Niko Resources Ltd.
TSX : NKO

Niko Resources Ltd.

June 25, 2008 08:30 ET

Niko Resources Announces Fourth Quarter & Year End Financial Results

CALGARY, ALBERTA--(Marketwire - June 25, 2008) - Niko Resources Ltd. (TSX:NKO) reports results for the three and twelve months ended March 31, 2008.

PRESIDENT'S REPORT TO THE SHAREHOLDERS

Following a year primarily focused on development, Niko is pleased to report a dramatic year-over-year increase in reserves. Our proved reserves at fiscal year-end increased by 86 percent to more than 200 MMBoe while proved plus probable reserves increased by 18 percent to almost 290 MMBoe. This represents a 20 fold production replacement ratio. The net present value of proved plus probable reserves increased by almost 40 percent. The reserves and net present value do not include the results of the additional 16 exploration discoveries in D6, nor any of the 10 successful exploration discoveries in NEC-25. From the first discovery at D6 in 2002, the development of the D6 gas fields has progressed in world record time for a deepwater offshore discovery. The development is on time and on budget, with first production scheduled to occur in the third calendar quarter of 2008. This will be a historic event not only for Niko, but also for India, as with less than 5 percent of the area of the massive D6 block developed, the fields will be able to more than double India's total current gas production.

Also during this past fiscal year, Niko continued to strengthen its balance sheet, preparing for the future by putting in place a US$550 million credit facility and exiting the year with a cash balance of over $450 million.

Last year, I indicated we would pursue new venture opportunities with the objective of expanding our inventory of high-impact prospective plays. I am pleased to report that over the last year Niko has obtained four new blocks in Pakistan and one new block in the Kurdistan Region of Iraq. These new blocks more than double Niko's net acreage from 2.4 million net acres to 4.9 million net acres.

OUTLOOK

D6 oil and natural gas production is expected to commence in the third calendar quarter of 2008. Volumes will ramp up to a targeted rate of 2.8 Bcf per day of natural gas and 40,000 bbls per day of oil. These events will culminate in a multi-fold increase in Niko's production and earnings.

Although four new exploration successes were made during the past year, drilling was largely allocated to development. Confirmed additional rigs becoming available in the coming year will enable redeployment to exploration drilling for both oil and gas.

Niko's goal is to continue to pursue new venture opportunities with the objective of expanding its inventory of high-impact prospective plays.

ACKNOWLEDGEMENTS

Once again, our successes in fiscal 2008 were owed to the hard work, the contributions made by our dedicated management team and employees and the commitment of our valued shareholders. On behalf of the Board of Directors, I express our sincere gratitude to all those involved in Niko's accomplishments.



(Signed) "Edward S. Sampson"
Edward S. Sampson,
Chairman of the Board, President and Chief Executive Officer
June 24, 2008


RESERVE, RESOURCE, OPERATIONAL AND FINANCIAL HIGHLIGHTS

- Total proved reserves at fiscal year-end increased by 86 percent to more than 200 MMBoe and total proved and probable reserves increased by 18 percent to almost 290 MMBoe.

- The R1 exploration well in the D6 Block added 2.2 Tcf (219 Bcf working interest to the Company) to the best case contingent resource.

- Niko signed production sharing agreements in Pakistan and the Kurdistan Region of Iraq in March and May of 2008, respectively.

- D6 proved natural gas reserves from the Dhirubhai 1 and 3 fields increased by 108 percent to 9.2 Tcf (0.9 Tcf working interest to the Company) while proved plus probable natural gas reserves increased by 15 percent to 13.0 Tcf (1.3 Tcf working interest to the Company).

- D6 gas development remains on track to start-up in the third calendar quarter of 2008 at a rate that is expected to increase to 2.8 Bcf/d (280 MMcf/d working interest to the Company).

- The MA discovery added 84 MMBoe (8.4 MMBoe working interest to the Company) of proved plus probable liquids reserves and 855 Bcf (85 Bcf working interest to the Company) of proved plus probable gas reserves.

- D6 oil development remains on track to start-up in the third calendar quarter of 2008 with a peak oil production rate of 40,000 bbls/d (4,000 bbls/d working interest to the Company).

- The D6 forecast net present value after income taxes discounted at 10 percent for proved plus probable reserves increased by 78 percent.



Reserve Highlights (1)
Natural Gas Natural Gas
March 31, 2008 March 31, 2007
Working Interest (2) Working Interest (2)
Reserves Category (Bcf) (Bcf)
----------------------------------------------------------------------------
Total proved 1,180 655
Total proved plus probable 1,683 1,465
----------------------------------------------------------------------------

Oil and NGL Oil and NGL:
March 31, 2008 March 31, 2007
Working Interest (2) Working Interest (2)
Reserves Category (MMBbls) (MMBbls)
----------------------------------------------------------------------------
Total proved 7.2 0.3
Total proved plus probable 8.9 0.6
----------------------------------------------------------------------------

(1) The reserves estimate includes the properties of Hazira, Surat, Feni and
Block 9 and the Dhirubhai 1 and 3 fields and the MA field of the D6
property at March 31, 2008. The MA field of the D6 property did not
previously have reserves attributable to it and is not included in the
above March 31, 2007 reserve estimate.
(2) Working Interest reserves are defined as those accruing to the Company's
working-interest share prior to the deduction of any royalty interests
owned by others including any profit petroleum amounts that may be
payable to the governments of India or Bangladesh.


Contingent Resource Highlights

D6 Block(1) Probabilistic Addition(2)
----------------------------------------------------------------------------
March 31, 2008 March 31, 2007
Contingent Contingent
OGIP (3) Resource (4) OGIP(3) Resource (4)
Working Working Working Working
Interest(5) Interest(5) Interest(5) Interest(5)
(Bcf) (Bcf) (Bcf) (Bcf)
----------------------------------------------------------------------------
Low Case (6) 880 610 662 468
Best Case (6) 1,050 720 822 585
High Case (6) 1,210 850 982 703
----------------------------------------------------------------------------

(1) The contingent resource includes discoveries made on the D6 property,
but excludes the Dhirubhai 1 and 3 fields and the MA field, which are
included in reserves.
(2) Probabilistic Addition is the statistical summation method for
estimating a range of uncertain outcomes pertaining to accretion of
resources resulting from multiple hydrocarbon discoveries. Results of
the addition are expressed with an associated probability of occurrence.
Each discovery included in the summation is itself a range of estimates.
(3) Original Gas In-Place (OGIP) is an engineering estimate of the gross
natural gas volume contained in the reservoir prior to production and
expressed at standard surface conditions.
(4) Contingent Resource is the quantity of hydrocarbons considered to be
potentially recoverable from a known accumulation, but which is not
currently considered to be commercially recoverable.
(5) Working Interest contingent resources are defined as those accruing to
the Company's working-interest share prior to the deduction of any
royalty interests owned by others including any profit petroleum amounts
that may be payable to the Government of India.
(6) The contingent resource is classified by range of uncertainty in
accordance with NI 51-101. The uncertainties associated with Resource
Estimates Low, Best and High are analogous to those of the Proved (1P),
Proved + Probable (2P) and Proved + Probable + Possible (3P) Reserves.
Specifically, the Low estimate has a greater than 90 percent chance of
being met or exceeded, the Best estimate has a 50 percent chance of
being met or exceeded and the High estimate has a 10 percent change of
being met or exceeded.

Operating Highlights
Three months ended Twelve months ended
March 31, March 31,
2008 2007 2008 2007
----------------------------------------------------------------------------
Average daily production
Oil and condensate (bbls/d) 288 280 311 290
Natural gas (Mcf/d) 78,528 86,729 80,991 86,888
----------------------------------------------------------------------------
Total combined (Mcfe/d) 80,253 88,410 82,854 88,630

Revenues, royalties and operating
costs
Oil and natural gas revenue
($/Mcfe) 3.33 3.66 3.44 3.57
Pipeline revenue ($/Mcfe) 0.01 0.02 0.02 0.02
Royalties ($/Mcfe) (0.15) (0.19) (0.17) (0.21)
Profit petroleum ($/Mcfe) (0.75) (0.71) (0.84) (0.65)
Operating costs ($/Mcfe) (0.30) (0.41) (0.36) (0.39)
----------------------------------------------------------------------------
Operating netback ($/Mcfe) 2.14 2.37 2.09 2.34

Drilling activity
Gross wells 6 10 23 21
Net wells 3.3 2.3 8.8 6.5
----------------------------------------------------------------------------

Financial Highlights

Three months ended Twelve months ended
March 31, March 31,
(thousands of dollars) 2008 2007 2008 2007
----------------------------------------------------------------------------
Petroleum and natural gas sales 24,327 29,093 104,225 115,486
Funds from operations 18,431 13,501 76,126 64,837
Net income (loss) 1,584 (3,128) (23,414) (31,637)
Capital expenditures 109,360 56,583 344,131 134,766
----------------------------------------------------------------------------


The selected financial information is prepared in accordance with Canadian generally accepted accounting principles (GAAP), except for "funds from operations" and "operating netback", which are used by the Company to analyze the results of operations. By examining funds from operations, the Company is able to assess its past performance and to determine its ability to fund future capital projects and investments. Funds from operations is calculated as cash flows from operating activities prior to the change in operating non-cash working capital and the change in long-term accounts receivable. 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 of similar measures for other companies. Operating netback is calculated as the average sales price per thousand cubic feet equivalent (Mcfe), plus pipeline revenue, less royalties, profit petroleum and operating expenses per Mcfe, and represents the before-tax cash margin for every Mcfe sold. The reporting currency of the Company is the Canadian dollar. Amounts presented are in Canadian dollars unless otherwise indicated.

OPERATIONS UPDATE

India

D6 BLOCK:

Exploration: The MK-1 Cretaceous exploration well, which is 11 kilometres from the MA oil development, is currently being drilled.

Conceptual studies are underway for the development of eight of the natural gas discoveries in the prolific D6 Block. These discoveries are adjacent to the Dhirubhai 1 and 3 gas fields that are currently under development. It is intended that these satellite discoveries be tied back to the Dhirubhai 1 and 3 facilities. Numerous other prospects have been identified in deeper water areas of the block where further upside potential will be evaluated.

Gas Development: The development of discoveries Dhirubhai 1 and 3 is on schedule for production of gas during the third calendar quarter of 2008. The wells and facilities are substantially complete.

The development plan for the Dhirubhai 1 and 3 gas fields provides for natural gas production at a rate of 2.8 Bcf/d (280 Mmcf/d working interest to the Company) envisaged within the first year of production operations. The Phase I initial field development costs are estimated at US$5.2 billion (US$520 million net to the Company). The project has remained on budget and the Company had spent US$258 million to March 31, 2008 of the US$520 million estimated cost for the project. The development provides flexibility in the critical components of the facilities to increase production to 4.2 Bcf/d (420 MMcf/d working interest to the Company).

In September 2007, the Government of India approved the pricing formula for the sale of natural gas to be produced from the D6 Block, which currently results in a gas price of US$4.20/MMBtu.

Oil Development: The wells, the floating production, storage and offloading vessel (FPSO) and other facilities for the MA field are substantially complete. Production is expected to commence in the third calendar quarter of 2008.

The field is estimated to have a peak oil production rate of 40,000 bbls/d (4,000 bbls/d working interest to the Company). The initial field development costs, excluding the FPSO, are estimated at US$1.5 billion (US$150 million net to the Company) and the Company had spent US$40 million to March 31, 2008.

The expected oil production from the MA field in the D6 Block will be sold at international market prices.

NEC-25 BLOCK: Geotechnical and geophysical studies have been completed with results used in the selection of drilling locations. Three wells were drilled during the year. Based on data obtained from logging and modular dynamics testing (MDT), the presence of hydrocarbons was confirmed in the wells. Additional exploratory locations are planned to be drilled in the coming year.

The offshore environmental study has been completed and onshore studies are in progress. Development plans have been prepared for the six gas discoveries that have been declared commercial by the Indian regulatory authorities, approved by the Joint Venture's Operating Committee and submitted to the Government of India.

CAUVERY: Two wells were drilled in Cauvery during the year and petrophysical analysis of the electric logs indicated no significant hydrocarbons were encountered in the wells. The 2007 Cauvery 3D seismic program was completed in September 2007. A total of 915 square kilometres of seismic data have been acquired on the Block. The seismic is currently being processed and drilling prospects will be identified to allow drilling of three new locations in early calendar 2009.

D4 BLOCK: In the deepwater block, MN-DWN-2003/1 (D4), located in the Mahanadi Basin, analysis of the 2,365-kilometre 2D seismic acquisition program has been completed. Based on the analysis, a further 2,800-kilometre 2D seismic program and a 3,600-square-kilometre 3D seismic program have been designed and acquisition is underway with completion expected in late calendar 2008. Once the new seismic data is processed and interpreted, initial drilling locations will be selected, possibly as early as mid-calendar 2009. Drilling is expected to follow shortly thereafter.

HAZIRA: The Hazira field is currently producing 44 MMcf/d (15 MMcf/d working interest to the Company). Workovers for onshore wells are ongoing. A new transition 3D seismic program is planned for later in calendar 2008 to explore for deeper oil and gas targets in the eastern half of the Hazira field.

SURAT: Current production from the Surat field is approximately 9 MMcf/d. A three-well drilling program has been successfully completed, the wells have been tied in and are on production.

Bangladesh

BLOCK 9: Two wells in Block 9, Bangora-1 and Bangora-5 are currently producing at a combined facility constrained rate of more than 70 MMcf/d (47 MMcf/d working interest to the Company). Facilities upgrades have commenced and are expected to allow production targets to increase to nearly 120 MMcf/d (80 MMcf/d working interest to the Company) by the fourth calendar quarter of 2008. A condensate plant module is scheduled to be installed and operational by mid-calendar 2009, which will increase condensate yields. Further drilling prospects have been identified south of the producing Bangora structure on the 40-kilometre-long Bangora-Lalmai anticline. Drilling is planned to commence on these prospects when a drilling rig is available.

FENI AND CHATTAK: Production from the Feni field is 5 MMcf/d. Future drilling activities at Feni and Chattak remain postponed pending resolution of overdue payment for gas owed to the Company by the Government of Bangladesh.

THAILAND: The Company exited Thailand during the fiscal year.

PAKISTAN: The four new production sharing agreements (PSAs) were signed in March 2008 and a contract has been awarded to conduct a 3,200-square-kilometre 3D seismic program to commence acquisition in late calendar 2008.

KURDISTAN REGION: Since signing the PSC for the Qara Dagh block in May 2008, field scouting has begun and a tender for a 500-kilometre 2D seismic program will be issued with acquisition expected to commence in the third quarter of calendar 2008.



PRODUCTION

The following table displays working interest production in the year ended
March 31, 2008 and forecast production for fiscal 2009:

Working interest Production Lower Estimate Upper Estimate
(daily average) March 31, 2008 Fiscal 2009 Fiscal 2009
----------------------------------------------------------------------------
Natural Gas (MMcf/d)
India
D6 - 90(1) 130(1)
Hazira 22 13 15
Surat 9 6 7
Bangladesh
Block 9 45 42 45
Feni 5 3 4
----------------------------------------------------------------------------
Oil (Bbls/d)
India
D6 - 1,100(1) 1,350(1)
Hazira 219 150 166
Other (2) 92 - -
----------------------------------------------------------------------------
Total (MMcfe/d) 83 219 231
----------------------------------------------------------------------------
(1) Production from the D6 Block is expected to commence in the third
calendar quarter of 2008. The above number represents the part year's
production during the period, spread over the entire year, and is not
representative of the daily rate.

(2) Less than 1 percent of total corporate volumes are from Canadian oil,
Bangladeshi condensate and Hazira condensate production. Therefore the
results from Canadian oil, Bangladeshi condensate and Hazira condensate
production are included in "Other", are not discussed separately and do
not have separate forecasts.


Operating Expense Outlook

During the year ended March 31, 2008 operating expenses averaged $0.36/Mcfe, and are anticipated to average less than $0.36/Mcfe in fiscal 2009.

FOURTH QUARTER HIGHLIGHTS

Net income in the quarter ended March 31, 2008 increased to $1.6 million from a net loss of $3.1 million in the same period in the prior year, for a total increase of $4.7 million. The main causes of the increase are from interest and other income and decreased income taxes, which were partially offset by a decrease in net revenues and a fair value loss on the Company's interest rate swaps. There was a decrease in net revenues of $4.4 million as additional production from Block 9 was more than offset by production declines in Hazira, Surat and Feni. Interest and other income increased by $6.5 million primarily as a result of interest earned on higher cash balances. Income tax expense decreased to $0.1 million in the fourth quarter from $4.2 million in the prior year's quarter. There was an income tax recovery of $2.0 million as a result of the application of a ruling received from the Indian Income Tax Appellate Tribunal to the prior years' income tax calculations more than offset by income taxes including additional tax assessed for the fiscal 2006 year related to Bangladesh.

The Company had working capital as at March 31, 2008 of $495.1 million, which included $456.3 million of cash and cash equivalents. The net increase in working capital from the quarter ended December 31, 2007 was a result of increased cash balances.

Capital expenditures were $109.4 million during the fourth quarter. Significant capital expenditures in the quarter were $101.3 million on the D6 property, primarily related to the development of the oil and gas fields, $2.5 million in Surat for drilling three new wells and $3.0 million at NEC-25 for exploration drilling. The remaining spending was for the other properties and new ventures.

RESERVES

The Canadian Oil and Gas Evaluation Handbook (COGE) definitions provide criteria for recoverable volumes to be classified as reserves. Reserves are those quantities of petroleum which are anticipated to be commercially recoverable from known accumulations. Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

The Company's petroleum reserves for Hazira, Surat, Feni, Block 9 and D6 were evaluated as at March 31, 2008 by Ryder Scott Company (RS). The Company's petroleum reserves for Hazira, Surat, Feni and Block 9 were evaluated as at March 31, 2007 by RS and the Company's petroleum reserves for D6 as at March 31, 2007 have been evaluated by Gaffney, Cline & Associates (GCA).

The Company's working interest proved natural gas reserves increased by 80 percent from 655 Bcf in the prior year-end to 1,180 Bcf as at March 31, 2008. Total working interest proved plus probable natural gas reserves increased by 15 percent from 1,465 Bcf in the prior year-end to 1,683 Bcf as at March 31, 2008. Under both proved and proved plus probable scenarios, the increase in reserves was due mainly to additional drilling during the year.

Oil and condensate reserves increased multi-fold year-over-year with the addition of oil and condensate (combined) reserves attributable to the MA field, which was included in the contingent resource at the prior year-end. Total proved oil and condensate (combined) reserves increased from 0.3 MMbbls to 7.2 MMbbls and total proved plus probable oil and condensate (combined) reserves increased from 0.6 MMbbls to 8.9 MMbbls.

The following tables detail the aggregate working interest reserves of the Company from the RS evaluation, as at March 31, 2008, using forecast prices and costs, as well as the aggregate net present value of future net revenue attributable to the reserves (after future income tax expense) estimated using forecast prices and costs, calculated without discount and using discount rates of 5 percent and 10 percent:



Summary of Oil and Gas Reserves - Company Total
Forecast Price and Costs
As at March 31, 2008
----------------------------------------------------------------------------
Oil and NGL Natural Gas
Working Interest Working Interest
Reserves Category (MMbbls) (Bcf)
----------------------------------------------------------------------------
Proved
Developed Producing 0.2 120
Developed Non-Producing 0.1 63
Undeveloped 6.9 998
----------------------------------------------------------------------------
Total Proved 7.2 1,180
Probable 1.7 502
----------------------------------------------------------------------------
Total Proved Plus Probable 8.9 1,683
----------------------------------------------------------------------------


Net Present Values of Future Net Revenues
After Income Taxes
Forecast Price and Costs
As at March 31, 2008
----------------------------------------------------------------------------
0% 5% 10%
Reserves Category (US$ thousands) (US$ thousands) (US$ thousands)
----------------------------------------------------------------------------
Proved
Developed Producing 164,623 142,974 125,928
Developed Non-Producing 46,284 34,958 27,458
Undeveloped 1,744,015 1,424,205 1,172,297
----------------------------------------------------------------------------
Total Proved 1,954,922 1,602,137 1,325,683
Probable 736,956 478,952 313,674
----------------------------------------------------------------------------
Total Proved Plus Probable 2,691,878 2,081,089 1,639,357
----------------------------------------------------------------------------

The following table reconciles the changes in reserves from the prior year
by category below:

Total Proved
Hazira +
D6 Surat Bangladesh Total
Natural Natural Natural Natural
Gas (WI) Gas (WI) Gas (WI) Gas (WI)
(Bcf) (Bcf) (Bcf) (Bcf)
----------------------------------------------------------------------------
March 31, 2007 442 25 189 655
Extensions/Discoveries 556 1 - 557
Technical revisions - - (2) (2)
Production - (11) (18) (30)
----------------------------------------------------------------------------
March 31, 2008 998 14 169 1,180
----------------------------------------------------------------------------

D6 Hazira Bangladesh Total
Oil & NGL Oil NGL Oil & NGL
(WI) (WI) (WI) (WI)
(MMbbls) (MMbbls) (MMbbls) (MMbbls)
----------------------------------------------------------------------------
March 31, 2007 - 0.1 0.2 0.3
Extensions/Discoveries 6.9 - - 6.9
Technical revisions - 0.1 - 0.1
Production - (0.1) - (0.1)
----------------------------------------------------------------------------
March 31, 2008 6.9 0.1 0.2 7.2
----------------------------------------------------------------------------

Total Proved Plus Probable

Hazira +
D6 Surat Bangladesh Total
Natural Natural Natural Natural
Gas (WI) Gas (WI) Gas (WI) Gas (WI)
(Bcf) (Bcf) (Bcf) (Bcf)
----------------------------------------------------------------------------
March 31, 2007 1,132 33 300 1,465
Extensions/Discoveries 252 1 - 252
Technical revisions - (1) (4) (5)
Production - (11) (18) (30)
----------------------------------------------------------------------------
March 31, 2008 1,384 21 278 1,683
----------------------------------------------------------------------------

D6 Hazira Bangladesh Total
Oil & NGL Oil NGL Oil & NGL
(WI) (WI) (WI) (WI)
(MMbbls) (MMbbls) (MMbbls) (MMbbls)
----------------------------------------------------------------------------
March 31, 2007 - 0.3 0.4 0.6
Extensions/Discoveries 8.4 - - 8.4
Technical revisions - - - -
Production - (0.1) - (0.1)
----------------------------------------------------------------------------
March 31, 2008 8.4 0.2 0.3 8.9
----------------------------------------------------------------------------

Reserve Price Forecast

The following forecast prices were provided by RS based on discussions with
Niko, existing contracts and expected future contracts:

D6 (D1 + D3 D6 (MA
fields) field) Hazira Surat Block 9 Feni
Natural Natural Natural Natural Natural Natural
Gas Price Gas Price Gas Price Gas Price Gas Price Gas Price
Fiscal US$/Mcf US$/Mcf US$/Mcf US$/Mcf US$/Mcf US$/Mcf
(1) (1) (2) (2) (3) (3)
----------------------------------------------------------------------------
2009 3.82 4.19 4.58 5.13 2.34 1.75
2010 3.82 4.19 4.97 5.64 2.34 1.75
2011 3.82 4.19 4.84 5.69 2.34 1.75
2012 3.82 4.19 4.84 5.69 2.34 1.75
2013 3.82 4.19 4.84 5.69 2.34 1.75
Average
thereafter 6.26 6.87 4.89 5.69 2.34 1.75
----------------------------------------------------------------------------


D6 Hazira Block 9 Feni
Oil Oil NGL NGL
Price Price Price Price
Calendar US$/bbl(4) US$/bbl(4) US$/bbl(5) US$/bbl(5)
----------------------------------------------------------------------------
2008 90.07 90.07 105.08 40.00
2009 84.45 84.45 98.53 40.00
2010 78.83 78.83 91.97 40.00
2011 75.08 75.08 87.60 40.00
2012 73.21 73.21 85.41 40.00
Average thereafter 79.84 79.84 93.15 40.00
----------------------------------------------------------------------------

(1) The D6 natural gas prices for shown in the table were provided by RS
based on term sheets Niko has signed with buyers that outline the terms
that will be included in the gas contracts for Dhirubhai 1 and 3 fields.

(2) The Hazira and Surat natural gas prices shown in the table were provided
by RS based on discussions with Niko and contractual agreements provided
by Niko to RS. The natural gas prices are the contracted prices plus the
royalty expense, which is paid by the purchaser in addition to the
contracted price.

(3) The natural gas prices shown in the table were provided by RS based on
the price contracted by the Company with the Government of Bangladesh
for production from the Feni field and based on the price in the PSC
between the Company, its joint venture partner and the Government of
Bangladesh for production from Block 9.

(4) The D6 and Hazira oil prices shown on this table were provided by RS and
reflect their current estimates, which are based on their survey of
future hydrocarbon parameters used by financial institutions and others
in industry.

(5) The oil prices shown on this table were provided by RS and reflect their
current estimates, which are based on their survey of future hydrocarbon
parameters used by financial institutions and others in industry. The
condensate price for Bangladesh is a combination of the Feni condensate
price, which is provided by RS based on sales data provided by Niko to
RS, and the Block 9 condensate price, which are provided by RS and
reflect its current estimates, which are based on its survey of future
hydrocarbon parameters used by financial institutions and others in
industry.


Contingent Resource

The Company has contingent resources for the discoveries on the D6 property that are not included in the Dhirubhai 1 and 3 and MA fields, as the Dhirubhai 1 and 3 and MA fields' discoveries are classified as reserves.

The SPE, WPC, AAPG and COGE definitions provide criteria for recoverable volumes to be classified as Contingent Resources and Prospective Resources. Contingent resources are those quantities discovered and potentially recoverable that are currently not considered to satisfy the criteria for commerciality. Prospective resources are those quantities estimated to be potentially recoverable from undiscovered accumulations, specifically where no drilling has taken place.

An independent study of the natural gas discovered to date in the D6 Block was prepared by GCA (Evaluation of Gas Reserves - Block KG-DWN-98/3 offshore India as at March 31, 2007 and 2008) and included an estimate for 14 of the discoveries. These discoveries do not have approved development plans to allow them to be classified as "reserves" under the SPE, WPC and National Instrument 51-101 (NI 51-101) (Canadian Standard) resources classification guidelines.

In accordance with NI 51-101, the categories of Low, Best and High equate to conservative (probability of 90 percent), realistic (probability of 50 percent) and optimistic (probability of 10 percent), respectively. Each resource estimate being mutually exclusive and must not be aggregated.

The following table presents the conservative, realistic and optimistic categories of the contingent resource for the Company's 10 percent interest in the D6 Block:



D6 Block(1) Probabilistic Addition(2)
----------------------------------------------------------------------------
2008 2007
Contingent Contingent
OGIP (3) Resource (4) OGIP(3) Resource(4)
Working Working Working Working
Interest(5) Interest(5) Interest(5) Interest(5)
(Bcf) (Bcf) (Bcf) (Bcf)
----------------------------------------------------------------------------
Low 880 610 662 468
Best 1,050 720 822 585
High 1,210 850 982 703
----------------------------------------------------------------------------

(1) The contingent resource includes discoveries made on the D6 property
excluding the Dhirubhai 1 and 3 fields and the MA field, which are
included in reserves.
(2) Probabilistic Addition is the statistical summation method for
estimating a range of uncertain outcomes pertaining to accretion of
resources resulting from multiple hydrocarbon discoveries. Results of
the addition are expressed with an associated probability of occurrence.
Each discovery included in the summation is itself a range of estimates.
(3) Original Gas In-Place (OGIP) is an engineering estimate of the gross
natural gas volume contained in the reservoir prior to production and
expressed at standard surface conditions.
(4) Contingent resource is the quantity of hydrocarbons to be potentially
recoverable from a known accumulation, but which is not currently
considered to be commercially recoverable.
(5) Working Interest contingent resources are defined as those accruing to
the Company's working-interest share prior to the deduction of any
royalty interests owned by others including any profit petroleum amounts
that may be payable to the Government of India.


LAND HOLDINGS

The Company signed PSAs for four blocks in Pakistan in March 2008 adding 9,920 square kilometres of undeveloped land to its portfolio of properties. In May 2008, the Company signed a PSC for an interest in a block in the Kurdistan Region of Iraq adding 846 square kilometres (228 net to the Company) of undeveloped land.

The following table sets out the Company's undeveloped and developed land position at June 23, 2008:



Undeveloped(1) Developed Total
Gross Net Gross Net Gross Net
km2 (2) km2 (3) km2 (2) km2 (3) km2 (2) km2 (3)
----------------------------------------------------------------------------
India 35,817 5,296 664 100 36,481 5,396
Pakistan 9,920 9,920 - - 9,920 9,920
Bangladesh 7,269 4,422 30 22 7,299 4,444
Kurdistan
Region 846 228 - - 846 228
Canada - - 3 1 3 1
----------------------------------------------------------------------------
Total 53,852 19,866 697 123 54,549 19,989
----------------------------------------------------------------------------

(1) Undeveloped land position refers to those lands in which Niko has an
interest and which have not been assigned reserves.
(2) Gross km2 is the area of land in square kilometres in which Niko has a
working interest.
(3) Net km2 is the sum of the products obtained by multiplying the number of
gross square kilometres by Niko's percentage working interest therein.


MANAGEMENT'S DISCUSSION and ANALYSIS

Management's Discussion and Analysis (MD&A) of the financial condition, results of operations and cash flows of Niko Resources Ltd. ("Niko" or "the Company") should be read in conjunction with the audited consolidated financial statements and accompanying notes for the year ended March 31, 2008. This MD&A is effective June 24, 2008. 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 continent. Over the reporting period, revenue and expenses were generated and capital expenditures were made in India, Bangladesh and Canada, and capital expenditures were made in Thailand and for new ventures. The Company's activities are carried out primarily in U.S. dollars as well as the currencies of each country in which the Company operates. The Company reports financial results in Canadian dollars. The selected financial information presented throughout the MD&A is prepared in accordance with Canadian generally accepted accounting principles (GAAP), except for "funds from operations", "funds from operations per share - diluted", "net operating income", "operating netback", "funds from operations netback" and "earnings netback", which are used by the Company to analyze the results of operations. These non-GAAP measures do not have any standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other companies.

The fiscal year for the Company is the 12-month period ended March 31. The terms "fiscal 2008", "current year" and "the year" are used throughout the MD&A and in all cases refer to the period from April 1, 2007 through March 31, 2008. The term "fiscal 2009" is used throughout the MD&A and refers to the period from April 1, 2008 through March 31, 2009. The terms "previous year", "prior year" and "fiscal 2007" are used throughout the MD&A for comparative purposes and refer to the period from April 1, 2006 through March 31, 2007. The term "fiscal 2006" is used throughout the MD&A for comparative purposes and refers to the period from April 1, 2005 through March 31, 2006. The terms "current quarter", "the quarter" and "fourth quarter" are used throughout the MD&A and in all cases refer to the period from January 1, 2008 through March 31, 2008.

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

Less than 1 percent of total corporate volumes and 3 percent of total corporate revenue are from Canadian oil, Bangladesh condensate and Hazira condensate production. Therefore, the results from Canadian oil, Bangladesh condensate and Hazira condensate production are not discussed separately.

Certain prior-year amounts have been reclassified to conform to current year presentation.

Forward-Looking Information

The information contained in this MD&A contains forward-looking information about Niko's operations, reserves estimates, production and capital spending. This forward-looking information is based on assumptions that the Company believes were reasonable at the time such information was prepared, but assurance cannot be given that these assumptions will prove to be correct, and the forward-looking information in this MD&A should not be unduly relied upon. The Company prepares production forecasts taking into account historical and current production, actual and planned events that are expected to increase or decrease production and production levels indicated in the Company's reserve reports. The Company prepares capital spending forecasts based on internal budgets for operated properties, budgets prepared by the Company's joint venture partners, when available, for non-operated properties, field development plans and actual and planned events that are expected to affect the timing or costs of the capital spending. The Company prepares operating expense forecasts based on historical and current levels of expenses and actual and planned events that are expected to increase or decrease production and/or the associated expenses. The Company discloses the nature and timing of expected future events based on the Company's budgets, plans, intentions and expected future events for operated properties and based on budgets, expected future events and other communications received from the Company's joint venture partners, when available, for non-operated properties. The forward looking information and the Company's assumptions are subject to uncertainties and risks including, but not limited to, expectations regarding financing sources, projections for capital spending, actual financial condition of the Company, results of operations, commodity prices and exchange rates, uncertainties inherent in estimating oil and natural gas reserves, performance characteristics of the Company's oil and natural gas properties, as well as liabilities inherent in oil and natural gas operations and in operating in foreign countries. The Company updates forward-looking information related to operations, production and capital spending on a quarterly basis and updates reserves on an annual basis.

Non-GAAP Measures

By examining funds from operations, the Company is able to assess its past performance and to determine its ability to fund future capital projects and investments. Funds from operations is calculated as cash flows from operating activities prior to the change in operating non-cash working capital and the change in long-term accounts receivable. Funds from operations is a non-GAAP measure and does not have any standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies.



Year Ended March 31,
($ thousands) 2008 2007
----------------------------------------------------------------------------
Cash flow provided by operating activities (GAAP
measure) 61,538 48,721
Less:
Change in non-cash working capital 1,992 959
Change in long-term accounts receivable (16,580) (17,075)
----------------------------------------------------------------------------
Funds from operations (Non-GAAP measure) 76,126 64,837
----------------------------------------------------------------------------


By examining net operating income, operating netback, funds from operations netback and earnings netback, the Company is able to evaluate past performance by segment and overall. Net operating income is calculated as oil, natural gas and pipeline revenues less royalties, profit petroleum expenses, operating expenses and pipeline expenses. Operating netback is calculated as net operating income per thousand cubic feet equivalent (Mcfe) and represents the before-tax cash margin for every Mcfe sold. Funds from operations netback is calculated as the funds from operations per Mcfe and represents the cash margin for every Mcfe sold. Earnings netback is calculated as net income per Mcfe and represents net income for every Mcfe sold. There are no comparable GAAP measures for net operating income, operating netback, funds from operations netback or earnings netback, and these measures are unlikely to be comparable with the calculation of similar measures in other companies.



Year Ended March 31,
($ thousands) 2008 2007
----------------------------------------------------------------------------
Oil and natural gas revenue 104,225 115,486
Pipeline revenue 666 777
Royalties (5,195) (6,704)
Profit petroleum (25,246) (20,885)
Operating and pipeline expense (11,027) (12,489)
----------------------------------------------------------------------------
Net operating income (non-GAAP measure) 63,423 76,185
----------------------------------------------------------------------------
Volume produced (Mcfe) 30,324,730 32,350,019
----------------------------------------------------------------------------
Operating netback ($/Mcfe) (non-GAAP measure) 2.09 2.34
----------------------------------------------------------------------------

Year Ended March 31,
($ thousands) 2008 2007
----------------------------------------------------------------------------
Net operating income (non-GAAP measure) 63,423 76,185
Interest and other income 21,852 4,377
General and administrative expense (7,069) (6,180)
Interest and financing on debt - (1,611)
Realized foreign exchange (loss) gain (206) 2,363
Current income tax expense (1,874) (10,297)
----------------------------------------------------------------------------
Funds from operations (non-GAAP measure) 76,126 64,837
----------------------------------------------------------------------------
Volume produced (Mcfe) 30,324,730 32,350,019
----------------------------------------------------------------------------
Funds from operations netback ($/Mcfe) (non-GAAP
Measure) 2.51 1.99
----------------------------------------------------------------------------

12 Months Ended March 31,
($ thousands) 2008 2007
----------------------------------------------------------------------------
Funds from operations (Non-GAAP measure) 76,126 64,837
Unrealized foreign exchange (loss) (8,391) (334)
Unrealized gain on short-term investments 1,421 -
Amortization of debt issue costs - (768)
Loss on risk management contracts (2,070) -
Discount of long-term account receivable (4,575) -
Stock-based compensation expense (17,257) (18,490)
Asset impairment (26,788) -
Depletion, depreciation and accretion (41,880) (76,882)
----------------------------------------------------------------------------
Earnings(1) (23,414) (31,637)
----------------------------------------------------------------------------
Volume produced (Mcfe) 30,324,730 32,350,019
----------------------------------------------------------------------------
Earnings netback ($/Mcfe) (Non-GAAP Measure) (0.77) (0.98)
----------------------------------------------------------------------------

(1) Earnings is a GAAP measure defined as net income (loss) on the
consolidated statement of operations and retained earnings.


OVERALL PERFORMANCE

Funds from operations

The reported funds from operations for the year were $76.1 million, an improvement of $11.3 million over the $64.8 million reported in the prior year. Net operating income was $12.8 million lower in the year than in the prior year. Net revenues decreased primarily as a result of a decrease in production from the Hazira, Surat and Feni fields due to natural declines. The current year's net operating income includes a one-time negative adjustment of $4.0 million due to the adverse resolution of a previously disclosed dispute regarding profit petroleum. In addition to the change in net operating income, interest and other income improved funds from operations by $17.5 million in the current year, primarily due to higher average cash balances. There was a realized foreign exchange loss in the year compared to a gain in the prior year resulting in a $2.6 million reduction in funds from operations. The realized net foreign exchange loss in the year was primarily a result of the translation of the Indian rupee-denominated working capital. Income taxes improved funds from operations by $8.4 million. The Company recognized an income tax recovery from re-estimating prior years' tax filings and current-year tax estimates, applying the Surat tax holiday deduction and recognized an income tax recovery as a result of applying a tax tribunal ruling received. These improvements were partially offset by tax on the interest income earned and additional tax assessed in Bangladesh.

Net Income (Loss)

There was a net loss of $23.4 million in the year compared to a net loss of $31.6 million in the prior year. The $8.2 million improvement occurred due to higher funds from operations of $11.3 million, which was only partially offset by a $3.1 million increase in non-cash charges.

In addition to an increase in funds from operations, as discussed in this MD&A, there was a decrease in depletion, depreciation and accretion expense of $35.0. These improvements in net income were more than offset by an increase in the unrealized foreign exchange loss of $8.1 million; an asset impairment of $26.8 million; a discount of long-term account receivable of $4.6 million; and a $2.1 million loss on risk management contracts, as discussed in this MD&A.

Depletion, depreciation and accretion expense for the year decreased by $35.0 million from the prior year, improving net income. On a per Mcfe basis, this was a reduction of 43 percent. There was a 47 percent decrease in the rate per Mcfe in India due largely to a decrease in the remaining costs being depleted as a result of a foreign currency translation adjustment in the fourth quarter of fiscal 2007.

The unrealized foreign exchange loss was incurred on translation of U.S. dollar held cash to Canadian dollars.

The improvements in net income as discussed above were partially offset by the write-off of Thailand and new venture assets of $26.8 million and a non-cash charge of $4.6 million related to discounting the long-term account receivable, which is for production from the Feni field in Bangladesh.

There was an unrealized loss of $2.1 million on the recognition of the fair value of the Company's risk management contracts, which are comprised of a series of interest rate swaps due to the decrease in forecast LIBOR rates during the period.



SELECTED ANNUAL INFORMATION

Year ended March 31 (thousands of dollars,
except per share amounts) 2008 2007 2006
----------------------------------------------------------------------------
Oil and natural gas revenue 104,225 115,486 121,168
Net income (loss) (23,414) (31,637) (4,352)
Per share basic and fully diluted ($) (0.51) (0.79) (0.11)
Total assets 1,353,923 674,560 517,258
Total long-term financial liabilities 207,552 8,974 6,779
Dividends per share 0.12 0.12 0.12
----------------------------------------------------------------------------


There was a decrease in oil and natural gas revenue in fiscal 2007 and fiscal 2008 due to natural declines in the Hazira, Surat and Feni fields and the effect of a decrease in the value of the U.S. dollar relative to the Canadian dollar, as the Company receives its revenue in U.S. dollars. This was partially offset by increased production from the Block 9 field and increased prices at Hazira and Surat.

In addition to the change in oil and natural gas revenue described above, the main reasons for the increase in net loss and net loss per share from fiscal 2006 to fiscal 2007 were the increase in stock-based compensation expense due to additional stock option grants, the increase in profit petroleum expense due to commencement of production from Block 9 and the increase in depletion and depreciation expense due to a downward revision of producing reserves in fiscal 2006.

Despite the decrease in oil and natural gas revenues described above, the net loss and net loss per share decreased from fiscal 2007 to fiscal 2008, mainly due to the increase in interest income as a result of higher cash balances in the year, the decrease in depletion expense due largely to a decrease in the remaining costs being depleted as a result of a foreign currency translation adjustment in the fourth quarter of fiscal 2007 and decreased income taxes, as the Company recognized an income tax recovery from re-estimating prior-years' tax filings and current-year income taxes applying the Surat tax holiday deduction, as well as an income tax recovery as a result of applying a tax tribunal ruling received, partially offset by tax on the interest income earned and additional tax assessed in Bangladesh. The items contributing to a decrease in the net loss and net loss per share were partially offset by the write-off of Thailand assets and a non-cash charge related to discounting the long-term account receivable, which is for production from the Feni field in Bangladesh. Finally, there was an increase in the net foreign exchange loss as a result of the translation of U.S. dollar held cash, the Indian rupee-denominated long-term income tax receivable and Indian rupee-denominated working capital also increasing the net loss.

Total assets increased by $157 million in fiscal 2007 and a further $679 million in fiscal 2008 largely as a result of increased cash balances in both years as well as an increase in capital assets.

Total long-term financial liabilities consisted of the asset retirement obligation in fiscal 2006 and fiscal 2007 and also included the long-term portion of debt incurred in fiscal 2008.

UPDATE ON SIGNIFICANT PROJECTS

Capital Expenditures

The following table displays capital spending during the year ended March 31, 2008 and forecast capital spending for fiscal 2009:



Exploration and Development Spending (net to
the Company)
Actual Forecast
(millions of dollars) Fiscal 2008 Fiscal 2009
----------------------------------------------------------------------------
India
Cauvery 20.3 8 - 9
D4 0.1 7 - 8
D6 295.2 380 - 400
Hazira 2.6 4 - 5
NEC-25 8.1 12 - 13
Surat 2.6 1
Bangladesh
Block 9 6.6 13 - 14
Chattak & Feni 2.5 1
Pakistan - 56 - 58
Kurdistan Region - 25 - 27
Thailand 4.5 -
Other 1.6 -
----------------------------------------------------------------------------
Total 344.1 507 - 536
----------------------------------------------------------------------------


India

Cauvery - The Company was awarded 100 percent interest in the Cauvery Block, which is located in southern Tamil Nadu, in the NELP-V bidding round in 2005. The block is in the exploration phase and has mainly oil potential.

Capital expenditures in the year were $20.3 million to drill two wells in the block and for a 3D seismic program. The remaining capital expenditures related to the minimum work program are estimated at US$7.5 million, which must be spent within three years of the issuance of the Production Exploration Licence. The seismic is currently being processed and drilling prospects will be identified to allow drilling of three new locations in early calendar 2009.

D4 - The Company was awarded a 15 percent interest in the D4 Block, located in the Mahanadi Basin offshore the east coast of India, as part of the NELP-V bidding round in 2005. The block, which is currently in the exploration phase, encompasses more than 17,000 square kilometres.

Analysis of a 2,365-kilometre 2D seismic acquisition program was completed. Based on the analysis, a further 2,800-kilometre 2D seismic program and a 3,600-square-kilometre 3D seismic program have been designed and acquisition is underway with completion expected in late calendar 2008. Once the new seismic data is processed and interpreted, initial drilling locations will be selected, possibly as early as mid-calendar 2009. Drilling is expected to follow shortly thereafter.

The estimated cost of the Phase I commitment, which includes seismic and drilling three exploration wells, totals US$97.6 million (US$14.6 million net to the Company), which must be expended by September 2009. Forecast expenditures for fiscal 2009 are primarily for the seismic programs described above.

D6 - The Company has a 10 percent working interest in the 7,645-square-kilometre D6 Block. The block was awarded to the Company and its partner in the Government of India's first international bid round in 1999. Development of the Dhirubhai 1 and 3 natural gas fields and the MA oil field is substantially complete and exploration is ongoing on this block.

Conceptual studies are underway for the development of eight of the natural gas discoveries in the D6 Block. The discoveries are adjacent to the Dhirubhai 1 and 3 gas fields that are currently under development. It is intended that these satellite discoveries be tied back to the Dhirubhai 1 and 3 facilities.

Gas Development: The development of discoveries Dhirubhai 1 and 3 is on schedule for production of gas during the third calendar quarter of 2008. The wells and facilities are substantially complete.

The development plan for the Dhirubhai 1 and 3 gas fields provides for natural gas production at a rate of 2.8 Bcf/d (280 Mmcf/d net to the Company) envisaged within the first year of production operations. The Phase I initial field development costs are estimated at US$5.2 billion (US$520 million net to the Company). The Company had spent US$258 million to March 31, 2008 of the US$520 million estimated for the project. The development provides flexibility in the critical components of the facilities to increase production to 4.2 Bcf/d (420 MMcf/d net to the Company).

In September 2007, the Government of India approved the pricing formula for the sale of natural gas to be produced from the D6 Block, which currently results in a gas price of US$4.20/MMBtu.

Oil Development: The wells, the floating production, storage and offloading (FPSO) vessel and other facilities are substantially complete. Production is expected to commence in the third calendar quarter of 2008.

The field is estimated to have the capacity for a peak oil production rate of 40,000 bbls/d (4,000 bbls/d net to the Company). The initial field development costs, excluding the FPSO, are estimated at US$1.5 billion (US$150 million net to the Company) and the Company had spent US$40 million to March 31, 2008.

The expected oil production from the MA field in the D6 Block will be sold at international market prices.

Capital expenditures at D6 in the year were $295.2 million. Spending during the year related primarily to natural gas and oil developments, but also included one exploration well. Forecast activity for fiscal 2009 includes the continuation of the gas development for the Dhirubhai 1 and 3 natural gas fields, development of the MA oil field and additional exploration drilling.

Hazira - The Company has a 33 percent working interest in the 50-square-kilometre Hazira onshore and offshore block on the west coast of India, which lies adjacent to a large industrial corridor about 25 kilometres southwest of the city of Surat. This field commenced gas production in 1996 and oil production in March 2006.

Capital expenditures in the year were $2.6 million primarily related to workover costs for natural gas wells. Capital expenditures forecast for fiscal 2009 include a new transition 3D seismic program, various well recompletions and upgrading of facilities.

Surat - The Company was awarded rights to the Surat Block in July 2001 and after completion of the exploratory phase retained a development area of 24 square kilometres containing the Bheema and NSA shallow natural gas fields. These fields have been producing natural gas since April 2004.

Capital expenditures of $2.6 million during the year were made for a three-well drilling program that was successfully completed. The wells have been tied in and are on production. There is no capital activity planned for fiscal 2009.

NEC-25 - The Company has a 10 percent working interest in the NEC-25 Block, which covers 10,755 square kilometres in the Mahanadi Basin off the east coast of India, awarded to the Company and its partner in the Government of India's first international bid round in 1999. The Company and its partner have capital commitments for Phase II exploration for seismic and two exploration wells as per the production sharing contract (PSC) and have drilled sufficient wells to meet the commitment. Capital expenditures in the year were $8.1 million, primarily for drilling wells- J1 and A9A, and for commencement of drilling an additional well, B3.

Development plans for the six discoveries that have been declared commercial by the Indian regulatory authorities have been approved by the Joint Venture's Operating Committee and submitted to the Government of India.

Capital expenditures forecast for fiscal 2009 include environmental studies and additional exploratory drilling.

Bangladesh

Block 9 - In October 2003 the Company acquired a 60 percent interest in Block 9, a 6,880-square-kilometre onshore block which encompasses the capital city of Dhaka. This field began natural gas production in May 2006 and commerciality was declared in December 2006. The Company and its partner have capital commitments for Phase I exploration, which includes seismic and the drilling of three wells and, in certain circumstances, up to 10 wells. The Company and its partner have completed the seismic and have drilled six wells that apply towards the commitment.

Capital expenditures during the year were $6.6 million. Expenditures were for the drilling and tie-in of the Bangora-5 well, well testing and upgrading the production facilities. Forecast capital spending for fiscal 2009 includes tie-in of the Bangora-3 well, continued work upgrading the facility and continued well testing.

Feni and Chattak - The Feni field covers 43 square kilometres and is located 6 kilometres west of the main natural gas line to Chittagong. The Company has been producing natural gas from the field since November 2004. The Chattak structure covers 376 square kilometres and rights to this block were obtained in October 2003. The upper fault block to the west previously produced from one well, while the down-thrown eastern fault block has not been drilled.

During the year, $2.5 million was spent primarily on carrying costs of the blocks. Future drilling activities at Feni and Chattak have been postponed pending resolution of overdue payment for gas owed to the Company by the Government of Bangladesh.

Thailand

In fiscal 2006 Niko acquired a 50 percent equity stake in a production and exploration block in northern Thailand, which includes a development area, Mae Soon, and an exploration area, Fang.

The Company subsequently performed recompletions on seven existing wells, resulting in little or no fluid production, and drilled four unsuccessful exploration wells. As a result, the Company exited Thailand during the year, resulting in a write-down of $26.1 million.

Pakistan

The four new PSAs were signed in March 2008 and a contract has been awarded to conduct a 3,200 square kilometer 3D seismic program to commence acquisition in late calendar 2008. Forecast capital expenditures for fiscal 2009 are for seismic acquisition.

Kurdistan

Since signing the PSC for the Qara Dagh block in May 2008, field scouting began and a tender for a 500 kilometre 2D seismic program will be issued with acquisition expected to commence in the third quarter of calendar 2008. Forecast capital expenditures for fiscal 2008 include the 2D seismic program, drilling an exploration well and various bonuses required as per the PSC.



RESULTS OF OPERATIONS

Revenue and Operating Income

Year ended March 31, 2008
(thousands of dollars,
except daily production) India Bangladesh All Other Total
----------------------------------------------------------------------------
Oil and natural gas revenue 58,847 44,517 861 104,225
Pipeline revenue 666 - - 666
Royalties (5,072) - (123) (5,195)
Profit petroleum (10,576) (14,670) - (25,246)
Operating and pipeline expenses (6,688) (4,144) (195) (11,027)
----------------------------------------------------------------------------
Net operating income (1) 37,177 25,703 543 63,423
Daily production (Mcfe/d) 32,487 50,164 203 82,854
----------------------------------------------------------------------------
(1) Net operating income is a non-GAAP measure as calculated above.

Year ended March 31, 2007
(thousands of dollars,
except daily production) India Bangladesh All Other Total
----------------------------------------------------------------------------
Oil and natural gas revenue 72,696 42,029 761 115,486
Pipeline revenue 777 - - 777
Royalties (6,602) - (102) (6,704)
Profit petroleum (7,892) (12,993) - (20,885)
Operating and pipeline expenses (8,159) (4,103) (227) (12,489)
----------------------------------------------------------------------------
Net operating income (1) 50,820 24,933 432 76,185
Daily production (Mcfe/d) 42,043 46,381 206 88,630
----------------------------------------------------------------------------
(1) Net operating income is a non-GAAP measure as calculated above.


INDIA

Revenue, Royalties and Profit Petroleum

The Indian properties Hazira and Surat generated revenue of $58.8 million in the year, representing approximately 56 percent of the Company's oil and natural gas revenue, compared to $72.7 million or 63 percent in the prior year. Revenue from the sale of natural gas was $51.2 million in the year and $68.7 million in the prior year. Revenue from the sale of oil was $7.6 million in the year and $4.0 million the prior year. Revenue in the current year includes a $1.1 million upward adjustment for previous years' sales, and $4.0 million in the prior year. The two factors affecting revenue are production volumes and price.

Average daily natural gas production in India during the year was 31 MMcf/d compared to 41 MMcf/d in the prior year. Production decreased due to expected natural declines at both the Hazira and Surat properties. Three additional wells were drilled in Surat during the year and are now on production to augment the production in the Surat field.

The average realized natural gas price net of royalties was $4.08/Mcf in the year compared to $4.20/Mcf in the prior year. The net decrease resulted from the changing Canada-U.S. dollar exchange rate, which was partially offset by an increased sales price charged for Hazira and Surat natural gas.

Sales of oil and condensate in the year increased to an average of 220 bbls/d from 206 bbls/d in the prior year. The average price received in the year was $93.69/bbl compared to $53.52/bbl in the prior year. The price increased due to the increasing market price for oil and a $1.1 million upward adjustment with respect to volumes sold in the previous years' as a result of testing of the quality of the oil. The fiscal 2008 average oil and condensate price excluding this adjustment is $80.27/bbl.

Pursuant to the terms of the PSC the Government of India is entitled to a sliding scale share in the profits once the Company has recovered its investment. For Hazira, in the current and prior years, the government was entitled to 25 percent and 20 percent, respectively, of the cash flow, defined as revenue less royalties, operating expenses and capital expenditures. The Company currently does not incur any profit petroleum expense with respect to the Surat field.

Profit petroleum expense in the year increased by $2.7 million from the prior year. The net increase was mainly due to the adverse resolution of a previously disclosed dispute regarding profit petroleum of US$3.7 million (Cdn$4.0 million) partially offset by decreased profit petroleum related to the current year as revenues were lower in the current year than the prior year. The Company calculates and remits profit petroleum expense to the Government of India in accordance with the PSC. The calculation considers revenues, which are the aggregate revenues of the Company and its joint venture partner. The Company's joint venture partner offers a price discount to the contracted prices, reducing the profit petroleum expense. The government indicated that it does not accept the discounted prices in the calculation of profit petroleum and, as a result, the Company paid an additional US$3.7 million (Cdn$4.0 million) related to the profit petroleum expense of prior years.

BANGLADESH

Revenue and Profit Petroleum

Revenues from the Bangladesh properties, Block 9 and Feni, increased to $44.5 million in the current year from $42.0 million in the prior year. The two factors affecting revenue are production volumes and price.

Block 9 production increased year-over-year due to an additional well being put on production, which increased revenues. The increased production from Block 9 was offset by natural declines in production from the Feni field.

The average natural gas price received in the year was $2.35/Mcf compared to $2.43/Mcf in the prior year. A proportionate increase in the higher-priced Block 9 production had the effect of improving revenues; however, this improvement was more than offset by a decrease in realized price due to the strengthening of the Canadian dollar vs. the U.S. dollar, resulting in a net decrease in price.

Pursuant to the terms of the Joint Venture Agreement (JVA) for Feni and the PSC for Block 9, the Government of Bangladesh is entitled to a sliding scale share in the revenue and profit gas, respectively. For the Feni project the government was entitled to 25 percent of the revenue during the current year and 20 percent and 25 percent of revenue in two and ten months of the prior year, respectively. For Block 9, the government's share is based on production levels and whether or not the Company has recovered its investment. In the current and prior years, the government's share was 61 percent of profit gas. Profit gas is calculated as the minimum of (i) 55 percent of revenue for the period and (ii) revenue less operating and capital costs, incurred to date.

The Company does not incur any royalty expense in Bangladesh.

Operating Expenses

Operating expenses decreased to $0.36/Mcfe in the year from $0.39/Mcfe in the prior year.

Operating expenses pertaining to India increased to $0.54/Mcfe in the year from $0.51/Mcfe in the prior year. The reduction in absolute operating expenses was not sufficient to compensate for the decrease in production. In Bangladesh, operating expenses were comparable year-over-year at $0.23/Mcfe in the year and $0.24/Mcfe in the prior year.

Netbacks

The following table outlines the Company's operating, cashflow and earnings netbacks for fiscal 2008 and 2007:



2008 2007
Oil/ Natural Combined Combined
Condensate Gas Total (1:6) Total (1:6)
($/Bbl) ($/Mcf) ($/Mcfe) ($/Mcfe)
----------------------------------------------------------------------------
Oil and natural gas revenue 89.15 3.17 3.44 3.57
Pipeline revenue - 0.02 0.02 0.02
Royalties (4.73) (0.16) (0.17) (0.21)
Profit petroleum (21.33) (0.77) (0.84) (0.65)
Operating and pipeline expense (6.14) (0.35) (0.36) (0.39)
----------------------------------------------------------------------------
Operating netback 56.95 1.91 2.09 2.34
Interest and Other income 0.72 0.14
General and administrative
expense (0.23) (0.19)
Interest and financing on debt - (0.05)
Realized foreign exchange gain
(loss) (0.01) 0.07
Current tax expense (0.06) (0.32)
----------------------------------------------------------------------------
Funds from operations netback 2.51 1.99
Unrealized foreign exchange
(loss) (0.28) (0.01)
Unrealized gain on short-term
investments 0.05 -
Amortization of debt set-up
costs - (0.02)
Gain (loss) on risk management
activities (0.07) -
Discount of long-term account
receivable (0.15) -
Stock-based compensation
expense (0.57) (0.57)
Asset impairment (0.88) -
Depletion, depreciation and
accretion expense (1.38) (2.37)
----------------------------------------------------------------------------
Earnings netback (0.77) (0.98)
----------------------------------------------------------------------------


Oil and condensate netbacks are calculated by dividing the revenue and costs related to oil and condensate production by the total oil and condensate production for the Company, measured in barrels. The natural gas netbacks are calculated by dividing the revenue and costs related to natural gas production in India and Bangladesh by the volume of natural gas production in India and Bangladesh, measured in Mcf. The combined average netback is calculated by dividing the revenue and costs in total for the Company by the total production of the Company measured in Mcfe.

The following tables outline the Company's operating netbacks by country for the years ended March 31, 2008 and 2007:



Year ended
March 31, 2008 India Bangladesh Other
----------------------------------------------------------------------------
Average daily production
Oil and condensate (bbls/d) 220 56 34
Natural gas (Mcf/d) 31,164 49,827 -
----------------------------------------------------------------------------
Total combined (Mcfe/d) 32,487 50,164 203
Revenue, royalties and operating
expenses
Oil and natural gas revenue ($/Mcfe) 4.95 2.42 11.32
Pipeline revenue 0.06 - -
Royalties ($/Mcfe) (0.43) - (1.66)
Profit petroleum ($/Mcfe) (0.89) (0.80) -
Operating and pipeline expenses
($/Mcfe) (0.54) (0.23) (2.62)
----------------------------------------------------------------------------
Operating netback ($/Mcfe) 3.15 1.39 7.04
----------------------------------------------------------------------------

Year ended
March 31, 2007 India Bangladesh Other
----------------------------------------------------------------------------
Average daily production
Oil and condensate (bbls/d) 206 50 34
Natural gas (Mcf/d) 40,807 46,081 -
----------------------------------------------------------------------------
Total combined (Mcfe/d) 42,043 46,381 206
Revenue, royalties and operating
expenses
Oil and natural gas revenue ($/Mcfe) 4.74 2.48 10.12
Pipeline revenue 0.04 - -
Royalties ($/Mcfe) (0.43) - (1.35)
Profit petroleum ($/Mcfe) (0.51) (0.77) -
Operating and pipeline expenses
($/Mcfe) (0.51) (0.24) (3.02)
----------------------------------------------------------------------------
Operating netback ($/Mcfe) 3.33 1.47 5.75
----------------------------------------------------------------------------


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

CORPORATE

Interest and Other Income

The Company earned interest income of $21.2 million in the year (fiscal 2007 - $4.2 million). The increase is due to higher average cash balances in the year. Other income includes an unrealized gain on short-term investments of $1.4 million (fiscal 2007 - nil), pipeline revenue of $0.7 million (2007 - $0.8 million) and proceeds on the sale of inventory of $0.6 million (fiscal 2007 - nil).

Interest and Financing Expense

The Company did not expense any interest during the year. The $13.5 million of interest and financing costs incurred during the year on the long-term debt were capitalized as a cost of the development of the D6 block. The charge of $2.4 million in the prior year related to interest expense and the amortization of the remaining debt issue costs associated with the Company's previous loan, which was repaid in October 2006.

General and Administrative (G&A) Expense

The Company incurred G&A costs of $7.1 million in the year compared to $6.2 million in the prior year. G&A expenses increased primarily as a result of increased fees for outside services due to expanding operations of the Company.

Foreign Exchange

The Company recorded a foreign exchange loss of $8.6 million in the year compared to a foreign exchange gain of $2.0 million in the prior year. The loss in the year is comprised of net unrealized losses of $8.4 million on the translation of U.S. dollar held cash and the translation of the Indian rupee-denominated long-term income tax receivable and net realized losses of $0.2 million on the translation of Indian rupee-denominated working capital. This is compared to a net unrealized loss of $0.3 million and a net realized gain of $2.4 million in the prior year. The net realized gain in the prior year was primarily a result of gains on the U.S. dollar denominated accounts payable and long-term debt.

In the quarter ended March 31, 2007, the Company began using the current-rate method as opposed to the temporal method to translate the accounts of its foreign operations to Canadian dollars, the effect of which is recognized in other comprehensive income. As a result, there was a foreign exchange gain in the prior year with no corresponding gain or loss on the income statement in the current year from the translation of the results of foreign operations to Canadian dollars.

Loss on Risk Management Activities

As required by the credit facility, the Company has entered into a series of interest rate swaps to fix the floating rate on a portion of the long-term debt. There was an unrealized loss of $2.1 million on the recognition of the fair value of the Company's interest rate swaps due to the decrease in forecast LIBOR rates during the period.

Discount of Long-term Account Receivable

A discount of $4.6 million was recognized in the year on the long-term account receivable to reflect the potential delay in collection of the receivable as it may not be collected until resolution of various claims related to the Chattak property that have been raised against the Company.

Stock-based Compensation

Stock-based compensation expense decreased to $17.3 million in the year from $18.5 million in the prior year. The net decrease is attributable to fewer options being expensed in the current year as some of the options issued have a one-year life and were fully expensed in the prior year, partially offset by new options issued in the year.

Asset Impairment

There was a write-off of $26.1 million including $3.3 million of other comprehensive income recognized in the year related to the unsuccessful wells, workovers and associated costs in Thailand.

There was a write-off of $0.7 million of costs previously capitalized related to the evaluation of a potential new venture with which the Company decided not to proceed.

Depletion, Depreciation and Accretion

There was a $35.0 million decrease in depletion, depreciation and accretion expense in the current year from the prior year.

Depletion in India decreased by $33.1 million or $1.72/Mcfe of production. The decrease was primarily a result of a foreign currency translation adjustment and the increase in estimated reserves in the fourth quarter of fiscal 2007. Depletion in Bangladesh decreased by $2.2 million or $0.21/Mcfe of production. There was a decrease in the depletion rate due to the increase in the reserves for Block 9 in the prior year.

Accretion expense increased to $0.6 million in the current year from $0.5 million in the prior year. The increase was a result of the asset retirement obligation recorded during the year.

Income Taxes

The Company's overall tax provision in the year was a current income tax expense of $1.9 million compared to a current income tax expense of $10.3 million in the prior year. The current year's net income tax expense is comprised of a net income tax recovery recognized in India of $1.3 million, an income tax expense in Canada of $1.6 million and an income tax expense in Bangladesh of $1.6 million.

In India, the Company recognized a net income tax recovery of $1.3 million compared to an income tax expense in the prior year of $9.9 million. The net income tax recovery occurred mainly as a result of the initial recognition of a tax holiday for Surat and a favourable ruling from the Indian Income Tax Appellate Tribunal.

Part of the net income tax recovery is attributable to preparing the fiscal 2007 tax filing and applying the tax holiday deduction for Surat in re-estimating the current year's income. The fiscal 2007 tax filing was prepared recognizing the tax holiday for the eligible undertaking in Surat. One undertaking became eligible for the tax holiday in fiscal 2007 resulting in a reduction of $4.2 million to reported fiscal 2007 income taxes, all of which was recognized in the current year.

The Company received a favourable ruling from the Income Tax Appellate Tribunal, the third tax assessment level of the Income Tax Department, with respect to the tax holiday for the 1999 through 2004 taxation years. The Company had calculated and recorded income taxes on this basis. However, the ruling also indicated the rates at which tax pools may be claimed in arriving at taxable income, which were different from the manner in which the Company had calculated and recorded income taxes. As a result, the Company recognized an income tax recovery of $2.0 million as a result of the ruling.

Income tax expense related to the current year in India, excluding the two income tax recoveries was $4.9 million compared to $9.9 million in the prior year. The expense decreased due to recognition of the Surat tax holiday deduction for current-year's production with no Surat tax holiday deduction recognized in the prior year and lower revenues.

The Canadian taxes increased to $1.6 million in the year, which was related to income tax on the interest earned from cash balances outstanding during the year.

For the Feni field, the Company pays tax at a rate of 4 percent of net revenues, defined as revenue less the government's share of profit petroleum as per a ruling by the Bangladesh National Board of Revenue in 2004 qualifying the Company for this specific clause in the income tax rules. Bangladeshi taxes on revenue in the current year decreased by $0.2 million from the prior year as production was lower during the year, generating lower revenues. In March 2008, the Company received a tax assessment for Taka 101,429,192 (Cdn $1.5 million) related to the Feni and Chattak fields in Bangladesh for fiscal 2006. The tax assessment is for tax on the foreign exchange gain reported in the financial statements of the Bangladesh subsidiary. The Company appealed the tax assessment to tax authorities and lost the appeal. As a result, the Company recorded tax expense as assessed of $1.5 million. The Company is in the process of appealing the decision of the Tax Appellate at the Tribunal level.

The Company does not pay income taxes related to Block 9 production, as indicated in the PSC. The PSC indicates that the calculation or profit petroleum expense includes consideration of income taxes and, therefore, no income tax is assessed for Block 9.

The Company has a contingency related to income taxes as at March 31, 2008. Refer to the audited consolidated financial statements and notes for the year for a complete discussion of the contingency.

SUMMARY OF QUARTERLY RESULTS

The following tables set forth selected financial information of the Company for the eight most recently completed quarters to March 31, 2008:



Three months ended
(thousands of dollars, except per June 30, Sept. 30, Dec. 31, March 31,
share amounts) 2007 2007 2007 2008
----------------------------------------------------------------------------
Petroleum and natural gas revenue 27,952 28,763 23,183 24,327
Net income (loss) (6,168) (19,387) 557 1,584
Per share
Basic ($) (0.14) (0.43) 0.01 0.03
Diluted ($) (0.14) (0.43) 0.01 0.03
----------------------------------------------------------------------------


Three months ended
(thousands of dollars, except per June 30, Sept. 30, Dec. 31, March 31,
share amounts) 2006 2006 2006 2007
----------------------------------------------------------------------------
Petroleum and natural gas revenue 29,627 28,129 28,637 29,093
Net (loss) (11,627) (11,117) (5,765) (3,128)
Per share
Basic ($) (0.30) (0.28) (0.14) (0.08)
Diluted ($) (0.30) (0.28) (0.14) (0.08)
----------------------------------------------------------------------------


Net income has fluctuated over the quarters, due in part to changes in net revenue, profit petroleum, interest income, foreign exchange, stock-based compensation expense, asset impairment, discount on the long-term account receivable, depletion and income taxes.

There were forecast natural declines in production at Hazira and Feni in fiscal 2007 continuing in fiscal 2008, which were partially offset by increases in production from Block 9, both of which affected revenue. Revenue decreased in the quarter ended June 30, 2007 due to a decrease in production and an increase in the proportion of sales from Block 9, which has a lower price than the other producing properties. In the quarter ended December 31, 2007, there was a planned pressure survey in Block 9 resulting in decreased volumes in addition to the continued natural declines in the Hazira and Feni fields.

In the quarter ended June 30, 2007, there was an adjustment to profit petroleum of US$3.7 million (Cdn$4.0 million) of additional expense related to amounts recorded in prior years, increasing the net loss during that quarter.

Interest income increased in the quarters ended September 30 and December 31, 2007 and again in the quarter ended March 31, 2008 due to higher average cash balances in the quarters.

In the quarter ended December 31, 2006, the net loss was positively impacted by a net foreign exchange gain of $4.3 million on the U.S. dollar held cash due to the strong U.S. dollar compared to the Canadian dollar for most of that quarter. In the quarters ended June 30 and September 30, 2007, there were net foreign exchange losses of $4.0 million and $5.3 million, respectively, due to the strengthening Canadian dollar compared to the U.S. dollar applied to U.S. denominated working capital amounts.

There was an asset impairment of $26.0 million recognized in the quarter ended September 30, 2007 as a result of unsuccessful wells, workovers and associated costs in Thailand.

In the quarter ended December 31, 2007, net income was reduced by $4.5 million for a discount of a long-term account receivable to reflect the potential delay in collection as the account receivable may not be collected until resolution of various claims raised against the Company.

In the quarter ended March 31, 2008, the Company recognized an expense of $2.1 million related to the change in fair value of the Company's interest rate swaps.

Depletion expense decreased in the quarter ended March 31, 2007 with the addition of reserves, primarily from Block 9 and the foreign currency translation adjustment recognized in the quarter.

In the quarter ended September 30, 2007, there was an income tax recovery of $4.2 million related to the recalculation of prior years' tax filings and the current year's estimate of Surat income taxes applying the tax holiday deduction, which had a positive effect on the net loss.

FOURTH QUARTER

Net income in the quarter ended March 31, 2008 increased to $1.6 million from a net loss of $3.1 million in the same period in the prior year, for a total increase of $4.7 million. The main causes of the increase are from interest and other income and decreased income taxes, which were partially offset by a decrease in net revenues and a fair value loss on the Company's interest rate swaps. There was a decrease in net revenues of $4.4 million as additional production from Block 9 was more than offset by production declines in Hazira, Surat and Feni. Interest and other income increased by $6.5 million primarily as a result of interest earned on higher cash balances. Income tax expense decreased to $0.1 million in the fourth quarter from $4.2 million in the prior year's quarter. There was an income tax recovery of $2.0 million as a result of the application of a ruling received from the Indian Income Tax Appellate Tribunal to the prior years' income tax calculations more than offset by income taxes including additional tax assessed for the fiscal 2006 year related to Bangladesh.

The Company had working capital as at March 31, 2008 of $495.1 million, which included $456.3 million of cash and cash equivalents. The net increase in working capital from the quarter ended December 31, 2007 was a result of increased cash balances.

Capital expenditures were $109.4 million during the fourth quarter. Significant capital expenditures in the quarter were $101.3 million on the D6 property, primarily related to the development of the oil and gas fields, $2.5 million in Surat for drilling three new wells and $3.0 million at NEC-25 for exploration drilling. The remaining spending was for the other properties and new ventures.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity and Capital Resources

At March 31, 2008, the Company had working capital of $495.1 million, which included $456.3 million of unrestricted cash and cash equivalents.

The restricted cash balance at March 31, 2008 was comprised of US$111.5 million of cash restricted in accordance with the facility agreement, US$16.4 million of performance guarantees and US$2.1 million of cash restricted for future site restoration. At March 31, 2008, the Company had provided performance guarantees to the governments of India and Bangladesh totalling US$8.7 million and US$7.7 million, respectively. The guarantee to the Government of Bangladesh was subsequently reduced to US$5.3 million. The guarantees to the Government of India were subsequently amended resulting in a net reduction to US$5.6 million.

In November 2007, the Company executed the facility agreement for its US$550 million credit facility. The facility was being used to fund 65 percent of the Company's share in D6 natural gas development and, upon completion of the D6 block development, may be used for other projects. The Company has drawn US$192.8 million on the loan and is currently prevented from drawing further amounts because the Company is unable to meet one of the conditions precedent to borrowing additional funds. The Company expects that this condition precedent will be fulfilled once the lenders have adopted projections based on the March 31, 2008 reserve reports and following this, the Company expects to borrow additional funds.

Repayment of the outstanding debt amounts is based on certain financial ratios as determined in accordance with the facility agreement, with the outstanding debt amount not to exceed a reduction schedule. The financial ratios are based on the future cash flows from producing properties determined in accordance with the facility agreement. Failure to meet these ratios will trigger early payment of a part or the entire long-term debt balance. There are a number of other items in the facility agreement that could trigger early payment of a part of the entire balance of long-term debt including, but not limited to: the inability of the Company to complete project completion as defined in the facility agreement prior to a specified date; the Company not having sufficient funds to complete the project; the Company not having gas sales contract for a quantity sufficient to support future cash flows required to meet the financial ratios and compliance with various information and other requirements specified in the facility agreement.

The Company has planned capital expenditures of $507 million to $536 million for fiscal 2009. The Company plans to meet planned capital expenditures with cash on hand, cash from operations and long-term debt.

Based on the cash requirements and cash sources described above, the Company expects its funds will be sufficient to meet its fiscal 2009 working capital requirements and planned capital expenditures.

The Company has a number of contingencies as at March 31, 2008. Refer to the audited consolidated financial statements and notes for the year for a complete list of the contingencies and any potential effects on the liquidity of the Company.

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

The Company has work commitments under its various performance guarantees as at March 31, 2008. The Company and its partner have work commitments for Phase I exploration as per the PSC signed for the D4 Block for seismic and drilling three exploration wells, which must be expended by September 2009. The cost of the work commitment is estimated at US$97.6 million (US$14.6 million net to the Company). The Cauvery block has a PSC Phase I three year commitment for seismic and drilling five exploration wells. The Company has completed the seismic and drilled two exploration wells. The cost remaining to complete the work commitment is estimated at US$7.5 million. The Company and its partner have work commitments for Phase II exploration for seismic and two exploration wells as per the PSC for the NEC-25 Block and have drilled a sufficient number of wells to meet the commitment. The Company and its partner have work commitments for Phase I exploration as per the PSC signed for Block 9 to conduct seismic and drill three wells and, in certain circumstances, up to 10 wells. The Company and its partner have completed the seismic and drilled six wells that apply towards the commitment. The Company has minimum work commitments under Phase I of the initial term and other requirements for the Pakistan blocks of US$8.6 million, which must be spent within 2 years of signing the PSAs The Company and its partners have minimum commitments of US$16.0 million (US$7.2 million net to the Company) related to seismic and drilling one exploratory well in Kurdistan Region, which must be spent within three years of signing the PSC and commitments of US$41.2 million (US$18.5 million net to the Company) for various bonuses and other payments under the agreement. The Company expects to meet these commitments from cash on hand and funds from operations. Although not committed, the Company has planned capital spending of $261 million (net to the Company) and $110 million (net to the Company) required to bring the Dhirubhai 1 and 3 gas fields and the MA Oil field, respectively, on production and these costs are included in the capital forecast for fiscal 2008.



Contractual Obligations

Payment Due by Period
As at March 31, 2008 Less than 1 - 3 4 - 5 After 5
(thousands of U.S. dollars) Total 1 year Years Years Years
----------------------------------------------------------------------------
Principal repayments
on long-term debt (1) 192,814 - 119,817 72,997 -
Guarantees(2) 16,407 8,757 7,650 - -
Work commitments(3) 34,278 28,378 5,900 - -
Asset retirement obligations(4) 14,434 - 5,637 1,516 7,281
----------------------------------------------------------------------------
Total contractual obligations 257,933 37,135 139,004 74,513 7,281
----------------------------------------------------------------------------

1 There are no portions of debt due within the year, therefore the entire
debt is classified as long-term.
2 The guarantees were amended subsequent to March 31, 2008. As at June 24,
2008, the guarantees for commitments less than one year were $10.9 million
and no amounts thereafter.
3 Includes work commitments for Pakistan blocks for which the company
provides a parent guarantee instead of a bank guarantee and for the
Company's interest in the block in the Kurdistan Region of Iraq.
4 Asset retirement obligations are based on the undiscounted estimated
future liability of the Company as disclosed in the notes to the
consolidated financial statements as at March 31, 2008 . It does not
include wells or facilities that are not complete as at March 31, 2008.


Related Parties

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

FINANCIAL INSTRUMENTS

Financial instruments of the Company consist of short-term investments, accounts receivable, accounts payable and accrued liabilities, long-term accounts receivable, long-term debt and interest rate swaps. As at March 31, 2008 and March 31, 2007, there were no significant differences between the carrying amounts of these instruments and the fair values.

The Company is exposed to fluctuations in the value of accounts receivable, long-term account receivable, accounts payable and accrued liabilities, interest rate swaps and long-term debt due to changes in foreign exchange rates as these financial instruments are primarily U.S.-dollar-denominated. This risk is reduced because a portion of the Company's revenues and expenses is denominated in U.S. dollars. The Company further manages the risk by converting Canadian held cash to U.S. dollars as required to fund forecast expenditures.

The Company is exposed to changes in the market value of short-term investments. The Company monitors the market value of marketable securities on a regular basis. An unrealized gain on the recognition of the short-term investments at fair value of $1.4 million was recorded in other income.

Financial instruments that potentially subject the Company to concentrations of credit risk consist of money market and short-term deposits, accounts receivable and long-term accounts receivable. The Company has deposited the cash equivalents with reputable financial institutions, from which management believes the risk of loss to be remote.

The Company has accounts receivable from clients engaged in various industries that are concentrated in a specific geographic area in India and with a specific customer in Bangladesh. The Company takes measures in order to mitigate any risk of loss which may include obtaining guarantees. The specific industries or government may be affected by economic factors that may impact accounts receivable.

The long-term account receivable for gas sales charged to Petrobangla for production from the Feni field has been discounted to $21.4 million as at March 31, 2008 to reflect the potential delay in collection of these amounts. A loss of $4.6 million was recognized in income to discount the receivable. The recorded amount of the long-term account receivable has been calculated using a discount rate of 6 percent and assumes collection in three years. The Company has and continues to attempt to collect the receivable through the agreed-upon processes as per the JVA and the gas purchase and sale agreement (GPSA) and any other available legal and political processes.

The book value of the accounts receivable and long-term account receivable reflects management's assessment of the credit risk.

The Company was required to enter into interest rate swaps as per the terms of the facility agreement in order to fix the interest rate on a portion of the outstanding long-term debt. The Company is exposed to changes in the LIBOR rate on the remaining portion of the outstanding long-term debt. The interest rate swaps are recorded at fair value, which is estimated to be a liability of $2.7 million, and are included in accounts payable. Hedge accounting had been applied to the interest rate swaps in the quarter ended December 31, 2007. In the quarter ended March 31, 2008, the hedge ceased to be effective and the change in the fair value of the interest rate swaps for the quarter were expensed. The fair value is provided by a third party using a forward LIBOR curve applied to future settlements.

The Company is exposed to risk of changes in market prices of commodities. The Company enters into physical commodity contracts, which manages this risk. The Company enters into physical commodity contracts in the normal course of business including contracts with fixed terms. The contracts are not classified as financial instruments. The Company expects to deliver all required volumes under the contracts. No amounts are recognized in the consolidated financial statements related to the contracts until such time as the associated volumes are delivered.

CRITICAL ACCOUNTING ESTIMATES

Proved Oil and Natural Gas Reserves, Full Cost Accounting, the Ceiling Test and Depletion Expense

The Company follows the Canadian full cost method of accounting whereby all costs related to the exploration for and development of oil and natural gas reserves are initially capitalized and accumulated in cost centres by country. Costs capitalized include land and acquisition costs, geological and geophysical expenses, costs of drilling productive and non-productive wells, costs of gathering and production facilities and equipment, and administrative costs related to capital projects. Gains or losses are not recognized upon disposition of oil and natural gas properties unless such disposition would alter the depletion rate by 20 percent or more.

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 cost 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.

Independent qualified engineers in conjunction with the Company's reserve engineers estimate the value of oil and natural gas reserves that are used in the depletion and depreciation as well as the ceiling test calculations. This estimation is performed in accordance with the standards set forth in the Canadian Oil and Gas Evaluation Handbook.

The amounts recorded for depletion of exploration and development costs and the carrying value of property and equipment are based on estimates of proved (and in certain circumstances proved plus probable) 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 and future cash flows, used in the depletion calculation and ceiling test, will be revised upwards or downwards over time, based on future changes to these variables. Reserve estimates and estimates of future cash flows can have a material impact on the depletion expense and the carrying value of property and equipment. Revisions to reserve estimates and future cash flows could increase or decrease depletion expense charged to net income and could result in a write-down of property and equipment based on the ceiling test.

Costs Excluded from the Depletable Base

Costs of acquiring unproved properties are initially excluded from the full cost pool and are assessed quarterly 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 of major development projects are initially excluded from the full cost pool and are assessed quarterly to ascertain whether impairment has occurred. When a portion of the property becomes capable of commercial production or the property is considered to be impaired, the cost or an appropriate portion of the cost of the property is added to the full cost pool. A change in any of the qualitative considerations for impairment including, but not limited too: geological interpretations; exploration activities and success/failure, the Company's plans with respect to the property and financial ability to hold the property; and the lease term for the property, may result in the inclusion of the property and equipment in the full cost pool, which may result in a significant downwards adjustment to property and equipment and an increase in depletion expense and/or an asset impairment based on the ceiling test resulting in a downwards adjustment to property and equipment and an equivalent expense.

Asset Retirement Obligations

As the Company's assets are retired, significant abandonment and reclamation costs will be incurred. The Company recognizes the fair value of a liability for asset retirement obligations, applicable to all business segments, relating to its long-lived assets in the period in which it is incurred. Specifically, wells are included when they have finished being drilled and facilities are completed and ready for use. The fair value of an asset retirement obligation is recorded as a liability with a corresponding increase in property and equipment. The increase in property and equipment is depleted using the unit-of-production method consistent with the underlying assets. The accretion expense and increases to the asset retirement obligation are recognized each period due to the passage of time. Subsequent to initial measurement, period-to-period changes in the liabilities 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 net income in the period in which settlement occurs.

The obligations are 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 costs to abandon and reclaim, timing of abandonment, inflation rates 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 obligations may result in a material impact to the carrying value of property and equipment, asset retirement obligations 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. In addition, the Company expects that its estimates of total asset retirement obligations will increase with the completion of additional wells and facilities that are being developed. Changes to these estimates in the past have resulted in material adjustments to the financial statements.

Income Taxes

The Company follows the tax asset and liability method to account for income taxes. Under this method, future income tax assets and liabilities are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax assets and liabilities is recognized in income in the period that the change occurs. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.

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

The Company has filed its income tax returns for the years 1998 through 2007 in India, under provisions that provide for a tax holiday for production from the Hazira and Surat fields.

The Company received a favourable ruling with respect to the tax holiday at the third tax assessment level for the 1999 through 2004 taxation years. The Income Tax Department has filed an appeal against the order and the matter is currently pending with the Indian courts. The taxation years 2005 through 2007 have been filed including a deduction for the tax holiday, but have not yet been assessed.

Should the Company fail through the legal process to receive a favourable ruling with respect to the taxation years 1999 through 2004, the Company would record a tax expense of US$39.9 million, pay additional taxes of US$10.7 million and write off US$29.2 million of the income tax receivable.

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 the 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, expected forfeitures and expected life of the option. Changes in these estimates may result in the actual compensation expense being materially different from the compensation expense recognized; however, this expense is not subsequently adjusted for changes in these factors. The Company capitalizes the stock-based compensation expense relating to those employees whose time is spent on exploration activities.

Accrual Accounting

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

Financial Instruments

Financial instruments of the Company consist of short-term investments, accounts receivable, accounts payable and accrued liabilities, long-term accounts receivable, long-term debt and interest rate swaps. As at March 31, 2008 and March 31, 2007, there were no significant differences between the carrying amounts of these instruments and the fair values.

The fair values of the accounts receivable and accounts payable and accrued liabilities approximate their carrying values due to their near-term maturity. Inability by the Company to settle these assets and liabilities in the near term may result in a significant downward or upward adjustment to the fair values and an associated expense.

The fair value of short-term investments is based on publicly quoted market values. The Company expects the market values of the short-term investments to increase or decrease over time and may result in a significant upward or downward adjustment to the fair values and an associated expense.

The fair value of the long-term account receivable has been calculated using a discount rate of 6 percent and assumes collection in three years. A change in the amount of the receivable that is considered collectible, the discount rate or timing of collection may result in a significant downward or upward adjustment to the fair value and an associated income or expense item.

The Company's interest rate swaps are recorded at fair value, which has been provided by a third party using a forward LIBOR curve applied to future settlements. The Company expects changes in the forward LIBOR rates to result in significant downward or upward adjustments to the fair value of the instrument and an associated income or expense item.

Legal, Environmental and Other Contingent Matters

The Company is required to determine whether a loss is likely, unlikely or not determinable based on judgement and interpretations of laws and regulations and, if likely, to determine whether the loss can reasonably be estimated. When the loss is likely and the amount of the loss is determinable, it is charged to net income. The Company monitors known and potential contingent matters and makes appropriate provisions by charges to net income when warranted by circumstances. Changes in factors used to make judgement and interpret laws and regulations may result in the change in likelihood of a contingent matter or allow the Company to determine the amount of the loss of a contingent matter resulting in a significant downward adjustment to a recorded asset or the recognition of a significant liability and associated expense.

ACCOUNTING CHANGES IN FISCAL 2008

Effective April 1, 2007, the Company adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants (CICA): Section 3855 "Financial Instruments - Recognition and Measurement", Section 1530 "Comprehensive Income", Section 3865 "Hedges" and Section 3861 "Financial Instruments - Disclosure and Presentation". The new standards were adopted prospectively. Adoption of these standards did not impact April 1, 2007 opening balances.

FUTURE ACCOUNTING CHANGES

Effective April 1, 2008, the Company adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants (CICA): Section 1535 "Capital Disclosures", Section 3862 "Financial Instruments - Disclosures", Section 3863 "Financial Instruments - Presentation" and Section 3031 "Inventories".

Section 1535 specifies the disclosure of information about an entity's objectives, policies and processes for managing capital; quantitative data about what the entity regards as capital; whether the entity has complied with any externally imposed capital requirements; and if it has not complied, the consequences of non-compliance. This section is expected to result in increased disclosures provided in the Company's financial statements.

Sections 3862 and 3863 specify the standards of presentation and enhanced disclosures on financial instruments, particularly with respect to the nature and extent of risks arising from financial instruments and how the entity manages those risks. This section is expected to have increased disclosures provided in the Company's financial statements.

Section 3031 replaces the existing inventories standard. The new standard provides additional guidance with respect to the measurement and disclosure requirements for inventories, requiring inventories to be valued at the lower of cost and net realizable value. This section is not expected to have a material impact on the Company's net income or financial position.

Effective April 1, 2009, the Company will adopt another new accounting standard issued by the CICA, Section 3064 "Goodwill and Intangible Assets", replacing Sections 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to their initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Company is currently evaluating the impact of the adoption of this new section; however does not expect a material impact on its consolidated financial statements.

Effective April 1, 2011, the Company will replace current Canadian accounting standards and interpretations, or GAAP, with International Financial Reporting Standards (IFRS) as required by the Canadian Accounting Standards Board. The Company is assessing the impact of the conversion and will provide information as required by regulations.

DISCLOSURE CONTROLS AND PROCEDURES

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

INTERNAL CONTROLS OVER FINANCIAL REPORTING

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

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

There were no changes in the internal controls over financial reporting during the year ended March 31, 2008 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

RISKS

In the normal course of business the Company is exposed to a variety of actual and potential events, uncertainties, trends and risks. In addition to the risks associated with critical accounting estimates and financial instruments as disclosed in this MD&A, the Company's commitments as disclosed in this MD&A and actual and expected operating events as disclosed in this MD&A, the Company has identified the following events, uncertainties, trends and risks that could have a material adverse impact on the Company:

- The Company may not be able to find reserves at a reasonable cost, develop reserves on time and at a reasonable cost and sell these reserves for a reasonable profit;

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

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

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

- Changing taxation policies, taxation laws and interpretations thereof;

- Changes in the timing of future debt repayments based on provisions in the agreement;

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

- Changes in foreign exchange rates that in turn change the Company's future recorded revenues as the majority of sales are based in U.S. dollars; and

- Changes in future oil and natural gas prices.

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

The Company has a number of contingencies as at March 31, 2008. Refer to the audited consolidated financial statements for a complete list of the contingencies and any potential effects on the Company.



OUTSTANDING SHARE DATA

At June 24, 2008, the Company had the following outstanding shares:

Number Amount
----------------------------------------------------------------------------
Common shares 49,172,033 $ 1,171,275,000
Preferred shares nil nil
Stock options 3,253,350 -
----------------------------------------------------------------------------


OUTLOOK

D6 oil and natural gas production is expected to start-up in the coming quarter. Volumes are expected to ramp up to a targeted rate of 2.8 Bcf per day of natural gas and 40,000 bbls/d. These events would culminate in a multi-fold increase in Niko's current production and earnings.

Although four new exploration successes were made during the year, drilling activity was largely allocated to development. Confirmed additional rigs becoming available in the coming year will enable the Company to redeploy assets focusing on exploration drilling for both oil and gas.

Niko's goal is to continue to pursue new venture opportunities with the objective of expanding its inventory of high-impact prospective plays.



On behalf of the Board of Directors,

Edward S. Sampson

Chairman of the Board, President
and Chief Executive Officer
June 24, 2008


MANAGEMENT'S REPORT

All information in this Annual Report is the responsibility of the management of Niko Resources Ltd. The consolidated financial statements necessarily include amounts that are based on estimates, which have been objectively developed by management using all relevant information. The financial information contained elsewhere in this report has been reviewed to ensure consistency with the consolidated financial statements.

Management maintains and evaluates the effectiveness of disclosure controls and procedures and maintains internal control over financial reporting for Niko Resources Ltd. Disclosure controls and procedures are designed to provide reasonable assurance that material information relating to Niko Resources Ltd., including its consolidated subsidiaries, is made known to management by others within those entities. Internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with Canadian generally accepted accounting principles.

The Audit Committee of the Board of Directors, comprised of non-management directors, has reviewed the consolidated financial statements with management and the auditors. The consolidated financial statements have been approved by the Board of Directors on the recommendation of the Audit Committee.

The consolidated financial statements have been audited by KPMG LLP, the external auditors, in accordance with auditing standards generally accepted in Canada on behalf of the shareholders.



Edward S. Sampson Murray Hesje
President and CEO Vice President, Finance and CFO
June 24, 2008


AUDITORS' REPORT

To the Shareholders of Niko Resources Ltd.

We have audited the consolidated balance sheets of Niko Resources Ltd. as at March 31, 2008 and 2007 and the consolidated statements of operations and retained earnings, comprehensive income (loss) and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at March 31, 2008 and 2007 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.



KPMG LLP
Chartered Accountants
Calgary, Canada
June 24, 2008



CONSOLIDATED BALANCE SHEETS

As at March 31, 2008 2007
(thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents $ 456,271 $ 209,370
Short-term investments (note 15) 17,721 -
Accounts receivable 38,982 21,917
Prepaid expenses 2,172 1,577
----------------------------------------------------------------------------
515,146 232,864
Restricted cash (note 3) 133,548 12,201
Long-term accounts receivable (note 4a) 21,432 26,191
Income tax receivable (note 4b) 37,532 24,180
Property and equipment (note 5) 646,265 379,124
----------------------------------------------------------------------------
$ 1,353,923 $ 674,560
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 16,905 $ 29,313
Current tax payable 3,151 1,292
----------------------------------------------------------------------------
20,056 30,605
Asset retirement obligation (note 6) 9,358 8,974
Long-term debt (note 7) 198,194 -
----------------------------------------------------------------------------
227,608 39,579
Shareholders' equity
Share capital (note 8) 1,130,052 603,112
Contributed surplus (note 9) 38,557 26,723
Accumulated other comprehensive income (loss)
(note 10) (85,758) (67,410)
Retained earnings 43,464 72,556
----------------------------------------------------------------------------
(42,294) 5,146
1,126,315 634,981
----------------------------------------------------------------------------
$ 1,353,923 $ 674,560
----------------------------------------------------------------------------

Guarantees (note 16)

Contractual Obligations (note 19)
Contingencies (note 20)

See accompanying Notes to Consolidated Financial Statements.


CONSOLIDATED STATEMENTS of
OPERATIONS and RETAINED EARNINGS

Years ended March 31, 2008 2007
(thousands of dollars, except per share amounts)
Revenue
Oil and natural gas $ 104,225 $ 115,486
Royalties (5,195) (6,704)
Profit petroleum (25,246) (20,885)
Interest and other 23,939 5,154
----------------------------------------------------------------------------
97,723 93,051
----------------------------------------------------------------------------

Expenses
Operating and pipeline 11,027 12,489
Interest and financing on debt - 2,379
General and administrative 7,069 6,180
Foreign exchange loss (gain) 8,597 (2,029)
Discount of long-term account receivable 4,575 -
Loss on risk management contracts 2,070 -
Stock-based compensation (note 8) 17,257 18,490
Asset impairment (note 11) 26,788 -
Depletion, depreciation and accretion 41,880 76,882
----------------------------------------------------------------------------
119,263 114,391
Income (loss) before income taxes $ (21,540) $ (21,340)
----------------------------------------------------------------------------

Income tax expense (note 14)
Current 1,874 10,297
----------------------------------------------------------------------------
1,874 10,297
----------------------------------------------------------------------------

Net income (loss) $ (23,414) $ (31,637)

Retained earnings, beginning of year 72,556 109,079
Dividends paid (5,678) (4,886)
----------------------------------------------------------------------------
Retained earnings, end of year $ 43,464 $ 72,556
----------------------------------------------------------------------------
Net income (loss) per share (note 13)
Basic and diluted $ (0.51) $ (0.79)
----------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.


CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME (LOSS)

Years ended March 31, 2008 2007
(thousands of dollars)
----------------------------------------------------------------------------
Net income (loss) $ (23,414) $ (31,637)
Other comprehensive income (loss):
Recognition of fair value of derivative (loss) (540) -
Foreign currency translation (loss) (17,808) (67,410)
----------------------------------------------------------------------------
Comprehensive income (loss) (note 10) $ (41,762) $ (99,047)
----------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.


CONSOLIDATED STATEMENTS of CASH FLOWS

Years ended March 31, 2008 2007
(thousands of dollars)
----------------------------------------------------------------------------
Cash provided by (used in):
Operating activities
Net income (loss) $ (23,414) $ (31,637)
Add items not involving cash
from operations:
Depletion, depreciation
and accretion 41,880 76,882
Asset impairment (note 11) 26,788 -
Unrealized foreign exchange loss 8,391 334
Unrealized (gain) on short-term investments (1,421)
Amortization of debt set-up costs - 768
Discount of long-term account receivable 4,575 -
Unrealized loss on risk management contracts 2,070 -
Stock-based compensation (note 8) 17,257 18,490
Change in non-cash working capital 1,992 959
Change in long-term accounts receivable (16,580) (17,075)
----------------------------------------------------------------------------
61,538 48,721
----------------------------------------------------------------------------

Financing activities
Proceeds from issuance of shares,
net of issuance costs (note 8) 519,308 304,777
Long-term debt 193,113 (27,478)
Dividends paid (5,678) (4,886)
----------------------------------------------------------------------------
706,743 272,413
----------------------------------------------------------------------------

Investing activities
Addition of property and equipment (344,131) (134,766)
Disposition of property and equipment - 6,360
Restricted cash contributions (163,468) (13,580)
Restricted cash returned 44,203 16,769
Addition to short-term investments (16,300) -
Change in non-cash working capital (33,008) (23,930)
----------------------------------------------------------------------------
(512,704) (149,147)
----------------------------------------------------------------------------
Increase in cash 255,577 171,987

Effect of translation on foreign currency
cash and cash equivalents (8,676) (1,814)
Cash and cash equivalents,
beginning of year 209,370 39,197
----------------------------------------------------------------------------
Cash and cash equivalents,
end of year $ 456,271 $ 209,370
----------------------------------------------------------------------------

Supplemental information:
Interest paid $ 2,106 $ 1,487
Taxes paid $ 13,800 $ 16,363
----------------------------------------------------------------------------

See accompanying Notes to Consolidated Financial Statements.


NOTES to CONSOLIDATED FINANCIAL STATEMENTS

All tabular amounts are in thousands of dollars except per share amounts, numbers of shares/stock options, stock option and share prices, and certain other figures as indicated.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Basis of Presentation

The consolidated financial statements include the accounts of Niko Resources Ltd. ("the Company") and all of its subsidiaries. Substantially all of the exploration and production activities of the Company are conducted jointly with others and, accordingly, these consolidated financial statements reflect only the Company's proportionate interest in such activities.
The functional currency of the Company's foreign subsidiaries is the U.S. dollar. These consolidated financial statements are reported in Canadian dollars.

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

(b) Cash and Cash Equivalents

Cash and cash equivalents consist of cash and demand deposits.

(c) Short-Term Investments

Short-term investments consist of marketable securities.

(d) Property and Equipment

The Company follows the Canadian full cost method of accounting whereby all costs related to the exploration for and development of oil and natural gas reserves are initially capitalized and accumulated in cost centres by country. Costs capitalized include land and acquisition costs, geological and geophysical expenses, costs of drilling productive and non-productive wells, costs of gathering and production facilities and equipment, and administrative costs related to capital projects. Gains or losses are not recognized upon disposition of oil and natural gas properties unless such disposition would alter the depletion rate by 20 percent or more.

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 cost 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.

(e) Capitalized Interest

Interest costs on major capital projects are capitalized until the projects are capable of commercial production. These costs are subsequently amortized with the related assets.

(f) Asset Retirement Obligations

The Company recognizes the fair value of the liabilities for asset retirement obligations relating to its long-lived assets in the period in which they are incurred. The fair value of an asset retirement obligation is recorded as a liability with a corresponding increase in property and equipment. The increase in property and equipment is depleted using the unit-of-production method consistent with the underlying assets. The accretion expense and increases to the asset retirement obligations are recognized each period due to the passage of time. Subsequent to initial measurement, period-to-period changes in the liabilities are recognized for revisions to either the timing or the amount of the original estimates of undiscounted cash flows. Actual costs incurred upon settlement are charged against the asset retirement obligations. Any difference between the actual cost and the recorded liability is recognized as a gain or loss in net income in the period in which settlement occurs.

(g) Comprehensive Income

Comprehensive income consists of net income and other comprehensive income (OCI). OCI comprises the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge, the change in fair value of any available-for-sale financial instruments and foreign exchange gains or losses arising from the translation of foreign operations using the current rate method to Canadian dollars. Amounts included in the OCI are shown net of tax. Accumulated other comprehensive income is a new equity category comprised of the cumulative amounts of OCI.

(h) Revenue Recognition

Sales of crude oil, natural gas and natural gas liquids are recorded in the period in which the title to the petroleum transfers to the customer. Crude oil and natural gas liquids produced, but unsold, are recorded as accounts receivable until sold.

(i) Depletion and Depreciation

Costs of acquiring unproved properties are initially excluded from the full cost pool and are assessed quarterly 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 of major development projects are initially excluded from the full cost pool and are assessed quarterly to ascertain whether impairment has occurred. When a portion of the property becomes capable of commercial production or the property is considered to be impaired, the cost or an appropriate portion of the cost of the property is added to the full cost pool.

Costs capitalized are depleted using the unit-of-production method by cost centre based upon gross proved oil and natural gas reserves as determined by independent engineers. For purposes of the calculation, oil and natural gas reserves are converted to a common unit of measure on the basis of their relative energy content.

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

(j) Foreign Currency

The Company's foreign operations have the U.S. dollar as their functional currency and, as the Company reports its results in Canadian dollars, it therefore uses the current rate method of foreign currency translation. Under the current rate method, accounts are translated to Canadian dollars from their U.S. dollar functional currency as follows: assets and liabilities are translated at the exchange rate in effect at the balance sheet date, and revenues and expenses are translated at the average exchange rate for the period. Gains and losses resulting from the translation of foreign operations to Canadian dollars are included in the foreign currency translation account within other comprehensive income (loss).

Transactions in foreign currencies, other than the U.S. dollar, are translated at rates in effect at the time of the transaction and any resulting gains and losses are included in net income.

(k) Income Taxes

The Company follows the tax asset and liability method to account for income taxes. Under this method, future income tax assets and liabilities are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax assets and liabilities is recognized in income in the period that the change occurs. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.

(l) Measurement Uncertainty

The preparation of the consolidated 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. By their nature, these estimates are subject to measurement uncertainty and actual results may differ from those estimates.

The most significant estimates made by management relate to amounts recorded for the depletion of capital assets, the provision for the asset retirement obligation, accretion expense, the ceiling test, stock-based compensation expense and the fair value of long-term accounts receivable. The ceiling test calculation and the provisions for depletion and asset retirement obligation are based on such factors as estimated proved reserves, production rates, petroleum and natural gas prices and future costs. Stock-based compensation is based on such factors as the risk-free interest rate, volatility, expected life, expected dividends and expected forfeiture rates. The fair value of the long-term account receivable is based on a discount rate and timing of collection. Future events could result in material changes to the carrying values recognized in the financial statements.

(m) Per Share Amounts

Basic earnings per share are computed by dividing net income 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 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 any other dilutive instruments.

(n) Stock-based Compensation Plans

The Company has a stock-based compensation plan as described in note 8. Compensation expense associated with the plan is calculated and recognized in net income or capitalized 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 the 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.

(o) Financial Instruments

All financial instruments must be initially recognized at fair value on the balance sheet date. The Company has classified each financial instrument into the following categories: held for trading financial assets and liabilities, loans or receivables; held to maturity investments; available-for-sale financial assets; and other financial liabilities. Subsequent measurement of the financial instruments is based on their classification.

Transaction costs on financial assets and financial liabilities classified other than as held for trading are added to the fair value upon initial recognition.

Unrealized gains and losses on held for trading financial instruments are recognized in net income.

Gains and losses on available-for-sale financial assets are recognized in other comprehensive income and transferred to net income when the asset is derecognized. The other categories of financial instruments are recognized at cost using the effective interest rate method.

Upon adoption of these new standards, the Company designated its accounts receivable as loans and receivables, which are measured at amortized cost. Upon initial recognition, the Company elected to designate short-term investments as held for trading. The Company accounts for regular-way purchases and sales of financial assets at the trade date.

Long-term debt, accounts payable and accrued liabilities are classified as other financial liabilities which are measured at amortized cost. The Company had no available-for-sale financial instruments.

Hedges:

The Company may enter into derivative instrument contracts to manage its commodity price exposure, foreign exchange exposure and interest rate exposure. The Company does not enter into derivative instrument contracts for trading or speculative purposes. The Company may choose to designate derivative instruments as hedges. Hedge accounting continues to be optional.

Hedge accounting requires the designation of a hedging relationship, including a hedged and a hedging item, identification of the risk exposure being hedged and reasonable assurance that the hedging relationship will be effective throughout its term. In addition, in the case of anticipated transactions, it must also be probable that the transaction designated as being hedged will occur.

The Company assesses, both at inception and over the term of the hedging relationship, whether the derivative contracts used in the hedging transactions are highly effective in offsetting changes in the fair value or cash flows of hedged items. If a derivative contract ceases to be effective or is terminated, hedge accounting is discontinued. Any gains or losses previously recognized in other comprehensive income as a result of applying hedge accounting continue to be carried forward to be recognized in net income in the same period as the hedged item.

For cash flow hedges, changes in the fair value of a financial instrument designated as a cash flow hedge are recognized in net income in the same period as the hedged item. The effective portion of any fair value change in the financial instrument before that period is recognized in other comprehensive income and the ineffective portion of any fair value change is recognized during the period of change in net income.

For fair value hedges, both the financial instrument designated as a fair value hedge and the underlying commitment are recognized on the balance sheet at fair value. Changes in fair value of both are reflected according to their nature, typically in net income.

For net investment hedges, the portion of the gain or loss on the hedging item that is determined to be an effective hedge is recognized in other comprehensive income and the ineffective portion of the gain or loss on the hedging item is recognized in net income.

The Company enters into physical commodity contracts in the normal course of business including contracts with fixed terms. The Company expects to deliver all required volumes under the contracts. No amounts are recognized in the consolidated financial statements related to the contracts until such time as the associated volumes are delivered.

2. CHANGES IN ACCOUNTING POLICIES

(a) During the quarter ended March 31, 2007, the Company changed the method by which its foreign operations are translated to Canadian dollars due to a change in the Company's foreign operations' functional currency. The Company's foreign operations' functional currency changed from the Canadian dollar to the U.S. dollar as a result of the increased significance of the U.S. dollar to the foreign operations' cash flows. Amongst other things, this increased significance of the U.S. dollar was as a result of the decision to proceed with a U.S.-dollar-based credit facility and an increased proportion of revenues being earned in U.S. dollars.

Effective January 1, 2007, the Company began translating the accounts of its foreign operations to Canadian dollars using the current rate method, whereas previously it had used the temporal method.

Under the current rate method, accounts are translated to Canadian dollars as follows: assets and liabilities are translated at the exchange rate in effect at the balance sheet date, and revenues and expenses are translated at the average exchange rate for the period. Gains and losses resulting from the translation of foreign operations to Canadian dollars are included in the foreign currency translation account within other comprehensive income (loss).

Under the temporal method, accounts were translated to Canadian dollars as follows: monetary assets and liabilities were translated at the period-end exchange rate, non-monetary assets and liabilities were translated using historical exchange rates, and revenues and expenses were translated using the average exchange rate for the period. Gains and losses resulting from the translation of foreign operations to Canadian dollars were included in net income for the period.

This change was adopted prospectively on January 1, 2007 and resulted in a foreign currency translation adjustment of $67.3 million with a corresponding decrease in property and equipment. An additional credit of $0.1 million was recorded to the foreign currency translation account for the activity during the quarter ended March 31, 2007.

(b) Effective April 1, 2007 the Company adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants (CICA): Section 3855 "Financial Instruments - Recognition and Measurement", Section 1530 "Comprehensive Income", Section 3865 "Hedges" and Section 3861 "Financial Instruments - Disclosure and Presentation" as described in Note 1(o). These new standards were adopted prospectively. Adoption of these standards did not impact April 1, 2007 opening balances.

(c) Future Accounting Changes

Effective April 1, 2008, the Company will adopt the following new accounting standards issued by the CICA: Section 1535 "Capital Disclosures", Section 3862 "Financial Instruments - Disclosures", Section 3863 "Financial Instruments - Presentation" and Section 3031 "Inventories".

Section 1535 specifies the disclosure of information about an entity's objectives, policies and processes for managing capital; quantitative data about what the entity regards as capital; whether the entity has complied with any externally imposed capital requirements; and if it has not complied, the consequences of non-compliance. This section is expected to have increased disclosures provided in the Company's financial statements.

Sections 3862 and 3863 specify the standards of presentation and enhanced disclosures on financial instruments, particularly with respect to the nature and extent of risks arising from financial instruments and how the entity manages those risks. This section is expected to have increased disclosures provided in the Company's financial statements.

Section 3031 replaces the existing inventories standard. The new standard provides additional guidance with respect to the measurement and disclosure requirements for inventories, requiring inventories to be valued at the lower of cost and net realizable value. This section is not expected to have a material impact on the Company's net income or financial position.

Effective April 1, 2009, the Company will adopt the new accounting standard, Section 3064 "Goodwill and Intangible Assets", issued by the CICA, replacing Sections 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". Section 3062 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Company is currently evaluating the impact of the adoption of this new section; however, it does not expect a material impact on its consolidated financial statements.

Effective April 1, 2011, the Company will replace current Canadian standards and interpretations with International Financial Reporting Standards (IFRS) as the Canadian generally accepted accounting principles (Canadian GAAP) as required by the Canadian Accounting Standards Board. The Company is assessing the impact of the conversion and will provide information as required by regulations.

3. RESTRICTED CASH

The restricted cash balance at March 31, 2008 includes guarantees of US$16.4 million (Cdn$16.8 million) (see note 16), US$2.1 million (Cdn$2.1 million) of cash that is restricted for future site restoration in India and US$111.5 million (Cdn$114.6 million) of cash that is restricted as per the provisions of the facility agreement (see note 7).

4. LONG-TERM ACCOUNTS RECEIVABLE

As described below, the Company has two long-term accounts receivable:

(a) Long-term account receivable: The long-term account receivable balance consists of gas sales charged to the Bangladesh Oil, Gas and Mineral Corporation (Petrobangla) for production from the Feni field in Bangladesh. The Company commenced production from the Feni field in November 2004 and has made gas deliveries to Petrobangla since that time. The Company formalized a Gas Purchase and Sales Agreement (GPSA) in the year ended March 31, 2007 at a price of US$1.75 per Mcf.

Payment of the receivable is being delayed as a result of various claims raised against the Company as a result of the blowouts which occurred in the Chattak field in January and June 2005. These claims are further discussed in note 20, Contingencies. Though the Company expects to collect the full amount of the receivable, the timing of collection is uncertain as the Company may not collect the receivable until resolution of the various claims raised against the Company described in Note 20 (b) and (c). As a result, the receivable has been classified as long-term and discounted to reflect the potential delay in collection of these amounts.

(b) Income tax receivable: The income tax receivable balance results from advances made to the tax authority in India as a result of assessments and re-filings for the taxation years 2001 through 2004. While no assurance can be given, the Company believes it will be successful on appeal and the tax authority will refund these advances. See further discussion in Note 20(f).



5. PROPERTY AND EQUIPMENT

Accumulated
Depletion, Net Book
As at March 31, 2008 Cost Depreciation Value
----------------------------------------------------------------------------
Oil and natural gas
India $ 646,158 $ 153,845 $ 492,313
Bangladesh 197,427 47,908 149,519
All Other 6,642 2,209 4,433
----------------------------------------------------------------------------
$ 850,227 $ 203,962 $ 646,265
----------------------------------------------------------------------------

Accumulated
Depletion, Net Book
As at March 31, 2007 Cost Depreciation Value
----------------------------------------------------------------------------
Oil and natural gas
India $ 354,633 $ 171,788 $ 182,845
Bangladesh 211,112 37,574 173,538
Thailand 20,910 - 20,910
All Other 3,625 1,794 1,831
----------------------------------------------------------------------------
$ 590,280 $ 211,156 $ 379,124
----------------------------------------------------------------------------


The Company expensed costs of $21.7 million that were previously capitalized in Thailand and $0.7 million for new ventures. See note 11, Asset Impairment, for further discussion of the asset impairment.

During the year ended March 31, 2008, the Company capitalized $1.3 million of general and administrative expenses, $2.2 million of stock-based compensation expense and $13.5 million of financing charges (2007 - $0.6 million of general and administrative expenses, $1.9 million of stock-based compensation expense and nil of financing charges).

Total costs of $460.9 million (March 31, 2007 - $179.7 million) have been excluded from costs subject to depletion and depreciation as at March 31, 2008. This is comprised of $457.5 million (March 31, 2007 - $157.1 million) associated with the Company's undeveloped properties and major development projects in India; nil (March 31, 2007 - $20.9 million) associated with the Company's undeveloped properties in Thailand; and $3.4 million (March 31, 2007 - $1.7 million) associated with the Company's new ventures.

At March 31, 2008, the Company performed ceiling tests for the relevant portion of the Indian, Bangladeshi and Canadian cost centres to assess the recoverable value. The natural gas prices used in the ceiling tests were based on contracts entered into by the Company and forecast future contract prices. The future oil and condensate prices for Hazira and Block 9 were based on the April 1, 2008 commodity price forecast relative to Brent blend prices of the Company's independent reserve evaluators and were adjusted for commodity price differentials specific to the Company being 90% of Brent Blend for Hazira and 105% of Brent Blend for Block 9. The future condensate price for Feni was based on the current billing rate of US$40.00/bbl. For the prices quoted in U.S. dollars, the Company converted the prices to Canadian dollars using the exchange rate on March 31, 2008 of 1 U.S. dollar to 1.0279 Canadian dollars. The future oil price for Canada was based on the March 2008 actual selling price as an independent reserve evaluation was not performed due to the small size of the Canadian operations relative to the size of the Company. The Canadian operations accounted for less than 1 percent of sales for the year ended March 31, 2008. The table below summarizes the benchmark and forecast prices used in the ceiling test calculation:



India Bangladesh
Benchmark Forecast Forecast
Price Natural Gas Natural Gas
(Brent Blend) Price Price
(US$/bbl) (US$/Mcf) (US$/Mcf)
----------------------------------------------------------------------------
2009 100.08 4.77 2.29
2010 93.83 5.21 2.34
2011 87.59 5.29 2.34
2012 83.42 5.69 2.34
2013 81.34 5.69 2.34
Thereafter 88.71 5.69 2.34
----------------------------------------------------------------------------


6. ASSET RETIREMENT OBLIGATIONS

The asset retirement obligations relate to the future site restoration and abandonment costs including the costs of production equipment removal and environmental cleanup based on regulations and economic circumstances at year-end.

The following table reconciles the Company's asset retirement obligations as at March 31 of each fiscal year:



2008 2007
----------------------------------------------------------------------------
Obligations, beginning of year $ 8,974 $ 6,779
Obligation incurred during the year 1,219 449
Obligation released for wells sold during the year - (90)
Obligation settled during the year (62) -
Revision in estimated cash flows 76 1,382
Accretion expense 605 454
Foreign currency translation (1,454) -
----------------------------------------------------------------------------
Obligation, end of year $ 9,358 $ 8,974
----------------------------------------------------------------------------


The Company has estimated the fair value of its total asset retirement obligations based on estimated future liabilities of $14.8 million. A credit-adjusted risk-free interest rate of 7 percent and inflation rates of 4.5 percent for Indian properties, 7 percent for Bangladeshi properties and 2 percent for Canadian properties were used to calculate the fair value of the asset retirement obligations. The costs are expected to be incurred between 2011 and 2023.

Indian regulations require a separate, restricted bank account to be funded over time to fund the costs of asset retirement obligations. The fair value of assets that are legally restricted for purposes of settling asset retirement obligations is estimated at $2.1 million as at March 31, 2008 (March 31, 2007 - $1.0 million).

7. LONG-TERM DEBT

In November 2007, the Company executed an agreement for its US$550 million credit facility. The facility is being used to fund 65 percent of the Company's share in the D6 natural gas development and, upon completion of the D6 block development, may be used for other projects. The current balance outstanding is US$192.8 million and the Company is currently prevented from drawing further amounts because the Company is unable to meet one of the conditions precedent to borrowing funds. The Company expects that this condition precedent will be fulfilled once the lenders have adopted projections based on the March 31, 2008 reserve reports and following this, the Company expects to be able to borrow additional funds.

Interest is at LIBOR plus 1.7 percent, falling to LIBOR plus 1.5 percent upon project completion, falling to LIBOR plus 1.2 percent once production reaches an average of 2.8 Bcf/d (280 MMcf/d net to the Company).

The Company is required to make U.S. dollar repayments of the outstanding balance if the loan exceeds the amount specified in a reduction schedule or in order to bring financial coverage ratios within specified limits. The facility will expire on September 30, 2011 and, under certain circumstances, may be extended, at the Company's option, to September 30, 2012. The aggregate amount of payments estimated as at March 31, 2008 to be required in each of the next five years ending March 31 to meet repayment provisions is:



(thousands of U.S. dollars) 2009 2010 2011 2012 2013

----------------------------------------------------------------------------
Estimated loan repayments - - 119,817 72,997 -
----------------------------------------------------------------------------


The provisions of the loan agreement restrict the distribution of retained earnings to $0.03 per share in any quarter to a limit of $15 million for the aggregate dividends paid from inception of the agreement to completion of the D6 project. In addition, no dividend may be paid in the event that the Company is in default of certain provisions of the agreement.

The loan is secured by an interest in the D6, Hazira, Surat and Block 9 Production Sharing Contracts (PSCs).

Long-term debt is a financial instrument classified as other financial liabilities, which are measured at amortized cost. During the year ended March 31, 2008, the Company recognized a foreign currency translation loss of Cdn$5.1 million on the translation of the U.S. dollar denominated long-term debt, which has been included in other comprehensive income. Refer to note 5 for the amount of financing charges that were capitalized during the year.

8. SHARE CAPITAL

(a) Authorized

Unlimited number of Common shares

Unlimited number of Preferred shares



(b) Issued

2008 2007
Number Amount Number Amount
----------------------------------------------------------------------------
Common shares
Balance, beginning of year 42,994,820 $ 603,112 38,532,820 $ 297,747
Equity offering 4,762,000 479,585 4,300,000 300,630
Stock options exercised 1,297,588 39,723 162,000 4,147
Contributed surplus - 7,632 - 588
----------------------------------------------------------------------------
Balance, end of year 49,054,408 $1,130,052 42,994,820 $ 603,112
----------------------------------------------------------------------------


(c) Stock Options

The Company has reserved for issue 4,905,440 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:



2008 2007
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
Outstanding, beginning
of year 3,753,250 $ 47.06 3,312,500 $ 39.88
Granted 838,563 92.09 839,750 70.81
Forfeited (74,500) 64.07 (237,000) 45.58
Exercised (1, 297,588) 30.61 (162,000) 25.60
----------------------------------------------------------------------------
Outstanding, end of year 3, 219,725 $ 65.02 3,753,250 $ 47.06
----------------------------------------------------------------------------
Exercisable, end of year 929,538 $ 49.79 1,545,938 $ 32.16
----------------------------------------------------------------------------


The following table summarizes stock options outstanding and exercisable
under the plan at March 31, 2008:

Outstanding Exercisable
Options Options
Weighted Weighted
Remaining Life Average Average
Exercise Price Options (Years) Price Options Price
----------------------------------------------------------------------------
$ 22.20 - $ 26.47 32,500 0.1 $ 25.30 32,500 $ 25.30
$ 27.85 - $ 39.30 150,850 1.1 $ 35.55 110,850 $ 34.72
$ 41.00 - $ 49.30 517,500 2.2 $ 43.44 320,000 $ 43.79
$ 53.70 - $ 63.00 1,357,562 1.6 $ 56.85 413,438 $ 56.28
$ 79.69 - $ 90.40 699,063 2.4 $ 85.95 52,750 $ 82.04
$ 92.17 - $ 105.47 462,250 3.1 $ 93.91 - $ -
----------------------------------------------------------------------------
3,219,725 2.3 $ 65.02 929,538 $ 49.79
----------------------------------------------------------------------------


Stock-based Compensation

The fair value of each option granted during the period was estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average grant-date fair values of options granted during the year ended March 31, 2008 was $30.94 (2007 - $25.40). The weighted average assumptions used in the Black-Scholes model to determine fair value for the current and prior years were as follows:

Modified Black-Scholes Assumptions



(weighted average) 2008 2007
----------------------------------------------------------------------------
Risk-free interest rate 3.77% 4.09%
Volatility 31% 34%
Expected life (years) 3.24 2.71
Expected annual dividend per share $ 0.12 $ 0.12
----------------------------------------------------------------------------


The Company has not incorporated an estimated forfeiture rate for stock options that will not vest; rather, the Company accounts for actual forfeitures as they occur.



9. CONTRIBUTED SURPLUS

2008 2007
----------------------------------------------------------------------------
Contributed surplus, beginning of year $ 26,723 $ 6,861
Stock-based compensation 19,466 20,450
Stock options exercised (7,632) (588)
----------------------------------------------------------------------------
Contributed surplus, end of year $ 38,557 $ 26,723
----------------------------------------------------------------------------


10. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

2008 2007
----------------------------------------------------------------------------
Accumulated other comprehensive income (loss),
beginning of year $ (67,410) $ -
Other comprehensive income (loss):
Recognition of fair value of derivative (loss) (540) -
Foreign currency translation (loss) (17,808) (67,410)
----------------------------------------------------------------------------
Accumulated other comprehensive income (loss),
end of year $ (85,758) $ (67,410)
----------------------------------------------------------------------------


Effective January 1, 2007, the Company began translating the accounts of its foreign operations to Canadian dollars using the current rate method, whereas previously it had used the temporal method. This change was adopted prospectively and resulted in a foreign currency translation adjustment of $67.3 million with a corresponding decrease in property and equipment. An additional credit of $0.1 million was recorded to the foreign currency translation account for the activity during the quarter ended March 31, 2007.

11. ASSET IMPAIRMENT

The Company expensed costs of $21.7 million that were previously capitalized related to the unsuccessful wells, workovers and associated costs in Thailand. An additional $3.3 million that was previously included in the foreign currency translation component of other comprehensive income was also expensed in the period. A cash call receivable in the amount of $1.1 million was also expensed.

The Company expensed costs of $0.7 million that were previously capitalized related to the evaluation of a potential new venture with which the Company decided not to proceed.

12. SEGMENTED INFORMATION

The Company's operations are conducted in one business sector, the oil and natural gas industry. Geographic areas are used to identify the Company's reportable segments. The accounting policies of the information of the reportable segments are the same as those described in the summary of significant accounting policies. Revenues, operating profits and net identifiable assets by reportable segments are as follows:



Year ended March 31, 2008

India Bangladesh All Other(1)(2) Total
----------------------------------------------------------------------------
Revenue $ 58,847 $ 44,517 $ 861 $ 104,225
Segment profit (loss) $ 14,610 $ 6,719 $ (1,660) $ 19,669
Capital additions $ 328,860 $ 9,090 $ 6,181 $ 344,131
Property and equipment $ 492,313 $ 149,519 $ 4,433 $ 646,265
Total assets (end of
period) $ 691,287 $ 178,888 $ 483,748 $ 1,353,923
----------------------------------------------------------------------------
(1) All Other includes the Canadian oil and gas operations, new ventures and
corporate activities. Thailand assets written off are included in All
Other.

(2) Revenues included in All Other are from Canadian sales of oil and
royalties.


Year ended March 31, 2007

India Bangladesh All Other(1)(2) Total
----------------------------------------------------------------------------
Revenue $ 72,696 $ 42,029 $ 761 $ 115,486
Segment profit (loss) $ (16,099) $ 4,993 $ 111 $ (10,995)
Capital additions $ 78,970 $ 36,615 $ 19,181 $ 134,766
Property and equipment $ 182,845 $ 173,538 $ 22,741 $ 379,124
Total assets (end of
period) $ 222,624 $ 208,589 $ 243,347 $ 674,560
----------------------------------------------------------------------------
(1) All Other includes the Canadian oil and gas operations, Thailand
operations, new ventures and corporate activities.

(2) Revenues included in All Other are from Canadian sales of oil and
royalties.


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

2008 2007
----------------------------------------------------------------------------
Segment profit (loss) $ 19,669 $ (10,995)
Interest and other income 23,273 4,378
Interest and financing expenses - (2,379)
General and administrative expenses (7,069) (6,180)
Discount of long-term account receivable (4,575) -
Loss on risk management contracts (2,070) -
Stock-based compensation expense (17,257) (18,490)
Asset impairment (26,788) -
Foreign exchange gain (loss) (8,597) 2,029
----------------------------------------------------------------------------
Net income (loss) $ (23,414) $ (31,637)
----------------------------------------------------------------------------


For the year ended March 31, 2008, revenue from transactions with three customers individually exceeded 10 percent of consolidated revenues (2007 - three customers). Gas production from the Bangladesh fields, Feni and Block 9, is sold exclusively to the Bangladesh Oil, Gas and Mineral Corporation (Petrobangla) accounting for 43 percent of consolidated revenues in 2008 (2007 - 36 percent). Two purchasers of gas from the Indian fields account for 11 percent and 17 percent, individually, of consolidated revenues in 2008 (2007 - 11 and 22 percent respectively).

13. EARNINGS PER SHARE

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



2008 2007
----------------------------------------------------------------------------
Weighted average number of common shares
outstanding
- basic and diluted 46,346,909 39,969,962
----------------------------------------------------------------------------


As the Company incurred a net loss for the years ended March 31, 2008 and 2007, all outstanding stock options (March 31, 2008 - 3,219,725 and March 31, 2007 - 3,753,250) were considered anti-dilutive and were therefore excluded from the calculation of diluted share amounts.

14. 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:



2008 2007
----------------------------------------------------------------------------
Loss before income taxes $ (21,540) $ (21,340)
Statutory income tax rate 31.47% 32.12%
Computed expected income taxes (6,779) (6,854)
Non-deductible expenses and other (7,026) 386
Stock-based compensation expense 5,442 5,954
Income exempt from tax 6,999 (1,823)
Prior years' foreign income tax expense adjustments (4,574) -
Adjustment to future Indian taxes (7,501) 19,223
Foreign non-income related taxes 214 121
Valuation allowance and other 15,099 (6,710)
----------------------------------------------------------------------------
Provision for income taxes $ 1,874 $ 10,297
----------------------------------------------------------------------------

The components of the Company's future income tax liability at March 31 of
the current and prior years are as follows:

2008 2007
----------------------------------------------------------------------------
Future income tax assets
----------------------------------------------------------------------------
Foreign currency cash and cash equivalents $ 1,666 $ -
Asset retirement obligation 1,486 2,602
Unused losses - 4,301
Unused foreign tax credits 23,138 14,670
Share issue expenses 7,486 1,239
Property and equipment 186 3,999
Long-term account receivable 878 149
----------------------------------------------------------------------------
$ 34,840 $ 26,960
----------------------------------------------------------------------------

2008 2007
----------------------------------------------------------------------------
Future income tax liabilities
----------------------------------------------------------------------------
Short-term investments $ 417 $ -
Property and equipment 1,457 3,037
Valuation allowance 32,966 23,923
----------------------------------------------------------------------------
$ 34,840 $ 26,960
----------------------------------------------------------------------------
Net future income tax liability $ - $ -
----------------------------------------------------------------------------


India's federal tax law contains a seven-year tax holiday provision that pertains to the commercial production or refining of mineral oil, which is generally accepted as including petroleum and natural gas substances. As a result of the tax holiday in India, the Company pays the greater of 42.23 percent of taxable income in India after a deduction for the tax holiday or a minimum alternative tax of 10.56 percent of Indian income. Taxes are based upon Indian income calculated in accordance with Indian GAAP. See also contingency note 20(f).

The Company pays taxes in Bangladesh at a rate of 4.0 percent of revenues net of profit petroleum. In addition, the Company accrues additional taxes assessed when it considers an unfavourable outcome to the Company to be more likely than not.

The Company does not pay income taxes related to Block 9 production as indicated in the PSC. The PSC indicates that the calculation for profit petroleum expense includes consideration of income taxes and, therefore, no income tax is assessed for Block 9.

15. FINANCIAL INSTRUMENTS

The following financial instruments are included on the Consolidated Balance Sheet. The carrying values and fair values of the financial instruments are as follow:



2008 2008 2007 2007
Carrying Fair Carrying Fair
Amount Value Amount Value
----------------------------------------------------------------------------
Held for trading financial assets
(designated upon initial recognition):
Short-term investments $ 17,721 $ 17,721 $ - $ -

Loans and receivables:
Accounts receivable $ 38,982 $ 38,982 $ 21,917 $ 21,917
Long term accounts receivable $ 21,432 $ 21,432 $ 26,191 $ 26,191
Other financial liabilities
(not held for trading):
Accounts payable and accrued
liabilities (1) $ 14,224 $ 14,224 $ 29,313 $ 29,313
Interest rate swaps(1) $ 2,681 $ 2,681 $ - $ -
Long-term debt $198,194 $198,194 $ - $ -
----------------------------------------------------------------------------
(1) The fair value of the interest rate swaps are included in accounts
payable and accrued liabilities on the balance sheet.


The fair values of the accounts receivable and accounts payable and accrued liabilities approximate their carrying values due to their short periods to maturity. The fair value of held for trading assets is based on publicly quoted market values. A gain of $1.4 million on recognizing the fair value of the held for trading assets at March 31, 2008 is included and recognized in other income. A discount on the long-term account receivable of $4.6 million has been recognized in income resulting in the long-term account receivable being carried at fair value. The fair value of the interest rate swaps is provided by a third party using a forward LIBOR curve applied to future settlements. A loss of $2.1 million on recognition of the interest rate swaps has been recognized in income. The Company's long-term debt bears interest based on a floating market rate and, accordingly, the fair market value approximates the carrying value.

Price Risk

Currency Risk: The Company is exposed to fluctuations in the value of accounts receivable, long-term account receivable, accounts payable and accrued liabilities, interest rate swaps and long-term debt due to changes in foreign exchange rates as these financial instruments are primarily U.S.-dollar-denominated. This risk is reduced because a portion of the Company's revenues and expenses is denominated in U.S. dollars. The Company further manages the risk by converting Canadian held cash to U.S. dollars as required to fund forecast expenditures.

Interest Rate Risk: The Company holds money market funds and short-term deposits for terms of up to six months. The Company is exposed to interest rate risk on the portion of its long-term debt without interest rate swaps. The long-term debt has a floating interest rate and changes to interest rates would impact the Company's future cash flows. As required by the terms of the facility agreement, the Company entered into a series of U.S. dollar interest rate swaps to mitigate a portion of this risk. The interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based. At March 31, 2008, the Company had the following interest rate swap contracts outstanding:



Fixed for floating interest rate
swaps Amount Fixed Floating
Term (US$ millions) rate rate
----------------------------------------------------------------------------
March 31, 2008 - June 30, 2008 96.7 4.12% 3 month US$-LIBOR(1)
June 30, 2008 - September 30, 2008 134.8 4.12% 3 month US$-LIBOR(1)
September 30, 2008 - December 31, 2008 157.0 4.12% 3 month US$-LIBOR(1)
December 31, 2008 - December 31, 2009 175.6 4.12% 3 month US$-LIBOR(1)
----------------------------------------------------------------------------
(1) Three-month, U.S. dollar-denominated, LIBOR determined on the last day
of the preceding period.


Market Risk: The Company is exposed to changes in the market value of held for trading assets. The Company monitors the market value of marketable securities on a regular basis. The Company is exposed to the risk of changes in market prices of commodities. The Company enters into natural gas contracts which manage this risk.

Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist of money market and short-term deposits, accounts receivable and long-term account receivable.

The Company has deposited the cash equivalents with reputable financial institutions, from which management believes the risk of loss to be remote.

The Company has accounts receivable from clients engaged in various industries that are concentrated in a specific geographic area in India and with a specific customer in Bangladesh. The Company takes measures in order to mitigate any risk of loss which may include obtaining guarantees. The specific industries or government may be affected by economic factors that may impact accounts receivable. See note 4 (a) for additional information related to the credit risk associated with the long-term account receivable. The book value of the accounts receivable and long-term account receivable reflects management's assessment of the credit risk.

Hedging

The Company is exposed to changes in the LIBOR rate as this is the rate of future U.S. dollar interest payments applicable to the U.S.-dollar long-term debt. During the three months ended December 31, 2007, the Company entered into a series of U.S.-dollar interest rate swaps to mitigate a portion of this risk. The interest rate swaps result in the Company paying a fixed rate of interest of 4.12 percent and receiving a floating rate, specifically LIBOR, for a portion of the forecast outstanding long-term debt for periods matching the interest periods on the loan. The first interest rate swap settled on December 31, 2007 and the interest rate swaps settle every three months thereafter with the final interest rate swap settling on March 31, 2009.

During the quarter ended December 31, 2007, the Company recognized the fair value loss on the interest rates swaps of $413,000 and a gain on the settlement of the interest rate swap in the amount of $15,000, resulting in an ending balance in accumulated other comprehensive income related to the interest rate swaps of $413,000 and a fair value liability related to the interest rate swaps of $428,000, which has been included in accounts payable.

During the quarter ended March 31, 2008, the hedge ceased to be effective and the Company recognized the change in fair value of the hedge for the quarter of $2.1 million in income. The fair value loss deferred in the prior period will be recognized in income over the life of the interest rate swaps.

16. GUARANTEES

As at March 31, 2008 and 2007, the Company had the following performance security guarantees: US$7.7 million for Block 9, US$7.0 million for the Cauvery block and US$1.7million for the D4 block. In addition, at March 31, 2007, the Company had a performance security guarantee of US$1.0 million for the NEC-25 block.

17. ECONOMIC DEPENDENCE

The Company sells all of the gas production from the Feni and Block 9 fields in Bangladesh to Petrobangla. As per the terms of the agreements governing production from these fields, the Company is unable to elect to sell to other purchasers.

18. RELATED-PARTY TRANSACTIONS

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

19. CONTRACTURAL OBLIGATIONS

The Company has estimated the costs to complete the Phase I minimum work commitment for the D4 and Cauvery blocks to be US$14.6 million and US$7.5 million, respectively. The minimum work commitments must be fulfilled within four years and three years of signing the PSC for the D4 and Cauvery blocks, respectively. The Company has minimum work commitments under Phase I of the initial term and other requirements for the Pakistan blocks of US$8.6 million, which must be spent within two years of signing the Production Sharing Agreements (PSAs). Subsequent to March 31, 2008, the Company signed a PSC for an interest in a block in the Kurdistan Region of Iraq including minimum commitments of US$7.2 million related to seismic and drilling one exploratory well in the Kurdistan Region within three years of signing the PSC and $18.5 million for various bonuses and other payments to the regional government under the agreement.

20. CONTINGENCIES

(a) During the year ended March 31, 2006, the Company was named as a defendant in a lawsuit that was filed in Texas by a number of plaintiffs who claim to have suffered damages as a result of the uncontrolled releases of natural gas that occurred at the Chattak-2 well in Bangladesh in January and June 2005. Total damages sought were in excess of US$250 million. On July 7, 2006, a court hearing was held to hear the Company's pleadings for the lawsuit to be dismissed due to lack of jurisdiction in Texas. The court in Texas dismissed the lawsuit on August 25, 2006 and the plaintiffs appealed the dismissal. The appeal was heard on July 10, 2007 and the appeal has been dismissed. The plaintiff did not appeal the second dismissal. As a result, the lawsuit is dismissed with no financial impact to the Company.

(b) During the year ended March 31, 2006, a group of petitioners in Bangladesh (the petitioners) filed a writ with the Supreme Court of Bangladesh (the Supreme Court) against various parties including Niko Resources (Bangladesh) Ltd., a subsidiary of the Company. The petitioners are requesting the following of the Supreme Court with respect to the Company:

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

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

(iii) that Petrobangla withhold future payments to the Company relating to production from the Feni field (US$25.3 million as at March 31, 2008); and

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

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

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

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

(i) Taka 368,500,000 (Cdn$5.3 million) for 3 Bcf of free natural gas delivered from the Feni field as compensation for the burnt natural gas;

(ii) Taka 723,500,000 (Cdn$10.6 million) for 5.89 Bcf of free natural gas delivered from the Feni field as compensation for the subsurface loss;

(iii) Taka 845,560,000 (Cdn$12.3 million) for environmental damages, an amount subject to be increased upon further assessment;

(iv) Taka 5,527,500,000 (Cdn$80.7 million) for 45 Bcf of natural gas as compensation for further subsurface loss; and

(v) any other claims that arise from time to time.

The Company and the Government of Bangladesh had previously agreed to settle the government's claims through arbitration conducted in Bangladesh based upon international rules. The Company will actively defend itself against the lawsuit. This process could take in excess of three years.

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

(d) In accordance with natural gas sales contracts to customers in the vicinity of the Hazira field, the Company and its joint venture partner at Hazira have committed to certain minimum quantities. Should the Company fail to supply the minimum quantity of natural gas in any month as specified in the contract, the Company may be liable to pay the vendor an approximately equivalent amount. The Company was unable to deliver the minimum quantities up to December 31, 2007. The Company intends to use D6 volumes to fulfill these past obligations and has signed an agreement to this effect. In the event the Company is unable to deliver the volumes, the Company will have a potential liability, which is currently estimated at US$27.0 million.

(e) The Company calculates and remits profit petroleum expense to the Government of India in accordance with the PSC. The profit petroleum expense calculation considers capital and other expenditures made by the joint venture, which reduce the profit petroleum expense. There are costs that the Company has included in the profit petroleum expense calculations that have been contested by the government. The Company believes that it is not determinable whether the above issue will result in additional petroleum expense. No amount has been recorded in these consolidated financial statements.

(f) The Company has filed its income tax returns for the years 1998 through 2007 in India, under provisions that provide for a tax holiday for production from the Hazira and Surat fields.

The Company received a favourable ruling with respect to the tax holiday at the third tax assessment level for the 1999 through 2004 taxation years. The Income Tax Department has filed an appeal against the one of the orders and the matter is currently pending with the Indian courts. The taxation years 2005 through 2007 have been filed including a deduction for the tax holiday, but have not yet been assessed.

Should the Company fail through the legal process to receive a favourable ruling with respect to the taxation years 1999 through 2004, the Company would record a tax expense of US$39.9 million, pay additional taxes of US$10.7 million and write off US$29.2 million of the income tax receivable.

(g) A vendor employed by the Company in conjunction with the construction of the Hazira offshore development has claimed US$1.8 million from the Hazira joint venture (US$0.6 million net to the Company) with respect to service tax liability on the contract. The Company believes that service tax is not applicable to the contract and that the outcome of this dispute is not determinable.

June 25, 2008

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.
    Murray Hesje
    Vice President Finance
    (403) 262-1020
    Website: www.nikoresources.com