Niko Resources Ltd.
TSX : NKO

Niko Resources Ltd.

February 12, 2010 06:00 ET

Niko Reports Results for the Three and Nine Month Period Ended December 31, 2009

CALGARY, ALBERTA--(Marketwire - Feb. 12, 2010) - Niko Resources Ltd. ("Niko" or "the Company") (TSX:NKO) is pleased to report its financial and operating results, including interim consolidated financial statements and notes thereto, as well as its management's discussion and analysis, for the three and nine month period ended December 31, 2009, the third quarter of Niko's fiscal year. The operating results are effective February 11, 2010.

PRESIDENT'S REPORT TO SHAREHOLDERS

HIGHLIGHTS

Exploration

- Three successful wells, AJ2, AJ3 and AJ5 were drilled and confirmed the significant hydrocarbon potential of NEC-25. A fourth well, AJ6, is currently being drilled and with success will add to the growing potential of the AJ area, which is located in deeper water in the southern part of the block.

- The BA-1-A exploration/appraisal well is currently being drilled approximately 80 kilometres south of the Dhirubhai 1 and 3 gas fields and is the southernmost location drilled to date in the D6 Block. This well is targeted to test multiple reservoir zones.

- The AB1 exploration/appraisal well is currently being drilled approximately 30 kilometres east of the Dhirubhai 1 and 3 gas fields to further evaluate the extent of the various gas discoveries including the deeper stratigraphic section of the gas bearing sands found in the R1 discovery.

- The approximately 10,000 square kilometre multi-beam survey in Madagascar is underway and will be completed in March 2010.

New Ventures

- The December 30, 2009 acquisition of Black Gold Energy LLC increased Niko's interest in the Indonesian blocks resulting in Niko becoming one of the largest holders of deepwater exploration acreage in Indonesia with current holdings of 11.8 million net acres. The cash cost of the acquisition was approximately US$282 million and was funded largely through the issuance of convertible debentures.

- In December 2009, the assignment to Niko of 26 percent interest and operatorship of the shallow water Block 2AB offshore Trinidad was approved by the Government of Trinidad and Tobago.

- On February 6, 2010, Niko executed an agreement to acquire a private company with interests in five production sharing contracts (PSC) in Trinidad including Block 2AB.



Production and Development

Three months ended Nine months ended
December 31, December 31,
2009 2008 2009 2008
----------------------------------------------------------------------------
Average daily sales volumes
Oil and condensate (bbls/d) 1,304 778 1,254 402
Natural gas (Mcf/d) 250,102 85,316 204,106 79,093
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Total combined (Mcfe/d) 257,929 89,986 211,630 81,507
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- The design capacity test of the D6 gas production facilities confirmed capability for a flow rate of 2,800 MMcf/d (280 MMcf/d working interest to the Company).

- The Company's share of D6 gas production increased to 161 MMcf/d in the quarter, which is a 37 percent increase over the previous quarter. Current D6 gas production is approximately 210 MMcf/d and the Company expects production to increase to design capability as additional contracts are signed with customers already approved by the Government of India.



Financial

Three months ended Nine months ended
December 31, December 31,
(thousands of U.S. dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Oil and natural gas revenue 91,757 28,045 223,489 76,490
Funds from operations 68,806 19,515 145,018 50,147
(Loss) gain on short-term
investments (26,525) (8,897) 11,163 (24,068)
Net income (loss) 14,637 (2,090) 80,121 (18,243)
Capital expenditures 24,053 96,829 185,367 308,105
Corporate acquisition 281,637 - 281,637 -
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- Unrestricted cash increased to US$140 million at December 31, 2009 from US$114 million at the beginning of the quarter.

- Quarterly funds from operations was US$68.8 million, which is a 44 percent increase over the previous quarter.

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/212nko.pdf

Gas production from the D6 Block commenced in April 2009 and has steadily increased Niko's total production. Production from the D6 Block in the quarter averaged 161 MMcf/d and is currently at approximately 210 MMcf/d. Assuming D6 production remains at this level, average Company-wide production for the fiscal year would approximate 233 MMcfe/d, which is a 174 percent increase over fiscal 2009.

The design capacity test of the D6 gas production facilities confirmed capability for a flow rate of 2,800 MMcf/d (280 MMcf/d working interest to the Company). The Empowered Group of Ministers (EGOM) has allocated firm and best efforts contracts in excess of design capability. The company currently has gas sales contracts for 210 MMcf/d. The Company will proceed to sign additional gas sales contracts and depending on the timing, could increase expected annual production.

The Company's share of oil sales from the MA field in the quarter was 1,000 bbls/d. Production in the quarter was from three wells. Two additional wells are expected to come online by the end of February 2010.

Gas production from Block 9 increased to 120 MMcf/d (80 MMcf/d working interest to the Company) in mid-October 2009, primarily as a result of a work over that was conducted on Bangora-3 in September 2009 to complete an additional sand. The timing of the increase from Bangora-3 and the decreased production during well testing resulted in average production for the quarter of 108 MMcf/d (69 MMcf/d working interest to the Company). The Company received 66.67 percent of production from Block 9 during the period in which it was recovering amounts paid in relation to the Government of Bangladesh's carried interest in the block. The amounts were fully recovered in November 2009 and the Company's share of production is now 60 percent.

Development

D6 Block

Dhirubhai 1 and 3 Gas Development: The scope of work under Phase I of the gas development project has been completed.

MA Oil Development: Two additional wells have been completed and are expected to come online by the end of February 2010.

Future Development: There have been several gas discoveries in addition to Dhirubhai 1 and 3. A development plan for nine such discoveries was submitted to the Government of India in July 2008, however, based on the Government's advice, in December 2009 the plan was modified to begin with four rather than nine discoveries. Additional development plans can be expected in the future.

Exploration

India

D6 Block: Two exploration/appraisal wells, BA-1-A and AB1, are currently being drilled in the D6 Block. BA-1-A is being drilled in the deeper water southern part of the block and will evaluate the hydrocarbon potential of multiple reservoir zones from the Pliocene through to lower Miocene time. The AB1 well will further evaluate the extent of the gas discovered in the AA and F wells and in addition, the AB1 well will test the deeper stratigraphic section equivalent of the gas bearing sands found in the R1 discovery. Six additional exploration/appraisal wells related to five of the discoveries to date are expected to be drilled in the coming year.

D4 Block: The block area is covered with 4,500 kilometres of 2D seismic and 3,600 square kilometers of 3D seismic. Extensive seismic interpretation was carried out and integrated with the regional dataset. Analysis brought out possible leads and three drilling locations have been selected. Drilling is planned to commence in the third calendar quarter of 2010.

Cauvery: 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 was 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 the seismic resulted in a three-well drilling program targeting three separate play types. The first well is expected to spud in February 2010.

NEC-25 Block: The six well drilling program is in progress. The first three wells, AJ2, AJ3 and AJ5 were successful and confirmed significant hydrocarbon potential for NEC-25. The fourth well, AJ6, is currently being drilled and with success would add to the growing prospectivity of the AJ area. To date, there have been a total of 11 discoveries on this block. A development plan was previously submitted for six of the discoveries. A separate commerciality report for the successful AJ wells will be prepared when drilling is completed.

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

The approximately 10,000 square kilometre multi-beam survey is underway and will be completed in March 2010. This will be immediately followed by coring of the seabed utilizing Niko's unique SeaSeepTM technology. Coring will occur at locations determined by the multi-beam survey. All multi-beam and coring work is expected to be completed by April 2010.

A seismic vessel is due to arrive and start a 3,000-square-kilometre 3D survey in April 2010. The program is expected to take approximately three months. The Company expects to drill a well in the second half of calendar 2012.

Kurdistan

The rig that will be used to drill the first well is expected to arrive on location in late March 2010. Lease preparation is near completion.

Indonesia

Niko has acquired interests in twelve deepwater offshore blocks in 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. Most of the blocks have a seismic commitment and nine of the blocks have a single well commitment.

Niko acquired Black Gold Energy LLC (Black Gold) in December 2009, resulting in increased interests in many of the blocks. The Company's interests are outlined below:



Block Offshore Area Niko's interest
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West Sageri(1) Makassar Strait 100%
SE Ganal(1) Makassar Strait 100%
Seram(1) Seram North 100%
South Matindok(1) Sulawesi NE 100%
Bone Bay Sulawesi SW 45%
Kofiau(1) West Papua 100%
Kumawa Papua SW 45%
Cendrawasih Papua NW 45%
Halmahera-Kofiau(1) Papua W 80%(2)
West Papua IV(1) Papua SW 80%(2)
East Bula(1) Seram NE 100%
North Makassar Makassar Strait 50%
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(1) Operated by the Company.
(2) The Company farmed out 20 percent of its interest subsequent to the
acquisition of Black Gold.


The 2D seismic programs for West Sageri, SE Ganal, South Matindok, Bone Bay and Kofiau are complete and the 2D seismic program for Kumawa is in progress. A total of 9,500 kilometres has been acquired of the 22,100 kilometre 2D seismic program planned for all blocks.

The 3D seismic programs for the West Sageri and SE Ganal blocks totaling 3,100 square kilometres have been acquired. A further 7,100 square kilometers of 3D seismic acquisition is planned for the remaining blocks.

The remaining 2D and 3D seismic is expected to be completed by the middle of calendar 2010.

Trinidad

In December 2009, the Government of Trinidad and Tobago approved the assignment of 26 percent interest and operatorship of the 1,605 square-kilometre shallow water Block 2AB offshore Trinidad to the Company. An aero-gravity survey has been completed and is currently being processed. The tender process for an 864-square-kilometre 3D seismic survey is currently underway.

In February 2010, the Company executed an agreement to acquire Voyager Energy Ltd. (Voyager), a private company with interests in five PSCs in Trinidad including an interest in Block 2AB. Voyager currently has cash on hand of approximately US$9.0 million. The acquisition will be a share exchange resulting in the issue of 397,379 shares of Niko Resources Ltd. for all of the outstanding shares of Voyager. The successful completion of these transactions is subject to approval by the shareholders of Voyager and acknowledgement by the Government of Trinidad and Tobago.

OPERATING EXPENSE

Operating costs in the quarter ended December 31, 2009 were US$0.36/Mcfe compared to US$0.49/Mcfe in the same period in the prior year. Operating costs per Mcfe have decreased substantially as a result of the commencement of gas production from the D6 Block since the prior year's period. Operating costs per Mcfe 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 nine months ended December 31, 2009 contains forward-looking information including forward-looking information about Niko's operations, production and capital spending.

Forward-looking information is generally signified by words such as "forecast", "projected", "expect", "anticipate", believe", "will", "should" and similar expressions. This forward-looking information is based on assumptions that the Company believes were reasonable at the time such information was prepared, but assurance cannot be given that these assumptions will prove to be correct, and the forward-looking information in this report on results for the three and nine months ended December 31, 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 nine months ended December 31, 2009 includes, but is not necessarily limited to, the following:

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

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

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

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

The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis and updates reserve estimates on an annual basis. Refer to "Risk Factors" contained in the Company's management's discussion and analysis for discussion of uncertainties and risks that may cause actual events to differ from forward-looking information provided in this report on results for the three and nine months ended December 31, 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 nine months ended December 31, 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 February 11, 2010. 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.

The term "the quarter" is used throughout the MD&A and in all cases refers to the period from October 1, 2009 through December 31, 2009. The term "prior year's quarter" is used throughout the MD&A for comparative purposes and refers to the period from October 1, 2008 through December 31, 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 December 31, 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 December 31, 2008. The term "prior year's periods" is used throughout this MD&A and in all cases refer to the three and nine-month period ended December 31, 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", "should" and similar expressions. This forward-looking information is based on assumptions that the Company believes were reasonable at the time such information was prepared, but assurance cannot be given that these assumptions will prove to be correct, and the forward-looking information in this MD&A should not be unduly relied upon. The forward-looking information and the Company's assumptions are subject to uncertainties and risks and are based on a number of assumptions made by the Company, any of which may prove to be incorrect.

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

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

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

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

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

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

Non-GAAP 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 and future income taxes related to each business segment.

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

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



OVERALL PERFORMANCE

Funds from Operations

Three months ended Nine months ended
December 31, December 31,
(thousands of U.S. dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Oil and natural gas revenues 91,757 28,045 223,489 76,490
Royalties (3,971) (1,144) (10,243) (3,468)
Profit petroleum (7,945) (6,116) (22,928) (16,883)
Operating expense (8,566) (4,054) (21,678) (8,412)
Interest and other income 9,658 3,944 12,532 10,969
Interest and financing expense (3,914) (745) (11,369) (745)
General and administrative expense (2,147) (965) (6,123) (5,627)
Realized foreign exchange gain (loss) 267 2,756 (590) 1,469
Current income tax expense (6,333) (2,206) (18,072) (3,646)
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Funds from operations (1) 68,806 19,515 145,018 50,147
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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 the majority of the increase in revenues in the quarter and year-to-date. 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. These increases more than offset declines at Hazira.

Royalties, operating expense and current income tax expense increased with the increased production described above.

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$0.6 million and US$1.4 million in the quarter and year-to-date, respectively, or one percent of revenues.

Interest and other income in the quarter includes a US$9.3 million adjustment related to a 36-inch pipeline that is connected to the Hazira facilities. Due to a dispute that was in arbitration, the Company had been assuming that it could not include the costs of the 36-inch pipeline for cost recovery, specifically, as a deduction in the calculation of profit petroleum. During the quarter, the Company was successful in arbitration and, as a result, pipeline costs will be eligible for cost recovery and the Company recognized the adjustment in the quarter. Year-to-date, interest and other income also includes 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 net increase in general and administrative expense was primarily a result of higher use of outside services and lower overhead recoveries.

The Company's realized foreign exchange arises on the settlement of Indian-rupee denominated working capital.



Net Income

Three months ended Nine months ended
December 31, December 31,
(thousands of U.S. dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Funds from operations (non-GAAP
measure) 68,806 19,515 145,018 50,147
Unrealized foreign exchange (loss)
gain (673) 8,374 (9,013) 5,095
(Loss) gain on short-term
investments (26,525) (8,897) 11,163 (24,068)
Equity gain (loss) on long-term
investment - 40 (91) (738)
Impairment of long-term investment - (4,186) - (4,186)
(Loss) gain on risk management
contracts - (824) - 499
Discount of long-term account
receivable (43) (56) (137) (235)
Stock-based compensation expense (5,754) (4,425) (14,841) (13,546)
Depletion, depreciation and
accretion (27,387) (11,631) (67,021) (31,211)
Future income tax reduction 6,213 - 15,043 -
----------------------------------------------------------------------------
Net income (loss) 14,637 (2,090) 80,121 (18,243)
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Net income increased substantially in the quarter and year-to-date over the prior year's periods. The increase is primarily a result of the increase in funds from operations as described above. Other factors affecting net income are explained below.

The unrealized foreign exchange loss arises primarily on U.S. dollar cash held by the parent whose functional currency is the Canadian dollar. An offsetting entry increases the accumulated other comprehensive income but does not flow through the income statement.

While there were no additional purchases during the quarter, there was a loss on marking the short-term investments to market value.

The increase in stock-based compensation expense in the quarter and year-to-date is primarily a result of the increased fair value expense per stock option.

Depletion expense increased primarily due to the increased production with the commencement of gas production from the D6 Block.

The future income tax recovery is 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, Indonesia, the Kurdistan region of Iraq, Trinidad, Pakistan and Madagascar. 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 or as specified in the production sharing contract (PSC). Where the Company is currently producing, the Company pays to the government an increasing share of the profits based on an Investment Multiple (IM) or on production levels plus an IM, or a fixed share of profits, depending on the agreement. The IM is the number of times the Company has recovered its investment in the property from its share of profits from the property. At the end of the life of the field or the mining licence, the field and the assets revert to the government; however, the Company is responsible for the costs of abandonment and restoration.

India

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 from the east coast of India. The block, which is currently in the exploration phase, encompasses more than 17,000 square kilometres. The commitment for Phase I exploration includes seismic work and 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 a 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 drilling is planned to commence in the third calendar quarter of 2010.

D6 - The Company has a 10 percent working interest in the 7,645-square-kilometre D6 Block. The scope of work under Phase I of the development for the Dhirubhai 1 and 3 natural gas discoveries has been completed. The development of the MA oil discovery is ongoing. 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 net and there is a marketing margin of US$0.135/MMBtu earned in addition to the price formula. This equates to a sales price of approximately US$3.95/Mcf. There have been several gas discoveries since Dhirubhai 1 and 3. A development plan for nine such discoveries was submitted to the Government of India in July 2008, however, based on the Government's advice, in December 2009 the plan was modified to include four rather than nine discoveries. Additional development plans can be expected in the future.

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 10 percent royalty, that is payable to the government, from the customer. The Company pays a percentage of the profits from the block to the government, which varies with the Investment Multiple (IM). The Company does not share profits when the IM is less than one; shares 10 percent of profits between one and 1.5; 20 percent between 1.5 and 2; 25 percent between 2 and 2.5; 35 percent between 2.5 and 3; and 40 percent thereafter.

NEC-25 - The Company has a 10 percent working interest in the NEC-25 Block, which covers 9,461 square kilometres in the Mahanadi Basin off the east coast of India. The Company has fulfilled its capital commitments for the block and is currently drilling under a six well program. A development plan was previously submitted for six of the discoveries. A separate commerciality report for the successful AJ wells will be prepared when drilling is completed.

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 at a price of US$5.50/Mcf until March 31, 2010 and US$6.00/Mcf until March 31, 2011. In addition to the price indicated, the Company collects the 10 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 15 to the unaudited interim consolidated financial statements for the period ended December 31, 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.

Indonesia

The Company holds interests in PSCs for twelve offshore exploration blocks covering approximately 59,000 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 100% 4,977
SE Ganal (1) Makassar Strait Nov. 2008 100% 4,868
Seram (1) Seram North Nov. 2008 100% 4,991
South Matindok (1) Sulewasi NE Nov. 2008 100% 5,182
Bone Bay Sulewasi SW Nov. 2008 45% 4,969
Kofiau (1) West Papua May 2009 100% 5,000
Kumawa Papua SW May 2009 45% 5,004
Cendrawasih Papua NW May 2009 45% 4,991
Halmahera-Kofiau (1) Papua W Nov. 2009 80% (2) 4,926
West Papua IV (1) Papua SW Nov. 2009 80% (2) 6,314
East Bula (1) Seram NE Nov. 2009 100% 6,029
North Makassar Makassar Strait Nov. 2009 50% 1,673
----------------------------------------------------------------------------
(1) Operated by the Company.
(2) The Company farmed out 20 percent of its interest subsequent to the
acquisition of Black Gold Energy LLC.


All of the blocks are in the first exploration period, which is a three-year period. Most of the blocks have a seismic commitment and nine of the blocks have a single well commitment. A total of 9,500 kilometres of the 22,100 kilometre 2D seismic program for all blocks has been acquired. A total of 3,100 square kilometres of the 10,200 square kilometres of 3D seismic planned for the blocks has been acquired.

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 in the Qara Dagh block from the Kurdistan Regional Government. The Company currently has a 37 percent interest and carries the proportionate cost for the regional government's remaining 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 near completion and the rig that will be used to drill the first well is expected to arrive on location in late March 2010.

Trinidad

In December 2009, the Government of Trinidad and Tobago approved the assignment of 26 percent interest and operatorship of the 1,605 square-kilometre shallow water Block 2AB offshore Trinidad to the Company. The Company has minimum work commitments to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells by July 2012.

In February 2010, the Company executed an agreement to acquire Voyager Energy Ltd. (Voyager), a private company with interests in five PSCs in Trinidad including an interest in Block 2AB. Voyager currently has cash on hand of approximately US$9.0 million. The acquisition will result in the Company having a 32.5 percent and 40 percent interest in the Shallow and Deep Horizon Central Range PSCs, respectively; a 65 percent and 80 percent interest in the Shallow and Deep Horizon Guayaguayare PSCs, respectively; and a 35.75 percent interest in the Block 2AB PSC. The successful completion of these transactions is subject to approval by the shareholders of Voyager and acknowledgement by the Government of Trinidad and Tobago.

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.

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.



Capital Expenditures

Exploration Spending (Net to the Company)

Actual spending for the Forecast spending
Nine months ended for January 1, 2010 to
(millions of U.S. dollars) December 31, 2009(1) March 31, 2010(2)
----------------------------------------------------------------------------
India 35.2 15
Indonesia 299.4 15
Kurdistan Region 40.4 5
Madagascar 2.3 5
Pakistan 1.3 2
Trinidad 3.9 1
----------------------------------------------------------------------------
Total 382.5 43
----------------------------------------------------------------------------

(1) The Company also spent US$0.6 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$382.5 million spent year-to-date, US$294.9 million was spent during the quarter. Spending during the quarter and year-to-date is discussed below.

Capital spending in India during the quarter included the remaining costs of drilling the Khoja-2 well in Cauvery (US$0.8 million) and drilling the AJ3 and AJ5 wells in NEC-25 (US$3.7 million). Year-to-date costs also included the costs of drilling the Khoja-1 and 2 wells in Cauvery, drilling the AJ2 well in NEC-25, drilling the BA2 well 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, additional drilling on the NEC-25 block and further exploratory/appraisal drilling in the D6 Block.

Indonesian capital spending in the quarter of US$282.1 million was primarily for the acquisition of Black Gold Energy LLC. Additional spending was for the ongoing 2D and 3D seismic programs and signing bonuses for the blocks awarded during the quarter. Year-to-date spending included the various signing bonuses, additional seismic and carrying costs of the blocks. Forecast capital spending in Indonesia is for the continuation of the seismic programs.

Costs incurred in the quarter of US$1.6 million for Kurdistan were for the remaining costs of the seismic and costs of preparation for drilling. Year-to-date costs included the cost to acquire an additional 10 percent interest in the Qara Dagh PSC of US$30 million paid to the Kurdistan Regional Government in accordance with the agreement, seismic costs and the cost of various bonuses required as per the PSC. Forecast capital spending is primarily for construction of a drilling location and the commencement of drilling of an exploratory well.

Costs of US$1.6 million incurred in Madagascar were for the multi-beam survey and carrying costs of the block. Year-to-date costs included the acquisition and reprocessing of existing 2D seismic data and the environmental impact assessment. Forecast capital spending is for the remainder of the multi-beam survey.

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

Capital spending for the Trinidad property during the quarter was for the bonuses required as per the PSC. The remaining forecast expenditures are for carrying costs of Block 2AB. The capital forecast for the additional interests in Trinidad PSCs as a result of the Voyager acquisition will be added to the capital forecast once the transaction is completed.



Development Spending (Net to the Company)

Actual spending for the Forecast spending
Nine months ended for January 1, 2010 to
(millions of U.S. dollars) December 31, 2009 March 31, 2010(1)
----------------------------------------------------------------------------
Bangladesh 9.3 2
India 69.9 55(2)
----------------------------------------------------------------------------
Total 79.2 57
----------------------------------------------------------------------------
(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 payments of amounts accrued and included in accounts
payable and accrued liabilities on the balance sheet.


Of the US$79.2 million spent year-to-date, US$5.9 million was spent during the quarter. Spending during the quarter and year-to-date is discussed below.

Bangladesh development in the quarter (US$0.5 million) was for facilities upgrades. Year-to-date spending also includes the workover of the Bangora-3 well, well testing and payment of the guarantee associated with the work commitment for the block.

Indian development in the quarter (US$5.4 million) was primarily for additional work on the MA oil development project. Year-to-date spending also included well completions and connecting wells to the offshore platform for the D6 gas development and drilling the MA6H and MA7H wells, completions and connecting wells to the FPSO for the D6 oil development. Forecast capital expenditures are for remaining costs of the gas development and the completion and tie-in of the MA6H and MA7H oil wells.



SEGMENT profit

INDIA

Three months ended Nine months ended
(thousands of U.S. dollars, December 31, December 31,
except as indicated) 2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas revenue 67,630 11,175 156,010 34,254
Oil revenue (1) 8,236 3,378 22,038 5,950
Royalties (3,942) (1,113) (10,183) (3,326)
Profit petroleum (2,689) (1,655) (7,894) (5,086)
Operating expenses (6,656) (2,355) (16,989) (4,701)
Depletion, depreciation
and accretion (20,239) (5,718) (46,357) (15,421)
Current income tax expense (6,369) (2,171) (17,633) (3,961)
Future income tax recovery 6,213 - 15,043 -
----------------------------------------------------------------------------
Segment profit (2) 42,184 1,541 94,035 7,709
----------------------------------------------------------------------------
Daily natural gas sales (Mcf/d) 179,151 23,741 135,829 24,892
Daily oil sales (bbls/d) (1) 1,192 687 1,147 315
Operating costs (US$/Mcfe) 0.38 0.95 0.43 0.67
Depletion rate (US$/Mcfe) 1.17 2.13 1.17 2.02
----------------------------------------------------------------------------
(1) Production that is in inventory has not been included in the revenue or
cost amountsindicated.
(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$58.4 million and US$124.9 million increase in revenues in the quarter and year-to-date, respectively. The average natural gas sales volume from the D6 Block increased to 161 MMcf/d in the quarter from 118 MMcf/d in the quarter ended September 30, 2009. The Company expects gas production to increase to its share of the design capacity of the gas plant of 280 MMcf/d as additional contracts are signed with customers already approved by the Government of India. 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 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 1,000 bbls/d and 942 bbls/d and increased revenues by US$4.8 million and US$16.2 million, respectively, compared to the prior year's periods. Oil production from the Hazira block averaged 192 bbls/d and 205 bbls/d in the quarter and year-to-date, respectively, compared to 219 bbls/d and 159 bbls/d in the 2008 periods, respectively. The average oil sales price for the blocks was US$75.01/bbl and US$69.87/bbl in the quarter and year-to-date, respectively, compared to US$52.41/bbl and US$69.40/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 10 percent of the sales price.

Profit Petroleum

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

For the D6 Block, the Company is able to use up to 90 percent of profits to recover costs. The government was entitled to 10 percent of the profits not used to recover costs during the quarter. Profit petroleum with respect to the D6 Block was US$0.6 million in the quarter and US$1.4 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.

For Surat, the Company recovered its investment since the prior year's quarter and began sharing profits 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 D6 and was partially offset by decreased profit petroleum payments for Hazira due to 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 gas field ramps up to design capacity.

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

The increase in current income tax expense in the quarter and year-to-date is primarily a result of the current income tax expense related to minimum alternative tax on the profits from the D6 Block, which commenced since the prior year's periods. Largely offsetting current taxes 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 December 31, 2009. Refer to the unaudited consolidated financial statements and notes for the period ended December 31, 2009 for a complete discussion of the contingency.



BANGLADESH

Three months ended Nine months ended
(thousands of U.S. dollars, December 31, December 31,
except as indicated) 2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas and condensate revenue 15,717 13,384 44,992 35,533
Profit petroleum (5,256) (4,462) (15,035) (11,798)
Operating and pipeline expenses (1,865) (1,666) (4,573) (3,622)
Depletion, depreciation and
accretion (6,710) (5,708) (19,214) (15,115)
Current income tax expense (13) (15) (33) (44)
----------------------------------------------------------------------------
Segment profit (1) 1,873 1,533 6,137 4,954
----------------------------------------------------------------------------
Daily natural gas sales (Mcf/d) 70,951 61,576 68,278 54,201
Operating costs (US$/Mcfe) 0.28 0.29 0.24 0.24
Depletion rate (US$/Mcfe) 1.02 0.98 1.01 1.01
----------------------------------------------------------------------------
(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 received 66.67 percent of production from Block 9 during the period in which it was recovering amounts paid in relation to the Government of Bangladesh's carried interest in the block. The amounts were fully recovered in November 2009 and the Company's share of production is now 60 percent.

Pursuant to the terms of the PSC for Block 9, the Government of Bangladesh was entitled to 61 percent of profit gas in the quarter and prior year's quarter. Profit petroleum expense 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 tables outline the Company's operating, funds from operations and earnings netbacks (all of which are non-GAAP measures) for the three and nine months ended December 31, 2009 and 2008:



Three months ended
December 31, 2009
----------------------------------------------------------------------------
India Bangladesh Total
(US$/Mcfe) (US$/Mcfe) (US$/Mcfe)
----------------------------------------------------------------------------
Oil and natural gas revenue 4.43 2.39 3.87
Royalties (0.23) - (0.17)
Profit petroleum (0.16) (0.75) (0.33)
Operating expense (0.38) (0.28) (0.36)
----------------------------------------------------------------------------
Operating netback 3.66 1.36 3.01
Interest and other income 0.40
Interest and financing expense (0.16)
General and administrative expense (0.09)
Realized foreign exchange gain 0.01
Current income tax expense (0.27)
----------------------------------------------------------------------------
Funds from operations netback 2.90
Unrealized foreign exchange (loss) gain (0.03)
Discount of long-term account receivable -
Stock-based compensation expense (0.24)
Loss on short-term investment (1.12)
Impairment of long-term investment -
Loss on risk management contracts -
Future income tax reduction 0.26
Depletion, depreciation and accretion expense (1.15)
----------------------------------------------------------------------------
Earnings netback 0.62
----------------------------------------------------------------------------


Three months ended
December 31, 2008
----------------------------------------------------------------------------
India Bangladesh Total
(US$/Mcfe) (US$/Mcfe) (US$/Mcfe)
----------------------------------------------------------------------------
Oil and natural gas revenue 5.68 2.35 3.39
Royalties (0.43) - (0.14)
Profit petroleum (0.65) (0.78) (0.74)
Operating expense (0.95) (0.29) (0.49)
----------------------------------------------------------------------------
Operating netback 3.65 1.28 2.02
Interest and other income 0.48
Interest and financing expense (0.09)
General and administrative expense (0.12)
Realized foreign exchange gain 0.33
Current income tax expense (0.27)
----------------------------------------------------------------------------
Funds from operations netback 2.35
Unrealized foreign exchange (loss) gain 1.02
Discount of long-term account receivable (0.01)
Stock-based compensation expense (0.53)
Loss on short-term investment (1.07)
Impairment of long-term investment (0.51)
Loss on risk management contracts (0.10)
Future income tax reduction -
Depletion, depreciation and accretion expense (1.40)
----------------------------------------------------------------------------
Earnings netback (0.25)
----------------------------------------------------------------------------


Nine months ended
December 31, 2009
----------------------------------------------------------------------------
India Bangladesh Total
(US$/Mcfe) (US$/Mcfe) (US$/Mcfe)
----------------------------------------------------------------------------
Oil and natural gas revenue 4.54 2.38 3.84
Royalties (0.26) - (0.18)
Profit petroleum (0.20) (0.81) (0.39)
Operating expense (0.43) (0.24) (0.37)
----------------------------------------------------------------------------
Operating netback 3.65 1.33 2.90
Interest and other income 0.22
Interest and financing expense (0.20)
General and administrative expense (0.11)
Realized foreign exchange (loss) gain (0.01)
Current income tax expense (0.31)
----------------------------------------------------------------------------
Funds from operations netback 2.49
Unrealized foreign exchange (loss) gain (0.15)
Discount of long-term account receivable -
Stock-based compensation expense (0.26)
Gain (loss) on short-term investment 0.19
Equity loss on long-term investment -
Impairment of long-term investment -
Gain on risk management contracts -
Future income tax reduction 0.26
Depletion, depreciation and accretion expense (1.15)
----------------------------------------------------------------------------
Earnings netback 1.38
----------------------------------------------------------------------------

Nine months ended
December 31, 2008
----------------------------------------------------------------------------
India Bangladesh Total
(US$/Mcfe) (US$/Mcfe) (US$/Mcfe)
----------------------------------------------------------------------------
Oil and natural gas revenue 5.46 2.37 3.41
Royalties (0.44) - (0.15)
Profit petroleum (0.69) (0.79) (0.75)
Operating expense (0.67) (0.24) (0.38)
----------------------------------------------------------------------------
Operating netback 3.66 1.34 2.13
Interest and other income 0.48
Interest and financing expense (0.03)
General and administrative expense (0.25)
Realized foreign exchange (loss) gain 0.07
Current income tax expense (0.16)
----------------------------------------------------------------------------
Funds from operations netback 2.24
Unrealized foreign exchange (loss) gain 0.23
Discount of long-term account receivable (0.01)
Stock-based compensation expense (0.60)
Gain (loss) on short-term investment (1.08)
Equity loss on long-term investment (0.03)
Impairment of long-term investment (0.19)
Gain on risk management contracts 0.02
Future income tax reduction -
Depletion, depreciation and accretion expe (1.39)
----------------------------------------------------------------------------
Earnings netback (0.81)
----------------------------------------------------------------------------


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 Nine months ended
December 31, December 31,
(thousands of U.S. dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenues
Interest and other income 9,658 3,944 12,532 10,969
(Loss) gain on risk management
contracts - (824) - 499
Expenses
Interest and financing 3,914 745 11,369 745
General and administrative 2,147 965 6,123 5,627
Foreign exchange (gain) loss 406 (11,130) 9,603 (6,564)
Loss (gain) on short-term
investments 26,525 8,897 (11,163) 24,068
Stock based-compensation 5,754 4,425 14,841 13,546
Equity (gain) loss on long-term
investment - (40) 91 738
Current income tax (reduction)
expense (49) 19 406 (359)
----------------------------------------------------------------------------


Interest and Other Income

Interest and other income in the quarter includes a US$9.3 million adjustment related to a 36-inch pipeline that is connected to the Hazira facilities. Due to a dispute that was in arbitration, the Company had been assuming that it could not include the costs of the 36-inch pipeline for cost recovery, specifically, as a deduction in the calculation of profit petroleum. During the quarter, the Company was successful in arbitration and, as a result, pipeline costs will be eligible for cost recovery and the Company recognized the adjustment in the quarter. Year-to-date, interest and other income also includes US$2.7 million on an income tax refund. Excluding the adjustment related to the pipeline arbitration and 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 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 was an unrealized loss in the prior year's quarter on the recognition of the fair value of the interest rate swaps due to the decrease in forecast LIBOR rates, which increased the differential compared to the fixed interest rate. In the prior year-to-date period, there was an opposite effect resulting in an unrealized gain.

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$1.4 million and US$3.9 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$7.4 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 and lower overhead recoveries as a result of decreased capital activities in Kurdistan and Pakistan. Year-to-date, there was a net increase in general and administrative expense as a result higher use of outside services partially offset by lower employee bonuses.



Foreign Exchange

Three months ended Nine months ended
December 31, December 31,
(thousands of U.S. dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Realized foreign exchange (gain) loss (267) (2,756) 590 (1,469)
Unrealized foreign exchange loss (gain) 673 (8,374) 9,013 (5,095)
----------------------------------------------------------------------------
Total foreign exchange loss (gain) 406 (11,130) 9,603 (6,564)
----------------------------------------------------------------------------


The Company's realized foreign exchange arises on the settlement of Indian-rupee denominated working capital. The gains and losses depend on the timing of settlement of individual accounts receivable and accounts payable as well as the movement in value of the Indian rupee against the U.S. dollar during the period.

The unrealized foreign exchange loss arises primarily on U.S. dollar cash held by the parent whose functional currency is the Canadian dollar. An offsetting entry increases the accumulated other comprehensive income but does not flow through the income statement. The unrealized foreign exchange loss was 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 Indian rupee.

Short-term Investments

The unrealized loss in the quarter and the unrealized gain year-to-date on the investments were on marking the short-term investments to market value.

Stock-based Compensation

There was a net increase in stock-based compensation expense in the quarter and year-to-date. Stock-based compensation expense increased in the quarter primarily as a result of the increased fair value expense per stock option. The increase year-to-date is a result of an increased number of options being expensed and the increased fair value expense per stock option partially offset by a credit of US$1.9 million as a result of directors of the Company forfeiting options during the year.

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$0.7 million in the prior year's periods calculated by the equity method. Vast has committed to issue additional common shares and, upon issue, the Company's shareholdings in Vast will fall to approximately 8 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 income tax on interest income from cash balances outstanding during the periods. For the nine month period ending December 31, 2008, the income tax on interest income was more than offset by an income tax recovery related to an adjustment to taxes estimated in the year prior thereto.



SUMMARY OF QUARTERLY RESULTS

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

Three months ended
(thousands of U.S.
dollars, except per March 31, June 30, Sept 30, Dec. 31,
share amounts) 2009 2009 2009 2009
----------------------------------------------------------------------------
Oil and natural gas
revenue 28,503 53,853 77,879 91,757
Gain (loss) on
short-term investments (311) 18,003 19,685 (26,525)
Net income (loss) (4,319) 20,441 45,043 14,637
Per share
Basic (US$) (0.09) 0.41 0.91 0.29
Diluted (US$) (0.09) 0.41 0.90 0.29
----------------------------------------------------------------------------

Three months ended
(thousands of U.S.
dollars, except per March 31, June 30, Sept 30, Dec. 31,
share amounts) 2008 2008 2008 2008
----------------------------------------------------------------------------
Oil and natural gas
revenue 23,576 24,381 24,064 28,045
Gain (loss) on
short-term investment 1,418 6,875 (22,046) (8,898)
Net income (loss) 1,355 6,267 (22,420) (2,090)
Per share
Basic (US$) 0.03 0.13 (0.46) (0.04)
Diluted (US$) 0.03 0.13 (0.46) (0.04)
----------------------------------------------------------------------------



Net income has fluctuated over the quarters, due in part to changes in revenue, interest and other income, operating expenses, profit petroleum, depletion expense, interest expense and the value of the short and long-term investments.

Revenues have increased over the quarters as a result of increased production in Block 9 and the D6 Block. In the quarter ended December 31, 2008, revenues increased due to an increase in production from Block 9 as a result of the completion of a plant upgrade as well as the first sale of oil from the D6 Block. Gas production from the D6 Block commenced in the quarter ended June 30, 2009 and ramped-up during the subsequent two quarters, substantially increasing revenues in all three quarters. Operating expense and depletion expense increased in the same quarters as a result of the increased production. Profit petroleum expense increased in the quarter ended December 31, 2008 with the increase in revenues from Block 9.

Interest and other income in the quarter ended December 31, 2009 includes a US$9.3 million adjustment related to a 36-inch pipeline that is connected to the Hazira facilities. Due to a dispute that was in arbitration, the Company had been assuming that it could not include the costs of the 36-inch pipeline for cost recovery, specifically, as a deduction in the calculation of profit petroleum. During the quarter, the Company was successful in arbitration and, as a result, pipeline costs will be eligible for cost recovery and the Company recognized the adjustment in the quarter.

Interest expense on the long-term debt was capitalized until the commencement of gas production from the D6 Block. In the quarter ended June 30, 2009, interest expense on the long-term debt was expensed, decreasing net income.

In the quarter ended 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 magnitude of the gains and losses compared to net income by quarter is displayed in the table above.

Liquidity and Capital Resources

At December 31, 2009, the Company had total restricted and unrestricted cash of US$192.8 million and a working capital surplus of US$68.9 million, calculated as current assets less current liabilities. The restricted portion of the cash balance was comprised of US$19.2 million of performance guarantees, US$3.5 million of cash restricted for future site restoration and US$30.0 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$75.7 million. In April 2009, the credit facility was reduced to US$192.8 million.

On December 30, 2009, the Company acquired all of the outstanding shares of Black Gold Energy LLC for a purchase price of US$282 million, which is net of US$19.4 million of cash of Black Gold Energy LLC at acquisition. The acquisition increased the Company's working interest in the Indonesian blocks. The purchase price was based on the fair value of the consideration provided using the purchase method of accounting. The assets acquired include US$19.4 million cash and cash equivalents, US$8.5 million restricted cash, US$2.2 million accounts receivable, US$6.1 million accounts payable and US$482.3 million of property and equipment. A future income tax liability of US$205.3 million was recorded with respect to the acquisition. The acquisition was funded primarily with convertible debentures.

On December 30, 2009, the Company issued Cdn $310 million, 5 percent, senior secured convertible debentures (the "Debentures"). The Debentures mature on December 30, 2012 and the interest is paid semi-annually in arrears on January 1st and July 1st of each year. Debentures are convertible at the option of the holder into common shares of the Company at a conversion price of Cdn $110.50 per common share until 60 days prior to the maturity date. After December 30, 2010, the Company may elect to convert all of the debentures into common shares at the conversion price in effect on that date, provided that the weighted average trading price for the prior 21 trading days exceeds Cdn $143.65 per share.

In February 2010, the Company executed an agreement to acquire Voyager Energy Ltd. (Voyager), a private company with interests in five PSCs in Trinidad including an interest in Block 2AB. Voyager currently has cash on hand of approximately US$9.0 million. The acquisition will be a share exchange resulting in the issue of 397,379 shares of Niko Resources Ltd. for all of the outstanding shares of Voyager. The successful completion of these transactions is subject to approval by the shareholders of Voyager and acknowledgement by the Government of Trinidad and Tobago.

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 December 31, 2009. Refer to the unaudited interim consolidated financial statements and notes for the period 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 December 31, 2009:

- D4 Block: The commitment for Phase I exploration includes seismic work and drilling three exploration wells. Originally, the work commitment was to be completed by September 2009; however, the Government of India is in the process of approving a blanket 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 a one year extension. The seismic work has been completed and drilling is planned to commence in the third calendar quarter of 2010. The cost of the remaining work commitment for the block is estimated at US$60 million (US$9 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 Phase II of the initial term, the Company will need to acquire additional seismic or drill one well. Phase II of the initial term expires in March 2013.

- 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 Company has completed the seismic and the rig to drill the exploratory well is expected to arrive on location in late March 2010. The remaining capital expenditures related to the minimum work program are estimated at US$33 million (US$15 million net to the Company).

- 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. All multi-beam and coring work is expected to be completed by April 2010.

- Indonesia: For the Indonesian blocks, the remaining work commitments for interests acquired in twelve PSCs include seismic for most of the blocks and one exploration well for nine of the blocks. The cost of the remaining minimum work commitments during the first exploration period are estimated at US$210 million (US$121 million net to the Company). This exploration period ends in November 2011 for five of the blocks, in May 2012 for the three blocks and in November 2012 for the remaining four 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$30 million to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells by July 2012.

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, convertible debentures and long-term debt.

The Company is exposed to fluctuations in the value of its cash, accounts receivable, short-term investments, accounts payable and accrued liabilities due to changes in foreign exchange rates as these financial instruments are partially or wholly denominated in Canadian dollars, Indian rupees and Bangladeshi taka. The Company manages the risk by converting cash held in foreign currencies to U.S. dollars as required to fund forecast expenditures. The Company is exposed to changes in foreign exchange rates as the future interest payments on the convertible debentures are in Canadian dollars. The Company is exposed to changes in the market value of the short-term investments. The Company is exposed to changes in the LIBOR rate on the long-term debt. The Company is exposed to credit risk with respect to all of its financial instruments if a customer or counterparty fails to meet its contractual obligations. The Company has deposited the cash and restricted cash with reputable financial institutions, for which management believes the risk of loss to be remote. The Company takes measures in order to mitigate any risk of loss with respect to the accounts receivable, which may include obtaining guarantees. The Company is exposed to the risk of changes in market prices of commodities. The Company enters into physical commodity contracts for the sale of natural gas, which manages this risk. The Company does so in the normal course of business, 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 loss on the recognition of the short-term investments at fair value of US$26.5 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$43,000 in the quarter was recognized in income. The debt component of the convertible debentures has been recorded net of the fair value of the conversion feature. The fair value of the conversion feature of the debentures included in shareholders' equity at the date of issue was US$14.8 million. The fair value of the conversion feature of the debentures was determine based on the discounted future payments using a discount rate of a similar financial instrument without a conversion feature compared to the fixed rate of interest on the debentures. 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's financial statements.

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 nine months ended December 31, 2009 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

RISKS 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 December 31, 2009. Refer to the notes to the Company's unaudited interim consolidated financial statements for a complete list of the contingencies and any potential effects on the Company.



OUTSTANDING SHARE DATA

At February 11, 2010, the Company had the following outstanding shares:

Number Cdn$ Amount (1)
----------------------------------------------------------------------------
Common shares 50,324,356 $ 1,252,357,000
Preferred shares nil nil
Stock options 4,252,339 -
----------------------------------------------------------------------------
(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 February 11, 2010 is US$1,097,834,000.


OUTLOOK

Financial strength, growing sales volume and an expanded exploration portfolio set the stage for adding shareholder value.



On behalf of the Board of Directors,
Edward S. Sampson
Chairman of the Board, President and CEO
February 11, 2010



INTERIM CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------
(thousands of U.S. dollars) (unaudited)

As at As at
Dec. 31, 2009 March 31, 2009
ASSETS
Current assets
Cash and cash equivalents (note 5) $ 140,068 $ 31,189
Restricted cash (notes 3, 5) 33,159 185,475
Short-term investments 27,816 9,067
Accounts receivable (note 5) 42,677 20,287
Inventory 372 616
Prepaid expenses 1,896 1,494
----------------------------------------------------------------------------
245,988 248,128
Restricted cash (note 3) 19,594 24,011
Long-term investment (note 4) - 4,216
Long-term accounts receivable (note 15a) 23,994 22,201
Income tax receivable (note 15e) 21,421 16,000
Future income tax asset 15,044 -
Property and equipment (note 5) 1,759,785 1,154,074
----------------------------------------------------------------------------
2,085,826 1,468,630
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities
(note 5) 88,584 119,555
Current tax payable 1,963 2,691
Current portion of capital lease obligation 10,752 10,752
Current portion of long-term debt 75,745 -
----------------------------------------------------------------------------
177,044 132,998
Asset retirement obligation 29,168 27,544
Capital lease obligation 54,307 57,984
Future income tax liability (note 5) 205,324 -
Long-term debt 117,069 192,814
Convertible debentures (note 6) 281,432 -
----------------------------------------------------------------------------
864,344 411,340
Shareholders' equity
Share capital (note 7) 1,051,081 1,001,885
Contributed surplus (note 8) 55,657 51,966
Equity component of convertible debentures
(note 6) 14,765 -
Accumulated other comprehensive income (loss)
(note 10) 18,322 (2,406)
Retained earnings 81,657 5,845
----------------------------------------------------------------------------
1,221,482 1,057,290
----------------------------------------------------------------------------
$ 2,085,826 $ 1,468,630
----------------------------------------------------------------------------
Segment information (note 12) Guarantees (note 13)
Commitments and contractual obligations (note 14)
Contingencies (note 15)
Subsequent event (note 16)
See accompanying Notes to Interim Consolidated Financial Statements.


INTERIM CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME AND
RETAINED EARNINGS
----------------------------------------------------------------------------
(thousands of U.S. dollars, except per share amounts)(unaudited)

Three months ended Nine months ended
December 31, December 31,
2009 2008 2009 2008
Revenue
Oil and natural gas $ 91,757 $ 28,045 $223,489 $ 76,490
Royalties (3,971) (1,144) (10,243) (3,468)
Profit petroleum (7,945) (6,116) (22,928) (16,883)
Interest and other income (note 9) 9,658 3,944 12,532 10,969
(Loss) gain on risk management
contracts - (824) - 499
----------------------------------------------------------------------------
89,499 23,905 202,850 67,607
----------------------------------------------------------------------------
Expenses
Operating 8,566 4,054 21,678 8,412
Interest and financing 3,914 745 11,369 745
General and administrative 2,147 965 6,123 5,627
Foreign exchange loss (gain) 406 (11,130) 9,603 (6,564)
Loss (gain) on short-term
investments 26,525 8,897 (11,163) 24,068
Equity (gain) loss on long-term
investment - (40) 91 738
Impairment of long-term investment - 4,186 - 4,186
Discount of long-term account
receivable 43 56 137 235
Stock-based compensation 5,754 4,425 14,841 13,546
Depletion, depreciation and
accretion 27,387 11,631 67,021 31,211
----------------------------------------------------------------------------
74,742 23,789 119,700 82,204
----------------------------------------------------------------------------
Income before income taxes 14,757 116 83,150 (14,597)
Current income tax expense 6,333 2,206 18,072 3,646
Future income tax reduction (6,213) - (15,043) -
----------------------------------------------------------------------------
Income tax expense 120 2,206 3,029 3,646
----------------------------------------------------------------------------
Net income (loss) $ 14,637 $ (2,090) $ 80,121 $(18,243)
----------------------------------------------------------------------------

Net income (loss) per share (note 11)
Basic $ 0.29 $ (0.04) $ 1.62 $ (0.37)
Diluted $ 0.29 $ (0.04) $ 1.60 $ (0.37)
----------------------------------------------------------------------------

Net income (loss) $ 14,637 $ (2,090) $ 80,121 $(18,243)
Foreign currency translation gain
(loss) 4,321 (32,118) 20,728 (40,523)
----------------------------------------------------------------------------
Comprehensive income (loss)
(note 10) $ 18,958 $(34,208) $100,849 $(58,766)
----------------------------------------------------------------------------

Retained earnings, beginning of
period $ 68,479 $ 14,482 $ 5,845 $ 33,472
Net income (loss) 14,637 (2,090) 80,121 (18,243)
Dividends paid (1,459) (1,047) (4,309) (3,884)
----------------------------------------------------------------------------
Retained earnings, end of period $ 81,657 $ 11,345 $ 81,657 $ 11,345
----------------------------------------------------------------------------

See accompanying Notes to Interim Consolidated Financial Statements.


INTERIM CONSOLIDATED STATEMENTS OF CASH FLOWS
----------------------------------------------------------------------------
(thousands of U.S. dollars)(unaudited)

Three months ended Nine months ended
December 31, December 31,
2009 2008 2009 2008
Cash provided by (used in):
Operating activities
Net income (loss) $ 14,637 $ (2,090) $ 80,121 $(18,243)
Add items not involving cash from
operations:
Unrealized foreign exchange loss
(gain) 673 (8,374) 9,013 (5,095)
Discount of long-term account
receivable 43 56 137 235
Stock-based compensation 5,754 4,425 14,841 13,546
Unrealized loss (gain) on
short-term investments 26,525 8,897 (11,163) 24,068
Equity (gain) loss on long-term
investment - (40) 91 738
Impairment of long-term investment - 4,186 - 4,186
Unrealized loss (gain) on risk
management contracts - 824 - (499)
Depletion, depreciation and
accretion 27,387 11,631 67,021 31,211
Future income tax reduction (6,213) - (15,043) -
Change in non-cash working capital (13,223) (1,368) (24,612) (5,353)
Change in long-term accounts
receivable (2,802) 12,825 (4,693) 11,579
----------------------------------------------------------------------------
52,781 30,972 115,713 56,373
----------------------------------------------------------------------------
Financing activities
Proceeds from issuance of shares
(note 7) 20,417 3,020 36,204 11,539
Convertible debentures 297,590 - 297,590 -
Dividends paid (1,459) (1,047) (4,309) (3,884)
----------------------------------------------------------------------------
316,548 1,973 329,485 7,655
----------------------------------------------------------------------------
Investing activities
Addition of property and equipment (24,053) (96,829) (185,367) (308,105)
Corporate acquisition (note 5) (281,637) - (281,637) -
Reduction in capital lease
obligations (1,263) (646) (3,300) (646)
Restricted cash contributions (86,959) (66,095) (158,229) (76,899)
Restricted cash returned 87,325 11,705 323,479 25,135
Addition to short-term investments - (5,213) - (19,927)
Disposition of short-term
investments - - 1,054 -
Addition to long-term investment - - - (11,378)
Change in non-cash working capital (35,993) 17,413 (33,555) 19,620
Change in cash call advances (1,250) 39,441 (1,147) 15,008
----------------------------------------------------------------------------
(343,830) (100,224) (338,702) (357,192)
----------------------------------------------------------------------------
Increase (decrease) in cash position 25,499 (67,279) 106,496 (293,164)
Effect of foreign currency
translation on cash and cash
equivalents 337 (18,956) 2,383 (21,920)
Cash and cash equivalents, beginning
of period 114,232 215,040 31,189 443,889
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period $140,068 $128,805 $140,068 $128,805
----------------------------------------------------------------------------

See accompanying Notes to Interim Consolidated Financial Statements.


NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

For the nine months ended December 31, 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.

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 standard did not have an impact on the Company's financial statements.

3. RESTRICTED CASH

At December 31, 2009, the restricted cash balance included in current assets was comprised of guarantees of US$19.2 million (March 31, 2009 - nil) (see note 13) and US$14.0 million (March 31, 2009 - US$185.5 million) that was 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 is comprised of US$3.5 million (March 31, 2009 - US$3.5 million) of cash that is legally restricted for future site restoration in India and US$16.1 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 for guarantees (March 31, 2009 - US$13.5 million).

4. 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 determined that the investment was impaired in the quarter ended December 31, 2008 and wrote the value of the investment down to the book value of the investee's net assets resulting in an impairment loss of US$4.2 million. Vast has committed to issue additional common shares and, upon issue, the Company's shareholdings in Vast will fall to approximately 8 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.

5. ACQUISITION

On December 30, 2009, the Company acquired all of the outstanding shares of Black Gold Energy LLC for a purchase price of US$300 million. The acquisition increased the Company's working interest in the Indonesian blocks.

The purchase price of Black Gold Energy LLC was based on the fair value of the consideration provided, using the purchase method of accounting, and was allocated as follows:



(thousands of U.S. dollars)
----------------------------------------------------------------------------
Cash and cash equivalents $ 19,367
Restricted cash 8,515
Accounts receivable 2,249
Accounts payable and accrued liabilities (6,091)
Property and equipment (1) 482,288
Future income tax liability (1) (205,324)
----------------------------------------------------------------------------
Net assets acquired $ 301,004

----------------------------------------------------------------------------
Cash paid $ 300,000
Capitalized acquisition costs 1,004
----------------------------------------------------------------------------
Total purchase price $ 301,004
----------------------------------------------------------------------------

(1) These amounts represent the estimated fair values of the respective
assets and liabilities except that the amount recorded for the future
income tax liability is based on the differences between the tax basis
and the amount allocated in the purchase equation at the applicable tax
rates.


The above amounts are estimates made by management based on currently available information. Amendments may be made to the purchase price equation as the cost estimates and balances are finalized.

6. CONVERTIBLE DEBENTURES

The Cdn $310 million, 5 percent, senior secured convertible debentures (the "Debentures") mature on December 30, 2012 with interest paid semi-annually in arrears on January 1st and July 1st of each year. Debentures are convertible at the option of the holder into common shares of the Company at a conversion price of Cdn $110.50 per common share until 60 days prior to the maturity date. After December 30, 2010, the Company may elect to convert all of the debentures into common shares at the conversion price in effect on that date, provided that the weighted average trading price for the prior 21 trading days exceeds Cdn $143.65 per share.

The fair value of the conversion feature of the Debentures included in shareholders' equity at the date of issue was US$14.8 million. The debt component is accreted over the term of the obligation to the principal value on maturity with a corresponding charge to earnings. If the Debentures are converted to common shares, the corresponding amount of the conversion feature within shareholders' equity will be reclassified to share capital along with the principal amount converted. At December 31, 2009, Debentures with a face value of Cdn $310 million remain outstanding.

7. SHARE CAPITAL

(a) Authorized

Unlimited number of common shares

Unlimited number of preferred shares



(b) Issued
Nine months ended Year ended
December 31, 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 765,437 36,204 243,725 11,615
Transferred from
contributed surplus
on exercise of stock
options - 12,992 - 4,220
----------------------------------------------------------------------------
Balance, end of period 50,063,570 $1,051,081 49,298,133 $ 1,001,885
----------------------------------------------------------------------------


(c) Stock Options

The Company has reserved for issue 5,006,357 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:

Nine months ended Year ended
December 31, 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 720,250 82.72 1,368,313 60.33
Forfeited (169,625) 85.79 (18,250) 83.11
Expired (99,125) 92.74 (295,313) 58.39
Exercised (765,437) 51.93 (243,725) 50.85
----------------------------------------------------------------------------
Outstanding, end of period 3,716,813 69.10 4,030,750 64.69
----------------------------------------------------------------------------
Exercisable, end of period 743,998 56.88 1,132,562 54.02
----------------------------------------------------------------------------


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

Outstanding Options Exercisable Options
----------------------------------------------------------------------------
Weighted Weighted
Remaining Average Average
Life Exercise Exercise
Exercise Price Options (Years) Price (Cdn$) Options Price (Cdn$)
----------------------------------------------------------------------------
$ 41.00 - $ 49.90 1,214,251 2.6 47.97 392,186 44.55
$ 52.80 - $ 59.87 448,249 0.8 53.69 134,062 53.70
$ 60.00 - $ 69.82 349,625 1.9 62.91 83,750 63.00
$ 71.00 - $ 79.88 76,250 3.3 76.05 - -
$ 80.00 - $ 89.99 764,813 3.2 85.53 12,250 82.86
$ 90.40 - $ 99.68 862,125 2.6 94.11 121,500 93.24
$ 105.00 - $ 105.47 1,500 2.2 105.24 250 105.47
----------------------------------------------------------------------------
3,716,813 2.5 69.10 743,998 56.88
----------------------------------------------------------------------------


8. CONTRIBUTED SURPLUS

Nine months ended Year ended
(thousands of U.S. dollars) December 31, 2009 March 31, 2009
----------------------------------------------------------------------------
Contributed surplus, beginning of
period $ 51,966 $ 34,952
Stock-based compensation 16,683 21,234
Stock options exercised (12,992) (4,220)
----------------------------------------------------------------------------
Contributed surplus, end of period $ 55,657 $ 51,966
----------------------------------------------------------------------------


9. INTEREST AND OTHER INCOME

Interest and other income in the quarter includes a US$9.3 million adjustment related to a 36-inch pipeline that is connected to the Hazira facilities. Due to a dispute that was in arbitration, the Company had been assuming that it could not include the costs of the 36-inch pipeline for cost recovery, specifically, as a deduction in the calculation of profit petroleum. During the quarter, the Company was successful in arbitration and, as a result, pipeline costs will be eligible for cost recovery and the Company recognized the adjustment in the quarter.



10. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Nine months ended Year ended
(thousands of U.S. dollars) December 31, 2009 March 31, 2009
----------------------------------------------------------------------------
Accumulated other comprehensive
income (loss), beginning of period $ (2,406) $ 40,989
Foreign currency translation gain
(loss) 20,728 (43,395)
----------------------------------------------------------------------------
Accumulated other comprehensive
income (loss), end of period $ 18,322 $ (2,406)
----------------------------------------------------------------------------


11. PER SHARE AMOUNTS

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




Three months ended Nine months ended
December 31, December 31,
2009 2008 2009 2008
----------------------------------------------------------------------------
Weighted average number of
common shares outstanding
- basic 49,740,300 49,238,400 49,594,939 49,171,322
- diluted 50,309,059 49,238,400 50,016,765 49,171,322
----------------------------------------------------------------------------


As the Company incurred net losses for the three and nine-month periods ended December 31, 2008, all 3,975,250 outstanding stock options were considered anti-dilutive and were therefore excluded from the calculation of diluted per share amounts for the periods. For the three and nine-month periods ended December 31, 2009, 1,160,188 and 1,661,688 stock options were out-of-the money and therefore excluded from the calculation of diluted per share amounts for the periods.



12. SEGMENT INFORMATION

(thousands of U.S. Three months ended Three months ended
dollars) December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Segment Segment
Profit Capital Profit Capital
Segment Revenue (Loss) Additions Revenue (Loss) Additions
----------------------------------------------------------------------------
Bangladesh $ 15,717 $ 1,873 $ 557 $ 13,384 $ 1,533 $ 3,352
India 75,866 42,184 10,026 14,553 1,541 64,854
Indonesia - - 487,444 - - 4,656
Kurdistan - - 1,591 - - 1,802
Madagascar - - 1,594 - - 4,177
Pakistan - - 1,024 - - 17,939
Trinidad - - 3,923 - - -
All other (1) 174 (289) 182 108 (180) 49
----------------------------------------------------------------------------
Total $ 91,757 $43,768 $ 506,341 $ 28,045 $ 2,894 $ 96,829
----------------------------------------------------------------------------


(thousands of U.S. Nine months ended Nine months ended
dollars) December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Segment
Profit Capital Segment Capital
Segment Revenue (Loss) Additions Revenue Profit Additions
----------------------------------------------------------------------------
Bangladesh $ 44,992 $ 6,137 $ 9,335 $ 35,533 $ 4,954 $ 14,144
India 178,048 94,035 105,028 40,205 7,709 235,256
Indonesia - - 504,744 - - 14,853
Kurdistan - - 40,420 - - 19,727
Madagascar - - 2,309 - - 4,177
Pakistan - - 1,336 - - 18,821
Trinidad - - 3,923 - - -
All other (1) 449 (1,582) 560 752 207 1,127
----------------------------------------------------------------------------
Total $223,489 $98,590 $ 667,655 $ 76,490 $ 12,870 $ 308,105
----------------------------------------------------------------------------
(1) Revenues included in All other are from Canadian oil sales.


(thousands of
U.S. dollars) As at December 31, 2009 As at March 31, 2009
Property and Property and
Segment Equipment Total Assets Equipment Total Assets
----------------------------------------------------------------------------
Bangladesh $ 129,085 $ 165,120 $ 138,667 $ 170,405
India 1,004,682 1,115,742 944,881 1,170,524
Indonesia 521,439 546,801 15,896 28,181
Kurdistan 65,565 65,890 24,579 28,477
Madagascar 6,729 6,772 4,393 5,826
Pakistan 24,258 24,279 22,863 22,932
Trinidad 3,923 3,928 -- --
All other 4,104 157,294 2,795 42,285
----------------------------------------------------------------------------
Total $ 1,759,785 $ 2,085,826 $ 1,154,074 $ 1,468,630
----------------------------------------------------------------------------


The reconciliation of the segment profit to net income (loss) as reported in
the financial statements is as follows:
Three months ended Nine months ended
December 31, December 31,
(thousands of U.S. dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Segment profit $ 43,768 $ 2,894 $ 98,590 $ 12,870
Interest and other income 9,658 3,944 12,532 10,969
Interest and financing expense (3,914) (745) (11,369) (745)
General and administrative expenses (2,147) (965) (6,123) (5,627)
Foreign exchange (loss) gain (406) 11,130 (9,603) 6,564
Discount of long-term account
receivable (43) (56) (137) (235)
Stock-based compensation expense (5,754) (4,425) (14,841) (13,546)
(Loss) gain on short-term
investments (26,525) (8,897) 11,163 (24,068)
Equity gain (loss) on long-term
investment - 40 (91) (738)
Impairment of long-term investment - (4,186) - (4,186)
(Loss) gain on risk management
contracts - (824) - 499
----------------------------------------------------------------------------
Net income (loss) $ 14,637 $ (2,090) $ 80,121 $(18,243)
----------------------------------------------------------------------------


13. GUARANTEES

As at December 31, 2009, the Company had performance security guarantees of US$3.4 million for the Cauvery block, US$0.6 million for the D4 block, US$21.3 million for the Indonesian blocks and US$1.2 million for the Madagascar block. The guarantees are cancelled when the Company completes the work required under the exploration period. The current portion of restricted cash includes US$0.4 million of the Cauvery guarantee and US$18.8 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.

14. COMMITMENTS AND CONTRACTUAL OBLIGATIONS

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

In addition, the Company has the following work commitments as at December 31, 2009:

The Company has minimum work commitments for the D4 Block in India for 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 a one year extension. The Company's share of the remaining costs are estimated at US$9 million.

The Company has minimum work commitments for a block in the Kurdistan Region of Iraq for drilling an exploratory well and for various payments under the agreement. The work must be completed by May 2011 and the Company's share of the remaining costs are estimated at US$15 million.

The Company has minimum work commitments for a block in Madagascar for 2,000 line kilometres of 2D seismic.

The Company has minimum work commitments for the Indonesian blocks for seismic on most of the blocks and drilling one well in nine of the blocks. The Company's share of the cost is estimated at US$121 million.

The Company has minimum work commitments for Block 2AB in Trinidad to acquire and process 864 square kilometres of 3D seismic and drill three exploration wells by July 2012. The Company's share of the cost is estimated at US$30 million. See also Note 16.

15. CONTINGENCIES

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

In November 2009, the High Court ruled on the writ. Both the Company and the petitioners have the right to appeal the ruling to the Supreme Court. While the written ruling is not available yet, the Company understands that the ruling can be summarized as follows:




----------------------------------------------------------------------------
Petitioner request High Court Ruling
----------------------------------------------------------------------------
That the Joint Venture Agreement The Joint Venture Agreement for Feni
for the Feni and Chattak fields and Chattak fields is valid.
be declared null and illegal.
----------------------------------------------------------------------------
That the government realize from The compensation claims should be
the Company compensation for the decided by the lawsuit described in
natural gas lost as a result of note (b) below or by mutual agreement.
the uncontrolled flow problems as
well as for damage to the
surrounding area.
----------------------------------------------------------------------------
That Petrobangla withhold future Petrobangla to withhold future
payments to the Company relating payments to the Company relating to
to production from the Feni field production from the Feni field until
(US$27.6 million as at December 31, the lawsuit described in note (b)
2009). below is resolved or both parties
agree to settlement.
----------------------------------------------------------------------------
That all bank accounts of the All bank accounts of the Company
Company maintained in Bangladesh maintained in Bangladesh remain frozen
be frozen. pending resolution of the lawsuit
described in note (b) below.
----------------------------------------------------------------------------


(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 370,916,000 (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 728,232,000 (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 5,563,743,000 (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, which may take an extended period of time to settle.

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. Payment, if any, will be recorded in the period of determination.

(c) In accordance with natural gas sales contracts to customers in the vicinity of the Hazira field in India, the Company and its joint interest 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 and receive the same price as for other D6 gas sold. 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 interest, which reduce the profit petroleum expense. There are costs that the Company has included in the profit petroleum expense calculations that have been contested by the government. The Company believes that it is not determinable whether the above issue will result in additional petroleum expense. No amount has been recorded in these consolidated financial statements. Payment, if any, will be recorded in the period of determination.

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

The Company has received unfavourable tax assessments related to taxation years 1999 through 2006. The assessments contend 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 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$68.4 million, pay additional taxes of US$47.0 million and write off approximately US$21.3 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, if any, to the Company are not determinable and no amounts have been recorded in these consolidated financial statements. Costs, if any, will be recorded in the period of determination.

16. SUBSEQUENT EVENT

In February 2010, the Company executed an agreement to acquire Voyager Energy Ltd. (Voyager), a private company with interests in five PSCs in Trinidad including an interest in Block 2AB. Voyager currently has cash on hand of approximately US$9.0 million. The acquisition will be a share exchange resulting in the issue of 397,379 shares of Niko Resources Ltd. for all of the issued and outstanding shares of Voyager. The acquisition is subject to approval by the shareholders of Voyager and acknowledgement by the Government of Trinidad and Tobago.

Contact Information

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