Continental Energy Corporation (www.continentalenergy.com) (Continental or the “Company”) is a Dallas, Texas based independent oil and gas exploration company focused on large commercial discoveries in Indonesia. Its current prospect inventory is in the prolific Bengara-II Block, which is known for still unexploited oil and gas reserves. The Company recently signed an agreement with CNPCHK (Indonesia) Limited (CNPC) to develop Bengara-II Block. CNPC is a wholly owned subsidiary of Hong Kong listed China National Petroleum Company (Hong Kong) Limited. Continental is a Canadian issuer listed on the OTC Bulletin Board and is trading under the symbol CPPXF.

Much of Continental’s current focus is the exploration and development of its interests in the Bengara-II Block. CNPC together with its partners Continental and Resources Company (GeoPetro) has exclusive petroleum exploration and production rights to this nine hundred thousand-acre block, located in East Kalimantan, Indonesia. The East Kalimantan region (together with Aceh, Irian Jaya, Java and Sumatra) is one of the primary oil rich areas in Indonesia and currently has several oil producing basins. Its main basins include the Tarakan Basin and the Kutei Basin. The Bengara-II is located in the Tarakan Basin.

The main oil companies in East Kalimantan include Exxon/Mobil (NYSE: XOM), Total-Fina-Elf partnership, China National Offshore Oil Corp. (HK/NYSE: CNOOC), Arco (a subsidiary of British Petroleum – LSE: BP). Arco’s main focus is in smaller fields and Unocal (a Chevron company – NYSE: CVX). Unocal’s West Seno field, offshore from East Kalimantan, currently produces 14,000 bpd oil and 18 million cubic feet (MMcf) per day gas. This field is expected to produce 60,000 barrels per day of oil and 150 million cubic feet of gas per day on completion of the second phase. The region is widely believed to be highly prolific with enough reserves to host an economic oil and gas operation.

Continental can be viewed as an investment opportunity that provides speculative exposure to the oil and gas sector in Indonesia. As much of its main fields mature, future Indonesian oil output is expected to come from smaller oil fields. Economics of smaller fields generally suit smaller companies with lean cost structures, as they can remain profitable even with a relatively lower production. Continental represents the new generation of oil and gas companies in Indonesia.

Despite the relatively volatile and risky political environment as well as generally mature oil fields, Indonesia continues to attract investments from foreign companies to develop its oil resources. High oil prices (which make exploration and development worthwhile) and its proximity to fast growing Chinese and Indian economies are viewed as the main reasons behind the continued interest. The industry further benefits from its ongoing reforms instigated by the Indonesian government. Continental benefits from these reforms with favorable contract terms as well as the assurance of minimum state interference.

The recent agreement with CNPC further reduces the risk profile of Continental. CNPC is expected to develop the Bengara-II Block following an agreement with the Company and has acquired 70% of the Bengara-II project.

In October 2006, Continental announced the farm out of 70% stake in Continental-GeoPetro (Bengara-II) Limited (CGB2), holder of the Bengara-II Production Sharing Contract (PSC) through an earn-in agreement to CNPC. Continental will retain 18% interest in CGB2 and will be engaged in the development of the block. The 70% divestment entails only the CGB2 not Continental, the holding company.

The agreement with CNPC entails the following:

-- CNPC was required to pay an Earning Obligation in cash for US$18,700,000. CNPC has already placed funds into a jointly controlled CGB2 account. These funds will be used exclusively as working capital for the exploration and development of Bengara-II.

-- CNPC shall also provide development loans to CGB2 and carry all of Continental's share of Bengara-II development costs on any oil or gas discoveries made in the amount of US$41,300,000 over and above the Earning Obligation.

-- CNPS shall pay out to Continental a cash bonus of US$3,000,000 on the first commercial oil or gas discovery in Bengara-II.

The agreement with CNPC is a very significant development as it further reduces the risk profile of the Company. It also provides funds to finance the development program. The agreement is in line with Continental’s original strategy of farming out drill ready prospects to larger companies.

Continental has also formed another fully owned subsidiary, TXX Energy Corporation (TXX) to pursue oil and gas exploration and production projects and obtain new exploration leases in the USA. The focus of TXX is to diversify the asset base and establish a presence in oil and gas sector in the USA. The Company is currently evaluating several opportunities in Texas that fit its risk/reward criteria and would provide revenues near-term.

The Company has already identified several interesting properties in the USA and Indonesia and is currently discussing acquisition funding with institutional sources. Continental growth strategy is expected to be both organic and acquisitions. The Company has also engaged oil and gas professionals with long operating experience in Texas to assist its exploration and acquisition endeavors.

Continental’s corporate strategy is to identify oil and gas exploration and development projects in appropriate regions that fit its technical and economic criteria. Once delineated and developed, the Company plans to be engaged in production as well. Continental plans to build its core business in Indonesia and first develop its existing license areas prior to embarking on other opportunities in the region. At present however, Continental is a pure exploration company with no producing fields, as such, the Company is not expected to report revenues in the short term. Its eventual long-term value will depend on its success in acquiring properties that it can add significant value to with production and technology, in a competitive production environment.

Continental’s has a relatively more flexible corporate strategy compared to other junior oil and gas companies engaged in exploration and development. The latter’s business model entails exploration and development of prospects to drill-ready stage and then selling them potentially at a premium to a larger company for subsequent production. Continental meanwhile intends to undertake both development and production, through a farm-out strategy partnering with CNPC.

Continental’s strategy of development followed by the continued involvement in production resonates well with its management track record. The management team has previously worked together and has extensive international oil and gas experience in a number of projects within both developing and developed countries, particularly in Indonesia. They have been involved not only in exploration but also in subsequent production and operations. Companies the senior management has collectively or individually developed include Mobil Oil, Phillips Petroleum, Amoco and Jackson Exploration Inc.

For instance, Mr. Richard McAdoo (President) and Mr. James Eger (Chief Financial Officer) worked together at Phillips Petroleum, Jackson Exploration and Tracer Petroleum. They have worked together in Indonesia as well. We consider the past experience of the management team in working together in considerably challenging environments to be a key factor that would positively contribute to the success of Continental. Their plan to be engaged in both exploration and subsequent production also offers much comfort. The management team has been successful “company makers” and their performance in steering Continental has so far been impressive.

As a part of its corporate strategy, Continental intends to develop its prospects through joint venture partnerships rather than on its own. This strategy is expected to minimize the required resource commitment and exposure to exploration risk. Such partnerships also provide added strength in competing with other oil companies with deep pockets operating in the region. We are encouraged by this prudent strategy as it reduces the risk profile of the Company considerably.

To this end, Continental has already formed CG Xploration Inc., as a 50/50 partnership with GeoPetro Resources Company (GeoPetro), to undertake exploration elsewhere in the Tarakan basin. GeoPetro is an independent oil and gas company headquartered in San Francisco, California with projects in North America, Australia, and Indonesia. Its other projects include Whicher Range Gas Field Project (Australia), Cook Inlet (Alaska), Pinnacle Reef Project (Canada) and Lokern, West Biggs & Madisonville (US). Continental is expected to benefit from GeoPetro’s expertise in the exploration and development of oil and gas reserves in the region.

From the reserve potential perspective, many Indonesian oil-producing basins are considered to be generally mature. This is evident from the falling oil and gas production in Indonesia. Reserves in a mature field do not meet the viability criterion of larger companies due to their considerably high cost bases and larger operating scale. However, smaller companies such as Continental can still remain profitable operating on reserves from smaller fields. In order to remain profitable however, such companies need a focused and technically savvy management. Continental’s focus on forming technical and exploration partnerships leading to the rationalization of financial and other resources augur well for the Company.

The Bengara-II Block is located on the Bulungan River Delta in the province of East Kalimantan on the northeast coast of Borneo. The Block is predominantly onshore but also has some partial offshore exposure astride the Bulungan River Delta. Geologically, the Bengara-II Block lies in the Tarakan basin near major oilfields at Tarakan and Bunyu. The Tarakan Basin has produced in excess of 310 million barrels of oil and 97 billion cubic meters of gas.

The Tarakan basin is one of five Tertiary rifted-margin sedimentary basins making up eastern Borneo on the eastern margin of the broad area of Southeast Asia. The five eastern Borneo basins initially are thought to have developed from a single large depocenter. This was subsequently believed to have separated into distinct features through the imposition of cross-high structures. Several sub-basins or depocenters exist in the Tarakan basin. One of these is the Bulungan sub-basin now occupied at the surface by the Bulungan River delta. The Bengara-II Block lies mostly within the Bulungan basin.

Both oil and natural gas prone hydrocarbon source rocks are widely distributed throughout the sedimentary section found in the Bengara-II Block area. Basin depths and geothermal gradient combine to place many source rocks in thermally mature environments very close to and interbedded with suitable reservoir units. The hydrocarbons in this area were generated from lacustrine, coastal plain and deltaic plain deposits. There is strong geological evidence in the region indicating the presence of high quality petroleum source rocks, sealing formations, and suitable reservoir sands along with organically strong and thermally mature source rocks. The sedimentary conditions in the region are ideal for generating and preserving hydrocarbons. Geology in the Bengara-II Block continues to indicate the existence of hydrocarbons in the region.

The Bengara-II Block area has strong logistics, access and operating conditions, thus making oil exploration and development in the block less challenging. The city of Tarakan with its scheduled air services and seaport provides the transportation logistics while the city of Tanjung Selor located closer to the center of the Block provides a good base for operations. Oil produced in the region can be transported cost effectively by barge to the Pertamina (the National Oil Company) crude oil terminal.

For gas produced in the region, the Bontang LNG gas processing plant is the most promising marketing channel. The plant has capacity to accommodate large commercial discoveries. In addition, there is a methanol plant operating at below capacity located within 70km of the Block at Bunyu Island. The proposed fertilizer plant also offers a strong local market opportunity for gas production in the region.

The Makapan Gas Field

The Makapan field is located midway between the cities of Tanjung Selor and Tarakan, entirely within the Bengara-II PSC contract area in the Bulungan Regency of East Kalimantan. The Makapan field dates its origins from 1998 when a wildcat exploration well was drilled by the German company, Deminex. The well tested an accumulated flow of more than 19.6 MMcf gas per day plus 600 barrels of 54º API condensate. The well was returned to Pertamina without further appraisal drilling despite the discovery of natural gas and condensate due to then depressed oil and gas prices.

The Makapan field development plan is expected to focus on the condensate recovery, LPG extraction and dry gas delivery by pipeline or by CNG ("Compressed Natural Gas") technology to local and regional Indonesian power generation markets and the Bunyu methanol plant. CNG is a new technology being utilized globally as an alternative to using pipelines to bring gas productions to the market. Once sufficient gas reserves have been proven up, the full development of the Makapan field would require the construction of at least one petrochemical plant to utilize dry gas as feedstock or connection to the Indonesian state gas distribution authority ("PGN") planned Kalimantan to Java pipeline.

The Company plans to explore the field utilizing a combination of vertical wells and small clusters of deviated wells drilled from a single surface location. Each of the wellheads would be independently connected to one or more production manifold platforms by Sub Sea flow lines. Gas production facilities would be installed in each production manifold platform. Well flowing pressures are expected to be sufficient to deliver gas to the production manifolds, through the process facilities and onward to the LPG plant without additional compression. Each manifold would contain production treatment equipment as well. Continental expects initial transportation of condensate to be by barge, but plans to seek a separate pipeline should the production be high.

The Makapan Field gas is believed to be "Wet" gas with a high Liquid Petroleum Gas (LPG) fraction. This makes it commercially viable to extract at the wellhead for a third revenue source in addition to the gas and condensate. However, Continental may be required to build a plant to extract LPG employing a cryogenic extraction process. Approximately 80% of the gas entering the LPG plant would be considered market ready and usable. Given the consequent modest capital requirement, the LPG plant is expected to be economically feasible even in a low production environment. The output could be delivered to the market through pipelines or utilizing CNG technology. The capital outlay for a transportation pipeline is estimated to be approximately US$500,000 per kilometer.


The Oil Lake

In addition to the Makapan Field, the southern part of the Bengara Block also has an oil lake, which spans approximately 2 acres of the block. Continental field geology team located the oil lake and at least four steel well casings, believed to be from a circa 1915 oil production operation, still actively leaking oil and water and feeding the oil lake.

Seismic test data in this area indicates that the surface anticline is part of large structure covering an area in excess of 40,000 acres of closure. In recognition of the reserve potential in the Lake, Continental plans to drill test a number of prospective sand units in this structure as part of the Bengara-II exploration program.

Geographically, the two markets with the closest proximity to Continental’s gas production would be the cities of Tanjung Selor and Tarakan. From the consumption viewpoint, Continental can market its expected gas output to the following end-user markets: Bunyu Methanol Plant, Power Generation Markets, Petrochemical Feedstock Markets.

An immediate opportunity exists with the Bunyu Methanol Plant on Bunyu Island. This plant at present is heavily underutilized and its daily production of approximately 20 million cubic feet of gas falls well short of the 65 million cubic feet per day design capacity. Continental has a ready outlet for its expected gas production in this Methanol Plant. The plant can increase its capacity by a further 35 million cubic feet per day without an incremental investment for transportation infrastructure. The existing underwater pipeline has excess capacity and can accommodate a further 15 million cubic feet per day.

The local electricity generation market surrounding the Makapan Field is another strong end-user segment the company would be able to exploit. The power output to satisfy the regional demand is estimated to be approximately 65 megawatts over the next 10 years. The expected gas consumption to generate the forecast energy is 1-2 MMcf per day for every 5 megawatts of electricity. This translates to a potential daily demand of 13-26 MMcf natural gas. The Company has also reached an agreement in principle with the Indonesian state gas distribution utility (PGN) to sell 6 MMcf natural gas per day to power the recently installed electricity generation plant in the Tarakan Island.

From the LPG plant, the dried gas (largely methane possibly mixed some ethane) could be delivered to one or more purpose built petrochemical plants such as a combined ammonia and methanol plant. Continental however will need to establish its reserve potential to demonstrate a 20-year supply. A typical petrochemical complex, such as a combined ammonia and methanol producing plant, would consume 75 MMcf of natural gas per day and would require a Makapan Field gas reserve of 600 Billion Cubic Feet (Bcf), which represents a 20-year supply, to justify construction.

There are two sites under consideration for petrochemical plants. Both sites are approximately the same distance from the center of the Makapan Gas Field development and would require approximately 20 to 30 kilometers of mostly subsea pipeline to access. The first possible plant site is located on the East Kalimantan mainland southeast of the town of Tanjung Selor. A second possible site is located on the southeast coast of the Island of Tarakan. Continental is prepared to undertake the necessary investments to develop pipelines should the Makapan Field proves to have sufficient reserves to service these markets over an extended period.

In addition to the above three markets, there are emerging opportunities for companies engaged in gas production in the Bengara Block II. The proposed 1,100 km pipeline between East Java and East Kalimantan by PGN would open up the rapidly growing Java gas market. The pipeline is expected to be operational in 2008 and will have a transmission capacity of 700 MMcf per day. The pipeline is expected to carry a toll of US$0.89 per thousand cubic feet. PGN has already approached Continental and other gas producers in East Kalimantan about supplying gas to the Java markets. Java has several large-scale industrial customers such as PT Krakatau Steel, fertilizer manufacturer PT Pupuk Kujang. Not surprisingly, the demand for natural gas in Java is expected to increase from 1.48 Bcf per day in 2002 to 2.4 Bcf cubic day by 2010.

The Company has also commenced discussions with PGN regarding the supply of gas to the world’s largest Liquefied Natural Gas (LNG) plant located in Bontang, East Kalimantan. The Bontang’s nine-train production plant has an annual capacity of 24 million metric tons and supplies gas under long term contracts to South Korea and Taiwan. Much of the natural gas feedstock into the Bontang LNG plant is supplied by Vico and Total-Fina-Elf from fields in the Mahakam Delta area. Due to declining gas production from major fields in the Mahakam Delta area together with its increased capacity, the Bontang Plant is expected to seek alternative suppliers, particularly from those operating in the Makapan field. The plant consumes approximately one trillion cubic feet of gas annually.

The availability of diverse and fast growing marketing avenues considerably reduces the risk profile of Continental. The Bengara Block is in close proximity to almost all these key markets. The area also has adequate infrastructure for a fully pledged oil and gas company to operate comfortably, including pipelines, air/sea port services and crude oil terminals. Much of Continental’s risk therefore is related to exploration.

The Company has already determined the most suitable drilling targets by conducting internal geological surveys of the field. The identification of stratigraphic and structural traps and a strong knowledge of sand distribution are the keys to successful exploration within the Block. Nearly 2,200 line kilometers of 2D seismic data available within the Bengara-II Block would facilitate the identification of drilling prospects. Results of the Muara Makapan #1 well have been integrated into this data, providing hard evidence of the generation and entrapment of oil and gas within the Bengara-II Block.

While it is premature to arrive at the full reserve potential at this stage, the exploration work conducted so far indicate a reserve potential of 50 to 200 million barrels. With the 50/50 propensity of source rocks, there appears to be strong possibilities of discovering oil and wet gas as well. This would indicate the potential for multiple gas fields with reserves in the range of 300 billion to 1.2 trillion cubic feet.

Continental has identified 22 drillable prospects and a further two leads within the Bengara Block. This is an unusually high number and is a good indicator of petroleum potential in this region. Many of these prospects are ready to be drilled. The Company has already obtained the necessary approvals for its 2006-2007 drilling program. CNPC has agreed to drill Continental’s top four prospects in the oil prone southern part of the Bengara-II Block. Given below are the costs associated with the first four wells to be drilled in the Bengara-II Block.

Oil


Indonesia is a member of the Organization of Petroleum Exporting Countries (OPEC), the only Southeast Asian country to have membership in the oil cartel. In 2005, Indonesia produced 1.07 bbls/d of oil accounting for 3% of total OPEC production and just over 1% of global production. Indonesia’s oil production is however below the OPEC permitted production. In fact, this is one of the main reasons that prompted Indonesian authorities to embark on private sector participation in developing the country’s petroleum resources.

Oil is one of Indonesia's largest exports and one of the largest sources accounting for approximately 25% of government revenue. Oil exports were instrumental in pulling Indonesia out of recession after the Asian financial crisis of 1997-98. Following its rapid economic development demonstrated by the GDP growth rate, falling inflation and banking sector reforms, the International Monetary Fund (IMF) has concluded its economic assistance program. Now that the country has exited from the supervision of the IMF including its deficit-financing package, the government needs oil revenues even more.

Indonesia’s oil reserves have been on a decline since 1994. Current reserves are at 4.7 billion barrels, a decline of 13% from the 1994 levels. This trend is expected to continue due to maturing oil fields and lack of new investment mostly due to regulatory hurdles and security concerns. With much of the largest and easily accessible deposits having already been developed, Indonesia is trying to persuade oil companies to explore smaller, more remote sites. This has so far been a relatively challenging exercise in the face of growing concerns about security, corruption and local unrest. Indonesian oil production has meanwhile been falling and is currently below its OPEC quota.

A significant portion of Indonesia’s proven oil resources are concentrated onshore. Central Sumatra is the country’s largest oil producing province and is home to the large Duri and Minas oil fields. The northwestern Java, East Kalimantan and the Natuna Sea regions also hold large reserves. Indonesian crude oil varies widely in quality, with most streams having gravities in the 22o to 37o API.

Indonesia’s 2005 production is 26% below its OPEC oil quota of 1.45 million bbl/d. Given its high dependence on oil, falling production and dwindling reserves have been matters of serious concern to the government. Meanwhile, Indonesia’s continued membership in OPEC is also under review as the current administration has expressed an interest in breaking away from the cartel. However a firm decision is yet to be made in this regard.

Despite uncertainties and falling reserves, there are several large oil companies remaining in Indonesia. Since January 2002 however, the Chinese have been the largest offshore oil producer in the country, with CNOOC at the forefront. CNOOC entered the Indonesian oil and gas market with the purchase of nearly all of Repsol-YPF’s assets in Indonesia for $585 million. The company has been on the lookout for further exploration licenses since then. All foreign companies however have a PSC with the national oil company, Pertamina. Continental’s Bengara Block II prospect is also governed by a PSC, and is now 70% owned by CNPC.

Contrary to wide spread belief, Indonesia’s PSCs are not generally unattractive. Indonesian PSCs provide for the recovery of costs for its foreign joint venture partner through the establishment of two production sharing regimes namely “Cost Oil” and “Profit Oil”. For “Cost Oil” the PSC seeks a lower percentage of output to the state through Pertamina, while “Profit Oil” seeks an increased share of output. The “Cost Oil” is defined as cash flow from oil production needed to recover the project investment cost while “Profit Oil” represents the cash flow after the recovery of investment costs.

This differs from PSCs in other jurisdictions, such as Latin America (particularly Venezuela), which seek a share of production, generally on a rising scale with increased output. Such PSCs do not provide for the recovery of investment. Together with high corporate taxes and royalty payments, PSCs linked to output rather than costs make investments in those regions questionable. In that respect Indonesian PSC is indeed reasonable.

Example of a PSC

Cepu Block in the Central/East Java area is believed to be the only remaining undeveloped oil field of significant size in Indonesia. The field is estimated to have 600 million barrels of recoverable reserves. In September 2005, Pertamina and ExxonMobil signed a contract to develop the Cepu Bock. However a subsequent skirmish between the two parties delayed the development of the field. Having resolved the conflict, Pertamina-ExxonMobil joint venture has signed a Joint Operating Agreement in March 2006, under a 30-year contract. Pertamina and ExxonMobil each hold a fifty-percent interest in the Contract, with the parties anticipating entry of a regional entity at the ten-percent level in the future. Both parties will provide the ten percent equally.

Apart from the Cepu Block, much of the remaining reserves are scattered smaller oil fields with some located in remote areas in hard to explore terrain. Smaller fields such as Unocal's West Seno field with an output of 40,000 bbl/day pale in comparison to Indonesia’s once-larger and more promising fields. Consequently, attracting investments to develop its petroleum reserves has been increasingly challenging.

Natural Gas


Indonesia also has large natural gas reserves and is the world’s largest producer of LNG. Its proven gas reserves are estimated to be 90.3 trillion cubic feet (Tcf), with the bulk of it located in East Kalimantan and Java. Indonesia’s gas reserves account for 1.6% of global reserves and 2.7% of global output making it a fringe player in the global market compared to the likes of Russia (reserves of 1,680 Tcf), Iran (reserves of 971 Tcf) and Qatar (reserves of 910 Tcf), which account for over 58% of global reserves and 27% of global output. Despite its significant natural gas reserves, Indonesia continues to rely on oil to generate approximately half of its own energy needs. Currently, ExxonMobil, Total, Anglo-Italian joint venture VICO Indonesia and Unocal provide natural gas from onshore and offshore fields. A third LNG production center operated by Anglo-American BP, with significant Chinese and Japanese shareholdings, is expected to come on stream in 2008.

LNG contributes substantially to the Indonesian economy. Oil and gas revenues, of which LNG represents about half, represents approximately 24% percent of the country’s domestic budget revenues. LNG sales represent approximately 3% of Indonesian GDP. Aided by high crude oil prices, LNG exports reached a record $7.7 billion in 2004, accounting for 11% of Indonesia’s total exports. Indonesia’s LNG buyers include Japan (68%), South Korea, Taiwan and Singapore. Beginning from 2007, Indonesia is contracted to ship LNG to the CNOOC’s planned Fujian terminal in China, U.S. Sempra Energy’s proposed Baja California terminal, and South Korea’s SK-POSCO.

As Indonesia’s oil production continues to fall, there has been a growing tendency to use natural gas resources for power generation. This has made little progress so far owing to the poor domestic natural gas distribution infrastructure. However, given its contracts to various countries and specific end-users such as those in China, Indonesian natural gas reserves need urgent development.

Similar to its oil market, Indonesian gas market is also facing similar challenges, but of a different nature. There have been concerns regarding the supply reliability and lower investment in the sector. Political uncertainties over support for the sanctity of contracts and the lack of regulatory transparency have undermined investment support. Consequently, other LNG producing countries such as Oman, Qatar, Russia, and Australia are gaining ground over Indonesia in the LNG market. Since early 2005, exports from the terminal at Arun in Aceh have been cut back below the level of contractual commitments, due to continuing production problems in the area. While natural gas reserves are not necessarily dwindling, the sector demands considerable remedial measures.

Sector Reforms


These challenges have however prompted the Indonesian government to take several positive steps to reform its energy sector. The most significant is the Oil and Gas Law 22/2001 (passed in October 2001), which limited Pertamina's monopoly on upstream oil development by the end of 2003. In addition, Pertamina's regulatory and administrative functions were transferred to other entities, while its regulatory role was spun off to a new body, BP Migas. Despite skepticism amongst foreign companies regarding BP Migas’ lack of efficiency, Indonesian Oil Sector reforms are making progress providing a level playing field for all stakeholders. This includes developments such as the extension of contracts beyond the previous 20-year limit, which helped facilitate ExxonMobil’s Cepu field development project.

Oil sector reforms oversee the distribution as well. For instance, Pertamina’s retail and distribution monopoly for petroleum products has now been reduced, with the sale of distribution licenses to foreign companies. The first license for a foreign firm to retail petroleum products was awarded to BP and Petronas of Malaysia. The government is still promising to open the sector to full competition, although the progress so far has been slow. This is largely due to the government’s political interests and ties to Pertamina. However, Pertamina itself was changed to a limited liability company by presidential decree in 2003, and is expected to be fully privatized by 2006. Liberalization of the downstream oil and gas sector continues to be a focal point of on going discussions in sector reforms.

While we are yet to see the full benefit of these reforms, Indonesian authorities appear to be committed to instill transparency and the abolishment of the state monopoly. In addition, the country is leaning heavily towards foreign investments to develop its petroleum resources. This policy shift not only is beneficial to Continental, but also provides considerable assurance in conducting its operations with least state interference.

Continental’s projects are currently at early stage and therefore its future success hinges on the resource potential and the drilling success of the properties by CNPC. The bulk of these properties are earmarked for exploration and development in Indonesia. Furthermore Indonesia has its share of political risk and uncertainty, which can have a significant impact on the operations of the company.

Political Instability: Indonesia, a former Dutch colony, has a history of political instability and cronyism. A sudden change in government could prompt changes to the existing regulatory and competitive structure leading to the cancellation/non-renewal of drilling licenses. In the past few years there has been landmark industry related legislation that has been approved making it easier for independent oil companies such as Continental to conduct oil exploration in the country. However a change in administration could well result in a reversal of such legislation. Tension between the central government and the leadership of select regional governments due to disagreements on the sharing of oil and gas revenue could also lead to conflicts.

Social Unrest: Civil unrest continues despite the 2005 peace agreement between the Indonesian government and the separatist rebels of the Aceh province. Separatist movements such as the one in the Papua province (Irian Jaya) and the Al Qaeda linked Jemaah Islamiyyah pose constant threats to foreign interests, specifically those with American links.

Reserve Assumptions and Technical Risk: Continental’s profitability is a function of the exploration success by CNPC. While Continental is confident of Bengara-II Block reserve potential, the Company is yet to prove-up the reserves under its license areas.

Drilling and Operations: Exploration, development and production activities may be hampered by teething problems related to technical and other operational issues. There could also be disruptions by rebels and insurgents. Such disruptions may cause lower than expected output, higher operating expenses and lower profitability. There could also be delays in development and production.

Implementation Ability: The ability of the Company to successfully market its products depends on the availability of infrastructure including pipeline and storage facilities in its oil and gas exploration sites. Such facilities may prove to be in demand and their allowed usage may be. Availability of infrastructure, their capacity utilization and development are beyond the control of the Company. Dependence on Key Personnel: Similar to many junior oil and gas companies engaged in exploration, Continental’s success depends on its management team. Continued availability of their services is not necessarily guaranteed and the loss of key personnel could lead to a perceived disruption of operations and exploration progress.

Ability to Raise Future Financing: While Continental has so far been successful in attracting investors and raising equity, its ability to raise future funding would depend on the exploration success, world oil prices, the political stability in the region and the availability of more attractive investment opportunities in oil and gas exploration pursuits elsewhere in the world.

Current Losses: The Company is not profitable as yet, and should not become profitable until such time it has major properties in development, which may take time. It is very conceivable the Company’s losses will continue to increase as it continues to grow and add infrastructure and it will need to add financing during the next year to achieve its overall objectives.

Equity Dilution: We expect Continental to look at the option of additional equity financing to fund its future expansion. In the event the company decides to chose this financing route it could lead to a value dilution in its equity. However this would position the Company for growth.

Global Oil & Gas Prices: Oil & natural gas prices are volatile and Continental’s profitability may be affected due to their price fluctuations. In addition to lower earnings, a sudden and prolonged decline in energy prices could affect the carrying value of Continental assets and its borrowing capacity.

Competition: The continuing deregulation of the Indonesian oil and gas sector could mean increased competition. The Indonesian government will continue to encourage increased exploration by issuing more drilling licenses in an effort to increase investment in this sector.

Richard L. McAdoo, Chairman/CEO and President: Mr. McAdoo holds a Bachelors degree in Geology and Masters Degrees in Geophysics from Texas Tech University; and a Masters degree in Business Administration from Boston University. He is a registered Certified Petroleum Geologist and has 28 years of international oil exploration and production experience. Mr. McAdoo has held a variety of technical and management positions in Mobil Oil, Phillips Petroleum, Jackson Exploration, Triton Energy, and Tracer Petroleum. His regional experience includes the North Sea, Middle East, Africa, South America, and Asia.

James D. Eger, Vice President, Chief Financial Officer and Director: Mr. Eger holds a Bachelors degree in Earth Science from Antioch College, and Masters Degrees in Geology, Marine Affairs, and Business Administration from the University of Florida, University of Rhode Island, and Boston University respectively. His career spans more than 25 years, in both international oil exploration and the securities and investments industries. He has worked for Phillips Petroleum, Jackson Exploration, Tracer Petroleum and Dimensions West Energy, and was involved in their operations in the North Sea, North Africa and Indonesia. His financial services experience has been with Dean Witter Reynolds Inc New York and Southwest Securities Inc. in Dallas, with specialty in energy futures, international equities, and options and currency trading.

Paul L. Hayes, Jr., Director: Mr. Hayes experience has over 20 years each in securities and energy industries. After graduating in Petroleum Engineering from the University of Oklahoma, he was employed by Exxon in Venezuela. Following the completion of his MBA from Harvard University, he worked for Mobil Oil and Amoco in Argentina and New York City. Subsequently he worked as an oil analyst for William D. Witter, Inc. and started his own NASD firm, Hayes Brothers Securities, Inc. After four years, he sold Hayes Brothers to Fahnestock & Co. and worked the head of research. My Hayes has also worked as an oil analyst for Oppenheimer & Co. and for Yorkton Securities in Toronto.

David W. T. Yu, Director: Mr. Yu is a resident of Hong Kong, and is an experienced independent financial professional with thirty years experience in the securities, commodities, bullion, and foreign exchange trading business. He has worked for Rothschild & Sons, Shearson American Express, and Citibank. Recently Mr. Yu was involved in forming long term intergovernmental oil supply agreements between the Chinese government and oil producing nations in Africa. He is currently working on similar deals in South America and in Indonesia.

Continental is yet to commence commercial production and therefore has no reported revenue. This is a common phenomenon amongst development stage exploration companies such as Continental. Important factors to consider in evaluating exploration companies are the burn rate, capital structure (existence of debt) and contingent liabilities. Continental is incorporated in Canada and indicative of its foreign issuer status, the company files 20-F and 6-K statements with the Securities and Exchange Commission (SEC). Its financial statements are in reported in US dollars and its financial statements are US GAAP compliant.

The Company’s continued existence as a going concern is dependent upon the future economic success of its exploration and development activities, the Company’s ability to continue to secure adequate financing and achieve a positive cash flow and profitable operations.

Nine Months ended April 30, 2006
During the nine months ended April 30, 2006, the Company continued to have no revenue as its properties are yet to commence commercial production. During this period, the Company improved its working capital position of approximately $2.5 million compared to a deficit of $39,000 as of July 31, 2005. The increase is due to the $3.6 million gain on the sale of Yapen subsidiary. The sale also led to a gain of $3,506,833.

During the same period the Company’s operating costs increased by 37% to just over $820K. Based on the operating cost for the nine-month period, the Company’s monthly burn rate is approximately $90,000. Based on the cash assets at the end of April, the Company has adequate cash to fund its operations for a period through year-end 2007.

The Company used $822,711 for operating activities during the nine months ended April 30, 2006 compared to $600,876 in the nine months ended April 30, 2005 (up 37%) reflecting its ongoing development activities. During the quarter ended April 30, 2006, the Company used $622,995 as compared with $433,127 in the same fiscal quarter in the prior year.

With the arrangement with CNPC upon the 70% sale of its subsidiary, Continental appears to be in a sound financial footing. While CNPC will undertake the development of Bengara-II, we expect further issue of equity to finance any new property acquisitions.

Fiscal Year ended July 31, 2005
During the fiscal year ended July 2005, the Company did not earn any revenue since none of its properties had commenced commercial production. The Company however recorded a net income for the year of $2.3 million or $0.05/share compared to a loss of $1.1 million or $0.02/share in 2004. This turnaround was due to a realized gain of $4 million on the disposal of its 70% ownership in GAT Bangkudulis Petroleum Company (GATB). During the same period the company’s operating expenses fell by 12.3% YoY mainly due to declines in interest costs, management fees and office expenses.

The Company follows the full cost method of accounting for oil and gas operations, as prescribed by the Canadian Institute of Chartered Accountants. This entails all costs of exploration and development of oil and gas reserves to be capitalized and accumulated in cost centers established on a country-by-country basis.

Continental’s operations remain primarily equity financed. In April 2005, the company raised $500,000 through a private placement of 3,333,334 shares at a price $0.15/unit to fund its working capital. The Company intends to continue its strategy of pursuing equity financing to meet future expansion needs and working capital.

In fiscal 2004, the Company paid off the entire principal and a portion of the interest on a promissory note due in July 2005. The balance of the interest component ($50,000) was carried as a current liability for the fiscal year ended July 31, 2005, and no further interest charges will be incurred on this amount. Consequently the Company has no long-term debt on its balance sheet and is not expected to take on any in the near term. Continental does not have any contingent liabilities at the present time.

We are continuing Continental coverage with a positive rating. Its properties are flanked by producing fields. The Company benefits from Indonesia’s interest in developing its petroleum reserves, which are expected to be predominantly in partnership with foreign companies. Investment rewards however would heavily depend on drill results by CNPC and subsequent acquisitions. A confirmation of reserve potential backed by adequate geological data and results would prove to be an important factor, as is the key for any exploration company. Furthermore any announcement on future funding will be a positive milestone particularly if the capital structure includes some institutional ownership.

Sam Kiri, CFA
Alan Stone, Managing Director
Copyright © October 2006. All Rights Reserved.

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