Niko Resources Ltd.
TSX : NKO

Niko Resources Ltd.

November 12, 2009 06:00 ET

Niko Reports Results for the Three and Six Months Ended September 30, 2009

CALGARY, ALBERTA--(Marketwire - Nov. 12, 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 management's discussion and analysis, for the three and six month period ended September 30, 2009, the second quarter of Niko's fiscal year. The operating results are effective November 11, 2009.

HIGHLIGHTS

Financial

- Niko reports quarterly funds from operations of US$47.9 million, the largest in its history.

Development

- D6 gas production completed 223 days of 100 percent uptime demonstrating flawless commissioning and execution.

- D6 gas production increased to 118 MMcf/d in the quarter, which is a 77 percent increase over the previous quarter. D6 gas production on November 11, 2009 was 161 MMcf/d. The Company has signed gas sales contracts totalling 191 MMcf/d and expects to add significantly to this total before the end of November.

- The scope of work under Phase I of the D6 gas development is complete.

- Commerciality proposal filed for the R series in the D6 block and an integrated development plan for all gas discoveries is being conceptualized.

- Successfully drilled the AJ2 appraisal well in the southern and deeper parts of the NEC-25 Block. Results from all wells including the recent AJ2 well are being incorporated to generate an integrated development plan for all discoveries to maximize cost efficiency.

New Ventures

- In Indonesia, Niko has been selected as the successful bidder and executed a letter of intent for three additional exploration blocks covering an area in excess of 17,000 square kilometres. Niko will have a 50 percent interest in each block and will operate two of the three blocks.

- In Trinidad, Niko signed an agreement whereby it will have a 26 percent interest and operate the 2AB shallow water block offshore Trinidad.

- Niko acquired an additional 10 percent interest in the Qara Dagh block in the Kurdistan Region. As a result, the Niko will hold an aggregate 37 percent net working interest in the production sharing contract.



Three months ended Six months ended
September 30, September 30,
2009 2008 2009 2008
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Average daily sales volumes
Oil and condensate (bbls/d) 1,644 175 1,229 213
Natural gas (Mcf/d) 206,653 74,895 180,983 75,964
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Total combined (Mcfe/d) 216,515 75,947 188,354 77,245
(thousands of U.S. dollars)
Oil and natural gas revenue 77,879 24,064 131,732 48,445
Funds from operations 47,948 14,549 76,212 30,632
Gain (loss) on short-term
investments 19,685 (22,046) 37,688 (15,171)
Net income (loss) 45,043 (22,420) 65,484 (16,153)
Capital expenditures 88,116 101,092 161,314 211,276
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Sales

The impact of the commencement of gas production from the D6 Block on the Company's total sales volumes in MMcfe/d is shown in the quarterly sales table displayed below:

To view the Sales History chart, please click the following link: http://media3.marketwire.com/docs/1111nko_saleshistory.jpg.

Gas production from the D6 Block commenced in April 2009 and has increased Niko's total production by 122 percent compared to total production prior to start-up. Primarily as a result of D6 gas production, average Company-wide production for the year ending March 31, 2010 is expected to increase to around 245 MMcfe/d, which is a 187 percent increase over fiscal 2009.

Oil production from the MA field in the D6 Block was shut-in from March 22, 2009 to April 25, 2009 for the hook-up of the Phase II subsea facility and connection to the floating production, storage and offloading vessel. Production in the quarter increased 25 percent to 10,600 bbls/d (1,060 bbls/d working interest to the Company) from 8,500 bbls/d (850 bbls/d working interest to the Company) in the previous quarter. Sales during the quarter averaged 13,230 bbls/d (1,323 bbls/d working interest to the Company) as inventory levels were reduced in the quarter. Oil production is targeted to reach 25,000 bbls/d (2,500 bbls/d working interest to the Company) before March 31, 2010.

Gas production from Block 9 in the quarter was 99 MMcf/d (66 MMcf/d working interest to the Company). The Bangora-3 well was put on-stream in June 2009 and a work over was conducted in September 2009 to complete an additional sand. The well is back on production and current production from the block is in excess of 120 MMcf/d (80 MMcf/d working interest to the Company).

Development

D6 Block - Dhirubhai 1 and 3 Gas Development: The scope of work under Phase I of the gas development project has been completed including completion and tie-in of all 18 planned wells. Contracts have been signed for the equivalent of approximately 1,910 MMcf/d (191 MMcf/d working interest to the Company) and the customers are currently taking approximately 1,610 MMcf/d (161 MMcf/d working interest to the Company).

Exploration

India

D6 Block: The BA2 well was not drilled to the planned total depth due to complications while drilling. Options to re-drill this well or a twin well are being evaluated. The Company expects exploration drilling on numerous prospects within the block will take place in the coming year.

D4 Block: The initial interpretation of the data within the 3,600-square-kilometre 3D seismic survey acquired has identified several areas of interest, which will be fully analysed as part of the ongoing evaluation. Processing and interpretation of the data are expected to be completed in time for the Company to begin drilling in the second half of calendar 2010.

Cauvery: The Khoja-2 well, which finished drilling in September 2009, was unsuccessful and was abandoned. The Company has received an extension to the exploration period to March 2011 in order to evaluate the technical merit of the block.

Hazira Block: The 30-square-kilometre transition zone 3D seismic survey is designed to explore for deeper oil and gas targets in the eastern half of the Hazira block. The survey has been merged with the offshore 3D seismic previously acquired providing 3D seismic coverage of almost the entire Hazira block. Evaluation of results is complete and a multi-well drilling program will be proposed to commence in the first calendar quarter of 2010.

NEC-25 Block: Approximately 1,000 square kilometres of 3D seismic have been acquired along the central portion of the northwest boundary of the previous 3D surveys. Drilling of the AJ2 well finished in July 2009 and discovered gas. An additional well, AJ3, will be drilled as a follow up to the successful AJ2 well.

Pakistan

The 2,000-square-kilometre 3D seismic program acquired during fiscal 2009 was shot to identify stratigraphic potential, resolve structural complexity and indicate the presence of hydrocarbons. Processing of the 3D data should be completed in the second calendar quarter of 2010 with interpretation and selection of drilling locations to follow.

Madagascar

Interpretation of the 7,600 kilometres of reprocessed 2D seismic is continuing. Further evaluation of the block is planned to commence in late 2009 including acquisition of a high-resolution multi-beam survey and a sea floor coring program intended to identify sea floor oil and gas seeps. Future work as prescribed in Phase II includes the acquisition of a 3D seismic program to be designed based on results of the 2D seismic reprocessing and the multi-beam survey. The Company expects to drill a well in the second half of calendar 2012.

Kurdistan

The 350 kilometre 2D seismic program covering the entire block, including the surface structure that dominates the Qara Dagh block, has been completed, processed and interpreted. A drilling location has been selected and drilling is expected to commence in the second calendar quarter of 2010.

Indonesia

Niko has acquired interests in several blocks in deepwater offshore Indonesia. Indonesia has long been a prolific oil and gas producing nation with very large reserves; however, its deepwater areas have remained essentially unexplored. Most blocks have sea bottom oil and gas seeps and large structural features, and several have direct indication of hydrocarbons on seismic. The single well commitment per block will follow seismic acquisition and interpretation. The seismic program planned for each block is outlined below:



Block Planned seismic
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Bone Bay 3,000 kilometres of 2D
Cendrawasih 1,200 square kilometres of 3D
Kofiau 1,042 kilometres of 2D, 3,150 square kilometres of 3D
Kumawa 3,000 kilometres of 2D
Seram 3,500 kilometres of 2D
South Matindok 4,400 kilometres of 2D
Southeast Ganal 2,250 kilometres of 2D, 2,700 square kilometres of 3D
West Sageri 3,400 kilometres of 2D, 702 square kilometres of 3D
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A 2,700 square kilometre 3D spec survey was completed in Southeast Ganal in September 2009 and a 702 square kilometre 3D spec survey is being acquired in West Sageri. Acquisition of 2D seismic in these blocks was completed in October 2009. New 2D seismic surveys are also planned for the Bone Bay, South Matindok, Kumawa, Kofiau and Seram blocks. A spec 3D survey is expected to commence in Kofiau in the calendar year.

Trinidad

In July 2009, the Company acquired the right to earn a 26 percent interest and operate the 1,605 square-kilometre shallow water block 2AB offshore Trinidad. Both the assignment of the interest and operatorship are subject to approval from the government of Trinidad and Tobago. The Company has minimum work commitments to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells within three years.

OPERATING EXPENSE

During the three months ended September 30, 2009 operating expenses decreased to US$0.33/Mcfe from US$0.45/Mcfe in the previous quarter. Operating expenses were higher in the quarter ended June 30, 2009 due to the start-up costs related to the commencement of D6 gas production as production rates were ramping up. Operating expenses fell in the quarter ended September 30, 2009 and are anticipated to continue to fall on a unit-of-production basis once the D6 gas field is producing at designed capacity.

Forward-Looking Information and Material Assumptions

This report on results for the three and six months ended September 30, 2009 contains forward-looking information including forward-looking information about Niko's operations, reserve estimates, production and capital spending.

Forward-looking information is generally signified by words such as "forecast", "projected", "expect", "anticipate", believe", "will" and similar expressions. This forward-looking information is based on assumptions that the Company believes were reasonable at the time such information was prepared, but assurance cannot be given that these assumptions will prove to be correct, and the forward-looking information in this report on results for the three and six months ended September 30, 2009 should not be unduly relied upon. The forward-looking information and the Company's assumptions are subject to uncertainties and risks and are based on a number of assumptions made by the Company, any of which may prove to be incorrect. Forward-looking information in this report on the results for the three and six months ended September 30, 2009 includes, but is not limited to, the following:

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

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

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

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

The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis and updates reserves on an annual basis. Refer to "Risk Factors" contained in the Company's management's discussion and analysis for discussion of uncertainties and risks that may cause actual events to differ from forward-looking information provided in this report on results for the three and six months ended September 30, 2009.

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis (MD&A) of the financial condition, results of operations and cash flows of Niko Resources Ltd. ("Niko" or "the Company") for the three and six months ended September 30, 2009 should be read in conjunction with the audited consolidated financial statements and accompanying notes for the year ended March 31, 2009. This MD&A is effective November 11, 2009. Additional information relating to the Company, including the Company's Annual Information Form (AIF), is available on SEDAR at www.sedar.com.

Effective March 31, 2009, the Company adopted the U.S. dollar as its reporting currency. All financial information is presented in U.S. dollars unless otherwise indicated. Certain prior-year amounts have been reclassified to conform to current-year presentation and to a U.S. dollar reporting currency.

The term "the quarter" is used throughout the MD&A and in all cases refers to the period from July 1, 2009 through September 30, 2009. The term "prior year's quarter" is used throughout the MD&A for comparative purposes and refers to the period from July 1, 2008 through September 30, 2008. The term "year-to-date" is used throughout the MD&A and in all cases refers to the period from April 1, 2009 through September 30, 2009. The terms "prior year's period" and "2008 period" are used throughout this MD&A and in all cases refer to the period from April 1, 2008 through September 30, 2008. The term "prior year's periods" is used throughout this MD&A and in all cases refer to the three and six-month periods ended September 30, 2008.

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

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

One MMbtu is equivalent to 1 Mcfe plus or minus up to 20 percent, depending on the composition and heating value of the natural gas in question.

Less than 1 percent of total corporate volumes and total corporate revenue are from Canadian oil, Bangladeshi condensate and Hazira condensate production. Therefore, the results from Canadian oil, Bangladeshi condensate and Hazira condensate production are not discussed separately.

Forward-Looking Information and Material Assumptions

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

Forward-looking information in this MD&A includes, but is not limited to, the following:

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

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

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

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

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

Non-GAAP Measures

The selected financial information presented throughout the MD&A is prepared in accordance with Canadian generally accepted accounting principles (GAAP), except for "funds from operations", "operating netback", "funds from operations netback", "earnings netback" and "segment profit", which are used by the Company to analyze the results of operations.

By examining funds from operations, the Company is able to assess its past performance and to help determine its ability to fund future capital projects and investments. Funds from operations is calculated as cash flows from operating activities prior to the change in operating non-cash working capital and the change in long-term accounts receivable.

By examining operating netback, funds from operations netback, earnings netback and segment profit, the Company is able to evaluate past performance by segment and overall. Operating netback is calculated as oil and natural gas revenues less royalties, profit petroleum expenses and operating expenses for a given reporting period, per thousand cubic feet equivalent (Mcfe) of production for the same period, and represents the before-tax cash margin for every Mcfe sold.

Funds from operations netback is calculated as the funds from operations per Mcfe and represents the cash margin for every Mcfe sold. Earnings netback is calculated as net income per Mcfe and represents net income for every Mcfe sold. Segment profit is defined as oil and natural gas revenues less royalties, profit petroleum expenses, operating expenses, depletion, depreciation and accretion expense and current income taxes related to each business segment.

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

These non-GAAP measures do not have any standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other companies.




OVERALL PERFORMANCE
Funds from Operations
Three months ended Six months ended
September 30, September 30,
(thousands of U.S. dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Oil and natural gas revenues 77,879 24,064 131,732 48,445
Royalties (3,751) (1,169) (6,272) (2,324)
Profit petroleum (7,759) (5,289) (14,983) (10,767)
Operating expense (6,505) (2,039) (13,112) (4,358)
Interest income 2,789 2,790 2,874 7,025
Interest and financing expense (4,088) - (7,455) -
General and administrative expense (2,445) (1,946) (3,976) (4,662)
Realized foreign exchange (loss) (230) (1,950) (857) (1,287)
Current income tax (expense)
recovery (7,942) 88 (11,739) (1,440)
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Funds from operations(1) 47,948 14,549 76,212 30,632
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(1) Funds from operations is a non-GAAP measure as calculated above.


Natural gas production from the Dhirubhai 1 and 3 gas fields in the D6 Block commenced in April 2009, accounting for approximately 80 percent of the increase in revenues in the quarter and year-to-date compared to the prior year. The remaining increase is attributable to oil sales from the D6 Block, which commenced in November 2008, and an increase in Bangladesh revenue as a result of facility upgrades at Block 9 and the Bangora-3 well going on-stream. Royalties, operating expense and income tax expense increased with the addition of D6 gas and oil production. Profit petroleum increased with increased production from Block 9 and because the Company shared profits from Surat with the Government of India during the quarter and year-to-date. Profit petroleum payable to the Government of India with respect to the D6 Block was US$0.5 million and US$0.8 million in the quarter and year-to-date, respectively, or one percent of revenues. The Company received interest of US$2.7 million on an income tax refund. The interest and financing expense relates to the lease of the Floating Production, Storage and Offloading vessel (FPSO) for D6 oil production and interest expense on the long-term debt. The realized foreign exchange loss in the quarter and year-to-date was a result of the weakening of the U.S. dollar against the Indian rupee.



Net Income
Three months ended Six months ended
September 30, September 30,
(thousands of U.S. dollars) 2009 2008 2009 2008
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Funds from operations (non-GAAP
measure) 47,948 14,549 76,212 30,632
Unrealized foreign exchange
(loss) (4,758) (1,004) (8,340) (3,279)
Gain (loss) on short-term
investments 19,685 (22,046) 37,688 (15,171)
Equity (loss) on long-term
investment - (778) (91) (778)
Gain on risk management contracts - 369 - 1,323
Discount of long-term account
receivable (46) (79) (94) (179)
Stock-based compensation expense (3,679) (4,718) (9,087) (9,121)
Depletion, depreciation and
accretion (22,937) (8,713) (39,634) (19,580)
Future income tax recovery 8,830 - 8,830 -
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Net income (loss) 45,043 (22,420) 65,484 (16,153)
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Net income increased substantially in the quarter and year-to-date over the prior year's periods. The main causes of the increases were higher funds from operations as previously discussed and the unrealized gains on marking the short-term investments to market value. Partial offsets include the unrealized foreign exchange loss and depletion expense. The unrealized foreign exchange loss was primarily a result of the weakening of the U.S. dollar against the Canadian dollar. Depletion expense increased primarily due to increased production with the commencement of gas production from the D6 Block. Finally, there was a future income tax recovery for a tax credit available for future years related to minimum alternative tax paid for the D6 Block in the current year.

BACKGROUND ON PROPERTIES

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

India

Cauvery - The Company has a 100 percent working interest and 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 four of the five wells required under the first exploration phase. The Company has received an extension to the exploration period to March 2011 in order to evaluate the technical merit of the block.

D4 - The Company has a 15 percent interest in the D4 Block, located in the Mahanadi Basin offshore the east coast of India. The block, which is currently in the exploration phase, encompasses more than 17,000 square kilometres. The commitment for Phase I exploration includes seismic work and drilling three exploration wells. Originally, the work commitment was to be completed by September 2009; however, the Government of India is in the process of approving a blanket extension of up to three years for this and other deepwater blocks, prompted by the shortage of deepwater drilling rigs. If the blanket extension is not approved, the Company will apply for an automatic one year extension. The Indian government has historically granted extensions, when required; however, there is a risk that either extension may not be granted to the Company and the rights to continue exploration on the block would cease. The seismic work has been completed and is ready for processing.

D6 - The Company has a 10 percent working interest in the 7,645-square-kilometre D6 Block. In addition to continued exploration on the block there are two development projects: the MA oil discovery and the Dhirubhai 1 and 3 natural gas discoveries. Production from the MA discovery began in September 2008 and from the Dhirubhai 1 and 3 discoveries in April 2009. The Company has been granted petroleum mining licences for the discoveries expiring in 2028 and 2025, respectively. Oil production is sold on the spot market at a price based on Bonny Light and adjusted for quality. Gas production is sold under long-term gas contracts using a pricing formula approved by the Government of India, which currently results in a price of US$4.20/MMbtu and there is a marketing margin of US$0.135/MMBtu earned in addition to the price formula. Net of adjustments for heating value, the sales price is approximately US$3.95/Mcf. A development plan for nine additional natural gas discoveries was submitted to the Government of India in July 2008; however, an integrated development plan for all gas discoveries in the D6 Block is being conceptualized.

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

Hazira - The Company has a 33 percent working interest in the 50-square-kilometre Hazira onshore and offshore block on the west coast of India, which lies adjacent to a large industrial corridor about 25 kilometres southwest of the city of Surat. The Company has a petroleum mining licence that expires in September 2014. The Company has two contracts for the sale of gas production from the field expiring in March 2013 and April 2016 at current prices up to US$4.87/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 9 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. Although a development plan for six of the gas discoveries had previously been submitted to the Government of India, an integrated development plan for all discoveries to date is being prepared to maximize cost efficiency.

Surat - The Company holds a development area of 24 square kilometres containing the Bheema and NSA shallow natural gas fields. These fields have been producing natural gas since April 2004. The Company has a petroleum mining licence that expires in September 2024. The Company has one contract for the sale of gas production from the field expiring on March 31, 2011 at a price of US$5.50/Mcf until March 31, 2010 and US$6.00/Mcf until expiry. In addition to the price indicated, the Company collects the 9 percent royalty, payable to the government, from the customer. In addition, the Company will pay a percentage of the profits from the block to the government, which varies with the Investment Multiple (IM). The Company shares 20 percent of profits when the IM is between one and 1.5; 30 percent between 1.5 and 2; 40 percent between 2 and 2.5; 50 percent between 2.5 and 3; and 60 percent thereafter.

Bangladesh

Block 9 - The Company holds a 60 percent interest in this 6,880-square-kilometre onshore block which encompasses the capital city of Dhaka. 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. Profits on natural gas are calculated as the minimum of (i) 55 percent of revenue for the period and (ii) revenue less operating and capital costs incurred to date.

Feni and Chattak - The Feni field covers 43 square kilometres and is located 6 kilometres west of the main natural gas line to Chittagong. The Chattak structure covers 376 square kilometres and rights to this block were obtained in October 2003. The Company has been producing natural gas from the Feni field since November 2004. As per the joint venture agreement (JVA), the Company has rights to produce until October 2023 and this arrangement can be extended if production continues beyond this period. The Company was selling gas under a GPSA including a price of US$1.75 per Mcf, which expired in November 2009 and can be extended with mutual consent. The Company has proposed postponing extension of the GPSA pending resolution of the various claims raised against the Company as described in note 13 to the unaudited consolidated financial statements for the period ended September 30, 2009. The Company is reviewing whether to continue to deliver gas from the field. Payment for the gas is being delayed as a result of the claims. The Company pays a percentage of the profits from the field to the government, which varies with the Investment Multiple (IM). The Company shares 20 percent of profits from the Feni field when the IM is less than one; 25 percent between 1 and 1.5; 32 percent between 1.5 and 2; 38 percent between 2 and 3; and 42 percent thereafter. Future drilling activities at Feni and Chattak have been postponed pending resolution of overdue payment for gas owed to the Company by the Government of Bangladesh.

Pakistan

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

Kurdistan Region

In May 2008 the Company signed a PSC for the onshore Qara Dagh block, which covers approximately 846 square kilometres, in the Sulaymaniyah Governorate of the Federal Region of Kurdistan in Iraq. In September 2009, the Company acquired an additional interest from the Kurdistan Regional Government. The Company currently has a 37 percent interest and carries the proportionate cost for the regional government's interest, resulting in a 46 percent cost interest. The exploration period is for a term of five years and is extendable by two one-year terms. The first exploration phase is for three years expiring in May 2011 and the Company has commitments under this phase for seismic and drilling one exploratory well. Processing and interpretation of the seismic program is complete and a drilling location has been selected. Construction of the drilling location is expected to commence in November 2009 and drilling is expected to commence in the second calendar quarter of 2010.

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 (OMNIS), which acts on behalf of the Republic of Madagascar. The PSC covers 16,845 square kilometres in water depths ranging from shallow water to 1,500 metres. The Company completed a 31,944-line-kilometre aero-magnetic survey applicable to the Phase I work commitment. The Company's remaining work commitments under the first exploration phase was for 2,000 kilometres of 2D seismic to be completed by June 2010. The 2,000 line-kilometre commitment has been converted to acquisition of a multi-beam bathymetric survey combined with a seabed coring program and has been approved by OMNIS.

Indonesia

The Company holds interests in PSCs for eight offshore exploration blocks covering approximately 40,000 square kilometres. The chart below indicates the location, award date, the Company's working interest and the size of the block.



Working Area (Square
Block Name Offshore Area Award Date Interest Kilometres)
----------------------------------------------------------------------------
West Sageri (1) Makassar Strait Nov. 2008 51% 4,977
SE Ganal (1) Makassar Strait Nov. 2008 51% 4,868
Seram Seram North Nov. 2008 25% 4,991
South Matindok Sulewasi NE Nov. 2008 25% 5,182
Bone Bay Sulewasi SW Nov. 2008 25% 4,969
Kofiau (1) West Papua May 2009 67% 5,000
Kumawa Papua SW May 2009 25% 5,004
Cendrawasih Papua NW May 2009 25% 4,991
----------------------------------------------------------------------------
(1) Operated by the Company.


All of the blocks are in the first exploration period, which is a three-year period. The Company has minimum work commitments for the blocks acquired in November 2008 to acquire and process 16,350 kilometres of 2D seismic in total for the five blocks and drill one well per block. The Company has minimum work commitments for the blocks acquired in May 2009 for the acquisition of 4,042 kilometres of 2D seismic, 1,200 square kilometres of 3D seismic and drilling one well per block.

Trinidad

In July 2009, the Company acquired the right to earn a 26 percent interest and operate the 1,605 square-kilometre shallow water Block 2AB offshore Trinidad. Both the assignment of the interest and the operatorship are subject to approval from the government of Trinidad and Tobago. The Company has minimum work commitments to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells within three years.



Capital Expenditures
Exploration Spending (Net to the Company)

Actual spending for the Forecast spending
six months ended for October 1, 2009 to
(millions of U.S. dollars) September, 2009 (1) March 31, 2010 (2)
----------------------------------------------------------------------------
India 30.5 26
Indonesia 17.3 40
Kurdistan Region 38.8 12
Madagascar 0.7 6
Pakistan 0.3 3
Trinidad - 4
----------------------------------------------------------------------------
Total 87.6 91
----------------------------------------------------------------------------
(1) The Company also spent US$0.4 million on new ventures and other.
(2) Refer to "Forward-Looking Information and Material Assumptions" in this
MD&A for a description of how forecast capital expenditures are
estimated.


Of the US$87.6 million spent year-to-date, US$53.3 million was spent during the quarter. Spending during the quarter and year-to-date is discussed below.

Indian capital spending in the quarter included costs of drilling the Khoja-2 well in Cauvery (US$4.9 million), the remaining costs of drilling the AJ2 well in NEC-25 (US$0.5 million) and exploratory drilling in the D6 Block (US$3.2 million). Year-to-date costs also included costs of drilling the Khoja-1 well in Cauvery, additional drilling in the D6 Block and seismic work in the D4 Block. Forecast capital spending for India includes processing of the 3D seismic acquired in D4 and further exploratory drilling in the D6 Block.

Indonesian capital spending in the quarter of US$7.0 million was for 3D seismic in the Southeast Ganal block and the remaining costs were for signing bonuses for various blocks and carrying costs of the blocks. Year-to-date spending included the signing bonus with respect to the Kofiau block. Forecast capital spending in Indonesia is for seismic.

The cost to acquire an additional 10 percent interest in the Qara Dagh PSC was US$30 million payable to the Kurdistan Regional Government in accordance with the agreement. The remaining year-to-date costs were for seismic and various bonuses required as per the PSC. Forecast capital spending is for the remaining seismic costs, construction of a drilling location and bonuses under the PSC.

Costs of US$0.7 million incurred in Madagascar were for the acquisition and reprocessing of existing 2D seismic data and the environmental impact assessment. Forecast capital spending is for a multi-beam survey.

Forecast expenditures in Pakistan are for processing of the seismic survey acquired in fiscal 2009.

The forecast expenditure for Trinidad includes the signing bonus and other bonuses required as per the PSC.



Development Spending (Net to the Company)
Actual spending for the Forecast spending
six months ended for October 1, 2009 to
(millions of U.S. dollars) September 30, 2009 March 31, 2010(1)
----------------------------------------------------------------------------
Bangladesh 8.8 3
India 64.5 83(2)
----------------------------------------------------------------------------
Total 73.3 86
----------------------------------------------------------------------------
(1) Refer to "Forward-Looking Information and Material Assumptions" in this
MD&A for a description of how forecast capital expenditures are
estimated.
(2) Does not include payment of amounts accrued and included in accounts
payable on the balance sheet.


Of the US$73.3 million spent year-to-date, US$34.8 million was spent during the quarter. Spending during the quarter and year-to-date is discussed below.

Bangladesh development in the quarter (US$1.0 million) was for the workover of the Bangora-3 well and facilities upgrades. Year-to-date spending also includes well testing and payment of the guarantee associated with the work commitment for the block.

Indian development in the quarter (US$33.8 million) was for the remaining well completions and connecting the wells to the offshore platform in the D6 gas development and completions, drilling the MA7H well and connecting wells to the FPSO in the D6 oil development. Year-to-date spending also included the completion and tie-in of additional wells for the Dhirubhai 1 and 3 gas fields and drilling an additional well and tie-in of existing wells in the MA oil field. The remaining costs of the Dhirubhai 1 and 3 gas field development and the ongoing development of the MA oil field are forecast for the rest of fiscal 2010.



SEGMENT PROFIT
INDIA

Three months ended Six months ended
(thousands of U.S. dollars, except September 30, September 30,
as indicated) 2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas revenue 53,004 11,707 88,380 23,079
Oil revenue (1) 9,590 982 13,802 2,572
Royalties (3,732) (1,111) (6,241) (2,213)
Profit petroleum (2,709) (1,620) (5,205) (3,431)
Operating expenses (5,326) (1,165) (10,333) (2,346)
Depletion, depreciation and
accretion (16,007) (3,595) (26,118) (9,703)
Current income tax expense (7,533) (684) (11,264) (1,790)
Future income tax recovery 8,830 - 8,830 -
----------------------------------------------------------------------------
Segment profit (2) 36,117 4,514 51,851 6,168
----------------------------------------------------------------------------
Daily natural gas sales (Mcf/d) 138,130 24,711 114,049 25,470
Daily oil sales (bbls/d) (1) 1,534 96 1,124 129
Operating costs (US$/Mcfe) 0.40 0.50 0.47 0.49
Depletion rate (US$/Mcfe) 1.17 1.49 1.17 1.96
----------------------------------------------------------------------------
(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 production from the Dhirubhai 1 and 3 gas fields in the D6 Block commenced in April 2009, resulting in a US$42.7 million and US$66.6 million increase in revenues in the quarter and year-to-date, respectively. The average natural gas sales volume from the D6 Block increased to 118 MMcf/d in the quarter from 66 MMcf/d in the quarter ended June 30, 2009. Production rates are expected to continue to ramp-up over the course of the year. The contracted sales price includes a gas price of US$4.20/MMBtu net and a marketing margin earned of US$0.135/MMBtu, resulting in a sales price, which is net of adjustments for heating value, of US$3.95/Mcf.

Oil production from the MA field in the D6 Block commenced in September 2008. Sales during the quarter and year-to-date averaged 1,323 bbls/d and 913 bbls/d and increased revenues by US$8.3 million and US$11.4 million, respectively. Oil production from the Hazira block averaged 211 bbls/d in the quarter and year-to-date compared to 96 bbls/d and 129 bbls/d in the 2008 periods, respectively. The average oil sales price for the blocks was US$68.00/bbl and US$67.12/bbl in the quarter and year-to-date, respectively, compared to US$118.36/bbl and US$114.99/bbl in the 2008 periods, respectively. Oil prices moved in accordance with world market prices.

The increase in royalties is a result of the commencement of revenues from the D6 Block since the prior year's quarter. Royalties applicable to production from the D6 Block are 5 percent for the first seven years of production and gas royalties applicable to the Hazira and Surat fields are currently 9 percent.

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 the D6 Block, the Company is able to use up to 90 percent of profits to recover costs including royalties, operating expenses and capital expenses. The government was entitled to 10 of the profits not used to recover costs during the quarter. Profit petroleum with respect to the D6 Block was US$0.5 million in the quarter and US$0.8 million year-to-date, which is one percent of revenues, and will continue at this level until the Company has recovered its costs. For Hazira, in the quarter and the prior year's quarter, the government was entitled to 25 percent of the profits, defined as revenue less royalties, operating expenses and capital expenditures. For Surat, the Company recovered its investment since the prior year's quarter and began sharing profits, defined as revenue less royalties, operating expenses and capital expenditures, with the government at a rate of 20 percent.

The net increase in profit petroleum in the quarter and year-to-date was primarily a result of profit petroleum payments commencing for Surat and was partially offset by decreased profit petroleum payments for Hazira due to a lower oil price and lower gas production than in the prior year's periods.

Operating Expenses

Operating expenses in the quarter and year-to-date increased with the commencement of D6 production. On a unit of production basis, average operating expenses have decreased from the prior year's periods and are expected to continue to decrease as the production from the D6 Block ramps up.

Depletion, Depreciation and Accretion

The depletion rate per Mcfe decreased in the quarter and year-to-date due to the inclusion of the capital costs and the reserves attributed to the D6 Block in the calculation for the Indian cost base. The undepleted capital costs per Mcfe are less for the D6 Block than for the Hazira and Surat fields.

Income Taxes

There was an increase in income tax expense in the quarter and year-to-date of US$6.8 million and US$9.5 million, respectively, on the profits from the D6 Block, which commenced since the prior year's periods. There was a future income tax recovery for a tax credit available for future years related to minimum alternative tax paid in the current year.

The Company has a contingency related to income taxes as at September 30, 2009. Refer to the unaudited consolidated financial statements and notes for the period ended September 30, 2009 for a complete discussion of the contingency.



BANGLADESH
Three months ended Six months ended
(thousands of U.S. dollars, except as September 30, September 30,
indicated) 2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas revenue 15,116 11,067 29,275 22,149
Profit petroleum (5,050) (3,669) (9,778) (7,336)
Operating and pipeline expenses (1,133) (835) (2,708) (1,956)
Depletion, depreciation and accretion (6,451) (4,807) (12,504) (9,407)
Current income tax expense (10) (8) (20) (29)
----------------------------------------------------------------------------
Segment profit (1) 2,472 1,748 4,265 3,421
----------------------------------------------------------------------------
Daily natural gas sales (Mcf/d) 68,524 50,184 66,934 50,493
Operating costs (US$/Mcfe) 0.18 0.18 0.22 0.21
Depletion rate (US$/Mcfe) 1.01 1.05 1.01 1.02
----------------------------------------------------------------------------
(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 and the Bangora-3 well, which came on-stream in June 2009. The Company receives 66.67 percent of production from Block 9 during the period in which it is recovering amounts paid in relation to the Government of Bangladesh's carried interest in the block. The Company's share will be reduced to 60 percent when the amounts are fully recovered, which is expected to occur in fiscal 2010.

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

Operating costs and depletion expense increased primarily as a result of increased production from Block 9 and were similar year-over-year on a unit-of-production basis.

NETBACKS

The following table outlines the Company's operating, funds from operations and earnings netbacks (all of which are non-GAAP measures) for the three and six months ended September 30, 2009 and 2008:



Three months ended Three months ended
September 30, 2009 September 30, 2008
----------------------------------------------------------------------------
India Bangladesh Total India Bangladesh Total
(US$/Mcfe) (US$/Mcfe)(US$/Mcfe)(US$/Mcfe)(US$/Mcfe)(US$/Mcfe)
----------------------------------------------------------------------------
Oil and natural
gas revenue 4.62 2.38 3.91 5.45 2.38 3.44
Royalties (0.28) - (0.19) (0.48) - (0.17)
Profit petroleum (0.18) (0.80) (0.39) (0.70) (0.79) (0.75)
Operating expense (0.40) (0.18) (0.33) (0.50) (0.18) (0.31)
----------------------------------------------------------------------------
Operating netback 3.76 1.40 3.00 3.77 1.41 2.21
Interest income 0.14 0.42
Interest and
financing expense (0.21) -
General and
administrative
expense (0.12) (0.28)
Realized foreign
exchange (loss) (0.01) (0.26)
Current income tax
(expense) recovery (0.40) 0.01
----------------------------------------------------------------------------
Funds from
operations netback 2.40 2.10
Unrealized foreign
exchange (loss) (0.24) (0.16)
Discount of long-term
account receivable - (0.01)
Stock-based
compensation
expense (0.18) (0.68)
Gain (loss) on
short-term
investment 0.99 (3.15)
Equity loss on
long-term
investment - (0.11)
Gain on risk
management
contracts - 0.05
Future income tax
recovery 0.44 -
Depletion, depreciation and
accretion expense (1.15) (1.25)
----------------------------------------------------------------------------
Earnings netback 2.26 (3.21)
----------------------------------------------------------------------------


Six months ended Six months ended
September 30, 2009 September 30, 2008
----------------------------------------------------------------------------
India Bangladesh Total India Bangladesh Total
(US$/Mcfe) (US$/Mcfe)(US$/Mcfe)(US$/Mcfe)(US$/Mcfe)(US$/Mcfe)
----------------------------------------------------------------------------
Oil and natural
gas revenue 4.62 2.37 3.82 5.34 2.38 3.43
Royalties (0.28) - (0.18) (0.45) - (0.16)
Profit petroleum (0.24) (0.79) (0.43) (0.71) (0.79) (0.76)
Operating expense (0.47) (0.22) (0.38) (0.49) (0.21) (0.32)
----------------------------------------------------------------------------
Operating netback 3.63 1.36 2.83 3.69 1.38 2.19
Interest income 0.08 0.50
Interest and
financing expense (0.22) -
General and
administrative
expense (0.12) (0.33)
Realized foreign
exchange (loss) (0.02) (0.08)
Current income
tax expense (0.34) (0.10)
----------------------------------------------------------------------------
Funds from
operations
netback 2.21 2.18
Unrealized
foreign exchange
(loss) (0.24) (0.24)
Discount of long-term
account receivable - (0.01)
Stock-based
compensation
expense (0.27) (0.65)
Gain (loss) on
short-term
investment 1.09 (1.06)
Equity loss on
long-term
investment - (0.06)
Gain on risk
management
contracts - 0.09
Future income tax
recovery 0.26 -
Depletion, depreciation
and accretion expense (1.15) (1.39)
----------------------------------------------------------------------------
Earnings netback 1.90 (1.14)
----------------------------------------------------------------------------


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



CORPORATE
Three months ended Six months ended
September 30, September 30,
(thousands of U.S. dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenues
Interest income 2,789 2,790 2,874 7,025
Gain (loss) on short-term investments 19,685 (22,046) 37,688 (15,171)
Gain on risk management contracts - 369 - 1,323
Expenses
Interest and financing expense 4,088 - 7,455 -
General and administrative expenses 2,445 1,946 3,976 4,662
Foreign exchange loss 4,988 2,954 9,197 4,566
Stock based-compensation expense 3,679 4,718 9,087 9,121
Equity loss on long-term investment - 778 91 778
Current income tax expense (recovery) 399 (780) 455 (379)
----------------------------------------------------------------------------


Interest Income

The Company received interest of US$2.7 million on an income tax refund in the quarter. Excluding the interest on the tax refund, interest income decreased primarily due to lower average cash balances and lower rates of interest earned during the quarter and year-to-date.

Gain on Short-term Investments

The unrealized gains on the investments during the quarter and year-to-date were on marking the short-term investments to market value. As at November 11, 2009, the market value of these investments has decreased significantly.

Gain on Risk Management Contracts

There were no interest rate swaps outstanding in the current fiscal period. In the prior year's periods, the Company had a series of interest rate swaps to fix the floating interest rate on a portion of the long-term debt, as required by the credit facility. There were unrealized gains in the prior year's periods on the recognition of the fair value of the interest rate swaps due to the increase in forecast LIBOR rates during the periods, which decreased the differential compared to the fixed interest rate.

Interest and Financing

The Company entered into a lease for the FPSO, which has been classified as a capital lease. As a result, the Company recognized US$1.6 million and US$2.5 million of lease payments as an interest cost in the quarter and year-to-date, respectively. Interest expense on the long-term debt was US$2.5 million and US$4.9 million in the quarter and year-to-date, respectively.

General and Administrative Expense

The net increase in general and administrative expense in the quarter from the prior year's quarter was a result of higher use of outside services as a result of increased Company activity. Year-to-date, there was a net decrease in general and administrative expense as a result of lower employee bonuses and increased overhead recoveries as a result of increased capital activities in Cauvery, Kurdistan and Madagascar.



Foreign Exchange
Three months ended Six months ended
September 30, September 30,
(thousands of U.S. dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Realized foreign exchange loss 230 1,950 857 1,287
Unrealized foreign exchange loss 4,758 1,004 8,340 3,279
----------------------------------------------------------------------------
Total foreign exchange loss 4,988 2,954 9,197 4,566
----------------------------------------------------------------------------


There was a realized foreign exchange loss in the quarter and year-to-date primarily on the settlement of Indian rupee-denominated working capital created by the weakening U.S. dollar against the Indian rupee applied to the settlement of working capital during the quarter.

The unrealized foreign exchange loss was primarily on the translation of U.S. dollar-held cash to Canadian dollars, partially offset by a gain on translating the Indian rupee-denominated income tax receivable to U.S. dollars as a result of the weakening of the U.S. dollar against the Canadian dollar and the Indian rupee, respectively.

Stock-based Compensation

Stock-based compensation decreased as a result of directors of the Company forfeiting a number of options during the quarter resulting in a credit of US$1.9 million. Excluding the effect of the forfeitures, stock-based compensation increased as a result of both an increased number of options being expensed during the quarter and an increased fair value expense per stock option.

Equity Loss on Long-term Investment

From inception to June 30, 2009, the Company accounted for its investment in Vast Exploration Inc. (Vast) using the equity method whereby the investment was initially recorded at cost and the carrying value was subsequently adjusted to include the Company's pro rata share of post-acquisition earnings of the investee. The Company recorded a loss of US$0.1 million year-to-date and US$0.8 million in the prior year's periods calculated by the equity method. Vast has issued additional common shares and the Company's shareholdings in Vast fell to 9 percent. Primarily as a result of this, the investment is no longer eligible for accounting under the equity method and the Company has reclassified the investment to short-term.

Income Taxes

Income taxes for the quarter and year-to-date are for the estimated Alberta tax applicable to foreign income.

In the prior year's periods, there was an income tax recovery related to an adjustment to taxes estimated in the year prior thereto partially offset by income taxes on interest income from cash balances outstanding resulting in a net income tax recovery.

SUMMARY OF QUARTERLY RESULTS

The following tables set forth selected financial information of the Company for the eight most recently completed quarters to September 30, 2009:



(thousands of U.S. dollars,
except per share amounts) Dec. 31, Mar. 31, June 30, Sept. 30,
Three months ended 2008 2009 2009 2009
----------------------------------------------------------------------------
Oil and natural gas revenue 28,045 28,503 53,853 77,879
Gain (loss) on short-term investments (8,898) (311) 18,003 19,685
Net income (loss) (2,090) (4,319) 20,441 45,043
Per share
Basic (US$) (0.04) (0.09) 0.41 0.91
Diluted (US$) (0.04) (0.09) 0.41 0.90
----------------------------------------------------------------------------

(thousands of U.S. dollars,
except per share amounts) Dec. 31, Mar. 31, June 30, Sept. 30,
Three months ended 2007 2008 2008 2008
----------------------------------------------------------------------------
Oil and natural gas revenue 22,467 23,576 24,381 24,064
Gain (loss) on short-term investment - 1,418 6,875 (22,046)
Net income (loss) 476 1,355 6,267 (22,420)
Per share
Basic (US$) 0.01 0.03 0.13 (0.46)
Diluted (US$) 0.01 0.03 0.13 (0.46)
----------------------------------------------------------------------------


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 investments.

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, 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. Gas production from the D6 Block commenced in the quarter ended June 30, 2009 and ramped-up during the quarter ended September 30, 2009, substantially increasing revenues in both quarters. Profit petroleum expense increased in the quarter ended December 31, 2008 with the increase in revenues from Block 9.

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.

In the quarter ended December 31, 2008, net income was reduced by US$4.2 million as the Company wrote the value of the long-term investment down to the Company's share of the book value of the investee's net assets.

The Company made purchases of securities in fiscal 2008 and fiscal 2009. The short-term investments are recognized at fair value, which is the publicly quoted market value, and the Company recognizes gains and losses based on the changing market prices. The net income in the quarters ended March 31, 2008 and June 30, 2008 and the net loss in the quarter ended September 30, 2008 are primarily a result of the gain or loss in the quarters. The losses continued through the quarter ended March 31, 2009. The net income in the quarter ended June 30, 2009 was primarily a result of the gain on the short-term investment in the quarter. In the quarter ended September 30, 2009, the long-term investment was reclassified to short-term. In the quarter, there was a gain on both investments based on the increase in their fair value.

Liquidity and Capital Resources

At September 30, 2009, the Company had total restricted and unrestricted cash of US$158.8 million and a working capital surplus of US$67.4 million, calculated as current assets less current liabilities. The restricted portion of the cash balance was comprised of US$7.7 million of performance guarantees, US$3.5 million of cash restricted for future site restoration and US$33.4 million of cash restricted in accordance with the credit facility agreement. The cash that is currently restricted in accordance with the credit facility agreement is a provision for 30 days of capital and 45 days of operating costs for Hazira, Surat, Block 9 and the Dhirubhai 1 and 3 gas field in the D6 Block and a debt service reserve account. The Company has drawn a total of US$192.8 million on its credit facility with a current portion of US$28.7 million. In April 2009, the credit facility was reduced to US$192.8 million.

The Company plans to fulfill its planned capital spending including commitments and current liabilities with existing cash and future funds from operations.

The Company has a number of contingencies as at September 30, 2009. Refer to the unaudited consolidated financial statements and notes for the quarter for a complete list of the contingencies and the potential effects on the liquidity of the Company.

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

The Company had the following work commitments under various agreements as at September 30, 2009:

- D4 Block: The commitment for Phase I exploration includes seismic work and drilling three exploration wells. Originally, the work commitment was to be completed by September 2009; however, the Government of India is in the process of approving a blanket extension of up to three years for this and other deepwater blocks, prompted by the shortage of deepwater drilling rigs. If the blanket extension is not approved, the Company will apply for an automatic one year extension. The seismic work has been completed and is ready for processing and the cost of the remaining seismic-related work and drilling is estimated at US$75.9 million (US$11.4 million net to the Company).

- Cauvery Block: The Phase I exploration period, which has been extended to March 2011, includes commitments for seismic work and drilling five exploration wells. The Company has completed the seismic and has drilled four exploration wells. The estimated cost of the remaining work commitment is US$2.5 million.

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

- Kurdistan: The Company has minimum work commitments under Phase I of the exploration period for seismic and drilling an exploratory well, which must be completed by May 2011. The remaining capital expenditures related to the minimum work program are estimated at US$21.8 million (US$10.1 million net to the Company) and US$0.6 million (US$0.3 million net to the Company) for various payments under the agreement.

- Madagascar: The Company has minimum work commitments for 2,000 kilometres of 2D seismic under Phase I of the exploration period, which expires in June 2010. The 2,000 line-kilometre commitment has been converted to acquisition of a multi-beam bathymetric survey combined with a seabed coring program and has been approved by OMNIS.

- Indonesia: For the Indonesian blocks, the remaining work commitments for interests acquired in eight PSCs include seismic for each block and one exploration well per block. The cost of the remaining minimum work commitments during the first exploration period are US$195.7 million (US$107.8 million net to the Company). This exploration period ends in November 2011 for five of the blocks and in May 2012 for the remaining three blocks.

- Trinidad: The Company signed an agreement to earn an interest in Block 2AB in Trinidad. The Company has minimum work commitments estimated to cost US$31.3 million to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells within three years.

The Company has planned spending of US$47 million (net to the Company) and US$35 million (net to the Company) related to Phase I development of the Dhirubhai 1 and 3 gas fields and the MA oil field, respectively, and these costs are included in the capital forecast for fiscal 2010.

Related Parties

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

FINANCIAL INSTRUMENTS

Financial instruments of the Company consist of cash, restricted cash, short-term investments, accounts receivable, long-term accounts receivable, accounts payable and accrued liabilities and long-term debt.

The Company is exposed to fluctuations in the value of its cash, accounts receivable, short-term investments, accounts payable and accrued liabilities due to changes in foreign exchange rates as these financial instruments are partially or wholly denominated in Canadian dollars, Indian rupees and Bangladeshi taka. The Company manages the risk by converting cash held in foreign currencies to U.S. dollars as required to fund forecast expenditures. The Company is exposed to changes in the market value of the short-term investments. The Company is exposed to changes in the LIBOR rate on the long-term debt. The Company is exposed to credit risk with respect to all of its financial instruments if a customer or counterparty fails to meet its contractual obligations. The Company has deposited the cash and restricted cash with reputable financial institutions, for which management believes the risk of loss to be remote. The Company takes measures in order to mitigate any risk of loss with respect to the accounts receivable, which may include obtaining guarantees. The Company is exposed to the risk of changes in market prices of commodities. The Company enters into physical commodity contracts for the sale of natural gas, which manages this risk. The Company does so in the normal course of business, including contracts with fixed terms. The contracts are not classified as financial instruments because the Company expects to deliver all required volumes under the contracts. No amounts are recognized in the consolidated financial statements related to the contracts until such time as the associated volumes are delivered. The Company is exposed to the change in the Brent crude price as the average Brent crude price from the preceding year is a variable in the gas price for the current year, calculated annually, for the D6 gas contracts.

The fair values of cash, restricted cash, accounts receivable and accounts payable and accrued liabilities approximate their carrying values due to their short periods to maturity. The fair value of the short-term investments is based on publicly quoted market values. An unrealized gain on the recognition of the short-term investments at fair value of US$19.7 million in the quarter was recognized in income. The fair value of the long-term account receivable is calculated based on the amount receivable discounted at 6.5 percent for three years as collection is assumed in three years. The loss on recognition of the fair value of the long-term account receivable of US$46,000 in the quarter was recognized in income. The fair value of the long-term debt is the amount of funds received by the Company.

CRITICAL ACCOUNTING ESTIMATES

The Company makes assumptions in applying certain critical accounting estimates that are uncertain at the time the accounting estimate is made and may have a significant effect on the financial statements of the Company. For a discussion of those critical accounting estimates, please refer to the MD&A for the Company's fiscal year ended March 31, 2009, available at www.sedar.com.

ACCOUNTING CHANGES IN FISCAL 2009

Effective April 1, 2009, the Company adopted the new accounting standard, Section 3064 "Goodwill and Intangible Assets", issued by the Canadian Institute of Chartered Accountants (CICA), replacing Sections 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. Adoption of this section did not have an impact on the Company.

FUTURE ACCOUNTING CHANGES

Effective April 1, 2011, the Company will replace current Canadian accounting standards and interpretations, or GAAP, with International Financial Reporting Standards (IFRS) as required by the Canadian Accounting Standards Board. The employees of the Company participated in continuing education courses over the past year and consulted with a peer group to discuss implementation issues. The Company has prepared a planning and scoping document that identifies the differences between GAAP and IFRS that are applicable to the Company and sets out the steps to evaluate the differences and convert the financial statements prepared under Canadian GAAP to IFRS.

DISCLOSURE CONTROLS AND PROCEDURES

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

INTERNAL CONTROLS OVER FINANCIAL REPORTING

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

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

There were no changes in the internal controls over financial reporting during the three and six months ended September 30, 2009 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

RISK FACTORS

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

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

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

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

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

- Changing taxation policies, taxation laws and interpretations thereof;

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

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

- Changes in foreign exchange rates that impact the Company's non-U.S. dollar transactions; and

- Changes in future oil and natural gas prices.

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

The Company has a number of contingencies as at September 30, 2009. Refer to the notes to the Company's unaudited consolidated financial statements for a complete list of the contingencies and any potential effects on the Company.



OUTSTANDING SHARE DATA

At November 11, 2009, the Company had the following outstanding shares:

Number Cdn $ Amount (1)
----------------------------------------------------------------------------
Common shares 49,684,383 $ 1,204,822,000
Preferred shares nil nil
Stock options 3,862,875 -
----------------------------------------------------------------------------
(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 November 11, 2009 is US$1,052,811,000.


OUTLOOK

With 23 exploration blocks in 6 countries, the Company is embarking upon the most significant exploration program in its history.

On behalf of the Board of Directors,

Edward S. Sampson

Chairman of the Board, President and CEO

November 11, 2009




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

As at As at
September 30, 2009 March 31, 2009
ASSETS
Current assets
Cash and cash equivalents $ 114,232 $ 31,189
Restricted cash (note 3) 30,269 185,475
Short-term investments (note 4) 53,242 9,067
Accounts receivable 31,072 20,287
Inventory 308 616
Prepaid expenses 1,252 1,494
----------------------------------------------------------------------------
230,375 248,128
----------------------------------------------------------------------------
Restricted cash (note 3) 14,333 24,011
Long-term investment (note 5) - 4,216
Long-term accounts receivable 22,541 22,201
Income tax receivable 18,315 16,000
Future income tax asset 8,830 -
Property and equipment 1,279,542 1,154,074
----------------------------------------------------------------------------
$ 1,573,936 $ 1,468,630
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 121,570 $ 119,555
Current portion of capital lease obligation 10,752 10,752
Current portion of long-term debt 28,685 -
Current tax payable 1,950 2,691
----------------------------------------------------------------------------
162,957 132,998
----------------------------------------------------------------------------
Asset retirement obligation 28,591 27,544
Capital lease obligation 55,570 57,984
Long-term debt 164,129 192,814
----------------------------------------------------------------------------
411,247 411,340
----------------------------------------------------------------------------
Shareholders' equity
Share capital (note 6) 1,023,319 1,001,885
----------------------------------------------------------------------------
Contributed surplus (note 7) 56,890 51,966
----------------------------------------------------------------------------
Accumulated other comprehensive income (loss)
(note 8) 14,001 (2,406)
Retained earnings 68,479 5,845
----------------------------------------------------------------------------
82,480 3,439
----------------------------------------------------------------------------
1,162,689 1,057,290
----------------------------------------------------------------------------
$ 1,573,936 $ 1,468,630
----------------------------------------------------------------------------
Segmented information (note 10)
Guarantees (note 11)
Commitments and contractual obligations
(note 12)
Contingencies (note 13)

See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENTS OF OPERATIONS,
COMPREHENSIVE INCOME AND RETAINED EARNINGS
----------------------------------------------------------------------------
THREE AND SIX MONTHS ENDED SEPTEMBER 30, (UNAUDITED)
(THOUSANDS OF U .S. DOLLARS, EXCEPT PER SHARE AMOUNTS)

Three months ended Six months ended
September 30, September 30,
2009 2008 2009 2008
Revenue
Oil and natural gas $ 77,879 $ 24,064 $131,732 $ 48,445
Royalties (3,751) (1,169) (6,272) (2,324)
Profit petroleum (7,759) (5,289) (14,983) (10,767)
Gain (loss) on short-term
investments 19,685 (22,046) 37,688 (15,171)
Interest 2,789 2,790 2,874 7,025
Gain on risk management contracts - 369 - 1,323
----------------------------------------------------------------------------
$ 88,843 $ (1,281) $151,039 $ 28,531
----------------------------------------------------------------------------
Expenses
Operating 6,505 2,039 13,112 4,358
Interest and financing 4,088 - 7,455 -
General and administrative 2,445 1,946 3,976 4,662
Foreign exchange loss 4,988 2,954 9,197 4,566
Discount of long-term account
receivable 46 79 94 179
Stock-based compensation 3,679 4,718 9,087 9,121
Equity loss on long-term investment - 778 91 778
Depletion, depreciation and
accretion 22,937 8,713 39,634 19,580
----------------------------------------------------------------------------
44,688 21,227 82,646 43,244
----------------------------------------------------------------------------
Income before income taxes 44,155 (22,508) 68,393 (14,713)

Current income tax expense
(recovery) 7,942 (88) 11,739 1,440
Future income tax (recovery) (8,830) - (8,830) -
----------------------------------------------------------------------------
Income tax (recovery) expense (888) (88) 2,909 1,440

----------------------------------------------------------------------------
Net income (loss) $ 45,043 $(22,420) $ 65,484 $(16,153)
----------------------------------------------------------------------------
Net income (loss) per share
(note 9)
Basic $ 0.91 $ (0.46) $ 1.32 $ (0.33)
Diluted $ 0.90 $ (0.46) $ 1.31 $ (0.33)
----------------------------------------------------------------------------

Net income (loss) 45,043 (22,420) 65,484 (16,153)
Foreign currency translation gain
(loss) 9,209 (12,581) 16,407 (8,405)
----------------------------------------------------------------------------
Comprehensive income (loss)
(note 8) $ 54,252 $(35,001) $ 81,891 $(24,558)
----------------------------------------------------------------------------

Retained earnings, beginning of
period 24,927 38,288 5,845 33,472
Net income (loss) 45,043 (22,420) 65,484 (16,153)
Dividends paid (1,491) (1,386) (2,850) (2,837)
----------------------------------------------------------------------------
Retained earnings, end of period $ 68,479 $ 14,482 $ 68,479 $ 14,482
----------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.


CONSOLIDATED STATEMENTS OF CASH FLOWS
----------------------------------------------------------------------------
THREE AND SIX MONTHS ENDED SEPTEMBER 30, (UNAUDITED)
(THOUSANDS OF U.S. DOLLARS)

Three months ended Six months ended
September 30, September 30,
2009 2008 2009 2008

Cash provided by (used in):
Operating activities
Net income (loss) $ 45,043 $(22,420) $ 65,484 $ (16,153)
Add items not involving cash
from operations:
Unrealized foreign exchange
loss 4,758 1,004 8,340 3,279
Discount of long-term account
receivable 46 79 94 179
Stock-based compensation 3,679 4,718 9,087 9,121
Unrealized (gain) loss on short-term
investments (19,685) 22,046 (37,688) 15,171
Equity loss on long-term
investment - 778 91 778
Unrealized (gain) on risk
management contracts - (369) - (1,323)
Depletion, depreciation and
accretion 22,937 8,713 39,634 19,580
Future income tax (recovery) (8,830) - (8,830) -
Change in non-cash working
capital (6,790) (13) (11,389) (3,986)
Change in long-term accounts
receivable (1,566) (1,219) (1,891) (1,246)
----------------------------------------------------------------------------
39,592 13,317 62,932 25,400
----------------------------------------------------------------------------
Financing activities
Proceeds from issuance of
shares, net of issuance costs
(note 6) 2,150 793 15,787 8,519
Dividends paid (1,491) (1,386) (2,850) (2,837)
----------------------------------------------------------------------------
659 (593) 12,937 5,682
----------------------------------------------------------------------------
Investing activities
Addition of property and
equipment (88,116) (101,092) (161,314) (211,276)
Reduction in capital lease
obligations (1,342) - (2,037) -
Restricted cash contributions (23,283) (8,187) (71,270) (10,804)
Restricted cash returned 120,786 5,326 236,154 13,430
Addition to short-term
investments - - - (14,714)
Disposition of short-term
investments 1,054 - 1,054 -
Addition to long-term
investment - - - (11,378)
Change in non-cash working
capital 35,635 (154) 2,438 2,207
Change in cash call advances - (24,778) 103 (24,433)
----------------------------------------------------------------------------
44,734 (128,885) 5,128 (256,968)
----------------------------------------------------------------------------
Increase (decrease) in cash 84,985 (116,161) 80,997 (225,886)
Effect of foreign currency
translation on cash
and cash equivalents 945 (6,627) 2,046 (2,963)
Cash and cash equivalents,
beginning of period 28,302 337,828 31,189 443,889
----------------------------------------------------------------------------
Cash and cash equivalents, end
of period $114,232 $215,040 $114,232 $215,040
----------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the six months ended September 30, 2009 (unaudited).
All tabular amounts are in thousands of U.S. dollars except per share
amounts, numbers of shares/stock options, stock option and share prices,
and certain other figures as indicated.


1. BASIS OF PRESENTATION

The interim consolidated financial statements of Niko Resources Ltd. (the "Company") have been prepared in accordance with Canadian generally accepted accounting principles. The interim consolidated financial statements have been prepared following the same accounting policies and methods of application as the audited consolidated financial statements for the fiscal year ended March 31, 2009, except as discussed in note 2. The disclosures provided herein are incremental to those included with the annual consolidated financial statements and the notes thereto for the year ended March 31, 2009. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto for the year ended March 31, 2009.

Certain comparative figures have been reclassified to conform to the current period's presentation and to conform to the Company's use of the U.S. dollar as its reporting currency.

2. CHANGES IN ACCOUNTING POLICIES

Effective April 1, 2009, the Company adopted the new accounting standard, Section 3064 "Goodwill and Intangible Assets", issued by the Canadian Institute of Chartered Accountants, replacing Sections 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs".

Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. Adoption of this section did not have an impact on the Company.

3. RESTRICTED CASH

At September 30, 2009, the restricted cash balance included in current assets is comprised of guarantees of US$7.7 million (March 31, 2009 - nil) (see note 11) and US$22.6 million (March 31, 2009 - US$185.5 million) that is restricted as per provisions of the credit facility. A portion of the cash that was restricted at March 31, 2009 with respect to the facility agreement was released during the period when the Dhirubhai 1 and 3 gas field project was completed as defined in the credit facility. The cash that continues to be restricted is a provision for 30 days of capital and 45 days of operating costs for Hazira, Surat, Block 9 and the Dhirubhai 1 and 3 gas field in the D6 Block.

The restricted cash balance included in non-current assets includes US$3.5 million (March 31, 2009 - US$3.5 million) of cash that is legally restricted for future site restoration in India, US$10.8 million (March 31, 2009 - US$7.0 million) that is restricted as per provisions of the credit facility in the amount of a debt service reserve account and nil (March 31, 2009 - US$13.5 million) for guarantees.

4. SHORT-TERM INVESTMENTS

The short-term investments consist of marketable securities with a fair value at September 30, 2009 of US$53.2 million, which decreased significantly subsequent to September 30, 2009.

5. LONG-TERM INVESTMENT

From inception to June 30, 2009, the Company accounted for its investment in Vast Exploration Inc (Vast) using the equity method whereby the investment was initially recorded at cost and the carrying value was subsequently adjusted to include the Company's pro rata share of post-acquisition earnings of the investee. Vast has issued additional common shares and the Company's shareholdings in Vast fell to 9 percent. As a result, the investment is no longer eligible for accounting under the equity method and the Company has reclassified the investment as a held for trading financial instrument, which is recognized at fair value on the balance sheet with unrealized gains and losses recognized in income.

6. SHARE CAPITAL

(a) Authorized

Unlimited number of common shares

Unlimited number of preferred shares



(b) Issued

Six months ended Year ended
September 30, 2009 March 31, 2009
----------------------------------------------------------------------------
Amount Amount
Number (US$000s) Number (US$000s)
----------------------------------------------------------------------------
Common shares
Balance, beginning of period 49,298,133 $1,001,885 49,054,408 $ 986,050
Stock options exercised 362,750 15,787 243,725 11,615
Transferred from contributed
surplus on exercise - 5,647 - 4,220
----------------------------------------------------------------------------
Balance, end of period 49,660,883 $1,023,319 49,298,133 $1,001,885
----------------------------------------------------------------------------


(c) Stock Options

The Company has reserved for issue 4,966,088 common shares for granting under stock options to directors, officers, and employees.

The options become 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:

Six months ended Year ended
September 30, 2009 March 31, 2009
----------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price (Cdn$) Options Price (Cdn$)
----------------------------------------------------------------------------
Outstanding, beginning of
period 4,030,750 64.69 3,219,725 65.02
Granted 362,500 69.82 1,368,313 60.33
Forfeited (133,000) 86.28 (18,250) 83.11
Expired (15,750) 93.06 (295,313) 58.39
Exercised (362,750) 50.06 (243,725) 50.85
----------------------------------------------------------------------------
Outstanding, end of period 3,881,750 66.02 4,030,750 64.69
Exercisable, end of period 924,562 57.96 1,132,562 54.02
----------------------------------------------------------------------------


The following table summarizes stock options outstanding and exercisable
under the plan at September 30, 2009:

Outstanding Options Exercisable Options
Remaining Weighted Weighted
Life Average Average
Exercise Price Options (Years) Price (Cdn$) Options Price (Cdn$)
----------------------------------------------------------------------------
$ 41.00 - $ 49.90 1,426,938 2.5 47.59 372,500 43.29
$ 52.80 - $ 59.87 558,249 0.9 53.69 244,062 53.70
$ 60.00 - $ 69.82 392,375 2.0 63.14 126,500 63.67
$ 71.00 - $ 79.88 95,250 2.3 76.73 11,250 79.69
$ 80.00 - $ 89.99 705,313 3.1 84.99 44,500 82.77
$ 90.40 - $ 99.68 701,875 2.3 94.32 125,500 93.19
$105.00 - $105.47 1,750 2.1 105.27 250 105.47
----------------------------------------------------------------------------
3,881,750 2.3 66.02 924,562 57.96
----------------------------------------------------------------------------


7. CONTRIBUTED SURPLUS

----------------------------------------------------------------------------
Six months ended Year ended
(thousands of U.S. dollars) September 30, 2009 March 31, 2009
----------------------------------------------------------------------------
Contributed surplus, beginning of period $ 51,966 $ 34,952
Stock-based compensation 10,571 21,234
Stock options exercised (5,647) (4,220)
----------------------------------------------------------------------------
Contributed surplus, end of period $ 56,890 $ 51,966
----------------------------------------------------------------------------


8. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

----------------------------------------------------------------------------
Six months ended Year ended
(thousands of U.S. dollars) September 30, 2009 March 31, 2009
----------------------------------------------------------------------------
Accumulated other comprehensive income
(loss), beginning of period $ (2,406) $ 40,989
Other comprehensive income (loss):
Foreign currency translation gain (loss) 16,407 (43,395)
----------------------------------------------------------------------------
Accumulated other comprehensive income
(loss), end of period $ 14,001 $ (2,406)
----------------------------------------------------------------------------


9. EARNINGS PER SHARE

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

Three months ended Six months ended
September 30, September 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Weighted average number of
common shares outstanding
- basic 49,614,008 49,178,950 49,522,258 49,137,783
- diluted 50,074,105 49,178,950 49,887,041 49,137,783
----------------------------------------------------------------------------


10. SEGMENTED INFORMATION

----------------------------------------------------------------------------
(thousands of Three months ended Three months ended
U.S. dollars) September 30, 2009 September 30, 2008
----------------------------------------------------------------------------
Segment Segment
Profit Capital Profit Capital
Segment Revenue (Loss) Additions Revenue (Loss) Additions
----------------------------------------------------------------------------
Bangladesh $ 15,116 $ 2,472 $ 915 $ 11,067 $ 1,748 $ 8,453
India 62,594 36,117 42,650 12,690 4,514 78,310
Indonesia - - 11,713 - - 10,197
Kurdistan - - 32,322 - - 3,075
Madagascar - - 237 - - -
Pakistan - - 270 - - 288
All other (1) 169 (774) 9 307 680 769
----------------------------------------------------------------------------
Total $ 77,879 $ 37,815 $ 88,116 $ 24,064 $ 6,942 $101,092
----------------------------------------------------------------------------
(1) Revenues included in All other are from Canadian oil sales net of
royalties.


(thousands of Six months ended Six months ended
U.S. dollars) September 30, 2009 September 30, 2008
----------------------------------------------------------------------------
Segment Segment
Profit Capital Profit Capital
Segment Revenue (Loss) Additions Revenue (Loss) Additions
----------------------------------------------------------------------------
Bangladesh $ 29,275 $ 4,265 $ 8,778 $ 22,149 $ 3,421 $ 10,792
India 102,182 51,851 95,002 25,652 6,168 170,402
Indonesia - - 17,300 - - 10,197
Kurdistan - - 38,829 - - 17,925
Madagascar - - 715 - - -
Pakistan - - 312 - - 882
All other (1) 275 (1,294) 378 644 387 1,078
----------------------------------------------------------------------------
Total $131,732 $ 54,822 $161,314 $ 48,445 $ 9,976 $211,276
----------------------------------------------------------------------------
(1) Revenues included in All other are from Canadian oil sales net of
royalties.


(thousands of U.S.
dollars) As at September 30, 2009 As at March 31, 2009
----------------------------------------------------------------------------
Property and Property and
Segment Equipment Total Assets Equipment Total Assets
----------------------------------------------------------------------------
Bangladesh $ 135,211 $ 191,612 $ 138,667 $ 170,405
India 1,014,642 1,112,336 944,881 1,170,524
Indonesia 33,476 42,011 15,896 28,181
Kurdistan 63,860 64,278 24,579 28,477
Madagascar 5,136 5,517 4,393 5,826
Pakistan 23,231 23,250 22,863 22,932
All other 3,986 134,932 2,795 42,285
----------------------------------------------------------------------------
Total $ 1,279,542 $ 1,573,936 $ 1,154,074 $ 1,468,630
----------------------------------------------------------------------------
(1) Revenues included in All other are from Canadian oil sales net of
royalties.


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

Three months ended Six months ended
September 30, September 30,
(thousands of U.S. dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Segment profit $ 37,815 $ 6,942 $ 54,822 $ 9,976
Interest income 2,789 2,790 2,874 7,025
Interest and financing expense (4,088) - (7,455) -
General and administrative expenses (2,445) (1,946) (3,976) (4,662)
Foreign exchange (loss) (4,988) (2,954) (9,197) (4,566)
Discount of long-term account
receivable (46) (79) (94) (179)
Stock-based compensation expense (3,679) (4,718) (9,087) (9,121)
Gain (loss) on short-term
investments 19,685 (22,046) 37,688 (15,171)
Equity (loss) on long-term
investment - (778) (91) (778)
Gain on risk management contracts - 369 - 1,323
----------------------------------------------------------------------------
Net income (loss) $ 45,043 $(22,420) $ 65,484 $(16,153)
----------------------------------------------------------------------------


11. GUARANTEES

As at September 30, 2009, the Company had performance security guarantees of US$3.4 million for Cauvery, US$0.6 million for the D4 block, US$9.7 million for Indonesia and US$1.2 million for Madagascar. The current portion of restricted cash includes US$0.4 million of the Cauvery guarantee and US$7.3 million for Indonesian guarantees related to upcoming seismic work. The seismic guarantees will be returned when contracts for seismic work are signed by the Company. The remaining guarantees mentioned above are not reflected on the balance sheet as they are supported by Export Development Canada.

12. COMMITMENTS AND CONTRACTUAL OBLIGATIONS

The Company has commitments for approved budgets and development plans under various joint venture agreements.

The material commitments incurred since March 31, 2009 are:

In May 2009, the Company acquired interests in three additional blocks in Indonesia. The Company has minimum work commitments and other payments under the production sharing contract for the first exploratory period, which expires in May 2012, of US$51.0 million related to acquisition of 4,042 kilometres of 2D seismic, 1,200 square kilometres of 3D seismic, drilling one well per block and various payments under the agreements.

In July 2009, the Company signed an agreement to earn an interest in Block 2AB in Trinidad. The assignment of the interest is subject to approval from the government of Trinidad and Tobago. The Company has minimum work commitments estimated to cost US$31.3 million to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells within three years.

13. CONTINGENCIES

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

The petitioners are requesting the following of the Supreme Court with respect to the Company:

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

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

(iii) that Petrobangla withhold future payments to the Company relating to production from the Feni field (US$27.3 million as at September 30, 2009); and

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

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

With respect to the fourth issue, the Company's Bangladesh branch has been permitted to make payments to Bangladesh vendors.

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

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

(i) taka 369,196,000 (US$5.3 million) for 3 Bcf of free natural gas delivered from the Feni field as compensation for the burnt natural gas;

(ii) taka 724,854,000 (US$10.3 million) for 5.89 Bcf of free natural gas delivered from the Feni field as compensation for the subsurface loss;

(iii) taka 845,560,000 (US$12.0 million) for environmental damages, an amount subject to be increased upon further assessment;

(iv) taka 5,537,936,000 (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 eligible undertakings related to the Hazira and Surat fields.

The Company has received unfavourable tax assessments related to taxation years 1999 through 2006. The assessments contend that the Company is not eligible for the requested tax holiday because: a) the holiday only applies to "mineral oil" which excludes natural gas; and/or b) the Company has inappropriately defined undertakings. The 2007 and 2008 taxation years have not yet been assessed.

In India, there are potentially four levels of appeal related to tax assessments: Commissioner Income Tax Authority ("CITA"); the Income Tax Appellate Tribunal ("ITAT"); the High Court; and the Supreme Court.

For taxation years 1999 to 2004, the Company has received favourable rulings at ITAT and the Revenue Department has appealed to the High Court. For the 2005 taxation year, the Company has received a favourable ruling at CITA and for the 2006 taxation year, the Company's CITA appeal is pending.

In August 2009, the Government of India passed into law a new Finance (No.2) Bill 2009 amending the tax holiday provisions in the Income Tax Act (Act).

The amended Act provides that the blocks licensed under the NELP-VIII round of bidding and starting commercial production on or after April 1, 2009 are eligible for the tax holiday on production of natural gas. However, the budget did not address the issue of whether the tax holiday is applicable to natural gas production from blocks that have been awarded under previous rounds of bidding, which includes all of the Company's Indian blocks. The Company has previously filed and recorded its income taxes on the basis that natural gas will be eligible for the tax holiday.

With respect to "undertakings" eligible for the tax holiday deduction, the Act was amended to include an "explanation" on how to determine undertakings. The act now states that all blocks licensed under a single contract shall be treated as a single undertaking. The "explanation" is described in the amendment as having retrospective effect from April 1, 2000. Since tax holiday provisions became effective April 1, 1997, it is unclear as to why the "explanation" has effect from April 1, 2000. The Hazira production sharing contract (PSC) was signed in 1994 and commenced production prior to April 1, 2000. As a result, an anomalous situation has been created and the Company is unable to apply the amended definition of "undertaking" to the Hazira PSC. The Company has previously filed and recorded its income taxes for the taxation years of 1999 to 2008 on the basis of multiple undertakings for the Hazira and Surat PSC.

The Company will continue to pursue both issues through the appeal process. The Company's partner in the Hazira PSC, who was also filing tax returns with multiple undertakings in the Hazira PSC, was recently granted an interim relief by the High Court. The interim relief instructed the Revenue Department to not give effect to the "explanation" referred to above until the matter is clarified in the courts. Even if the Company receives favourable outcomes with respect to both issues discussed above, the Revenue Department can challenge other aspects of the Company's tax filings.

For the taxation year ending March 31, 2009, the Company has filed its tax return assuming natural gas is eligible for the tax holiday at Hazira and Surat but, unlike all previous years, has filed its tax return based on Hazira and Surat each having a single undertaking. The Company has reserved its right, under Indian tax law, to claim the tax holiday with multiple undertakings. While the Company still believes that it is eligible for the tax holiday on multiple undertakings, the change in method of filing is because the legislative changes, referred to above, lead to ambiguity in the Act. More specifically, if the Company files in a manner that it deemed to be in violation of the current legislation, the Company can be liable for interest and penalties. As a result, the Company has filed in a more conservative manner than is its interpretation of tax law as described previously. Despite filing in a conservative manner, the Company will continue to pursue the tax holiday changes through the appeals process.

Should the High Court overturn the rulings previously awarded in favour of the Company by the Tribunal court, and the Company either decide not to appeal to the Supreme Court or appeals to the Supreme Court and lose, the Company would record a tax expense of approximately US$65.2 million, pay additional taxes of US$48.2 million and write off approximately US$17.3 million of the net income tax receivable. In addition, the Company could be obligated to pay interest on taxes for the past periods.

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

Contact Information

  • Niko Resources Ltd.
    Edward S. Sampson
    Chairman of the Board, President and CEO
    (403) 262-1020
    www.nikoresources.com