Sekayu PSC

On November 10, 2009, the Company announced that it had elected to enter into a revised letter of intent ("Revised LOI") with Batavia Energy Inc. ("Batavia") to acquire 24 percent of South Sumatra Energy Inc. ("SSE") which together with PT Medco CBM Sekayu ("PT Medco"), holds a Production Sharing Contract ("PSC") for coalbed methane on the 58,349 hectare Sekayu Block located in the South Sumatra Basin (the "Sekayu PSC"), Indonesia. Awarded May 27, 2008, the Sekayu PSC marked the first time the Government of Indonesia's Executive Agency for Upstream Oil and Natural Gas Activities ("BPMigas") awarded a PSC for the exploration and development of coalbed methane in Indonesia. PT Medco Energi Internasional Tbk ("Medco"), Indonesia's leading independent oil and gas company, a consortium member of PT Medco and operator of the Sekayu PSC, forecasted first commercial coalbed methane production to begin in 2011 and peak in six years.

Under the terms of the Revised LOI, CBM Asia is required to make a cash payment of US$1,000,000 upon closing of the acquisition and incur exploration expenditures totalling US$3,243,500 under the Sekayu PSC on or before December 31, 2012, to earn an estimated 12% working interest in the Sekayu PSC. The Revised LOI will also grant CBM Asia the sole and exclusive right to provide financing for up to an additional 24% interest in SSE, representing the remaining estimated 12% working interest in the Sekayu PSC. Initial exploration drilling for the Sekayu PSC commenced in September 2009.

Summary of Typical CBM Reservoir Properties of Indonesian Coal Basins^[1]

	Basin	Province	Target Form- ation	Completeable Coal Thickness	Coal Rank	Avg Depth	High Graded Area	CBM Complet- Able	Resources Concen- Tration
				(m)	(R0%)	(m)	(km2)	(Tcf)	(Bcf/mi2)
1	S. Sumatra	Sumatra	M.Enim	37	0.47	762	7,350	183.0	24.9
2	Barito	Kalimantan	Warukin	28	0.45	915	6,330	101.6	16.0
3	Kutei	Kalimantan	Prangat	21	0.50	915	6,100	80.4	13.2
4	C. Sumatra	Sumatra	Petani	15	0.40	762	5,150	52.5	10.2
5	N. Tarakan	Kalimantan	Tabul	15	0.45	701	2,734	17.5	6.4
6	Berau	Kalimantan	Latih	24	0.45	671	780	8.4	10.8
7	Ombilin	Sumatra	Sawaht	24	0.80	762	47	0.5	10.7
8	Pasir/Asem	Kalimantan	Warukin	15	0.45	701	385	3.0	7.9
9	NW Java	Java	T.Akar	6	0.70	1524	100	0.8	7.6
10	Sulawesi	Sulawesi	Toraja	6	0.55	610	500	2.0	4.0
11	Bengkulu	Lemau	Lemau	12	0.40	610	772	3.6	4.7
	TOTAL						30,248	453.3	15.0

Source: Stevens, S. "Indonesia Coalbed Methane Indicators and Basin Evaluation", presented at SPE Asia Pacific Oil and Gas Conference and Exhibit, Perth, Australia, 18-20 October, 2004, SPE 88630, Advanced Resources International, Inc. on behalf of Hadiyanto, Indonesian Ministry of Energy and Mineral Resources, Directorate General of Geology and Mineral Resources.



Study Phase - Completed
From February 2007 to April 2007, an initial study to evaluate the resources and describe the field development plan for commercial production for coalbed methane was completed for the Sekayu Block located in the South Sumatra Basin, Indonesia. A cooperation contract was submitted to the Government of Indonesia's Executive Agency for Upstream Oil and Natural Gas Activities ("BPMigas"), for production sharing on the Sekayu Block which is in close proximity to gas transmission lines providing access to markets on Java and Singapore. BPMigas awarded a Production Sharing Contract ("PSC") for exploration and development of coalbed methane on the Sekayu Block ("Sekayu PSC") on May 27, 2008. The Sekayu PSC marked the first time the Government of Indonesia awarded a PSC for coalbed methane in Indonesia under its new framework for development of unconventional resources and initiated the country's rapidly emerging multi-basin coalbed methane industry.



Regional Geology of the South Sumatra Basin
Regionally, South Sumatra Basin is situated in the southern part of Sumatra Island, and is part of a Tertiary back-arc basin series. The Muara Enim Formation is the principal target of coalbed methane exploration and production. Thickness of this formation in the area is approximately 500 to 700 meters, about 15% of which is coal in seams that are widely distributed vertically and laterally. The Muara Enim Formation is also exposed in the middle and southwestern parts of the study area.


Geological Cross Section (Pertamina BPPKA, 1996)

South Sumatra Coal Data (DMRI, 2003)

Formation	Muara Enim
Coal Thickness (ft)	120
Depth (ft)	2500
Gas Content (scf/ton)	223
Ash Content (%)	10
Moisture Content (%)	7.5
CO2	3

References

I.B. Sosrowidjojo, A. Saghafi, R&D Centre for Oil and Gas Technology, LEMIGAS, Jakarta, Indonesia, 2009, Development of the first coal seam gas exploration program in Indonesia: Reservoir properties of the Muaraenim Formation, south Sumatra, International Journal of Coal Geology, 79 (2009) 145-156, July 13, 2009.

Darman, H. and Sidi, F.H. (eds.), 2000, An outline of the Geology of IndonesiaIAGI Press.

Ephindo, 2007, Report of CBM Project, South Sumatra Joint Evaluation Medco-Ephindo.

Koesoemadinata, R.P., 2000, Tectono-stratigraphic framework of Tertiary coal deposits of Indonesia. Proceedings the Southeast Asian Coal Geology Conference, 8-16.

Pertamina-BPPKA, 1996, Petroleum Geology of the Indonesian basins.

Pulunggono, A., Haryo, A.S., and Kosum C.G., 1992, Pre-tertiary and Tertiary fault system as frame work of the South Sumatra Basin: a study of SAR maps. Proceedings Indonesian Petroleum Association, 339-360.


DISCLAIMER - Gas in Place resource estimates make no allowance for recovery of the gas. The volumes of gas which may be recoverable will depend on the reservoir characteristics encountered and future economic conditions. These Gas in Place estimates are not compliant with volumes of oil and gas resources classified as "discovered petroleum initially-in-place" within the meaning of the Canadian Oil & Gas Evaluation Handbook (COGE Handbook). The term "discovered petroleum initially-in-place" is equivalent to discovered resources, and is defined in the COGE Handbook to mean that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. Estimates of Gas in Place do not reflect volumes that are demonstrated as being commercially or technically recoverable. Even if commercially or technically recoverable, a significant recovery factor would be applied to these volumes to determine estimates of volumes of proved reserves. Accordingly, these estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. The methodology for estimating Gas in Place may also be different than the methodology and guidelines used by the Society of Petroleum Engineers.

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^[1] Note: these resource estimates are based on extensive surface and subsurface data available for basic CBM parameters, such as coal thickness, depth, rank, and other coal properties derived from coal exploration coreholes, deep petroleum exploration well logs, measured coal outcrop sections, and laboratory data. No significant CBM drill testing has been done on these basis to derive these CBM resource estimates. Therefore, due to the lack of detailed CBM specific data for reservoir properties, we note these estimates only delineate potential CBM in place.