Niko Resources Ltd.
TSX : NKO

Niko Resources Ltd.

November 10, 2005 08:30 ET

Niko Resources Announces 2nd Quarter Financial Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 10, 2005) - Niko Resources Ltd. (TSX:NKO) reports results for the three and six months ended September 30, 2005.

HIGHLIGHTS

- Began drilling the first oil well from the Hazira offshore platform

- Production increased by 79 percent to 84 mmcf/day

- Data acquisition well in Chattak successfully drilled



Three months ended Six months ended
September 30 September 30
2005 2004 2005 2004

FINANCIAL
(thousands of dollars,
except per share amounts)
Petroleum and natural gas sales 32,899 22,864 65,605 45,331
Funds from operations 18,648 14,086 39,195 26,862
Per share, diluted ($) 0.47 0.38 1.00 0.74
Net income 4,393 6,804 8,736 12,274
Per share, diluted ($) 0.11 0.19 0.22 0.34
Capital expenditures 30,306 27,660 49,417 73,977
Total assets 525,300 357,155 525,300 357,155
Shareholders' equity 421,288 243,452 421,288 243,452
Weighted average common
shares outstanding 38,287 35,553 38,287 35,214
Common shares outstanding
Basic (thousands) 38,312 35,658 38,312 35,658
Diluted (thousands) 40,266 38,343 40,266 38,343

OPERATIONS
Average daily production
Oils (bbls/day) 85 48 99 43
Natural gas (mmcf/day) 84 47 84 45
Total combined (boe/day) 14,110 7,854 14,173 7,519
Revenues, royalties and operating costs
Gross revenue received ($/boe) 25.34 31.64 25.29 32.94
Royalties ($/boe) (3.33) (5.04) (3.16) (5.79)
Profit Petroleum ($/boe) (3.00) (2.52) (2.90) (2.64)
Operating costs ($/boe) (1.56) (2.28) (1.62) (2.10)
------------------------------------------------------------------------
------------------------------------------------------------------------
Operating netback ($/boe) 17.45 21.80 17.61 22.41
Drilling activity
Gross wells 3 5.0 5 11.0
Net wells 1.4 1.2 2.5 4.0
------------------------------------------------------------------------


The Company's activities are carried out primarily in U.S. dollars as well as the currencies of each country in which the Company operates. The Company reports financial results in Canadian dollars.

The selected financial information presented above is prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP), except for funds from operations and funds from operations per share, which are used by the Company to analyze the results of operations and liquidity. By examining funds from operations, the Company is able to determine their ability to fund future capital projects and investments. Funds from operations is calculated as cash flows prior to the change in non-cash working capital related to operating activities. Funds from operations is not an alternative to cash flow from operating activities as determined in accordance with Canadian GAAP and may not be comparable with the calculation or similar measure for other companies. Funds from operations per share, diluted, is calculated by dividing the funds from operations by the weighted average number of diluted shares outstanding.

The fiscal period for the Company is the 12 months ending on March 31st of each year. The term 'fiscal 2006' is used throughout this report and refers to the period from April 1, 2005 through March 31, 2006.

FINANCIAL

During the three months ended September 30, 2005, funds from operations increased to $18.6 million or $0.47 per share compared to $14.1 million or $0.38 per share in the comparative period due to increased production and the resulting increase in revenue partially offset by increased profit petroleum. The Company earned $4.4 million or $0.11 per share in the quarter compared to $6.8 million or $0.19 per share in the comparative period. Although revenue increased, net income was reduced due to the increase in profit petroleum, a foreign exchange loss compared to a gain in the comparative period and an increase in depletion expense. Profit petroleum increased $2.1 million with the addition of production in Bangladesh and the increase in profit petroleum in Hazira due to lower capital expenditures in the period. There was a net foreign exchange loss during the quarter of $1.6 million compared to a gain of $1.3 million in the same quarter in the prior year resulting in a reduction in net income of $2.9 million. Losses occurred due to the strengthening of the Canadian dollar versus the U.S. dollar applied to cash held in U.S. dollars and U.S. dollar receivables in excess of payables. Depletion expense increased $7.4 million as a result of a downward technical revision in the Hazira proved reserves. For the quarter ending September 30, 2005 revenues were $32.9 million compared to $22.9 million in the comparative period. The increase in revenue is due to increased production in India and the addition of production from Bangladesh partially offset by the decrease in the selling price of natural gas in India due to the strengthening of the Canadian dollar versus the U.S. dollar resulting in a lower price received by the Company for Indian production.

For the six month period ending September 30, 2005, funds from operations increased to $39.2 million or $1.00 per share compared to $26.9 million or $0.74 per share in the comparative period due to increased revenue partially offset by increased profit petroleum. Net income for the six month period was $8.7 million or $0.22 per share compared to $12.3 million or $0.34 per share in the prior year's six months. Although production and corresponding revenue increased year over year, net income decreased primarily due to the increase in the depletion charge.

ENTREPRENEUR OF THE YEAR

The Board of Directors is pleased to announce that Mr. Edward Sampson, Chairman of the Board, President and Chief Executive Officer was recognized as the Entrepreneur Of The Year in the Energy Producers category of the annual Ernst & Young Entrepreneur Of The Year Awards® 2005.

The Board is proud that the hard work, dedication and leadership of Mr. Sampson, and his team, over the past years has been recognized.

OPERATIONS REVIEW

OPERATIONS UPDATE

India

The sixth new well drilled on the offshore platform in Hazira was put on production during the quarter resulting in a total of seven gas wells, including an appraisal well, currently producing from the platform. Production from Hazira during the quarter averaged 44 million cubic feet per day (net). Gas production from the field was curtailed during the quarter due to a temporary increase in supply in the market from other sources and a turnaround in the quarter at the plant of Essar Steel, which is one of the largest customers of Hazira gas, due to the fire in the plant in the previous quarter. The seventh new well was drilled from the platform and successfully tested oil at rates of 5,500 barrels of oil per day. Drilling of this well was completed subsequent to the end of the quarter and will be the first significant oil producer for the Company. Construction of oil production and handling facilities has commenced with first production scheduled for the fourth quarter of fiscal 2006. At least two more oil wells will be drilled from the offshore platform and two to three oil wells are planned from the land based drilling platform.

Production in Surat, which was slightly curtailed by market factors, averaged 9 million cubic feet per day. There was a temporary increase in supply in the market from other sources. Supply has returned to previous levels and the Company expects production for fiscal 2006 to average between 12 and 14 million cubic feet per day.

In the D6 Block, an additional gas discovery was made during the quarter in the P-1A well, which is the fifteenth successful well in the block. The P-1A well encountered thick channel sand gas pay during drilling in three stratigraphic intervals and is the first well on the newly acquired 3D seismic area. The well drilled to a total depth of 3,675 metres, which is the deepest well drilled to date on the D6 block and was not tested due to mechanical difficulties. The drilling results support the potential of discovering large reserves on the new 3D seismic area. Drilling of the first of two planned development wells, A-10A, commenced during the quarter. The A-10A well was extensively cored. Preliminary results show that the well encountered significantly more pay than was previously assessed. Drilling of the A-10A well was completed subsequent to the end of the quarter and drilling of the second development well on the original 3D seismic area, B-7, began. Drilling of the B-7 well will be followed by drilling of the exploratory well, MA-1, located on the new 3D seismic area. An additional drilling rig, capable of drilling in the deeper water depths on the prospects in the new 3D seismic area, has been contracted and is expected to commence drilling in September 2006. Further, a 2,550 square kilometre 3D seismic program is scheduled to be acquired in the fourth quarter of fiscal 2006 in the area to the south of the new 3D seismic area. The Company is looking forward to continued drilling success on this block.

In the NEC-25 Block, front-end engineering and reserve evaluation work was undertaken by the operator and third party engineering firms. This work was necessary to prepare development plans for the six consecutive gas discoveries made to date in the NEC-25 Block. The operator, Reliance Industries Limited (Reliance), has formally applied for declaration of commerciality for all of these discoveries, which are all within the original 1,800 square kilometre 3D seismic area.

Gaffney, Cline & Associates (GCA) were engaged by the operator to provide an independent assessment of natural gas resources contained in NEC-25 effective as of March 31, 2005. The findings of the GCA assessment include the exploration results from the six wells drilled by Reliance and Niko in the first original 1,800 square kilometre area and include analysis of log, production test and subsurface sampling of twelve separate gas accumulations. In addition to completing a review of these discoveries, GCA also independently evaluated the range of prospective resources that might be associated with undrilled seismic leads in the first seismic area.

GCA has stated that as yet none of the discoveries in NEC-25 have approved development plans to allow them to be classified as "reserves" under Society of Petroleum Engineers (SPE), World Petroleum Council (WPC) and National Instrument 51-101 resources classification guidelines.

In its assessment, GCA's best estimate of original gas in place for the drilled discoveries in NEC-25 is 2.3 trillion cubic feet (230 billion cubic feet net) with a low estimate of 0.8 trillion cubic feet (80 billion cubic feet net) and a high estimate of 5.5 trillion cubic feet (550 billion cubic feet net). In addition, GCA's best estimate of original gas in place for the undrilled prospects in the first seismic area in NEC-25 is 1.4 trillion cubic feet (140 billion cubic feet net), with a low estimate of 1.0 trillion cubic feet (100 billion cubic feet net) and a high estimate of 2.7 trillion cubic feet (270 billion cubic feet net) for an upside total of 8.2 trillion cubic feet (820 billion cubic feet net).

Acquisition of 1,700 square kilometres of new 3D seismic over the prospective area extending south from the original seismic area is now complete and the data is being processed and evaluated. Drilling on this new seismic area is expected to begin in fiscal 2007.

Niko has been awarded two blocks under the most recent round of bidding of the Government of India's New Exploration Licensing Policy, NELP V.

Niko has a 100 percent working interest in the 236,379 acre on land block CY-ONN-2003/1 (Cauvery) located in the Cauvery basin on the southeastern coast of India. The Cauvery block is adjacent to several producing oilfields and is located within the Cauvery Delta. Niko's Phase I commitment, which must be executed over the next three years, consists of shooting approximately 550 square kilometres of 3D seismic and the drilling of five wells.

Niko and its partner, Reliance, have also been awarded the 4,211,350 acre deep water block MN-DWN-2003/1 (D4) located in the Mahanadi basin off the northern part of the east coast of India. Niko has a 15 percent working interest in this block, of which Reliance will be the operator. Exploration potential for the D4 block is expected to exceed the potential of the D6 block and Niko's higher working interest in this block provides potential for new high impact discoveries.

Bangladesh

Combined gas production from the three wells in the Feni field averaged 31 million cubic feet per day during the quarter. Two new wells extending north and south of the structure are planned for fiscal 2006 and are expected to maintain production between 30 and 35 million cubic feet per day to the end of fiscal 2006.

Three drilling locations have been identified on the western part of the Chattak structure and one location on east Chattak. The Company moved in drilling equipment and spudded the Chattak-2 well on December 31, 2004. Early in January 2005, an uncontrolled release of gas occurred. A relief well, spudded in May 2005, also encountered uncontrolled flow problems in June 2005.

In September 2005, a data acquisition well, Chattak-2C, was drilled successfully into the sand from which the blowout occurred. This well was followed by a relief well, Chattak-2B, which intersected the original Chattak-2 well in the reservoir section of the blowout sand. Communication with the original blowout well was obtained and after pumping sufficient kill fluids, the well was cemented on October 9, 2005 and the Company believes the blowout has been successfully killed. Gas seepages to the surface have decreased to five to ten percent of previous levels and are continuing to subside. Total gas seepages currently are estimated at less than 20 thousand cubic feet per day. The Company continues to monitor the area, but believes current levels are insignificant. Clean up, leveling and restoration of the site has commenced. The drilling of Chattak-3 as the first gas producer will commence shortly followed by the drilling of Chattak-4.

Gas plant and pipeline facilities are near completion and will be ready for production in the third quarter of fiscal 2006. Production in Chattak is scheduled to commence in the fourth quarter of fiscal 2006.

An appraisal program for both the Lalmai and Bangora discoveries has been approved, which includes acquiring a 2D seismic program over the Lalmai/Bangora anticline, drilling of two appraisal wells in the Bangora field and the tie-in and placing on production of the Bangora-1 well. The seismic acquisition program began in October 2005 and drilling is expected to commence in February 2006. Tie-in of the Bangora-1 well has commenced. The installation of gas production and processing facilities and the commencement of production are both expected in the fourth quarter of fiscal 2006.

Production Forecast

For fiscal 2006, production from Hazira is expected to average between 50 and 55 million cubic feet per day (net), production from Surat is expected to average between 12 and 14 million cubic feet per day and production from Feni is expected to average between 30 and 35 million cubic feet per day.

Hazira oil production is scheduled to commence in the fourth quarter of fiscal 2006 at rates between 2,000 and 3,000 barrels of oil per day (gross). Niko is anticipating further production increases when Block 9 and Chattak West come online. Production at Block 9 is scheduled to commence in the fourth quarter of fiscal 2006. The Company plans to drill the two remaining wells of the three well program at Chattak West after which production is expected to commence in the fourth quarter of fiscal 2006.

The Company's total production outlook for fiscal 2006 is expected to average 105 to 115 million cubic feet per day (net) with a fiscal year-end exit rate of approximately 160 million cubic feet per day (net).

Operating Expense Outlook

Operating costs per boe for fiscal 2006 are expected to be lower than fiscal 2005. During the three and six months ended September 30, 2005, operating costs were $1.56 and $1.62 per boe, respectively, and are anticipated to average $1.50 to $1.70 per boe in fiscal 2006.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis (MD&A) of the financial condition, results of operations and cash flows should be read in conjunction with the unaudited consolidated financial statements and accompanying notes. This MD&A is effective November 8, 2005. Additional information relating to the Company, including the Company's Annual Information Form (AIF), is on SEDAR at www.sedar.com.

The Company's activities are focused on the Asian subcontinent. Over the reporting period, revenue and expenses were generated and capital expenditures were made in India, Bangladesh and Canada. The company's activities are carried out primarily in U.S. dollars as well as the currencies of each country in which the Company operates. The Company reports financial results in Canadian dollars.

The selected financial information presented throughout the MD&A is prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP), except for funds from operations and funds from operations per share, which are used by the Company to analyze the results of operations and liquidity. Funds from operations is calculated as cash flows from operating activities prior to the change in operating non-cash working capital. Funds from operations is not an alternative to cash flow from operating activities as determined in accordance with Canadian GAAP and may not be comparable with the calculation or similar measures for other companies. The consolidated statements of cash flows in the unaudited financial statements present the reconciliation between net income and cash flow from operating activities. Funds from operations per share, diluted, is calculated by dividing the funds from operations by the weighted average number of diluted shares outstanding.

The fiscal period for the Company is the 12 months ending on March 31st of each year. The term 'fiscal 2006' is used throughout the MD&A and refers to the period from April 1, 2005 through March 31, 2006.

Barrel of oil equivalent (boe) is a measure used throughout the MD&A. Boe is derived by converting gas to oil in the ratio of 6 Mcf: 1 bbl. Boes may be misleading, particularly if used in isolation. A boe conversion of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

The information contained in this MD&A may contain forward-looking information. Forward-looking information is subject to numerous known and unknown risks and uncertainties including, but not limited to, results of operations, financial condition, capital spending, financing sources, commodity prices and the magnitude of oil and natural gas reserves. These risks and uncertainties may cause actual events and circumstance to differ materially from those predicted. Readers are cautioned not to place undue reliance on this forward-looking information.

Less than two percent of total corporate volumes and revenues are from oil and condensate production. Therefore, the results from oil and condensate production, which include all of the Canadian results, are not discussed separately. Financial condition is discussed in this quarterly MD&A only where factors have changed substantially.

NETBACKS

The following table outlines the Company's operating and earnings netbacks for the three and six month periods ended September 30, 2005 and 2004.


Three months ended Six months ended
September 30 September 30
------------------------------------------------------------------------
Natural 2005 2004 Natural 2005 2004
gas (6:1) (6:1) gas (6:1) (6:1)
total total total total total total
($/Mcf) ($/boe) ($/boe) ($/Mcf) ($/boe) ($/boe)
------------------------------------------------------------------------
Price 4.19 25.34 31.64 4.18 25.29 32.94
Royalties (0.56) (3.33) (5.04) (0.52) (3.16) (5.79)
Profit Petroleum (0.50) (3.00) (2.52) (0.48) (2.90) (2.64)
Operating costs (0.25) (1.56) (2.28) (0.26) (1.62) (2.10)
------------------------------------------------------------------------
Operating netback 2.88 17.45 21.80 2.92 17.61 22.41
Pipeline and other
income 0.77 0.84 0.77 0.96
Pipeline expense (0.07) (0.23) (0.08) (0.24)
General and
administrative (0.81) (1.22) (0.76) (0.99)
Interest and
financing (0.62) (0.55) (0.74) (0.27)
Current taxes (1.38) (1.76) (1.39) (1.46)
------------------------------------------------------------------------
Cash flow netback 15.34 18.88 15.41 20.41
Foreign exchange (1.20) 1.83 (0.41) 0.24
Depletion and
depreciation (10.33) (8.29) (11.22) (8.28)
Future income taxes - (2.70) - (3.17)
Stock-based
compensation (0.43) (0.31) (0.43) (0.28)
------------------------------------------------------------------------
Earnings Netback 3.38 9.41 3.35 8.92
------------------------------------------------------------------------
------------------------------------------------------------------------


Netbacks are calculated by dividing the revenues and costs related to gas production in India and Bangladesh and revenues and costs in total for the Company by the volume measured in Mcf for the gas production in India and Bangladesh and by the sum of boe for the total production of the Company.

The following tables outline the Company's operating netbacks by country for the three and six months ended September 30, 2005 and 2004:




Three months ended Joint
September 30, 2005 Venture(1) Surat India Bangladesh Canada
---------------------------------------------------------------------
Average daily production
Oil (bbls/day) 8 - 8 27 50
Natural gas (mmcf/day) 44 9 53 31 -
Total combined
(boe/day) 7,412 1,482 8,894 5,166 50
Revenues, royalties
and operating costs
Gross revenue received
($/boe) 30.80 28.44 30.41 16.27 62.74
Royalties ($/boe) (5.24) (5.36) (5.26) - (4.98)
Profit Petroleum
($/boe) (3.44) - (2.87) (3.25) -
Operating costs
($/boe) (1.36) (3.89) (1.78) (1.06) (12.15)
---------------------------------------------------------------------
Operating netback
($/boe) 20.76 19.19 20.50 11.96 45.61
---------------------------------------------------------------------
(1) The joint venture includes results from Hazira, Bhandut, Cambay
and Sabarmati.


Three months ended Joint
September 30, 2004 Venture(1) Surat India Bangladesh Canada
---------------------------------------------------------------------
Average daily production
Oil (bbls/day) 30 - 30 - 18
Natural gas (mmcf/day) 40 7 47 - -
Total combined
(boe/day) 6,727 1,109 7,836 - 18
Revenues, royalties
and operating costs
Gross revenue received
($/boe) 31.70 31.15 31.62 - 41.33
Royalties ($/boe) (4.90) (5.83) (5.03) - (7.65)
Profit Petroleum
($/boe) (2.94) - (2.53) - -
Operating costs
($/boe) (1.19) (8.64) (2.24) - (16.06)
---------------------------------------------------------------------
Operating netback
($/boe) 22.67 16.68 21.82 - 17.62
---------------------------------------------------------------------


Six months ended Joint
September 30, 2005 Venture(1) Surat India Bangladesh Canada
---------------------------------------------------------------------
Average daily production
Oil (bbls/day) 16 - 16 32 51
Natural gas (mmcf/day) 44 9 53 31 -
Total combined
(boe/day) 7,170 1,568 8,738 5,384 51
Revenues, royalties
and operating costs
Gross revenue received
($/boe) 30.86 28.92 30.52 16.50 57.52
Royalties ($/boe) (5.01) (5.45) (5.09) - (5.73)
Profit Petroleum
($/boe) (3.26) - (2.68) (3.30) -
Operating costs
($/boe) (1.53) (3.69) (1.92) (1.06) (8.87)
---------------------------------------------------------------------
Operating netback
($/boe) 21.06 19.78 20.83 12.14 42.92
---------------------------------------------------------------------


Six months ended Joint
September 30, 2004 Venture(1) Surat India Bangladesh Canada
---------------------------------------------------------------------
Average daily production
Oil (bbls/day) 24 - 24 - 19
Natural gas (mmcf/day) 40 5 45 - -
Total combined
(boe/day) 6,626 874 7,500 - 19
Revenues, royalties and
operating costs
Gross revenue received
($/boe) 33.01 32.27 32.93 - 38.71
Royalties ($/boe) (5.67) (6.73) (5.79) - (7.38)
Profit Petroleum
($/boe) (2.99) - (2.64) - -
Operating costs
($/boe) (1.01) (10.10) (2.07) - (14.34)
Operating netback
($/boe) 23.34 15.44 22.43 - 16.99
---------------------------------------------------------------------
(1) The joint venture includes results from Hazira, Bhandut, Cambay
and Sabarmati.


Netbacks by country are calculated by dividing the revenues and costs related to oil and gas production combined by the volume measured in boe for that country.

OVERALL PERFORMANCE

Revenues increased by 44 percent in the quarter ended September 30, 2005 to $32.9 million from $22.9 million in the same period in the previous year. The increase is due to increased production in India and Bangladesh partially offset by a lower price received in India due to the strengthening of the Canadian dollar versus the U.S. dollar.

There was an increase in production in India of 13 percent from 47 million cubic feet per day to 53 million cubic feet per day due to production from additional wells on the offshore platform and increased recovery from existing wells in Surat due to the installation of compression equipment. The commencement of production in Bangladesh increased gas production by an average of 31 million cubic feet per day in the quarter.

The price charged to Hazira customers increased from the Rupee equivalent of US$3.45 per Mcf to a range of prices between US$3.45 per Mcf and US$3.75 per Mcf. The price has been renegotiated with one customer at a price of US$3.65 per Mcf and two customers at a price of US$3.75 per Mcf. Although the price has not yet been renegotiated with the remaining customers since the former prices expired in November 2004 and January 2005, three customers are paying at a rate of US$3.65 per Mcf and the remaining customers are paying at a rate of US$3.45 per Mcf. The Company expects to renegotiate prices to rates that are 5 to 10 percent higher than the previous rate of US$3.45 per Mcf. The increased revenue resulting from the increase in price in Hazira was more than offset by the decrease in the price received due to the strengthening of the Canadian dollar versus the U.S. dollar. These two factors resulted in a price before royalties in India of $5.06 per Mcf compared to $5.26 per Mcf in the same quarter in the prior year. Although a price has not yet been negotiated for production selling in Bangladesh, the Company is currently recording sales at US$2.20 per Mcf. This resulted in a price for the quarter of$2.68 per Mcf.

Revenues for the six months ended September 30, 2005 increased 45 percent to $65.6 million from $45.3 million in the comparative period. Indian production increased 18 percent over the comparative period with a price change from $5.48 per Mcf in the prior year to $5.08 per Mcf for the six months ended September 30, 2005. Bangladesh production averaged 31 million cubic feet per day and was recorded at a price of $2.72 per Mcf for the six months ended September 30, 2005.

Net income for the quarter ended September 30, 2005 was $4.4 million or $0.11 per share compared to $6.8 million or $0.19 per share in the same period in the previous year. Although revenue increased, net income was reduced due to an increase in profit petroleum of $2.1 million, a foreign exchange loss compared to a gain in the comparative period for a change of $2.9 million and an increase in the depletion expense of $7.4 million. Profit petroleum increased with the addition of production in Bangladesh. Profit petroleum in Bangladesh is currently 20 percent of revenue and totaled $1.6 million for the quarter. Profit petroleum in India is currently 20 percent of cash flow and therefore is at a lower effective rate than the Bangladesh profit petroleum. Profit petroleum in India was $2.3 million compared to $1.8 million in the same quarter in the prior year. There was a net foreign exchange loss during the quarter of $1.6 million compared to a gain of $1.3 million in the comparative quarter resulting in a reduction in net income of $2.9 million. There was a foreign exchange loss on the conversion of cash held in U.S. dollars and U.S. dollar receivables in excess of payables to Canadian dollars as the Canadian dollar strengthened versus the U.S. dollar during the quarter. These losses were partially offset by the gain on the U.S. dollar denominated debt due to the strengthening of the Canadian dollar versus the U.S. dollar. The depletion expense in India increased due to the 13 percent increase in production and the increase in the depletion rate as a result of a downward technical revision in the Hazira proved estimate by 39 billion cubic feet as at March 31, 2005. In addition, there was depletion expense in Bangladesh of $2.5 million.

For the six months ended September 30, 2005, net income was $8.7 million or $0.22 per share compared to $12.3 million or $0.34 per share in the same period in the previous year. Although revenue increased, net income decreased as a result of the increase in profit petroleum and the increase in depletion expense.

Funds from operations increased to $18.6 million in the quarter ended September
30, 2005 from $14.1 million in the same period in the previous year. Funds from operations for the six months ended September 30, 2005 increased to $39.2 million from $26.9 million in the same period in the prior year. The increase is due to the increased production and the resulting increase in revenue offset by the increase in profit petroleum. The Company has experienced a consistent increase in funds from operations.

A total of $30.3 million was spent on capital additions in the quarter compared to $27.7 million in the same period in the previous year. In Hazira, $3.5 million (net) was spent on the drilling and completion of the gas well, OS-6 and beginning drilling of the first oil well, OS-7. In Surat, there was a sale of inventory for a net reduction of $0.7 million. In the D6 Block, $6.1 million (net) was spent on drilling the P-1A well, additional seismic and commencing drilling of well A-10A. In Bangladesh, $19.6 million was spent on drilling of the data and relief wells, the gas plant and the pipeline in Chattak West and site preparation for the planned wells in Feni and Chattak. An additional $1.6 million (net) was spent in Block 9 for engineering work and initial work on the tie-in of Bangora-1.

For the six months ended September 30, 2005, $49.4 million was spent on capital additions compared to $74.0 million in the same period in the previous year. In the prior year, there were significant capital costs associated with building and installing the Hazira offshore platform. The current year costs relate to exploration and development activities in the various blocks. In Hazira, $10.0 million (net) was spent on drilling and completion of the offshore gas wells, OS-5 and OS-6, and beginning drilling of the first offshore oil well, OS-7. In the D6 Block, $8.8 million (net) was spent on drilling the P-1A well, seismic on the fan section to the east of the P-1A well and commencing drilling the A-10A well. In Bangladesh, $28.4 million was spent on drilling of the data and relief wells, the gas plant and the pipeline in Chattak West and site preparation for the planned wells in Feni and Chattak. An additional $1.9 million (net) was spent in Block 9 for engineering work and commencing the tie-in of Bangora-1.

MARKETING

India

There are 15 contracts for the sale of natural gas from the Hazira field and one contract for the sale of gas from the Surat field. The largest customer accounted for 23 percent of the Company's sales during the second quarter of fiscal 2006 (24 percent year to date). The operator of the D6 Block has initiated discussions for gas sales from that Block to several major customers in Andhira Pradesh, Tamil Nadi, Karnataka and Maharashtra.

Under the existing Hazira and Surat contracts, the natural gas purchaser pays the royalty and sales tax levied by the government and transportation charges on top of the contracted sales price. All contracts are supported by financial guarantees. All of the contracts contain a take-or-pay and/or supply-or-pay provision. Contract volumes are gross amounts, which are filled jointly by the Company and its partner. Most of the gas contracts are U.S. dollar-denominated and the price had been at the Indian Rupee equivalent of US$3.45 per Mcf while spot sales were at US$3.75 per Mcf. The price provisions in most of the Hazira gas contracts expired in November 2004 and January 2005, and most of the contracts contain renewal provision at prices negotiated based on the market at that time. The Company has signed contracts with one customer at a price of US$3.65 per Mcf and two customers at a price of US$3.75 per Mcf and gas is selling to remaining customers at prices between US$3.45 per Mcf and US$3.65 per Mcf until a new price can be negotiated. Discussions are ongoing with respect to the revised prices and the Company expects new prices to be 5 to 10 percent above previously negotiated levels. The Company's crude oil production is sold at international prices. The Company's Bhandut production is sold to a Government of India company based on Nigerian Bonny Lite, which trades at a discount of approximately US$1.50 per barrel to West Texas Intermediate (WTI), adjusted for quality differences. The price of Canadian crude oil production is based on WTI prices, adjusted for quality and transportation.

Bangladesh

First production beginning in November 2004 from the Company's Feni discovery had a start up rate exceeding 20 million cubic feet per day. The Government of Bangladesh has reached an agreement with the Company to purchase up to 50 million cubic feet per day from Feni. The Company is currently in discussions with the Government of Bangladesh in an attempt to finalize the gas price. In the interim, the Company is recording sales at US$2.20 per Mcf. Under the terms of the Joint Venture Agreement (JVA), transmission and distribution margin shall be the responsibility of the buyer.

Feni production, along with production from Chattak and Block 9, will assist meeting the country's current and future demand, which is forecast to double over the next five years.

RESULTS OF OPERATIONS

Revenue

Revenues increased by 44 percent in the quarter ended September 30, 2005 to $32.9 million from $22.9 million in the same period in the previous year. The increase is due to increased production in India and Bangladesh partially offset by a lower price received in India due to the strengthening of the Canadian dollar versus the U.S. dollar.

There was an increase in production in India of 13 percent from 47 million cubic feet per day to 53 million cubic feet per day due to production from additional wells on the offshore platform and increased recovery from existing wells in Surat due to the installation of compression equipment. The commencement of production in Bangladesh increased gas production by an average of 31 million cubic feet per day in the quarter.

The price charged to Hazira customers increased from the Rupee equivalent of US$3.45 per Mcf to a range of prices between US$3.45 per Mcf and US$3.75 per Mcf. The price has been renegotiated with one customer at a price of US$3.65 per Mcf and two customers at a price of US$3.75 per Mcf. Although the price has not yet been renegotiated with the remaining customers since the former prices expired in November 2004 and January 2005, three customers are paying at a rate of US$3.65 per Mcf and the remaining are paying US$3.45 per Mcf. The Company expects to negotiate prices at rates that are 5 to 10 percent higher than the previous rate of US$3.45 per Mcf. The increased revenue resulting from the increase in price in Hazira was more than offset by the decrease in the price received due to the strengthening of the Canadian dollar versus the U.S. dollar. These two factors resulted in a price before royalties in India of $5.06 per Mcf compared to $5.26 per Mcf in the same quarter in the prior year. Although a price has not yet been negotiated for production selling in Bangladesh, the Company is currently recording sales at US$2.20 per Mcf. This resulted in a price for the quarter of $2.68 per Mcf.

Revenues for the six months ended September 30, 2005 increased 45 percent to $65.6 million from $45.3 million in the comparative period. Indian production increased 18 percent over the comparative period with a price change from $5.48 per Mcf in the prior year to $5.08 per Mcf for the six months ended September 30, 2005. Bangladesh production averaged 31 million cubic feet per day and was recorded at a price of $2.72 per Mcf.

Royalties

Under the terms of the gas contracts in India, the purchaser is responsible for all royalties and sales taxes and the royalty increases proportionately to gas sales. These charges are levied by the Government and vary according to the type of purchaser. The Company charged and remitted $4.3 million in the quarter compared to the $3.6 million remitted in the same period in the previous year. Royalties increased for the quarter primarily due to the increase in sales in India. The Company charged and remitted royalties of $8.1 million in the six months ended September 30, 2005 compared to $7.9 million in the same period in the prior year. Year to date, the increase in royalties as a result of the increase in sales in India was partially offset by a higher proportion of gas sales made to customers who were exempt from sales tax in the first quarter of fiscal 2006. There are no royalties applicable to Bangladesh production.

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. The Government's share increases as the Company recovers a multiple of its investment. In the quarter ended September 30, 2005, the Government was entitled to 20 percent (2004 - 20 percent) of the cash flow from the Hazira field after deducting capital expenditures. This amounted to $2.3 million in the quarter (2004 - $1.8 million). For the six months ended September 30, 2005, this amounted to $4.3 million (2004 - $3.6 million). The increase in profit petroleum reflects the increase in cash flows. Specifically, the increase in revenues less expenses and the decrease in capital expenditures compared to the prior year. There were significant expenditures on the Hazira offshore platform in the prior year, resulting in a lower profit petroleum amount payable in the prior year compared to the current year.

Profit petroleum increased with the addition of production in Bangladesh. Pursuant to the terms of the JVA, the Government of Bangladesh is entitled to a sliding scale share in the revenues. The Government's share increases as the Company recovers a multiple of its investment. The Government was entitled to 20 percent of revenues resulting in profit petroleum of $1.6 million during the quarter and $3.3 million during the six months ended September 30, 2005.

Pipeline and Other Income

During the quarter, the Company earned pipeline tariff revenue of $0.2 million ($0.5 million year to date) compared to $0.4 million ($0.8 million year to date) in the comparative period. Pipeline and tariff revenue has decreased due to a decreased number of customers using the pipeline.

Interest income of $0.8 million (2004 - $0.2 million) was earned on excess cash balances during the quarter and $1.5 million (2004 - $0.5 million) for the six months ended September 30, 2005. The increase is due to higher cash balances remaining from the equity issuance in February 2005 and the additional US$20 million drawn on the debt facility.

Operating Expenses

Operating costs decreased by 32 percent to $1.56 per boe in the quarter ended September 30, 2005 from $2.28 per boe in the same period in the previous year. For the six month period ending September 30, 2005, operating costs decreased by 23 percent to $1.62 per boe compared to $2.10 per boe in the same period in the previous year. The decrease is due to one-time start up costs in Surat incurred in the comparative period that were not present in the current period. In addition, the Company incurred lower operating costs per boe in Bangladesh as compared to India, which lowered the Company's overall per boe operating cost. Operating costs in Bangladesh were $1.06 per boe and $1.06 per boe for the quarter and year to date, respectively, compared to $1.78 per boe and $1.92 per boe in India for the quarter and year to date, respectively.

General and Administrative

The Company's G&A costs for the quarter were $1.0 million compared to $0.9 million in the previous year. For the six months ended September 30, 2005, G&A costs were $2.0 million compared to $1.4 million in the previous year. The increase in the year to date amount is due to increased professional fees and lower overhead recoveries due to the change in capital spending year over year.

Foreign Exchange

The Company's long-term debt is denominated in U.S. dollars. Due to the strengthening of the Canadian dollar in the quarter, the Company incurred an unrealized foreign exchange gain on the outstanding debt and a realized foreign exchange gain on the principal repayments. The Company incurs an unrealized foreign exchange gain or loss on long term accounts payables and accounts receivables and restricted cash. The Company repatriates its revenues out of India in U.S. dollars. A portion of the funds is kept in U.S. dollars as large amounts of planned capital expenditures are in that currency. As a result, there is a foreign exchange effect due to the change in the Canadian dollar versus the U.S. dollar.

For the quarter ended September 30, 2005, there was a foreign exchange loss of $1.6 million compared to a foreign exchange gain of $1.3 million in the same quarter in the prior year. There was a foreign exchange gain on the long-term debt in the quarter due to the strengthening of the Canadian dollar versus the U.S. dollar. The gain was offset by a loss on the conversion of U.S. dollars held in cash and U.S. dollar receivables in excess of payables due to the strengthening of the Canadian dollar versus the U.S. dollar.

For the six months ended September 30, 2005, the Company incurred a foreign exchange loss of $1.1 million compared to a gain of $0.3 million in the same period in the previous year. The year to date loss is lower than the loss in the second quarter due to the Canadian dollar weakening versus the U.S. dollar in the first quarter.

Depletion and Depreciation

Depletion in India was $10.7 million or $13.12 per boe of production in the quarter compared to $5.9 million or $8.04 per boe during the same period in the previous year. For the six month period ending September 30, 2005, depletion in India was $21.0 million or $13.12 per boe of production compared to $11.1 million or $8.04 per boe of production. The increase is due to the 13 percent and 18 percent increase in production in the quarter and year to date, respectively, and the increase in the depletion rate as a result of a downward technical revision in the Hazira proved reserves by 39 billion cubic feet as at March 31, 2005.

Depletion in Bangladesh in the quarter ended September 30, 2005 was $2.5 million or $5.33 per boe of production. For the six month period ending September 30, 2005, depletion in Bangladesh was $7.8 million or $7.96 per boe of production. The decrease in the per boe of production cost was a result of an internal revision to the proven reserves. Compression at the Feni gas plant in Bangladesh, which is scheduled to be added during the third fiscal quarter, is expected to increase the recoverable reserves from the existing reservoir.

Income Taxes

The Company's overall tax provision in the quarter was a charge of $1.8 million compared to a $3.2 million charge in the same period in the previous year. Year to date, the overall tax provision was a charge of $3.6 million compared to a charge of $6.4 million in the same period in the previous year. The Company pays income tax at the highest rate of the jurisdictions in which it operates. The Company's current tax provision for the quarter increased to $1.8 million from $1.3 million and year to date, increased to $3.6 million from $2.0 million. The increase in current taxes relates to the addition of Bangladesh production and the increase in Indian production. The current tax provision for the quarter includes Indian tax of $1.5 million and Bangladesh tax of $0.2 million ($3.1 million and $0.5 million year to date, respectively). There is no future tax provision in the quarter due to the continued recognition of a tax holiday in India.

As a result of the tax holiday in India, the Company pays the greater of 41.82 percent of net income in India after a deduction for the tax holiday and minimum alternative tax of 7.84 percent of Indian income. The Company previously expected to pay minimum alternative tax for fiscal 2006 at a rate of 7.84 percent.

In the current period, production from the land based drilling platform was lower than previously expected resulting in a lower deduction for the tax holiday. As a result, the Company recorded current income taxes at a rate of 41.82 percent of net income after a deduction related to the tax holiday, resulting in an effective current tax rate in India of 14 percent for the quarter and year to date.

The Company paid tax in Bangladesh at a rate of 3.75 percent of revenues net of profit petroleum up until June 30, 2005. Since July 1, 2005, the Company pays tax at a rate of 4.00 percent of revenues. This amounted to $0.2 million for the quarter and $0.5 million year to date.

Capital Expenditures

A total of $30.3 million was spent on capital additions in the quarter compared to $27.7 million in the same period in the previous year. In Hazira, $3.5 million (net) was spent on the drilling and completion of the gas well, OS-6 and beginning drilling of the first oil well, OS-7. In Surat, there was a sale of inventory for a net reduction of $0.7 million. In the D6 Block, $6.1 million (net) was spent on drilling the P-1A well, additional seismic and commencing drilling of well A-10A. In Bangladesh, $19.6 million was spent on drilling of the data and relief wells, the gas plant and the pipeline in Chattak West and site preparation for the planned wells in Feni and Chattak. An additional $1.6 million (net) was spent in Block 9 for engineering work and initial work on the tie-in of Bangora-1.

For the six months ended September 30, 2005, $49.4 million was spent on capital additions compared to $74.0 million in the same period in the previous year. In the prior year, there were significant capital costs associated with building and installing the Hazira offshore platform. The current year costs relate to exploration and development activities in the various blocks. In Hazira, $10.0 million (net) was spent on drilling and completion of the offshore gas wells, OS-5 and OS-6, and beginning drilling of the first offshore oil well, OS-7. In the D6 Block, $8.8 million (net) was spent on drilling the P-1A well, seismic on the fan section to the east of the P-1A well and commencing drilling the A-10A well. In Bangladesh, $28.4 million was spent on drilling of the data and relief wells, the gas plant and the pipeline in Chattak West and site preparation for the planned wells in Feni and Chattak East. An additional $1.9 million (net) was spent in Block 9 for engineering work and initial work on the tie-in of Bangora-1.

Dividend

During the quarter, the Company continued its policy of paying quarterly dividends on its common shares. As a result, the Company declared a quarterly dividend of $0.03 per common share to shareholders of record on September 30, 2005.

UPDATE ON SIGNIFICANT PROJECTS

India

The Company has a 33.33 percent working interest in the offshore platform at Hazira. The sixth new well drilled on the offshore platform in Hazira was put on production during the quarter resulting in a total of seven gas wells, including an appraisal well, currently producing on the platform. The next phase of development in Hazira includes drilling three planned oil wells from the offshore platform and two to three oil wells from the land based drilling platform. The first planned oil well, OS-7, began drilling from the platform during the quarter. Installation is continuing on oil production and handling facilities at the existing gas plant and first oil production from the offshore platform is expected to commence in the fourth quarter of fiscal 2006. Capital expenditures in the quarter were $3.5 million (net) ($10.0 million (net) year to date) related to drilling activities on the offshore platform. Forecasted expenditures for the remainder of fiscal 2006, related to oil development, total between $8 and $13 million (net). Forecasted expenditures to complete the oil development project are between $10 million and $15 million (net).

The Company has a 10 percent working interest in the D6 Block off the east coast of India. An additional gas discovery was made during the quarter with the exploration well, P-1A, the first well drilled on the new seismic area. Drilling of the first of two planned development wells, A-10A, commenced during the quarter. Drilling of the A-10A well was completed subsequent to the end of the quarter and drilling of the second development well on the original seismic area, B-7, began. Drilling of the B-7 well will be followed by the drilling of the exploratory well, MA-1, which is located on the new 3D seismic area. An additional 3D seismic acquisition program of 2,550 square kilometres is scheduled to be acquired in the fourth quarter of fiscal 2006 in the area to the south of the new 3D seismic area. Capital expenditures in the quarter were $6.1 million (net) ($8.8 million (net) year to date) for drilling activities related to the P-1A and A-10A wells. Remaining capital expenditures for fiscal 2006 for exploration and development activities are forecasted at between $8 and $10 million (net).

The Company has a 10 percent working interest in the NEC-25 Block off the east
coast of India. During the quarter, an assessment of the natural gas resources was performed by an independent engineering firm, however, in the absence of approved development plans, the discoveries in this block cannot be classified as "reserves" under Society of Petroleum Engineers (SPE), World Petroleum Council (WPC) and National Instrument 51-101 resources classification guidelines. Capital expenditures in the quarter were $0.1 million (net) ($0.1 million (net) year to date) related to seismic activities. The Company is currently acquiring an additional 1,700 square kilometres of seismic on which drilling is expected to commence in fiscal 2007. There are remaining forecasted capital expenditures for fiscal 2006 of $2 to $3 million (net) related to seismic.

The Company and its partner, Reliance Industries Limited (Reliance), signed PSCs on September 23, 2005 for the 4,211,350 acre deep water block MN-DWN-2003/1 (D4) located in the Mahanadi basin off the northern part of the east coast of India. The Company has a 15 percent working interest in this block, of which Reliance will be the operator. Phase I development, which must be executed over the next four years, includes 2,100 kilometres of 2D seismic and 1,800 square kilometres of 3D seismic, reprocessing of existing seismic and drilling of three exploratory wells. The estimated cost of the Phase I commitment is US$97.6 million (US$14.6 million net) and seismic work for the 2D program is expected to commence in fiscal 2007.

On September 23, 2005, the Company signed a PSC with a 100 percent working interest in the 236,379 acre on land block CY-ONN-2003/1 (Cauvery) located in the Cauvery basin on the southeastern coast of India. The Cauvery block is adjacent to several producing oilfields and is located within the Cauvery Delta. The Company's Phase I commitment, which must be executed over the next three years, consists of shooting approximately 550 square kilometres of 3D seismic and the drilling of five wells. The estimated cost of the Phase I seismic and drilling commitment is US$15.9 million. Seismic acquisition work is expected to commence in the fourth quarter of fiscal 2006 with drilling commencing in fiscal 2007.

The PSCs signed for the D4 and the Cauvery blocks specify the following formula for sharing the profit oil and gas produced from the block between the Company and the Government of India (GOI). In D4, 80 percent of the revenue can be used to recover costs. In Cauvery, 90 percent of the revenue can be used to recover costs. The remaining profit oil and gas in each block is shared with the GOI being entitled to 10 percent when production begins. The back-in escalates on a formula basis with the GOI share of profit oil and gas increasing as a greater multiple of the investment is recovered by the Company according to the following investment multiples:



Investment Multiple GOI Entitlement
D4 Cauvery
0.0 - 1.5 10% 10%
1.5 - 2.0 10% 20%
2.0 - 2.5 19% 30%
2.5 - 3.0 70% 30%
3.0 - 3.5 76% 35%
less than 3.5 85% 50%


The formula for the back-in is calculated on a cumulative basis at March 31st of each year and the results of the calculation establish the sharing ratio for the next year. The GOI back-in is applied to the pre-tax cash flow from the field after deducting allocated overhead and capital expenditures.

Bangladesh

At Feni, the Company plans to drill two new wells extending north and south of the structure in fiscal 2006. Capital expenditures in the quarter were $1.7 million ($1.8 million year to date) related to development activities, site preparation for the two planned wells and development activities.

Three drilling locations are scheduled to be drilled on the western part of the Chattak structure and one location on east Chattak. Drilling of the first planned well and relief well resulted in an uncontrolled release of gas in January and June 2005, respectively. Drilling of a data acquisition well, Chattak-2C, was completed in September 2005. This well was followed by drilling of a relief well, Chattak-2B, which intersected the original Chattak-2 well in the reservoir section of the blowout sand and was cemented on October 9, 2005. The drilling of the second scheduled well, Chattak-3, will commence shortly followed by the drilling of Chattak-4. Gas plant and pipeline facilities are near completion and will be ready for production in the third quarter of fiscal 2006. Production in Chattak is scheduled to commence in the fourth quarter of fiscal 2006.

The Company had a control of well insurance policy with US$20.0 million of coverage for each of the original well and the relief well. Costs totaling US$21.6 million have been submitted to the insurers related to the first blowout and US$15.3 million has been received to date. Costs to control the second blowout include drilling of the data acquisition well, Chattak-2C, and the relief well, Chattak-2B. These costs total US$29.1 million and have been submitted to the insurers. The Company expects to collect the US$4.7 million outstanding under the first policy and the US$20.0 million outstanding under the second policy, however, no assurance can be given that all costs submitted can be covered under the insurance policies. Total costs to the end of September exceed the insurance coverage, therefore the costs in excess of the insurance coverage of US$10.7 million have been capitalized. Total costs to control the second blowout are expected to reach US$40 million.

Capital expenditures for the Chattak field during the quarter were $17.9 million for the drilling of the data and relief wells, the gas plant, the pipeline and site preparation for the planned wells. Capital expenditures for the remainder of fiscal 2006 are forecasted to be $20 to $25 million.

The Company has a 60 percent working interest in Block 9 and is also responsible for the costs associated with a 6.67 percent earned interest in the Block held by BAPEX. Two of the three exploration wells drilled to date encountered commercial quantities of natural gas. An appraisal program for both the Lalmai and Bangora discoveries has been approved, which includes acquiring a 2D seismic program over the Lalmai/Bangora anticline, drilling of two appraisal wells in the Bangora field and the tie-in and placing on production of the Bangora-1 well. The seismic acquisition program began in October 2005 and drilling is expected to commence in February 2006. Tie-in of the Bangora-1 well has commenced. The installation of gas production and processing facilities and the commencement of production are both expected in the fourth quarter of fiscal 2006. Capital expenditures in the quarter were $1.6 million (net) ($1.9 million (net) year to date). Capital expenditures forecasted for the remainder of fiscal 2006 are $13 to $18 million (net).

SUMMARY OF QUARTERLY RESULTS

The Company's activities are carried out primarily in U.S. dollars as well as the currencies of each country in which the Company operates. The Company reports financial results in Canadian dollars. The selected financial information presented above is prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP), except for funds from operations and funds from operations per share, which are used by the Company to analyze the results of operations and liquidity. Funds from operations is calculated as cash flows prior to the change in non-cash working capital related to operating activities. Funds from operations is not an alternative to cash flow from operating activities as determined in accordance with Canadian GAAP and may not be comparable with the calculation or similar measures for other companies. The consolidated statements of cash flows in the unaudited financial statements present the reconciliation between net earnings and cash flow from operating activities. Funds from operations per share, diluted, is calculated by dividing the funds from operations by the weighted average number of diluted shares outstanding.

The following tables set forth selected financial information of the Company for each of the eight most recently completed quarters to September 30, 2005:



Three months ended
(thousands of dollars, Dec 31, Mar 31, Jun 30, Sep 30,
except per share amounts) 2004 2005 2005 2005
------------------------------------------------------------------------
Petroleum and natural gas sales 27,849 34,670 32,706 32,899
Funds from operations
Per share
- basic ($) 0.50 1.17 0.54 0.49
- diluted ($) 0.49 1.13 0.52 0.47
Net income 14,684 47,264 4,343 4,393
Per share
- basic ($) 0.41 1.29 0.11 0.11
- diluted ($) 0.40 1.26 0.11 0.11
------------------------------------------------------------------------
------------------------------------------------------------------------

Three months ended
(thousands of dollars, Dec 31, Mar 31, Jun 30, Sep 30,
except per share amounts) 2003 2003 2004 2004
------------------------------------------------------------------------
Petroleum and natural gas sales 19,958 20,851 22,467 22,864
Funds from operations
Per share
- basic ($) 0.32 0.29 0.37 0.40
- diluted ($) 0.31 0.29 0.35 0.38
Net income 5,045 6,840 5,470 6,804
Per share
- basic ($) 0.15 0.20 0.16 0.19
- diluted ($) 0.15 0.20 0.15 0.19
------------------------------------------------------------------------
------------------------------------------------------------------------


Net income has fluctuated over the quarters in part due to changes in revenue, profit petroleum, foreign exchange, insurance proceeds, depletion and income tax.

Overall, revenues have increased due to increased production volumes. This increase has been partially offset by a decrease in the price received as revenues are received in U.S. dollars and the U.S. dollar has weakened against the Canadian dollar during fiscal 2004 and fiscal 2005 and overall in fiscal 2006. In the quarter ended December 31, 2004, Bangladesh production began, increasing revenue.

Profit petroleum expense decreased in the last two quarters of fiscal 2004 due to deducting capital expenditures from the cash flow from Hazira prior to calculating the charge. Profit petroleum increased throughout fiscal 2005 as capital activity in Hazira declined compared to the prior year, availing fewer deductions in the calculation. Profit petroleum increased further beginning in the third quarter of fiscal 2005 in part due to the addition of Bangladesh production.

There was a foreign exchange gain in fiscal 2005 primarily due to the strengthening of the Canadian dollar versus the U.S. dollar applied to the U.S. dollar denominated debt. In the first quarter of fiscal 2006, there was a weakening of the Canadian dollar versus the U.S. dollar resulting in a foreign exchange loss related to the long term debt and a gain on the funds held in U.S. dollars. In the second quarter of fiscal 2006, the Canadian dollar strengthened versus the U.S. dollar resulting in a foreign exchange gain on the long term debt, which was more than offset by the loss on the conversion of the U.S. dollar held cash and the U.S. dollar receivables in excess of payables.

In the third quarter of fiscal 2005, insurance proceeds of $3.3 million were recorded increasing net income.

Depletion expense increased in fiscal 2004 and the first two quarters of fiscal 2005 due to increased production and the inclusion of the Surat exploration and Hazira development costs in the cost base. Depletion expense increased in the third quarter of fiscal 2005 because of increased production including the commencement of production in Bangladesh. Depletion expense continued to increase in the fourth quarter of fiscal 2005 due to a downward technical revision in the Hazira proved reserves by 39 billion cubic feet. In the second quarter of fiscal 2006, depletion expense decreased due to an internal revision to the proven reserves. Compression at the Feni gas plant in Bangladesh, which is scheduled to be added during the third fiscal quarter, is expected to increase the recoverable reserves from the existing reservoir and lower the per boe depletion expense.

There was a tax recovery in the third quarter of fiscal 2005 related to Canadian tax pools available for future claim. In the fourth quarter of fiscal 2005, there was a recovery in current and future income taxes as a result of the recognition of the benefit of a tax holiday in India. In fiscal 2006, current tax in India is being recorded at an effective rate of 14 percent due to the continued recognition of the tax holiday. This results in a lower tax amount compared to prior quarters.

In general, funds from operations per share trend with revenue with variations for timing differences of payments and collections.

Liquidity

At September 30, 2005, the Company had a working capital surplus of $80.7 million, which included $85.4 million of cash and cash equivalents. The cash and cash equivalent balance at September 30, 2005 includes the residual of the $97.7 million (net) raised in the public offering the Company completed in February 2005 and the additional US$20 million drawn on the loan facility. Although successful in raising funds in the capital market in the past, the Company's ability to raise funds in the future is subject to market or commodity price changes, economic downturns and the future performance of the Company. The Company expects to meet obligations as they become due using working capital and funds from operations.

The restricted cash on the balance sheet at September 30, 2005 of $13.9 million relates to a US$12 million guarantee the Company provided to Century Resources International Pty Ltd., in connection with the drilling of the second Chattak relief well. This guarantee was returned to the Company in full on October 26, 2005.

Permission has been received from the Reserve Bank of India to transfer funds from the Indian branch to the Company.

Included in accounts receivable is US$13.7 million outstanding from one customer. Since the commencement of production in Bangladesh in November 2004, the Company has sold all of its gas and condensate production in Bangladesh to one customer, the Government of Bangladesh. The Company has reached an agreement with the Government of Bangladesh to sell up to 50 million cubic feet per day and is currently in discussions with the Government of Bangladesh in an attempt to finalize the gas sales price. The Company has received two payments totaling US$4.0 million since the commencement of production.

A group of petitioners have filed a writ with the Supreme Court of Bangladesh against, amongst others, Niko Resources (Bangladesh) Ltd., a subsidiary of the Company. The petitioners are requesting that the Government withhold future payments (US$13.7 million outstanding as at September 30, 2005) to the Company relating to the production from the Feni field and that all bank accounts of the Company maintained in Bangladesh be frozen. Currently, the Company is unable to repatriate funds from the country.

Included in accounts receivable is $0.5 million recorded as revenues for the incremental prices increases still under negotiation with some of the Hazira gas customers. There are 15 contracts for the sale of natural gas from the Hazira field. Most of the gas contracts are U.S. dollar-denominated and the price had been at the Indian Rupee equivalent of US$3.45 per Mcf while spot sales were at US$3.75 per Mcf. The price provisions in most of the contracts expired in November 2004 and January 2005, and most of the contracts contain renewal provision at prices negotiated based on the market at that time. The Company has signed contracts with one customer at US$3.65 per Mcf and two customers at a price of US$3.75 per Mcf and gas is selling to remaining customers at prices between US$3.45 per Mcf and US$3.65 per Mcf until a new price can be negotiated. Additionally, though no contracts have been signed with the remaining customers, three customers are paying at a rate of US$3.65 per Mcf. The Company is confident the negotiated price will be consistent with the price currently being billed and the full amount owed from these customers will be collected.

Included in accounts receivable is US$24.7 million receivable from the insurers with respect to the uncontrolled releases of gas which occurred while drilling the Chattak-2 well and the subsequent relief well Chattak-2A in January and June of 2005, respectively. The Company had a control of well insurance policy with US$20.0 million of coverage for each of the wells. Costs totaling US$21.6 million have been submitted to the insurers related to the first blowout and US$15.3 million has been received to date. Costs to control the second blowout include drilling of the data acquisition well, Chattak-2C, and the relief well, Chattak-2B. These costs total US$29.1 million to the end of September 30, 2005 and have been submitted to the insurers. The Company expects to collect the US$4.7 million outstanding under the first policy and the US$20.0 million outstanding under the second policy, however, no assurance can be given that all costs submitted can be covered under the insurance policies.

The current portion of long term debt decreased compared to March 31, 2005 as the repayment period was rescheduled to provide for the first repayment of principal on March 15, 2005, instead of September 15, 2004 with each of the six subsequent installments also deferred six months. At September 30, 2005, long-term debt was $36.1 million compared to $21.5 million at March 31, 2005. The difference is attributable to the additional US$20 million drawn on the facility less the September payment of US$6.7 million and a change for the foreign exchange gain. If the Company fails to meet a number of positive and negative covenants, the loan will become payable at the discretion of the debtor.

As at September 30, 2005, the Company had a performance guarantee to the Government of Bangladesh in the amount of US$20 million as specified in the production sharing agreement for Block 9. Subsequent to September 30, 2005, as part of the most recent renewal of the guarantee, the Company provided US$13.3 million of the guarantee and its joint venture partner provided the remaining US$6.7 million. The renewal of the guarantee becomes effective upon return of the previous guarantee provided by the Company for US$20 million on behalf of both the Company and its joint venture partner. Upon cancellation of the previous US$20 million guarantee, the Company will have a US$13.3 million guarantee outstanding.

The Company has been named as a defendant in a lawsuit that has been filed in the state of Texas, by a number of plaintiffs who claim to have suffered damages as a result of the uncontrolled releases of gas that occurred at the Chattak-2 well in Bangladesh in January and June of 2005. Damages sought total in excess of US$250 million. The Company believes that the outcome of the lawsuit and associated cost, if any, is not determinable. As such, no amounts have been recorded in the financial statements for the period ending September 30, 2005.

Capital Resources

At September 30, 2005 year to date, the Company had incurred capital expenditures of $49.4 million related to exploration and development activities throughout India and Bangladesh. The Company has planned capital expenditures of between $120 and $140 million (net) for the 2006 fiscal year and expects to finance the remaining expenditures with working capital and funds from operations.

As at September 30, 2005, the Company had a performance guarantee to the Government of Bangladesh in the amount of US$20 million as specified in the production sharing agreement for Block 9. Subsequent to September 30, 2005, as part of the most recent renewal of the guarantee, the Company provided US$13.3 million of the guarantee and its joint venture partner provided the remaining US$6.7 million. The renewal of the guarantee becomes effective upon return of the previous guarantee provided by the Company for US$20 million on behalf of both the Company and its joint venture partner. Upon cancellation of the previous US$20 million guarantee, the Company will have a US$13.3 million guarantee outstanding.

The Government of Bangladesh has the right to collect on this guarantee if the Company does not carry out specified geological, geophysical and drilling activities.

The Company has capital commitments for Phase I development as per the PSC signed for the D4 Block of US$97.6 million (US$14.6 million net), which must be spent over the next four years. The Phase I commitment as per the PSC signed for the Cauvery Block is US$15.9 million, which must be spent over the next three years. These commitments are expected to be funded with working capital and funds from operations.

The Company had a control of well insurance policy with US$20.0 million of coverage for each of the original well and the relief well. Costs totaling US$21.6 million have been submitted to the insurers related to the first blowout and US$15.3 million has been received to date. Costs to control the second blowout include drilling of the data acquisition well, Chattak-2C, and the relief well, Chattak-2B. These costs total US$29.1 million and have been submitted to the insurers. The Company expects to collect the US$4.7 million outstanding under the first policy and the US$20.0 million outstanding under the second policy, however, no assurance can be given that all costs submitted can be covered under the insurance policies. Total costs to the end of September exceed the insurance coverage, therefore the costs in excess of the insurance coverage of US$10.7 million have been capitalized. Total costs to control the second blowout are expected to reach US$40 million.

Critical Accounting Estimates

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

Proved Oil and Gas Reserves and Full Cost Accounting

The Company follows the Canadian full cost method of accounting whereby all costs related to the exploration for and development of oil and gas reserves are initially capitalized and are depleted and depreciated using the unit-of-production method based upon proved oil and gas reserves as determined by independent engineers. In applying the full cost method, the Company performs a cost recovery test ("ceiling test") placing a limit on the carrying value of property and equipment. The carrying value is considered recoverable when the fair value, calculated as the sum of the undiscounted value of future net revenues from proved reserves, the lower of cost and market of unproved properties and the cost of major development properties, exceeds the carrying value.

The amounts recorded for depletion and depreciation of exploration and development costs and the ceiling test are based on estimates of proved reserves, production rates, future oil and natural gas prices and future costs, which are all subject to measurement uncertainties and various interpretations.
The Company expects that its estimates of reserves will be revised, upwards or downwards over time, based on future changes to these variables.

Reserve estimates can have a material impact on the depletion and depreciation expense and the carrying value of property and equipment. Revisions to reserve estimates could increase or decrease depletion and depreciation expense charged to net income and a decrease in estimated reserves could result in a write-down of property and equipment based on the ceiling test.

Asset Retirement Obligation

The Company recognizes the fair value of a liability for an asset retirement obligation with a corresponding amount capitalized to property and equipment. The liability increases and accretion expense is recognized each period due to the passage of time. The capitalized portion is depleted based on the unit-of-production method.

The obligation is based on factors including current regulations, abandonment costs, technologies, industry standards and obligations in the Company's agreements. The fair value calculation takes into account estimated timing of abandonment, inflation and a credit-adjusted risk free interest rate. Changes in any of the factors and revisions to any of the estimates used in calculating the obligation may result in a material impact to the carrying value of property and equipment, asset retirement obligation and depletion expense charged to net income. The Company expects that its estimates of its asset retirement obligations will be revised, upwards or downwards over time, based on future changes to the factors and estimates involved.

Stock-Based Compensation

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

Income Taxes

The Company follows the tax liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs.

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

Costs Excluded from Depletable Base

Costs associated with the Company's undeveloped properties in India and Bangladesh are excluded from cost subject to depletion and depreciation until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly for impairment.

Accrual Accounting

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

Outstanding Share Data

At November 8, 2005, the Company had the following outstanding shares:



Number Amount
------------------------------------------------------------------------
Common shares 38,311,570 $ 304,563,586
Preferred shares nil nil
Stock options 1,954,250 -
------------------------------------------------------------------------
------------------------------------------------------------------------


Outlook

The Company maintains an aggressive growth strategy. With the addition of the D4 and Cauvery blocks, Niko has added two new exciting opportunities to an already exceptional asset base. In addition to contributing to the overall growth of the Company, as the first major oil block undertaken by Niko, Cauvery will also serve to diversify Niko's portfolio. However, the future growth is not limited to these new blocks, as we have an exciting year of exploration and development activities planned for all of our properties and look forward to the continued success that will follow.



On behalf of the Board of Directors,


(Signed)
Edward S. Sampson
Chairman of the Board, President and Chief Executive Officer
November 8, 2005


CONSOLIDATED BALANCE SHEETS



As at September 30, As at March 31,
(thousands of dollars) 2005 2005
------------------------------------------------------------------------
(Unaudited) (Audited)
ASSETS
Current assets
Cash and cash equivalents $ 85,446 $ 101,957
Accounts receivable (note 2) 71,945 46,219
Prepaid expenses 1,525 303
------------------------------------------------------------------------
158,916 148,479
Restricted cash (note 10) 13,937 -
Income tax receivable 12,357 12,961
Property and equipment 340,090 319,274
------------------------------------------------------------------------
$ 525,300 $ 480,714
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued
liabilities $ 61,808 $ 40,694
Current portion of long-term debt 15,512 7,088
Current tax payable 916 326
------------------------------------------------------------------------
78,236 48,108
Asset retirement obligation 5,155 4,644
Long-term debt (note 3) 20,621 14,418
------------------------------------------------------------------------
104,012 67,170
Shareholders' equity
Share capital (note 4) 294,496 294,297
Contributed surplus (note 5) 2,319 1,212
Retained earnings 124,473 118,035
------------------------------------------------------------------------
421,288 413,544
$ 525,300 $ 480,714
------------------------------------------------------------------------
------------------------------------------------------------------------
Contingencies (note 9)
See accompanying notes to Consolidated Financial Statements.


CONSOLIDATED STATEMENTS OF
INCOME AND RETAINED EARNINGS


(Unaudited) Three months ended Six months ended
(thousands of dollars, September 30 September 30
except per share amounts) 2005 2004 2005 2004
------------------------------------------------------------------------
Revenue
Oil and gas $ 32,899 $ 22,864 $ 65,605 $ 45,331
Royalties (4,329) (3,639) (8,188) (7,972)
Profit Petroleum (3,891) (1,822) (7,531) (3,629)
Pipeline and other 996 608 2,009 1,320
------------------------------------------------------------------------
25,675 18,011 51,895 35,050
------------------------------------------------------------------------

Expenses
Production and pipeline 2,114 1,807 4,387 3,223
Interest and financing 809 399 1,925 375
General and administrative 1,045 882 1,981 1,356
Foreign exchange (gain) loss 1,553 (1,322) 1,051 (330)
Stock-based compensation 556 226 1,107 380
Depletion and depreciation 13,412 5,992 29,112 11,394
------------------------------------------------------------------------
19,489 7,984 39,563 16,398
Income before income taxes 6,186 10,027 12,332 18,652
------------------------------------------------------------------------
Income taxes (note 8)
Current 1,793 1,270 3,596 2,010
Future - 1,953 - 4,368
------------------------------------------------------------------------
1,793 3,223 3,596 6,378
------------------------------------------------------------------------

Net income 4,393 6,804 8,736 12,274

Retained earnings,
beginning of period 121,229 52,571 118,035 48,167
Dividends paid (1,149) (1,070) (2,298) (2,136)
------------------------------------------------------------------------
Retained earnings,
end of period $ 124,473 $ 58,305 $ 124,473 $ 58,305
------------------------------------------------------------------------
Net income per share
(note 7)
Basic $ 0.11 $ 0.19 $ 0.23 $ 0.35
------------------------------------------------------------------------
Diluted $ 0.11 $ 0.19 $ 0.22 $ 0.34
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes to Consolidated Financial Statements.


CONSOLIDATED STATEMENTS OF CASH FLOWS


Three months ended Six months ended
(Unaudited) September 30 September 30
(thousands of dollars) 2005 2004 2005 2004
------------------------------------------------------------------------

Cash provided by (used in):
Operating activities
Net income $ 4,393 $ 6,804 $ 8,736 $ 12,274
Add items not involving
cash from operations
Depletion and
depreciation 13,412 5,992 29,112 11,394
Future income taxes - 1,953 - 4,368
Unrealized foreign
exchange (gain) loss 287 (889) 240 (1,554)
Stock-based compensation 556 226 1,107 380
------------------------------------------------------------------------
Funds from operations 18,648 14,086 39,195 26,862
Change in non-cash working
capital (7,500) (16,014) (27,667) 1,492
------------------------------------------------------------------------
11,148 (1,928) 11,528 28,354
------------------------------------------------------------------------
Financing activities
Proceeds from issuance
of shares, net of issuance
costs (note 4) 199 869 199 66,214
Long-term debt (7,849) - 16,847 -
Dividends paid (1,149) (1,070) (2,298) (2,136)
------------------------------------------------------------------------
(8,799) (201) 14,748 64,078
------------------------------------------------------------------------
Investing activities
Addition of property
and equipment (30,306) (27,660) (49,417) (73,977)
Acquisition of property
and equipment - - - -
Restricted cash
contributions (14,675) - (14,675) -
Change in non-cash
working capital 84 (4,382) 21,305 (6,088)
------------------------------------------------------------------------
(44,897) (32,042) (42,787) (80,065)
------------------------------------------------------------------------
Increase (decrease) in cash (42,548) (34,171) (16,511) 12,367
Cash, beginning of period 127,994 67,753 101,957 21,215
Cash, end of period $ 85,446 $ 33,582 $ 85,446 $ 33,582
------------------------------------------------------------------------
Supplemental information:
Interest paid $ 1,641 $ 1,241 $ 1,641 $ 2,043
Taxes paid $ 1,779 $ 1,077 $ 2,965 $ 1,808
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes to Consolidated Financial Statements.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the six months ended September 30, 2005 (unaudited)
All tabulated amounts are in thousands of dollars except per share
amounts and number of shares.


1. BASIS OF PRESENTATION

The interim consolidated financial statements of Niko Resources Ltd. 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, 2005. The disclosures provided herein are incremental to those included with the annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto for the year ended March 31, 2005.

Certain comparative figures have been reclassified to conform to the current period's presentation.

2. ACCOUNTS RECEIVABLE

Included in accounts receivable are:

(a) Since the commencement of production in Bangladesh in November 2004, the Company has sold all of its gas and condensate production in Bangladesh to one customer, the Government of Bangladesh. The Company has reached an agreement with the Government of Bangladesh to sell up to 50 million cubic feet per day and is currently in discussions with the Government of Bangladesh in an attempt to finalize the gas sales price. The Company has received two payments totaling US$4 million since the commencement of production. Included in accounts receivable is US$13.7 million (CAD $15.9 million) outstanding from this customer.

Refer to note 9, Contingencies, for further discussion regarding the Company's ability to collect this receivable.

(b) There are 15 contracts for the sale of natural gas from the Hazira field. Most of the gas contracts are U.S. dollar-denominated and the price had been at the Indian Rupee equivalent of US$3.45 per Mcf while spot sales were at US$3.75 per Mcf. The price provisions in most of the contracts expired in November 2004 and January 2005, and most of the contracts contain renewal provision at prices negotiated based on the market at that time. The Company has signed contracts with one customer at a price of US$3.65 per Mcf and two customers at a price of US$3.75 per Mcf and gas is selling to remaining customers at prices between US$3.45 per Mcf and US$3.65 per Mcf until a new price can be negotiated. Additionally, though no contracts have been signed with the remaining customers, three customers are paying at a rate of US$3.65 per Mcf. Certain customers are not paying the incremental increase in price and are paying at the previously negotiated price of US$3.45. The total amount of the incremental price increases still under negotiation is CAD $0.5 million. The Company is confident the negotiated price will be consistent with the price currently being billed and the full amount owed from these customers will be collected.

(c) With respect to the uncontrolled releases of gas which occurred while drilling the Chattak-2 well and the subsequent relief well Chattak-2A in January and June of 2005, respectively, the Company had a control of well insurance policy with US$20.0 million of coverage for each of the wells. Costs totaling US$21.6 million have been submitted to the insurers related to the first blowout and US$15.3 million has been received to date. Costs to control the second blowout include drilling of the data acquisition well, Chattak-2C, and the relief well, Chattak-2B. These costs total US$29.1 million to the end of September 30, 2005 and have been submitted to the insurers. The Company expects to collect the US$4.7 million outstanding under the first policy and the US$20.0 million outstanding under the second policy, however, no assurance can be given that all costs submitted can be covered under the insurance policies.

3. LONG-TERM DEBT

A project facility (the facility) was established to fund the Company's development activities on India's west coast, specifically the Hazira offshore platform project and the Surat development project. At March 31, 2005, the facility limit was US$30 million of which US$20 million was drawn. During the six months ended September 30, 2005, the loan amount was expanded from US$30 million to US$40 million as certain financial and operational criteria were met at Hazira and the remaining US$20 million was drawn. On September 15, 2005, the Company made a repayment for 11.1 percent (US$2.22 million) of the second US$20 million drawn plus 11.1 percent (US$4.44 million) of the total amount drawn, US$40 million. As at September 30, 2005, US$31.12 million was outstanding. There will be five subsequent semi-annual repayments on March 15 and September 15 of each year; the first two installments for 16.7 percent (US$6.68 million) of the total amount drawn (US$40 million) and the remaining three installments for 14.8 percent (US$5.92 million) of the total amount drawn (US$40 million). Interest is payable semi-annually on March 15 and September 15 and accrues at the London Inter Bank Offered Rate ("LIBOR") plus 4.5 percent from the date of drawdown (LIBOR plus 3 percent once security is perfected).

The security will be perfected once the Management Committee of the Hazira property, which is comprised of members of the Company and its joint venture partner as well as the Indian Government, gives its formal approval.



4. SHARE CAPITAL

(a) Authorized

Unlimited number of Common shares

Unlimited number of Preferred shares

(b) Issued

As at September 30, As at March 31,
(thousands of dollars, 2005 2005
except share amounts) Number Amount Number Amount
------------------------------------------------------------------------
Common Shares
Balance, beginning
of period 38,286,570 $ 294,297 33,542,820 $ 118,338
Issued for cash
pursuant to public
offering - - 4,000,000 171,000
Stock options exercised 25,000 199 743,750 12,767
Contributed surplus - - - 300
------------------------------------------------------------------------
38,311,570 $ 294,496 38,286,570 $ 294,297
------------------------------------------------------------------------
------------------------------------------------------------------------


(c) Stock options

The Company has reserved for issue 3,803,000 common shares for granting under option to directors, officers, and employees. The options become 100 percent vested one to four years after the date of grant and expire four to five years after the date of grant. Stock option transactions for the respective years were as follows:



As at September 30, As at March 31,
2005 2005
------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
------------------------------------------------------------------------
Outstanding,
beginning of
period 1,979,250 $ 26.42 2,540,000 $ 19.92
Granted - - 533,000 41.70
Expired - - (350,000) 22.20
Exercised 25,000 7.96 (743,750) 17.17
------------------------------------------------------------------------
Outstanding,
end of period 1,954,250 $ 26.66 1,979,250 $ 26.42
------------------------------------------------------------------------
Exercisable,
end of period 812,500 $ 20.62 720,000 $ 18.32
------------------------------------------------------------------------
------------------------------------------------------------------------

The following table summarizes stock options outstanding and exercisable
under the plan at September 30, 2005:

Outstanding Options Exercisable Options
------------------------------------------------------------------------
Weighted Weighted
Remaining Average Average
Exercise Price Options (Years) Price Options Price
------------------------------------------------------------------------
$7.14 - $9.00 175,000 0.3 $ 7.95 175,000 $ 7.95
$22.20 - $26.47 1,190,000 2.4 $ 22.61 572,500 $ 22.55
$27.85 - $39.30 316,250 3.7 $ 35.95 65,000 $ 37.71
$45.20 - $49.30 273,000 4.2 $ 45.50 - -
------------------------------------------------------------------------
1,954,250 2.9 $ 26.66 812,500 $ 20.62
------------------------------------------------------------------------
------------------------------------------------------------------------


Stock-based compensation

Prior to April 1, 2003, the Company did not record compensation expense when stock options were issued to employees, officers and directors. Had compensation cost for stock options granted to employees been determined based on a fair value method, the net earnings and earnings per share would approximate the following pro forma amounts:



Three months ended Six months ended
(thousands of dollars, September 30 September 30
except per share amounts) 2005 2004 2005 2004
------------------------------------------------------------------------
Stock-based compensation $ 919 $ 919 $ 1,828 $ 1,828
Net income
As reported $ 4,393 $ 6,804 $ 8,736 $12,274
Pro forma $ 3,474 $ 5,885 $ 6,908 $10,446
Net income per common share
Basic
As reported $ 0.11 $ 0.19 $ 0.23 $ 0.35
Pro forma $ 0.09 $ 0.17 $ 0.18 $ 0.30
Diluted
As reported $ 0.11 $ 0.19 $ 0.22 $ 0.34
Pro forma $ 0.09 $ 0.16 $ 0.18 $ 0.29
------------------------------------------------------------------------
------------------------------------------------------------------------


The pro forma amounts include the compensation costs associated with stock options granted between April 1, 2002 and 2003. The fair value of each option granted was estimated on the date of grant using the Modified Black-Scholes option-pricing model with the following assumptions:



Modified Black-Scholes Assumptions

Three months ended Six months ended
September 30 September 30
(weighted average) 2005 2004 2005 2004
------------------------------------------------------------------------
Fair value of stock options
granted (per option) $ 9.67 $ 8.25 $ 9.67 $ 8.14
Risk-free interest rate 2.86% 2.97% 2.86% 3.00%
Volatility 35% 36% 35% 36%
Expected life (years) 4 4 4 4
Expected annual dividend
per share $ 0.12 $ 0.12 $ 0.12 $ 0.12
------------------------------------------------------------------------
------------------------------------------------------------------------


The weighted average grant-date fair value of options granted during the three and six months ended September 30, 2005 was nil and nil respectively (2004 - $11.87 and $11.71).



5. CONTRIBUTED SURPLUS

As at As at
(thousands of dollars) September 30, 2005 March 31, 2005
------------------------------------------------------------------------
Contributed surplus,
beginning of period $ 1,212 $ 215
Stock-based compensation 1,107 1,297
Stock options exercised - (300)
------------------------------------------------------------------------
Contributed surplus, end of period $ 2,319 $ 1,212
------------------------------------------------------------------------
------------------------------------------------------------------------


6. SEGMENTED INFORMATION

The Company's operations are conducted in one business segment, the oil and gas industry. Revenues, operating profits and net identifiable assets by geographic segments are as follows:



Three months ended September 30, 2005
(thousands of dollars) India Bangladesh Canada Corporate Total
------------------------------------------------------------------------
Revenue 24,883 7,730 286 - 32,899
Segment profit 6,113 3,146 141 (13) 9,387
------------------------------------------------------------------------
------------------------------------------------------------------------


Three months ended September 30, 2004
(thousands of dollars) India Bangladesh Canada Corporate Total
------------------------------------------------------------------------
Revenue 22,794 - 70 - 22,864
Segment profit 9,995 - 15 - 10,010
------------------------------------------------------------------------
------------------------------------------------------------------------


Six months ended September 30, 2005
(thousands of dollars) India Bangladesh Canada Corporate Total
------------------------------------------------------------------------
Revenue 48,799 16,254 552 - 65,605
Segment profit 12,508 4,111 280 (25) 16,874
------------------------------------------------------------------------
------------------------------------------------------------------------


Six months ended September 30, 2004
(thousands of dollars) India Bangladesh Canada Corporate Total
------------------------------------------------------------------------
Revenue 45,191 - 140 - 45,331
Segment profit 19,907 - 25 - 19,932
------------------------------------------------------------------------
------------------------------------------------------------------------


At September 30, 2005
(thousands of dollars) India Bangladesh Canada Corporate Total
------------------------------------------------------------------------
Property and
equipment 221,277 116,407 709 1,697 340,090
Total assets 261,263 169,933 958 93,146 525,300
------------------------------------------------------------------------
------------------------------------------------------------------------


At March 31, 2005
(thousands of dollars) India Bangladesh Canada Corporate Total
------------------------------------------------------------------------
Property and
equipment 222,719 93,880 784 1,891 319,274
Total Assets 267,371 117,334 913 95,096 480,714
------------------------------------------------------------------------
------------------------------------------------------------------------


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

Three months ended Six months ended
September 30 September 30
(thousands of dollars) 2005 2004 2005 2004
------------------------------------------------------------------------
Segment profit 9,387 10,010 16,874 19,932
Interest and other income (762) (202) (1,522) (501)
Financing 809 399 1,925 375
Administrative expenses 1,045 882 1,981 1,356
Stock-based compensation 556 226 1,107 380
Foreign exchange (gain) loss 1,553 (1,322) 1,051 (330)
Income tax expense 1,793 3,223 3,596 6,378
------------------------------------------------------------------------
Net income 4,393 6,804 8,736 12,274
------------------------------------------------------------------------
------------------------------------------------------------------------


7. PER SHARE DATA

Three months ended Six months ended
September 30 September 30
2005 2004 2005 2004
------------------------------------------------------------------------
Weighted average
number of common
shares outstanding 38,286,570 35,552,820 38,286,570 35,214,487
Weighted average
number of diluted
shares outstanding 39,275,634 36,635,031 39,298,203 36,300,566
------------------------------------------------------------------------
------------------------------------------------------------------------


8. INCOME TAXES

India's federal tax law contains a seven-year tax holiday provision that pertains to the commercial production or refining of petroleum and natural gas substances. The benefit of the Indian tax holiday is preserved in the Canadian tax system through a tax sparing provision of the Canada-India Tax Convention.

As a result of the tax holiday in India, the Company pays the greater of 41.82 percent of net income in India after a deduction for the tax holiday and minimum alternative tax of 7.84 percent of Indian income. The Company previously expected to pay minimum alternative tax for fiscal 2006 at a rate of 7.84 percent.

In the current period, production from the land based drilling platform was lower than previously expected resulting in a lower deduction for the tax holiday. As a result, the Company recorded current income taxes at a rate of 41.82 percent of net income after a deduction related to the tax holiday, resulting in an effective current tax rate in India of 14 percent for the quarter and year to date.

9. CONTINGENCIES

(a) The Company has been named as a defendant in a lawsuit that has been filed, in the state of Texas, by a number of plaintiffs who claim to have suffered damages as a result of the uncontrolled releases of gas that occurred at the Chattak-2 well in Bangladesh in January and June of 2005. Damages sought total in excess of US$250 million.

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

(b) A group of petitioners in Bangladesh (the "petitioners") have filed a writ with the Supreme Court of Bangladesh (the "Supreme Court") against various parties including Niko Resources (Bangladesh) Ltd., a subsidiary of the Company. The writ is in the matter of the Company's Joint Venture Agreement with the Government of Bangladesh (the "Government") that includes the Feni and Chattak Marginal Field Developments, compensation for the uncontrolled flow problems that occurred in the Chattak field in January and June of 2005 as well as payments to the Company for production from the Feni Field.

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

(i) that the Joint Venture Agreement be declared null and illegal,

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

(iii) that the Government withhold future payments to the Company relating to production from the Feni Field (US$13.7 million as at September 30, 2005), and

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

The Company believes that the outcome of the writ with respect to the first two issues is not determinable.

The Company believes that the full amount owed with respect to the Feni Field will be collected from the Government. As such, a writedown to this receivable has not been recorded in these interim consolidated financial statements.

The Company has been permitted to make payments to Bangladesh vendors. However, payments to foreign vendors from Bangladesh are not permitted. The Company's foreign vendors are being paid by Niko Resources (Bangladesh) Ltd.

10. SUBSEQUENT EVENTS

(a) Subsequent to September 30, 2005, the performance guarantee the Company and its joint venture partner had to the Government of Bangladesh in the amount of US$20 million as specified in the production sharing agreement for Block 9 was extended to October 15, 2006. The Government of Bangladesh has the right to collect on this guarantee if the Company does not carry out specified geological, geophysical and drilling activities. The Company considers the contingent future payment amount of US$20 million to be a reasonable approximation of fair value. There is risk related to the amount of contingent future payment recorded due to fluctuations in foreign exchange rates.

In the past, the Company had provided the full US$20 million of the guarantee to the Government of Bangladesh and had recourse to recover US$6.7 million from its joint venture partner if the Government of Bangladesh collected on the guarantee.

As part of the most recent renewal of the guarantee, the Company provided US$13.3 million of the guarantee and its joint venture partner provided the remaining US$6.7 million. The renewal of the guarantee becomes effective upon return of the previous guarantee provided by the Company for US$20 million on behalf of both the Company and its joint venture partner. Upon cancellation of the previous US$20 million guarantee, the Company will have a US$13.3 million guarantee outstanding.

Additionally, upon the most recent renewal of the guarantee, the guarantee is now considered restricted cash. As the renewal occurred subsequent to quarter-end, the restricted cash balance as at September 30, 2005 does not include this guarantee. See note 10. b) for further clarification regarding the restricted cash balance as at September 30, 2005.

(b) On July 20, 2005, the Company provided a bank guarantee in the amount of US$12 million to Century Resources International Pty Ltd., for Century's drilling rig and associated equipment, in connection with the drilling of the second Chattak relief well. The bank guarantee was returned to the Company in full on October 26, 2005.

The restricted cash balance as at September 30, 2005 pertains to the Century bank guarantee.

November 10, 2005

Certain statements in this press release are forward-looking statements. Specifically, this press release contains forward-looking statements relating to management's approach to operations, estimates of future sales, production and deliveries, business plans for drilling and development, estimated amounts and timing of capital expenditures, anticipated operating costs, royalty rates, cash flows, transportation plans and capacity, anticipated access to infrastructure or other expectations, beliefs, plans, goals, objectives, assumptions and statements about future events or performance. The reader is cautioned that the assumptions used in the preparation of such information, although considered reasonable by Niko at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: general economic, market and business conditions; industry capacity; competitive action by other companies; fluctuations in oil and gas prices; the results of exploration and development drilling and related activities; the uncertainty of estimates and projections relating to productions, costs and expenses; uncertainties as to the availability and cost of financing; fluctuations in currency exchange rates; the imprecision in reserve estimates; risks associated with oil and gas operations, such as operational risks in exploring for, developing and producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits; the weather in the Company's area of operations; the ability of suppliers to meet commitments; changes in environmental and other regulations; actions by governmental authorities including changes in laws and increases in taxes; decisions or approvals of administrative tribunals; risks in conducting foreign operations (for example, political and fiscal instability or the possibility of civil unrest or military action in countries such as India and Bangladesh); the effect of acts of, or actions against international terrorism; and other factors, many of which are beyond the control of Niko. There is no representation by Niko that the actual results achieved during the forecast period will be the same in whole or in part as those forecast.

Contact Information

  • Niko Resources Ltd.
    Edward Sampson
    Chairman of the Board, President & CEO
    (403) 262-1020
    or
    Niko Resources Ltd.
    Richard Alexander
    Vice President Finance
    (403) 262-1020