Niko Resources Ltd.
TSX : NKO

Niko Resources Ltd.

June 27, 2005 08:30 ET

Niko Achieves Record Results

CALGARY, ALBERTA--(CCNMatthews - June 27, 2005) - Niko Resources Ltd. (TSX:NKO) reports results for the three and twelve months ended March 31, 2005.

Fourth Quarter Highlights and Summary Financial Review

- Gas production up 117 percent to 91 mmcf per day

- Exploration success at G-1 on the D6 Block

- Receipt of a tax holiday in India

Financial

For the year ending March 31, 2005, petroleum and natural gas sales were $107.9 million compared to $85.8 million in the comparative period. Cash flow from operations increased to $87.4 million or $2.39 per share compared to $44.8 million or $1.31 per share last year. The Company earned $74.2 million or $2.03 per share compared to $25.4 million or $0.74 per share in the prior year.

During the three months ended March 31, 2005, petroleum and natural gas sales increased 66 percent to $34.7 million compared to $20.9 million for the quarter ended March 31, 2004. The increase is due to an increase in natural gas production to 91 million cubic feet per day compared to 42 million cubic feet per day in the comparative period. The increase in production was offset by a decrease in the price received to $4.19 from $5.45 in the comparative period due to the inclusion of the Feni gas sales and the strengthening of the Canadian dollar versus the U.S. dollar.

Funds from operations in the fourth quarter increased 287 percent to $42.6 million compared to $11.0 million for the same period last year, while funds from operations per share increased 253 percent to $1.13 per share from $0.32 per share in the previous year's fourth quarter. Funds from operations were positively impacted by the increased revenues as well as a reduction in current income taxes and a recovery of prior years' income taxes due to the recognition of a tax holiday in India. Excluding the effect of the recovery of prior years' income taxes, funds from operations per share for the quarter would be $0.66, which is an increase of 106 percent over the same period in the prior year.

Net income in the fourth quarter was $47.3 million or $1.26 per share compared to $6.8 million or $0.20 per share in the same quarter in fiscal 2004. Net income increased due to the higher production offset by lower price caused by the strengthening of the Canadian dollar versus the U.S. dollar. Net income was also impacted by an increase in the depletion expenses due to increased volumes, including the addition of depletion on the Feni Field in Bangladesh combined with a downward technical revision in the Hazira proved reserve by 39 billion cubic feet. Finally, there was a significant impact on net income as a result of the recognition of the tax holiday in India resulting in a reduction to previously recorded current and future income tax expenses as well as a recovery of prior years' income taxes.



Financial Three months ended Twelve months ended
March 31, March 31,
2005 2004 2005 2004
------------------------------------------------------------------------
($ thousands, except per
share amounts)
Petroleum and natural
gas sales 34,670 20,851 107,850 85,834
Funds from operations
Per share, diluted 1.13 0.32 2.39 1.31
Net income 47,264 6,840 74,222 25,351
Per share, diluted 1.26 0.20 2.03 0.74
Capital expenditures 22,436 44,331 119,105 116,864
------------------------------------------------------------------------


Operating Three months ended Twelve months ended
March 31, March 31,
2005 2004 2005 2004
------------------------------------------------------------------------
Crude oil and NGL
production (1)
Thousands of barrels 7 7 21 14
Barrels per day 80 75 57 38
Natural gas production (2)
Million cubic feet 8,171 3,767 22,439 15,202
Million cubic feet per day 91 42 61 42
------------------------------------------------------------------------

(1) 52 percent (2004 - 30 percent) of production is from Canada, 8
percent (2004 - 70 percent) is from India and 40 percent
(2004 - nil) is from Bangladesh for the quarter.

(2) 65 percent (2004 - 100 percent) of production is from India, 35
percent (2004 - nil) is from Bangladesh for the quarter.


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 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 generally accepted accounting principles and may not be comparable with the calculation or similar measure for other companies. The consolidated statements of cash flows in the audited 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.

Operations Update

India

Three wells were drilled on the offshore platform in Hazira during the quarter for a total of five wells drilled on the platform to date. Three of these wells are producing and the remaining two are currently being completed. Gas production from the field increased with the addition of the new wells with year-end rates exceeding 53 million cubic feet per day (net). Three of these wells also tested oil from a deeper sand. Development plans for this oil potential have been submitted to the Government of India.

In Surat, the company recently drilled the NSA-8 well, which is expected to increase gas production to between 12 and 14 million cubic feet average for fiscal 2006.

In the D6 Block, an additional gas discovery was made in the quarter in the G-1 well. This discovery is a follow-up to the large gas discoveries made in 2002 and 2003 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, was completed subsequent to year-end and encountered thick channel sand gas pay. The P-1A well is currently drilling and is the first well on the newly acquired 3D seismic area. Gas pay has already been identified in the shallow sections of the well and drilling is continuing to a total depth of 3,600 metres. 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 F-2 well, which is also located on the new 3D seismic, south of the F-1 discovery. A second rig capable of operating in these water depths is being sourced from a 'window' on another program. This rig is expected to be available for 120 to 150 days commencing in August to September 2005. This rig will be used to drill prospects identified on the new 3D seismic area. A third drilling rig, capable of drilling in the deeper water depths on the prospects in the new 3D seismic area, has been contracted and will commence drilling in September 2006. The Company is looking forward to continued drilling success on this block.

During the fourth quarter, the Company completed drilling of the sixth exploratory well at NEC-25, resulting in the sixth consecutive gas discovery within the 1,800 square kilometre 3D seismic. Currently, a 1,700 kilometre 3D seismic program is being acquired that will extend to the south of the existing 3D coverage. Drilling on this new seismic is expected to begin in late 2005.

Reserve estimates for the six gas discoveries at NEC-25 are in progress by Gaffney, Cline & Associates Ltd. and will be released when available.

Bangladesh

The third well in the Feni Field began producing in the quarter. Combined production from the wells exceeded 40 million cubic feet per day during March 2005. Natural gas production during the quarter averaged 31 million cubic feet per day and condensate production averaged 32 barrels of oil equivalent per day. Two new wells extending north and south of the structure are planned for fiscal 2006.

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. Renewed relief drilling operations are expected to commence in July and production from Chattak is expected to commence by late 2005.

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. Production from the Bangora-1 well is expected to commence in late 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 fiscal 2006. 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 the fourth quarter of 2005. Production is scheduled to increase when Chattak West comes online in the fourth quarter of 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. Fiscal 2005 operating costs were $2.26 per boe and are expected to decrease to the range of $1.50 to $1.70 per boe in the absence of start up and initial production costs at Feni and Surat.

Capital Expenditure Outlook

Niko expects fiscal year 2006 capital spending to be $120 million to $140 million.

The Company anticipates fiscal 2006 capital expenditures at D6 and NEC-25 of approximately $20 million to $25 million (net) and $8 million to $10 million (net), respectively.

Planned capital expenditures for Hazira in fiscal 2006 includes the drilling of two more gas wells, six to eight oil wells and installing oil handling facilities at a total cost budgeted between $18 and $23 million (net).

Capital expenditures in Bangladesh for Chattak in fiscal 2006 are expected to be between $25 and $30 million and for Block 9 are expected to be between $15 and $20 million (net).

Reserves

The Company's petroleum reserves for Hazira, Surat, Feni and Block 9 have been evaluated as at March 31, 2005 by Ryder Scott Company (RS) and DeGolyer & MacNaughton (D&M) evaluated the Company's petroleum reserves on Block D6 as at March 31, 2005. Based on these reports, the Company's proved gas reserves are consistent with the prior year at 312 bcf.(1) Total proved and probable reserves have increased to 532 bcf from 521 bcf in the prior year.(1) Under both proved and proved and probable scenarios, the reserve additions in Bangladesh were approximately offset by technical revisions in Hazira and production in Hazira and Surat. The technical revisions in Hazira were primarily due to some of the sands not extending as far westward as previously mapped. In addition to the technical revision, the NPV of the reserves was adversely impacted due to the strengthening of the Canadian dollar versus the U.S. dollar and the increases in the expected operating and capital costs for the D6 Block.

The Company's reserve reports do not include the results of the NEC-25 wells. The following table summarizes the key information for these reserves based on forecast price analysis:




Natural Future Net Revenue (3)
Natural Gas Before Income Taxes
Reserves Gas Oil Liquids Discounted at:
Category Net Net Net 0% 10% 15% 20%
(2) (2) (2)
------------------------------------------------------------------------
(bcf) (mstb) (mstb) ($000s) ($000s) ($000s) ($000s)
Proved
producing 63.7 - 12 $ 211,043 $174,350 $160,188 $148,170
Proved
non-
producing 26.2 - 3 67,783 50,019 43,616 38,346
Proved
undeveloped 221.7 159 - 550,864 270,431 189,169 131,049
------------------------------------------------------------------------
Total
proved 311.6 159 15 $ 829,690 $494,800 $392,973 $317,565
Probable 220.4 35 3 $ 627,206 $352,660 $270,192 $209,228
Total
proved
plus
probable(4) 532.0 194 18 $1,456,896 $847,460 $663,165 $526,793
------------------------------------------------------------------------


(1) In the current year, "Net" reserves are defined as those accruing to Niko's working interest share after royalty interests owned by others have been deducted, including a reduction to reflect any profit petroleum amounts that may be payable to the governments of India and Bangladesh.

In the prior year, "Net" reserves attributable to the Hazira Field and Surat Block were defined in the Ryder Scott Report as those accruing to Niko's working interest share after royalty interests owned by others have been deducted; however no deduction to reserves was reflected in the Ryder Scott Report for any profit petroleum amounts that may be payable to the Government of India. As a result of the differing definitions between the prior year and current year, Ryder Scott adjusted the net reserves attributable to the Hazira and Surat properties as at March 31, 2004.

The definition of "Net" reserves attributable to the D6 Block defined in the DeGolyer & MacNaughton Report in the prior year is consistent with the definition of "Net" reserves in the current year.

(2) "Net" reserves are defined as those accruing to Niko's working interest share after royalty interests owned by others have been deducted including a reduction to reflect any profit petroleum amounts that may be payable to the governments of India and Bangladesh.

(3) The estimated future net revenue value does not represent fair market value. The values are based on forecast prices and costs after well abandonment costs and before income taxes. These values reflect reductions for estimates of profit petroleum amounts that may be payable to the governments of India and Bangladesh.

(4) In addition, the D&M report assigns 120 bcf of net possible gas reserves (79 bcf as at March 31, 2004).



The following table summarizes the key information for reserves based on
forecast price analysis after tax:

Natural Future Net Revenue (2)
Natural Gas Before Income Taxes
Reserves Gas Oil Liquids Discounted at:
Category Net Net Net 0% 10% 15% 20%
(1) (1) (1)
------------------------------------------------------------------------
(bcf) (mstb) (mstb) ($000s) ($000s) ($000s) ($000s)
Proved
producing 63.7 - 12 $ 194,100 $162,130 $149,471 $138,607
Proved
non-
producing 26.2 - 3 65,938 48,773 42,579 37,476
Proved
undeveloped 221.7 159 - 480,995 239,437 167,960 116,289
------------------------------------------------------------------------
Total
proved 311.6 159 15 $ 741,033 $450,340 $360,010 $292,372
Probable 220.4 35 3 $ 569,627 $322,803 $247,865 $192,223
Total
proved
plus
probable(3) 532.0 194 18 $1,310,660 $773,143 $607,875 $484,595
------------------------------------------------------------------------


(1) "Net" reserves are defined as those accruing to Niko's working interest share after royalty interests owned by others have been deducted including a reduction to reflect any profit petroleum amounts that may be payable to the governments of India and Bangladesh.

(2) The estimated future net revenue value does not represent fair market value. The values are based on forecast prices and costs after well abandonment costs and before income taxes. These values reflect reductions for estimates of profit petroleum amounts that may be payable to the governments of India and Bangladesh.

(3) In addition, the D&M report assigns 120 bcf of net possible gas reserves (79 bcf as at March 31, 2004).


The following forecast prices were provided by Ryder Scott (Indian properties of Hazira and Surat and the Bangladesh properties of Feni and Block 9) and D&M (Indian property of D6) based on discussions with Niko, existing contracts and expected future contracts:



Hazira Hazira Surat D6
Oil Natural Gas Natural Gas Natural gas
Prices Prices Prices Prices
------------------------------------------------------------------------
US$/bbl (1) US$/Mcf (2) US$/Mcf (2) US$/Mcf (3)
2006 45.25 3.65 3.36 n/a
2007 44.51 3.65 3.36 n/a
2008 40.79 3.65 3.36 3.67
2009 37.20 3.65 3.36 3.71
2010 34.97 3.87 3.56 3.74
Thereafter 35.35 4.05 3.77 3.93
------------------------------------------------------------------------


Feni Feni Block 9 Foreign
Condensate Natural Gas Natural Gas Exchange
Prices Rate Prices Rate
------------------------------------------------------------------------
US$/bbl (4) US$/Mcf (5) US$/Mcf (5) CAD
2006 43.11 2.20 2.50 1.21
2007 40.10 2.20 2.50 1.21
2008 36.17 2.20 2.50 1.21
2009 32.72 2.20 2.50 1.21
2010 30.47 2.20 2.50 1.21
Thereafter 30.47 2.20 2.50 1.21
------------------------------------------------------------------------


(1) The oil prices shown on this table were provided by Ryder Scott and reflect their current estimates, which are based on their survey of future hydrocarbon parameters used by financial institutions and others in industry.

(2) The natural gas prices shown in the table were provided by Ryder Scott based on discussions with Niko and contractual agreements provided by Niko to Ryder Scott.

(3) The natural gas prices used in the D&M report for the forecast prices and costs case utilized the prices in the constant price and cost case and escalated them by 1 percent per year for every year in the evaluation. The constant price is the price Niko could reasonably expect to receive as at March 31, 2005. The forecast gas price is before a reduction for a royalty expense estimated by D&M of 10 percent. Niko assumes royalty expense will be paid by the purchaser as is the case in its current natural gas producing properties in India. Production is forecast to begin in 2008.

(4) The condensate prices shown on this table were provided by Ryder Scott and reflect its current estimates, which are based on its survey of future hydrocarbon parameters used by financial institutions and others in industry.

(5) The natural gas prices shown in the table were provided by Ryder Scott based on discussions with Niko.

Weighted average oil and natural gas prices received, in Canadian dollars, by the Company in India in 2005 were $60.22 per bbl and $5.21 per Mcf, respectively. Weighted average condensate and natural gas prices received, in Canadian dollars, by the Company in Bangladesh in 2005 were $48.50 per bbl and $2.68 per Mcf, respectively.

Management's Discussion & 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 audited consolidated financial statements and accompanying notes. This MD&A is effective June 24, 2004. 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. 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, funds from operations per share and net operating income, 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 audited 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. Net operating income is calculated as revenue ($107.9 million) and pipeline revenue ($1.0 million) less royalties ($16.6 million), profit petroleum ($9.1 million) and operating and pipeline expenses ($8.9 million), for a net of $74.3 million.

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 circumstances to differ materially from those predicted. Readers are cautioned not to place undue reliance on this forward-looking information.

Overall Performance

With an increase in production of 48 percent, the Company continued to deliver a strong performance during the fiscal year ended March 31, 2005. Niko generated net income of $74.2 million ($2.03 per share) in fiscal 2005 compared to $25.4 million ($0.74 per share) in the prior year. Overall, there was a net increase in income in fiscal 2005 compared to the prior fiscal year due to the increase in production, insurance proceeds, foreign exchange gain and current and future income tax reductions offset by a lower sales price due to the strengthening of the Canadian dollar versus the U.S. dollar, increased operating costs and increased depletion expense.

Revenues increased by 26 percent to $107.9 million from $85.8 million in the previous year. This increase was driven by a 48 percent increase in average natural gas production, which rose to 61 million cubic feet per day in fiscal 2005 from 42 million cubic feet per day in fiscal 2004. The increase is a result of the addition of production from the Surat field, the offshore platform at Hazira and the Feni field in Bangladesh. Production increases were partially offset by a lower sales price due to the continued strengthening of the Canadian dollar versus the U.S. dollar. The operating results by country are outlined on page 24.

Natural gas prices are generally influenced by local market supply and demand. The Company's natural gas production in India is sold with fixed-price contracts at U.S. dollar-equivalent prices and the Company expects to continue to enter into natural gas contracts in India on this basis. Most contracts expired in November 2004 and contain a renewal provision at prices to be set according to prevailing market conditions. The Company has agreed to a price of US$3.75 per Mcf with two customers and gas is currently selling to the remaining customers at prices between US$3.45 per Mcf and US$3.65 per Mcf until a new price can be negotiated.

Niko has reached an agreement with the Government of Bangladesh to purchase up to 50 million cubic feet per day from the Feni field. Niko is currently finalizing the gas sales price. In the interim, the Company is recording sales at US$2.20 per Mcf.

Production and pipeline expenses increased to $8.9 million in fiscal 2005 compared to $3.4 million in 2004. The increase is due to the inclusion of operating costs from Surat, increased insurance costs, well testing and start up costs in Bangladesh.

Foreign exchange rates had an influence on the Company's performance during the year. Revenues were adversely impacted by the decrease in the value of the U.S. dollar as revenues are received in U.S. dollars. There was a foreign exchange gain as a result of the decrease in the value of the U.S. dollar applied to the debt, which is denominated in U.S. dollars.

Insurance proceeds of $3.3 million were received during the year related to a key man term life insurance policy held by the Company on the life of Robert N. Ohlson, the former President.

Depletion in India was $29.7 million or $9.64 per boe of production compared to $18.1 million or $7.12 per boe in 2004. Increased production resulted in higher depletion coupled with a higher depletion rate due to the decrease in the reserve base as a result of production and a downward technical revision in the Hazira proved reserve estimate by 39 billion cubic feet. Depletion in Bangladesh of $5.8 million or $8.72 per boe of production was recorded with the commencement of production during the year.

The overall tax provision is a recovery of 94 percent in fiscal 2005, compared to a charge of 35 percent in fiscal 2004. The Company recognized the effect of a tax holiday in India resulting in a decrease in current income taxes and a future income tax recovery related to the decrease in the future tax rate.

During fiscal 2005, the Company financed its capital expenditure program with a combination of working capital, share offerings closing in each of April 2004 and February 2005 and cash flow. At March 31, 2005 the Company had a working capital surplus of $100.4 million. This includes the residual funds from the $97.7 million equity offering closing in February 2005. The Company has planned capital expenditures of between $120 and $140 million for fiscal 2006 and expects to finance these expenditures with working capital, additional debt and funds from operations. 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.

Permission has been received from the Reserve Bank of India to transfer funds from the Indian branch to the Company. Permission is given under the JVA in accordance with the policy of the Government of Bangladesh and Bangladesh Bank to transfer funds from the Bangladesh branch to the Company.

Selected Annual Information

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 below is prepared in accordance with Canadian GAAP, except for dividends per share. Dividends per share is the sum of the dividends per share declared during the year.



Financial

Year ended March 31
($ thousands, except per share amounts) 2005 2004 2003
------------------------------------------------------------------------
Petroleum and natural gas sales 107,850 85,834 82,851
Net earnings 74,222 25,351 26,714
Per share basic ($) 2.08 0.76 0.87
Per share fully diluted ($) 2.03 0.74 0.86
Total assets 480,714 278,939 204,990
Total long-term
financial liabilities 19,062 42,772 20,854
Dividends per share 0.12 0.12 0.12
------------------------------------------------------------------------


2003 - 2004 Comparison

Earnings per share decreased from fiscal 2003 to 2004 primarily due to the equity financing in February 2003. The weighted average shares outstanding in fiscal 2004 were higher than in 2003, thereby diluting earnings. Total assets increased due to capital expenditures in fiscal 2004 offset by depletion expenses and a decrease in cash and short-term investments. Capital expenditures increased significantly in 2004 due to activity in Surat, Hazira, offshore India (D6 and NEC-25 Blocks) and Bangladesh. Capital spending in fiscal 2004 totalled $30 million in Surat, $7.8 million in each of the NEC-25 and D6 Blocks for exploration and development and $34.1 million in Hazira for construction and installation of the offshore platform and development activities. Capital spending in Bangladesh in fiscal 2004 totalled $36.3 million for acquisition and drilling activities. The significant cash and short-term investment balance at the end of fiscal 2003 resulted from an equity financing in February 2003. The balance has decreased by $26.4 million in fiscal 2004 as it was used to fund exploration and development and operating activities. Total long-term financial liabilities increased in fiscal 2004 due to the addition of long-term debt drawn on the project facility to fund the Hazira offshore platform and the Surat development project.

2004 - 2005 Comparison

Petroleum and natural gas sales increased from fiscal 2004 to 2005 due to the commencement of production from the Hazira offshore platform in India, the Feni field in Bangladesh and recommencement of production from the Surat shallow gas field in India, partially offset by the decrease in the value of the U.S. dollar, as revenues are received in U.S. dollars. The increase in net income was 193 percent compared to the 26 percent increase in petroleum and natural gas sales. In addition to the increase in revenues, net income for the year was positively impacted by insurance proceeds received as well as reduced current income taxes, a recovery of prior years' income taxes and a future income tax reduction, all due to the recognition of the tax holiday in India. Earnings per share increased by 174 percent due to the increased production and the recognition of the tax holiday. As a result of the tax holiday, the Company expects to pay minimum alternative tax of 7.84 percent of income. The February 2005 equity financing resulted in a significant cash balance at the end of fiscal 2005. Capital spending in India in fiscal 2005 totalled $57.6 million related to development activities in Hazira, drilling on the offshore platform and exploratory activity in the NEC-25 and D6 Blocks. Capital spending in Bangladesh in fiscal 2005 totalled $60.7 million related to development activities in Feni, Chattak and Block 9. Accounts receivable has increased due to increased revenues, an insurance receivable related to the blowout at Chattak-2 and the long-term account receivable has increased due to the recovery of the prior years' income taxes.

Results of Operations

The Company's March 31, 2005 revenues increased by 26 percent to $107.9 million from $85.8 million the previous fiscal year. This increase resulted from a 48 percent increase in average natural gas production, which rose to 61 million cubic feet per day from 42 million cubic feet per day in fiscal 2004. However, the Canadian equivalent price of gas was adversely impacted by the weakening U.S. dollar versus the Canadian dollar. The Company generated net income of $74.2 million ($2.03 per share) in fiscal 2005 compared to $25.4 million ($0.74 per share) in fiscal 2004. The operating results by country are outlined below.



Revenue and Operating Income

Year ended March 31, 2005
($ thousands, except
daily production) India Bangladesh Canada Total
------------------------------------------------------------------------
Revenue 96,500 10,929 421 107,850
Pipeline revenue 982 - - 982
Royalty (16,496) - (57) (16,553)
Profit petroleum (6,868) (2,182) - (9,050)
Operating and
pipeline expenses (7,291) (1,463) (149) (8,903)
------------------------------------------------------------------------
Net operating
income (1) 66,827 7,284 215 74,326
Daily production
(boe/d) 8,445 1,834 24 10,303
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Net operating income is a non-GAAP measure calculated as above.


Year ended March 31, 2004
($ thousands, except
daily production) India Bangladesh Canada Total
------------------------------------------------------------------------
Revenue 85,552 - 282 85,834
Pipeline revenue 1,175 - - 1,175
Royalty (15,265) - (44) (15,309)
Profit petroleum (8,817) - - (8,817)
Operating and
pipeline expenses (3,236) - (137) (3,373)
------------------------------------------------------------------------
Net operating
income (1) 59,409 - 101 59,510
Daily production
(boe/d) 6,958 - 21 6,979
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Net operating income is a non-GAAP measure calculated as above.


Netbacks

Less than 1 percent of volumes and revenues are from oil production and Canadian production, therefore, these items are not disclosed separately, but are included in the total. The following table outlines the Company's operating and earnings netbacks for fiscal years 2005 and 2004.



Year ended March 31, 2005 2004
------------------------------------------------------------------------
Natural (6:1) Natural (6:1)
Gas Total Total Gas Total Total
------------------------------------------------------------------------
($/Mcf) ($/boe) ($/Mcf) ($/boe)
Price 4.76 28.68 5.61 33.69
Royalties (0.74) (4.40) (1.00) (6.01)
Profit petroleum (0.40) (2.41) (0.58) (3.46)
Operating costs (0.36) (2.26) (0.17) (1.11)
------------------------------------------------------------------------
Operating netback 3.26 19.61 3.86 23.11
Pipeline and other
income 0.58 0.82
Pipeline expense (0.10) (0.22)
General and
administrative (0.96) (1.33)
Interest and
financing (0.43) (0.13)
Insurance proceeds 0.89 -
Current taxes 3.66 (4.68)
------------------------------------------------------------------------
Cash flow netback 23.25 17.57
Foreign exchange 0.49 0.31
Stock-based
compensation (0.34) (0.08)
Depletion and
depreciation (9.56) (7.15)
Future income taxes 5.91 (0.71)
------------------------------------------------------------------------
Earnings netback 19.75 9.94
------------------------------------------------------------------------
------------------------------------------------------------------------


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 table outlines the Company's operating netbacks by
country for fiscal years 2005 and 2004.

Year ended Joint India
March 31, 2005 Venture (1) Surat Total Bangladesh Canada
------------------------------------------------------------------------
Average daily
production
Oil (bbls/day) 20 - 20 13 24
Natural gas
(mmcf/day) 43 8 51 10 -
Total combined
(boe/day) 7,163 1,282 8,445 1,834 24
------------------------------------------------------------------------
Revenues, royalties
and operating costs
Gross revenue
received ($/boe) 31.52 30.14 31.31 16.33 46.96
Royalties ($/boe) (5.26) (5.89) (5.35) - (6.62)
Profit petroleum
($/boe) (2.63) - (2.23) (3.26) -
Operating costs
($/boe) (1.16) (8.26) (2.24) (2.19) (17.22)
------------------------------------------------------------------------
Operating netback
($/boe) 22.47 15.99 21.49 10.88 23.12
------------------------------------------------------------------------
------------------------------------------------------------------------

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


Year ended Joint India
March 31, 2004 Venture (1) Surat Total Bangladesh Canada
------------------------------------------------------------------------
Average daily
production
Oil (bbls/day) 17 - 17 - 21
Natural gas
(mmcf/day) 41 1 42 - -
Total combined
(boe/day) 6,859 99 6,958 - 21
------------------------------------------------------------------------
Revenues, royalties
and operating costs
Gross revenue
received ($/boe) 33.69 33.16 33.68 - 34.45
Royalties ($/boe) (5.97) (8.69) (6.01) - (5.84)
Profit petroleum
($/boe) (3.52) - (3.47) - -
Operating costs
($/boe) (0.88) (13.44) (1.06) - (18.14)
------------------------------------------------------------------------
Operating netback
($/boe) 23.32 11.03 23.14 - 10.47
------------------------------------------------------------------------
------------------------------------------------------------------------

(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.

India

Revenue, Royalties and Profit Petroleum

India represented approximately 90 percent of the Company's oil and gas revenue or $96.5 million in fiscal 2005 and in excess of 99 percent of the Company's oil and gas revenue of $85.6 million in fiscal 2004. Average daily natural gas production in India increased by 21 percent during fiscal 2005 to 51 million cubic feet per day from 42 million cubic feet per day the previous fiscal year. This production increase was due to wells drilled on the offshore platform coming on production in August 2004 and production from the Surat wells for the entire year. Current natural gas production in India is approximately 62 million cubic feet per day. Average crude oil production was 20 barrels of oil per day during fiscal 2005 compared to 17 barrels of oil per day in the prior fiscal year.

The average plant outlet price received by the Company for its gas in India during fiscal 2005 decreased by 7 percent, primarily due to the drop in the U.S. dollar versus the Canadian dollar, to $4.31 per Mcf from $4.61 per Mcf in fiscal 2004. Since June 2002 most of the Company's gas contracts have had the same pricing terms of US$3.45 per Mcf with spot sales at US$3.75 per Mcf. The majority of the prices in the Company's gas contracts expired in November 2004 and January 2005 and will be renegotiated. The Company has agreed to a price of US$3.75 per Mcf with two customers and gas is currently selling to the remaining customers at prices between US$3.45 per Mcf and US$3.65 per Mcf until a new price can be negotiated.

Under the terms of all gas contracts the purchaser is responsible for transportation charges, royalties and sales taxes. The latter two charges, levied against Niko by the Government, vary according to the type of purchaser and are collected on top of the contracted sales price. In fiscal 2005, Niko charged and remitted $16.5 million or $0.90 per Mcf (2004 - $15.3 million, or $1.00 per Mcf) in royalties and sales taxes, increasing the average purchaser's cost to $5.21 per Mcf in fiscal 2005 (2004 - $5.61).

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 fiscal 2005, the Government was entitled to 20 percent of the cash flow from the Hazira field after deducting capital expenditures. This amounted to $6.9 million in the year (2004 - $8.8 million). The decrease in profit petroleum reflects the increased capital spending on the Hazira offshore platform in fiscal 2004, which is deducted from cash flows prior to calculating the profit petroleum amount. In fiscal 2006, the Government of India will be entitled to 20 percent. However, the Company and its partner are currently in arbitration with the Government of India with respect to the cost recovery status of the investment in the 36-inch pipeline at Hazira. If successful in the arbitration, the Company will reduce its profit petroleum payments currently being made and possibly receive a refund.

Bangladesh

Revenue, Royalties and Profit Petroleum

Production from the Feni field in Bangladesh began in November 2004 representing almost 10 percent of the Company's oil and gas revenue or $10.9 million in fiscal 2005 (2004 - nil). Initial production rates were in excess of 20 million cubic feet per day and rose to an average of 26 million cubic feet per day for the production period and 10 million cubic feet per day over the year. Current natural gas production in Bangladesh is approximately 33 million cubic feet per day. Average condensate production was 31 barrels of oil equivalent per day for the producing period and 13 barrels of oil equivalent during fiscal 2005.

The Company has reached an agreement with the Government of Bangladesh to purchase up to 50 million cubic feet per day. The company is currently finalizing the gas sales price. In the interim, the Company is recording sales at US$2.20 per Mcf. The average price recorded by the Company for its gas in Bangladesh during fiscal 2005 was $2.68 per Mcf.

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. In fiscal 2005, the Government was entitled to 20 percent of the revenues from the Feni field. This amounted to $2.2 million (2004 - nil). In fiscal 2006, the Government of Bangladesh will be entitled to 20 percent.

Canada

Revenue from the Company's Canadian property increased to $421,000 in fiscal 2005 from $282,000 in fiscal 2004. Production increased to 24 barrels of oil per day (2004 - 21 barrels of oil per day). The oil price averaged $46.96 per barrel in fiscal 2005, compared to $34.45 per barrel in fiscal 2004. Royalty income included in revenue was $14,000 in fiscal 2005 compared to $19,000 in the prior fiscal year, while royalty expense was $57,000 compared to $44,000. Operating expenses increased to $149,000 versus $138,000 in the prior fiscal year as there was a workover on the Cullen unit during the year.

Operating Expenses

On a unit-of-production basis, operating costs increased by 104 percent to $2.26 per boe in fiscal 2005 from $1.11 per boe in fiscal 2004 due to the inclusion of operating costs from Surat, increased insurance costs, well testing and start up costs in Bangladesh. Overall operating expenses were $8.9 million in fiscal 2005 compared to $3.4 million in fiscal 2004. The Company expects fiscal 2006 operating costs to decrease to between $1.50 and $1.70 per boe in the absence of start up and initial production costs at Feni and Surat.

Pipeline Revenue

In fiscal 2003 the Company resolved the dispute over the ownership of the 36-inch pipeline at Hazira, although legal title to the pipeline has not yet been transferred to the joint venture. Pipeline revenue for fiscal 2005 decreased to $1.0 million compared to $1.2 million in the prior year due to a decreased number of vendors utilizing the pipeline.

Significant Projects

Bangladesh

Feni

The Feni Field covers an area of 43 square kilometres and lies on the main gas line from Dhaka to Chittagong. A 3D seismic program has been shot over the field and the first three wells under the field development plan have been drilled. Feni-3, Feni-4 and Feni-5 were completed during fiscal 2005 and placed on-stream. Facilities were upgraded to increase production capacity to 50 million cubic feet per day and current production is approximately 33 million cubic feet per day. Capital expenditures of $29.8 million have been incurred to the end of fiscal 2005 ($23.2 million in fiscal 2005). Two additional development wells at Feni are planned for fiscal 2006.

Chattak

The Chattak Block is 376 square kilometres. The upper fault Block to the west has produced from one well, while the down-thrown fault Block to the east has not been drilled. The Company completed an extensive 3D seismic program and drilling on the first location in Chattak West began in December 2004. Early in January 2005, an uncontrolled release of gas occurred at Chattak-2 and the drilling rig equipment was lost. A relief well, spudded in May 2005, also encountered uncontrolled flow problems. The Company expects the majority of costs to be covered by insurance. Actual costs cannot be estimated until the relief operation is complete and a final assessment including all appropriate clearances resulting from the blowout are complete.

A 182 square kilometre 3D seismic program was completed in fiscal 2004 to optimize the planned drilling locations at Chattak East and West gas fields. Capital expenditures to the end of fiscal 2005 total $27.2 million ($20.5 million in fiscal 2005). Planned development in Chattak for fiscal 2006 includes drilling three wells at Chattak West, one well at Chattak East, building facilities and a pipeline at a total expected cost of between $35 and $40 million. Initial production at Chattak West is expected to commence in December 2005.

Block 9

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. Capital expenditures to the end of fiscal 2005 total $42.6 million ($17.1 million in fiscal 2005). Future plans for Block 9 include the tie-in of the Bangora well and commencement of production in a continuation of the appraisal phase, a 3D seismic program over the Bangora and Lalmai structure and further appraisal drilling. Planned expenditures for fiscal 2006 are between $15 and $20 million (net). Production in Block 9 is targeted for fourth quarter 2005.

India

The Company has a 10 percent working interest in the D6 Block off the east coast of India. Expenditures to date total $44.4 million ($13.3 million incurred in 2005) for seismic and drilling of 14 wells (1.4 wells net). Five additional exploration wells, including one well on the new 3,200 square-kilometre seismic shoot, and two development wells are scheduled for fiscal 2006 at a total cost of between $20.0 and $25.0 million (net). The operator is continuing to process and interpret 2,500 square-kilometres of seismic shot on the Block in 2004. The field development plan for this Block has been approved by the Government of India.

The Company has a 33 percent working interest in the offshore platform at Hazira. The platform was completed in April 2004. The Company's share of capital expenditures for construction, transportation and completion of the platform total $35.5 million to date ($6.0 million incurred in fiscal 2005). Capital expenditures to the end of fiscal 2005 related to drilling on the platform are $17.6 million. Capital expenditures to complete the project are budgeted between $18 and $23 million and include drilling two more gas wells, six to eight oil wells and installing oil handling facilities.

The Company has a 10 percent working interest in the NEC-25 Block off the east coast of India. Six wells exploration wells have been drilled. Capital expenditures to the end of fiscal 2005 total $20.5 million ($9.7 million incurred in 2005). Planned expenditures for fiscal 2006 include 1,700 square-kilometres of 3D seismic, drilling of four additional exploration wells, front-end engineering and preparation of development plans at a budgeted cost between $8 and $10 million (net).

Corporate

Interest and Other Income

The Company invests its excess cash balance in Canada, India and Bangladesh in short-term instruments such as banker's acceptances. Interest and other income was $1.2 million in fiscal 2005 compared to $0.9 million in the prior fiscal year. The increase relates to the equity financings closing in April 2004 and February 2005 resulting in a larger average cash balance outstanding during the year.

Interest and Financing

The Company incurred interest and financing expenses of $1.6 million in fiscal 2005 compared to $0.3 million in the prior fiscal year. Interest of $1.3 million related to the long-term debt and $0.3 million amortization of deferred financing charges (2004 - $0.3 million).

General and Administrative Expenses

General and administrative expenses decreased to $0.96 per boe in fiscal 2005 compared to $1.33 per boe in fiscal 2004 as production increased during the year. Overall costs increased to $3.6 million in fiscal 2005 from $3.4 million and the previous fiscal year.

Foreign Exchange

During fiscal 2005, the Company recorded a foreign exchange gain of $1.9 million, compared to a gain of $0.8 million in fiscal 2004. Of the gain, $2.0 million arose as a result of the increase in the value of the Canadian dollar relative to the U.S. dollar applied to the debt, which is denominated in U.S. dollars. The remaining increase is primarily due to a gain on the translation of the Bangladesh Taka.

Depletion and Depreciation Expenses

Depletion in India was $29.7 million or $9.64 per boe of production compared to $18.1 million or $7.12 per boe in 2004. Increased production resulted in higher depletion coupled with a higher depletion rate due to the decrease in the reserve base as a result of production and a downward technical revision in the Hazira proved reserve estimate by 39 billion cubic feet. Depletion in Bangladesh of $5.8 million or $8.72 per boe of production with the commencement of production was recorded during the year. In Canada, depletion increased to $109,000 in fiscal 2005 (2004 - $20,000).

Depreciation expense was $57,000 in fiscal 2005 compared to $53,000 in fiscal 2004. Accretion expense was $223,000 in fiscal 2005 compared to $42,000 in fiscal 2004. The asset retirement obligation was $4.6 million in fiscal 2005, versus $553,000 in fiscal 2004. The increase is due to inclusion of the offshore platform and offshore wells. Starting in the 2006 fiscal year the Company expects to contribute funds for restoration under the Government of India's Site Restoration Fund, which requires companies to cover future restoration costs through a contribution of a portion of their profits over time.

Insurance Proceeds

The life insurance proceeds relate to a key man term life insurance policy held by the Company on the life of Robert N. Ohlson, the former President, who died on November 24, 2004 from natural causes. Proceeds of $3.3 million were received in the year.

Income Taxes

The Company's overall tax provision was a recovery of 94 percent of income before taxes in fiscal 2005, compared to a charge of 35 percent in fiscal 2004. The Company's future tax recovery was $22.2 million in fiscal 2005 compared to a provision of $1.8 million in fiscal 2004. The current tax recovery of $13.8 million in fiscal 2005 (2004 - $11.9 million) includes Indian taxes of $3.6 million (2004 - $14.6 million), a recovery of prior years' Indian income taxes of $17.7 million and Bangladesh taxes of $0.3 million (2004 - nil). 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. The Company believes much of its production in India will qualify for the tax holiday and has recorded the benefit of this tax holiday for 2005 in computing both the current and future components of its provision for income taxes and the recovery of prior years' income taxes during the periods to which the tax holiday is applicable. As a result of the tax holiday, the Company expects to pay minimum alternative tax of 7.84 percent of income.

Capital Expenditures

Capital expenditures during fiscal 2005 were $119.1 million compared to $116.9 million in the previous year. Approximately 47 percent of the expenditures were in India (2004 - 68 percent) as activity in Bangladesh has increased year over year. In Hazira $34.6 million was spent on completion of and drilling on the offshore platform and expansion of the gas plant in fiscal 2005. A further $23.0 million was spent on exploration activities in the NEC-25 and D6 Blocks. In Bangladesh, $23.2 million was spent on the development of the Feni field, $20.5 million for exploration and development activities in Chattak and $17.1 million for drilling and development activities in Block 9. The funds raised in the share offerings closing in April 2004 and February 2005 were used to fund capital expenditures and for ongoing working capital purposes.

Dividends

The Company declared four quarterly dividends during fiscal 2005 of $0.03 per share each, totalling $4.4 million (2004 - $4.0 million). While the Company intends to pursue a policy of paying quarterly dividends, the level of future dividends will be determined by the Board of Directors in light of income from operations, capital requirements and the financial condition of the Company. The Company is restricted under the terms of its credit facility to a maximum dividend of the greater of 15 percent of its net income from the most recently completed financial quarter and $0.03 per share on a quarterly basis.

Liquidity

During fiscal 2005 the Company financed its capital expenditure program with a combination of working capital, cash flow and share offerings closing in April 2004 and February 2005. A further $13.0 million was received in funds through the exercise of stock options. At March 31, 2005 the Company had a working capital surplus of $100.4 million, which included $102.0 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 for the coming year and expects to finance these expenditures with working capital, additional debt and funds from operations. Subsequent to March 31, 2005, the Company drew an additional US $20 million 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 March 31, 2005, the Company's current portion of long-term debt was $7.1 million and interest is payable semi-annually on the remaining outstanding principal of US$37.8 million. 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.



The following table sets out the Company's contractual obligations for
the next five years:

Contractual Obligations Payments Due by Period
Less than 4-5 After 5
Total 1 year 1-3 years years years
------------------------------------------------------------------------
Long-term
debt (1) $ 45,698,688 $ 16,136,064 $ 29,562,624 - -
Guarantees (2) 16,261,862 16,261,862 - - -
Offices leases 1,827,000 283,000 670,000 202,000 672,000
Total
contractual
obligations $ 63,787,550 $ 32,680,926 $ 30,232,624 $202,000 $672,000
------------------------------------------------------------------------
------------------------------------------------------------------------


(1) A project facility (the facility) was established to fund the Corporation's development activities on India's west coast, specifically the Hazira offshore platform project and the Surat development projects. At March 31, 2005 the facility limit was US$30 million of which US$20 million was drawn. Subsequent to year end, 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 long-term debt amount above includes the repayments for the US$20 million that was drawn subsequent to March 31, 2005.

In September 2004, the Company was granted approval to reschedule the repayment period of the loan to provide for the first repayment of principal on March 15, 2005 and six subsequent semi-annual payments. The first repayment occurred on March 15, 2005 based on the US$20 million drawn at that time. Subsequent to March 31, 2005, the Company drew an additional US$20 million under the project facility.The September 2005 instalment will be for 11.1 percent of the total amount drawn (US$40 million) plus 11.1 percent of the second US$20 million drawn subsequent to the March instalment. Each of the next two instalments will be for 16.7 percent of the total amount drawn, and each of the last three instalments will be for 14.8 percent of the total amount drawn. 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).

(2) At March 31, 2005, the Company had issued US$0.11 million in letters of credit as part of the normal course of operations. Letters of credit issued in excess of the facility amount are secured by the Company's cash balance or EDC performance guarantees. At March 31, 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 for Block 9. 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. The Company expects to renew the guarantee when it expires on October 15, 2005

Capital Resources

At March 31, 2005, the Company had issued US$0.11 million in letters of credit as part of the normal course of operations. Letters of credit issued in excess of the facility amount are secured by the Company's cash balance or EDC performance guarantees. At March 31, 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 for Block 9. 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.

For fiscal 2006, the Company has planned capital expenditures between $120 and $140 million related to exploration and development activities throughout India and Bangladesh. These planned expenditures are expected to be funded through working capital, cash flow from operations and long-term debt.

Subsequent to year end, 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.

Net Asset Value

The following table calculates the net asset value of the Company at a discount rate of 10 percent before tax, as at March 31, 2005, under a forecast price scenario.



April 1, 2005 ($000s) Per Share
------------------------------------------------------------------------
Reserves (1)
Proved $ 503,143 $ 12.50
Probable 352,660 8.76
Land (2) 35,540 0.88
Working capital 100,372 2.49
Proceeds on dilution (3) 52,290 1.30
------------------------------------------------------------------------
Total $ 1,044,005 $ 25.93
Fully diluted number of shares (000s) 40,266
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Based on the DeGolyer & MacNaughton and Ryder Scott forecast price
cases, using 10 percent discount rate, pre-tax and internal
estimates for the Bhandut Field in India and the Canadian property.
NAV calculated in the same manner as above based on forecast
prices and costs after tax is $24.08 per share.
(2) The Company has 422,913 acres of undeveloped land in India, which
was valued at $50 per acre. The undeveloped land in Bangladesh,
1,092,222 acres, was valued based on the purchase cost of Block 9
($13 per acre).
(3) Includes proceeds from exercise of 1,979,250 stock options.


Risks

In the normal course of business the Company is exposed to a variety of risks in its operations. These include operational, currency, taxation, foreign operations, commodity price, political, government policy and legislation and concentrated sales risks. Steps have been taken to mitigate these risks.

The Company is exposed to operational risks inherent in exploring for, developing and producing crude oil and gas. There are numerous uncertainties in estimating oil and gas reserves and in projecting future production and costs. Uncertanties also exist when predicting the results and timing of exploration and development projects and their related expenditures. Total amounts or timing of production may vary significantly from reserves and production estimates. The Company attempts to limit these risks by maintaining a focused asset base and by hiring qualified professionals with appropriate industry experience. A comprehensive insurance program is maintained to mitigate risks and to protect against significant losses, while maintaining levels of risk within the Company which management believes to be acceptable. This includes traditional industry coverage such as well control insurance. In addition, because of the physical concentration of production at Hazira, the Company carries business interruption insurance that, after the deductible period, would provide six months of revenue at current production levels on the land based drilling platform wells and one year of revenue on the offshore platform wells.

The Company plans to operate in regions where the petroleum industry is a key component of the economy to help mitigate the risks of operating in foreign jurisdictions. The Company believes that management's experience operating internationally helps to further reduce these risks.

Currency risks have been reduced by denominating revenues in one currency, the U.S. dollar. Since June 2002, the majority of the Company's revenue is from U.S. dollar-denominated contracts. The vast majority of capital expenditures are in U.S. dollars, as are a portion of operating costs. The remaining operating costs are in local currency. The Company's financial risk profile at March 31, 2005 is described in Note 12 to the Consolidated Financial Statements.

Natural gas prices are generally influenced by local market supply and demand. The Company's natural gas production in India is sold with fixed-price contracts at U.S. dollar-equivalent prices and the Company expects to continue entering into natural gas contracts in India on this basis. Most contracts expired in November 2004 and contain a renewal provision at prices to be set according to prevailing market conditions. The Company has agreed to a price of US$3.75 per Mcf with two customers and gas is currently selling to the remaining customers at prices between US$3.45 per Mcf and US$3.65 per Mcf until a new price can be negotiated. The Company's natural gas enjoys a significant price, efficiency and environmental advantage compared to naphtha, the main competing fuel. Liquefied natural gas imports have begun and are currently priced at levels consistent with market prices and are expected to be a key price determinant in the future.

Currently the Company is selling gas to 17 customers, up from 14 last year. The largest customer accounted for 23 percent of sales in fiscal 2005 and 22 percent of sales in fiscal 2004. The increase in the number of customers reduces the potential negative impact on the Company's cash flows and revenue in the event a single purchaser defaults on its contractual commitments.

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 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 measure for other companies. The consolidated statements of cash flows in the audited 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 and 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
March 31, 2005.

Summary of Quarterly Results

Three months ended
($ thousands,
except per Jun 30, Sep 30, Dec 31, Mar 31,
share amounts) 2004 2004 2004 2005 Total
------------------------------------------------------------------------
Petroleum and
natural gas
sales 22,467 22,864 27,849 34,670 107,850
Funds from
operations
Per share
- basic 0.41 0.38 0.47 1.16 2.45
- diluted 0.40 0.37 0.46 1.13 2.39
Net income 5,470 6,804 14,684 47,264 74,222
Per share
- basic 0.16 0.19 0.41 1.29 2.08
- diluted 0.15 0.19 0.40 1.26 2.03
------------------------------------------------------------------------
------------------------------------------------------------------------


Three months ended
($ thousands,
except per Jun 30, Sep 30, Dec 31, Mar 31,
share amounts) 2003 2003 2003 2004 Total
------------------------------------------------------------------------
Petroleum and
natural gas
sales 23,826 21,199 19,958 20,851 85,834
Funds from
operations
Per share
- basic 0.39 0.31 0.32 0.33 1.34
- diluted 0.38 0.30 0.31 0.32 1.31
Net income (loss) 6,897 6,569 5,045 6,840 25,351
Per share
- basic 0.21 0.20 0.15 0.20 0.76
- diluted 0.20 0.19 0.15 0.20 0.74
------------------------------------------------------------------------


Net income has fluctuated over the quarters in part due to changes in revenues. Overall, revenues have fluctuated due to changes in production and the change in the price, as revenues are received in U.S. dollars and the U.S. dollar has weakened against the Canadian dollar during fiscal 2004 and 2005.

Other factors affecting net income include depletion, profit petroleum and foreign exchange. 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 due to 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. Profit petroleum expense decreased over fiscal 2004 due to deducting capital expenditures from the cash flow from Hazira prior to calculating the charge and profit petroleum increased in quarter four of fiscal 2005 related to the Bangladesh production. There was a foreign exchange gain in fiscal 2004 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. There was a tax recovery in quarter three related to Canadian tax pools available for future claim.

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

Fourth Quarter

Net income increased by 222 percent from quarter three to quarter four in fiscal 2005. The increase is due to higher revenue and a recovery of income taxes offset by a lower foreign exchange gain and increased depletion expense. The increase in revenue of 24 percent is due to higher production volumes at Feni and the offshore platform at Hazira offset by a lower price received. There was a reduction in current income tax expense, a recovery of prior years' income taxes and a recovery of future income taxes, all as a result of recognizing the effect of the tax holiday in India. Current income taxes in India are recorded at minimum alternative tax of 7.84 percent of income. Profit petroleum increased from quarter three to quarter four by $1.3 million due to increased revenues from India as well as the addition of Bangladesh profit petroleum. The foreign exchange gain on the long-term debt was lower than in quarter three due to a smaller movement in the U.S. dollar to Canadian dollar exchange rate. Depletion expense increased due to increased production combined with a downward technical revision in the Hazira proved reserve estimate by 39 billion cubic feet.

Funds from operations per share increased due to increased revenues, the decrease in current income tax expense and a recovery of prior years' income taxes. Excluding the effect of the recovery of prior years' income taxes, funds from operations per share for the quarter would be $0.66 per share, which is an increase of 43 percent over quarter three.

The Company had a working capital surplus of $100.4 million at the end of quarter four including cash of $102.0 million largely from the $97.7 million equity offering closing in February. Accounts receivable increased from quarter three to quarter four due to increased capital activity, the commencement of operating activity in Bangladesh and the insurance proceeds receivable related to the blowout. Capital expenditures totalling $22.4 million were made during quarter four.

On February 2, 2005, the Company closed an equity financing selling 2,000,000 common shares at a price of $51.00 per common share, raising net proceeds of $97.7 million after commissions and share issue costs. The net proceeds will be used to fund the ongoing exploration and development activities of the Company and for general working capital purposes.

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.

At the end of fiscal 2005, abandonment costs, timing of abandonment, and the credit-adjusted risk-free interest rate were revised based on current information. The Company obtained an external estimate of abandonment costs on the offshore wells and increased the future cost based on this report. The Company adjusted the future abandonment costs on certain land wells, gas plants and the land based drilling platform based on internal estimates. The credit-adjusted risk-free interest rate was reduced to coincide with the current rate on the Company's project facility. The Company feels that additional funds could be borrowed at this rate. The effect of these changes in factors used in the estimates resulted in a net increase in the asset retirement cost and the asset retirement obligation of $1.9 million.

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 involves interpretation of complex laws and regulations involving multiple jurisdictions. The Company pays income tax at the highest rate in each 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.

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. The Company believes much of its production in India will qualify for the tax holiday and has recorded the benefit of this tax holiday for fiscal 2005 in computing both the current and future components of its provisions for income taxes. As a result of the tax holiday, the Company expects to pay minimum alternative tax of 7.84 percent of income.

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.

Financial Instruments

A project facility (the facility) was established to fund the Corporation's development activities on India's west coast, specifically the Hazira offshore platform project and the Surat development projects. At March 31, 2005 the facility limit was US$30 million of which US$20 million was drawn. Subsequent to year end, 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.

In September 2004, the Company was granted approval to reschedule the repayment period of the loan to provide for the first repayment of principal on March 15, 2005 and six subsequent semi-annual payments. The first repayment occurred on March 15, 2005 based on the US$20 million drawn at that time. The September 2005 instalment will be for 11.1 percent of the total amount drawn (US$40 million) plus 11.1 percent of the second US$20 million drawn subsequent to the March instalment. Each of the next two instalments will be for 16.7 percent of the total amount drawn, and each of the last three instalments will be for 14.8 percent of the total amount drawn. 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 Company is exposed to fluctuations in interest rates as interest is based on a floating interest rate. Interest expense of $1.6 million was recognized in interest and financing expense on the income statement for fiscal 2005 (2004 - $339,000). If the Company fails to meet a number of positive and negative covenants, the loan will become payable at the discretion of the debtor. The Company monitors the requirements on an ongoing basis to ensure compliance.

Disclosure Controls and Procedures

The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of Niko's disclosure controls and procedures as of March 31, 2005. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls were effective in ensuring material information required to be disclosed by the Company in its annual filings or other reports filed or submitted under applicable Canadian securities laws is made known to management on a timely basis to allow decisions regarding required disclosure.



Outstanding Share Data

At June 24, 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 -
------------------------------------------------------------------------


CONSOLIDATED BALANCE SHEETS

As at March 31 (thousands of dollars) 2005 2004
------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 101,957 $ 21,215
Accounts receivable 46,219 25,403
Prepaid expenses 303 287
------------------------------------------------------------------------
------------------------------------------------------------------------
148,479 46,905
Income tax receivable (note 9) 12,961 -
Property and equipment (note 4) 319,274 232,034
$ 480,714 $ 278,939
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 40,694 $ 57,289
Current portion of long-term debt (note 6) 7,088 6,212
Current taxes payable 326 -
------------------------------------------------------------------------
48,108 63,501
Asset retirement obligation (note 5) 4,644 553
Taxes payable - 5,946
Future tax liability (note 9) - 22,221
Long-term debt (note 6) 14,418 19,998
------------------------------------------------------------------------
67,170 112,219
Shareholders' Equity
Share capital (note 7) 294,297 118,338
Contributed surplus (note 8) 1,212 215
Retained earnings 118,035 48,167
------------------------------------------------------------------------
413,544 166,720
$ 480,714 $ 278,939
------------------------------------------------------------------------
------------------------------------------------------------------------
Commitments (note 14)

See accompanying Notes to Consolidated Financial Statements


CONSOLIDATED STATEMENTS OF
INCOME AND RETAINED EARNINGS

Years ended March 31
(thousands of dollars,
except per share amounts) 2005 2004
------------------------------------------------------------------------

Revenue
Oil and gas $ 107,850 $ 85,834
Royalties (16,553) (15,309)
Profit petroleum (9,050) (8,817)
Pipeline and other 2,169 2,098
------------------------------------------------------------------------
84,416 63,806
Expenses
Production and pipeline 8,903 3,373
Interest and financing 1,622 339
General and administrative 3,613 3,376
Foreign exchange gain (1,861) (794)
Insurance proceeds (note 15) (3,333) -
Stock-based compensation 1,297 215
Depletion and depreciation 35,956 18,210
------------------------------------------------------------------------
46,197 24,719
------------------------------------------------------------------------
Income before income taxes 38,219 39,087
Income taxes (note 9)
Current (recovery) (13,782) 11,934
Future (reduction) (22,221) 1,802
------------------------------------------------------------------------
(36,003) 13,736
------------------------------------------------------------------------
Net income 74,222 25,351
Retained earnings, beginning of year 48,167 26,832
Dividends paid (4,354) (4,016)
------------------------------------------------------------------------
Retained earnings, end of year $ 118,035 $ 48,167
------------------------------------------------------------------------
Net income per share (note 11)
Basic $ 2.08 $ 0.76
Diluted $ 2.03 $ 0.74
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements


CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended March 31
(thousands of dollars) 2005 2004
------------------------------------------------------------------------
Cash provided by (used in):
Operating activities
Net income $ 74,222 $ 25,351
Add items not involving cash
from operations:
Depletion and depreciation 35,956 18,210
Future income taxes (reduction) (22,221) 1,802
Foreign exchange gain (1,861) (794)
Stock-based compensation 1,297 215
------------------------------------------------------------------------
Funds from operations 87,393 44,784
Change in non-cash working capital (17,141) 2,755
------------------------------------------------------------------------
70,252 47,539
Financing activities
Proceeds from issuance of shares, net of
issuance costs (note 7) 175,659 2,362
Long-term debt (2,698) 27,592
Dividends paid (4,354) (4,016)
------------------------------------------------------------------------
168,607 25,938
Investing activities
Addition of property and equipment (119,105) (103,597)
Acquisition of property and equipment - (13,267)
Change in non-cash working capital (39,012) 17,014
------------------------------------------------------------------------
(158,117) (99,850)
------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents 80,742 (26,373)
------------------------------------------------------------------------
Cash and cash equivalents, beginning of year 21,215 47,588
------------------------------------------------------------------------
Cash and cash equivalents, end of year $ 101,957 $ 21,215
------------------------------------------------------------------------
------------------------------------------------------------------------
Supplemental information:
Interest paid $ 3,049 $ 1,267
Taxes paid $ 3,941 $ 10,067
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements


Notes to Consolidated Financial Statements

All tabulated amounts are in thousands of dollars except per share amounts and oil and gas prices.

1. Company Activities

Niko Resources Ltd's (the "Company") business consists of the exploration for and development of petroleum and natural gas. The Company's business is carried on primarily in India, Bangladesh and Canada. The consolidated financial statements include the accounts of the Company, which is incorporated under the laws of Alberta together with the accounts of its wholly-owned subsidiaries, which are incorporated under the laws of the Barbados, Bermuda and Grand Caymans.

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

2. Accounting Policies

(a) Exploration and development costs

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 accumulated in cost centres by country. Costs capitalized include land and acquisition costs, geological and geophysical expenses, interest costs on major development projects (until commercial production commences), costs of drilling productive and non-productive wells, gathering and production facilities and equipment, and financing and administrative costs related to capital projects. Gains or losses are not recognized upon disposition of oil and gas properties unless such disposition would alter the depletion rate by 20 percent or more.

Costs of acquiring unproved properties are initially excluded from the full cost pool and are assessed yearly to ascertain whether impairment has occurred. When proved reserves are assigned to the property or the property is considered to be impaired, the cost of the property or the amount of impairment is added to the full cost pool. Costs capitalized are depleted and depreciated using the unit-of-production method by cost centre based upon net proved oil and gas reserves as determined by independent engineers. For purposes of the calculation, oil and gas reserves are converted to a common unit of measure on the basis of their relative energy content.

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. When the carrying value exceeds the fair value, an impairment loss is recognized to the extent that the carrying value of assets exceeds the net present value, calculated as the sum of the discounted value of future net revenues from proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects. The net present value is estimated using expected future prices and costs and is discounted using a risk-free interest rate.

The preparation of the financial statements in conformity with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The most significant estimates made by management relate to amounts recorded for the depletion and depreciation of capital assets, the provision for the asset retirement obligation and accretion expense and the ceiling test. The ceiling test calculation and the provisions for depletion, depreciation and asset retirement obligation are based on such factors as estimated proved reserves, production rates, petroleum and natural gas prices and future costs. By their nature, these estimates are subject to measurement uncertainty and actual results may differ from those estimates.

(b) Asset retirement obligation

The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred or when a reasonable estimate of fair value can be made. The fair value of an asset retirement obligation is recorded as a liability and a corresponding increase in property and equipment and is depleted based on the unit-of-production method. The liability increases and accretion expense are recognized each period due to the passage of time. Subsequent to initial measurement, period-to-period changes in the liability are recognized for revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Actual costs incurred upon settlement are charged against the asset retirement obligation. Any difference between the actual costs and the recorded liability is recognized as a gain or loss in earnings in the period in which the settlement occurs.

(c) Joint venture accounting

Substantially all of the exploration and production activities of the Company are conducted jointly with others and accordingly, these financial statements reflect only the Company's proportionate interest in such activities.

(d) Revenue recognition

Sales of petroleum are recorded in the period in which the title to the petroleum transfers to the customer. Petroleum produced but unsold is recorded as inventory until sold.

(e) Depreciation

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

(f) Foreign currency

Accounts of foreign operations, all of which are considered financially and operationally integrated, are translated to Canadian dollars using average exchange rates for the year for revenue and expenses. Monetary assets and liabilities are translated at the year-end current exchange rate and non-monetary assets and liabilities are translated using historical rates of exchange. Gains or losses resulting from these translation adjustments are included in net income for the year.

Transactions in foreign currencies are translated at rates in effect at the time of the transaction. Monetary assets and liabilities are translated at current rates. Gains and losses are included in income.

(g) Financial instruments

The Company from time to time employs financial instruments to manage exposures related to Canada/U.S. dollar exchange rates. These instruments are not used for speculative trading purposes.

The Company's risk management policy includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company believes the derivative financial instruments are effective as hedges, both at inception and over the term of the instrument, when the term and notional amount do not exceed the firm commitment or forecasted transaction and the underlying basis of the instrument, foreign exchange rate, correlates highly with the Company's exposure.

The Company may enter into foreign exchange forward contracts to hedge anticipated U.S. dollar denominated petroleum and natural gas sales. These derivatives, accounted for as hedges, are not recognized on the balance sheet. The gains and losses on these derivatives are recognized as an adjustment to petroleum and natural gas revenues when the revenue is recognized.

Gains and losses resulting from changes in the fair value of derivative contracts that do not qualify for hedge accounting are recognized in earnings when those changes occur.

The Company does not have any financial instruments that qualify for hedge accounting.

(h) 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.

(i) Measurement uncertainty

The carrying values of property and equipment, including acquired probable reserves, are subject to uncertainty associated with the quantity of oil and gas reserves, future production rates, commodity prices and other factors. Future events could result in material changes to the carrying values recognized in the financial statements. The Company participates in international joint ventures to which the ultimate finalization of definitive terms of arrangements may alter the degree of involvement in the particular project. These terms are subject to change over an extended period of time.

(j) Per share amounts

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

(k) Stock-based compensation plans

The Company has a stock-based compensation plan described in note 7. Effective April 1, 2003, compensation expense associated with the plan is calculated and recognized in income over the vesting period of the plan with a corresponding increase in contributed surplus. Compensation expense is based on the fair value of the stock options at the grant date using a Black-Scholes option pricing model. Any consideration received upon exercise of the stock options, together with the amount previously recognized in contributed surplus, is recorded as an increase to share capital.

3. Cash and Cash Equivalents

The Company considers deposits in banks and short-term investments with original maturities of three months or less as cash and cash equivalents. The short-term investments interest rates vary between 1.9 and 2.5 percent.



4. Property and Equipment

Accumulated
Depletion and Net Book
2005 (thousands) Cost Depreciation Value
------------------------------------------------------------------------
Oil and gas
India $284,752 $ 62,033 $222,719
Canada 1,859 1,075 784
Bangladesh 99,717 5,837 93,880
Other 485 - 485
Corporate 1,655 249 1,406
------------------------------------------------------------------------
$388,468 $ 69,194 $319,274
------------------------------------------------------------------------

Accumulated
Depletion and Net Book
2004 (thousands) Cost Depreciation Value
------------------------------------------------------------------------
Oil and gas
India $223,542 $ 32,303 $191,239
Canada 1,078 965 113
Bangladesh 38,814 - 38,814
Other 485 - 485
Corporate 1,576 193 1,383
------------------------------------------------------------------------
$265,495 $ 33,461 $232,034
------------------------------------------------------------------------


Costs of $135,848,000 (2004 - $81,188,000) associated with the Company's undeveloped properties in India and Bangladesh have been excluded from costs subject to depletion and depreciation.

At March 31, 2005, the Company performed a "ceiling test" for the Indian (Hazira and Surat), Bangladesh (Feni) and Canadian cost centres to assess the recoverable value. The D6 and NEC-25 blocks in India and Block 9 and Chattak in Bangladesh have been excluded from the ceiling test as the Company considers these properties to be major development projects. The future oil and condensate prices for Hazira, Surat and Feni are based on the April 1, 2005 commodity price forecast relative to Brent blend prices of our independent reserve evaluators and are adjusted for commodity price differentials specific to the Company. The future oil price for Canada is based on March 2005's actual selling price as an independent reserve evaluation was not performed due to the size of the Canadian operations relative to the Company. The Canadian operations accounted for less than 1% of sales for the year ended March 31, 2005. The gas price is based on contracts entered into by the Company. The following tables summarize the benchmark prices used in the ceiling test calculation. Based on these assumptions, the undiscounted value of future net revenues from the Company's proved reserved exceeded the carrying value of property, plant and equipment at March 31, 2005.




Hazira Surat Feni
Hazira Natural Natural Feni Natural Foreign Canada
Oil Gas Gas Condensate Gas Exchange Oil
Prices Prices Prices Prices Prices Rate Prices
------------------------------------------------------------------------
(US$/bbl)(US$/Mcf)(US$/Mcf) (US$/bbl)(US$/Mcf) (CAD)(CAD$/bbl)
2006 45.25 3.65 3.36 43.11 2.20 1.21 58.18
2007 44.51 3.65 3.36 40.10 2.20 1.21 58.18
2008 40.79 3.65 3.36 36.17 2.20 1.21 58.18
2009 37.20 3.65 3.36 32.72 2.20 1.21 58.18
2010 34.97 3.87 3.56 30.47 2.20 1.21 58.18
There-
after 35.35 4.05 3.77 30.47 2.20 1.21 58.18
------------------------------------------------------------------------


5. Asset Retirement Obligation

The asset retirement obligation relates to the future site restoration and abandonment costs including the costs of production equipment removal and environmental clean up based on regulations and economic circumstances at year end. The fair value of the asset retirement obligation is estimated at $4,644,000 as at March 31, 2005 (March 31, 2004 - $553,000).




The following table reconciles the Company's asset retirement
obligations at the end of each year:

(thousands) 2005 2004
------------------------------------------------------------------------
Obligation, beginning of year $ 553 $ 434
Obligation incurred during the year 1,972 77
Revision in estimated cash flows 1,896 -
Accretion expense 223 42
------------------------------------------------------------------------
Obligation, end of year $ 4,644 $ 553
------------------------------------------------------------------------


The Company has estimated the fair value of its total asset retirement obligations based on estimated future liability of $11,061,935 discounted using a credit adjusted risk-free rate of 7 percent. The costs are expected to be incurred between 2012 and 2019.

6. Long Term Debt

A project facility (the facility) was established to fund the Corporation's development activities on India's west coast, specifically the Hazira offshore platform project and the Surat development projects. At March 31, 2005 the facility limit was US$30 million of which US$20 million was drawn. Subsequent to year end, 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.

In September 2004, the Company was granted approval to reschedule the repayment period of the loan to provide for the first repayment of principal on March 15, 2005 and six subsequent semi-annual payments. The first repayment occurred on March 15, 2005 based on the US$20 million drawn at that time. The September 2005 instalment will be for 11.1 percent of the total amount drawn, US$40 million, plus 11.1 percent of the second US$20 million drawn subsequent to the March instalment. Each of the next two instalments will be for 16.7 percent of the total amount drawn, and each of the last three instalments will be for 14.8 percent of the total amount drawn. 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).




7. Share Capital

(a) Authorized

Unlimited number of Common shares
Unlimited number of Preferred shares

(b) Issued

(thousands, 2005 2004
except share amounts) Number Amount Number Amount
------------------------------------------------------------------------
Common shares
Balance, beginning of year 33,542,820 $118,338 33,247,820 $115,976
Issued for cash pursuant
to public offering 4,000,000 171,000 - -
Stock options exercised 743,750 12,767 295,000 2,362
Contributed surplus - 300
Share issue costs (d) - (8,108) - -
------------------------------------------------------------------------
Balance, end of year 38,286,570 $294,297 33,542,820 $118,338
------------------------------------------------------------------------


(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:




2005 2004
Weighted Weighted
Number of Exercise Number of Exercise
Options Price Options Price
------------------------------------------------------------------------
Outstanding April 1 2,540,000 $ 19.92 2,700,000 $ 18.14
Granted 533,000 41.70 285,000 25.73


Expired (350,000) 22.20 (25,000) 22.20
Forfeited - - (125,000) 22.20
Exercised (743,750) 17.17 (295,000) 8.05
------------------------------------------------------------------------
Outstanding March 31 1,979,250 $ 26.42 2,540,000 $ 19.92
------------------------------------------------------------------------
Exercisable March 31 720,000 $ 18.32 961,250 $ 15.13
------------------------------------------------------------------------

The following table summarizes stock options outstanding and
exercisable under the plan at March 31, 2005.

Outstanding Options Exercisable Options
Weighted Weighted
Remaining Average Average
Exercise Price Options (Years) Price Options Price
------------------------------------------------------------------------
$ 7.14 - 9.00 200,000 0.8 $ 7.95 200,000 $ 7.95
$ 22.20 - 26.47 1,190,000 2.9 22.61 520,000 22.30
$ 27.85 - 39.30 316,250 4.1 35.95 - -
$ 45.20 - 49.30 273,000 4.7 45.50 - -
------------------------------------------------------------------------
1,979,250 3.4 $ 26.42 720,000 $ 18.32
------------------------------------------------------------------------


Stock-based compensation:

In the fourth quarter of fiscal 2004, the Company adopted a new accounting policy for stock-based compensation related to common share options. Effective April 1, 2003, the Company records stock-based compensation expense for all common share options granted to employees and directors after April 1, 2003 using a fair value based method. Common share options granted prior to April 1, 2003, did not result in a compensation expense. The Company continues to disclose the pro-forma earnings impact for these options.

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:




Year ended March 31
(thousands, except per share amounts) 2005 2004
------------------------------------------------------------------------
Stock-based compensation $ 3,646 $ 3,573
Net income
As reported $ 74,222 $ 25,351
Pro forma $ 70,576 $ 21,778
Net income per common share
Basic
As reported $ 2.08 $ 0.76
Pro forma $ 1.98 $ 0.65
Diluted
As reported $ 2.03 $ 0.74
Pro forma $ 1.93 $ 0.64
------------------------------------------------------------------------



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

Year ended March 31 2005 2004
------------------------------------------------------------------------
Fair value of stock options granted (per option) $ 8.78 $ 8.05
Risk-free interest rate 2.93% 3.13%
Volatility 36% 38%
Expected life 4 Years 4 Years
Expected annual dividend per share $ 0.12 $ 0.12
------------------------------------------------------------------------


(d) The total share issue costs for the year ended March 31, 2005 were $8,108,000 (2004 - $12,705) net of the estimated future tax benefit of $nil (2004 - $nil).

(e) A shareholder rights plan (the "Rights Plan") was adopted by the shareholders on September 15, 1999. The Rights Plan is designed to provide shareholders with sufficient time to evaluate any unsolicited bid to acquire control of the Company and to allow shareholders to receive full and fair value for their shares. In the event that a bid, other than a permitted bid, to acquire 20 percent or more of the common shares is made, shareholders will become entitled to exercise rights to acquire common shares of the Company at 50 percent of market value. The Rights Plan was renewed at the Company's annual meeting in 2002 and expires at the Company's Annual Meeting in 2005 unless otherwise reconfirmed.



8. Contributed Surplus

As at March 31 (thousands) 2005 2004
------------------------------------------------------------------------
Contributed surplus, beginning of year $ 215 $ -
Stock based compensation 1,297 215
Stock options exercised (300) -
------------------------------------------------------------------------
Contributed surplus, end of year $ 1,212 $ 215
------------------------------------------------------------------------


9. Income Taxes

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



Year ended March 31 (thousands) 2005 2004
------------------------------------------------------------------------
Income before income taxes $ 38,219 $ 39,087
Statutory income tax rate 32.12% 33.63%
Computed expected income taxes 12,276 13,145
Higher tax rate in other jurisdiction - 3,919
Increase (reduction) in anticipated rate on
previously accumulated differences - (3,286)
Non-deductible expenses and other (783) 450
Adjustment to ending future income tax
liability resulting from reduction in tax rate - (492)
Recognition of new tax pools in the year (757) -
Recognition of tax holiday (46,739) -
------------------------------------------------------------------------
Provision for income taxes $(36,003) $ 13,736
------------------------------------------------------------------------

The components of the Company's future income tax liability at March 31,
2005 are as follows:

(thousands) 2005 2004
------------------------------------------------------------------------
Future income tax assets
Asset retirement obligation $ 1,492 $ 151
Unused losses 5,105 -
Unused foreign tax credits 4,031
Share issue expenses 2,583 422
Property and equipment 218 -
Financing cost - 284
Long-term amount receivable 75 -
------------------------------------------------------------------------
$ 13,504 $ 857
------------------------------------------------------------------------
Future income tax liabilities
Property and equipment 6,264 22,372
Long term debt 340 -
Valuation allowance 6,900 706
------------------------------------------------------------------------
13,504 23,078
------------------------------------------------------------------------
Net future income tax liability $ - $ 22,221
------------------------------------------------------------------------


Among its operations, the Company carries on business in India through a branch operation of a Canadian resident corporation. It is thus subject to taxation in both India and Canada. As a resident of Canada, the Company is granted relief from double taxation through the operation of the Canadian foreign tax credit system.

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 ("Convention").

The Company has recorded the benefit of this tax holiday for 2005 in computing both the current and future components of its provision for incomes taxes. As a result of the tax holiday, the Company expects to pay an alternative minimum tax of 7.84 percent of income.

In addition, based on tax legislation in India, the Company has applied for a refund on taxes for its 2001 fiscal year and has been successful at the first level of the Indian judicial system. The Indian tax authorities have appealed this decision to an appellate level court in India, but the case has not yet been heard. Company management expects the appeal to be successful based on the existing legislation and this judicial decision should also be applicable to fiscal years after 2001. The refund in question relates to the application of the tax holiday noted above. The Company originally made its tax filings in 2001 through 2003 without claiming this tax exemption. The Company has made representation and has discussed the tax sparing clause of the Convention with the Canadian tax authorities. Based upon agreement in principle by the Canada Revenue Agency that the Company is entitled to the benefit of the tax sparing clause of the Convention, a recovery of Indian taxes paid for the 2001 to 2003 fiscal years has been accrued in the financial statements as a long-term receivable in the amount of $17,729,000. The long-term receivable on the balance sheet of $12,961,000 is net of current income taxes payable in India of $4,768,000. The Company expects to realize this receivable as the Indian tax authorities reassess the taxes paid for these years.

10. 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:




Year ended March 31
($ thousands) India Bangladesh Canada Corporate Total
------------------------------------------------------------------------
2005
Revenue 96,500 10,929 421 - 107,850
Segment Profit 36,879 1,446 44 (2) 38,367
------------------------------------------------------------------------

2004
Revenue 85,552 - 282 - 85,834
Segment Profit 41,279 - 22 - 41,301
------------------------------------------------------------------------

2005
Total assets 267,371 117,334 913 95,096 480,714
Property and equipment 222,719 93,880 784 1,891 319,274
------------------------------------------------------------------------

2004
Total assets 220,270 39,661 235 18,773 278,939
Property and equipment 191,239 38,814 113 1,868 232,034
------------------------------------------------------------------------

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

Year ended March 31 (thousands) 2005 2004
------------------------------------------------------------------------
Segment profit $ 38,367 $ 41,301
Interest and other income 1,190 922
Financing (1,622) (339)
Administrative expenses (3,613) (3,376)
Foreign exchange gain 1,861 794
Insurance proceeds 3,333 -
Stock-based compensation (1,297) (215)
Income tax (expense) reduction 36,003 (13,736)
------------------------------------------------------------------------
Net income $ 74,222 $ 25,351
------------------------------------------------------------------------


11. Per Share Data

The weighted average number of common shares issued and outstanding for the year ended March 31, 2005 was 35,657,403 (2004 - 33,410,737). In computing diluted per share amounts, 883,392 shares with respect to stock options were added to the weighted average number of common shares outstanding for the year ended March 31, 2005 (2004 - 736,581).

12. Financial Instruments

Financial instruments of the Company consist of cash, prepaid expenses, accounts receivable, investments, accounts payable, accrued liabilities and bank indebtedness. As at March 31, 2005 and 2004 there were no significant differences between the carrying amounts of these instruments and their fair values.
The Company is exposed to floating interest rates with respect to its bank facility. The Company is also exposed to fluctuations in exchange rates due to the nature of the Company's operations as its revenue is in both Indian Rupees and U.S. dollars. Under the terms of the long-term debt agreement, the Company cannot manage its exposure to foreign exchange risk.

A portion of the Company's accounts receivable are with organizations in the oil and gas industry and are subject to normal industry credit risks. Purchasers of the Company's oil and natural gas production are subject to an internal credit review and must provide financial performance guarantees in order to minimize the risk of non-payment. Gas is sold under fixed-price, fixed-term contracts while oil is sold at prevailing world market prices.

13. Economic Dependence

During the year ended March 31, 2005, four customers purchasing production from India and one customer purchasing production from Bangladesh accounted for more than 69 percent of revenue (March 31, 2004 - 60 percent) and each of these customers individually accounted for more than 10 percent of revenue. During the year ended March 31, 2005 one customer accounted for 15 percent of revenue (March 31, 2004 - 22 percent).

14. Commitments

The Company and its partner are currently in arbitration with the government of India with respect to the cost recovery status of the investment in the 36-inch pipeline at Hazira. If successful in the arbitration the Company would reduce its Profit Petroleum payments currently being made and possibly receive a refund. Additionally, in October 2002, Gujarat State Petroleum Company Ltd. (GSPCL) and the Company signed a Memorandum of Understanding in which GSPCL agreed to transfer the rights of the 36-inch pipeline to the joint venture. At March 31, 2005, the Company is still in the process of obtaining the legal title of the 36-inch pipeline. For the year ended March 31, 2005 the Company included the 36-inch pipeline in property and equipment at the net book value of $7,592,000 (2004 - $8,684,000), a net payable to GSPC of $7,091,000 (2004 - $7,733,000) and net accrued revenues, after operating costs and depreciation of $501,000 (2004 - $957,000) with respect to the pipeline.

All of the Company's natural gas sales contracts contain supply-or-pay provisions by which should the Company fail to supply the minimum quantity of gas in any one month as specified in the contract, the Company may be liable to pay the vendor an approximately equivalent amount. To date, the Company has supplied at least the minimum quantity each month.



The Company has the following commitments with respect to its office
leases:

For the years ended March 31
(thousands) 2006 2007 2008 2009 2010 Thereafter
------------------------------------------------------------------------
Canada $ 187 $ 187 $ 187 $ 197 $ 202 $ 672
India 55 - - - - -
Bangladesh 41 41 41 17 - -
------------------------------------------------------------------------
$ 283 $ 228 $ 228 $ 214 $ 202 $ 672
------------------------------------------------------------------------


15. Insurance Proceeds

The life insurance proceeds relate to a key man term life insurance policy held by the Company on the life of Robert N. Ohlson, the former President, who died suddenly on November 24, 2004 from natural causes. The Company received the proceeds of $3.3 million during the year.

16. Guarantees

At March 31, 2005, the Company had issued US$0.11 million in letters of credit as part of the normal course of operations. Letters of credit issued in excess of the facility amount are secured by the Company's cash balance or EDC performance guarantees.

At March 31, 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 for Block 9. 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 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. The Company expects to renew the guarantee when it expires on October 15, 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 & Chief Executive Officer
    (403) 262-1020
    or
    Niko Resources Ltd.
    Richard Alexander
    Vice President Finance
    (403) 262-1020