Ltd.
TSX : NKO

Niko Resources Ltd.

June 23, 2009 09:00 ET

Niko Reports Results for the Year Ended March 31, 2009

CALGARY, ALBERTA--(Marketwire - June 23, 2009) - Niko Resources Ltd. ("Niko" or "the Company") (TSX:NKO) 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 fiscal year ended March 31, 2009 ("fiscal 2009"). The operating results are effective June 22, 2009.

PRESIDENT'S REPORT TO THE SHAREHOLDERS

The start-up of the D6 oil and gas projects has fundamentally changed the Company. As a result, Niko expects fiscal 2010 sales volumes to average over 269 MMcfe/d, which is a 217 percent improvement over fiscal 2009. We are proud to have achieved this step-change while maintaining a strong balance sheet. In fact, at March 31, 2009 the Company's cash exceeded its debt.

In addition to development activity, Niko also made a significant change in the diversity and opportunity in our exploration portfolio. We entered the fiscal year with nine active exploration blocks in two countries and are now actively pursuing opportunities in our 19 exploration blocks in five countries.

OUTLOOK

In addition to the significant increase in forecasted sales volumes for fiscal 2010 compared to fiscal 2009, we expect to receive approval for the development of the D6 satellite fields and the NEC-25 discoveries.

We will also actively explore in the coming year. Seismic and drilling activity is planned in multiple blocks. It will be the largest program in the Company's history.

ACKNOWLEDGEMENTS

Once again, our successes in fiscal 2009 were owed to the hard work, the contributions made by Niko's people and the commitment of our valued shareholders. On behalf of the Board of Directors, I express our sincere gratitude to all those involved in Niko's accomplishments.

Edward S. Sampson, Chairman of the Board, President and Chief Executive Officer

June 22, 2009

OPERATIONAL HIGHLIGHTS

Development

- Production from the D6 gas field began subsequent to the end of the fiscal year, in April 2009, and current production is averaging in excess of 1,000 MMcf/d (100 MMcf/d working interest to Niko), which is over 35 percent of the 2,800 MMcf/d (280 MMcf/d working interest to Niko) target that is now expected before calendar year-end.

- D6 oil production commenced in September 2008 and expected peak liquids production is 40,000 bbls/d (4,000 bbls/d working interest to Niko).

- The development plan for the D6 satellite fields was submitted in July 2008.

- Facilities upgrades during fiscal 2009 at Block 9 have resulted in a 21 percent year-over-year increase in Niko's share of natural gas production, to 54 MMcf/d for the year.

Exploration

- At D6, the L1 well was the first significant discovery in the Pleistocene channel complex. Drilling of this well concluded in the second quarter of fiscal 2009. The AR2 gas discovery was drilled in April 2009, the AS1 well finished being drilled in May 2009 and the BA2 well is currently being drilled.

- At Cauvery, the Khoja-1 well is currently being drilled.

- At NEC-25, the NEC-AJ2 well is currently being drilled.

- 3D Seismic activity in:

-- Pakistan;

-- Kurdistan; and

-- Hazira.

New Ventures

- In Indonesia, Niko signed production sharing contracts (PSC) in November 2008 and May 2009 resulting in interests in 8 blocks and 40,000 square kilometres of gross acreage in Indonesia. Niko's working interests in these blocks range from 25 percent to 67 percent with an average of 37 percent.

- Niko farmed-in to a 16,845 square kilometre block in Madagascar in October 2008 whereby it will operate and earn a 65 percent participating interest.

- Niko signed a PSC in the Kurdistan Region of Iraq in May 2008 whereby it will operate and currently has a 36 percent participating interest in the 846 square kilometre Qara Dagh block.



Years ended March 31, 2009 2008
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Average daily sales volumes
Oil and condensate (bbls/d) 501 311
Natural gas (Mcf/d) 82,249 80,991
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Total combined (Mcfe/d) 85,257 82,854
Revenues, royalties and operating costs
(US$/Mcfe)
Oil and natural gas revenue 3.37 3.33
Pipeline revenue 0.01 0.02
Royalties (0.15) (0.17)
Profit petroleum (0.73) (0.81)
Operating costs (0.40) (0.34)
----------------------------------------------------------------------------
Operating netback (US$/Mcfe) 2.10 2.03
Drilling activity
Gross wells 6 23
Net wells 0.6 8.8
----------------------------------------------------------------------------


OPERATIONS REVIEW

PRODUCTION AND DEVELOPMENT

Reserves

From a reserve perspective, the highlight for the year was in moving undeveloped reserves to the developed reserves category, which enables a substantial ramp-up in production and operating cashflow for fiscal 2010 and beyond.

The following charts display the Company's total proved plus probable gross reserves effective March 31, 2009 as evaluated by Ryder Scott Company, segregated into developed and undeveloped reserves:

To view charts please click the following link: http://media3.marketwire.com/docs/623nko_chart1.pdf



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Total Proved Plus Probable Working Interest Reserves 2009 2008

----------------------------------------------------------------------------
Natural gas, Oil and
Developed reserves NGL(1) Bcfe 721 212
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Natural gas, Oil and
Undeveloped reserves NGL(1) Bcfe 957 1,524
----------------------------------------------------------------------------

(1) Bcfe is derived by converting oil and NGL to natural gas in the ratio
of 1 bbl:6 Mcf.


Overall, proved plus probable reserves were relatively flat year over year. For the potential development plans referred to below, the Company will add to its reserve base.

Development

The Company developed 37 percent of its total proved plus probable reserves during the year. The development was primarily in the D6 Blocks and also included the tie-in of an additional well in Block 9. Development costs of US$368 million were incurred during the year to develop reserves. The Company has forecast spending at US$236 million in fiscal 2010 to further develop reserves.

D6 Block - MA Oil Development: A portion of the reserves from the MA discovery was reclassified to developed with the commencement of oil production from the field in September 2008. The revised field development costs, excluding the capital cost of the FPSO as it is currently being leased, are budgeted at US$1.9 billion (US$194 million net to the Company) and the Company had spent US$119 million of this amount at March 31, 2009. The remainder of the budgeted costs will be spent to drill and tie-in three additional wells and, after a period of oil production, to convert some of the oil wells to gas producers and complete tie-ins to allow the gas produced to be delivered to the onshore gas processing plant and sold.

D6 Block - Dhirubhai 1 and 3 Gas Development: Commencement of production from the Dhirubhai 1 and 3 discoveries occurred in April 2009 and a significant portion of the reserves was reclassified to developed. The Phase I costs (costs to bring production to 2.8 Bcf/d, which is 280 MMcf/d working interest to the Company) are budgeted at US$6.3 billion (US$627 million net to the Company). The Company had spent US$479 million of this amount to March 31, 2009. Costs will be incurred after start-up to tie in the remaining wells. Additional reserves will move from undeveloped to developed upon completion of Phase I. The then remaining undeveloped reserves will move to developed reserves over the life of the field as additional wells are drilled and compression is added.

Potential Future Developments

A field development plan has been submitted to the Government of India for nine natural gas discoveries in the D6 Block in addition to the Dhirubhai 1 and 3 gas discoveries. The discoveries are adjacent to the Dhirubhai 1 and 3 gas fields that are currently producing. If the development plan is approved, it is intended that these satellite discoveries be tied back to the Dhirubhai 1 and 3 facilities.

For the NEC Block, a development plan has been submitted for the six natural gas discoveries that have been declared commercial by the Indian regulatory authorities.

Sales

The Company's actual production for the years ended March 31, 2008 and 2009 and the forecast production for the year ending March 31, 2010 are displayed below:

To view Sales and Forecast chart, please click following link: http://media3.marketwire.com/docs/623nko_chart2.pdf

Gas production from the Dhirubhai 1 and 3 gas fields commenced in April 2009 and is expected to increase average Company production for the year ending March 31, 2010 to 269 MMcfe/d, which is a 217 percent increase over fiscal 2009. Production from the Dhirubhai 1 and 3 gas fields is currently averaging in excess of 1,000 MMcf/d (100 MMcf/d working interest to the Company) and is targeted to reach 2,800 MMcf/d (280 MMcf/d working interest to the Company) before calendar year-end. Average oil production from the MA field for fiscal 2009 was 2,781 Bbls/d (279 Bbls/d working interest to the Company) and is targeted to reach 38,000 Bbls/d (3,800 Bbls/d working interest to the Company) before March 31, 2010. Sales from the MA field during the year were 88,000 BBls working interest to the Company. Production from Block 9 was 55 MMcfe/d during the year and is expected to increase to over 100 MMcf/d (60 MMcf/d working interest to the Company) in fiscal 2010. Production from the Hazira and Surat fields was 57 MMcfe/d (26 MMcfe/d working interest to the Company). The forecast production is consistent with the Company's reserve report for these fields.

Exploration

The following chart depicts the number of the Company's active exploration blocks as at March 31, 2008 and its current holdings:

To view the Active Exploratin Blocks chart, please click the following link: http://media3.marketwire.com/docs/623nko_chart3.pdf

The Company has been successful in adding exploration blocks to its portfolio. As shown above, ten blocks have been added since March 31, 2008 and the Company is now active in 19 exploration blocks in five countries. The Company operates 11 of the blocks: two in India; four in Pakistan; one in Madagascar; one in Kurdistan and three in Indonesia.

Exploration During Fiscal 2009

Since March 31, 2008, the Company has participated in drilling four exploration wells in India: the L1, MK1 and AR2 wells in the D6 Block and the B3 well in the NEC-25 Block. The L1 well encountered significant quantities of hydrocarbons and the MK1 well was not successful. The AR2 well is located in water depth of 1,844 metres and is approximately 5.7 kilometres northwest of the R1 late Miocene gas discovery in the D6 Block. The well extended the gas accumulation originally discovered by the R1 well and as a result enhanced the potential natural gas resource in this area. The B3 well was drilled in 64 metres of water to a total true vertical depth of 3,928 metres and encountered a gas zone at 1,900 metres. The Company has not updated its contingent resources to take into account these discoveries.

During the year, the Company completed a 3,600-square-kilometre 3D seismic survey in the D4 Block in India; a 1,000-square-kilometre 3D seismic survey in the NEC-25 Block in India; a 30-square-kilometre transition zone 3D seismic survey in the Hazira Block in India; a 2,000-square-kilometre 3D seismic survey in Pakistan; and reprocessing of 7,600 kilometres of 2D seismic in Madagascar. The Company is currently nearing completion of a 350-kilometre 2D seismic program in Kurdistan.

Planned Exploration

The Company expects to spend US$121 million to complete the planned exploration work program for the year ending March 31, 2010. The chart below shows the planned work program for fiscal 2010 and the tentative work program until December 31, 2011. With the exception of D6, NEC-25 and Hazira Blocks, the activity shown on the chart below is based on the minimum work commitments under PSC/PSAs. The chart also includes wells that are expected to be drilled by other companies in the same geological basin as the Company's acreage.

To view the Planned Exploration chart, please click the following link: http://media3.marketwire.com/docs/623NKOCHART4.pdf

India

D6 Block: The Company is currently drilling the BA2 and AS1 wells. The company expects a continuous drilling program on numerous prospects within the block.

D4 Block: The initial interpretation of the data within the 3,600 square kilometre 3D seismic survey acquired has identified several areas of interest, which will be fully analysed as part of the ongoing evaluation. Processing and interpretation of the data are expected to be completed in time for the Company to meet the drilling schedule shown above.

Cauvery: The The Khoja-1 well spud in April 2009 and has a planned true vertical depth of 4,100 metres. The primary target of the well is the Cretaceous-Jurassic-Basement interval. Drilling of the well planned in the second quarter of fiscal 2010 is contingent on the results of the Khoja-1 well.

Hazira Block: The 3D survey is designed to explore for deeper oil and gas targets in the eastern half of the Hazira block. The survey will merge with the offshore seismic previously acquired and provide 3D coverage for almost the entire Hazira block. Dependent on results of processing and interpretation of the 3D program, a multi-well drilling program is to be initiated as shown above.

NEC-25 Block: Approximately 1,000 square kilometres of 3D seismic have been acquired along the central portion of the northwest boundary of the previous 3D surveys. The AJ2 well is currently being drilled to delineate the J1 discovery.

Pakistan

The 3D seismic program acquired during fiscal 2009 is expected to identify stratigraphic potential, resolve structural complexity and indicate the presence of hydrocarbons. Processing of the 3D data should be completed in the third calendar quarter of 2009 with interpretation and selection of drilling locations to follow.

Madagascar

Interpretation of the reprocessed 2D seismic and further evaluation of the block is planned including a high-resolution multi-beam survey and sea floor coring program intended to identify sea floor oil and gas seeps. Future work as prescribed in Phase II includes the acquisition of a 3D seismic program to be designed based on results of the 2D seismic reprocessing and the multi-beam survey. The Company expects to drill a well in the first quarter ending June 30, 2011.

Kurdistan

The 2D seismic program is currently being acquired over the surface structure that dominates the Qara Dagh block. Processing has commenced and interpretation will follow once final processed sections are received. Interpretation of the data is expected to resolve the sub-surface structural picture and characterize potential reservoir sections leading to the selection of a drilling location. Drilling is expected to commence in the first quarter of fiscal 2011.

Indonesia

Niko has acquired several blocks in deepwater offshore Indonesia. Indonesia has long been a prolific oil and gas producing nation with very large reserves, however, the deepwater areas have remained essentially unexplored. All blocks have sea bottom oil and gas seeps, large structural or stratigraphic features and several have direct indication of hydrocarbons on seismic.

The well commitment for each block will follow seismic interpretation. The seismic program planned for each block is outlined below.

Bone Bay: The seismic program planned for the block includes acquisition of 3,000 kilometres of 2D seismic.

Cendrawasih: The seismic program planned for the block includes acquisition 1,200 square-kilometres of 3D seismic, which will cover 24 percent of the 5,000 square kilometre block.

Kofiau: The seismic program planned for the block includes acquisition of 1,062 kilometres of 2D seismic and 3,150 square kilometres of 3D seismic, which will cover 60 percent of the 5,000 square kilometre block.

Kumawa: The seismic program planned for the block includes acquisition of 3,000 kilometres of 2D seismic.

Seram: The seismic program planned for the block includes acquisition of 3,500 kilometres of 2D seismic.

South Matindok: The seismic program planned for the block includes acquisition of 4,400 kilometres of 2D seismic.

Southeast Ganal: The seismic program planned for the block includes acquisition of 284 kilometres of 2D seismic and 2,700 square kilometres of 3D seismic, which will cover over 50 percent of the 5,000 square kilometre block.

West Sageri: The seismic program planned for the block includes acquisition of 371 kilometres of 2D seismic and 702 square kilometres of 3D seismic, which will cover 14 percent of the 5,000 square kilometre block.

OPERATING EXPENSE

During the year ended March 31, 2009, operating expenses averaged US$0.40/Mcfe. Operating expenses increased during the year due to the start-up costs related to the commencement of D6 oil production and are anticipated to fall significantly on a unit-of-production basis once the D6 gas field is producing at designed capacity.

Forward-Looking Information and Material Assumptions

This report on results for the year ended March 31, 2009 contains forward-looking information including forward-looking information about Niko's operations, reserve estimates, production and capital spending. Forward-looking information is generally signified by words such as "forecast", "projected", "expect", "anticipate", believe", "will" and similar expressions. This forward-looking information is based on assumptions that the Company believes were reasonable at the time such information was prepared, but assurance cannot be given that these assumptions will prove to be correct, and the forward-looking information in this report on results for the year ended March 31, 2009 should not be unduly relied upon. The forward-looking information and the Company's assumptions are subject to uncertainties and risks and is based on a number of assumptions made by the Company, any of which may prove to be incorrect. Forward-looking information in this report on the results ended March 31, 2009 includes, but is not limited to, the following:

Forecast production rates: The Company prepares production forecasts taking into account historical and current production, actual and planned events that are expected to increase or decrease production and production levels indicated in the Company's reserve reports.

Forecast capital spending and commitments: The Company prepares capital spending forecasts based on internal budgets for operated properties, budgets prepared by the Company's joint venture partners, when available, for non-operated properties, field development plans and actual and planned events that are expected to affect the timing or amount of the capital spending.

Forecast operating expenses: The Company prepares operating expense forecasts based on historical and current levels of expenses and actual and planned events that are expected to increase or decrease production and/or the associated expenses.

Timing of production increases, timing of commencement of production and timing of capital spending: The Company discloses the nature and timing of expected future events based on the Company's budgets, plans, intentions and expected future events for operated properties. The nature and timing of expected future events for non-operated properties are based on budgets and other communications received from the Company's joint venture partners, when available.

The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis and updates reserves on an annual basis. Refer to "Risk Factors" contained in the Company's management's discussion and analysis for discussion of uncertainties and risks that may cause actual events to differ from forward-looking information provided in this report on results for the year ended March 31, 2009.

MANAGEMENT'S DISCUSSION AND ANALYSIS

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, 2009 should be read in conjunction with the consolidated financial statements and accompanying notes for the year ended March 31, 2009. This MD&A is effective June 22, 2009. Additional information relating to the Company, including the Company's Annual Information Form (AIF), is on SEDAR at www.sedar.com.

Over the reporting period, revenue and expenses were generated and capital expenditures were made in India, Bangladesh and Canada, and capital expenditures were made for Indonesia, Kurdistan, Madagascar, Pakistan, and new ventures. The Company's activities are carried out primarily in U.S. dollars as well as the currencies of each country in which the Company operates. The Company reports its financial results in U.S. dollars.

The selected financial information presented throughout the MD&A is prepared in accordance with Canadian generally accepted accounting principles (GAAP), except for "funds from operations", "segment profit", "operating netback", "funds from operations netback" and "earnings netback", which are used by the Company to analyze the results of operations. These non-GAAP measures do not have any standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other companies. Effective March 31, 2009, the Company adopted the U.S. dollar as its reporting currency. The change is attributable to the fact that the Company's transactions are primarily conducted in U.S. dollars. All comparative financial information being presented has been restated to reflect the Company's financial statements as if they had been historically reported in U.S. dollars. All financial information is presented in U.S. dollars unless otherwise indicated.

The fiscal year for the Company is the 12-month period ended March 31. The terms "fiscal 2009", "current year" and "the year" are used throughout the MD&A and in all cases refer to the period from April 1, 2008 through March 31, 2009. The term "fiscal 2010" is used throughout the MD&A and refers to the period from April 1, 2009 through March 31, 2010. The terms "previous year", "prior year" and "fiscal 2008" are used throughout the MD&A for comparative purposes and refer to the period from April 1, 2007 through March 31, 2008. The term "fiscal 2007" is used throughout the MD&A for comparative purposes and refers to the period from April 1, 2006 through March 31, 2007.

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

Less than 1 percent of total corporate volumes and 3 percent of total corporate revenue are from Canadian oil, Bangladeshi condensate and Hazira condensate production. Therefore, the results from Canadian oil, Bangladeshi condensate and Hazira condensate production are not discussed separately. Canadian oil revenue and royalty income was US$0.8 million in the year and US$0.9 million in the prior year. Canadian royalty expense was US$0.1 million in the year and US$0.1 million in the prior year. Canadian operating expenses were US$0.1 million in the year and US$0.2 million in the prior year. Canadian and head office depletion, depreciation and accretion expense was US$0.6 million in the year and US$0.4 million in the prior year.

Certain prior-year amounts have been reclassified to conform to current-year presentation and to conform to a U.S. dollar reporting currency.

Forward-Looking Information and Material Assumptions

This MD&A contains forward-looking information including forward-looking information about Niko's operations, reserve estimates, production and capital spending. Forward-looking information is generally signified by words such as "forecast", "projected", "expect", "anticipate", believe", "will" and similar expressions. This forward-looking information is based on assumptions that the Company believes were reasonable at the time such information was prepared, but assurance cannot be given that these assumptions will prove to be correct, and the forward-looking information in this MD&A should not be unduly relied upon. The forward-looking information and the Company's assumptions are subject to uncertainties and risks and is based on a number of assumptions made by the Company, any of which may prove to be incorrect. Forward-looking information in this MD&A includes, but is not limited to, the following:

Forecast production rates: The Company prepares production forecasts taking into account historical and current production, actual and planned events that are expected to increase or decrease production and production levels indicated in the Company's reserve reports.

Forecast capital spending and commitments: The Company prepares capital spending forecasts based on internal budgets for operated properties, budgets prepared by the Company's joint venture partners, when available, for non-operated properties, field development plans and actual and planned events that are expected to affect the timing or amount of the capital spending.

Forecast operating expenses: The Company prepares operating expense forecasts based on historical and current levels of expenses and actual and planned events that are expected to increase or decrease production and/or the associated expenses.

Timing of production increases, timing of commencement of production and timing of capital spending: The Company discloses the nature and timing of expected future events based on the Company's budgets, plans, intentions and expected future events for operated properties. The nature and timing of expected future events for non-operated properties are based on budgets and other communications received from the Company's joint venture partners, when available.

The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis and updates reserves on an annual basis. Refer to "Risk Factors" contained in this MD&A for discussion of uncertainties and risks that may cause actual events to differ from forward-looking information provided in this MD&A.

Non-GAAP Measures

By examining funds from operations, the Company is able to assess its past performance and to help determine its ability to fund future capital projects and investments. Funds from operations is calculated as cash flows from operating activities prior to the change in operating non-cash working capital and the change in long-term accounts receivable. Funds from operations is a non-GAAP measure and does not have any standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies.

By examining operating netback, funds from operations netback, earnings netback and segment profit, the Company is able to evaluate past performance by segment and overall. Operating netback is calculated as oil, natural gas and pipeline revenues less royalties, profit petroleum expenses, operating expenses and pipeline expenses, per thousand cubic feet equivalent (Mcfe) and represents the before-tax cash margin for every Mcfe sold. Funds from operations netback is calculated as the funds from operations per Mcfe and represents the cash margin for every Mcfe sold. Earnings netback is calculated as net income per Mcfe and represents net income for every Mcfe sold. Segment profit is defined as oil, natural gas and pipeline revenues less royalties, profit petroleum expenses, operating and pipeline expenses, depletion, depreciation and accretion expense and current income taxes related to each business segment. There are no comparable GAAP measures for operating netback, funds from operations netback, earnings netback or segment profit, and these measures are unlikely to be comparable with the calculation of similar measures in other companies. See "Segment Profit" and "Netbacks" in this MD&A.

The Company defines working capital as current assets less current liabilities and uses working capital deficit as a measure of the Company's ability to fulfill past obligations with current assets.



OVERALL PERFORMANCE

Funds from Operations

(thousands of U.S. dollars)
Years ended March 31, 2009 2008
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Oil and natural gas revenues $ 104,993 $ 101,006
Pipeline revenue 318 646
Royalties (4,801) (5,037)
Profit petroleum (22,863) (24,462)
Operating and pipeline expense (12,367) (10,682)
Interest income 11,331 21,661
Interest and financing on capital lease (1,498) -
General and administrative expense (7,125) (7,051)
Realized foreign exchange (loss) gain 3,320 (123)
Current income tax expense (5,059) (1,862)
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Funds from operations(1) $ 66,249 $ 74,096
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(1) Funds from operations is a non-GAAP measure as calculated above.


Revenues net of royalties increased slightly year-over-year as a result of the sale of first oil production from the D6 block and increased production from Block 9. The prior year's profit petroleum included a one-time negative adjustment of US$3.7 million due to the adverse resolution of a previously disclosed dispute regarding profit petroleum. Excluding the effect of this adjustment, profit petroleum increased primarily due to increased revenues from Block 9. The increase in operating expense is due to bonuses with respect to the Block 9 production sharing contract (PSC) and the inclusion of D6 oil operating expenses partially offset by decreased operating expenses in the other producing properties. Interest income includes US$2.4 million of interest on a tax refund received in India, which was more than offset by lower interest rates and lower cash balances in the periods. The interest expense relates to the lease of the Floating Production, Storage and Offloading vessel (FPSO) for D6 oil production. There was a realized foreign exchange gain on the settlement of the Indian rupee-denominated income tax receivable. Finally, there was an income tax recovery in the prior year.



Net Income (Loss)

(thousands of U.S. dollars)
Years ended March 31, 2009 2008
----------------------------------------------------------------------------
Funds from operations (non-GAAP measure) 66,249 74,096
Unrealized foreign exchange gain (loss) 4,784 (8,149)
(Loss) gain on short-term investment (24,380) 1,418
Equity (loss) on long-term investment (982) -
Impairment of long-term investment (4,186) -
Gain (loss) on risk management contracts 494 (2,065)
Discount of long-term account receivable (265) (4,434)
Asset impairment (1,258) (23,377)
Stock-based compensation expense (18,989) (16,927)
Depletion, depreciation and accretion (44,029) (40,577)
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Net (loss) (22,562) (20,015)
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The unrealized foreign exchange gain was on the translation of U.S. dollar-held cash to Canadian dollars, partially offset by a loss on translating the Indian rupee-denominated income tax receivable to U.S. dollars. The Company occasionally purchases securities in entities that represent strategic opportunities. The loss on the short-term investment is consistent with the overall market decline. The equity loss and the impairment of long-term investment is related to the Company's investment in Vast Exploration Inc. The gain on risk management contracts relates to the Company's interest rate swaps. During the prior year, the Company discounted the long-term account receivable to fair value and wrote-off Thailand assets of US$22.8 million. The increase in stock-based compensation was attributable to both an increased number of options being expensed during the year and an increased fair value expense per stock option. Depletion expense increased primarily due to an increase in the depletion rates per Mcfe as a result of an increase in the cost base.

BACKGROUND ON PROPERTIES

Niko Resources Ltd. is engaged in the exploration for and, where successful, the development and production of natural gas and oil in India, Bangladesh, Pakistan, Kurdistan, Madagascar and Indonesia. The Company has agreements with the governments of these countries or with other companies operating in these countries and regions for rights to explore for and, if successful, produce natural gas and oil. The Company generally is granted an exploration licence to commence work. The agreements generally involve a number of exploration phases with specified minimum work commitments and the maximum number of years to complete the work. At the end of any exploration phase, the Company has the option of continuing to the next exploration phase and may be required to relinquish a portion of the non-development acreage to the respective government. If a commercial discovery is not made by the end of all the exploration phases, the Company's rights to explore the block generally terminate. In the event of a discovery that is determined to be commercial, the Company prepares a development plan and applies to the government for a petroleum mining licence. The petroleum mining licences are for a specified number of years and may be extended under certain circumstances. During the production phase, the Company is required to pay any royalties specified in the agreements and taxes applicable in the country. The Company pays to the government an increasing share of the profits based on an Investment Multiple (IM) or on production levels plus an IM, or a fixed share of profits, depending on the agreement. The IM is the number of times the Company has recovered it's investment in the property from its share of profits from the property. At the end of the life of the field or the mining licence, the field and the assets revert to the government; however, the Company is responsible for the costs of abandonment and restoration.

India

Cauvery - The Company operates the block, which covers 957 square kilometres. The production exploration licence was granted for a period of 20 years; however, the exploration phases in the agreement cover seven years. The Company has performed the seismic work and drilled two of the four to five wells required under the first exploration phase. The Company is currently drilling the third exploration well. The Company has received a six month extension to the exploration period to January 2009. Depending on exploration results, the Company will apply to the government for another extension to the first exploration period in order to have sufficient time to complete the work commitment and assess the potential of the block. The Indian government has historically granted extensions, when required; however, there is a risk that the extension may not be granted to the Company and the rights to continue exploration on the block would cease.

D4 - The Company has a 15 percent interest in the D4 Block, located in the Mahanadi Basin offshore the east coast of India. The block, which is currently in the exploration phase, encompasses more than 17,000 square kilometres. The commitment for Phase I exploration includes seismic work and drilling three exploration wells. Originally, the work commitment was to be completed by September 2009; however, the Government of India is in the process of approving a blanket three-year extension for this and other deepwater blocks, prompted by the shortage of deepwater drilling rigs. The seismic work was completed during the year and is ready for processing.

D6 - The Company has a 10 percent working interest in the 7,645-square-kilometre D6 Block. In addition to continued exploration on the block there are two development projects: the MA oil discovery and the Dhirubhai 1 and 3 natural gas discoveries. Production from the MA discovery began in September 2008 and from the Dhirubhai 1 and 3 discoveries in April 2009. The Company has been granted a petroleum mining lease for a period of 20 years. Oil production is sold on the spot market at a price based on Bonny Light and adjusted for quality. Gas production is sold under long-term gas contracts using a pricing formula approved by the Government of India, which currently results in a price of US$4.20/MMbtu. The development plan for nine additional natural gas discoveries in the D6 Block was submitted to the Government of India in July 2008. The discoveries are adjacent to the Dhirubhai 1 and 3 gas fields that are currently producing. If the development plan is approved, it is intended that these satellite discoveries be tied back to the Dhirubhai 1 and 3 facilities.

Under the terms of the production sharing contract with the Government of India for the D6 block, the Company is required to pay the government a royalty of 5 percent of the well-head value of crude oil and natural gas for the first seven years from the commencement of commercial production in the field and thereafter to pay 10 percent. In addition, the Company pays a percentage of the profits from the block to the government, which varies with the Investment Multiple (IM). The Company pays 10 percent of profits when the IM is less than 1.5; 16 percent between 1.5 and 2; 28 percent between 2 and 2.5; and 85 percent thereafter.

Hazira - The Company has a 33 percent working interest in the 50-square-kilometre Hazira onshore and offshore block on the west coast of India, which lies adjacent to a large industrial corridor about 25 kilometres southwest of the city of Surat. The Company has a petroleum mining licence that expires in September 2014. The Company has three contracts for the sale of gas production from the field expiring between October 2009 and April 2016 at current prices up to US$5.00/Mcf and sells any production in excess of contracted amounts to one of the contracted customers at a price of US$4.87/Mcf. In addition to the price indicated, the Company collects the 10 percent royalty, that is payable to the government, from the customer. The Company pays a percentage of the profits from the block to the government, which varies with the Investment Multiple (IM). The Company does not share profits when the IM is less than one; shares 10 percent of profits between one and 1.5; 20 percent between 1.5 and 2; 25 percent between 2 and 2.5; 35 percent between 2.5 and 3; and 40 percent thereafter.

NEC-25 - The Company has a 10 percent working interest in the NEC-25 Block, which covers 10,755 square kilometres in the Mahanadi Basin off the east coast of India. The Company has fulfilled its capital commitments for the block and is currently drilling under an appraisal program. Development plans have been submitted for the six gas discoveries that have been declared commercial by the Indian regulatory authorities.

Surat - The Company holds a development area of 24 square kilometres containing the Bheema and NSA shallow natural gas fields. These fields have been producing natural gas since April 2004. The Company has a petroleum mining licence that expires in September 2024. The Company has one contract for the sale of gas production from the field expiring on March 31, 2011 at a price of US$5.00/Mcf until March 31, 2009 and increasing to US$5.50/Mcf and US$6.00/Mcf in each subsequent year. In addition to the price indicated, the Company collects the 9 percent royalty, payable to the government, from the customer. In addition, the Company will pays percentage of the profits from the block to the government, which varies with the Investment Multiple (IM). The Company shares 20 percent of profits when the IM is between one and 1.5; 30 percent between 1.5 and 2; 40 percent between 2 and 2.5; 50 percent between 2.5 and 3; and 60 percent thereafter.

Bangladesh

Block 9 - The Company holds a 60 percent interest in this 6,880-square-kilometre onshore block which encompasses the capital city of Dhaka. The Company has fulfilled its obligations under the exploration period for the block. Natural gas and condensate production from this field began in May 2006. As per the PSC, the Company has rights to produce for a period of 25 years and this arrangement is extendable if production continues beyond this period. The Company sells gas under a gas purchase and sales agreement (GPSA) at a current price of US$2.34/MMbtu for a period up to 25 years. The Company shares a percentage of the profits from the block with the government, which varies with production and whether or not the Company has recovered its investment. The Company pays to the government 61 percent and 66 percent of profits, respectively, before and after costs are recovered on natural gas production up to 150 MMcf/d; 66 percent and 72.5 percent on natural gas production between 150 MMcf/d and 300 MMcf/d; 72.5 percent and 78 percent on production between 300 MMcf/d and 450 MMcf/d; 75 percent and 82.5 percent on production between 450 MMcf/d and 600 MMcf/d and 82 percent and 85 percent on production in excess of 600 MMcf/d. Profits on natural gas are calculated as the minimum of (i) 55 percent of revenue for the period and (ii) revenue less operating and capital costs incurred to date.

Feni and Chattak - The Feni field covers 43 square kilometres and is located 6 kilometres west of the main natural gas line to Chittagong. The Chattak structure covers 376 square kilometres and rights to this block were obtained in October 2003. The Company has been producing natural gas from the Feni field since November 2004. As per the JVA, the Company has rights to produce until October 2023 and this arrangement can be extended if production continues beyond this period. The Company sells gas under a GPSA including a price of US$1.75 per Mcf, which expires in November 2009 and can be extended with mutual consent. Receipt of payment for the gas is being delayed as a result of various claims raised against the Company as described in note 24 to the consolidated financial statements for the year ended March 31, 2009. The Company pays a percentage of the profits from the field to the government, which varies with the Investment Multiple (IM). The Company shares 20 percent of profits from the Feni field when the IM is less than one; 25 percent between 1 and 1.5; 32 percent between 1.5 and 2; 38 percent between 2 and 3; and 42 percent thereafter. Future drilling activities at Feni and Chattak have been postponed pending resolution of overdue payment for gas owed to the Company by the Government of Bangladesh.

Pakistan

Four production sharing agreements (PSAs) were signed in March 2008. The blocks are located in the Arabian Sea offshore the city of Karachi and cover an area of almost 10,000 square kilometres. Each agreement is for an initial exploration term of five years with two exploration renewal periods of two years each and further renewal in the event of commercial production. The blocks are currently in Phase I of the exploration period, which expires in March 2010, and have work commitments for a minimum of 200 square kilometres of 3D seismic in each block. A 2,000-square-kilometre 3D seismic program has been completed and, once processed, will fulfill the work commitment under Phase I. To retain the blocks for the full 5-year exploration period, the Company will need to acquire additional seismic or drill one well.

Kurdistan Region

In May 2008 the Company signed a PSC for the onshore Qara Dagh block, which covers approximately 846 square kilometres, in the Sulaymaniyah Governorate of the Federal Region of Kurdistan in Iraq. The Company currently has a 36 percent interest and carries the proportionate cost for the regional government's interest, resulting in a 45 percent cost interest. The exploration period is for a term of five years and is extendable by two one-year terms. The first exploration phase is for three years expiring in May 2011 and the Company has commitments under this phase for seismic and drilling one exploratory well. The seismic program is currently underway.

Madagascar

In October 2008 the Company farmed-in to a PSC for a property off the west coast of Madagascar. The farm-in agreement and appointment of the Company as operator have been approved by the Office of National Mines and Strategic Industries, which acts on behalf of the Republic of Madagascar. In January 2009 the Company farmed out a portion of its interest and currently has a 65 percent interest in the block. The PSC covers 16,845 square kilometres in water depths ranging from shallow water to 1,500 metres. The Company completed a 31,944-line-kilometre aero-magnetic survey applicable to the Phase I work commitment. The Company has remaining work commitments under the first exploration phase for 2,000 line-kilometres of 2D seismic, which must be completed by June 2010.

Indonesia

In November 2008, the Company signed four PSCs for interests in four deep-water offshore exploration blocks covering almost 20,000 square kilometres. The Company will operate two of the blocks, South East Ganal and West Sageri, and will earn a 51 percent working interest. These blocks are located in the Makassar Strait. The Company will participate in the South Matindok and Seram blocks and earn a 25 percent working interest therein. The South Matindok block is located in northeast Sulewasi and the Seram block is located in north Seram.

Also in November 2008, the Company acquired the right to earn a 25 percent interest in another deep-water offshore exploration block, Bone Bay, covering almost 5,000 square kilometres. The Bone Bay block is located in southwest Sulewasi.

Each of the five Indonesian blocks is in the first exploration period, which expires in November 2011. The Company has minimum work commitments in this period to acquire and process 16,550 kilometres of 2D seismic in total for the five blocks and drill one well in each of the five blocks.

In May 2009, the Company and its partners were awarded three additional offshore exploration blocks: Kofiau, Kumawa and Cendrawasih. The Company will operate the Kofiau block, will earn a 67 percent working interest. This block is located in west Papua. In the Kumawa and Cendrawasih blocks, which will not be operated by the Company, the Company will earn a 25 percent working interest. These blocks are located in southwest and northwest Papua, respectively. Each of these three Indonesian blocks is in the first exploration period, which expires in May 2012 and the Company has minimum work commitments for the acquisition of 4,042 kilometres of 2D seismic, 1,200 square kilometres of 3D seismic, drilling one well per block and various payments under the agreements.



CAPITAL EXPENDITURES

Exploration Spending (Net to the Actual Forecast
Company) spending for spending for
the year the year
ended ending
March 31, March 31,
(millions of U.S. dollars) 2009 (1) 2010 (2)
----------------------------------------------------------------------------
India 46.2 63
Indonesia 15.7 25
Kurdistan Region 23.7 23
Madagascar 4.6 7
Pakistan 22.6 3
----------------------------------------------------------------------------
Total 112.8 121
----------------------------------------------------------------------------
(1) The Company also spent $0.2 million on Bangladesh exploration and $0.7
million on new ventures.
(2) Refer to "ForwardLooking Information and Material Assumptions" in this
MD&A for a description of how forecast capital expenditures are
estimated.


Indian capital spending in fiscal 2009 included the costs of site preparation and drilling in Cauvery (US$3.4 million), a transitional 3D seismic program in Hazira (US$2.3 million), seismic work in the D4 block (US$8.2 million), seismic work in NEC-25 (US$12.0 million) and exploratory drilling in the D6 Block (US$20.3 million). Forecast capital spending for India includes drilling the remaining wells under the work commitment for Cauvery, processing of the 3D seismic acquired in D4 and further exploratory drilling in the D6 Block.

There were also bonuses payable upon signing five Indonesian PSCs during the year and the purchase of a seismic data package totalling US$15.7 million. Forecast capital spending is for seismic and drilling an exploratory well.

Costs of US$23.7 million were incurred in Kurdistan, primarily for various bonuses required as per the PSC.

Costs of US$4.6 million were incurred in Madagascar for the acquisition and reprocessing of existing 2D seismic data. Expenditures are forecast for a multi-beam survey.

In Pakistan, US$22.6 million was spent on the acquisition of 2,000 square kilometres of 3D seismic. Forecast capital spending is for processing of the seismic and local office costs.




Development Spending (Net to the Actual Forecast
Company) spending for spending for
the year the year
ended ending
March 31, March 31,
(millions of U.S. dollars) 2009 2010 (1)
----------------------------------------------------------------------------
Bangladesh 14.6 11
India 353.6 225
----------------------------------------------------------------------------
Total 368.2 236
----------------------------------------------------------------------------
(1) Refer to "Forward-Looking Information and Material Assumptions" in this
MD&A for a description of how forecast capital expenditures are
estimated.


Indian development spending was primarily for the D6 development including drilling and tie-in of additional wells and putting the MA oil field onstream, and drilling, tie in and construction of facilities for the Dhirubhai 1 and 3 gas fields. The development continues in fiscal 2010. Development in Bangladesh included the tie-in of the Bangora-3 well, well testing and upgrading the production facility in Block 9. Forecast spending in Bangladesh includes the remaining costs of the facilities upgrades, well testing and payment of the guarantee associated with the work commitment for the block.



SEGMENT PROFIT

India

(thousands of U.S. dollars, except as indicated)
Years ended March 31, 2009 2008
----------------------------------------------------------------------------
Natural gas revenue 45,509 49,646
Oil revenue (1) 8,715 7,383
Pipeline revenue 318 646
Royalties (4,666) (4,915)
Profit petroleum (6,224) (10,249)
Operating and pipeline expenses (7,632) (6,481)
Depletion, depreciation and accretion (22,040) (23,100)
Current income tax expense (5,138) 1,241
----------------------------------------------------------------------------
Segment profit (2) 8,842 14,171
----------------------------------------------------------------------------
Daily natural gas sales (Mcf/d) 24,642 31,164
Daily oil sales (Bbls/d) (1) 410 220
Depletion rate (US$/Mcfe) 2.14 1.91
----------------------------------------------------------------------------
(1) Production that is in inventory has not been included in the revenue or
cost amounts indicated.
(2) Segment profit is a non-GAAP measure as calculated above.


Revenue and Royalties

Natural gas revenue was positively impacted by increased sales prices charged for Hazira and Surat natural gas. The prices negotiated under the Company's gas contracts are revised periodically as per contract terms. During the year, the Company had various gas contracts with prices between US$4.05/Mcf and US$5.00/Mcf (year ended March 31, 2008- US$3.50/Mcf to US$4.50/Mcf). Production is forecast to increase in fiscal 2010 due to the commencement of production from the Dhirubhai 1 and 3 gas fields in India.

The effect of prices on natural gas revenue was more than offset by a decrease in the average daily natural gas production from the Hazira field due to ongoing natural declines. Natural gas production from the Surat block was stable year-over-year as natural declines were offset by production from three additional wells.

There was a net increase in oil revenues due to the sales of oil from the D6 block commencing in November 2008 of 88,107 bbls for proceeds of US$4.2 million. Oil production from the Hazira block in the year was 169 Bbls/d. The average oil sales price moved in accordance with world market prices.

Profit Petroleum

Pursuant to the terms of the PSCs the Government of India is entitled to a sliding scale share in the profits once the Company has recovered its investment. For Hazira, in the current and prior years' periods, the government was entitled to 25 percent of the cash flow, defined as revenue less royalties, operating expenses and capital expenditures. For Surat, the Company recovered its investment during the year and began sharing profits, defined as revenue less royalties, operating expenses and capital expenditures, with the government at a rate of 20 percent.

The decrease in profit petroleum in the year was mainly due to the adverse resolution of a previously disclosed dispute regarding profit petroleum of US$3.7 million recorded in the prior year.

Operating Expenses

Operating expenses in the year increased with the start-up costs associated with D6 oil. Operating expenses per barrel are expected to decrease on a unit-of-production basis once the D6 gas field is producing at designed capacity.

There was a decrease in the dollar amount of operating expenses for Hazira and Surat in the year compared to the prior year.

Depletion, Depreciation and Accretion

The depletion rate per Mcfe increased in the year primarily due to the inclusion of the D6 oil capital costs, including the costs of the FPSO, and the D6 oil reserves in the calculation for the Indian cost base.



Income Taxes

(thousands of U.S. dollars)
Years ended March 31, 2009 2008
----------------------------------------------------------------------------
Indian income tax expense 5,138 4,553
Indian income tax (recovery) related to prior periods - (5,794)
----------------------------------------------------------------------------
Indian current income tax expense 5,138 (1,241)
----------------------------------------------------------------------------


There was an increase in income tax expense during the year related to the effect of the interest received on the income tax refund, which was recognized in the year. The increase was approximately offset by the effect of a change in taxation policy. A tax ruling received by the Company indicated the rates at which tax pools may be claimed in arriving at taxable income, which was different than the manner in which the Company had calculated and recorded income taxes in the prior years'. There were income tax recoveries in the prior year related to re-estimating previously recorded income taxes applying the tax holiday deduction for eligible undertakings in Surat.

The Company has a contingency related to income taxes as at March 31, 2009. Refer to the consolidated financial statements and notes for the year for a complete discussion of the contingency.



Bangladesh

(thousands of U.S. dollars, except as indicated)
Years ended March 31, 2009 2008
----------------------------------------------------------------------------
Natural gas revenue 48,165 41,440
Condensate revenue 1,785 1,687
Profit petroleum (16,639) (14,212)
Operating expenses (4,606) (4,006)
Depletion, depreciation and accretion (21,024) (16,845)
Current income tax expense 166 (1,552)
----------------------------------------------------------------------------
Segment profit (1) 7,847 6,512
----------------------------------------------------------------------------
Daily natural gas production (Mcf/d) 57,607 49,827
Depletion rate (US$/Mcfe) 0.99 0.92
----------------------------------------------------------------------------
(1) Segment profit is a non-GAAP measure as calculated above.


Revenue, Profit Petroleum, Depletion and Operating Expenses

Overall, Bangladesh revenue increased as a result of facility upgrades at Block 9. The Company had been receiving its 60 percent share of production from Block 9 as well as 6.67 percent of production in order to recover amounts the Company paid in relation to the Government of Bangladesh's share of costs in the block prior to declaration of commerciality in accordance with the PSC. The Company expects that it will finish recovering the amounts paid on behalf of the Government's share in fiscal 2010 and its share of production will be 60 percent.

Pursuant to the terms of the PSC for Block 9, the Government of Bangladesh was entitled to 61 percent of profit gas in the current and prior years' periods. Profit petroleum expense increased due to increased revenues from Block 9.

There was a net increase in Block 9 operating costs due to the production bonus of US$0.6 million when production was sustained above 75 MMcf/d (50 MMcf/d working interest to the Company) and a research and development contribution of US$0.3 million, both payable to the Government of Bangladesh as per the terms of the PSC.

Depletion expense in Bangladesh has increased due to increased production and an increased depletion rate per Mcfe. The depletion rate per Mcfe of production increased in the year primarily due to an increase in the estimate of future costs to produce the reserves in Block 9.

Income Taxes

The Company pays taxes for the Feni property in Bangladesh at a rate of 4.0 percent of revenues net of profit petroleum. In the prior year, the Company accrued taxes assessed by the Government of Bangladesh beyond the calculated taxes in the amount of US$1.4 million. The assessment was reduced in the current year resulting in a recovery of US$0.2 million.

The Company does not pay income taxes related to Block 9 production, as indicated in the PSC. The PSC indicates that the calculation of profit petroleum expense includes consideration of income taxes and, therefore, no income tax is assessed for Block 9.

NETBACKS

The following table outlines the Company's operating, funds from operations and earnings netbacks (all of which are non-GAAP measures) for the years ended March 31, 2009 and 2008:



Years ended March 31, 2009
----------------------------------------------------------------------------
India Bangladesh Total
(US$/Mcfe) (US$/Mcfe) (US$/Mcfe)
----------------------------------------------------------------------------
Oil and natural gas revenue $ 5.48 $ 2.36 $ 3.37
Pipeline revenue 0.03 - 0.01
Royalties (0.47) - (0.15)
Profit petroleum (0.63) (0.79) (0.73)
Operating and pipeline
expense (0.76) (0.21) (0.40)
----------------------------------------------------------------------------
Operating netback $ 3.65 $ 1.36 $ 2.10
Interest and other income 0.36
Interest and financing expense on
capital lease (0.05)
General and administrative
expense (0.23)
Realized foreign exchange
gain 0.11
Current tax expense (0.16)
----------------------------------------------------------------------------
Funds from operations
netback $ 2.13
Unrealized foreign exchange gain
(loss) 0.15
Discount of long-term account
receivable (0.01)
Stock-based compensation
expense (0.61)
(Loss) gain on short-term
investment (0.79)
Equity loss on long-term
investment (0.03)
Impairment of long-term
investment (0.13)
Gain (loss) on risk management
contracts 0.02
Asset impairment (0.04)
Depletion, depreciation and accretion
expense (1.42)
----------------------------------------------------------------------------
Earnings netback $ (0.73)
----------------------------------------------------------------------------


Years ended March 31, 2008
----------------------------------------------------------------------------
India Bangladesh Total
(US$/Mcfe) (US$/Mcfe) (US$/Mcfe)
----------------------------------------------------------------------------
Oil and natural gas revenue $ 4.80 $ 2.35 $ 3.33
Pipeline revenue 0.05 - 0.02
Royalties (0.41) - (0.17)
Profit petroleum (0.86) (0.77) (0.81)
Operating and pipeline expense (0.55) (0.22) (0.34)
----------------------------------------------------------------------------
Operating netback $ 3.03 $ 1.36 $ 2.03
Interest and other income 0.71
Interest and financing expense on
capital lease -
General and administrative expense (0.23)
Realized foreign exchange gain -
Current tax expense (0.06)
----------------------------------------------------------------------------
Funds from operations netback $ 2.45
Unrealized foreign exchange gain
(loss) (0.27)
Discount of long-term account
receivable (0.15)
Stock-based compensation expense (0.56)
(Loss) gain on short-term
investment 0.05
Equity loss on long-term
investment -
Impairment of long-term investment -
Gain (loss) on risk management
contracts (0.07)
Asset impairment (0.77)
Depletion, depreciation and
accretion exprense (1.34)
----------------------------------------------------------------------------
Earnings netback $ (0.66)
----------------------------------------------------------------------------


The netback for India, Bangladesh and in total for the Company is a non-GAAP measure calculated by dividing the revenue and costs for each country and in total for the Company by the total sales volume for each country and in total for the Company measured in Mcfe.



CORPORATE

(thousands of U.S. dollars)
Years ended March 31, 2009 2008
----------------------------------------------------------------------------
Revenues
Interest income 11,331 21,661
Expenses
Interest and financing on capital lease 1,498 -
General and administrative expenses 7,125 7,051
Foreign exchange (gain) loss (8,104) 8,272
Stock based-compensation expense 18,989 16,927
Loss (gain) on short-term investment 24,380 (1,418)
Equity (gain) loss on long-term investment 982 -
Impairment of long-term investment 4,186 -
Loss (gain) on risk management contracts (494) 2,065
Asset impairment 1,258 23,377
Current income tax expense 87 1,551
----------------------------------------------------------------------------


Interest Income

Interest income decreased from US$21.7 million to US$11.3 million year-over-year primarily due to lower average cash balances and lower rates of interest earned during the year. The decrease was partially offset by interest of US$2.4 million received with respect to the income tax refund.

Interest and financing on capital lease

The Company entered into a lease for the FPSO, which has been classified as a capital lease. As a result, the Company recognizes a portion of lease payments as an interest cost.

General and Administrative Expense

General and administrative expense increased during the year primarily as a result of increased activity resulting in higher use of outside services, additional employees and payment of the employee bonus plan related to the prior year. The increases were partially offset by overhead recoveries as a result of increased capital activities in Pakistan and Kurdistan.



Foreign Exchange

(thousands of U.S. dollars)
Years ended March 31, 2009 2008
----------------------------------------------------------------------------
Realized foreign exchange (gain) loss (3,320) 123
Unrealized foreign exchange (gain) loss (4,784) 8,149
----------------------------------------------------------------------------
Total foreign exchange (gain) loss (8,104) 8,272
----------------------------------------------------------------------------


There was a realized foreign exchange gain in the year primarily on the settlement of Indian rupee-denominated income tax receivable created by the weakening of the Indian rupee against the U.S. dollar. The loss in the prior year was on Indian rupee-denominated working capital.

The unrealized foreign exchange gain was primarily on the translation of U.S. dollar-held cash to Canadian dollars, partially offset by a loss on translating the Indian rupee-denominated income tax receivable to U.S. dollars. There were unrealized losses on both of these items in the prior year.

Stock-based Compensation

The increase in stock-based compensation was attributable to both an increased number of options being expensed during the year and an increased fair value expense per stock option.

Short-term Investment

The Company occasionally purchases securities in entities that represent strategic opportunities and made such purchases in the year. The unrealized loss in the year is consistent with the overall market decline.

Equity Loss on Long-term Investment

The Company accounts for its investment in Vast Exploration Inc. using the equity method whereby the investment is initially recorded at cost and the carrying value is subsequently adjusted to include the Company's pro rata share of post-acquisition earnings of the investee. The Company recorded a loss of Cdn$1.1 million (US$1.0 million) calculated by the equity method during the year. There was a significant decline in the value of the shares compared to the carrying value of the investment, which had been continuing throughout the year. As a result, the Company determined that the investment was impaired during the year and wrote the value of the investment down to the Company's share of the book value of the investee's net assets. This resulted in an impairment of Cdn$5.2 million (US$4.2 million) and an ending carrying value for the investment of Cdn$5.3 million (US$4.2 million). The market value of the long-term investment at March 31, 2009 was Cdn$5.1 million (US$4.1 million).

Gain on Risk Management Contracts

As required by the credit facility, the Company entered into a series of interest rate swaps to fix the floating interest rate on a portion of the long-term debt. There were losses totalling US$2.1 million on the settlement of swaps during the year. These losses were included in the fair value of the interest rate swaps on the balance sheet at March 31, 2008, and therefore did not affect net income for the year ended March 31, 2009. There was a gain of US$0.5 million recognized in income during the year as the estimated fair value liability at March 31, 2008 of US$2.6 million was in excess of actual settlements during the year of US$2.1 million. This is due to the higher actual LIBOR rates applicable to the settlement of the swaps compared to the forecast LIBOR rates at March 31, 2008, which decreased the differential compared to the fixed interest rate.

Asset Impairment

During the prior year's periods, the Company wrote-off Thailand assets of US$22.8 million and US$0.6 million that was previous capitalized for new ventures. During the year ended March 31, 2009, the Company expensed costs of US$1.3 million that were previously capitalized for new ventures.

Income Taxes

In Canada, there was an income tax recovery in the year related to an adjustment to taxes estimated for the prior year and income tax expense on interest income from cash balances outstanding and as a result of a change in the method of allocating overseas income to Canada for income tax purposes.



SELECTED ANNUAL INFORMATION

(thousands of U.S. dollars, except
per share amounts)
Years ended March 31, 2009 2008 2007
----------------------------------------------------------------------------
Oil and natural gas revenue 104,993 101,006 101,362
Net income (loss) (22,562) (20,015) (26,465)
Per share basic and fully diluted
(US$) (0.46) (0.43) (0.66)
Total assets 1,468,630 1,316,987 607,771
Total long-term financial
liabilities 278,342 201,921 7,308
Dividends per share (Cdn$) 0.12(1) 0.12 0.12
----------------------------------------------------------------------------
(1) The dividend of Cdn$0.03 per share related to the quarter ended March
31, 2009 was declared in April 2009.



There was a decrease in oil and natural gas revenue in fiscal 2008 due to natural gas declines in the Hazira, Surat and Feni fields partially offset by increased production from Block 9 and increased sales prices at Hazira and Surat. In fiscal 2009, oil and natural gas revenues increased primarily as a result of the sale of first oil production from the D6 block and increased production from Block 9.

In addition to the changes in oil and natural gas revenue described above, the net loss and net loss per share decreased in fiscal 2008 from fiscal 2007, mainly due to interest income, depletion expense, and income tax. The increase in interest income was a result of higher cash balances in that year. Depletion expense decreased as a result of the increase in estimated reserves during fiscal 2007. Income taxes decreased as the Company recognized an income tax recovery from re-estimating prior years' tax filings and current-year's income taxes applying the Surat tax holiday deduction, and in addition there was an income tax recovery as a result of applying a tax tribunal ruling received, which were partially offset by tax on the interest income earned and additional tax assessed in Bangladesh. The above items, which decreased the net loss in fiscal 2008 versus fiscal 2007, were partially offset by the write-off of Thailand assets and a non-cash charge relating to discounting the long-term account receivable, which is for production from the Feni field in Bangladesh. Please see "Overall Performance" in this MD&A for a discussion of the change in the net loss from fiscal 2008 to fiscal 2009.

Total assets increased in fiscal 2008 over fiscal 2007 largely as a result of increased cash balance and capital asset additions during the year. There was a net increase in total assets in fiscal 2009 as the increase in capital assets was partially offset by the decrease in cash and cash call advances, which were used to fund capital asset and investment additions and part of the income tax receivable was collected during the year.

Total long-term financial liabilities consisted of the asset retirement obligation in fiscal 2007 and included that plus the long-term portion of debt incurred in fiscal 2008 and those two items plus the long-term portion of the capital lease obligation incurred in fiscal 2009.

FOURTH QUARTER

Overall, the results of the quarter ended March 31, 2009 were similar to the results of the previous quarter. The following items affected fourth quarter results.

Revenue from Block 9 in Bangladesh increased by 10 percent in the quarter ended March 31, 2009 compared to the previous quarter as a result of the facilities upgrades.

The remaining interest rate swap was settled during the quarter and the Company does not have any interest rate swaps outstanding at March 31, 2009. There was not a significant effect on the income statement as the payment had been accrued in the previous quarter.

Interest earned by the Company declined during the quarter as a result of decreasing cash balances.

The Canadian dollar weakened compared to the U.S. dollar during the quarter resulting in a foreign exchange gain on the translation of U.S. dollar-held-cash to Canadian dollars.

The Company's financial position improved as a result of the amendment to the credit facility in April 2009. As a result of the amendment, the cash that is restricted in accordance with the credit facility agreement may be used to fund development costs for Hazira, Surat, Block 9 and the D6 Block and the costs of operating the Hazira, Surat, Block 9 and the Dhirubhai 1 and 3 gas fields of the D6 Block. The Company began showing the portion of restricted cash that is expected to be used for the costs mentioned above as a current asset. Accounts payable increased from the previous quarter as a result of an increase in unpaid costs related to the D6 oil and gas development projects. At March 31, 2009, the Company had total restricted and unrestricted cash of US$240.7 million and a working capital surplus of US$115.1 million calculated as current assets less current liabilities.

SUMMARY OF QUARTERLY RESULTS

The following tables set forth selected financial information of the Company for the eight most recently completed quarters to March 31, 2009:



Three months ended
(thousands of U.S. dollars, except June 30, Sept. 30, Dec. 31, March 31,
per share amounts) 2008 2008 2008 2009
----------------------------------------------------------------------------
Oil and natural gas revenue 24,381 24,064 28,045 28,503
Net income (loss) 6,267 (22,420) (2,090) (4,319)
Per share
Basic (US$) 0.13 (0.46) (0.04) (0.09)
Diluted (US$) 0.13 (0.46) (0.04) (0.09)
----------------------------------------------------------------------------

Three months ended
(thousands of U.S. dollars, except June 30, Sept. 30, Dec. 31, March 31,
per share amounts) 2007 2007 2007 2008
----------------------------------------------------------------------------
Oil and natural gas revenue 27,088 27,875 22,467 23,576
Net income (loss) (5,273) (16,573) 476 1,355
Per share
Basic (US$) (0.12) (0.37) 0.01 0.03
Diluted (US$) (0.12) (0.37) 0.01 0.03
----------------------------------------------------------------------------


Net income has fluctuated over the quarters, due in part to changes in net revenue, profit petroleum, discount on the long-term account receivable and the value of the short-term investment.

There were forecast natural declines in production at the Hazira, Surat and Feni fields over the quarters, which were partially offset by increases in production from Block 9, both of which affected revenue. In the quarter ended December 31, 2007, there was a planned pressure survey in Block 9 resulting in decreased volumes in addition to the natural declines in the Hazira, Surat and Feni fields. In the quarter ended December 31, 2008, revenues increased due to an increase in production from Block 9 as a result of completion of a plant upgrade as well as the first sale of oil from the D6 block. Profit petroleum expense increased in the quarter ended December 31, 2008 with the increase in revenues from Block 9.

There was an asset impairment of US$22.8 million recognized in the quarter ended September 30, 2007 as a result of unsuccessful wells, workovers and associated costs in Thailand. In the quarter ended December 31, 2007, net income was reduced by US$4.3 million for a discount of the long-term account receivable to reflect the potential delay in collection as the account receivable may not be collected until resolution of various claims raised against the Company in Bangladesh.

The Company occasionally purchases securities in entities that represent strategic opportunities and made such purchases in fiscal 2008 and fiscal 2009. The short-term investment is recognized at fair value, which is the publicly quoted market value and the Company recognizes gains and losses based on market the changing market prices. The net income in the quarter ended June 30, 2008 and the net loss in the quarter ended September 30, 2008 are primarily a result of the gain and loss in the quarters, respectively. The losses continued through the quarter ended March 31, 2009.

LIQUIDITY AND CAPITAL RESOURCES

At March 31, 2009, the Company had total restricted and unrestricted cash of US$240.7 million and a working capital surplus of US$115.1 million calculated as current assets less current liabilities. The restricted portion of the cash balance was comprised of US$13.5 million of performance guarantees, US$3.5 million of cash restricted for future site restoration and US$192.5 million of cash restricted in accordance with the credit facility agreement. The cash that is currently restricted in accordance with the credit facility agreement may be used to fund development costs for Hazira, Surat, Block 9 and the D6 Block and the costs of operating the Hazira, Surat, Block 9 and the Dhirubhai 1 and 3 gas fields of the D6 Block. The Company has drawn US$192.8 million on its credit facility. No portion of the debt is due within the next twelve months. In April 2009, the credit facility was reduced to US$192.8 million.

The Company plans to fulfill its planned capital spending including commitments and current liabilities with future funds from operations and the permitted use of restricted cash. The Company's exposure to liquidity risks has decreased significantly from the previous period primarily as a result of the start-up of the D6 gas project in April 2009 and the amendment to the credit facility.

The Company has a number of contingencies as at March 31, 2009. Refer to the consolidated financial statements and notes for the year for a complete list of the contingencies and any potential effects on the liquidity of the Company.

The Company is able to make payments to Bangladesh vendors from its Feni and Chattak branch office, but is unable to repatriate funds from the Feni and Chattak branch office or to pay foreign vendors.

The Company had the following work commitments under various agreements as at March 31, 2009:

- D4 Block: The commitment for Phase I exploration includes seismic work and drilling three exploration wells. Originally, the work commitment was to be completed by September 2009; however, the Government of India is in the process of approving a blanket three-year extension for this and other deepwater blocks, prompted by the shortage of deepwater drilling rigs. The seismic work was completed during the year and is ready for processing and the cost of the remaining seismic-related work and drilling is estimated at US$73.0 million (US$11.0 million net to the Company).

- Cauvery Block: The Phase I exploration period, which ends in 2009, includes commitments for seismic work and drilling five exploration wells. The Company has completed the seismic, has drilled two exploration wells and is currently drilling a third exploration well. The estimated cost of the well that is currently being drilled and of the remaining wells under the work commitment total US$22.4 million.

- Pakistan: The Company has spent sufficient funds under Phase I of the initial term and processing of the seismic will fulfill the minimum work commitments. Phase I of the initial term expires in March 2010. To retain the blocks for the full 5-year exploration period, the Company will need to acquire additional seismic or drill one well.

- Kurdistan: The Company has minimum work commitments under Phase I of the exploration period for seismic and drilling an exploratory well, which must be completed by May 2011. The remaining capital expenditures related to the minimum work program are estimated at US$31.5 million (US$14.2 million net to the Company) and US$6.1 million (US$2.7 million net to the Company) for various payments under the agreement.

- Madagascar: The Company has minimum work commitments for 2,000-line kilometres of 2D seismic under Phase I of the exploration period, which expires in June 2010.

- Indonesia: For the eight Indonesian blocks, the total remaining minimum work commitments, including seismic and one exploration well per block during the first exploration periods, are US$210.3 million (US$119.3 million net to the Company). This exploration period ends in November 2011 for five of the blocks and May 2012 for the remaining three blocks.

The Company's contractual obligations (including those discussed above) are summarized in the following table:



Payments due by Period
(thousands of U.S. dollars) Less than 1 - 3 4 - 5 After 5
As at March 31, 2009 Total 1 Year Years Years Years
----------------------------------------------------------------------------

Principal repayments on
long-term debt (1) 192,814 - 192,814 - -
Guarantees(2) 24,373 15,910 8,463 - -
Work commitments(3) 157,469 52,698 66,070 38,701 -
Asset retirement
obligations (4) 73,717 - 5,637 1,445 66,635
Capital lease obligation (5) 101,320 10,757 21,514 21,514 47,535
----------------------------------------------------------------------------
Total contractual obligations 549,693 79,365 294,498 61,660 114,170
----------------------------------------------------------------------------

(1) There are no portions of debt due within the year, therefore the entire
debt is classified as long-term.
(2) The guarantees were amended subsequent to March 31, 2009. As at June 22,
2009, the guarantees for commitments less than one year were US$8.9
million and one to three years were US$10.9.
(3) Includes work commitments for the Pakistan blocks and Kurdistan block
for which the Company provides a parent guarantee instead of a bank
guarantee. Does not include work commitments for the three Indonesian
PSCs signed subsequent to March 31, 2009 with work commitments less than
one year of US$10.0 million and one to three years of US$46.6 million.
(4) Asset retirement obligations are based on the undiscounted estimated
future liability of the Company as disclosed in the notes to the
consolidated financial statements as at March 31, 2009. They do not
include wells or facilities that were not complete as at March 31, 2009.
(5) Capital lease obligation includes both the current and long-term
portions.


Although not committed, the Company has planned capital spending of US$148 million (net to the Company) and US$75 million (net to the Company) required to complete Phase I development of the Dhirubhai 1 and 3 gas fields and the MA oil field, respectively, and these costs are included in the capital forecast for fiscal 2010.

The Company has recognized the capital lease of the FPSO at the fair value of US$68.7 million. The lease is for 10 years and has lease payments of US$10.8 million per 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 of the Company, are measured at the exchange amount, which is also considered to be the fair value, and are in the normal course of business.

FINANCIAL INSTRUMENTS

Financial instruments of the Company consist of cash, restricted cash, the short-term investment, accounts receivable, cash call advances, long-term accounts receivable, accounts payable and accrued liabilities and long-term debt. As at March 31, 2009 and 2008, there were no significant differences between the carrying amounts of these instruments and the fair values. The fair values of cash, restricted cash, accounts receivable and accounts payable and accrued liabilities approximate their carrying values due to their short periods to maturity. The fair value of the cash call advances to joint venture partners is the amount of the funds advanced.

The Company is exposed to fluctuations in the value of its cash, accounts receivable, short-term investment, accounts payable and accrued liabilities due to changes in foreign exchange rates as these financial instruments are partially or wholly denominated in Canadian dollars, Indian rupees and Bangladeshi taka. The Company manages the risk by converting Canadian-held cash to U.S. dollars as required to fund forecast expenditures.

Financial instruments that potentially subject the Company to concentrations of credit risk consist of accounts receivable, cash call advances and long-term accounts receivable. The Company has accounts receivable from customers engaged in various industries that are concentrated in a specific geographical area in India and from one customer in Bangladesh. The Company takes measures in order to mitigate any risk of loss, which may include obtaining guarantees. The specific industries or government may be affected by economic factors that may impact accounts receivable.

The Company is exposed to changes in the market value of the short-term investment. The fair value of the investment is based on publicly quoted market values. An unrealized loss on the recognition of the short-term investment at fair value of US$24.4 million in the year was recognized in income to bring the carrying value of the investment to its fair value of US$9.1 million at March 31, 2009.

The long-term account receivable for gas sales charged to Petrobangla for production from the Feni field is carried at the discounted value of US$22.1 million as at March 31, 2009 and reflects the potential delay in collection of the amount. A loss of US$0.3 million in the year was recognized in income to discount the additional revenue recorded and included in the long-term account receivable to its fair value. The recorded amount of the long-term account receivable has been calculated using a discount rate of 6.5 percent and assumes collection in three years. The Company has and continues to attempt to collect the receivable through the agreed upon processes as per the JVA and the GPSA and any other available legal and political processes. The book value of the accounts receivable and long-term account receivable reflects management's assessment of the credit risk.

The Company is exposed to changes in the LIBOR rate on the long-term debt. The Company was exposed to interest rate risk on the interest rate swaps during the year, however, no interest rate swaps are outstanding at March 31, 2009. There were realized losses of US$2.1 million on the settlement of swaps at during the year which was included in the fair value of the interest rate swaps on the balance sheet at March 31, 2008 of US$2.6 million, and therefore, did not affect net income during the year. A gain of $0.5 million in the year was recorded in income for the difference between the fair value of the swaps at March 31, 2008 and the settlement amounts. The fair value of the interest rate swaps at March 31, 2008 was provided by the counterparty using forward LIBOR rates.

The Company is exposed to the risk of changes in market prices of commodities. The Company enters into physical commodity contracts for the sale of natural gas, which manages this risk. The Company does so in the normal course of business including contracts with fixed terms. The contracts are not classified as financial instruments because the Company expects to deliver all required volumes under the contracts. No amounts are recognized in the consolidated financial statements related to the contracts until such time as the associated volumes are delivered. In addition, the Company will be 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 following year, calculated annually, for the D6 gas contracts. This production commenced in April 2009.

CRITICAL ACCOUNTING ESTIMATES

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

Proved Oil and Natural Gas Reserves, Full Cost Accounting, the Ceiling Test and Depletion Expense

The Company follows the full cost method of accounting whereby all costs related to the exploration for and development of oil and natural gas reserves are initially capitalized and accumulated in cost centres by country. Costs capitalized include land and acquisition costs, geological and geophysical expenses, costs of drilling productive and non-productive wells, costs of gathering and production facilities and equipment, and administrative costs related to capital projects. Gains or losses are not recognized upon disposition of oil and natural gas properties unless such disposition would alter the depletion rate by 20 percent or more.

In applying the full cost method, the Company performs a cost recovery test (ceiling test), placing a limit on the carrying value of property and equipment. The carrying value is considered recoverable when the fair value, calculated as the sum of the undiscounted value of future net revenues from proved reserves, the cost of unproved properties and the cost of major development properties, exceeds the carrying value. When the carrying value exceeds the fair value, an impairment loss is recognized to the extent that the carrying value of assets exceeds the net present value, calculated as the sum of the discounted value of future net revenues from proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects. The net present value is estimated using expected future prices and costs and is discounted using a risk-free interest rate.

Independent qualified engineers in conjunction with the Company's reserve engineers estimate the value of oil and natural gas reserves that are used in the depletion and depreciation as well as the ceiling test calculations. This estimation is performed in accordance with the standards set forth in the Canadian Oil and Gas Evaluation Handbook.

The amounts recorded for depletion of exploration and development costs and the carrying value of property and equipment are based on estimates of proved (and in certain circumstances proved plus probable) reserves, production rates, future oil and natural gas prices and future costs, which are all subject to measurement uncertainties and various interpretations. The Company expects that its estimates of reserves and future cash flows, used in the depletion calculation and ceiling test, will be revised upwards or downwards over time, based on future changes to these variables. Reserve estimates and estimates of future cash flows can have a material impact on the depletion expense and the carrying value of property and equipment. Revisions to reserve estimates and future cash flows could increase or decrease depletion expense charged to net income and could result in a write-down of property and equipment based on the ceiling test.

Costs Excluded from the Depletable Base

Costs of acquiring unproved properties are initially excluded from the full cost pool and are assessed quarterly to ascertain whether impairment has occurred. When proved reserves are assigned to the property or the property is considered to be impaired, the cost of the property or the amount of impairment is added to the full cost pool. Costs of major development projects are initially excluded from the full cost pool and are assessed quarterly to ascertain whether impairment has occurred. When a portion of the property becomes capable of commercial production or the property is considered to be impaired, the cost or an appropriate portion of the cost of the property is added to the full cost pool. A change in any of the qualitative considerations for impairment including, but not limited too: geological interpretations; exploration activities and success/failure, the Company's plans with respect to the property and financial ability to hold the property; and the lease term for the property, may result in the inclusion of the property and equipment in the full cost pool, which may result in a significant downwards adjustment to property and equipment and an increase in depletion expense and/or an asset impairment based on the ceiling test resulting in a downwards adjustment to property and equipment and an equivalent expense.

Asset Retirement Obligations

As the Company's assets are retired, significant abandonment and reclamation costs will be incurred. The Company recognizes the fair value of a liability for asset retirement obligations, applicable to all business segments, relating to its long-lived assets in the period in which it is incurred. Specifically, wells are included when they have finished being drilled and facilities are completed and ready for use. The fair value of an asset retirement obligation is recorded as a liability with a corresponding increase in property and equipment. The increase in property and equipment is depleted using the unit-of-production method consistent with the underlying assets. The accretion expense and increases to the asset retirement obligation are recognized each period due to the passage of time. Subsequent to initial measurement, period-to-period changes in the liabilities are recognized for revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Actual costs incurred upon settlement are charged against the asset retirement obligation. Any difference between the actual costs and the recorded liability is recognized as a gain or loss in net income in the period in which settlement occurs.

The obligations are based on factors including current regulations, abandonment costs, technologies, industry standards and obligations in the Company's agreements. The fair value calculation takes into account estimated costs to abandon and reclaim, timing of abandonment, inflation rates and a credit-adjusted risk-free interest rate. Changes in any of the factors and revisions to any of the estimates used in calculating the obligations may result in a material impact to the carrying value of property and equipment, asset retirement obligations and depletion expense charged to net income. The Company expects that its estimates of its asset retirement obligations will be revised upwards or downwards over time, based on future changes to the factors and estimates involved. In addition, the Company expects that its estimates of total asset retirement obligations will increase with the completion of additional wells and facilities that are being developed. Changes to these estimates in the past have resulted in material adjustments to the financial statements.

Income Taxes

The Company follows the tax asset and liability method to account for income taxes. Under this method, future income tax assets and liabilities are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax assets and liabilities is recognized in income in the period that the change occurs. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.

The calculation of the Company's current and future income tax assets and liabilities involves interpretation of complex laws and regulations involving multiple jurisdictions. The Company pays income tax at the highest rate of the jurisdictions in which it operates. This is subject to changing laws and regulations and tax filings are subject to audit and potential reassessment. The Company expects that its estimates of current and future income tax assets and liabilities will be revised upwards or downwards over time, based on changes in the reversal of timing differences, substantively enacted income tax rates, laws and regulations, interpretations of laws and regulations, valuation allowances, reassessment of tax filings and rulings received from tax authorities.

The Company has filed its income tax returns for the years 1998 through 2008 in India, under provisions that provide for a tax holiday for production from the Hazira and Surat fields.

The Company received a favourable ruling with respect to the tax holiday at the third tax assessment level for the 1999 through 2004 taxation years. The Income Tax Department has filed an appeal against the order and the matter is currently pending with the Indian courts. The taxation years 2005 through 2008 have been filed including a deduction for the tax holiday, but have not yet been assessed.

Should the Company fail through the legal process to receive a favourable ruling with respect to the taxation years 1999 through 2005, the Company would record a tax expense of US$31.2 million, pay additional taxes of US$20.9 million and write off US$10.3 million of the income tax receivable. In addition, any failure could result in interest and penalties.

Stock-Based Compensation

The Company uses the fair value method of accounting for its stock-based compensation expense associated with its stock option plan. Compensation expense is based on the fair value of stock options at the grant date using the Black-Scholes option-pricing model. The Black-Scholes model requires estimates for the expected volatility of the Company's stock, a risk-free interest rate, expected dividends on the stock, expected forfeitures and expected life of the option. Changes in these estimates may result in the actual compensation expense being materially different from the compensation expense recognized; however, this expense is not subsequently adjusted for changes in these factors. The Company capitalizes the stock-based compensation expense relating to those employees whose time is spent on exploration activities.

Accrual Accounting

The Company follows the accrual method of accounting, making estimates in its financial and operating results. This may include estimates of revenue, royalties, operating and other expenses and capital items related to the period being reported, for which actual results have not yet been received. The estimates are prepared for individual properties and individual locations. The Company expects that its accrual estimates will be revised, upwards or downwards, based on the receipt of actual results.

Financial Instruments

Financial instruments of the Company consist of cash, restricted cash, cash call advances, short-term investments, accounts receivable, accounts payable and accrued liabilities, long-term accounts receivable and long-term debt. As at March 31, 2009 and March 31, 2008, there were no significant differences between the carrying amounts of these instruments and the fair values.

The fair values of the accounts receivable and accounts payable and accrued liabilities approximate their carrying values due to their near-term maturity. Inability by the Company to settle these assets and liabilities in the near term may result in a significant downward or upward adjustment to the fair values and an associated expense.

The fair value of short-term investments is based on publicly quoted market values. The Company expects the market values of the short-term investments to increase or decrease over time and may result in a significant upward or downward adjustment to the fair values and an associated expense.

The fair value of the long-term account receivable has been calculated using a discount rate of 6.5 percent and assumes collection in three years. A change in the amount of the receivable that is considered collectible, the discount rate or timing of collection may result in a significant downward or upward adjustment to the fair value and an associated income or expense item.

The Company's interest rate swaps are recorded at fair value, which has been provided by a third party using a forward LIBOR curve applied to future settlements. The Company expects changes in the forward LIBOR rates to result in significant downward or upward adjustments to the fair value of the instrument and an associated income or expense item.

Legal, Environmental and Other Contingent Matters

The Company is required to determine whether a loss is likely, unlikely or not determinable based on judgement and interpretations of laws and regulations and, if likely, to determine whether the loss can reasonably be estimated. When the loss is likely and the amount of the loss is determinable, it is charged to net income. The Company monitors known and potential contingent matters and makes appropriate provisions by charges to net income when warranted by circumstances. Changes in factors used to make judgement and interpret laws and regulations may result in the change in likelihood of a contingent matter or allow the Company to determine the amount of the loss of a contingent matter resulting in a significant downward adjustment to a recorded asset or the recognition of a significant liability and associated expense.

ACCOUNTING CHANGES IN FISCAL 2009

Effective April 1, 2008, the Company adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants (CICA): Section 1535 "Capital Disclosures", Section 3862 "Financial Instruments - Disclosures", Section 3863 "Financial Instruments - Presentation" and Section 3031 "Inventories". For a discussion of the effects of adopting these new accounting standards, please refer to the notes to the Company's consolidated financial statements for the year ended March 31, 2009, available at www.sedar.com.

FUTURE ACCOUNTING CHANGES

Effective April 1, 2009, the Company will adopt the new accounting standard issued by the CICA, Section 3064 "Goodwill and Intangible Assets", replacing Sections 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". Adoption of this section is not expected to have a material impact on the Company's consolidated financial statements.

Effective April 1, 2011, the Company will replace current Canadian accounting standards and interpretations, or GAAP, with International Financial Reporting Standards (IFRS) as required by the Canadian Accounting Standards Board. The employees of the Company participated in continuing education courses during the year and consulted with a peer group to discuss implementation issues. The Company is currently reviewing the existing IFRS policies used by the Company's foreign subsidiaries and assessing the differences between the Company's current accounting policies and IFRS for the Company's subsidiaries that do not report under IFRS. Subsequently, the Company will develop a plan for adoption. The exemptions available to first-time adopters of IFRS under the IFRS1 standard will not be available to the Company's foreign subsidiaries that already prepare IFRS-compliant 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 Canadian GAAP.

Because of their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, errors or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

There were no changes in the internal controls over financial reporting during the year ended March 31, 2009 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

RISK FACTORS

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

- The Company may not be able to find reserves at a reasonable cost, develop reserves within required time-frames or at a reasonable cost, or sell these reserves for a reasonable profit;

- Reserves may be revised due to economic and technical factors;

- The Company may not be able to obtain approval, or obtain approval on a timely basis, for exploration and development activities;

- Changing governmental policies, social instability and other political, economic or diplomatic developments in the countries in which the Company operates;

- Changing taxation policies, taxation laws and interpretations thereof;

- Changes in the timing of future debt repayments based on provisions in the Company's loan agreement;

- Adverse factors including climate and geographical conditions, weather conditions and labour disputes;

- Changes in foreign exchange rates that in turn change the Company's future recorded revenues and expenses as the majority of sales and expenses are denominated in U.S. dollars; and

- Changes in future oil and natural gas prices.

For a comprehensive discussion of all identified risks, refer to the Company's Annual Information Form, which can be found at www.sedar.com.

The Company has a number of contingencies as at March 31, 2009. 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 22, 2009, the Company had the following outstanding shares:



Number Cdn$ Amount(1)
----------------------------------------------------------------------------
Common shares 49,595,008 $ 1,198,229,000
Preferred shares nil nil
Stock options 3,865,625 -
----------------------------------------------------------------------------
(1) This is the dollar amount received for common shares issued excluding
share issue costs and is presented in Canadian dollars. The U.S. dollar
equivalent at June 22, 2009 is US$1,046,709,000.


OUTLOOK

In addition to the significant increase in forecasted sales volumes for fiscal 2010 compared to fiscal 2009, we expect to receive approval for the development of the D6 satellite fields and the NEC-25 discoveries.

We will also actively explore in the coming year. Seismic and drilling activity is planned in multiple blocks. It will be the largest program in the Company's history.

On behalf of the Board of Directors,

Edward S. Sampson, Chairman of the Board, President and Chief Executive Officer

June 22, 2009



CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------
(THOUSANDS OF U.S. DOLLARS)

As at As at
March 31, 2009 March 31, 2008

ASSETS
Current assets
Cash and cash equivalents (note 19) $ 31,189 $ 443,889
Restricted cash (note 4, 19) 185,475 -
Short-term investment (note 19) 9,067 17,240
Accounts receivable (note 19) 20,287 14,402
Inventory (note 3) 616 -
Prepaid expenses 1,494 2,113
----------------------------------------------------------------------------
248,128 477,644
----------------------------------------------------------------------------
Restricted cash (note 4) 24,011 129,923
Cash call advances (note 5, 19) 103 23,523
Long-term investment (note 6) 4,216 -
Long-term accounts receivable (note 7a, 19) 22,098 20,850
Income tax receivable (note 7b) 16,000 36,514
Property and equipment (note 8) 1,154,074 628,533
----------------------------------------------------------------------------
$ 1,468,630 $ 1,316,987
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities
(note 19) $ 119,555 $ 16,499
Current portion of capital lease obligation
(note 23) 10,752 -
Current tax payable 2,691 3,104
----------------------------------------------------------------------------
132,998 19,603
----------------------------------------------------------------------------
Asset retirement obligation (note 9) 27,544 9,107
Capital lease obligation (note 23) 57,984 -
Long-term debt (note 10, 19) 192,814 192,814
----------------------------------------------------------------------------
411,340 221,524
----------------------------------------------------------------------------
Shareholders' equity
Share capital (note 11) 1,001,885 986,050
----------------------------------------------------------------------------
Contributed surplus (note 12) 51,966 34,952
----------------------------------------------------------------------------
Accumulated other comprehensive income
(loss) (note 13) (2,406) 40,989
Retained earnings 5,845 33,472
----------------------------------------------------------------------------
3,439 74,461
----------------------------------------------------------------------------
1,057,290 1,095,463
----------------------------------------------------------------------------
$ 1,468,630 $ 1,316,987
----------------------------------------------------------------------------
----------------------------------------------------------------------------

U.S. dollar reporting (note 1)
Segmented information (note 17)
Capital management (note 18)
Guarantees (note 20)
Economic dependence (note 21)
Related-party transactions (note 22)
Commitments and contractual obligations (note 23)
Contingencies (note 24)

See accompanying Notes to Consolidated Financial Statements.


CONSOLIDATED STATEMENTS OF
OPERATIONS AND RETAINED EARNINGS
----------------------------------------------------------------------------
(THOUSANDS OF U.S. DOLLARS, EXCEPT PER SHARE AMOUNTS)

Years ended March 31, 2009 2008

Revenue
Oil and natural gas $ 104,993 $ 101,006
Royalties (4,801) (5,037)
Profit petroleum (22,863) (24,462)
Interest and other 11,649 22,307
----------------------------------------------------------------------------
88,978 93,814
----------------------------------------------------------------------------

Expenses
Operating and pipeline 12,367 10,682
Interest and financing on capital lease
(note 23) 1,498 -
General and administrative 7,125 7,051
Foreign exchange (gain) loss (8,104) 8,272
Discount of long-term account receivable
(note 7a, 19) 265 4,434
Stock-based compensation (note 11) 18,989 16,927
Loss (gain) on short-term investment (note 19) 24,380 (1,418)
Equity loss on long-term investment (note 6) 982 -
Impairment of long-term investment (note 6) 4,186 -
Loss (gain) on risk management contracts
(note 19) (494) 2,065
Asset impairment (note 14) 1,258 23,377
Depletion, depreciation and accretion 44,029 40,577
----------------------------------------------------------------------------
106,481 111,967
----------------------------------------------------------------------------
(Loss) before income taxes (17,503) (18,153)

Current income tax expense 5,059 1,862
----------------------------------------------------------------------------

Net (Loss) (22,562) (20,015)

Retained earnings, beginning of year 33,472 59,121
Dividends paid (5,065) (5,634)
----------------------------------------------------------------------------
Retained earnings, end of year $ 5,845 $ 33,472
----------------------------------------------------------------------------

Net (Loss) per share (note 16)
Basic and diluted $ (0.46) $ (0.43)
----------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.


CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME (LOSS)
----------------------------------------------------------------------------
(THOUSANDS OF U.S. DOLLARS)

Years ended March 31, 2009 2008
Net (loss) $ (22,562) $ (20,015)
Other comprehensive income (loss):
Recognition of fair value of derivative (loss) - (541)
Foreign currency translation gain (loss) (43,395) 36,304
----------------------------------------------------------------------------
Comprehensive income (loss) (note 13) $ (65,957) $ 15,748
----------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.


CONSOLIDATED STATEMENTS OF CASH FLOWS
----------------------------------------------------------------------------
(THOUSANDS OF U.S. DOLLARS)

Years ended March 31, 2009 2008
Cash provided by (used in):
Operating activities
Net (loss) $ (22,562) $ (20,015)
Add items not involving cash from operations:
Unrealized foreign exchange (gain) loss (4,784) 8,149
Discount of long-term account receivable 265 4,434
Stock-based compensation 18,989 16,927
Unrealized loss (gain) on short-term
investment 24,380 (1,418)
Equity loss on long-term investment 982 -
Impairment loss on long-term investment 4,186 -
Unrealized loss (gain) on risk management
contracts (494) 2,065
Asset impairment 1,258 23,377
Depletion, depreciation and accretion 44,029 40,577
Change in non-cash working capital (5,792) 1,928
Change in long-term accounts receivable 11,480 (16,085)
----------------------------------------------------------------------------
71,937 59,939
----------------------------------------------------------------------------
Financing activities
Proceeds from issuance of shares, net of
issuance costs (note 11) 11,614 492,650
Long-term debt - 192,814
Dividends paid (5,065) (5,634)
----------------------------------------------------------------------------
6,549 679,830
----------------------------------------------------------------------------
Investing activities
Addition of property and equipment (481,936) (334,493)
Reduction in capital lease obligations (1,111) -
Restricted cash contributions (103,914) (163,122)
Restricted cash returned 24,351 44,051
Addition to short-term investment (19,927) (16,261)
Addition to long-term investment (11,378) -
Change in non-cash working capital 103,795 (31,988)
Change in cash call advances 23,421 -
----------------------------------------------------------------------------
(466,699) (501,813)
----------------------------------------------------------------------------
(Decrease) increase in cash (388,213) 237,956
Effect of foreign currency translation on
cash and cash equivalents (24,487) 24,330
Cash and cash equivalents, beginning of year 443,889 181,603
----------------------------------------------------------------------------
Cash and cash equivalents, end of year $ 31,189 $ 443,889
----------------------------------------------------------------------------

Supplemental information:
Interest paid $ 8,245 $ 2,097
Taxes paid $ 5,281 $ 13,374
----------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the year ended March 31, 2009.

All tabular amounts are in thousands of U.S. dollars except per share amounts, numbers of shares/stock options, stock option and share prices, and certain other figures as indicated.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Basis of Presentation

The consolidated financial statements include the accounts of Niko Resources Ltd. ("the Company") and all of its subsidiaries. Substantially all of the exploration and production activities of the Company are conducted jointly with others and, accordingly, these consolidated financial statements reflect only the Company's proportionate interest in such activities.

Effective March 31, 2009, the Company adopted the U.S. dollar as its reporting currency. The change is attributable to the fact that the Company's transactions are conducted primarily in U.S. dollars. In making this change in reporting currency, the Company followed the recommendations of the Emerging Issues Committee (EIC) of the Canadian Institute of Chartered Accountants set out in EIC-130, "Translation Method When the Reporting Currency Differs from the Measurement Currency or there is a Change in the Reporting Currency". Financial statements for all periods presented have been translated from Canadian dollars into U.S. dollars using the current rate method. Using this method, consolidated assets and liabilities have been translated using the exchange rate at the balance-sheet dates, while shareholders' equity has been translated using the historical rates of exchange in effect on the dates of the corresponding transactions. The consolidated statements of operations and retained earnings and consolidated statements of cash flows have been translated using the average exchange rates for the periods. Any resulting exchange rate differences due to this translation are included in shareholders' equity as accumulated other comprehensive income. All comparative financial information being presented has been restated to reflect the Company's financial statements as if they had been historically reported in U.S. dollars and the effect on the consolidated financial statements resulted in an accumulated other comprehensive income adjustment of US$36.3 million for the year ended March 31, 2008. These consolidated financial statements are reported in U.S. dollars and have been prepared in accordance with Canadian generally accepted accounting principles.

Certain comparative figures have been reclassified to conform to the current year's presentation and to conform to a U.S. dollar reporting currency.

(b) Cash and Cash Equivalents

Cash and cash equivalents consists of cash and demand deposits.

(c) Short-Term Investments

Short-term investments consist of marketable securities. The short-term investment was designated as held for trading upon initial recognition. See note 1® for a description of the accounting policy.

(d) Inventory

Inventories consist of oil and condensate, which are recorded at the lower of cost and net realizable value. Cost is comprised of operating expenses that have been incurred in bringing inventories to their present location and condition and the portion of depletion expense associated with the oil and condensate production. Net realizable value is the estimated selling price in the ordinary course of business less applicable variable selling expenses.

(e) Long-Term Investments

The Company's long-term investment is accounted for using the equity method whereby the investment is initially recorded at cost and the carrying value is subsequently adjusted to include the Company's pro rata share of post-acquisition earnings of the investee.

(f) Property and Equipment

The Company follows the full cost method of accounting whereby all costs related to the exploration for and development of oil and natural gas reserves are initially capitalized and accumulated in cost centres by country. Costs capitalized include land and acquisition costs, geological and geophysical expenses, costs of drilling productive and non-productive wells, costs of gathering and production facilities and equipment, and administrative costs related to capital projects. Gains or losses are not recognized upon disposition of oil and natural gas properties unless such disposition would alter the depletion rate by 20 percent or more.

In applying the full cost method, the Company performs a cost recovery test (ceiling test), placing a limit on the carrying value of property and equipment. If the carrying value exceeds the fair value, an impairment loss is recognized to the extent that the carrying value of assets exceeds the net present value, calculated as the sum of the discounted value of future net revenues from proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects. The net present value is estimated using expected future prices and costs and is discounted using a risk-free interest rate.

(g) Capitalized Interest

Interest costs on major capital projects are capitalized until the projects are capable of commercial production. These costs are subsequently amortized with the related assets.

(h) Asset Retirement Obligations

The Company recognizes the fair value of the liabilities for asset retirement obligations related to its long-lived assets in the period in which they are incurred. The fair value of an asset retirement obligation is recorded as a liability with a corresponding increase in property and equipment. The increase in property and equipment is depleted using the unit-of-production method consistent with the underlying assets. The accretion expense for increases to the asset retirement obligations due to the passage of time are recognized at the end of each period. Subsequent to initial measurement, period-to-period changes in the liabilities are recognized for revisions to either the timing or the amount of the original estimates of undiscounted cash flows. Actual costs incurred upon settlement are charged against the asset retirement obligations. Any difference between the actual cost and the recorded liability is recognized as a gain or loss in net income in the period in which settlement occurs.

(i) Lease

Leases are classified as either capital or operating in nature. Capital leases are those that transfer substantially all of the benefits and risks of ownership related to the leased property from the lessor to the lessee. Assets acquired under capital leases are depleted along with the petroleum and natural gas properties. Obligations recorded under capital leases are reduced by the principal portion of lease payments as incurred and the imputed interest portion of capital lease payments is charged to expense. Operating leases are those where the benefits and risks of ownership related to the lease property are substantially retained by the lessor. Operating lease payments are charged to expense.

(j) Comprehensive Income

Comprehensive income consists of net income and other comprehensive income (OCI). OCI comprises the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge, the change in fair value of any available-for-sale financial instruments and foreign exchange gains or losses arising from the translation of Canadian operations using the current rate method to U.S. dollars. Amounts included in OCI are shown net of tax. Accumulated other comprehensive income is an equity category comprised of the cumulative amounts of OCI.

(k) Revenue Recognition

Sales of crude oil, natural gas and natural gas liquids are recorded in the period in which the title to the petroleum transfers to the customer. Crude oil and natural gas liquids produced and stored by the Company, but unsold, are recorded as inventory until sold.

(l) Depletion and Depreciation

Costs of acquiring unproved properties are initially excluded from the full cost pool and are assessed quarterly to ascertain whether impairment has occurred. When proved reserves are assigned to the property or the property is considered to be impaired, the cost of the property or the amount of impairment is added to the full cost pool. Costs of major development projects are initially excluded from the full cost pool and are assessed quarterly to ascertain whether impairment has occurred. When a portion of the property becomes capable of production or the property is considered to be impaired, the cost or an appropriate portion of the cost of the property is added to the full cost pool.

Costs capitalized, including capital leases, are depleted using the unit-of-production method by cost centre based upon gross proved oil and natural gas reserves as determined by independent engineers and updated internally as applicable. For purposes of the calculation, oil and natural gas reserves are converted to a common unit of measure on the basis of their relative energy content.

Office and other equipment is depreciated using the declining balance method at rates of 20 to 30 percent per annum.

(m) Foreign Currency

The Company's Canadian operations have the Canadian dollar as their functional currency and, as the Company reports its results in U.S. dollars, it therefore uses the current rate method of foreign currency translation. Under the current rate method, accounts are translated to U.S. dollars from their Canadian dollar functional currency as follows: assets and liabilities are translated at the exchange rate in effect at the balance sheet date, and revenues and expenses are translated at the average exchange rate for the period. Gains and losses resulting from the translation of Canadian operations to U.S. dollars are included in the foreign currency translation account within other comprehensive income.

Transactions in foreign currencies, other than the U.S. dollar, are translated at rates in effect at the time of the transaction and any resulting gains and losses are included in net income.

(n) Income taxes

The Company follows the tax asset and liability method to account for income taxes. Under this method, future income tax assets and liabilities are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax assets and liabilities is recognized in income in the period that the change occurs. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.

(o) Measurement Uncertainty

The preparation of the consolidated financial statements in conformity with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. By their nature, these estimates are subject to measurement uncertainty and actual results may differ from those estimated.

The most significant estimates made by management relate to amounts recorded for the depletion of property and equipment, the provision for the asset retirement obligation, accretion expense, the ceiling test, stock-based compensation expense and the fair value of long-term accounts receivable. The ceiling test calculation and the provisions for depletion and asset retirement obligations are based on such factors as estimated proved reserves, production rates, petroleum and natural gas prices and future costs. Stock-based compensation is based on such factors as the risk-free interest rate, volatility, expected life, expected dividends and expected forfeiture rates. The fair value of the long-term account receivable is based on a discount rate and timing of collection. Future events could result in material changes to the carrying values recognized in the financial statements.

(p) Per Share Amounts

Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding during the year. Diluted per share amounts reflect the potential dilution that could occur if options to purchase common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and any other dilutive instrument.

(q) Stock-based Compensation Plans

The Company has a stock-based compensation plan as described in note 11. Compensation expense associated with the plan is calculated and recognized in net income or capitalized over the vesting period of the plan with a corresponding increase in contributed surplus. Compensation expense is based on the fair value of the stock options at the grant date using the Black-Scholes option-pricing model. Any consideration received upon exercise of the stock options, together with the amount previously recognized in contributed surplus, is recorded as an increase to share capital. The Company has not incorporated an estimated forfeiture rate for stock options that will not vest; rather, the Company accounts for actual forfeitures as they occur.

(r) Financial Instruments

Financial instruments are initially recognized at fair value on the balance sheet date. The Company has classified each financial instrument into the following categories: held for trading financial assets and liabilities; loans and receivables; held to maturity investments; available-for-sale financial assets; and other financial liabilities. Subsequent measurement of the financial instruments is based on their classification.

Transaction costs on financial assets and liabilities classified other than as held for trading are added to the fair value upon initial recognition.

Unrealized gains and losses on held for trading financial instruments are recognized in net income.

Gains and losses on available-for-sale financial assets are recognized in other comprehensive income and transferred to net income when the asset is derecognized or impaired. The other categories of financial instruments are recognized at cost using the effective interest rate method.

The Company designated its accounts receivable and long-term accounts receivable as loans and receivables, which are measured at amortized cost and cash, restricted cash and cash call advances as held for trading. Upon initial recognition, the Company elected to designate short-term investments as held for trading. The Company accounts for regular-way purchases and sales of financial assets at the trade date.

Long-term debt, accounts payable and accrued liabilities are classified as other financial liabilities, which are measured at amortized cost. The Company has no available-for-sale financial instruments.

Hedges:

The Company may enter into derivative instrument contracts to manage its commodity price exposure, foreign exchange exposure and interest rate exposure. The Company does not enter into derivative instrument contracts for trading or speculative purposes. The Company may choose to designate derivative instruments as hedges.

Hedge accounting requires the designation of a hedging relationship, including a hedged and a hedging item, identification of the risk exposure being hedged and reasonable assurance that the hedging relationship will be effective throughout its term. In addition, in the case of anticipated transactions, it must also be probable that the transaction designated as being hedged will occur.

The Company assesses, both at inception and over the term of the hedging relationship, whether the derivative contracts used in the hedging transactions are highly effective in offsetting changes in the fair value or cash flows of hedged items. If a derivative contract ceases to be effective or is terminated, hedge accounting is discontinued. Any gains or losses previously recognized in other comprehensive income as a result of applying hedge accounting continue to be carried forward to be recognized in net income in the same period as the hedged item.

For cash flow hedges, changes in the fair value of a financial instrument designated as a cash flow hedge are recognized in net income in the same period as the hedged item. The effective portion of any fair value change in the financial instrument is recognized in other comprehensive income and the ineffective portion of any fair value change is recognized in net income.

For fair value hedges, both the financial instrument designated as a fair value hedge and the underlying commitment are recognized on the balance sheet at fair value. Changes in fair value of both are reflected according to their nature, typically in net income.

For net investment hedges, the portion of the gain or loss on the hedging item that is determined to be an effective hedge is recognized in other comprehensive income and the ineffective portion of the gain or loss on the hedging item is recognized in net income.

The Company enters into physical commodity contracts in the normal course of business including contracts with fixed terms. No amounts are recognized in the consolidated financial statements related to the contracts until such time as the associated volumes are delivered.

2. CHANGES IN ACCOUNTING POLICIES

(a) Accounting changes during the year

Effective April 1, 2008 the Company adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants (CICA): Section 1535 "Capital Disclosures", Section 3862 "Financial Instruments - Disclosures", Section 3863 "Financial Instruments - Presentation" and Section 3031 "Inventories". These new standards were adopted prospectively. Adoption of these standards did not impact April 1, 2008 opening balances.

Section 1535 specifies the disclosure of information about an entity's objectives, policies and processes for managing capital; quantitative data about what the entity regards as capital; whether the entity has complied with any externally imposed capital requirements; and if it has not complied, the consequences of non-compliance.

Sections 3862 and 3863 specify the standards of presentation and enhanced disclosures on financial instruments, particularly with respect to the nature and extent of risks arising from financial instruments and how the entity manages those risks.

Section 3031 replaces the existing inventories standard. The new standard provides additional guidance with respect to the measurement and disclosure requirements for inventories and requires inventories to be valued at the lower of cost and net realizable value. This section became applicable during the current reporting year with the commencement of production from the MA field in the D6 Block.

(b) Future accounting changes

Effective April 1, 2009, the Company will adopt the new accounting standard, Section 3064 "Goodwill and Intangible Assets", issued by the CICA, replacing Sections 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". Section 3062 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. Adoption of this section is not expected to have a material impact on the Company.

Effective for fiscal years beginning on or after January 1, 2011, the Company will be required to report under International Financial Reporting Standards, which will replace Canadian generally accepted accounting principles. At this time, the impact on the Company's consolidated financial statements is not determinable.

3. INVENTORY

The cost of the inventory sold during the year ended March 31, 2009 was US$3.1 million.

The Company wrote-down the oil inventory from the D6 property to net realizable value during the year, resulting in a total carrying value for all properties at March 31, 2009 of US$0.6 million. The US$0.3 million write-down has been recognized in income as an operating expense.

4. RESTRICTED CASH

The restricted cash balance included in current assets at March 31, 2009 includes US$185.5 million that is restricted as per provisions of the credit facility (March 31, 2008 - nil). The cash may be used to fund development costs for Hazira, Surat, and D6 Blocks in India and Block 9 in Bangladesh and the costs of operating the Hazira, Surat, Block 9 and the Dhirubhai 1 and 3 gas fields of the D6 Block including amounts included in accounts payable and accrued liabilities and amounts to be incurred in the upcoming year. The current portion of restricted cash will become unrestricted once the Dhirubhai 1 and 3 gas field project is complete as defined in the credit facility.

The restricted cash balance included in non-current assets includes guarantees of US$13.5 million (March 31, 2008 - US$16.4 million) (see note 20), US$3.5 million (March 31, 2008 - US$2.1 million) of cash that is legally restricted for future site restoration in India (see note 9) and US$7.0 million that is restricted as per provisions of the credit facility and will continue to be restricted after the Dhirubhai 1 and 3 gas field project is complete as defined in the credit facility (March 31, 2008 - US$111.5 million). Subsequent to project completion, cash will continue to be restricted in the amount of a debt service reserve account and a provision for up to 45 days of capital and operating costs for Hazira, Surat, Block 9 and the D6 Block.

5. CASH CALL ADVANCES

Cash call advances are funds that have been advanced to joint venture partners, where the joint venture partner is operator of the property, as per cash call requests for capital and/or operating expenses that have not been spent by the operator as at the balance sheet date. Although the Company has the right to request the return of funds that have been advanced and not spent on capital and/or operating expenses, the Company generally leaves the funds with the operator when there are forecast expenditures to which they will be applied subsequent to the end of the year. The cash call advances will be transferred to property and equipment and/or operating expenses as these costs are incurred by the operator.

6. LONG-TERM INVESTMENT

The long-term investment is in shares of a company trading on the TSX Venture Exchange, Vast Exploration Inc. The initial cost recorded was Cdn$11.6 million (US$11.4 million). An equity loss of Cdn$1.1 million (US$1.0 million) was recognized during the year ended March 31, 2009. The Company determined that the investment was impaired during the year and wrote the value of the investment down to the book value of the investee's net assets. This resulted in a carrying value for the investment of Cdn$5.3 million (US$4.2 million) at March 31, 2009. The market value of the long-term investment at March 31, 2009 was Cdn$5.1 million (US$4.1 million).

7. LONG-TERM ACCOUNTS RECEIVABLE

(a) Long-term account receivable: The long-term account receivable balance consists of gas sales charged to the Bangladesh Oil, Gas and Mineral Corporation (Petrobangla) for production from the Feni field in Bangladesh.

The Company commenced production from the Feni field in November 2004 and has made gas deliveries to Petrobangla since that time. The Company formalized a Gas Purchase and Sales Agreement (GPSA) in the year ended March 31, 2007 at a price of US$1.75 per Mcf.

Payment of the receivable is being delayed as a result of various claims raised against the Company, which are described in note 24 (a) and (b). Although the Company expects to collect the full amount of the receivable, the timing of collection is uncertain as the Company may not collect the receivable until resolution of the various claims raised against the Company. As a result, the receivable has been classified as long-term and discounted using a risk-adjusted rate to reflect the potential delay in collection of these amounts.

(b) Income tax receivable: The income tax receivable balance results from advances made to the tax authority in India in excess of the original tax filing. While no assurance can be given, the Company believes it will be successful on appeal and the tax authority will refund these advances. See further discussion in note 24 (e).

8. PROPERTY AND EQUIPMENT



----------------------------------------------------------------------------
Accumulated
(thousands of U.S. dollars) Depletion and
As at March 31, 2009 Cost Depreciation Net Book Value
----------------------------------------------------------------------------
Oil and natural gas
Bangladesh $ 206,277 $ 67,610 $ 138,667
India(1) 1,116,384 171,503 944,881
Indonesia 15,896 - 15,896
Kurdistan 24,597 18 24,579
Madagascar 4,393 - 4,393
Pakistan 22,874 11 22,863
All other 5,106 2,311 2,795
----------------------------------------------------------------------------
$ 1,395,527 $ 241,453 $ 1,154,074
----------------------------------------------------------------------------

(1) India property and equipment includes a capital lease for the floating,
production, storage and offloading vessel (FPSO) which had a cost of
US$71.4 million, accumulated depletion of US$2.7 million and a net book
value of US$68.7 million.

----------------------------------------------------------------------------
Accumulated
(thousands of U.S. dollars) Depletion and
As at March 31, 2008 Cost Depreciation Net Book Value
----------------------------------------------------------------------------
Oil and natural gas
Bangladesh $ 191,602 $ 46,608 $ 144,994
India 628,779 149,668 479,111
Indonesia - - -
Kurdistan - - -
Madagascar - - -
Pakistan - - -
All other 6,580 2,152 4,428
----------------------------------------------------------------------------
$ 826,961 $ 198,428 $ 628,533
----------------------------------------------------------------------------


During the year ended March 31, 2009, the Company expensed costs of US$1.3 million that were previously capitalized for new ventures (year ended March 31, 2008 - US$21.7 million that were previously capitalized in Thailand and US$0.6 million for new ventures). See note 14.

During the year ended March 31, 2009, the Company capitalized US$1.5 million of general and administrative expenses, US$2.3 of stock-based compensation expense and US$11.0 million of financing charges (year ended March 31, 2008 - US$1.3 million of general and administrative expenses, US$2.1 million of stock-based compensation expense and US$13.5 million of financing charges).

Total costs of US$797.2 million (March 31, 2008 - US$448.4 million) have been excluded from costs subject to depletion and depreciation as at March 31, 2009. This is comprised of US$727.2 million (March 31, 2008 - US$445.1 million) associated with the Company's undeveloped properties and major development projects in India; US$15.9 million associated with the Company's undeveloped properties in Indonesia; US$24.6 million associated with the Company's undeveloped property in Kurdistan; US$22.9 million associated with the Company's undeveloped properties in Pakistan; US$4.4 million associated with the Company's undeveloped property in Madagascar; and US$2.2 million (March 31, 2008 - US$3.3 million) associated with the Company's new ventures.

At March 31, 2009, the Company performed ceiling tests for the relevant portion of the Indian, Bangladeshi and Canadian cost centres to assess the recoverable value. The natural gas prices used in the ceiling tests were based on contracts entered into by the Company and forecast future contract prices. The future oil and condensate prices for the D6 Block and Hazira Field in India and Block 9 in Bangladesh were based on the April 1, 2009 commodity price forecast relative to Brent blend prices of the Company's independent reserve evaluators and were adjusted for commodity price differentials specific to the Company, being 90% of Brent Blend for the D6 Block, 95% of Brent Blend for the Hazira Field and 105% of Brent Blend for Block 9. The future condensate price for Feni was based on the current billing rate of US$40.00/bbl. The Company's independent reserve evaluators use a calendar year commodity price forecast. As a result, the Company's commodity price forecast for the fiscal period is a weighted average of the calendar year prices. The future oil price for Canada was based on the March 2009 actual selling price as an independent reserve evaluation was not performed due to the small size of the Canadian operations relative to the size of the Company. The Canadian operations accounted for less than 1 percent of sales for the year ended March 31, 2009. The table below summarizes the benchmark and forecast prices used in the ceiling test calculation:



India
Benchmark India Forecast
Price (Brent Forecast Oil Condensate
Year ending Blend) Year ending Price Price
December 31, (US$/bbl) March 31, (US$/bbl) (US$/bbl)
----------------------------------------------------------------------------
2009 53.39 2010 51.21 52.46
2010 63.37 2011 58.03 58.27
2011 68.36 2012 62.18 62.24
2012 72.36 2013 65.24 66.60
2013 75.35 2014 - 68.65
Thereafter 87.88 Thereafter - 78.66
----------------------------------------------------------------------------

Bangladesh India Bangladesh
Forecast Forecast Forecast
Condensate Natural Gas Natural Gas
Year ending Price Price Price
March 31, (US$/bbl) (US$/Mcf) (US$/Mcf)
----------------------------------------------------------------------------
2010 58.24 5.17 2.31
2011 67.83 4.68 2.33
2012 72.76 4.52 2.33
2013 76.67 4.31 2.33
2014 80.05 4.19 2.33
Thereafter 91.77 7.08 2.33
----------------------------------------------------------------------------


9. ASSET RETIREMENT OBLIGATIONS

The asset retirement obligations relate to the future site restoration and abandonment costs including the costs of production equipment removal and environmental cleanup based on regulations and economic circumstances at March 31, 2009.

The following table reconciles the Company's asset retirement obligations as at March 31 of each fiscal year:



(thousands of U.S. dollars)
Years ended March 31, 2009 2008
----------------------------------------------------------------------------
Obligation, beginning of year $ 9,107 $ 7,725
Obligations incurred 17,735 1,191
Obligations settled - (60)
Revision in estimated cash flows - (362)
Accretion expense 717 593
Foreign currency translation (15) 20
----------------------------------------------------------------------------
Obligation, end of year $ 27,544 $ 9,107
----------------------------------------------------------------------------


The Company has estimated the fair value of its total asset retirement obligations based on estimated future undiscounted liabilities of US$73.8 million. The inflation rates used in calculating the fair value were 4.5 percent for Indian properties, 7 percent for Bangladeshi properties and 2 percent for Canadian properties of the asset retirement obligations. The costs are expected to be incurred between 2011 and 2026. A credit-adjusted risk-free interest rate of 7 percent was used in the fair value calculation to discount future costs.

Indian regulations require a separate, restricted bank account to be funded over time to fund the costs of asset retirement obligations. The fair value of assets that are legally restricted for purposes of settling asset retirement obligations is estimated at US$3.5 million as at March 31, 2009 (March 31, 2008 - US$2.1 million).

10. LONG-TERM DEBT

In November 2007, the Company executed a facility agreement for its US$550 million credit facility. In April 2009, the facility was reduced to US$192.8 million. At March 31, 2009, the Company has drawn US$192.8 million on the loan.

Interest was at LIBOR plus 1.7 percent during the year ended March 31, 2009. In April 2009, the facility was amended resulting in an interest rate on the debt of LIBOR plus 4.0 percent. During the year ended March 31, 2009, the Company capitalized interest expense of US$8.3 million (year ended March 31, 2008 - US$2.6 million). During the year ended March 31, 2009, the Company capitalized commitment fees of US$2.1 million (year ended March 31, 2008 - US$1.0 million).

The Company is required to make U.S. dollar repayments of the outstanding balance if the loan exceeds the amount specified in a reduction schedule or in order to bring financial coverage ratios within specified limits. The facility will expire on September 30, 2011. See further discussion of repayment in note 19. The amended facility is secured by a debt service reserve account and the assets of the D6 Block, Hazira Field, and Surat Block in India and Block 9 in Bangladesh.

In April 2009, the amendment to the credit facility resulted in the Company's ability to use restricted cash to fund development costs for Hazira, Surat, and D6 Blocks in India and Block 9 in Bangladesh and the costs of operating the Hazira, Surat, Block 9 and the Dhirubhai 1 and 3 gas fields of the D6 Block.



11. SHARE CAPITAL

(a) Authorized

Unlimited number of common shares

Unlimited number of preferred shares

(b) Issued
Year ended Year ended
March 31, 2009 March 31, 2008
----------------------------------------------------------------------------
Amount Amount
Common shares Number (US$) Number (US$)
----------------------------------------------------------------------------
Balance, beginning of year 49,054,408 986,050 42,994,820 486,077
Equity offering - - 4,762,000 453,534
Stock options exercised 243,725 11,615 1,297,588 39,115
Transferred from contributed
surplus on exercise - 4,220 - 7,324
----------------------------------------------------------------------------
Balance, end of year 49,298,133 1,001,885 49,054,408 986,050
----------------------------------------------------------------------------


(c) Stock Options

The Company has reserved for issue 4,929,813 common shares for granting under stock options to directors, officers, and employees. The options become 100 percent vested one to four years after the date of grant and expire two to five years after the date of grant. Stock option transactions for the respective periods were as follows:



Year ended Year ended
March 31, 2009 March 31, 2008
----------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price (Cdn$) Options Price (Cdn$)
----------------------------------------------------------------------------
Outstanding, beginning
of year 3,219,725 65.02 3,753,250 47.06
Granted 1,368,313 60.33 838,563 92.09
Forfeited (18,250) 83.11 (74,500) 64.07
Expired (295,313) 58.39 - -
Exercised (243,725) 50.85 (1,297,588) 30.61
----------------------------------------------------------------------------
Outstanding, end of
year 4,030,750 64.69 3,219,725 65.02
----------------------------------------------------------------------------
Exercisable, end of
year 1,132,562 54.02 929,538 49.79
----------------------------------------------------------------------------


The following table summarizes stock options outstanding and exercisable under the plan at March 31, 2009:



Outstanding Options Exercisable Options
----------------------------------------------------------------------------
Remaining Weighted Weighted
Life Average Average
Exercise Price Options (Years) Price (Cdn$) Options Price (Cdn$)
----------------------------------------------------------------------------
$ 37.45 - $ 39.30 111,250 0.1 37.83 111,250 37.83
$ 41.00 - $ 49.90 1,509,938 2.9 47.49 452,500 43.72
$ 50.15 - $ 59.25 614,249 1.4 53.71 299,062 53.72
$ 60.00 - $ 69.82 399,500 1.5 63.81 114,500 62.99
$ 76.38 - $ 79.69 42,500 2.2 79.29 11,250 79.69
$ 80.90 - $ 89.99 590,813 3.1 86.36 40,250 82.74
$ 90.40 - $ 99.68 760,750 2.7 94.32 103,500 93.28
$ 105.00 - $ 105.47 1,750 2.6 105.27 250 105.47
----------------------------------------------------------------------------
4,030,750 2.4 64.69 1,132,562 54.02
----------------------------------------------------------------------------


Stock-based Compensation

The fair value of each option granted during the year was estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average grant-date fair values of options granted during the year ended March 31, 2009 were Cdn$26.62 (year ended March 31, 2008 - Cdn$30.94 ). The weighted average assumptions used in the Black-Scholes model to determine fair value for the current and prior years were as follows:



Black-Scholes Assumptions
Year ended
(weighted average) March 31,
Years ended March 31, 2009 2008
----------------------------------------------------------------------------
Risk-free interest rate 2.1% 3.8%
Volatility 52% 31%
Expected life (years) 3.0 3.2
Expected annual dividend per share (Cdn$) 0.12 0.12
----------------------------------------------------------------------------

12. CONTRIBUTED SURPLUS

(thousands of U.S. dollars)
Years ended March 31, 2009 2008
----------------------------------------------------------------------------
Contributed surplus, beginning of year $ 34,952 $ 23,190
Stock-based compensation 21,234 19,086
Stock options exercised (4,220) (7,324)
----------------------------------------------------------------------------
Contributed surplus, end of year $ 51,966 $ 34,952
----------------------------------------------------------------------------

13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

(thousands of U.S. dollars)
Years ended March 31, 2009 2008
----------------------------------------------------------------------------
Accumulated other comprehensive income
(loss), beginning of year $ 40,989 $ 5,226
Other comprehensive income (loss):
Recognition of fair value of derivative
(loss) - (541)
Foreign currency translation gain (loss) (43,395) 36,304
----------------------------------------------------------------------------
Accumulated other comprehensive income
(loss), end of year $ (2,406) $ 40,989
----------------------------------------------------------------------------


14. ASSET IMPAIRMENT

During the year ended March 31, 2009, the Company expensed costs of US$1.3 million that were previously capitalized related to the evaluation of potential new ventures with which the Company decided not to proceed (year ended March 31, 2008 - US$0.6 million).

During the year ended March 31, 2008, the Company expensed costs of US$21.7 million that were previously capitalized related to the unsuccessful wells, workovers and associated costs in Thailand. A cash call receivable in the amount of US$1.1 million was also expensed.

15. INCOME TAXES

The provision for income taxes in the financial statements differs from the result that would have been obtained by applying the combined federal and provincial tax rate to the Company's earnings before income taxes. This difference results from the following items:



(thousands of U.S. dollars except tax rate
percentages)
Years ended March 31, 2009 2008
----------------------------------------------------------------------------
(Loss) before income taxes $ (17,503) $ (18,153)
Statutory income tax rate 29.38% 31.47%
Computed expected income taxes (5,142) (5,712)
Non-deductible expenses (662) (9,284)
Stock-based compensation expense 5,599 5,273
(Loss) income exempt from tax (5,510) 6,783
Prior years' foreign income tax expense
adjustments (166) (4,432)
Adjustment to future Indian taxes (9,936) (7,269)
Foreign non-income related taxes 212 207
Difference between current and future
income tax rates and other 4,848 2,475
Valuation allowance and other 15,816 13,821
----------------------------------------------------------------------------
Provision for income taxes $ 5,059 $ 1,862
----------------------------------------------------------------------------

The components of the Company's net future income tax liability at March 31
of each fiscal year are as follows:

(thousands of U.S. dollars)
Future income tax assets 2009 2008
----------------------------------------------------------------------------
Foreign currency cash and cash equivalents $ - $ 1,614
Short-term investments 3,364 -
Long-term investments 743 -
Asset retirement obligations 1,490 1,447
Unused foreign tax credits 24,864 17,583
Share issue expenses 4,951 6,737
Property and equipment 4,594 -
Long-term account receivable 2,607 854
Unused losses 336 -
----------------------------------------------------------------------------
$ 42,949 $ 28,235
----------------------------------------------------------------------------

Future income tax liabilities 2009 2008
----------------------------------------------------------------------------
Foreign currency cash and cash equivalents $ 332 $ -
Short-term investments - $ 288
Property and equipment 1,431 2,577
Valuation allowance 41,186 25,370
----------------------------------------------------------------------------
$ 42,949 $ 28,235
----------------------------------------------------------------------------
Net future income tax liability $ - $ -
----------------------------------------------------------------------------


India's federal tax law contains a seven-year tax holiday provision that pertains to the commercial production or refining of mineral oil, which is generally accepted as including petroleum and natural gas substances. As a result of the tax holiday provision in India, the Company pays the greater of 42.23 percent of taxable income in India after a deduction for the tax holiday or a minimum alternative tax of 10.56 percent of Indian income. Indian income is calculated in accordance with Indian generally accepted accounting principles. See also contingency note 24(e).

The Company pays taxes for the Feni property in Bangladesh at a rate of 4.0 percent of revenues net of profit petroleum. In addition, the Company accrues taxes assessed by the Government of Bangladesh beyond the calculated taxes.

The Company does not pay income taxes related to Block 9 production as indicated in the production sharing contract (PSC). The PSC indicates that the calculation for profit petroleum expense includes consideration of income taxes and, therefore, no income tax is assessed for Block 9.

The Company has unused non-capital losses in Canada totalling US$1.3 million expiring between 2011 and 2029.

16. EARNINGS PER SHARE

The following table summarizes the weighted average number of common shares used in calculating basic and diluted earnings per share:



Years ended March 31, 2009 2008
----------------------------------------------------------------------------
Weighted average number of common shares
outstanding
- basic 49,202,400 46,346,909
- diluted 49,202,400 46,346,909
----------------------------------------------------------------------------


As the Company incurred net losses for the years ended March 31, 2009 and 2008, all outstanding stock options (March 31, 2009 - 4,030,750; March 31, 2008 - 3,219,725) were considered anti-dilutive and were therefore excluded from the calculation of diluted per share amounts for the specified years.

17. SEGMENTED INFORMATION

The Company's operations are conducted in one business sector, the oil and natural gas industry. Geographical areas are used to identify the Company's reportable segments. A geographic segment is considered a reportable segment once its activities are regularly reviewed by the Company's management. The accounting policies of the information of the reportable segments are the same as those described in the summary of significant accounting policies. Revenues, operating profits and net identifiable assets by reportable segments are as follows:



Year ended March 31, 2009 As at March 31, 2009
----------------------------------------------------------------------------
(thousands of Segment
U.S. dollars) profit Capital Property and
Segment Revenue (loss) Additions Equipment Total Assets
----------------------------------------------------------------------------
Bangladesh $ 49,950 $ 7,847 $ 14,836 $ 138,667 $ 170,405
India 54,224 8,842 399,813 944,881 1,170,524
Indonesia - - 15,652 15,896 28,181
Kurdistan - - 23,660 24,579 28,477
Madagascar - - 4,600 4,393 5,826
Pakistan - - 22,637 22,863 22,932
All Other (1) 819 (496) 738 2,795 42,285
----------------------------------------------------------------------------
Total $ 104,993 $ 16,193 $ 481,936 $ 1,154,074 $ 1,468,630
----------------------------------------------------------------------------

Year ended March 31, 2008 As at March 31, 2008
----------------------------------------------------------------------------
(thousands of Segment
U.S. dollars) profit Capital Property and
Segment Revenue (loss) Additions Equipment Total Assets
----------------------------------------------------------------------------
Bangladesh $ 43,127 $ 6,512 $ 8,809 $ 144,994 $ 173,567
India 57,029 14,171 319,694 479,111 672,687
Indonesia - - - - -
Kurdistan - - - - -
Madagascar - - - - -
Pakistan - - - - -
All Other (1) 850 (1,651) 5,990 4,428 470,733
----------------------------------------------------------------------------
Total $ 101,006 $ 19,032 $ 334,493 $ 628,533 $ 1,316,987
----------------------------------------------------------------------------
(1) Revenues included in All Other are from Canadian oil sales net of
royalties.

The reconciliation of the segment profit to net income as reported in the
financial statements is as follows:

Years ended March 31, (thousands of U.S.
dollars) 2009 2008
----------------------------------------------------------------------------
Segment profit $ 16,193 $ 19,032
Interest and other income 11,330 21,661
Interest and financing on capital lease (1,498) -
General and administrative expenses (7,125) (7,051)
Foreign exchange gain (loss) 8,104 (8,272)
Discount of long-term account receivable (265) (4,434)
Stock-based compensation expense (18,989) (16,927)
Loss on short-term investment (24,380) 1,418
Equity (loss) on long-term investment (982) -
Impairment of long-term investment (4,186) -
Gain (loss) on risk management contracts 494 (2,065)
Asset impairment (1,258) (23,377)
----------------------------------------------------------------------------
Net (loss) $ (22,562) $ (20,015)
----------------------------------------------------------------------------


18. CAPITAL MANAGEMENT

Policy

The Company's policy is to maintain a strong capital base and related capital structure. The objectives of this policy are:

(i) to promote confidence in the Company by the capital markets, by investors, by creditors and by government agencies in the countries in which the Company bids for concessions and/or operates;

(ii) to maintain resources required to withstand financial difficulties due to exogenous influences such as financial, political, economic, social or market uncertainties and events; and

(iii) to facilitate the Company's ability to fulfill exploration and development commitments, and to seek and execute growth opportunities.

Capital Base

The Company's capital base includes shareholders' equity, outstanding long-term debt and undrawn and available long-term debt:



(thousands of U.S. dollars) March 31, 2009 March 31, 2008
----------------------------------------------------------------------------
Long-term debt $ 192,814 $ 192,814
Shareholders' equity $ 1,057,290 $ 1,095,463
----------------------------------------------------------------------------


The Company has certain obligations in accordance with its facility agreement. The facility agreement defines levels within which the Company must maintain the debt to equity ratio and the ratio of debt to earnings before interest expense, taxes, depletion and any extraordinary items. The Company monitors these ratios on a semi-annual basis in accordance with the facility agreement and complied with the ratios as at March 31, 2009.

Capital Management

The Company's objective in capital management is to have the flexibility to alter the capital structure to take advantage of capital-raising opportunities in the capital markets, whether they are equity or debt-related. However, the Company would generally use long-term debt either to fund portions of the development of proven properties or to finance portions of possible acquisitions. Exploration is generally funded by cash flow from operations and equity.

To manage capital, the Company uses a rolling five year projection. The projection provides details for the major components of sources and uses of cash for operations, financing and development and exploration expenditure commitments. Management and the Board of Directors review the projection annually and when contemplating interim financing or expenditure alternatives. The periodic reviews ensure that the Company has the short-term and long-term ability to fulfill its obligations, to fund ongoing operations, to pay dividends, to fund opportunities that might arise, to have sufficient funds to withstand financial difficulties or to bridge unexpected delays or satisfy contingencies and to grow the Company's producing assets.

19. FINANCIAL INSTRUMENTS

The following financial instruments are included on the Consolidated Balance Sheets. The carrying values and fair values of the financial instruments are as follow:



As at March 31, 2009 2009 2008 2008
----------------------------------------------------------------------------
(thousands of U.S. Carrying Fair Carrying Fair
dollars) Amount Value Amount Value
----------------------------------------------------------------------------
Held for trading financial
assets (designated upon initial
recognition):
Cash $ 31,189 $ 31,189 $ 443,889 $ 443,889
Restricted cash(2) 209,486 209,486 129,923 129,923
Short-term
investment 9,067 9,067 17,240 17,240
Loans and
receivables:
Accounts receivable 20,287 20,287 14,402 14,402
Cash call advances 103 103 23,523 23,523
Long-term accounts
receivable 22,098 22,098 20,850 20,850
Other financial
liabilities (not
held for trading):
Accounts payable and
accrued liabilities(1) 119,555 119,555 13,891 13,891
Interest rate swap(1) - - 2,608 2,608
Long-term debt $ 192,814 $ 192,814 $ 192,814 $ 192,814
----------------------------------------------------------------------------
(1) The fair value of the interest rate swap is included in accounts payable
and accrued liabilities on the balance sheet at March 31, 2008.
(2) Restricted cash is broken into a current portion (US$185.5 million) and
a non-current portion (US$24.0 million) as at March 31, 2009.


Basis for Determining Fair Values

The fair values of the cash, restricted cash, accounts receivable and accounts payable and accrued liabilities approximate their carrying values due to their short periods to maturity. The fair value of the short-term investment was based on publicly quoted market values. A loss of Cdn$27.7 million (US$24.4 million) on recognizing the fair value of the investment at March 31, 2009 (March 31, 2008 - nil) was recognized in income for the year ended March 31, 2009. The fair value of the cash calls advanced to joint venture partners approximates the amount of funds advanced. A discount on the long-term account receivable of US$0.3 million was recognized in income during the year ended March 31, 2009 (year ended March 31, 2008 - US$4.4 million) resulting in the long-term account receivable being carried at approximately fair value. There were no interest rates swaps at March 31, 2009. At March 31, 2008, the fair value of the interest rate swaps was provided by the counterparty using forward LIBOR rates. A gain of US$0.5 million on recognition of the fair value of the interest rate swap for the year ended March 31, 2009 (March 31, 2008 - loss of US$2.1 million) was recognized in income for the year ended March 31, 2009. The Company's long-term debt bears interest based on a floating market rate and, accordingly, the fair market value approximates the carrying value.

Market Risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and equity prices, will affect the Company's income or the value of its financial instruments. There were no changes in the Company's exposure to market risks or the Company's processes for managing the risks from the previous period. The Company is exposed to the risk of changes in market prices of commodities. The Company enters into natural gas contracts, which manages this risk. Because the Company has long-term gas contracts, a change in natural gas prices would not have impacted net income for the year ended March 31, 2009. The Company is exposed to changes in the market price of oil and condensate. If the market prices of oil and condensate had been 34 percent higher during the period, which is based on fluctuations in market prices over the past two fiscal periods, net income would have increased by US$3.9 million, all other things constant. An opposite change in the market price would result in an opposite change to net income. In addition, the Company will be 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 following year, calculated annually, for the D6 gas contracts. This production commenced in April 2009.

(a) Currency Risk

The majority of the Company's revenues and expenses are denominated in U.S. dollars. In addition, the Company converts Canadian-held cash to U.S. dollars as required to fund forecast U.S. dollar expenditures. As a result, the Company has limited its cash exposure to fluctuations in the value of the U.S. dollar versus other currencies. However, the Company is exposed to changes in the value of the Indian rupee and Bangladesh taka versus the U.S. dollar as they are applied to the Company's working capital of its foreign subsidiaries. The Company's exposure to the changes in the value of the Bangladesh taka versus the U.S. dollar is not significant. A 5 percent strengthening of the Indian rupee against the U.S. dollar at March 31, 2009, which is based on historical movements in the foreign exchange rates, would have decreased net income by US$0.8 million. This analysis assumes that all other variables remained constant.

The financial instruments are exposed to fluctuations in foreign exchange rates, which are used in the translation of the financial statements of the Canadian and corporate operations to U.S. dollars. The reported U.S. dollar value of the cash and cash equivalents, accounts receivable, short-term investment and accounts payable of the Canadian and corporate operations is exposed to fluctuations in the value of the Canadian dollar versus the U.S. dollar. A 6 percent weakening of the Canadian dollar against the U.S. dollar at March 31, 2009, which is based on historical movement in foreign exchange rates, would have increased net income by US$1.3 million with an offsetting decrease to other comprehensive income. This analysis assumes that all other variables remained constant.

(b) Interest Rate Risk

The Company is exposed to interest rate risk on its money market funds and short-term deposits. The Company manages the interest rate risk on these investments by monitoring the interest rates on an ongoing basis. The Company is exposed to interest rate risk on its long-term debt and was exposed to interest rate risk on its interest rate swaps, which settled during the year. If interest rates applicable to the long-term debt had been 36 basis points higher than they were during the period, which is based on historical changes in the applicable interest rates, net income would have decreased by US$0.7 million. If interest rates applicable to the interest rate swaps had been 36 basis points higher than they were during the period, net income would have increased by US$0.5 million. An opposite change in interest rates would result in an opposite change to net income.

(c) Other Price Risk

The Company has deposited the cash equivalents with reputable financial institutions, for which management believes the risk of loss to be remote.

The Company is exposed to the risk of fluctuations in the market prices of its short-term investments. A 26 percent change in the publicly quoted market values at the reporting date, which is based on historical changes in market values, would have increased or decreased net income for the year by Cdn$2.9 million (US$2.6 million). The fair value was Cdn$11.4 million (US$9.1 million) at March 31, 2009.

Credit Risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company's receivables from customers. The carrying amounts of the cash and cash equivalents, restricted cash, accounts receivable, cash call advances and the long-term account receivable reflect management's assessment of the maximum credit exposure. The Company is no longer exposed to credit risk associated with interest rate swaps as there are no interest rate swaps outstanding at March 31, 2009. There were no other changes in the Company's exposure to credit risks or any changes to the Company's processes for managing the risks from the previous period.

Accounts Receivable, Cash Call Advances and Long-term Receivable

The Company has accounts receivable from customers engaged in various industries that are concentrated in a specific geographical area in India and with a specific customer in Bangladesh. Management determines concentrations of risks based on the proportion of revenue from each customer out of total sales as well as the physical location of the customers. The accounts receivable and long-term accounts receivable balance include US$36.3 million receivable from one customer in Bangladesh and US$3.3 million from four gas customers in India, all of which are in one geographic area. The cash call advances of US$0.1 million at March 31, 2009 have been forwarded to the joint venture partners of various properties in order to fund exploration, development and/or operating expenses.

The Company takes measures in order to mitigate any risk of loss, which may include obtaining guarantees. The specific industries or government may be affected by economic factors that may impact accounts receivable. The aging of accounts receivable as at March 31, 2009 was:



(thousands of U.S. dollars) As at March 31, 2009
----------------------------------------------------------------------------
0 - 30 days $ 13,016
30 - 90 days 6,450
Greater than 90 days 821
----------------------------------------------------------------------------
Total accounts receivable $ 20,287
----------------------------------------------------------------------------


The accounts receivable, included in the table, that are not past due and that are past due are not considered impaired. The accounts receivable that are not past due are receivable from counterparties with whom the Company has a history of timely collection and the Company considers the accounts receivable collectible.

The long-term account receivable balance consists of gas sales charged to Petrobangla for the production from the Feni field in Bangladesh. Payment of the receivable is being delayed as a result of various claims raised against the Company as described in note 24 (a) and (b). The long-term accounts receivable is comprised of US$1.5 million that was recorded in fiscal 2009, US$2.6 million that was recorded in fiscal 2008, US$7.9 million that was recorded in fiscal 2007 and US$14.9 million that was recorded prior thereto, and the combined receivable has been adjusted to approximate its fair value of US$22.1 million. The long-term accounts receivable is not considered impaired. The Company considered the delay in payment, the writ and the lawsuit raised against the Company and progress towards resolving these issues in reaching the conclusion that the delay in payment is temporary. Despite the temporary delay in payment, the Company expects to collect the full amount of the receivable. The timing of collection is uncertain as the Company may not collect the receivable until resolution of the various claims raised against the Company described in note 24 (a) and (b).

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. As at March 31, 2009, the Company had cash of US$240.7 million (including restricted cash of US$209.5 million) and long-term debt of US$192.8 million resulting in cash exceeding long-term debt by $47.9 million.

The Company plans to meet its commitments with cash on hand and cash flow from operations.

The Company has the following financial liabilities and due dates as at March 31, 2009:



less than
(thousands of U.S. dollars) Carrying Value 1 year 1 - 3 years
----------------------------------------------------------------------------
Non-derivative financial liabilities(1)
Accounts payable $ 119,555 118,417 1,138
Principal repayments on long-term debt $ 192,814 - 192,814
----------------------------------------------------------------------------
(1) The Company also has capital lease commitments as outlined in note 23.


20. GUARANTEES

As at March 31, 2009, the Company had performance security guarantees, which are included in the restricted cash balance, of US$12.3 million for Indonesia and US$1.2 million for Madagascar. Additionally, the Company provided performance security guarantees of US$3.0 million for Cauvery, US$2.6 million for the D4 block and US$5.3 million for Block 9. The guarantees were supported by Export Development Canada.

As at March 31, 2008, the Company had performance security guarantees of US$7.7 million for Block 9, US$7.0 million for the Cauvery block and US$1.7 million for the D4 block.

21. ECONOMIC DEPENDENCE

The Company sells all of the gas production from the Feni and Block 9 fields in Bangladesh to Petrobangla. As per the terms of the agreements governing production from these fields, the Company is unable to elect to sell to other purchasers.

22. RELATED-PARTY TRANSACTIONS

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 consolidated financial statements, are measured at the exchange amount, which is also considered to be the fair value, and are in the normal course of business.

23. COMMITMENTS AND CONTRACTUAL OBLIGATIONS

The Company has commitments for approved budgets and development plans under various joint venture agreements. Outstanding development plan commitments for the D6 block are approximately US$223 million.

In May 2008, the Company signed a PSC for an interest in a block in the Kurdistan Region of Iraq that includes remaining minimum work commitments for the first exploratory period estimated at US$14.2 million related to seismic and drilling one exploratory well by May 2011 and US$2.7 million for various payments under the agreement. In October 2008 the Company farmed-in to a PSC for a property located off the west coast of Madagascar and the Company has minimum work commitments under the first exploratory period, which expires in June 2010, for 2,000 line kilometres of 2D seismic. In November 2008 the Company acquired interests in five blocks in Indonesia. The Company has minimum work commitments under the first exploratory period, which expires in November 2011, of US$62.7 million related to acquisition of 16,550 kilometres of 2D seismic and drilling one well per block.

Subsequent to March 31, 2009, the Company signed PSCs for interests in three additional blocks in Indonesia. The Company has minimum work commitments under the first exploratory period, which expires in May 2012, of US$56.7 million related to acquisition of 4,042 kilometres of 2D seismic, 1,200 square kilometres of 3D seismic, drilling one well per block and various payments under the agreements.

The Company has recognized the capital lease of the floating production, storage and off-loading vessel (FPSO) at the fair value of US$68.7 million. The lease is for 10 years and has lease payments of US$10.8 million per year. The discount rate used in determining the present value of minimum lease payments is 9 percent.



(thousands of U.S. dollars)
----------------------------------------------------------------------------
Fiscal 2010 $ 10,757
Fiscal 2011 10,757
Fiscal 2012 10,757
Fiscal 2013 10,757
Fiscal 2014 10,757
Thereafter (net of salvage value) 47,535
----------------------------------------------------------------------------
Total minimum payments 101,320
Less amount representing imputed interest 32,584
----------------------------------------------------------------------------
Present value of obligation under capital leases $ 68,736
----------------------------------------------------------------------------


24. CONTINGENCIES

(a) During the year ended March 31, 2006, a group of petitioners in Bangladesh (the petitioners) filed a writ with the Supreme Court of Bangladesh (the Supreme Court) against various parties including Niko Resources (Bangladesh) Ltd., a subsidiary of the Company. The petitioners are requesting the following of the Supreme Court with respect to the Company:

(i) that the Joint Venture Agreement for the Feni and Chattak fields be declared null and illegal;

(ii) that the government realize from the Company compensation for the natural gas lost as a result of the uncontrolled flow problems as well as for damage to the surrounding area;

(iii) that Petrobangla withhold future payments to the Company relating to production from the Feni field (US$26.8 million as at March 31, 2009); and

(iv) that all bank accounts of the Company maintained in Bangladesh be frozen.

The Company believes that the outcome of the writ with respect to the first two issues is not determinable. With respect to the third issue, Petrobangla is currently withholding payments to the Company relating to production from the Feni field.

With respect to the fourth issue, the Company's Bangladesh branch has been permitted to make payments to Bangladesh vendors. However, payments to foreign vendors from the Bangladesh Feni and Chattak branch are not permitted. The Company's foreign vendors for the Feni and Chattak fields are being paid by Niko Resources (Bangladesh) Ltd., which is incorporated outside of Bangladesh.

(b) During the year ended March 31, 2006, Niko Resources (Bangladesh) Ltd. received a letter from Petrobangla demanding compensation related to the uncontrolled flow problems that occurred in the Chattak field in January and June 2005. Subsequent to March 31, 2008, Niko Resources (Bangladesh) Ltd. was named as a defendant in a lawsuit that was filed in Bangladesh by Petrobangla and the Republic of Bangladesh demanding compensation as follows:

(i) taka 369,385,000 (US$5.3 million) for 3 Bcf of free natural gas delivered from the Feni field as compensation for the burnt natural gas;

(ii) taka 725,225,000 (US$10.3 million) for 5.89 Bcf of free natural gas delivered from the Feni field as compensation for the subsurface loss;

(iii) taka 845,560,000 (US$11.2 million) for environmental damages, an amount subject to be increased upon further assessment;

(iv) taka 5,540,771,000 (US$78.8 million) for 45 Bcf of natural gas as compensation for further subsurface loss; and

(v) any other claims that arise from time to time.

The Company and the Government of Bangladesh had previously agreed to settle the government's claims through arbitration conducted in Bangladesh based upon international rules. The Company will actively defend itself against the lawsuit. This process could take in excess of three years.

The Company believes that the outcome of the lawsuit and the associated cost to the Company, if any, are not determinable. As such, no amounts have been recorded in these consolidated financial statements.

(c) In accordance with natural gas sales contracts to customers in the vicinity of the Hazira field in India, the Company and its joint venture partner at Hazira have committed to certain minimum quantities. Should the Company fail to supply the minimum quantity of natural gas in any month as specified in the contract, the Company may be liable to pay the vendor an approximately equivalent amount. The Company was unable to deliver the minimum quantities up to December 31, 2007. The Company has agreed to provide five times the gas that the Company was unable to deliver from D6 volumes. In the event the Company is unable to deliver the volumes, the Company will have a potential liability, which is currently estimated at US$11.2 million.

(d) The Company calculates and remits profit petroleum expense to the Government of India in accordance with the PSC. The profit petroleum expense calculation considers capital and other expenditures made by the joint venture, which reduce the profit petroleum expense. There are costs that the Company has included in the profit petroleum expense calculations that have been contested by the government. The Company believes that it is not determinable whether the above issue will result in additional petroleum expense. No amount has been recorded in these consolidated financial statements.

(e) The Company has filed its income tax returns in India for the taxation years 1998 through 2008 under provisions that provide for a tax holiday deduction for production from the Hazira and Surat fields for eligible undertakings.

The Company received a favourable ruling with respect to the tax holiday at the third tax assessment level for the taxation years 1999 through 2004. The Company has received US$12.8 million during the year with respect to the tribunal ruling on these years, excluding taxation year 2002, and US$2.4 million for interest on the balance received. The Income Tax Department has filed an appeal against the orders and the matter is currently pending with the Indian court. The 2005 taxation year has been assessed at the first level with unfavourable treatment with respect to the tax holiday and other deductions. The Company has filed an appeal against the order. The taxation years 2006 through 2008 have been filed including a deduction for the tax holiday, but have not yet been assessed.

Should the Company fail through the legal process to receive a favourable ruling with respect to the taxation years 1999 through 2005, the Company would record a tax expense of US$31.2 million, pay additional taxes of US$20.9 million and write off US$10.3 million of the income tax receivable. In addition, any failure could result in interest and penalties.

(f) The Company has a potential liability of US$1.8 million (US$0.6 million) with respect to the service tax liability that the government can charge to a vendor employed for the construction of the Hazira offshore development. To date, the vendor has claimed US$0.6 million, being the amount assessed by the government. An external expert has determined that the service tax is applicable and US$0.6 million has been recognized in these financial statements.

(g) In January 2009, the Company received confirmation from Canadian authorities that they are engaged in a formal investigation into allegations of improper payments in Bangladesh by either the Company or its subsidiary in Bangladesh. No charges have been laid against either the Company or its subsidiary in Bangladesh. The Company believes that the outcome of the investigation and associated costs to the Company are not determinable and no amounts have been recorded in these consolidated financial statements.


Contact Information

  • Niko Resources Ltd.
    Edward S. Sampson
    Chairman of the Board, President & CEO
    (403) 262-1020
    or
    Niko Resources Ltd.
    Murray Hesje
    VP Finance & CFO
    (403) 262-1020
    Website: www.nikoresources.com