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Niko Resources Announces 1st Quarter Financial Results

August 13, 2008

CALGARY, ALBERTA–(Marketwire – Aug. 13, 2008) – Niko Resources Ltd. (TSX:NKO) reports results for the three months ended June 30, 2008.

PRESIDENT’S REPORT to SHAREHOLDERS

OPERATIONAL HIGHLIGHTS

New Ventures

– In May of 2008, Niko signed a production sharing contract (PSC) in the Kurdistan Region of Iraq whereby it will operate and currently has a 36 percent participating interest in the 846 square kilometre block.

– In July of 2008, Niko signed a Heads of Agreement whereby it will operate and earn a 75 percent participating interest in a 16,845 square kilometre block in Madagascar.

Exploration

– In Pakistan, a contract has been awarded to conduct a 3,200- square-kilometre 3D seismic program.

– In the Kurdistan Region, field scouting began and a tender for a 300 to 500-kilometre 2D seismic program will be issued shortly.

– In D6, the L1 well was the first discovery in the Pleistocene channel complex.

Development

– D6 gas development is expected to start-up in the third calendar quarter of 2008. Volumes are expected to ramp-up to 2.8 Bcf/ d (280 MMcf/d working interest to the Company).

– D6 oil development is expected to start-up in the third calendar quarter of 2008. Expected peak oil production is 40,000 bbls/d (4,000 bbls/d working interest to the Company).

– The development plan for the D6 satellite fields was submitted.

——————————————————————– ——– ________________________________________________Three months ended__June 30,

erations______________________________________________2008__________ 2007 ——————————————————————– ——– Average daily production Oil and condensate (bbls/d)____________________________ 252____________366 Natural gas (Mcf/ d)__________________________________77,044________ 84,499 ——————————————————————– ——– Total combined (Mcfe/d)______________________________ 78,557________ 86,697 Revenues, royalties and operating costs ($/Mcfe) Oil and natural gas revenue____________________________3.45__________ 3.54 Pipeline revenue______________________________________ 0.01__________ 0.02 Royalties____________________________________________ (0.16)________ (0.19) Profit petroleum______________________________________(0.78)________ (1.19) Operating costs______________________________________ (0.34)________ (0.41) ——————————————————————– ——– Operating netback ($/Mcfe)____________________________ 2.18__________ 1.77 Drilling activity ——————————————————————– ——– Gross wells______________________________________________ 3______________3 Net wells______________________________________________ 0.3____________0.7 ——————————————————————– ——– ——————————————————————– ——– Financial Highlights____________________________ Three months ended June 30, (thousands of dollars)__________________________________2008__________ 2007 ——————————————————————– ——– Petroleum and natural gas sales______________________ 24,628________ 27,952 Funds from operations________________________________ 16,227________ 13,342 Net income (loss)______________________________________6,207________ (6,168) Capital expenditures________________________________ 111,129________ 62,798 ——————————————————————– ——–

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 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. 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 REVIEW

OPERATIONS UPDATE

India

D6 BLOCK:

Exploration: The MK-1 Cretaceous exploration well, located 11 kilometres from the MA oil development, was drilled during the quarter, the rig has been released and the well results are under evaluation. Subsequent to June 30, 2008, the L1 well, located just outside the Dhirubhai 1 and 3 development area, was the first discovery in the Pleistocene submarine channel complex play. This complex extends over a significant portion of the block, particularly in the northern and eastern areas.

Gas Development: The Dhirubhai 1 and 3 discoveries are expected to start production during the third calendar quarter of 2008.

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 Company had spent US$328 million to June 30, 2008 of the US$520 million estimated for the project. Fourteen of the planned 18 Phase I wells will be tied in after start-up. 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).

The development plan for eight of the natural gas discoveries in the D6 Block has been submitted to the Government of India. 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. Numerous other prospects have been identified in deeper water areas of the block where further upside potential will be evaluated.

Oil Development: Production from the MA discovery 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$52 million to June 30, 2008. A large portion of these costs will be spent subsequent to start-up to drill and tie in four of the planned six oil development wells and after a period of oil production, to convert some of the oil wells to gas producers.

NEC-25 BLOCK: Geotechnical and geophysical studies have been completed with results used in the selection of drilling locations. One well, B3, was drilled during the quarter. The rig has been released and the well results are under evaluation. 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 submitted for the six gas discoveries that have been declared commercial by the Indian regulatory authorities.

CAUVERY: Two wells were drilled in Cauvery during fiscal 2008 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 has been 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 47 MMcf/d (16 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 8 MMcf/d. This includes production from the three wells drilled in fiscal 2008.

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 4 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.

PAKISTAN: Four 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, which is expected to commence data acquisition in late calendar 2008.

KURDISTAN REGION: In May of 2008, the Company signed a PSC for the Qara Dagh block. Field scouting is underway and a tender for a 300 to 500-kilometre 2D seismic program will be issued shortly with data acquisition expected to commence later in the third quarter of calendar 2008.

MADAGASCAR: In July of 2008, the Company signed a Heads of Agreement whereby it has farmed-in to a production sharing contract for a property located off the west coast of Madagascar. The agreement is subject to the execution of definitive agreements and the approval of the Office of National Mines and Strategic Industries, who act on behalf of the Republic of Madagascar and the Company is awaiting approval.

PRODUCTION

The following table displays working interest production in the three months ended June 30, 2008 and forecast production for fiscal 2009:

________________________________ Three months__________Lower__________Upper Working interest Production____________ ended____ Estimate(1)____Estimate(1) (daily average)________________ June 30, 2008____Fiscal 2009____Fiscal 2009 ——————————————————————– ——– Natural Gas (MMcf/d) India D6________________________________________ -__________ 90(2)________ 130(2) Hazira____________________________________18____________ 13____________ 15

_____________________________________9______________6______________7 Bangladesh Block 9__________________________________ 46____________ 54____________ 58 Feni______________________________________ 5______________3______________4 Oil (Bbls/d) India D6________________________________________ -________1,100(2)______ 1,350(2) Hazira__________________________________ 162____________150____________166 Other (3)__________________________________90______________- ______________- ——————————————————————– ——– Total (MMcfe/ d)____________________________79____________174____________223 ——————————————————————– ——– (1) Refer to “Forward-looking Information” in the Company’s MD&A for the ____quarter ended June 30, 2008, which can be found at www.sedar.com, for a ____description of how forecast production is estimated. (2) 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. (3) 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 three months ended June 30, 2008, operating expenses averaged $0.34/Mcfe, and are anticipated to average less than $0.36/ Mcfe in fiscal 2009.

CAPITAL EXPENDITURES

The following table displays capital spending during the three months ended June 30, 2008 and forecast capital spending for all of fiscal 2009:

Exploration and Development Spending (Net to the Company) __________________________________________Three months ended__Forecast(1)(2) ($ millions)__________________________________ June 30, 2008____Fiscal 2009 ——————————————————————– ——– India

very__________________________________________________0.3__________8 – 9 D4______________________________________________________ 0.9__________7 – 8

6______________________________________________________84.9______380 – 400 Hazira__________________________________________________ 0.2__________4 – 5 NEC-25__________________________________________________ 6.5________12 – 13

__________________________________________________0.1______________1 ——————————————————————– ——– Bangladesh Block 9__________________________________________________2.1________13 – 14 Chattak & Feni__________________________________________ 0.3______________1 ——————————————————————– ——– Pakistan________________________________________________ 0.6________56 – 58 ——————————————————————– ——– Kurdistan Region________________________________________15.0________25 – 27 ——————————————————————– ——– Madagascar________________________________________________ – __________5 – 6 ——————————————————————– ——–

__________________________________________________0.2____________0.2 ——————————————————————– ——–

otal__________________________________________________111.1______512 – 542 ——————————————————————– ——– ——————————————————————– ——– (1) Refer to “Forward-looking Information” in the Company’s MD&A for the ____quarter ended June 30, 2008, which can be found at www.sedar.com, for a ____ description of how forecast capital expenditures are estimated. (2) Forecast fiscal 2009 is the sum of the actual spending for the quarter ____and expected spending for the remainder of the fiscal year.

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 during the quarter were mainly for the carrying costs of the block. 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 has been 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 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.

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. Capital expenditures during the quarter and 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.

Gas Development: The Dhirubhai 1 and 3 discoveries are expected to commence production during the third calendar quarter of 2008.

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 Company had spent US$328 million to June 30, 2008 of the US$520 million estimated for the project. Fourteen of the planned 18 Phase I wells will be tied in after start-up. 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).

The development plan for eight of the natural gas discoveries in the D6 Block has been submitted to the Government of India. 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.

Oil Development: Production from the MA discovery 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 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$52 million to June 30, 2008. A large portion of these costs will be spent subsequent to start-up to drill and tie in four of the planned six oil development wells and after a period of oil production, to convert some of the oil wells to gas producers.

Capital expenditures at D6 in the quarter were $84.9 million. Spending during the quarter 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 quarter were primarily related to well recompletions 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.

The remaining capital expenditures of putting the three new wells into service were incurred during the quarter. 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, and was awarded to the Company and its partner in the Government of India’s first international bid round in 1999. Under the production sharing contract (PSC), the Company and its partner have capital commitments for Phase II exploration, which includes seismic and two exploration wells. To date, the Company and its partner have drilled sufficient wells to meet the commitment. Capital expenditures in the quarter were $6.5 million, primarily for the acquisition of 3D seismic and drilling the B3 well. Capital expenditures forecast for fiscal 2009 include environmental studies and additional exploratory drilling.

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.

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 quarter were $2.1 million. Expenditures were to commence the tie-in of the Bangora-3 well, for well testing and for upgrading of the production facility. The remaining forecast capital spending for fiscal 2009 includes completing the 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.

Capital expenditures during the quarter were made 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.

Pakistan

Four 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, which is expected to commence data acquisition in late calendar 2008. Capital expenditures of $0.6 million during the quarter were for annual fees required as per the PSAs. Remaining forecast capital expenditures for fiscal 2009 are primarily for seismic acquisition.

Kurdistan

In May of 2008, the Company obtained an interest in the onshore Qara Dagh block in the Sulaymaniyah Governorate of the Federal Region of Kurdistan in Iraq, which covers approximately 846 square kilometres. The Company currently has a 36 percent interest and carries the proportionate cost for the government’s interest resulting in a 45 percent cost interest. Field scouting is underway and a tender for a 300 to 500-kilometre 2D seismic program will be issued shortly with acquisition expected to commence later in the third quarter of calendar 2008. Capital expenditures during the quarter were for various bonuses required as per the PSC. Remaining forecast capital expenditures for fiscal 2009 include various payments under the PSC, a 2D seismic program and drilling one exploration well.

Madagascar

In July of 2008, the Company signed a Heads of Agreement whereby it has farmed-in to a production sharing contract (PSC) off the west coast of Madagascar. The agreement is subject to the execution of definitive agreements and the approval of the Office of National Mines and Strategic Industries, which acts on behalf of the Republic of Madagascar and the Company is awaiting approval.

The PSC covers 16,845 square kilometres in water depths ranging from shallow water to 1,500 metres. The joint venture is currently reprocessing 7,600 kilometres of 2D seismic, which is to be followed by a 3,000-square-kilometre 3D seismic program planned to commence in the first quarter of calendar 2009. Forecast capital expenditures for fiscal 2009 relate to the planned seismic.

OVERALL PERFORMANCE

Funds from Operations

Reported funds from operations increased to $16.2 million in the current quarter from $13.3 million in the prior year’s quarter. Net operating income was $1.6 million higher in the quarter than in the prior year’s quarter. Net revenues and operating expenses decreased in the current quarter primarily as a result of a decrease in production from the Hazira and Surat fields due to natural declines. The 2007 quarter’s net operating income included 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 income improved funds from operations by $2.2 million in the quarter, primarily due to higher average cash balances. An increase in general and administrative expense decreased funds from operations by $1.7 million and was a result of increased activity, number of employees and the employee bonus plan.

Net Income (Loss)

The Company generated net income of $6.2 million in the quarter compared to a net loss of $6.2 million in the prior year’s quarter resulting in a $12.4 million improvement in net income. In addition to the increase in funds from operations discussed above, there was an unrealized gain on the short-term investment, a decrease in the unrealized foreign exchange loss and a unrealized gain on risk management contracts, as discussed elsewhere, all of which improved net income.

The unrealized gain on the short-term investment of $7.0 million was recorded on recognition of the fair value of the investment.

The unrealized foreign exchange loss of $2.3 million in the quarter was primarily due to the translation of the rupee- denominated long-term income tax receivable.

There was an unrealized gain of $1.0 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 increase in forecast LIBOR rates during the period.

OUTLOOK

Whereas Niko once counted in years or months to the startup of the D6 oil and natural gas production, it is now counting in days. D6 oil and natural gas production is expected to start-up before the end of this quarter. Volumes are expected to ramp up to a targeted rate of 2.8 Bcf/d of natural gas (280 MMcf/d working interest to the Company) and 40,000 bbls/d of oil (4,000 bbls/d working interest to the Company). These events would culminate in a multi-fold increase in Niko’s current production and earnings.

With the addition of properties in Pakistan, the Kurdistan Region and Madagascar to Niko’s portfolio of exploration plays, Niko has secured promising investments in which to employ the current cash balance and the future cashflow from the D6 fields.

As always, Niko has coordinated its resources to fulfill exploration and development commitments and to seek and execute growth opportunities.

August 13, 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, Bangladesh, Pakistan, Iraq and Madagascar); 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.

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