The Company reports a reduction to its reserves as discussed more fully below. Total proved plus probable reserves are 377 bcfe. The after tax net present value, discounted at 10% (NPV10) equates to $674 million or $13.05 per share. These values assume that D6 natural gas price will remain at $4.20 per mmbtu net until March 31, 2014. However the Government of India is currently considering increasing price for the F2013 and F2014 periods. A price increase during these periods to $8.00 per mmbtu net would increase the NPV10 to approximately $15.89 per share.
In addition there is significant upside from contingent resource discoveries at D6, NEC 25 and Block 5c. The contingent resources are not reflected as reserves because development plans have not been finalized with government authorities.
These discoveries are expected to deliver an NPV10 of approximately $15.00 to $18.00 per share assuming developments proceed as currently planned. This value has been determined based on internally determined 2C contingent resources using price derived from the Company's third party reserve report. In the aggregate these discoveries are expected to add approximately 600 bcfe.
The graph below shows expected production over the next 7 years based on the third party proved plus probable reserve report for D1D3/MA and Block 9 and based on currently envisioned developments for contingent resources.
To view the Production graph, please visit the following link: http://media3.marketwire.com/docs/620nko_fig1.pdf
The reason for the decline in reserves referred to above relates to the D6 block. Proved plus probable reserves at D6 as at March 31, 2012 have reduced to 193 bcfe but it is important to recognize that coincident with the reduced reserves there is approximately a $700 million reduction in future capital.
While a portion of the change relates to production the vast majority relates to field performance and a revised geological model. Field performance at the D1/D3 field during 2011 demonstrated higher than expected pressure draw-downs and material balance estimates began to appreciably differ from in place gas volumes derived from geologic mapping. An assessment of reservoir performance concluded that, contrary to the previous geological model, the current D1/D3 producing wells did not appear to be receiving any contribution from outside the main channel areas. Two wells were drilled to determine the incidence of reservoir outside the main channel fairways. Reservoir analysis of these wells coupled with analysis of the field pressure behavior referred to above has resulted in the need to develop a revised geological model to better represent the field performance. The revised model no longer anticipates reservoir outside the main channel fairways. In addition this new interpretation and model has had an adverse effect on the geometry, orientation, the aerial extent of the reservoir net rock volume and size of the main channel rock volumes. In addition, the enhanced inter-connectedness of the main channel sands has resulted in increased water production and hence lowered the ultimate recovery.
June 20, 2012
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.
Edward S. Sampson
Niko Resources Ltd.
Chairman of the Board, President & CEO
Niko Resources Ltd.
VP Finance & CFO