We have been in the development stage, and to date our activities have mainly included initial organization, capital formation, acquisition of mineral leases and/or production sharing contracts giving us the right to explore for, develop, produce and sell oil and gas or coalbed methane, and, notably, we have now drilled our first three wells in Yunnan to total depth. The drilling program will continue as described hereinbelow. In October 2003, we drilled our first well on the Enhong-Laochang coalbed methane block in the Yunnan Province of the PRC. On January 8, 2004, we spudded our second well on the Enhong-Laochang Block and the well reached total depth on February 18, 2004. Our third well in China (the FCY-EH01well) was spudded on March 16, 2004. The well is located on Far East’s Enhong Block in Yunnan Province near Shang Sheshui Village. This is the third of five exploration wells which are expected to be drilled and completed by the early summer of 2004.
On January 25, 2002, we entered into a production sharing contract with the China United Coal Bed Methane Corporation (“CUCBM”). The PRC has granted CUCBM the exclusive authority to explore, develop, and produce coalbed methane in cooperation with foreign enterprises. Our contract with CUCBM gives us authority to jointly explore, develop, produce and sell coal bed methane (CBM) gas in and from a total area of 1,072 square kilometers or 265,000 gross acres (between 643.2 and 1072 net square kilometers or between 159,000 and 265,000 net acres for the Far East Energy share, depending upon the extent to which CUCBM decides to participate) in the Enhong and Laochang areas of Yunnan Province, PRC (whose closest cities are Qujing City and Kunming). The production sharing contract was formally ratified by PRC’s Ministry of Commerce (formerly known as the Ministry of Foreign Trade and Economic Co-operation) on December 30, 2002. Our contract commits us to drill five (5) exploration wells and eight (8) pilot exploration wells in Yunnan province during an initial three-year exploration and production period. Pilot exploration wells refer to the drilling of wells aimed at evaluating, through pilot production of coalbed methane, the potential commercial value of coalbed methane in a specific area. This does not imply the existence of proved reserves.
In addition to the wells we must drill, we are required to make other expenditures over the term of the Yunnan Province production sharing contract:
• Signature fees of $100,000, due on January 1, 2005 (the second anniversary date of the contract); • CUCBM assistance fees and training fees for Chinese personnel each costing $45,000 per year during the exploration phase and $80,000 per year during the development and production phase; • Rental payments on land for exploration of $8,000 per year for the first three years; and
• Salary and benefits paid to CUCBM professionals totaling $18,000 per month.
We have the right to earn a minimum of 60% interest in the joint venture, with CUCBM retaining the remaining 40%. In the event that CUCBM elects to participate at a level less than 40%, their interest will be reduced proportionately, increasing our participating interest. After completion of these exploration and pilot wells, CUCBM has the right to contribute up to forty percent (40%) of further expenditures in return for a 40% interest in the project.
We have another production sharing contract with CUCBM covering the Zhaotong area of Yunnan Province (closest city is Zhaotong City), which has not yet received required government approval. Upon ratification of this contract, we would have the right to earn a minimum 60% interest in the joint venture, with CUCBM retaining the remaining 40%. In the event CUCBM elects to participate at a level less than 40%, their interest will be reduced proportionately, increasing our participating interest on a total of 200 square kilometers or 49,000 gross acres (between 120 and 200 net square kilometers or between 30,000 and 49,000 net acres based on CUCBM’s level of participation). CUCBM notified us on November 11, 2003, that the Zhaotong production sharing contract has not yet been ratified because the Ministry of Land and Resources of China has not yet received ‘the reply on the Yunnan Zhaotong project from the local governmental departments in Zhaotong City’. These responses from governmental departments in Zhaotong city are needed before CUCBM can forward its recommendation for approval to the Ministry of Commerce. CUCBM stated that it ‘will continue to pursue the early approval of the Ministry of Commerce to the Contract of Yunnan Zhaotong CBM project as soon as CUCBM obtains the CBM exploration license of Zhaotong.’ The Zhaotong contract specifies that we can commence an exploration program of two (2) exploratory wells and four (4) pilot wells. If the contract is ratified in early 2004, we believe that the first exploration well in the Zhaotong Block can be spudded in late 2004.
Our wholly owned subsidiary, Far East Montana, Inc. acquired Newark Valley Oil & Gas Inc. (“Newark”), as of December 31, 2002, through a merger which was completed on January 21, 2003. The original agreement terms of the merger agreement, which was dated December 31, 2002, concerning payment and fund raising was amended on June 19, 2003. The merger required that we raise $2,000,000 in financing on or before June 21, 2003. In the Amended Plan of Merger Agreement the requirement to raise $2 million was extended to December 31, 2003. The deadline for the raising of $2 million was extended because Far East appeared unlikely to raise sufficient financing in time to meet the June 21, 2003 deadline. We satisfied this requirement by generating in excess of $5 million in financing through an accredited investors offering that closed on October 7, 2003. As of December 31, 2003, all obligations related to the Newark acquisition were satisfied.
The aforementioned contingency required that the Company use its best efforts to secure additional financing in the amount of $2,000,000 within 120 days from the date of closing (December 31, 2002). In the event such financing was not secured within 120 days of Closing, the Company would have been in default of this Agreement and the transaction would have been subject to rescission. In the event of rescission, the Company would have transferred all of the outstanding equity interests in Newark to North American. North American would have returned to the company the 1,600,000 restricted common shares of the Company. However, North American would have retained any monies tendered pursuant to the Agreement.
The Company has accounted for this transaction as an asset purchase. Due to the significance and uncertainty of this contingency the effect of the transaction was not recorded by the Company until the contingency was resolved in August 2003. The results of operations of Newark have been included in the consolidated financial statements from September 2003 forward.
The aggregate acquisition price was $4,778,000, which included cash in the amount of $600,000, assumption of liabilities of $375,000, ongoing payment of annual lease expense and legal fees, and 1,600,000 shares of the Company’s common stock valued at $3,600,000. The value of the restricted stock was determined based on the market price of the shares on the date of the agreement. Simultaneous to the consummation of the agreement, assets were deemed to be impaired and written down to their fair value. Fair value, which was determined by the valuation of reserves estimated for the assets acquired, indicated a revised carrying value of approximately $1,450,000. Accordingly, an impairment loss of $3,328,000 has been charged to operations in 2003.
As a result of the merger with Newark, we now own undeveloped oil, gas and mineral rights and interests in approximately 147,535.10 net acres (165,000 gross acres) in eastern Montana (Phillips and Valley Counties, Montana) and are in the process of developing plans for an exploratory drilling program which it is hoped will demonstrate the existence of gas in commercial quantities. Between January 28, 2003 and September 30, 2003, the Company acquired an additional 1,643 acres of oil and gas leases in eastern Montana in exchange for our consideration of $ 15,690. These leases are contiguous or nearly contiguous with the leases already acquired in the Newark Valley Oil & Gas merger. Revenue is not expected to be generated from the Montana venture until 2005. Acquired acreage is subject to royalty and overriding royalty interest ranging from 14 to 18%.
In addition to the two production sharing contracts with CUCBM, on March 19, 2003, we entered into a Memorandum of Understanding (“MOU”) with a Conoco Phillips subsidiary, Phillips China Inc., which sets forth the terms and conditions of an agreement for our acquisition of a net undivided forty percent (40%) of Phillips’ seventy percent (70%) interest in both the Shouyang PSC (near Taiyuan City) and the Qinnan PSC (near Jincheng and Qinshui). On July 17, 2003, we signed two Farmout Agreements with Phillips on the Qinnan and Shouyang CBM blocks in Shanxi Province, P.R.C. and also signed an Assignment Agreement on the two blocks. These agreements formalized our acquisition of an undivided forty percent (40%) working interest from Phillips’ (70%) interest, with CUCBM retaining the remaining thirty percent (30%). The Assignment Agreement and appropriate amendments to the PSCs, substituting Far East Energy for Phillips China as the principal party and Operator was approved by CUCBM on March 15, 2004 and final ratification was received from the PRC’s Ministry of Commerce on March 22, 2004.
The Farmout Agreements require that we fracture stimulate and production test three exploration wells that were drilled by Phillips China, and pay 100% of the cost for these tests (we will later recover the other working interest participants’ share of these costs if they elect to participate after the completion
of Phase 2 as described below). Upon the satisfactory completion of the fracing and testing, which we expect to begin in June or July now that the Ministry of Commerce has provided ratification, we have the option to extend into the second phase of exploration by drilling three (3) additional wells. We estimate the cost of drilling these wells to approximate $1.5 million if the wells are vertical wells and $3 million if these wells are drilled horizontally. Our best estimate for the cost of the average horizontal well, assuming we eventually move into actual development, is about $800,000 per well; but we have estimated the cost of these first three horizontal wells at $1 million apiece to cover contingencies and problems that may arise as we first employ horizontal technology in these fields. In the event we decide to extend into the second phase, we will be responsible for 100% of the costs of exploration and the drilling of three (3) second phase wells.. In addition to the wells we must drill, we are required to make other expenditures over the term of these Farmout Agreements, including the following:
• Signature fees of $300,000, payable within 30 days after the approval of the first overall development plan; • Training fees of $120,000 per year during the exploration phase and $300,000 per year during the development and production phase; • CUCBM assistance fees of $100,000 per year during the exploration phase and $240,000 per year during the development and production phase; • Rental payments on land for exploration totaling $56,000 per year for the first three years; and • Salary and benefits to CUCBM professionals totaling $180,000 per year.
In the event we successfully complete the second phase, Phillips China will have the option to elect to either retain its net undivided thirty percent (30%) participating interest, or take a five percent (5%) overriding royalty interest (“ORRI”) on the contractor’s overall Participating Interest share under the PSCs. The ORRI will be capped at five percent (5%) of the current contractor’s seventy percent (70%) Participating Interest, or a three and a half percent (3.5%) ORRI on a one hundred percent (100%) interest basis. After the second phase, CUCBM will also have the option to elect to participate as a working interest partner for anywhere from a net undivided participating interest of zero to thirty percent (30%). Under the terms of the Farmout Agreement, within thirty (30) days of final approval of the Assignment by the Ministry of Commerce, we must post a $1,000,000 bank guarantee or surety bond to act as a work performance guarantee covering all aspects of the evaluation and work program to test the three existing wells, which the Company is attempting to obtain now. We estimate the cost of a surety bond to be in the range of $200,000. Alternatively, the Company may place $1,000,000 in an interest-bearing escrow account in order to avoid the unrecoverable expense of a surety bond.
To generate revenue in China prior to the point at which production reaches pipeline quantities, we may elect to construct liquefied natural gas (LNG) facilities on our properties. However, we believe an LNG company may decide to construct such facilities at their own cost. This would allow gas to be produced and sold in the period before we achieve production in sufficient quantities to justify constructing short connecting pipelines to the Shangjing II and West-East pipelines in the Shanxi Province, or before a pipeline or other offtake facility is operational in the Yunnan Province. A 100 ton/day LNG facility, which would absorb
approximately 5 million cubic feet of gas per day, would cost $10-15 million to construct. A 1000 LNG ton/day facility capable of absorbing 50 million cubic feet of gas per day would cost approximately $75 million. Again, while we may opt to construct LNG facilities, it is quite possible that an LNG concern may decide to construct such facilities near our properties at their own cost. We may construct pipelines to move gas from our fields to either municipalities or other pipelines. We estimate the cost to construct a pipeline in the Enhong and Laochang areas to be approximately $28 million. Our farmout agreement from ConocoPhillips provides us with rights to two separate blocks; the Shouyang block, approximately 40 km south of the Shangjing II Pipeline to Beijing, and the Qinnan block, approximately 10 km north of the West-East Pipeline to Shanghai. We estimate the cost to construct pipeline connections from the Shouyang and Qinnan blocks to the Shangjing II and West-East Pipelines, respectively, to be approximate $63 million. We are delaying any decisions regarding the construction of LNG facilities or pipelines until such time as significant gas volumes are achieved. We believe this delay may allow us to avoid construction costs to the extent other entities (attracted by our gas), have constructed, are constructing or are planning to construct, such facilities.
Production of Coalbed Methane Gas
Our primary focus is on the development of coalbed methane gas in China. For reference purposes, it is noteworthy that eight to ten percent of all current natural gas production in the United States comes from coal beds, or underground coal seams.
Natural gas is basically methane gas. In fact, coal can contain 3-6 times the natural gas per ton of rock that a conventional natural gas reservoir contains assuming that both reservoirs have comparable pressures. Coalbed methane exploration and production involves drilling into a known coal deposit and extracting the gas that is contained in the coal.
Coal is formed from ancient environments rich in plant life such as swamps, wetlands and marshes. Hundreds of millions of years ago, massive earth movements and geologic events slowly covered up these environments. During the time (millions of years) when the coal is formed (coalification), large amounts of gas are also generated and trapped within the internal surfaces (pores) of the coal. Many coal beds are at relatively shallow depths (less than 1,500 meters). Water permeates coal beds and creates enough pressure to seal the gas within the pores. Drilling into the coal and dewatering (pumping out) the coalbed allows the gas to escape and be gathered.
Most coal beds contain gas. The gas adheres to the microscopic surfaces of the coal. This is called adsorption (meaning on the surface, not to be confused with absorption, which means to be inside of something). On a molecular level, the gas molecules attach to the coal’s internal microscopic pores. Since coal is also basically carbon, the attraction of the gas to the solid is very natural.
Even after a coalbed has been identified as containing a commercial quantity of gas, a remaining crucial factor is to be able to retrieve the gas from the coal. This requires that the coal have sufficient permeability, which means that the gas can migrate, or flow, through the coal to the gas well that has entered the coal seam. Permeability is based upon how many fractures, or
cleats, the coal has and how close they are to each other. The more cleats coal has, the better the coal’s permeability.
Gas within coal beds becomes mobile primarily through the flow mechanism of the coal, which is from the cleats. Gas is stored in the micropores of the coal. When the water in the coal seam is produced, the pressure in the coal cleat is reduced; gas is released and diffuses into the cleats. Gas flows to the well bore through the cleat system as well as any of the other cracks, crevices and fractures that the coal bed has. The looser the particles and the more spaces, fractures, cracks or air space a solid has the easier it is for something to flow through it. Hence if a reservoir has a high permeability, the better the production will be.
Coal seams have many different characteristics. You could have an unacceptably low permeability seam, but with enough thickness, the otherwise deficient permeability would be overcome. In this case, the gas would flow out slowly, but because the coal seam is thick, more of the slow flowing gas would be produced since you have a thick area from which to collect the gas.
Coal Ranking
Methane or natural gas is contained in all ranks of coal. The most gas is contained in the highest rank coal, which is called anthracite. Unfortunately anthracite has very low permeability. Semi-anthracite coal typically has higher quantities of gas than anthracite coal, but may still contain significant cleats (fractures) as well, making it more permeable. Far East Energy’s ConocoPhillips project is semi-anthracite coal that has a favorable cleat structure, which should make the permeability favorable.
The next lesser coal rank is bituminous coal that contains less gas per ton but usually has a good cleat structure, which allows for better flow or permeability of the gas through the coal. Far East’s other major projects, Enhong and Laochang have bituminous and semi-anthracite coal.
Isotherm Tests
Isotherm tests are lab tests that identify how much gas can be released from a ton of coal at various temperature and pressure levels. These tests provide important information on the saturation level of the coal. All three of Far East’s projects have produced favorable isotherm tests meaning saturation levels are favorable. In fact, gas content from the Shanxi Project on the Qinnan and Shouyang blocks in China compares favorably with that of typical coal from the San Juan Basin and Black Warrior Basin – both prolific U.S. CBM basins.
On January 25, 2002, we entered into a production sharing contract with the China United Coal Bed Methane Corporation (“CUCBM”). The PRC has granted CUCBM the exclusive authority to explore, develop, and produce coalbed methane in cooperation with foreign enterprises. Our contract with CUCBM gives us authority to jointly explore, develop, produce and sell coal bed methane (CBM) gas in and from a total area of 1,072 square kilometers or 265,000 gross acres (between 643.2 and 1072 net square kilometers or between 159,000 and 265,000 net acres for the Far East Energy share, depending upon the extent to which CUCBM decides to participate) in the Enhong and Laochang areas of Yunnan Province, PRC (whose closest cities are Qujing City and Kunming). The production sharing contract was formally ratified by PRC’s Ministry of Commerce (formerly known as the Ministry of Foreign Trade and Economic Co-operation) on December 30, 2002. Our contract commits us to drill five (5) exploration wells and eight (8) pilot exploration wells in Yunnan province during an initial three-year exploration and production period. Pilot exploration wells refer to the drilling of wells aimed at evaluating, through pilot production of coalbed methane, the potential commercial value of coalbed methane in a specific area. This does not imply the existence of proved reserves.
In addition to the wells we must drill, we are required to make other expenditures over the term of the Yunnan Province production sharing contract:
• Signature fees of $100,000, due on January 1, 2005 (the second anniversary date of the contract); • CUCBM assistance fees and training fees for Chinese personnel each costing $45,000 per year during the exploration phase and $80,000 per year during the development and production phase; • Rental payments on land for exploration of $8,000 per year for the first three years; and
• Salary and benefits paid to CUCBM professionals totaling $18,000 per month.
We have the right to earn a minimum of 60% interest in the joint venture, with CUCBM retaining the remaining 40%. In the event that CUCBM elects to participate at a level less than 40%, their interest will be reduced proportionately, increasing our participating interest. After completion of these exploration and pilot wells, CUCBM has the right to contribute up to forty percent (40%) of further expenditures in return for a 40% interest in the project.
We have another production sharing contract with CUCBM covering the Zhaotong area of Yunnan Province (closest city is Zhaotong City), which has not yet received required government approval. Upon ratification of this contract, we would have the right to earn a minimum 60% interest in the joint venture, with CUCBM retaining the remaining 40%. In the event CUCBM elects to participate at a level less than 40%, their interest will be reduced proportionately, increasing our participating interest on a total of 200 square kilometers or 49,000 gross acres (between 120 and 200 net square kilometers or between 30,000 and 49,000 net acres based on CUCBM’s level of participation). CUCBM notified us on November 11, 2003, that the Zhaotong production sharing contract has not yet been ratified because the Ministry of Land and Resources of China has not yet received ‘the reply on the Yunnan Zhaotong project from the local governmental departments in Zhaotong City’. These responses from governmental departments in Zhaotong city are needed before CUCBM can forward its recommendation for approval to the Ministry of Commerce. CUCBM stated that it ‘will continue to pursue the early approval of the Ministry of Commerce to the Contract of Yunnan Zhaotong CBM project as soon as CUCBM obtains the CBM exploration license of Zhaotong.’ The Zhaotong contract specifies that we can commence an exploration program of two (2) exploratory wells and four (4) pilot wells. If the contract is ratified in early 2004, we believe that the first exploration well in the Zhaotong Block can be spudded in late 2004.
Our wholly owned subsidiary, Far East Montana, Inc. acquired Newark Valley Oil & Gas Inc. (“Newark”), as of December 31, 2002, through a merger which was completed on January 21, 2003. The original agreement terms of the merger agreement, which was dated December 31, 2002, concerning payment and fund raising was amended on June 19, 2003. The merger required that we raise $2,000,000 in financing on or before June 21, 2003. In the Amended Plan of Merger Agreement the requirement to raise $2 million was extended to December 31, 2003. The deadline for the raising of $2 million was extended because Far East appeared unlikely to raise sufficient financing in time to meet the June 21, 2003 deadline. We satisfied this requirement by generating in excess of $5 million in financing through an accredited investors offering that closed on October 7, 2003. As of December 31, 2003, all obligations related to the Newark acquisition were satisfied.
The aforementioned contingency required that the Company use its best efforts to secure additional financing in the amount of $2,000,000 within 120 days from the date of closing (December 31, 2002). In the event such financing was not secured within 120 days of Closing, the Company would have been in default of this Agreement and the transaction would have been subject to rescission. In the event of rescission, the Company would have transferred all of the outstanding equity interests in Newark to North American. North American would have returned to the company the 1,600,000 restricted common shares of the Company. However, North American would have retained any monies tendered pursuant to the Agreement.
The Company has accounted for this transaction as an asset purchase. Due to the significance and uncertainty of this contingency the effect of the transaction was not recorded by the Company until the contingency was resolved in August 2003. The results of operations of Newark have been included in the consolidated financial statements from September 2003 forward.
The aggregate acquisition price was $4,778,000, which included cash in the amount of $600,000, assumption of liabilities of $375,000, ongoing payment of annual lease expense and legal fees, and 1,600,000 shares of the Company’s common stock valued at $3,600,000. The value of the restricted stock was determined based on the market price of the shares on the date of the agreement. Simultaneous to the consummation of the agreement, assets were deemed to be impaired and written down to their fair value. Fair value, which was determined by the valuation of reserves estimated for the assets acquired, indicated a revised carrying value of approximately $1,450,000. Accordingly, an impairment loss of $3,328,000 has been charged to operations in 2003.
As a result of the merger with Newark, we now own undeveloped oil, gas and mineral rights and interests in approximately 147,535.10 net acres (165,000 gross acres) in eastern Montana (Phillips and Valley Counties, Montana) and are in the process of developing plans for an exploratory drilling program which it is hoped will demonstrate the existence of gas in commercial quantities. Between January 28, 2003 and September 30, 2003, the Company acquired an additional 1,643 acres of oil and gas leases in eastern Montana in exchange for our consideration of $ 15,690. These leases are contiguous or nearly contiguous with the leases already acquired in the Newark Valley Oil & Gas merger. Revenue is not expected to be generated from the Montana venture until 2005. Acquired acreage is subject to royalty and overriding royalty interest ranging from 14 to 18%.
In addition to the two production sharing contracts with CUCBM, on March 19, 2003, we entered into a Memorandum of Understanding (“MOU”) with a Conoco Phillips subsidiary, Phillips China Inc., which sets forth the terms and conditions of an agreement for our acquisition of a net undivided forty percent (40%) of Phillips’ seventy percent (70%) interest in both the Shouyang PSC (near Taiyuan City) and the Qinnan PSC (near Jincheng and Qinshui). On July 17, 2003, we signed two Farmout Agreements with Phillips on the Qinnan and Shouyang CBM blocks in Shanxi Province, P.R.C. and also signed an Assignment Agreement on the two blocks. These agreements formalized our acquisition of an undivided forty percent (40%) working interest from Phillips’ (70%) interest, with CUCBM retaining the remaining thirty percent (30%). The Assignment Agreement and appropriate amendments to the PSCs, substituting Far East Energy for Phillips China as the principal party and Operator was approved by CUCBM on March 15, 2004 and final ratification was received from the PRC’s Ministry of Commerce on March 22, 2004.
The Farmout Agreements require that we fracture stimulate and production test three exploration wells that were drilled by Phillips China, and pay 100% of the cost for these tests (we will later recover the other working interest participants’ share of these costs if they elect to participate after the completion
of Phase 2 as described below). Upon the satisfactory completion of the fracing and testing, which we expect to begin in June or July now that the Ministry of Commerce has provided ratification, we have the option to extend into the second phase of exploration by drilling three (3) additional wells. We estimate the cost of drilling these wells to approximate $1.5 million if the wells are vertical wells and $3 million if these wells are drilled horizontally. Our best estimate for the cost of the average horizontal well, assuming we eventually move into actual development, is about $800,000 per well; but we have estimated the cost of these first three horizontal wells at $1 million apiece to cover contingencies and problems that may arise as we first employ horizontal technology in these fields. In the event we decide to extend into the second phase, we will be responsible for 100% of the costs of exploration and the drilling of three (3) second phase wells.. In addition to the wells we must drill, we are required to make other expenditures over the term of these Farmout Agreements, including the following:
• Signature fees of $300,000, payable within 30 days after the approval of the first overall development plan; • Training fees of $120,000 per year during the exploration phase and $300,000 per year during the development and production phase; • CUCBM assistance fees of $100,000 per year during the exploration phase and $240,000 per year during the development and production phase; • Rental payments on land for exploration totaling $56,000 per year for the first three years; and • Salary and benefits to CUCBM professionals totaling $180,000 per year.
In the event we successfully complete the second phase, Phillips China will have the option to elect to either retain its net undivided thirty percent (30%) participating interest, or take a five percent (5%) overriding royalty interest (“ORRI”) on the contractor’s overall Participating Interest share under the PSCs. The ORRI will be capped at five percent (5%) of the current contractor’s seventy percent (70%) Participating Interest, or a three and a half percent (3.5%) ORRI on a one hundred percent (100%) interest basis. After the second phase, CUCBM will also have the option to elect to participate as a working interest partner for anywhere from a net undivided participating interest of zero to thirty percent (30%). Under the terms of the Farmout Agreement, within thirty (30) days of final approval of the Assignment by the Ministry of Commerce, we must post a $1,000,000 bank guarantee or surety bond to act as a work performance guarantee covering all aspects of the evaluation and work program to test the three existing wells, which the Company is attempting to obtain now. We estimate the cost of a surety bond to be in the range of $200,000. Alternatively, the Company may place $1,000,000 in an interest-bearing escrow account in order to avoid the unrecoverable expense of a surety bond.
To generate revenue in China prior to the point at which production reaches pipeline quantities, we may elect to construct liquefied natural gas (LNG) facilities on our properties. However, we believe an LNG company may decide to construct such facilities at their own cost. This would allow gas to be produced and sold in the period before we achieve production in sufficient quantities to justify constructing short connecting pipelines to the Shangjing II and West-East pipelines in the Shanxi Province, or before a pipeline or other offtake facility is operational in the Yunnan Province. A 100 ton/day LNG facility, which would absorb
approximately 5 million cubic feet of gas per day, would cost $10-15 million to construct. A 1000 LNG ton/day facility capable of absorbing 50 million cubic feet of gas per day would cost approximately $75 million. Again, while we may opt to construct LNG facilities, it is quite possible that an LNG concern may decide to construct such facilities near our properties at their own cost. We may construct pipelines to move gas from our fields to either municipalities or other pipelines. We estimate the cost to construct a pipeline in the Enhong and Laochang areas to be approximately $28 million. Our farmout agreement from ConocoPhillips provides us with rights to two separate blocks; the Shouyang block, approximately 40 km south of the Shangjing II Pipeline to Beijing, and the Qinnan block, approximately 10 km north of the West-East Pipeline to Shanghai. We estimate the cost to construct pipeline connections from the Shouyang and Qinnan blocks to the Shangjing II and West-East Pipelines, respectively, to be approximate $63 million. We are delaying any decisions regarding the construction of LNG facilities or pipelines until such time as significant gas volumes are achieved. We believe this delay may allow us to avoid construction costs to the extent other entities (attracted by our gas), have constructed, are constructing or are planning to construct, such facilities.
Production of Coalbed Methane Gas
Our primary focus is on the development of coalbed methane gas in China. For reference purposes, it is noteworthy that eight to ten percent of all current natural gas production in the United States comes from coal beds, or underground coal seams.
Natural gas is basically methane gas. In fact, coal can contain 3-6 times the natural gas per ton of rock that a conventional natural gas reservoir contains assuming that both reservoirs have comparable pressures. Coalbed methane exploration and production involves drilling into a known coal deposit and extracting the gas that is contained in the coal.
Coal is formed from ancient environments rich in plant life such as swamps, wetlands and marshes. Hundreds of millions of years ago, massive earth movements and geologic events slowly covered up these environments. During the time (millions of years) when the coal is formed (coalification), large amounts of gas are also generated and trapped within the internal surfaces (pores) of the coal. Many coal beds are at relatively shallow depths (less than 1,500 meters). Water permeates coal beds and creates enough pressure to seal the gas within the pores. Drilling into the coal and dewatering (pumping out) the coalbed allows the gas to escape and be gathered.
Most coal beds contain gas. The gas adheres to the microscopic surfaces of the coal. This is called adsorption (meaning on the surface, not to be confused with absorption, which means to be inside of something). On a molecular level, the gas molecules attach to the coal’s internal microscopic pores. Since coal is also basically carbon, the attraction of the gas to the solid is very natural.
Even after a coalbed has been identified as containing a commercial quantity of gas, a remaining crucial factor is to be able to retrieve the gas from the coal. This requires that the coal have sufficient permeability, which means that the gas can migrate, or flow, through the coal to the gas well that has entered the coal seam. Permeability is based upon how many fractures, or
cleats, the coal has and how close they are to each other. The more cleats coal has, the better the coal’s permeability.
Gas within coal beds becomes mobile primarily through the flow mechanism of the coal, which is from the cleats. Gas is stored in the micropores of the coal. When the water in the coal seam is produced, the pressure in the coal cleat is reduced; gas is released and diffuses into the cleats. Gas flows to the well bore through the cleat system as well as any of the other cracks, crevices and fractures that the coal bed has. The looser the particles and the more spaces, fractures, cracks or air space a solid has the easier it is for something to flow through it. Hence if a reservoir has a high permeability, the better the production will be.
Coal seams have many different characteristics. You could have an unacceptably low permeability seam, but with enough thickness, the otherwise deficient permeability would be overcome. In this case, the gas would flow out slowly, but because the coal seam is thick, more of the slow flowing gas would be produced since you have a thick area from which to collect the gas.
Coal Ranking
Methane or natural gas is contained in all ranks of coal. The most gas is contained in the highest rank coal, which is called anthracite. Unfortunately anthracite has very low permeability. Semi-anthracite coal typically has higher quantities of gas than anthracite coal, but may still contain significant cleats (fractures) as well, making it more permeable. Far East Energy’s ConocoPhillips project is semi-anthracite coal that has a favorable cleat structure, which should make the permeability favorable.
The next lesser coal rank is bituminous coal that contains less gas per ton but usually has a good cleat structure, which allows for better flow or permeability of the gas through the coal. Far East’s other major projects, Enhong and Laochang have bituminous and semi-anthracite coal.
Isotherm Tests
Isotherm tests are lab tests that identify how much gas can be released from a ton of coal at various temperature and pressure levels. These tests provide important information on the saturation level of the coal. All three of Far East’s projects have produced favorable isotherm tests meaning saturation levels are favorable. In fact, gas content from the Shanxi Project on the Qinnan and Shouyang blocks in China compares favorably with that of typical coal from the San Juan Basin and Black Warrior Basin – both prolific U.S. CBM basins.
Dewatering
To produce methane from coalbeds, water must be removed from the coal seams to decrease reservoir pressure and release the gas. After desorption (from the coal matrix, the gas diffuses through the coalbed’s cleats and fractures toward the well bore. Substantial dewatering of the coalbed is required initially. Water production declines as methane gas production increases. Produced water disposal presents major economic and environmental challenges for operators. These costs alone can determine the feasibility of coalbed methane projects. Additionally, the length of time required to complete the dewatering process will also impact the economic results of these coalbed methane projects.
Horizontal Drilling
A potentially significant development is the ability to engage in horizontal drilling. This would allow a well bore to be in contact with hundreds of feet of coal since the drill stem, when it hits the coal seam, is redirected from a downward angle to a horizontal plane and simply follows the coal bed for hundreds of feet (sometimes 500 feet) in various directions. This access would change the dynamics of the gas recovery dramatically. In a normal well you would have to drill an 8-inch hole contacting and hollowing out a coal seam 10 feet thick. With horizontal drilling, you could go directly along the coal seam for hundreds of feet or more in many directions, increasing your contact area. Of course, horizontal wells are more costly than traditional wells, but offer significantly more potential in reduced surface facilities and increased production rate.
The benefits of horizontal drilling for coalbed methane are far more profound than for conventional oil and gas wells because of the greater exposure of the coalface to flow. This allows significantly more gas production on a daily basis than can be achieved with conventional vertical stimulation techniques. We will consider utilizing horizontal drilling if it successfully concludes the exploratory phases of our contracts.
Competition
The Company will be operating in the competitive area of natural gas exploration, development and production in China and Montana. The Company’s competitors include major integrated oil and gas companies and substantial independent energy companies, many of which possess greater financial and other resources than the Company. We conduct our operations in the competitive area of natural gas exploration, development and production in China and Montana.
Regulations
The Company’s operations will be subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations require the acquisition of a permit before drilling
commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for any pollution resulting from the Company’s operations. The cost of complying with these environmental laws is expected to be $500 per well per year.
Market for Gas
In 2003 China became the world’s second largest user of petroleum (behind the United States). With the vast natural resources, China is also becoming one of the largest importers of oil and gas in the world. Demand is project to outpace the rest of the world over the next decade. The State Council of China, the chief administrative body of the People’s Republic of China, is currently advocating a four-fold increase in natural gas usage by 2010. Additionally, China has mandated that natural gas replace coal as a major source of electricity by the 2008 Summer Olympics being held in Beijing.
To support China’s use of natural gas, the Chinese government has provided incentives to stimulate the development of CBM. Included in these incentives are:
• Exempting CBM development from import duties and import-related duties; • The first two years of CBM development will be subject to an income tax “holiday” from the government’s 33.3% income tax, followed by, in years three, four, and five, taxing at one-half the normal income tax rate; • CBM projects with foreign companies will be subject to a reduced value-added tax, at 5%, compared to the standard 13% to 17% VAT for conventional gas companies; and • There will be market pricing on natural gas sales.
Our competitors include major integrated oil and gas companies and substantial independent energy companies, many of which possess greater financial and other resources. Any sales we secure could be adversely affected by a sustained economic recession in China. As our operations and end user markets are primarily in China, a sustained economic recession could result in lower demand or lower prices for the natural gas to be produced by the Company. However, with government mandates requiring reduced dependency on coal and increased usage of natural gas, demand appears likely to grow steadily, at least in the near term.
Employees
As of March 26, 2004, the Company had a total of sixteen (16) employees, all of which were employed full-time.
To produce methane from coalbeds, water must be removed from the coal seams to decrease reservoir pressure and release the gas. After desorption (from the coal matrix, the gas diffuses through the coalbed’s cleats and fractures toward the well bore. Substantial dewatering of the coalbed is required initially. Water production declines as methane gas production increases. Produced water disposal presents major economic and environmental challenges for operators. These costs alone can determine the feasibility of coalbed methane projects. Additionally, the length of time required to complete the dewatering process will also impact the economic results of these coalbed methane projects.
Horizontal Drilling
A potentially significant development is the ability to engage in horizontal drilling. This would allow a well bore to be in contact with hundreds of feet of coal since the drill stem, when it hits the coal seam, is redirected from a downward angle to a horizontal plane and simply follows the coal bed for hundreds of feet (sometimes 500 feet) in various directions. This access would change the dynamics of the gas recovery dramatically. In a normal well you would have to drill an 8-inch hole contacting and hollowing out a coal seam 10 feet thick. With horizontal drilling, you could go directly along the coal seam for hundreds of feet or more in many directions, increasing your contact area. Of course, horizontal wells are more costly than traditional wells, but offer significantly more potential in reduced surface facilities and increased production rate.
The benefits of horizontal drilling for coalbed methane are far more profound than for conventional oil and gas wells because of the greater exposure of the coalface to flow. This allows significantly more gas production on a daily basis than can be achieved with conventional vertical stimulation techniques. We will consider utilizing horizontal drilling if it successfully concludes the exploratory phases of our contracts.
Competition
The Company will be operating in the competitive area of natural gas exploration, development and production in China and Montana. The Company’s competitors include major integrated oil and gas companies and substantial independent energy companies, many of which possess greater financial and other resources than the Company. We conduct our operations in the competitive area of natural gas exploration, development and production in China and Montana.
Regulations
The Company’s operations will be subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations require the acquisition of a permit before drilling
commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for any pollution resulting from the Company’s operations. The cost of complying with these environmental laws is expected to be $500 per well per year.
Market for Gas
In 2003 China became the world’s second largest user of petroleum (behind the United States). With the vast natural resources, China is also becoming one of the largest importers of oil and gas in the world. Demand is project to outpace the rest of the world over the next decade. The State Council of China, the chief administrative body of the People’s Republic of China, is currently advocating a four-fold increase in natural gas usage by 2010. Additionally, China has mandated that natural gas replace coal as a major source of electricity by the 2008 Summer Olympics being held in Beijing.
To support China’s use of natural gas, the Chinese government has provided incentives to stimulate the development of CBM. Included in these incentives are:
• Exempting CBM development from import duties and import-related duties; • The first two years of CBM development will be subject to an income tax “holiday” from the government’s 33.3% income tax, followed by, in years three, four, and five, taxing at one-half the normal income tax rate; • CBM projects with foreign companies will be subject to a reduced value-added tax, at 5%, compared to the standard 13% to 17% VAT for conventional gas companies; and • There will be market pricing on natural gas sales.
Our competitors include major integrated oil and gas companies and substantial independent energy companies, many of which possess greater financial and other resources. Any sales we secure could be adversely affected by a sustained economic recession in China. As our operations and end user markets are primarily in China, a sustained economic recession could result in lower demand or lower prices for the natural gas to be produced by the Company. However, with government mandates requiring reduced dependency on coal and increased usage of natural gas, demand appears likely to grow steadily, at least in the near term.
Employees
As of March 26, 2004, the Company had a total of sixteen (16) employees, all of which were employed full-time.
