Niko Resources Ltd.
TSX : NKO

Niko Resources Ltd.

August 11, 2005 06:35 ET

Niko Resources Announces 1st Quarter Financial Results

CALGARY, ALBERTA--(CCNMatthews - Aug. 11, 2005) - Niko Resources Ltd. (TSX:NKO) announced its financial results for the three months ended June 30, 2005.

HIGHLIGHTS

- Awarded two new blocks under the Government of India's New Exploration Licensing Policy, NELP V

- The fourth and fifth wells on the offshore platform at Hazira began production and commenced drilling of sixth and final new gas well

- Year-over-year production increased 98 percent



Three months ended June 30 2005 2004 % Change
------------------------------------------------------------------------
FINANCIAL
(thousands of dollars, except
per share and share amounts)
Petroleum and natural gas sales 32,706 22,467 46
Funds from operations 20,092 14,433 39
Per share, diluted ($) 0.51 0.40 28
Net income 4,343 5,470 (21)
Per share, diluted ($) 0.11 0.15 (27)
Capital expenditures 19,111 46,317 (59)
Total assets 522,783 370,603 41
Shareholders' equity 417,289 236,623 76
Weighted average common shares outstanding 38,287 34,876 10
Common shares outstanding
Basic (thousands) 38,287 35,543 8
Diluted (thousands) 40,266 38,228 5

OPERATIONS
Average daily production
Oil (bbls/day) 114 38 200
Natural gas (mmcf/day) 85 43 98
Total combined (boe/day) 14,238 7,180 98
Revenues, royalties and operating costs
Gross revenue received ($/boe) 25.24 34.39 (27)
Royalties ($/boe) (2.98) (6.63) 55
Profit petroleum ($/boe) (2.81) (2.77) (1)
Operating costs ($/boe) (1.68) (1.91) 12
------------------------------------------------------------------------
Operating netback ($/boe) 17.77 23.08 (23)
Drilling activity
Gross wells 2.0 6.0 (67)
Net wells 1.1 2.7 (59)
------------------------------------------------------------------------
------------------------------------------------------------------------


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 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 measure 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, basic and diluted, are calculated by dividing the funds from operations by the weighted average number of shares outstanding and the weighted average number of diluted shares outstanding, respectively.

FINANCIAL

During the three months ended June 30, 2005, funds from operations increased to $20.1 million or $0.51 per share compared to $14.4 million or $0.40 per share in the period ended June 30, 2004 as revenues increased in India and the Company added production in Bangladesh. The Company earned net income of $4.3 million or $0.11 per share compared to $5.5 million or $0.15 per share in the same period in the previous year. The decrease is due to the increases in depletion, interest and financing expenses which were partially offset by the increase in revenues, the foreign exchange gain and the decreases in royalties and income taxes.

OPERATIONS REVIEW

OPERATIONS UPDATE

India

The fourth and fifth new wells drilled on the offshore platform in Hazira were put on production during the quarter resulting in a total of six wells, including an appraisal well, currently producing on the platform. Gas production from the field was curtailed during the quarter due to a fire in the plant of Essar Steel, which is one of the largest customers of Hazira gas. Production from Hazira for the quarter averaged 41 million cubic feet per day (net). The sixth planned gas well is currently drilling from the platform, which will complete the current stage of the gas development. This well will be drilled to the prospective oil interval and will be tested if oil sands are encountered. The Oil Development Plan at Hazira has been approved. The drilling of at least three additional wells from the platform for oil production will commence immediately after completion of the sixth and final gas well, which is currently being drilled.

In Surat, the Company drilled the NSA-8 well, which has been tied in and wellsite facilities are currently being installed. This well is expected to increase gas production to between 12 and 14 million cubic feet per day on average for fiscal 2006.

In the D6 Block, an additional gas discovery was made during the quarter in the E-1 well. This discovery is in addition to the large gas discoveries made in 2002, 2003 and 2004 on the block and further confirms the D6 Block's reputation as being a "world class" gas province. The E-1 well, which is located near the edge of the new 3D seismic area, encountered thick channel sand gas pay. The P-1A well, the fifteenth well in the block, is currently testing and has 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. Testing of one of the zones is currently underway. These very encouraging results from both the E-1 and P-1A wells confirm the potential of discovering large reserves on the new 3D seismic area. After completion of the P-1A well, drilling will commence on the AA-1 well, which is also located on the new 3D seismic. 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. 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 is necessary to prepare development plans for the six consecutive gas discoveries made to date. All of these discoveries are within the original 1,800 square kilometre 3D seismic area. Currently, a 1,700 square kilometer 3D seismic program is being acquired that will extend to the south of the existing 3D seismic coverage. Drilling on this new seismic area is expected to begin in late calendar 2005.

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

The Company was awarded a 100% working interest in the 236,379 acre onland 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 kilometers of 3D seismic and the drilling of five wells.

The Company and its partner, Reliance Industries Limited (Reliance), have also been awarded the 4,211,350 acre deep water block MN-DWN-2003/1 (D-4) located in the Mahanadi basin off the northern part of the east coast of India. The Company has a 15% working interest in this block, of which Reliance will be the operator.

Bangladesh

Combined gas production from the three wells in the Feni Field averaged 34 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 increase production to between 35 and 40 million cubic feet per day by 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. Renewed relief drilling operations commenced on July 30, 2005 and production from Chattak is expected to commence in late calendar 2005.

An appraisal program for both the Lalmai and Bangora discoveries in Block 9 has been approved, which includes acquiring 2D and 3D seismic programs 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 programs and drilling are expected to commence in October 2005 and in the first quarter of calendar 2006, respectively. 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 late calendar 2005.

Production Forecast

Niko expects fiscal 2006 production to average 120 to 140 million cubic feet per day (net) with the expected addition of production from Chattak and Block 9 during the year. Production from Hazira is expected to be between 50 and 55 million cubic feet per day (net), production from Surat is expected to be between 12 and 14 million cubic feet per day and production from Feni is expected to be between 30 and 35 million cubic feet per day.

Production at Block 9 is scheduled to commence in late calendar 2005. Production is scheduled to increase when Chattak West comes online in late calendar 2005 and increase with the completion of three additional planned wells.

The Company's total production outlook for fiscal 2006 is expected to average 120 to 140 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 quarter ended June 30, 2005, operating costs were $1.68 per boe and are expected 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 August 10, 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 past year, 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 Management's Discussion and Analysis 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 measure 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, basic and diluted, are calculated by dividing the funds from operations by the weighted average number of shares outstanding and the weighted average number of diluted shares outstanding, respectively.

Barrel of oil equivalent (boe) is a measure used throughout the Management's Discussion and Analysis. 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 production. Therefore, the results from oil production, which includes 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 month periods ended June 30, 2005 and 2004:



Three months ended June 30
2005 2004
------------------------------------------------------------------------
Natural gas (6:1) (6:1)
total total total
($/Mcf) ($/boe) ($/boe)

Price 4.17 25.24 34.39
Royalties (0.49) (2.98) (6.63)
Profit petroleum (0.47) (2.81) (2.77)
Operating costs (0.27) (1.68) (1.91)
------------------------------------------------------------------------
Operating netback 2.94 17.77 23.08
Pipeline and other income 0.78 1.09
Pipeline expense (0.08) (0.25)
General and administrative (0.72) (0.72)
Interest and financing (0.86) 0.04
Current taxes (1.39) (1.13)
------------------------------------------------------------------------
Cash flow netback 15.50 22.11
Foreign exchange 0.39 (1.52)
Stock based compensation (0.42) (0.24)
Depletion and depreciation (12.12) (8.27)
Future income taxes - (3.70)
------------------------------------------------------------------------
Earnings netback 3.35 8.38
------------------------------------------------------------------------
------------------------------------------------------------------------


Netbacks are calculated by dividing the revenues and costs related to gas production in India and Bangladesh and revenue 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, respectively.

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




Three months ended Joint
June 30, 2005 Venture(1) Surat India Bangladesh Canada
------------------------------------------------------------------------
Average daily production
Oil (bbls/day) 24 - 24 37 53
Natural gas (mmcf/day) 41 10 51 34 -
Total combined (boe/day) 6,926 1,655 8,581 5,604 53
Revenues, royalties
and operating costs
Gross revenue received
($/boe) 30.93 29.36 30.63 16.72 52.67
Royalties ($/boe) (4.75) (5.53) (4.90) - (6.43)
Profit petroleum ($/boe) (3.07) - (2.48) (3.35) -
Operating costs ($/boe) (1.70) (3.52) (2.05) (1.06) (5.79)
------------------------------------------------------------------------
Operating netback ($/boe) 21.41 20.31 21.20 12.31 40.45
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) The joint venture includes results from Hazira, Bhandut, Cambay and
Sabarmati.

Three months ended Joint
June 30, 2004 Venture(1) Surat India Bangladesh Canada
------------------------------------------------------------------------
Average daily production
Oil (bbls/day) 18 - 18 - 20
Natural gas (mmcf/day) 39 4 43 - -
Total combined (boe/day) 6,525 635 7,160 - 20
Revenues, royalties
and operating costs
Gross revenue received
($/boe) 34.38 34.25 34.37 - 37.81
Royalties ($/boe) (6.47) (8.30) (6.63) - (7.12)
Profit petroleum ($/boe) (3.04) - (2.77) - -
Operating costs ($/boe) (0.83) (12.69) (1.88) - (12.71)
------------------------------------------------------------------------
Operating netback ($/boe) 24.04 13.26 23.09 - 17.98
------------------------------------------------------------------------
------------------------------------------------------------------------

(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 46 percent in the quarter ended June 30, 2005 to $32.7 million from $22.5 million in the same period in the previous year. The primary reason for the increase is production from Bangladesh, which began in November of 2004 and added an additional $8.5 million of revenue. Revenue in India increased to $23.9 million from $22.4 million in the comparative period due to a 19 percent increase in natural gas production, from 43 to 51 million cubic feet per day (net). The increase is partially offset by a decrease in the selling price before royalties from $5.72 per Mcf to $5.09 per Mcf due to the strengthening of the Canadian dollar versus the U.S. dollar.

Net income has decreased 21 percent to $4.3 million in the quarter ended June 30, 2005 from $5.5 million in the same period in the previous year. Net income has decreased due to the increases in depletion, interest and financing expenses, which were partially offset by the increase in revenues, the foreign exchange gain and the decreases in royalties and income taxes. Net income per share decreased to $0.11 per share for the quarter compared to $0.15 per share in the same period in the previous year.

Funds from operations increased to $20.1 million in the quarter from $14.4 million in the same period in the previous year due to an increase in production from India and the addition of production in Bangladesh.

A total of $19.1 million was spent on capital additions in the quarter compared to $46.3 million in the same period in the previous year. The lower capital expenditures are the result of the decreased activity in Feni and Block 9 as compared to the same period in the previous year and the offshore platform in Hazira being completed during the quarter ended June 30, 2004. In Hazira, $6.5 million was spent on the drilling and completion of two wells on the offshore platform. In Surat, $0.9 million was spent on the workover of one well and the drilling of another. In the D-6 block, off the east coast of India, $2.7 million was spent on drilling activities for the E-1 and P-1A wells. In Bangladesh, $7.8 million was spent on pipeline and facility construction in Chattak.

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 individual customer accounted for 32 percent of Niko's sales in India during the first quarter of fiscal 2006. Discussions are ongoing with customers in Gujarat for the sale of Hazira and Surat gas. The operator of Block D-6 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 Niko 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 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 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 began in November 2004 from the Company's Feni discovery at a rate in excess of 20 million cubic feet per day. Niko has reached an agreement with the Government of Bangladesh to purchase up to 50 million cubic feet per day from Feni. Niko is currently finalizing the gas sales price. In the interim, the Company is recording sales at US$2.20 per Mcf. Under the terms of the 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 46 percent in the quarter ended June 30, 2005 to $32.7 million from $22.5 million in the same period in the previous year. The primary reason for the increase is production from Bangladesh, which began in November of 2004 and added an additional $8.5 million of revenue. Revenue in India increased to $23.9 million from $22.4 million in the comparative period due to a 19 percent increase in natural gas production, from 43 to 51 million cubic feet per day (net). The increase is partially offset by a decrease in the selling price before royalties from $5.72 per Mcf to $5.09 per Mcf due to the strengthening of the Canadian dollar versus the U.S. dollar.

Royalties

Under the terms of the gas contracts in India, the purchaser is responsible for all royalties and sales taxes and the royalties increase proportionately to gas sales. These charges are levied by the Government and vary according to the type of purchaser. The Company charged and remitted a total of $3.9 million in the quarter compared to the $4.3 million remitted in the same period in the previous year. The Company does not incur any royalty expense in Bangladesh and as a result, royalties are comparable with the prior year despite an increase in revenue.

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 June 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 $1.9 million in the quarter (2004 - $1.8 million).

In Bangladesh, Bangladesh Petroleum Exploration and Production Company (BAPEX) is entitled to a sliding scale share of the revenues. BAPEX's share increases as the Company recovers a multiple of its investment. The current allocation of profit petroleum production is 20 percent of revenues and amounted to $1.7 million for the period (2004 - nil). Production from Bangladesh commenced in November of 2004.

Pipeline and Other Income

During the quarter, the Company earned pipeline tariff revenue of $0.2 million (2004 - $0.4 million) and interest income of $0.8 million (2004 - $0.3 million) was earned on excess cash balances. The increase in interest income is the result of having larger average cash balances on hand relative to the comparative period due to equity financings in fiscal 2005.

Operating Expenses

On a unit-of-production basis, operating costs decreased by 12 percent to $1.68 per boe in the quarter ended June 30, 2005 from $1.91 per boe in the same period in the previous year. The decrease is partially due to one-time start-up costs in Surat, which were incurred in the period ended June 30, 2004 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.

General and Administrative

The Company's general and administrative costs for the quarter increased by 80 percent from $0.5 million to $0.9 million when compared to the same period in the prior year. The increase is due to increased professional fees and lower overhead recovery in Bangladesh due to lower capital spending.

Foreign Exchange

The Company's long-term debt is denominated in U.S. dollars. Due to the weakening of the Canadian dollar in the quarter, the Company incurred an unrealized foreign exchange loss on the debt. The Company repatriates its revenues out of India and Bangladesh 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, the foreign exchange loss related to the debt was more than offset by a gain on U.S. dollar denominated funds due to the weakening of the Canadian dollar in the quarter for a net gain in the quarter of $0.5 million compared to a loss of $1.0 million in the same period in the previous year. The Company will continue to incur foreign exchange gains and losses due to fluctuations in the currency market.

Depletion and Depreciation

Depletion in India was $10.2 million or $13.11 per boe of production in the quarter compared to $5.3 million or $8.18 per boe during the same period in the previous year. The increase is due both to the 20 percent increase in production and the increase in the depletion rate as a result of production and a downward technical revision in the Hazira proved estimate by 39 billion cubic feet as at March 31, 2005.

Depletion in Bangladesh was $0.5 million in the quarter or $10.41 per unit.

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. The Company pays income tax at the highest rate of the jurisdictions in which it operates. The Company's current tax provision increased to $1.8 million from $0.8 million. The increase in current taxes relates to the addition of Bangladesh production and the increase in Indian production. The current tax provision includes Indian taxes of $1.6 million and Bangladesh tax of $0.2 million. There is no future tax provision in the current 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.

The Company pays tax in Bangladesh at a rate of 3.75 percent on revenues net of profit petroleum amounting to $0.2 million in the quarter. As of July 1, 2005, this rate is expected to increase to 4 percent.

Capital Expenditures

A total of $19.1 million was spent on capital additions in the quarter compared to $46.3 million in the same period in the previous year. The lower capital expenditures are the result of the decreased activity in Feni and Block 9 as compared to the same period in the previous year and the offshore platform in Hazira being completed during the quarter ended June 30, 2004. In Hazira, $6.5 million was spent on the drilling and completion of two wells on the offshore platform. In Surat, $0.9 million was spent on the workover of one well and the drilling of another. In D-6 off the east coast of India, $2.7 million was spent on drilling activities for the E-1 and P-1A wells. In Bangladesh, $7.8 million was spent on pipeline and facility construction in Chattak.

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 June 30, 2005.

UPDATE ON SIGNIFICANT PROJECTS

India

The Company has a 33.33 percent working interest in the offshore platform at Hazira. The platform was completed in April 2004 and five of six planned wells are on production. The sixth and final gas well is currently being drilled. Production from the platform commenced on August 6, 2004. Capital expenditures in the quarter were $6.5 million (net) related to drilling activities on the offshore platform.

The Company has a 10 percent working interest in the D-6 Block off the east coast of India. Capital expenditures in the quarter were $2.7 million (net) for drilling activities for the E-1 and P-1A wells. Drilling of the fourteenth consecutive successful well, E-1, in the D-6 Block was completed in April 2005. Testing of the first well on the new 3D seismic, the fifteenth well, P-1A, is currently underway.

The Company has a 10 percent working interest in the NEC-25 Block off the east coast of India. During the quarter, the Company began the process of obtaining a reserve evaluation report which is necessary to prepare development plans for the six consecutive gas wells drilled to date. Capital expenditures in the quarter were $0.1 million (net) related to seismic and drilling activities. The Company is currently acquiring an additional 1,700 square kilometre seismic area on which drilling is expected to commence in late calendar 2005.

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 $0.2 million related to development activities.

Three drilling locations are scheduled to be drilled 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. The Company expects the majority of costs to be covered by insurance. Actual costs cannot be estimated until the well is complete and a final assessment including all appropriate clearances resulting from the blowout are complete. Renewed relief drilling operations commenced on July 30, 2005 and production from Chattak is expected to commence by late calendar 2005. Capital expenditures in the quarter were $7.8 million related to facility and pipeline construction.

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 encountered commercial quantities of natural gas. An appraisal program for both the Lalmai and Bangora discoveries has been approved, which includes acquiring 2D and 3D seismic programs 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. Capital expenditures during the quarter were $0.3 million (net). Planned expenditures for fiscal 2006 are between $15 and $20 million (net). Production in Block 9 is targeted for late calendar 2005.

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, basic and diluted, is calculated by dividing the funds from operations by the weighted average number of shares outstanding or the weighted average number of diluted shares outstanding respectively.

The following table sets forth selected financial information of the Company for each of the eight most recently completed quarters to June 30, 2005:


Three months ended
(thousands of dollars, Sep 30, Dec 31, Mar 31, Jun 30,
except per share amounts) 2004 2004 2005 2005
------------------------------------------------------------------------
Petroleum and natural gas sales 22,864 27,849 34,670 32,706
Funds from operations
Per share
- basic ($) 0.38 0.47 1.16 0.52
- diluted ($) 0.37 0.46 1.13 0.51
Net income 6,804 14,684 47,264 4,343
Per share
- basic ($) 0.19 0.41 1.29 0.11
- diluted ($) 0.19 0.40 1.26 0.11
------------------------------------------------------------------------

Three months ended
(thousands of dollars, Sep 30, Dec 31, Mar 31, Jun 30,
except per share amounts) 2003 2003 2004 2004
------------------------------------------------------------------------
Petroleum and natural gas sales 21,199 19,958 20,851 22,467
Funds from operations
Per share
- basic ($) 0.31 0.32 0.33 0.41
- diluted ($) 0.30 0.31 0.32 0.40
Net income 6,569 5,045 6,840 5,470
Per share
- basic ($) 0.20 0.15 0.20 0.16
- diluted ($) 0.19 0.15 0.20 0.15
------------------------------------------------------------------------
------------------------------------------------------------------------


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

Overall revenues have increased due to increased volumes. Revenues have fluctuated in part due to the change in price 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 strengthened against the Canadian dollar thus far in fiscal 2006. In the quarter ended December 31, 2004, Bangladesh production began, increasing revenues.

Depletion expense increased throughout fiscal 2004 due to increased production and the inclusion of the Surat exploration and Hazira development costs in the cost base. Depletion expense increased in fiscal 2005 because of increased production including the commencement of production in Bangladesh and a downward technical revision in the Hazira proved reserve estimate by 39 billion cubic feet.

There was a tax recovery in the third quarter of fiscal 2005 related to Canadian tax pools available for future claim. In the quarter ended March 31, 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.

Profit petroleum expense decreased over fiscal 2004 due to deducting capital expenditures from the cash flow from Hazira prior to calculating the charge. Profit petroleum increased in quarter four of fiscal 2005 due to the addition of Bangladesh production.

There was a foreign exchange gain in fiscal 2004 and the first quarter of fiscal 2006 due to the volatility in the foreign exchange markets as the Company holds U.S. dollars to fund planned capital expenditures in that currency. In fiscal 2005, there was a foreign exchange gain on the translation of the long-term debt, which is held in U.S. dollars.

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

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

Liquidity

At June 30, 2005, the Company had a working capital surplus of $116.0 million, which included $128.0 million of cash and cash equivalents. The Company expects to spend in excess of cash flow in the current year. The Company has planned capital expenditures of between $120 and $140 million during fiscal 2006, $19.1 million of which has been spent year to date and expects to finance remaining expenditures with working capital and funds from operations. During the quarter, the Company drew the remaining US$20 million available under the project 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.

At June 30, 2005, the Company's current portion of long-term debt was $16.4 million and interest is payable semi-annually on the outstanding principal. The payments are expected to be funded with working capital and funds from operations. The amount of future interest payments is uncertain due to the floating interest rate on long-term debt. If the Company fails to meet a number of positive and negative covenants, the loan will become payable at the discretion of the debtor.

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

Capital Resources

The Company has planned capital expenditures of between $120 and $140 million for the 2006 fiscal year, of which $19.1 million has been spent year to date and expects to finance the remaining expenditures with working capital and funds from operations.

At June 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 Contract. The Government of Bangladesh has the right to collect on this guarantee if the Company does not carry out work commitments required under the Production Sharing Contract. The fair value and the amount of the contingent future payment do not differ significantly due to the short-term nature of the contingent future payment. There is risk related to the amount of the contingent future payment recorded due to fluctuations in foreign exchange rates. Subject to risk of non-collection, the Company has recourse to recover US$6.7 million from the other joint-venture partner if the Government of Bangladesh collects on the guarantee.

During the quarter, the project facility 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.

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 liabilities 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 liabilities 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 August 10, 2005, the Company had the following outstanding shares:

Number Amount
------------------------------------------------------------------------
Common shares 38,286,570 $ 304,365,000
Preferred shares nil nil
Stock options 1,979,250 -
------------------------------------------------------------------------
------------------------------------------------------------------------


Outlook

Over the remainder of the year, the Company looks forward to the results of drilling on the new seismic area in the D-6 Block and planned gas wells on NEC-25, D-6 Block, Chattak, Feni and Block 9 and oil wells in Hazira. Obtaining the two new blocks in India, Cauvery and D-4, adds two exciting plays to increase the Company's future growth potential.



CONSOLIDATED BALANCE SHEETS

As at June 30, As at March 31,
(thousands of dollars) 2005 2005
------------------------------------------------------------------------
(Unaudited) (Audited)
ASSETS
Current assets
Cash $ 127,994 $ 101,957
Accounts receivable 58,395 46,219
Prepaid expenses 271 303
------------------------------------------------------------------------
186,660 148,479
Income tax receivable 13,180 12,961
Property and equipment 322,943 319,274
------------------------------------------------------------------------
$ 522,783 $ 480,714
------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 53,340 $ 40,694
Current portion of long-term debt 16,350 7,088
Current tax payable 950 326
------------------------------------------------------------------------
70,640 48,108
Asset retirement obligation 4,902 4,644
Long-term debt (note 3) 29,952 14,418
------------------------------------------------------------------------
105,494 67,170
Shareholders' equity
Share capital (note 4) 294,297 294,297
Contributed surplus (note 5) 1,763 1,212
Retained earnings 121,229 118,035
------------------------------------------------------------------------
417,289 413,544
------------------------------------------------------------------------
$ 522,783 $ 480,714
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to Consolidated Financial Statements.


CONSOLIDATED STATEMENTS OF
INCOME AND RETAINED EARNINGS

(Unaudited)
(thousands of dollars, Three months ended June 30
except per share amounts) 2005 2004
------------------------------------------------------------------------

Revenue
Oil and gas $ 32,706 $ 22,467
Royalties (3,859) (4,333)
Profit petroleum (3,640) (1,807)
Pipeline and other 1,013 712
------------------------------------------------------------------------
26,220 17,039
------------------------------------------------------------------------

Expenses
Production and pipeline 2,273 1,416
Interest and financing 1,116 (24)
General and administrative 936 474
Foreign exchange loss (gain) (502) 992
Stock-based compensation 551 154
Depletion and depreciation 15,700 5,402
------------------------------------------------------------------------
20,074 8,414
------------------------------------------------------------------------
Income before income taxes 6,146 8,625
------------------------------------------------------------------------
Income taxes (note 8)
Current 1,803 740
Future - 2,415
------------------------------------------------------------------------
1,803 3,155
------------------------------------------------------------------------

Net income 4,343 5,470

Retained earnings, beginning of period 118,035 48,167
Dividends paid (1,149) (1,066)
------------------------------------------------------------------------
Retained earnings, end of period $ 121,229 $ 52,571
------------------------------------------------------------------------
Net income per share (note 7)
Basic $ 0.11 $ 0.16
------------------------------------------------------------------------
Diluted $ 0.11 $ 0.15
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to Consolidated Financial Statements.


CONSOLIDATED STATEMENTS OF CASH FLOWS

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

Cash provided by (used in):
Operating activities
Net income $ 4,343 $ 5,470
Add items not involving cash from
operations
Depletion and depreciation 15,700 5,402
Future income taxes - 2,415
Foreign exchange loss (gain) (502) 992
Stock-based compensation 551 154
------------------------------------------------------------------------
Funds from operations 20,092 14,433
Change in non-cash working capital (19,712) 15,849
------------------------------------------------------------------------
380 30,282
------------------------------------------------------------------------
Financing activities
Proceeds from issuance of shares,
net of issuance costs (note 4) - 65,345
Long-term debt 24,696 -
Dividends paid (1,149) (1,066)
------------------------------------------------------------------------
23,547 64,279
------------------------------------------------------------------------
Investing activities
Addition of property and equipment (19,111) (46,317)
Change in non-cash working capital 21,221 (1,706)
------------------------------------------------------------------------
2,110 (48,023)
------------------------------------------------------------------------
Increase in cash 26,037 46,538
Cash, beginning of period 101,957 21,215
Cash, end of period $ 127,994 $ 67,753
------------------------------------------------------------------------
Supplemental information:
Interest paid $ - $ 802
Taxes paid $ 1,186 $ 731
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to Consolidated Financial Statements.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the three months ended June 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.

2. ACCOUNTS RECEIVABLE

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 finalizing 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$8.6 million outstanding from this customer.

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 quarter, 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. The first repayment of the loan occurred on March 15, 2005 based on 11.1 percent of the US$20 million outstanding at that time. The next repayment will be on September 15, 2005 for 11.1 percent of the second US$20 million drawn plus 11.1 percent of the total amount drawn, US$40 million. 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 of the total amount drawn (US$40 million) and the remaining three installments for 14.8 percent 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).

4. SHARE CAPITAL

(a) Authorized

Unlimited number of Common shares

Unlimited number of Preferred shares



(b) Issued

As at June 30, As at March 31,
2005 2005
------------------------------------------------------------------------
(thousands of dollars,
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 - - 743,750 12,767
Contributed surplus - - - 300
Share issue costs - - - (8,108)
------------------------------------------------------------------------
38,286,570 $ 294,297 38,286,570 $ 294,297
------------------------------------------------------------------------
------------------------------------------------------------------------


(c) Stock options

The Company has reserved for issue 2,400,000 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 two to five years after the date of grant. Stock option transactions for the respective years were as follows:



As at June 30, As at March 31,
2005 2005
------------------------------------------------------------------------
Average Weighted Average Weighted
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 - - (743,750) 17.17
------------------------------------------------------------------------
Outstanding,
end of period 1,979,250 $ 26.42 1,979,250 $ 26.42
------------------------------------------------------------------------
Exercisable,
end of period 758,750 $ 19.27 720,000 $ 18.32
------------------------------------------------------------------------
------------------------------------------------------------------------

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


Outstanding Options Exercisable Options
------------------------------------------------------------------------
Weighted Weighted
Remaining Average Average
Exercise Price Options (Years) Price Options Price
------------------------------------------------------------------------
$ 7.14 - $ 9.00 200,000 0.5 $ 7.95 200,000 $ 7.95
$ 22.20 - $ 26.47 1,190,000 2.6 $ 22.61 522,500 $ 22.32
$ 27.85 - $ 39.30 316,250 3.9 $ 35.95 36,250 $ 37.67
$ 45.20 - $ 49.30 273,000 4.5 $ 45.50 - $ -
------------------------------------------------------------------------
1,979,250 3.2 $ 26.42 758,750 $ 19.27
------------------------------------------------------------------------
------------------------------------------------------------------------


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 these stock options granted to employees been determined based on a fair value method, the net income and net income per share would approximate the following pro forma amounts:



Three months ended June 30
(thousands of dollars,
except per share amounts) 2005 2004
------------------------------------------------------------------------
Stock-based compensation $ 909 $ 909
Net income
As reported $ 4,343 $ 5,470
Pro forma $ 3,434 $ 4,561
Net income per common share
Basic
As reported $ 0.11 $ 0.16
Pro forma $ 0.09 $ 0.13
Diluted
As reported $ 0.11 $ 0.15
Pro forma $ 0.09 $ 0.13
------------------------------------------------------------------------
------------------------------------------------------------------------


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 June 30
(weighted average) 2005 2004
------------------------------------------------------------------------
Fair value of stock options granted
(per option) $ 9.67 $ 8.05
Risk-free interest rate 2.86% 2.99%
Volatility 35% 36%
Expected life (years) 4 4
Expected annual dividend per share $ 0.12 $ 0.12
------------------------------------------------------------------------
------------------------------------------------------------------------


There were no options granted during the three months ended June 30, 2005. The weighted average grant-date fair value of options granted during the three months ended June 30, 2004 was $11.59.



5. CONTRIBUTED SURPLUS

As at As at
June 30, March 31,
(thousands of dollars) 2005 2005
------------------------------------------------------------------------
Contributed surplus, beginning of period $ 1,212 $ 215
Stock-based compensation 551 1,297
Stock options exercised - (300)
------------------------------------------------------------------------
Contributed surplus, end of period $ 1,763 $ 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:




(thousands of Three months ended and as at June 30, 2005
dollars) India Bangladesh Canada Corporate Total
------------------------------------------------------------------------
Revenue 23,916 8,524 266 - 32,706
Segment profit 6,395 965 139 (12) 7,487
Property and
equipment 222,874 97,520 738 1,811 322,943
Total assets 267,904 136,960 957 116,962 522,783
------------------------------------------------------------------------
------------------------------------------------------------------------



(thousands of Three months ended and as at June 30, 2005
dollars) India Bangladesh Canada Corporate Total
------------------------------------------------------------------------
Revenue 22,398 - 69 - 22,467
Segment profit 9,912 - 10 - 9,922
------------------------------------------------------------------------
------------------------------------------------------------------------


(thousands of As at March 31, 2005
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 June 30
(thousands of dollars) 2005 2004
------------------------------------------------------------------------
Segment profit 7,487 9,922
Interest income 760 299
Financing (1,116) 24
Administrative expenses (936) (474)
Foreign exchange gain (loss) 502 (992)
Stock-based compensation (551) (154)
Income tax expense (1,803) (3,155)
------------------------------------------------------------------------
Net income 4,343 5,470
------------------------------------------------------------------------
------------------------------------------------------------------------


7. PER SHARE DATA

The weighted average number of common shares issued and outstanding for the three months ended June 30, 2005 was 38,286,570 (year ended March 31, 2005 - 35,657,403). In computing diluted per share amounts, 1,059,320 shares with respect to stock options were added to the weighted average number of common shares outstanding for the three months ended June 30, 2005.

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.

9. SUBSEQUENT EVENT

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 expires on July 19, 2006. There is risk related to the amount of the contingent future payment recorded due to fluctuations in foreign exchange rates.

August 11, 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