Orchid Island Capital
Annual Report 2004

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A leader in developing and marketing Tanzania’s natural gas resources 2 0 0 4 A n n u a l R e p o r t EastCoast Energy Corporation is a well-financed, international public company engaged in the exploration, development and production of Tanzanian natural gas and the marketing of “Additional Gas” to expanding markets in East Africa. EastCoast Energy began trading on the TSXV on 31 August 2004 under the trading symbols ECE.SV.B and ECE.MV.A. The Company is headquartered in Tortola, British Virgin Islands and maintains its operations offices in Dar es Salaam, Tanzania. 1 2 6 Financial and Operating Highlights Chairman’s message Tanzania Perspective 8 Operational Review 18 Management’s Discussion and Analysis 36 Management’s Report 37 Auditors’ Report 38 Financial Statements 51 Corporate Information This annual report contains certain forward-looking statements based on current expectations, but which involve risks and uncertainties. Actual results may differ materially. See page 21 for additional information. All financial information is reported in U.S. dollars, unless noted otherwise. F I N A N C I A L A N D O P E R AT I N G H I G H L I G H T S 1 Financial (US$’000) Revenue Loss for the period Working Capital Shareholders’ Equity Outstanding Shares (‘000s) Class A shares Class B shares Options Natural Gas Reserves (based on McDaniel & Associates Consultants Ltd. reserves report as at 31 December 2004) Gross Recoverable Reserves to end of licence (bcf) Proved Probable Proved plus probable Present Value, discounted at 10% (US$ million) Proved Proved plus probable Period ended December 2004 441 (727) 1,216 11,516 1,751 19,386 2,000 171.2 84.2 255.4 35.5 43.4 There are no comparative numbers as the Company was consolidated within PanOcean Energy Corporation until 31 August 2004. G LO S S A RY Mcf ..............................Thousands of standard cubic feet Mmscf ..............................Millions of standard cubic feet Bcf ....................................Billions of standard cubic feet Mmscf/d ............Millions of standard cubic feet per day Kwh..........................................................kilowatt hour MW ..............................................................Megawatt US$..............................................................US dollars Cdn$ ................................................Canadian dollars 2 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | CHAIRMAN’S MESSAGE EastCoast Energy is a new public company in its first year of operation as an independent natural gas produc- tion and marketing organization. We are focused on developing Tanzania’s gas resources and delivering them to rapidly expanding energy markets in East Africa. While our company is new, our interest is not. Through predecessor companies, EastCoast has been working to develop Tanzania’s gas resources for over a decade. We have built positive relations with the Tanzanian Government, with the Tanzanian Petroleum Development Corporation and the utilities and industries in the Dar es Salaam area. We have a solid foundation for growth and the opportunity to create wealth for our shareholders. The hard work, patience and discipline of our predecessor companies has paid off and the Songo Songo offshore gas field, about 200 kilometres south of Dar es Salaam, is now in production. EastCoast commissioned five natural gas wells at Songo Songo in 2004 and now operates the wells and production facilities for the Tanzanian Petroleum Development Corporation. Natural gas from the field is shipped by pipeline to the Dar es Salaam area to supply five gas turbine genera- tors at the Ubungo Power Plant and the cement kilns at a nearby industrial facility. Since the pipeline can transport more natural gas than was initially required, significant additional volumes are available to be marketed. EastCoast owns the right to market this gas and has already constructed a ring main distribution system to supply industrial customers in the Dar es Salaam area. Seven gas contracts have been signed by EastCoast with Dar es Salaam industries and we anticipate that by the second half of 2005 industrial gas sales will triple to 3.5 million cubic feet per day. The future holds great promise. With an expanding gas market on the horizon, the Company is preparing a 2005 seismic program on adjacent exploration blocks that are held by EastCoast. We have identified high potential leads near the Songo Songo field and will use the seismic to assess these potential drilling targets. The discovery of new reserves could lead to Dar es Salaam becoming the thermal generation hub for the region, with power being exported to Kenya. 2004 Highlights .. EastCoast successfully com- missioned the five natural gas wells at Songo Songo with a forecast maximum field deliverability of 158 million cubic feet per day. .. .. .. .. .. .. .. .. Produced (as the contract field operator) 4.6 billion cubic feet of natural gas from the Songo Songo field from the commencement of com- mercial operations to year end 2004. Increased the gross certified proved recoverable gas reserves available to be marketed by EastCoast by 101% to 171.2 billion cubic feet over the licence period. Completed a pressure reduction station and a 14-kilometre ring main distribution pipeline at Dar es Salaam to provide connections for EastCoast to sell “Additional Gas” production to industrial customers in the area. Commenced natural gas sales to Dar es Salaam industries Kioo Limited and Tanzanian Breweries Limited who purchased 120.6 million cubic feet (an average of 1.2 million cubic feet per day) to 31 December 2004. Signed five additional industrial gas sales contracts. These are expected to be connected over the first half of 2005 tripling our Company’s industrial gas sales to 3.5 million cubic feet per day by Q3 2005. Commenced negotiations with TANESCO, the electricity utility, to supply gas to a 34 MW turbine that is expected to be operational by Q3 2005 and have a maximum utilization of 8.4 million cubic feet per day. Prepared a 500 kilometre seismic acquisition programme over the Songo Songo field and adjacent licence blocks. Prepared and announced a Rights Issue that successfully raised gross proceeds of Cdn$5.5 million in Q1 2005. Marketing Opportunities There are two categories of Songo Songo gas production. “Protected Gas” is owned by the Tanzanian Petroleum Development Corporation and is contracted to Songas Limited (“Songas”) primarily for use in specific turbines at Dar es Salaam’s Ubungo Power Plant and at the Wazo Hill cement plant. Additional Gas is surplus to the volumes contracted to Songas and can be marketed by EastCoast Photo top right: eastcoast operates the songo songo gas plant which is connected by marine pipeline to mainland tanzania. bottom right: tanzanian technicians operate and maintain the plant. opposite page: songo songo island is approximately 25 kilometres from the coast of mainland tanzania. 3 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | 4 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | C H A I R M A N ’ S M E S S AG E Our first priority is to maximise the value of our existing Tanzanian asset base through building larger, sustainable markets for natural gas. Photo above: children on songo songo island take a break from school. to industrial customers or as fuel for other power generation turbines. Based on the latest certified reserve report by McDaniel & Associates Consultants Ltd., up to 171.2 bcf of gross proven reserves is currently available to be marketed by EastCoast over the term of the Songo Songo licence. This is a totally new market for the sale of natural gas and the pace of natural gas demand in Tanzania is expected to accelerate over the next two years. Local industrial customers can benefit from using natural gas in their operations and increasing demand for electricity in both Tanzania and elsewhere in East Africa will require additional power generating capacity. Infrastructure to Support Growth To deliver Additional Gas to Dar es Salaam industrial customers, EastCoast has constructed a ring main distribution system. By the end of 2004, five customers had been connected to the ring main and two others are in the process of being connected at a cost of US$1.1 million. Industrial gas sales over the period to 31 December 2004 averaged US$5.31/mcf, which is a 25% discount to the price of Heavy Fuel Oil in Dar es Salaam. Songo Songo Exploration Potential EastCoast is updating surveys over the existing Songo Songo field and its adjacent interest lands. This primarily involves the acquisition and reprocessing of data. Once the data is reviewed, a decision will be taken as to whether to drill a well in 2006. To retain the Company’s licences on the seven blocks adjacent to Songo Songo, EastCoast must invest a minimum of US$2.0 million on seismic or related expenditure by October 2005 and drill a well on the adjacent blocks by October 2006. 2005 Outlook Over 2005, EastCoast will continue to focus on four activities intended to increase shareholder value. .. Expand our gas sales to industrial and utility customers to increase the revenues EastCoast earns from the distribution and sale of Additional Gas. .. .. .. Closely monitor the Songo Songo wells and pressure data to increase our understanding of the field, and its production and reserve potential. Assess drilling leads on leases adjacent to Songo Songo to identify potential prospects to be targeted in 2006. Seek to secure further opportunities in East Africa and elsewhere. EastCoast’s current industrial sales contracts are expected to generate Additional Gas sales of 3.5 million cubic feet per day by Q3 2005. Additional contracts are under discussion with potential customers and connections can be constructed if these negotiations are successful. To expand the sale of Additional Gas to electrical utilities, EastCoast is engaged in ongoing discussions with the Tanzanian electric utility, TANESCO. The Company is expecting to supply gas to a 34 MW sixth turbine at the Ubungo power plant that should be operational in Q3 2005. This turbine will have a maximum gas utilisa- tion of 8.4 million cubic feet per day. Over the longer term, it is forecast that 5 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | TANESCO will increase its power generating capacity by 50 MW per annum, commencing in 2007. These increases will be needed to meet a forecast 7% annual increase in demand for electricity in Tanzania. To remain competitive with other fuels, our strategy is to target price levels that make gas more competitive than other sources of energy. Superior long-term returns EastCoast is committed to both growth and value. Our first priority is to maximise the value in our existing Tanzanian asset base through building larger sustainable markets for natural gas. Our second is to prospect for additional low cost, long life opportunities where EastCoast can create additional shareholder value. EastCoast appreciates the very positive response of the investment community to our Company. We thank our management and employees for their expertise and commitment. We are excited about future prospects and the opportunity to be a leader in developing East Africa’s natural gas resources. W. David Lyons 15 April 2005 Photo above: the dar es salaam harbour has a place for both traditional sailboats and large freighters. 6 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | TANZANIA PERSPECTIVE Tanzania is a country of approximately 37 million people best known outside Africa for its amazing range of wildlife and magnifi- cent scenery. The image of Mount Kilimanjaro rising above the plains to a height of 5,895 metres is recognized worldwide. Much less is known about the country’s people, its economy, its resources and its form of government. Tanzania has been an independent country since 1961. It covers an area of 945,000 square miles and has approximately 1,200 kilometres of coastline. Tanzania is a multi-party republic with an elected president, vice president and national assembly. The country’s economy is heavily dependent on agriculture which employs 80% of the work force. The other 20% is employed in the growth sector of services, industry and natural resource extraction. Tanzania’s ability to effectively manage its energy requirements and to make best use of its own energy resources will play an important part in strengthening the country’s expanding economy. Currently in Tanzania the major sources of commercial energy are oil, hydropow- er and coal. Coal and hydro power are domestic resources but oil has to be imported. Local non-commercial energy needs are met primarily from burning wood from Tanzania’s natural forests and plantations or from charcoal. Recent annual growth in Tanzania’s total energy demand has averaged between 7 and 9 per cent. Over the next ten years peak electrical demand is forecast to increase from about 530 MW to close to 1,000 MW. The energy demand is created by a number of factors including a growing urban population, the need for secure supplies of electrical energy in a developing economy and Tanzania’s desire to bring electric energy to the approximately 25% of the country that currently does not have access to the national grid. The rapid growth of large cities is also a contributing factor. In Dar es Salaam, the country’s largest city, there are over 3 million residents who need dependable electrical energy supply. Over the last year, Tanzania’s energy sector has demonstrated its readiness to begin to substitute natural gas for other fuels and energy sources. This makes good economic and environmental sense. First, domestic electricity demand in Tanzania cannot always be met from hydro sources. Second, continued reliance on diesel fuel for power generation requires costly foreign imports. Finally, there is a growing market for reliable, less polluting, and cost efficient industrial energy sources. Natural gas, a previously untapped energy resource, is rapidly winning acceptance among both power generation companies and large industries in Tanzania. With the successful introduction of natural gas at Dar es Salaam, the area could be poised to become the thermal generating hub for East Africa. In the 1990s, after four severe droughts, neighbouring Kenya installed 237 MW of thermal gen- eration, primarily at Mombasa. Despite this increase in electrical power generating capacity, Kenya is still susceptible to power shortages – particularly in drought years. It is possible that Kenya may look to Tanzania for power through the con- struction of a planned interconnector between Arusha in Tanzania and Nairobi. Opportunities for use of natural gas in Tanzania are not limited to power genera- tion. Industrial energy users in the Dar es Salaam area have been quick to sign con- tracts to access natural gas production from Songo Songo. Cement plants, a glass pant and a brewery were the first to convert. Another option that has been studied would convert road vehicles to use CNG (Compressed Natural Gas) as fuel. This technology has been successfully applied in North and South America, Europe and Asia. A CNG system introduced recently in Delhi, India has led to the conversion of approximately 84,000 vehicles that can be fueled at 116 filing stations. This could be an attractive option for buses, munici- pal vehicles, taxis and other fleet vehicles, though any development is likely to be slow. EastCoast has organized a tender for CNG construction and is currently evaluating proposals submitted by qualified CNG operators. EastCoast Energy is a leader in helping to develop Tanzania’s natural gas resources and, with its operatorship of the Songo Songo field, EastCoast is positioned to grow in parallel to the country’s economic expansion. While three-quarters of the country is connected to the national electric power grid, the peak installed capacity is unable to meet demand. Brownouts, blackouts and power rationing are the result. This is primarily because electri- cal power from hydro is prone to be reduced at certain times of the year or in seasons of drought. While Tanzania has an estimated 3800 MW of economic hydro capacity, only 561 MW has been developed. Installed hydro capacity is augmented by over 251 MW of thermal generating capa- city at Dar es Salaam. Until mid-2004 these turbines ran on imported diesel fuel. However in July 2004, the Songo Songo gas field came on stream and natural gas was substituted for diesel. Photo above left: rural electrification is a priority of the tanzanian government. centre: large urban centres like dar es salaam have increasing demands for electricity. right: conversion of industries from fuel oil to domestic natural gas increases security of supply and contributes to a cleaner environment. Electrical generation, transmission and distribution in tanzania is through the tanzania electric supply company known as tanesco. the company is 100% government owned and is responsible for the majority of the country’s electrical supply. hydro power, natural gas and oil are the major sources of commercial energy. 7 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | 0500100015002000250030003500ThermalHydro200420032002200120001999199819971996199519941993199219911990050100150200SS-9SS-7SS-5SS-4S2004 ForecastCapacity1997 ForecastCapacity01020304050S02004006008001000Line packand flareAdditionalgas salesProtected gas salesDecNovOctSepAugJuly05101520253035Ju 8 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | OPERATIONAL REVIEW B a ckg ro u n d The Company’s operations at the Songo Songo gas field in Tanzania provide for EastCoast to operate five producing wells and two 35 mmscf/d dehydration and refrigeration gas processing units on Songo Songo Island. Gas processed by EastCoast is then transported to Dar es Salaam through a 25-kilometre 12-inch offshore pipeline and a 207-kilometre 16-inch onshore pipeline. Gas produced and sold from the Songo Songo field is classified as either Protected Gas or Additional Gas. The Protected Gas is 100% owned by the Tanzanian Petroleum Development Corporation (“TPDC”) and is sold to Songas Limited (“Songas”) under a 20 year Gas Agreement either for use at the Ubungo Power Plant or for onward sale to the Wazo Hill Cement Plant or for the Village Electrification Programme. At a 100% utilisation rate, the Protected Gas consumption is forecast to be 44.8 mmscf/d and therefore the total Protected Gas required over the twenty year period of TPDC’s gas agreement with Songas cannot be more than 327 bcf. For the purposes of calculating the level of gas available for the Additional Gas it has been assumed that the Protected Gas users will operate their facilities at a 75% utilisation rate over a twenty year period reflecting maintenance downtime and times of non usage. This assumption will be reviewed on an annual basis based on historic and projected usage. The Protected Gas users and their forecast demand are as follows: Songo songo gas marketing interest area Photo above: two gas processing trains at the songo songo gas plant are operated by skilled eastcoast technicians. Protected Gas consumer Ubungo Two ABB turbines Two GE turbines Fifth GE turbine Wazo Hill Cement Plant Kiln 1 Kiln 2 Village Electrification Programme Total daily gas demand Reserves over 20 years from commercial start up (bcf) Theoretical max 100% load factor (mmscf/d) Most likely (mmscf/d) 10.97 18.55 8.40 37.92 3.40 2.47 5.87 1.00 44.79 327.0 8.23 13.91 6.30 28.44 2.55 1.85 4.40 0.75 33.59 245.2 Dire DawaKuguriSChipataLivingstoneBLubangoLuenaMalangePFrancistownMaunBwaNgaoundereBangassouBerberatiBossangoaNdeleMoundouAAselaGobaMMakokouPEldoretKisumuMombasaBAntsirFianarantsoaTolanaroTomasTulearBlantyreABeiraNampulaKeetmanshoopTsumebABerberaHargeysaBeaufortWestDeAarEast LondonKimberleyOudtshoornPietersburgPort ElizabethWelkomMJubaPWauMwanzaTangaSBukavuBumbaKaminaKanangaKisanganiMonguVictoriaFallsLuderitzLBishoKArushaHuamboDDurbanUmtataCLikasiMatadiMbandakaBulawayoAWalvis BayJohannesburgLuandaABujumburaYoundeNDjamenaDjiboutiAAddisAbbabaLNairobiKMaseruTAntananarivoLilongweBWindhoekNCape TownDar es SalaamSongoSongoDodomaSingidaTKinshasaLusakaHarareAGaboroneBanguiBrazzavilleNMaputoLBloemfonteinPretoriaKMbabaneLKampalaDKENYAETHIOPIAESOMALIANAMIBIALSOUTH AFRICATANZANIAANGOLAAMADAGASCARMOZAMBIQUEBOTSWANAZAMBIAGCENTRAL AFRICANREPUBLICTUGANDASWAZILANDLESOTHOMALAWIRWANDATONZIMBABWECONGOCONGOEDJIBOUTISL.KivuL.MalawiL.TanganyikaLLakeVictoriaLake KaribaLakeMweruLLake TurkanaLIndianOceanSongo Songogas fieldSongaspipelineAFRICAAINDIANOCEAN500KM0 P ro d u c t i o n Commercial production commenced from the Songo Songo field on 20 July 2004 when the Ubungo Power Plant was commissioned. By the end of December 2004, 4.6 bcf of Protected Gas and Additional Gas had been produced from the field since commercial start up as follows: Gas produced mmscf Protected & Additional Gas Production Analysed between: Protected Gas sales Additional Gas sales Flare and generator consumption at the gas processing plant Line pack Protected Gas Sales Total 4,623 4,097 121 325 80 4,623 In the period to 31 December, 2004 the Protected Gas consumers’ utilisation rate was 55% and may be analysed as follows: Protected Gas user Ubungo Wazo Hill Cement Plant Village Electrification Programme Total consumption Total consumption at 100% utilisation Protected Gas not utilised Period 20 July 2004 – 31 December 2004 Protected Gas consumed mmscf mmscf/d Utilisation rate % 3,696.9 399.7 – 4,096.6 7,300.7 3,204.2 22.09 2.41 – 24.50 44.79 n/a 58 41 n/a 55 n/a n/a The Protected Gas utilisation rate was relatively low in 2004 as: 1. The two ABB turbines were not operational at Ubungo until October 2004. The four turbines consumed an average of 22.1 mmscf/d from commercial start up to 31 December 2004. This increased to an average of 27.3 mmscf/d in December when all four turbines were operational. The fifth turbine was commissioned in March 2005 and has a forecast maximum con- sumption of 8.4 mmscf/d. Above left: gas is processed at songo songo island to bring it to pipeline standards. above right: the ubungo power plant is currently operating five turbines using “protected gas” from songo songo. 9 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | 0500100015002000250030003500ThermalHydro200420032002200120001999199819971996199519941993199219911990050100150200SS-9SS-7SS-5SS-4SS-32004 Forecast Capacity1997 Forecast Capacity01020304050TBLKiooDecNovOctSept02004006008001000Line pack and flareAdditional gas salesProtected gas salesDecNovOctSepAugJuly05101520253035Wazo HillUbungoDecNovOctSeptAugJul 1 0 O P E R AT I O N A L R E V I E W | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | photo opposite: many of songo songo island’s people live in traditional thatched houses and some fish the ocean for a living. photo below: a sixth turbine is being installed at the ubungo power plant. It is expected to be in operation at mid-2005 using additional gas from songo songo. 2. The two kilns at the Wazo Hill cement plant were not operating at expected capacity until January 2005. The plant consumed an average of 2.4 mmscf/d from commercial start up and peaked at 3.0 mmscf/d in November when both kilns were being utilised. 3. The scheme to supply gas for electrification for some of the villages affected by the development of the Songo Songo project is unlikely to be implemented until Q3 2005. As a consequence of the above, 3.2 bcf of gas was not utilised by the Protected Gas consumers and consequently the maximum gas required for the Protected Gas users over the 20 year term of their gas agreement fell to 323.8 bcf as at 31 December 2004. This shortfall allows the Additional Gas reserves to be raised by a similar amount. Additional Gas Sales Small volumes of Additional Gas sales commenced in September 2004. This is discussed under ‘Infrastructure and Markets’ below. Flare and generator After normal and expected flaring during the commissioning and start up of the gas processing plant, there was a malfunction of a pressure control valve installed by the contractor and this led to the flaring of slightly higher than normal volumes of gas. The problem was fixed in January 2005 and the flaring has returned to normal levels. Line Pack It is estimated that the 232 Kilometre pipeline to Dar es Salaam is capable of holding a maximum of 85 mmscf of gas. This is reflected in the amount of July production that was required to fill the line prior to gas sales. We l l c a p a c i t y te s t i n g With these initial production rates, the Company has per- formed a series of pressure tests using Keller well head gauges and bottom-hole gauges that were installed in all the wells (except SS-9) before the start up of the field. These were pulled in November and data was analysed to provide a more accurate determination of reserves. New bottom-hole gauges were installed in the wells (two in SS-5 and SS-7 and one in SS-3 and SS-4) and these will be pulled in May 2005. As at 31 December, tests had been performed on four of the wells namely the two onshore wells, SS-3 and SS-4, and two offshore well SS-7 and SS-5. In December, SS-9 was brought on stream after the Company successfully pulled the back pressure valve that had been stuck in the tubing hanger. This enabled the Company to run a perforated tubing plug to prevent any operational problems with two sets of gauges and a length of wireline that were left downhole at the time of the 1997 extended well program. This well was then tested in January 2005. The results of the well tests during the period, based on the requirement to have 1,600 psig of pressure in the gas processing plant, are as follows: Mmscf/d Capacity SS-3 SS-4 SS-5 SS-7 SS-9 (Note 1) Maximum Protected Gas demand Available for Additional Gas Well flow rates 1997 capacity forecast 31 December 2004 capacity forecast 10 10 60 20 40 140 (45) 95 17 19 65 22 35 158 (45) 113 Note 1: The well test on SS-9 was conducted in January 2005. Potentially the well will produce at rates in excess of 35 mmscf/d, but rates will be restricted to ensure that no downhole problems occur from gauges and wireline left in the hole in 1997. The capacity of the wells was 13% higher than forecast at the time of the 1997 well tests. This means that: .. There is a potential of 113 mmscf/d of production capacity for Additional Gas above the peak demand for the Protected Gas; and .. Even if the two largest wells are unable to produce, the Company can still supply the Protected Gas users at peak demand and 13 mmscf/d of Additional Gas for a short period of time. SS-9 was tested in January 2005 and the well was produced at a rate of 35 mmscf/d. Accordingly, the perforated tubing plug and the downhole gauges and wireline do not seem to be having a significant effect on the production rate. The test indicated that the well could produce at rates in excess of 35 mmscf/d. However, the well will be produced conservatively given its downhole condition and the fact that there is excess production capacity. Reservoir interference tests have been conducted to understand the main connectivity between the main reservoir area surrounding SS-5 and SS-9 and the southern area of SS-7. The initial conclusions are that the connec- tivity in the reservoir is good and that SS-7 is communicating with other wells in the field. The areas that the Company will focus on in 2005 are: (i) (ii) Understanding the aquifer strength of the reservoir; and The connectivity of the wells and fault transmissibility. 1 1 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | Songo songo gas field SS-9SS-1SS-5SS-7SS-4SS-3SS-2SS-6SS-8Songo Songo IslandGas PlantGas Well12” Marine Pipeline1 km0500100015002000250030003500ThermalHydro200420032002200120001999199819971996199519941993199219911990050100150200SS-9SS-7SS-5SS-4SS-32004 Forecast Capacity1997 Forecast Capacity01020304050TBLKiooDecNovOctSept02004006008001000Line pack and flareAdditional gas salesProtected gas salesDecNovOctSepAugJuly05101520253035Wazo HillUbungoDecNovOctSeptAugJul Songo songo licensed blocks 1 2 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | S e i s m i c p ro g r a m m e There are nine licences included in the Company’s PSA with TPDC, namely the two blocks within which the Songo Songo field lies (“Discovery Blocks”) and seven blocks in adjacent areas (“Adjoining Blocks”). The PSA obligates the Company to perform certain work on the Adjoining Blocks including US$2.0 million (in October 2001 terms) of seismic and related work before October 2005 and drill a well by October 2006, if it wishes to retain the Adjoining Blocks for the term of the PSA. During 2004, TPDC agreed that this seismic obliga- tion would be satisfied even if some of the seismic was run over the Discovery Blocks. In the event that EastCoast elects not to explore or retain the Adjoining Blocks, there is no explo- ration obligation for seismic acquisi- tion or drilling in 2005 or 2006. The seismic used to evaluate the field was acquired between 1978 and 1984 and is considered fair for its vintage. In 2005, the Company intends to: .. .. Reprocess 450 kilometres of the existing seismic; Acquire and process approximately 10 kilometres of infill 2D seismic in order to delineate the field; and .. Acquire and process approximately 490 kilometres of 2D seismic over some exploration acreage within both the Discovery Blocks and the Adjoining Blocks. The field is located within a shallow operating environment where the water is sometimes less than 10 meters in depth. Accordingly the seismic will be conducted with a shallow marine vessel. It is intended to complete all the processing of the data by the end of 2005. Re s e r ve s In accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, the independent petroleum engineers, McDaniel & Associates Consultants Ltd (“McDaniel”) prepared a report dated 11 April 2005 that assessed the EastCoast natural gas reserves based on information on the Songo Songo field as at 31 December 2004 (the “McDaniel Report”). The reserves summary to the end of the license period (October 2026) for the Additional Gas was as follows: BCF Certified Reserves Proved producing Proved non producing Total proved (“1P”) Probable Proven and probable (“2P”) Gross Reserves 2004 Net Reserves 2004 124.6 46.6 171.2 84.2 255.4 66.2 35.6 101.8 39.3 141.1 Gross reserves are based on 100% of the property gross Additional Gas reserves (excluding Protected Gas). Net reserves are based on the Company’s share of the Cost Gas and Profit Gas revenues (see Manage- ment’s Discussion & Analysis for definitions). During the course of the year, there has been a: .. .. 101% increase in the gross 1P reserves from 85.3 bcf to 171.2 bcf; and 2% decrease in the gross 2P reserves from 259.6 bcf to 255.4 bcf. TanzaniaSS-8Interest LandsReefsCurrent seismicProposed seismicSongo Songo fieldNew leads010 kmSongo songo licensed blocksSS-3Gas wellSS-9SS-5SS-7SS-4SS-2SS-6SS-1Songo Songo Island For the purpose of calculating the gross Additional Gas reserves, McDaniel has assumed that 249.3 bcf will be required to meet the demands of the Protected Gas users from 1 January 2005. This compares with 247.1 bcf at 1 January 2004. 4.7 bcf was consumed during 2004 by the Protected Gas users (including gas required for testing pre-commercial operations). On a life of field basis the gross recoverable proven and proven and probable reserves increases to 203.1 bcf (net 123.9 bcf) and 358.3 bcf (net 202.8 bcf) respectively. This provides an indication of the recoverable reserves in the field that may be exploited with additional capital expenditure prior to the end of the licence period. The principal assumptions used by McDaniel in their evaluation of the Tanzanian PSA are as follows: Year 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Thereafter 1P gas sales mmscf/d 2P gas sales mmscf/d Brent crude US$/BBL 1P US$/mcf 2P US$/mcf Annual inflation % 4.7 12.1 20.7 32.3 32.3 32.3 32.3 32.3 32.3 32.3 32.3 16.4 16.4 16.4 16.4 16.4 16.4 16.4 16.4 16.4 16.4 4.7 15.7 32.9 33.8 34.0 34.0 34.0 34.0 34.0 34.0 34.0 34.0 34.0 34.0 34.0 34.0 34.0 34.0 34.0 34.0 34.0 39.5 37.5 35.4 33.4 32.9 32.6 33.3 34.0 34.6 35.3 36.0 36.7 37.5 38.3 39.0 39.8 40.5 41.4 42.3 43.1 43.1 3.88 2.54 2.27 2.29 2.32 2.36 2.41 2.46 2.50 2.55 2.61 2.66 2.71 2.77 2.82 2.88 2.93 2.99 3.05 3.11 3.11 3.96 2.75 2.51 2.52 2.56 2.60 2.65 2.71 2.76 2.81 2.87 2.93 2.99 3.05 3.11 3.17 3.23 3.30 3.36 3.43 3.43 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 Photo above: three of songo songo’s five producing wells are located offshore in shallow water. 1 3 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | 1 4 O P E R AT I O N A L R E V I E W | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | Re s e r ve s Re c o n c i l i a t i o n BCF Gross Net Proved Proved and Probable Proved Proved and Probable Reserves at 31 August 2004 85.3 259.6 55.2 155.7 Extensions Improved recovery Technical revisions Discoveries Acquisitions Dispositions Economic factors Production Reserves at 31 December 2004 – – – – – – – – 86.0 (4.1) 46.7 (14.5) – – – – – – – – – – – – – – – – (0.1) 171.2 (0.1) 255.4 (0.1) 101.8 (0.1) 141.1 There has been no development activity on the Songo Songo field during 2004 and the increase in the proven reserves has arisen from the reinterpretation of subsurface data and the positive pressure and gas production data since commercial operations commenced in July 2004. It is forecast that the work program that will be undertaken on the field and adjoining acreage in 2005 and 2006 could lead to an increase in the proven and probable reserves. P re s e n t v a l u e o f re s e r ve s The estimated value of the Songo Songo reserves based on the assumptions on production and pricing, as detailed on page 15, are as follows: 5% 32.5 19.2 51.7 12.9 64.6 2004 10% 22.3 13.2 35.5 7.9 43.4 15% 16.6 9.0 25.6 5.7 31.3 As at 31 August 2004 5% – 17.7 17.7 73.3 91.0 10% – 7.6 7.6 38.8 46.4 15% – 2.9 2.9 22.4 25.3 US$millions Proved producing Proved undeveloped Total proved Probable Total proved and probable Photo above: well servicing is undertaken by eastcoast crews based at the songo songo gas plant. Photo opposite above: with direction from two international staff members, tanzanian technicians operate and maintain the wells, gathering system and processing plant. C e r t i f i c a t i o n fo r p ro j e c t s p o n s o r s EastCoast contracted Gaffney Cline Associates Ltd (“GCA”) to prepare a revised certified reserve report as of 1 January 2005 utilising the more recent surface and subsurface data, including that obtained since production commenced in June 2004. The objective of this report is to demonstrate to the Government of Tanzania, TPDC, Songas and the World Bank that there are sufficient Additional Gas reserves to enable other gas-to-electricity projects to go ahead. This report has not been prepared in accordance with National Instrument 51-101-Standards of Disclosure for Oil and Gas Activities. Its conclusions and findings have no impact on any of the financial information contained within this annual report. GCA initially prepared a certified report in January 2001 to support the development of the Songo Songo project by the World Bank and other sponsors. This original report certified that there was 297 bcf of proved recoverable reserves and 580 bcf of proven, probable and commercially recoverable reserves in the Songo Songo field. However, this report limited the proven reserves to the volumes contracted to the Protected Gas users. GCA reported in March 2005 and their analysis was as follows: Bcf Low estimate Most likely High estimate Potential Gross Recoverable Gas Volumes 540 649 875 These volumes represent the total recoverable gas in the Songo Songo field and includes both the Protected Gas and Additional Gas reserves. The ‘low estimate’, ‘most likely’ and ‘high estimate’ are analogous to Proven, Proven and Probable and Possible respectively with the exception that these cases do not make any assumptions about the level of gas sales (either Protected or Additional Gas). With this level of certified ‘low estimate’ reserves, there is 220 bcf of Additional Gas reserves available assuming that Songas consume the Protected Gas at a 100% utilisation from 1 January 2005. This equates to 30 mmscf/d and 60 mmscf/d over a twenty and ten year period respectively. The report has been made available to the World Bank and other sponsors and should facilitate the commitment to other gas to electricity projects. O p e r a to r s h i p The Company is the operator of the wells and gas processing plant on Songo Songo Island on behalf of the stakeholders including Songas. Operatorship is on a ‘no gain/no loss’ basis. Two internationally experienced staff manage the site operations on a rotational basis with backup support from the Company’s head office personnel in Dar es Salaam. Twenty-six Tanzanian technicians operate and maintain the wells, gathering system and processing plant. During the period to 31 December 2004, the gas processing facilities had performed in line with management’s expectations and there had been no unplanned shutdowns on Songo Songo Island that had impacted the supply of gas to Dar es Salaam. The December 2004 Asian Tsunami had a negligible impact on the operations. The gas processing plant is located nine meters above sea level. Subsea installations were inspected for damage caused by high currents associated with the Tsunami, and none was found. I n f r a s t r u c t u re a n d m a r ke t s The infrastructure that transports the gas from the field to Dar es Salaam was commissioned in July 2004. The current infra- structure configuration has a capacity of approximately 70 mmscf/d, limited by the two gas processing trains that have a design specification of 35 mmscf/d each. Of this up to 44.8 mmscf/d has to be made available for the Protected Gas users. A de-bottlenecking review will be conducted in 2005 to see if the capacity of the two gas processing trains could be increased beyond the specified 35 mmscf/d. To date, 42 mmscf/d has been processed through a single train. 1 5 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | 1 6 O P E R AT I O N A L R E V I E W | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | The infrastructure can be increased to approximately 105 mmscf/d by the construction of a third train at the gas processing plant on Songo Songo Island. There are provisions in the agreements with Songas to enable EastCoast to finance and install a third train. This would be considered where the Company has to expand the infrastructure capacity to meet the demand for Additional Gas in Dar es Salaam. This may be financed externally in preference to Company funds. The Company’s 14 km ring main distribution system and pressure reduction station was commissioned during September 2004. This system enables gas to be transported from the main Songo Songo pipeline to industrial customers in the Dar es Salaam area. The ring main will have an initial capacity of 10 mmscf/d. However, it is forecast that it will operate at 50% of capacity on an averaged basis. Industrial Sales Gas sales commenced with Kioo Limited and Tanzania Breweries Limited in the latter half of September. These two customers are expected to take an average of 1.4 mmscf/d. The Company has signed four new five year interruptible contracts with customers adjacent to the ring main distribution pipeline namely Bora Industries Ltd, Aluminium Africa Ltd, Tanzania China Friendship Textile Co. Ltd and Nida Textile Mills Ltd. It is forecast that they will consume an additional 1.3 mmscf/d from EastCoast once they have completed the conversion of their boilers to burn natural gas (forecast to be completed during Q1 and Q2 2005). Three of the connections to these customers have been constructed and the fourth is currently under construction. In addition a contract has been signed with Karibu Textile Mills Ltd which will require the construction of an 8.6 kilometre plastic pipeline at a cost of US$ 1.1 million. It is forecast that this company will consume an average of 0.8 mmscf/d. In total it is forecast that gas sales to the industrial customers will increase to 2.7 mmscf/d by the end of Q2 2005 and 3.5 mmscf/d by the end of Q3 2005. Power sales As at 31 March 2005, Tanzania had approximately 812 MW of installed generation as follows: Feedstock Power Plant Installed capacity MW Hydro: Kidatu Mtera Hale Pangani Falls Kihansi Others Gas fired: Ubungo (units 1-5) 204 80 21 68 180 8 561 151 Other thermal: Independent Power of Tanzania Limited (“IPTL”) 100 Total 812 Photo above: kioo glass of dar es salaam was one of eastcoast’s first industrial customers. gas is supplied through the ring main distribution system. The majority of Tanzania’s generation is hydro and is therefore very dependent on the level of the rain during its two rainy seasons which run from November to December and March to May. The country has in the last two years had lower than average rainfalls, which has resulted in the actual hydro capacity being significantly less than its theoretical maximum. In addition the Kihansi hydro plant has been operating at less than 50% of the planned capacity due to environmental restrictions. The lower generation capacity of the hydro plants in 2004 meant that TANESCO had to base load electricity generation at IPTL, which utilises expensive Heavy Fuel Oil as a feedstock. The increase in the generation capacity at Ubungo as a result of the commissioning of the Songo Songo project ensured that there were no severe black outs during 2004, though demand was held back. TANESCO has stated its intention to balance its generation capacity by utilising the available gas and ensuring that the hydro is operated at lower rates allowing it to build up the water reserves. The gas fired generation is currently all owned by Songas and is fuelled by Protected Gas. Before the year end, Songas ordered a sixth GE turbine (34 MW) for installation at Ubungo, alongside the existing five turbines that are run on Protected Gas. The sixth turbine has already been shipped to Tanzania and is expected to be operational by Q3 2005 utilising Additional Gas. At 100% utilisation, it is forecast that the turbine would utilise 8.4 mmscf/d. TANESCO has the option to convert IPTL. Work has commenced to assess its technical feasibility and the World Bank has indicated its willingness to finance the conversion. However, whilst the conversion is eco- nomically attractive, disputes between the various interested parties in IPTL may hinder or even prevent the conversion work being undertaken. It is forecast that TANESCO will need to add 50 MW of generation capacity each year from 2007 to meet a 7% growth in demand for electricity. The cheapest generation capacity in the short term would be gas fired, but longer term the Company has to be competitive with other hydro and coal fired projects. Photo above left: potential customers for additional gas include cement plants in kenya. above right: six dar es salaam industries are connected to eastcoast’s ring main distribution system. Natural gas infrastructure at dar es salaam 1 7 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | Kioo ltdTanzania breweries ltdDar es SalaamPipeline connectionsat dar es salaamUbungoPower PlantWazo HillIPTLTanzania china textile co. ltdBora industries limitedKaribu textile mills limitedAluminium africa limitedNida textile mills ltdTie-ins for additional gasOn gas nowRing main under constructionRing main systemThermal generation8“ Pipeline16” Pipeline0 km5 MANAGEMENT’S DISCUSSION and ANALYSIS As at 15 April 2005 1 8 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | FORWARD LOOKING STATEMENTS: THIS DISCLOSURE CONTAINS CERTAIN FORWARD-LOOKING STATEMENTS THAT INVOLVE SUBSTANTIAL KNOWN AND UNKNOWN RISKS AND UNCERTAINTIES, CERTAIN OF WHICH ARE BEYOND EASTCOAST’S CONTROL, INCLUDING THE IMPACT OF GENERAL ECONOMIC CONDITIONS IN THE AREAS IN WHICH THE COMPANY OPERATES, CIVIL UNREST, INDUSTRY CONDITIONS, CHANGES IN LAWS AND REGULATIONS INCLUDING THE ADOPTION OF NEW ENVIRON- MENTAL LAWS AND REGULATIONS AND CHANGES IN HOW THEY ARE INTERPRETED AND ENFORCED, INCREASED COMPETITION, THE LACK OF AVAILABILITY OF QUALIFIED PERSONNEL OR MANAGEMENT, FLUCTUATIONS IN COMMODITY PRICES, FOREIGN EXCHANGE OR INTEREST RATES, STOCK MARKET VOLATILITY AND OBTAINING REQUIRED APPROVALS OF REG- ULATORY AUTHORITIES. IN ADDITION THERE ARE RISKS AND UNCERTAINTIES ASSOCIATED WITH GAS OPERATIONS. THEREFORE, EASTCOAST’S ACTUAL RESULTS, PERFORMANCE OR ACHIEVEMENT COULD DIFFER MATERIALLY FROM THOSE EXPRESSED, OR IMPLIED BY, THESE FORWARD-LOOKING ESTIMATES AND, ACCORDINGLY, NO ASSURANCES CAN BE GIVEN THAT ANY OF THE EVENTS ANTICIPATED BY THE FORWARD LOOKING ESTIMATES WILL TRANSPIRE OR OCCUR, OR IF ANY OF THEM DO SO, WHAT BENEFITS, INCLUDING THE AMOUNTS OF PROCEEDS, THAT EASTCOAST WILL DERIVE THEREFROM. B a ckg ro u n d EastCoast Energy Corporation’s (“EastCoast” or the “Company”) only operating asset is its interest in a Production Sharing Agreement (“PSA”) with the Tanzania Petroleum Development Corporation (“TPDC”) in Tanzania. This PSA covers the production and marketing of certain gas from the Songo Songo gas field. The gas in the Songo Songo field is divided between Protected Gas and Additional Gas. The Protected Gas is owned by TPDC and is sold under a 20 year gas agree- ment to Songas Limited (“Songas”). Songas is the owner of the infrastructure that enables the gas to be delivered to Dar es Salaam, namely a gas processing plant on Songo Songo Island, 232 kilometres of pipeline to Dar es Salaam and a 16 kilo- metres spur to the Wazo Hill Cement Plant. Songas utilises the Protected Gas (maximum 44.8 mmscf/d) as feedstock for five of its gas turbine electricity generators at Ubungo, for onward sale to the Wazo Hill Cement Plant and for some limited electrification for villages along the pipeline route. EastCoast receives no revenue for the gas delivered to Songas, but does operate the field and gas processing plant on a ‘no gain no loss’ basis. EastCoast is the operator of the natural gas development and has the right to produce and market all gas in the Songo Songo field in excess of the Protected Gas requirements (“Additional Gas”). P r i n c i p a l te r m s o f th e P S A a n d re l a te d a g re e m e n t s The principal terms of the Songo Songo PSA and related agree- ments are as follows: Obligations and restrictions (a) (b) The Company has the right to conduct petroleum opera- tions, market and sell all Additional Gas produced and share the net revenue with TPDC for a term of 25 years expiring in October 2026. The PSA covers the two licences in which the Songo Songo field is located (“Discovery Blocks”) and the seven licences adjoining the Discovery Block (“Adjoining Blocks”). Together the Discovery Blocks and Adjoining Blocks are the Contract Area. The Proven Section is a specified area within the Discovery Blocks. (c) The Company is obliged to fund work in return for their rights to explore for and sell Additional Gas. The Company’s right regarding the Adjoining Blocks is for the period from 1 9 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | Contract area SS-8SS-3SS-9SS-5SS-7SS-4SS-2SS-6SS-1Songo Songo IslandProven SectionDiscovery BlocksAdjoining BlocksContract area0500100015002000250030003500ThermalHydro200420032002200120001999199819971996199519941993199219911990050100150200SS-9SS-7SS-5SS-4SS-32004 Forecast Capacity1997 Forecast Capacity01020304050TBLKiooDecNovOctSept02004006008001000Line pack and flareAdditional gas salesProtected gas salesDecNovOctSepAugJuly05101520253035Wazo HillUbungoDecNovOctSeptAugJul 2 0 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | M A N AG E M E N T ’ S D I S C U S S I O N A N D A N A LYS I S October 2001 to October 2005. During this period, the Company must conduct a market survey, spend at least US$2.0 million (in October 2001 terms) on seismic or other field expenditures acceptable to TPDC, commit to drill one exploration well in the Adjoining Blocks by October 2006, demonstrate to the Ministry of Energy and Minerals (“MEM”) compliance with submitted Additional Gas plans and make diligent attempts to sell Additional Gas. If the MEM determines that the Company has failed to comply with these obligations, the Company’s rights to the Adjoining Blocks ceases. (d) No sales of Additional Gas may be made from the Discovery Blocks if in EastCoast’s reasonable judgement such sales would jeopardise the supply of Protected Gas. Any Additional Gas contracts entered into prior to 31 July 2009 are subject to interruption. Songas has the right to request that the Company and TPDC obtain security reasonably accept- able to Songas prior to making any sales of Additional Gas from the Discovery Block to secure the Company’s and TPDC’s obligations in respect of Insufficiency (see (f) below). (e) By 31 July 2009, the Government of Tanzania (“GoT”) can request EastCoast to sell 100 bcf of Additional Gas for the generation of electricity over a period of 20 years from the start of its commercial use, subject to a maximum of 6 bcf per annum or 20 mmscf/d (“Reserved Gas”). In the event that the GoT does not nominate by 31 July 2009 or consump- tion of the Reserved Gas has not commenced within three years of the nomination date, then the reservation shall terminate. Where Reserved Gas is utilised, TPDC and the Company will receive a price that is no greater than 75% of the market price of the lowest cost alternative fuel delivered at the facility to receive Reserved Gas or the price of the lowest cost alternative fuel at Ubungo. (f) “Insufficiency” occurs when there is insufficient gas from the Discovery Blocks to supply the Protected Gas requirements or is so expensive to develop that its cost exceeds the market price of alternative fuels at Ubungo. Where there have been third party sales of Additional Gas by EastCoast and TPDC from the Discovery Blocks prior to the occurrence of the Insufficiency then EastCoast and TPDC shall be jointly liable for the Insufficiency and shall satisfy its related liability by either replacing the Indemnified Volume (as defined in (g) below) at the Protected Gas price with natural gas from other sources; or by paying money damages equal to the difference between: (a) the market price for a quantity of alternative fuel that is appropriate for the five gas turbine electricity generators at Ubungo (“Complex”) without significant modification together with the costs of any modification; and (b) the sum of the price for such volume of Protected Gas (at US$0.55 per mmbtu) and the amount of transportation revenues previously credited by Songas to the electricity utility, TANESCO, for the gas volumes. (g) The “Indemnified Volume” means the lesser of the total volume of Additional Gas sales supplied from the Discovery Blocks prior to an Insufficiency and the Insufficiency Volume. “Insufficiency Volume” means the volume of natural gas determined by multiplying the average of the annual Protected Gas volumes for the three years prior to the Insufficiency (where the fifth turbine has been installed, but has not been operational for three years an imputed amount of annual gas consumption for the fifth turbine is incorporated) by 110% and multiplied by the number of remaining years (initial term of 20 years) of the power purchase agreement entered into between Songas and TANESCO in relation to the five gas turbine electricity generators at Ubungo from the date of the Insufficiency. Access and development of infrastructure (h) The Company is able to utilise the Songas infrastructure including the gas processing plant and main pipeline to Dar es Salaam. The pipeline and gas processing plant is open access and can be utilised by any third party who wishes to process or transport gas. Songas are not required to incur capital costs with respect to additional processing and transportation facilities unless the construction and operation of the facilities are, in the reasonable opinion of Songas, financially viable. If Songas is unable to finance such facilities, Songas shall permit the seller of the gas to construct the facilities at its expense, provided that, the facilities are designed, engineered and constructed in accordance with good pipeline and oilfield practices. Revenue sharing terms and taxation (i) 75% of the gross revenues less pipeline tariffs and direct sales taxes in any year (“Net Revenues”) can be used to recover past costs incurred. Costs recovered out of Net Revenues are termed Cost Gas. The Company pays and recovers all costs of exploring, developing and operating the Additional Gas with two exceptions: (i) TPDC may recover reasonable market and market research costs as defined under the PSA; and (ii) TPDC has the right to elect to participate in the drilling of at least one well for Additional Gas in the Contract Area for which there is a development program as detailed in the Additional Gas plans as submitted to the Ministry of Energy and Minerals (“Additional Gas Plan”) subject to TPDC being able to elect to participate in a development program only once and TPDC having to pay a proportion of the costs of such development program by committing to pay between 5% and 20% of the total costs (“Specified Proportion”). If TPDC does not notify the Company within 90 days of notice from the Company that the Ministry of Energy and Minerals has approved the Additional Gas Plan, then TPDC is deemed not to have elected. If TPDC elects to participate, then it will be entitled to a rateable proportion of the Cost Gas and a rateable share of the Profit Gas. (j) The price payable to Songas for the general processing and transportation of the gas is 17.5% of the price of gas delivered to a third party less any direct taxes payable by the customer that are included in the gas price less any tariffs paid for non-Songas owned distribution facilities (“Songas Outlet Price”). In September 2001, the GoT made a formal request to the World Bank for funds to increase the diameter of the onshore pipeline from 12 inches to 16 inches at a projected incremental cost of $3.5 million. The World Bank agreed to finance this increase and accordingly the pipeline capacity was increased from circa 65 mmscf/d to 105 mmscf/d. The tariff that is payable to GoT for this incremental capacity has yet to be agreed, but the Company has assumed it will be 17.5% of the Songas Outlet Price. (k) The cost of maintaining the wells and flowlines is split between the Protected Gas and Additional Gas users in propor- tion to the volume of their respective sales. The cost of operating the gas processing plant and the pipeline to Dar es Salaam is covered through the payment of the pipeline tariff. (l) Profits on sales from the Proven Section (“Profit Gas”) are shared between TPDC and the Company, the proportion of which is dependent on the average daily volumes of Additional Gas sold or cumulative production. The Company receives a higher share of the Net Revenues after cost recovery, the higher the cumulative production or the average daily sales, whichever is higher. The profit share is a minimum of 25% and a maximum of 55%. Average daily sales mmscfd 0 - 20 >20 <=30 >30 <=40 >40<=50 >50 Cumulative sales of Additional Gas bcf TPDC’s share of Profit Gas % Company’s share of Profit Gas % 0 - 125 >125<=250 >250<=375 >375<=500 >500 75 70 65 60 45 25 30 35 40 55 For Additional Gas produced outside of the Proven Section, the Company’s profit share increases to 55%. Where TPDC elects to participate in a development program, their profit share increases by the Specified Proportion (for that development program). The Company is liable to income tax. Where income tax is payable, there is a corresponding deduction in the amount of the Profit Gas payable to TPDC. (m) Additional Profits Tax is payable where the Company has recovered its costs plus a specified return out of Cost Gas revenues and Profit Gas revenues. As a result: (i) no Additional Profits Tax is payable until the Company recovers all its costs out of Additional Gas revenues plus 25% plus the percentage change in the United States Industrial Goods Producer Price Index (“PPI”) annual return; and (ii) the maximum Additional Profits Tax rate is 55% when costs have been recovered with a 35% plus PPI return. The PSA is, therefore, structured to encourage the Company to develop the market and the gas fields in the knowledge that the profit share can increase with larger daily gas sales and that the costs will be recovered with a 25% plus PPI annual return before Additional Profits Tax becomes payable. Additional Profits Tax can have a significant impact on the project economics if only limited capital expenditure is incurred. 2 1 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | M A N AG E M E N T ’ S D I S C U S S I O N A N D A N A LYS I S 2 2 Operatorship (n) (o) The Company is appointed to develop, produce and process Protected Gas and operate and maintain the gas produc- tion facilities and processing plant, including the staffing, procurement, capital improvements, contract maintenance, maintain books and records, prepare reports, maintain permits, handle waste, liaise with GoT and take all necessary safe, health and environmental precautions all in accordance with good oilfield practices. In return, the Company is paid or reimbursed by Songas so that the Company neither benefits nor suffers a loss as a result of its performance. In the event of loss arising from Songas’ failure to perform and the loss is not fully compensated by Songas, EastCoast, CDC or insurance coverage, then EastCoast is liable to a performance and operation guarantee of US$2,500,000 when (i) the loss is caused by the gross negligence or wilful misconduct of the Company, its subsidiaries or employees, and (ii) Songas has insufficient funds to cure the loss and operate the project. C o n s o l i d a t i o n Pursuant to a Scheme of Arrangement which was approved by the shareholders of PanOcean Energy Corporation (“PanOcean”) on 9 June 2004, the Company and its Tanzanian assets were spun off from PanOcean on 31 August 2004. Accordingly, the financial results contained herein are for the period 31 August 2004 to 31 December 2004. The results prior to 31 August 2004 are consolidated within PanOcean. The Consolidated Financial Statements have been prepared in accordance with the International Financial Reporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”) and interpretations issued by the Standing Interpretations Committee of the IASB. | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | The companies that are being consolidated are: Company EastCoast Energy Corporation PAE PanAfrican Energy Corporation PanAfrican Energy Tanzania Limited Incorporated British Virgin Islands Mauritius Jersey S ch e m e o f A r r a n g e m e n t a n d o p e n i n g B a l a n c e S h e e t a t 31 Au g u s t 2 0 0 4 The principal benefits of the Scheme of Arrangement in respect of the Tanzanian operations were to provide EastCoast with: .. Increased access to both debt and equity capital. The internal competition for capital within PanOcean and the different financing requirements for Tanzania had the potential to constrain the future development of the Tanzanian natural gas business. .. The ability to focus on gas exploration and production and the development of downstream infrastructure combined with marketing and gas-to-electricity conversion activity. The spin off was achieved by the distribution of the two entities that were party to the Songo Songo agreements to a new entity, EastCoast Energy Corporation. As part of the reorganisation, PanOcean agreed to ensure that the Company was adequately capitalised by: .. .. Financing the construction of the ring main distribution system up to a maximum of US$2.25 million; and Contributing minimum working capital of US$2.0 million to the Company less 50% of the legal fees associated with the spin off. O p e n i n g B a l a n c e S h e e t 2 3 The opening balance sheet of EastCoast as at the point of spin off from PanOcean on 31 August 2004 was as follows: US$’000 Assets Cash and cash equivalents Trade and other receivables Natural gas properties and other equipment Liabilities Current liabilities Trade and other payables Shareholders’ Equity Capital Stock Reserves As at 31 August, the Company had working capital of $2.4 million, and this may be analysed as follows: US$’000 Cash and cash equivalents Trade and other receivables PanOcean Energy Corporation Songas Limited Other receivables Total current liabilities Terasen International Songas Limited PanOcean Energy Corporation Accruals Total Working Capital As at 31 Aug 1,997 2,403 4,400 9,411 13,811 1,949 11,862 – 11,862 13,811 As at 31 Aug 1,997 1,682 434 287 2,403 1,417 247 132 153 1,949 2,451 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | M A N AG E M E N T ’ S D I S C U S S I O N A N D A N A LYS I S 2 4 Results for the period 31 August to 31 December 2004 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | Re ve n u e a n d o p e r a t i n g c o s t s The sales of Additional Gas commenced on 18 September 2004. Under the terms of the PSA with TPDC, EastCoast is responsible for invoicing, collecting and allocating the revenue. EastCoast is able to recover all costs incurred on the development and administration of the project out of 75% of the Net Revenues. Any costs not recovered in any period are carried forward to be recovered out of future revenues. Revenue less cost recovery is allocated 75% to TPDC and 25% to EastCoast. EastCoast had recoverable costs throughout the period to 31 December 2004 and accordingly was allocated 81.25% of the Net Revenues in the period as follows: Period ended (US$’000 except production and per mcf data) Gross sales volume (mcf) Average sales price (US$/mcf) Gross sales revenue Gross tariff for processing plant and pipeline infrastructure Gross net revenue after tariff Analysed as to: Company Cost Recovery Company Profit Gas TPDC Profit Gas Operating costs for Additional Gas: Ring main distribution pipeline Share of gas production costs Other operating costs Depletion 31 Dec 120,593 5.31 640 97 543 407 34 441 102 543 36 19 23 35 The tariff is calculated as 17.5% of the price of gas at the Songas main pipeline in Dar es Salaam (“Songas Outlet Price”). In calculating the Songas Outlet Price, 74 cents/mcf (“Ringmain Tariff”) has been deducted from the achieved sales price of US$5.31/mcf to reflect the gas price that would be achievable at the Songas main pipeline. The Ringmain Tariff represents the amount that would be required to compensate a third party distributor of the gas for constructing the connections from the Songas main pipeline to the industrial customers. The cost of maintaining the ring main distribution pipeline and pressure reduction station (security, insurance and personnel) is forecast to be approximately US$0.2 million per annum in its current form. The well maintenance costs are allocated between Protected and Additional Gas based on the proportion of their respective sales during the year. The total costs for the maintenance for the period was US$532,000 and US$19,000 was allocated for the Additional Gas. The well maintenance costs included the costs of pulling the down-hole pressure gauges and the remedial work on SS-9 as discussed in the Operational Review. P r i c i n g The price of gas for the period was at a discount to the price of Heavy Fuel Oil (“HFO”) in Dar es Salaam. This resulted in average gas prices of $5.31 per mcf over the period. The gas price achieved will fluctuate with world oil prices and the discount agreed with the customers. The price of HFO in Dar es Salaam in any particular month is estimated to be reflective of HFO prices in Dubai some two to three months prior to delivery, plus transportation costs. It is anticipated that a significant discount will be required to secure gas sales to the power sector. The average price for electricity in Tanzania is approximately 8.5 cents/kwh. This electricity price is comparable with other electricity tariffs in East Africa, but is significantly lower than the current prices achieved in western economies. The Company will be under pressure to keep gas prices at a level that enables TANESCO to be profitable. N e t b a ck s The netback per mcf before general and administrative costs and overheads may be analysed as follows: Period ended (US$/mcf) Average price for gas Tariff (after allowance for the Ringmain Tariff) TPDC profit share Net selling price Well maintenance Ring main distribution costs Net Back 31 Dec 5.31 (0.80) (0.85) 3.66 (0.35) (0.30) 3.01 Netbacks are currently high as all the sales in 2004 were to the industrial sector at prices that were below the cost of HFO in Dar es Salaam and the Company was recovering 75% of the Net Revenues as Cost Gas. The Netback per mcf is likely to fall if the Company secures gas sales for electricity generation. 2 5 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | M A N AG E M E N T ’ S D I S C U S S I O N A N D A N A LYS I S 2 6 G e n e r a l a n d Ad m i n i s t r a t i ve E x p e n s e s All general and administrative expenses (“G&A”), with the exception of stock-based compensation, were capitalised until com- mercial production of Additional Gas commenced on 18 September 2004. The G&A for the period may be analysed as follows: | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | Period ended (US$’000) Employee costs Stock based compensation Travel & accommodation Communications Office Consultants Insurance Auditing & taxation Other corporate Capitalised pre-operating costs Total general and administrative expenses 31 Dec 216 381 45 24 75 175 72 34 119 1,141 (87) 1,054 G&A is averaging approximately US$0.25 million per month (including the stock-based compensation. The cost per gross mcf sold was high at US$8.74/mcf. This will fall significantly when contracted sales increase as a large proportion of the G&A is relatively fixed in nature. Ta xe s Under the terms of the PSA, the Company is liable to Tanzanian income tax, but this is paid through the profit sharing arrange- ments with TPDC. Where income tax is payable the Company’s revenue will be grossed up by the tax due and the tax will be shown as a current tax. The Company has taxable losses brought forward and has incurred losses in the period under review. Therefore the Company was not liable to income tax during 2004. Under the terms of the PSA, in the event that all costs have been recovered with an annual return of 25% plus the percent- age change in the United States Industrial Goods Producer Price Index, an Additional Profits Tax (“APT”) is payable. As at 31 December 2004, there were un-recovered costs of $6.6 million and therefore no APT is payable. Management does not anticipate that any income tax or APT will be payable in 2005 as the forecast revenues will not be sufficient to cover the un-recovered costs brought forward and the expenditures incurred in 2005. The actual taxes paid will be dependent on the achieved value of the Additional Gas sales and the quantum and timing of the operating costs and capital expenditure programme. The APT can have a significant impact on the Songo Songo project economics as measured by the net present value of the cash flow streams. Higher revenue in the initial years leads to a rapid payback of the project costs and consequently acceler- ates the payment of the APT that can account for up to 55% of the Company’s profit share. Therefore, the terms of the PSA rewards the Company for taking higher risks by incurring capital expenditure in advance of revenue generation. D e p l e t i o n a n d D e p re c i a t i o n 2 7 The Natural Gas Properties are depleted using the unit of production method based on the production for the period as a percentage of the total future production from the Songo Songo proven reserves. As at 31 December 2004, the proven reserves as evaluated by the independent reservoir engineers, McDaniel & Associates Consultants Ltd (“McDaniels”) increased from 85.3 bcf as at the time of the spin off from PanOcean on 31 August 2004 to 171.5 bcf on a life of licence basis. As a consequence of this and changes in the forecast capital expenditure profile, the depletion charge per mcf decreased to US$0.29/mcf against US$0.44/mcf in Q3 2004. Re c ove r a b l e c o s t s As at 31 December 2004, the Company had US$6.6 million of costs that are recoverable out of 75% of the future Net Revenue. C a r r y i n g Va l u e o f A s s e t s Capitalised costs are periodically assessed to determine whether it is likely that such costs will be recovered in the future. To the extent that these capitalised costs are unlikely to be recovered in the future, they are written off and charged to earnings. As at 31 December 2004, McDaniels reviewed the level of the recoverable proven reserves on a life of licence basis and estimated the discounted future net revenues from the production of these proven reserves. Management has reviewed the current carrying value of the Tanzanian Natural Gas Properties as prepared by McDaniels and has concluded that there should not be a write off of these assets. C a s h f l ow Pre tax cash flows from operations decreased by US$0.3 million in the period to 31 December 2004 as there were limited Additional Gas sales to offset the principally fixed cost base. The components of the Company’s cash flow were as follows. Period ended (US$’000) Net loss before taxation Adjustment for non cash items Pre tax cash flows from operations Working capital adjustments Acquisition of natural gas properties and other equipment Net increase in cash and cash equivalent 31 Dec (727) 416 (311) 1,278 (924) 43 The significant movement in working capital is primarily attributable to the receipt of the majority of the spin off funds due from PanOcean and the retention of revenues from the Additional Gas sales that were paid to TPDC (profit share) and Songas (tariff) shortly after the year end and consequently included in creditors. C a p i t a l E x p e n d i t u re s Gross capital expenditure amounted to $0.9 million in the period to 31 December 2004. The capital expenditure may be analysed as follows: Period ended (US$’000) Geological and geophysical Pipelines and infrastructure Business development 31 Dec 147 480 297 924 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | M A N AG E M E N T ’ S D I S C U S S I O N A N D A N A LYS I S 2 8 At the end of 2004, work commenced on preparing for the 2005 seismic program including a re-evaluation of the existing seismic and an analysis of potential exploration leads. Costs associated with this work were capitalised. | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | The first phase of the construction of the ring main distribution pipeline was completed in September 2004. The ring main connects to the main pipeline at Ubungo (where the Protected Gas feeds into the power plants) and runs to five customers, namely Kioo Limited, Tanzania Breweries Limited, Nida Textiles Ltd, Bora Industries Ltd and Aluminium Africa Ltd. The total cost of the pipeline as at 31 December 2004 was US$2.25 million. Up to the commencement of gas sales in September, costs associated with the development of the gas market and admin- istrative costs were capitalised. Since September they have been expensed within G&A, with the exception of the year end employee bonus which was partially capitalised to reflect the amount that related to work performed pre the commence- ment of gas sales. Wo r k i n g c a p i t a l Working capital as at 31 December 2004 was US$1.2 million and may be analysed as follows: US$’000 Cash and cash equivalents Trade and other receivables Total current liabilities Working capital As at 31 Dec 2,040 441 2,481 1,265 1,216 Under the terms of the PSA and other Songo Songo agreements: .. The profit share owed to TPDC is payable within 30 days of each quarter end. Accordingly, the Company benefits from holding the cash receipts for this period of time and the quarter end cash balance is likely to increase as sales increase. As at 31 December, US$92,000 was owed to TPDC. .. .. Songas advances funds to cover all anticipated expenditure on the gas processing plant and wells in the following month. As at 31 December, US$251,000 of cash had been advanced by Songas to cover these operating expenses. The tariff for the use of the gas processing plant and pipeline infrastructure is payable to Songas within 30 days of each month end. As at 31 December, the Company owed Songas US$97,000 for the tariff. Also included in cash and cash equivalents was US$100,000 advanced by Tanzania China Friendship Textile Co Ltd as a deposit for their connection. This will be repaid to the company once they have consumed in excess of US$200,000 of Additional Gas. This amount is also shown in current liabilities. The majority of the cash is held in US dollars. There are no restrictions in Tanzania for converting Tanzania Schillings into US dollars. Any surplus cash is held in a fixed rate interest earning deposit account. Under the contract terms with the industrial customers, the Additional Gas payments must be received within 30 days of the month end. As at 31 December, Kioo Limited and Tanzania Breweries Limited were current in their payments and US$174,000 was due for the month of December (including VAT). Management forecasts that the Company will be able to meet its 2005 capital expenditure programme of US$5.2 million (primarily seismic and pipeline connections) through the Cdn$5.5 million of gross proceeds from the rights issue and inter- nally generated funds. In addition, the Company has no bank borrowings and there is scope for utilising debt funding once sufficient gas contracts are in place. O u t s t a n d i n g s h a re c a p i t a l 2 9 There were 21.1 million shares outstanding at 31 December 2004 and may be analysed as follows: No of shares (‘000) Shares outstanding Class A Shares Class B Shares Convertible securities: Options Fully diluted Class A and Class B shares Weighted average Class A and Class B Shares Options Weighted average diluted Class A and Class B Shares No new Class A or Class B Shares were issued between 31 August and 30 December 2004. Sto ck b a s e d c o m p e n s a t i o n As at 31Dec 1,751 19,386 21,137 2,000 23,137 21,137 2,000 23,137 The stock option plan provides for the granting of stock options to directors, officers, employees and consultants. Stock Options granted have a maximum term of ten year to expiry and vest equally over a two year period commencing 1 September 2004. The exercise price of each stock option is determined as the closing market price of the common shares on the day prior to the day of grant. Each stock option granted permits the holder to purchase one common share at the stated exercise price. In accordance with IFRS2, the Company records a charge to the profit and loss account using the Black & Scholes fair valuation option pricing model. The valuation is dependent on a number of estimates, including the risk free interest rate, the level of stock volatility, together with an estimate of the level of forfeiture. 2,000,000 options were issued to certain Directors and Officers on 1 September 2004. As at the year end, no eligible options had been exercised. C o n t r a c t u a l O b l i ga t i o n s a n d C o m m i t te d C a p i t a l I n ve s t m e n t The Company’s rights regarding the seven licences adjoining the Songo Songo field (“Adjoining Blocks”) are for the period until October 2005. If the Company wishes to retain the Adjoining Blocks, it must incur a minimum of US$2.0 million (in October 2001 terms) on seismic pre October 2005 and drill one well on the Adjoining Blocks before October 2006. This has not been shown as a commitment in the accounts as the Company has not yet approved the seismic program and a decision as to drill a well in 2006 will not be taken until the seismic program has been evaluated. On 19 January 2005 the Board of EastCoast approved the construction of a pipeline to sell gas to Karibu Textile Mills Ltd. The pipeline is to be constructed at a cost of US$1.1 million. This has not been shown as a commitment in the accounts as the Company had not approved the construction before the year end. Management expects to fund its committed capital investments from the proceeds of the rights issue in March 2005, self generated funds and debt. | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | 3 0 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | M A N AG E M E N T ’ S D I S C U S S I O N A N D A N A LYS I S Under the terms of the contracts with Kioo Limited, Tanzania Breweries Limited and Karibu Textile Mills Ltd, the Company is liable to pay penalties in the event that there is a shortfall in the Additional Gas supply in excess of 5% of the contracted quantity. The penalties equate to the difference between the price of gas and an alternative feedstock multiplied by the notional daily quantities. The maximum penalty for shortfall gas is US$1.1 million for these three contracts and the remedy is payable as a credit against future monthly invoices. Under the terms of the PSA, in the event that there is a shortfall in Protected Gas as a consequence of the sale of Additional Gas, then the Company is liable to pay the difference between the price of Protected Gas (US$0.55 a mmbtu) and the price of an alternative feedstock multiplied by the volumes of Protected Gas up to a maximum of the volume of Additional Gas sold. Songas has the right to request reasonable security on all Additional Gas sales. No security has been requested for the initial industrial gas sales, but Songas still retains this right and may require security for larger volumes. O f f - B a l a n c e s h e e t t r a n s a c t i o n s As at 31 December 2004, the Company had no off-balance sheet arrangements. O p e r a t i n g l e a s e s The Company has entered into a five year rental agreement for the use of the offices in Dar es Salaam at a cost of approximately $92,000 per annum. Re l a te d p a r t y t r a n s a c t i o n s The Company was spun off from PanOcean through a Scheme of Arrangement on 31 August 2004. W. David Lyons is the Chairman and controlling shareholder of both PanOcean and EastCoast. As part of the spin off, PanOcean provided the Company with certain working capital and other funding as more fully described under Opening Balance Sheet in this Management Discussion & Analysis. The Company has entered into an arms length agreement with PanOcean for the use of certain administrative and technical support services provided by PanOcean staff for the transitional period after the spin off. These services were not utilised in the period to 31 December 2004. In addition, the Chief Financial Officer of PanOcean, Robert Wynne, was awarded options in the Company for interim corporate advice. There have been no other transactions undertaken with related parties during the period ended 31 December 2004. P o s t B a l a n c e S h e e t E ve n t s On 19 January 2005, the Board of EastCoast approved the construction of a pipeline to sell gas to Karibu Textile Mills Ltd. The pipeline is to be constructed at a cost of US$1.1 million. On 4 March 2005, the Company successfully completed the rights issue through the issue of 2,113,744 Class B shares at a price of Cdn$2.60 per share. This raised Cdn$5.5 million for the Company (Cdn$5.4 million after expenses). E a s t C o a s t C o r p o r a t i o n There are numerous factors which may affect the success of EastCoast's business which are beyond EastCoast's control includ- ing local, national and international economic and political conditions. EastCoast's business will involve a high degree of risk which a combination of experience, knowledge and careful evaluation may not overcome. The operations of EastCoast in East Africa, will expose EastCoast to risks such as political and currency risks. The Corporation is at a relatively early stage of development and accordingly there are numerous uncertainties in estimating gas reserves and in projecting future production, costs and expenses and the results, timing and costs of exploration and development projects, as well as the timing and costs associated with the realisation of markets for natural gas production. O p e r a t i n g H a z a rd s a n d U n i n s u re d R i s k s 3 1 The business of EastCoast is subject to all of the operating risks normally associated with the exploration for, and the produc- tion, storage, transportation and marketing of oil and gas. These risks include blowouts, explosions, fire, gaseous leaks, migration of harmful substances and oil spills, any of which could cause personal injury, result in damage to, or destruction of, oil and gas wells or formations or production facilities and other property, equipment and the environment, as well as interrupt operations. In addition, all of EastCoast's operations will be subject to the risks normally incident to drilling of natural gas wells and the operation and development of gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blowouts, equipment failures and other accidents, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution and other environmental risks. Drilling conducted by EastCoast overseas will involve increased drilling risks of high pressures and mechanical difficulties, including stuck pipe, collapsed casing and separated cable. The impact that any of these risks may have upon EastCoast is increased due to the fact that EastCoast currently only has one producing property. EastCoast will maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant unfavourable event not fully covered by insurance could have a material adverse effect on EastCoast's financial condition, results of operations and cash flows. Furthermore, EastCoast cannot predict whether insurance will continue to be available at a reasonable cost or at all. Fo re i g n O p e r a t i o n s All of EastCoast's operations and related assets will be located in countries which may be considered to be politically and/or economically unstable. Exploration or development activities in such countries may require protracted negotiations with host governments, national oil companies and third parties and are frequently subject to economic and political considerations, such as, the risks of war, actions by terrorist or insurgent groups, expropriation, nationalization, renegotiation or nullification of existing contracts, taxation policies, foreign exchange restrictions, changing political conditions, international monetary fluctuations, currency controls and foreign governmental regulations that favour or require the awarding of drilling contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. In addition, if a dispute arises with foreign operations, EastCoast may be subject to the exclusive jurisdiction of foreign courts. In the foreign countries in which EastCoast will conduct business, currently limited to Tanzania, the state generally retains ownership of the minerals and consequently retains control of (and in many cases, participates in) the exploration and production of hydrocarbon reserves. Accordingly, these operations may be materially affected by host governments through royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses and other charges. All of EastCoast's development properties and all of its proved natural gas reserves will be located offshore and on the Songo Songo Island in Tanzania, and, consequently, EastCoast's assets will be subject to regulation and control by the government of Tanzania and certain of its national and parastatal organizations. EastCoast and its predecessors have operated in Tanzania for a number of years and believe that it has good relations with the current Tanzanian government. However, there can be no assurance that present or future administrations or governmental regulations in Tanzania will not materially adversely affect the operations or future cash flows of EastCoast. Ad d i t i o n a l F i n a n c i n g Depending on future exploration, development, and marketing plans, EastCoast may require additional financing. The ability of EastCoast to arrange such financing in the future will depend in part upon the prevailing capital market conditions as well as the business performance of EastCoast. There can be no assurance that EastCoast will be successful in its efforts to arrange additional financing on terms satisfactory to EastCoast. If additional financing is raised by the issuance of shares from treasury of EastCoast, control of EastCoast may change and shareholders may suffer additional dilution. From time to time EastCoast may enter into transactions to acquire assets or the shares of other companies. These transactions may be financed partially or wholly with debt, which may temporarily increase EastCoast's debt levels above industry standards. | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | M A N AG E M E N T ’ S D I S C U S S I O N A N D A N A LYS I S 3 2 I n d u s t r y C o n d i t i o n s | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | The oil and gas industry is intensely competitive and EastCoast competes with other companies which possess greater technical and financial resources. Many of these competitors not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum, natural gas products and other products on an international basis. Oil and gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and invasion of water into producing formations. Currently, EastCoast's Songo Songo natural gas property is operated by EastCoast. There is a risk that in the future either the operatorship could change and the property operated by third parties or operations may be subject to control by national oil companies, Songas, or other parastatal organisations and, as a result, EastCoast may have limited control over the nature and timing of exploration and development of such properties or the manner in which operations are conducted on such properties. The marketability and price of natural gas which may be acquired, discovered or marketed by EastCoast will be affected by numerous factors beyond its control. There is currently no developed natural gas market in Tanzania and no infrastructure with which to serve potential new markets beyond that being constructed by EastCoast and Songas. The ability of EastCoast to market any natural gas from current or future reserves may depend upon its ability to develop natural gas markets in Tanzania and the surrounding region, obtain access to the necessary infrastructure to deliver sales gas volumes, including acquiring capacity on pipelines which deliver natural gas to commercial markets. EastCoast is also subject to market fluctua- tions in the prices of oil and natural gas, uncertainties related to the delivery and proximity of its reserves to pipelines and processing facilities and extensive government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and gas and many other aspects of the oil and gas business. EastCoast is also subject to a variety of waste disposal, pollution control and similar environmental laws. The oil and natural gas industry is subject to varying environmental regulations in each of the jurisdictions in which EastCoast may operate. Environmental regulations place restrictions and prohibitions on emissions of various substances produced concurrently and oil and natural gas and can impact on the selection of drilling sites and facility locations, potentially result- ing in increased capital expenditures. Ad d i t i o n a l G a s EastCoast has the right, under the terms of the PSA, to market volumes of Additional Gas subject to satisfying the require- ments to deliver Protected Gas to Songas. There is a risk that Songas could interfere in EastCoast's ability to produce, transport and sell volumes of Additional Gas if EastCoast's obligations to Songas under the Gas Agreement are not met. In particular, Songas has the right to request reasonable security on all Additional Gas sales. Re p l a c e m e n t o f Re s e r ve s EastCoast's natural gas reserves and production and, therefore, its cash flows and earnings are highly dependent upon EastCoast developing and increasing its current reserve base and discovering or acquiring additional reserves. Without the addition of reserves through exploration, acquisition or development activities, EastCoast's reserves and production will decline over time as reserves are depleted. To the extent that cash flow from operations is insufficient and external sources of capital become limited or unavailable, EastCoast's ability to make the necessary capital investments to maintain and expand its oil and natural gas reserves will be impaired. There can be no assurance that EastCoast will be able to find and develop or acquire additional reserves to replace production at commercially feasible costs. A s s e t C o n c e n t r a t i o n EastCoast's natural gas reserves are limited to one property, the Songo Songo field, and the production potential from this field is currently limited to five wells. There has been limited production from the five wells in the Songo Songo field to date. There is no assurance that EastCoast will have sufficient deliverability through the existing wells to provide additional natural gas sales volumes, and that there may be significant capital expenditures associated with any remedial work or new drilling required to achieve deliverability. In addition, any difficulties relating to the operation or performance of the field would have a material adverse effect on EastCoast. E n v i ro n m e n t a l a n d O th e r Re g u l a t i o n s 3 3 Extensive national, state, and local environmental laws and regulations in foreign jurisdictions will affect nearly all of EastCoast's operations. These laws and regulations set various standards regulating certain aspects of health and environmen- tal quality, provide for penalties and other liabilities for the violation of such standards and establish in certain circumstances obligations to remediate current and former facilities and locations where operations are or were conducted. In addition, special provisions may be appropriate or required in environmentally sensitive areas of operation. There can be no assurance that EastCoast will not incur substantial financial obligations in connection with environmental compliance. Significant liability could be imposed on EastCoast for damages, cleanup costs or penalties in the event of certain discharges into the environment, environmental damage caused by previous owners of property purchased by EastCoast or non-compliance with environmental laws or regulations. Such liability could have a material adverse effect on EastCoast. Moreover, EastCoast cannot predict what environmental legislation or regulations will be enacted in the future or how existing or future laws or regulations will be administered or enforced. Compliance with more stringent laws or regulations, or more vigorous enforce- ment policies of any regulatory authority, could in the future require material expenditures by EastCoast for the installation and operation of systems and equipment for remedial measures, any or all of which may have a material adverse effect on EastCoast. As party to various licenses, EastCoast has an obligation to restore producing fields to a condition acceptable to the authorities at the end of their commercial lives. While management believes that EastCoast is currently in compliance with environmental laws and regulations applicable to EastCoast's operations in Tanzania, no assurances can be given that EastCoast will be able to continue to comply with such environmental laws and regulations without incurring substantial costs. EastCoast's petroleum and natural gas operations are subject to extensive governmental legislation and regulation and increased public awareness concerning environmental protection. No provision has been recognized for future decommissioning costs which are anticipated to be immaterial as it is forecast that there will still be commercial gas reserves once EastCoast relinquishes the licence in 2026. EastCoast expects that the cost of complying with environmental legislation and regulations will increase in the future. Compliance with existing envi- ronmental legislation and regulations has not had a material effect on capital expenditures, earnings or competitive position of EastCoast to date. Although management believes that EastCoast's operations and facilities are in material compliance with such laws and regulations, future changes in these laws, regulations or interpretations thereof or the nature of its operations may require the Company to make significant additional capital expenditures to ensure compliance in the future. Vo l a t i l i t y o f O i l a n d G a s P r i c e s a n d M a r ke t s EastCoast's financial condition, operating results and future growth will be dependent on the prevailing prices for its natural gas production. Historically, the markets for oil and natural gas have been volatile and such markets are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes to the demand for oil and natural gas, whether the result of uncertainty or a variety of additional factors beyond the control of EastCoast. Any substantial decline in the prices of oil and natural gas could have a material adverse effect on EastCoast and the level of its economic natural gas reserves. Additionally, the economics of producing from some wells may change as a result of lower prices, which could result in a suspension of production by EastCoast. No assurance can be given that oil and natural gas prices will be sustained at levels which will enable EastCoast to operate profitably. From time to time EastCoast may avail itself of forward sales or other forms of hedging activities with a view to mitigating its exposure to the risk of price volatility. The Songo Songo field is the first gas field to be developed in East Africa. The Company has therefore been able to negotiate gas sales contracts with gas prices that are at a discount to the lowest cost alternative fuels in Dar es Salaam namely HFO. Recently, there has been increased activity in the exploration of oil and gas in Tanzania, with the result that one well has been drilled on an adjacent prospect to Songo Songo, a gas well may be shortly re-entered in the south of Tanzania at Mnazi Bay and a number of Production Sharing Agreements are being negotiated for the drilling offshore Tanzania. These developments will be closely monitored by the Company, but could lead to increased competition for gas markets and lower gas prices in the future. | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | 3 4 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | M A N AG E M E N T ’ S D I S C U S S I O N A N D A N A LYS I S In addition, various factors, including the availability and capacity of oil and gas gathering systems and pipelines, the effect of foreign regulation of production and transportation, general economic conditions, changes in supply due to drilling by other producers and changes in demand may adversely affect EastCoast's ability to market its gas production. Any significant decline in the price of oil or gas would adversely affect EastCoast's revenues, operating income, cash flows and borrowing capacity and may require a reduction in the carrying value of EastCoast's gas properties and its planned level of capital expenditures. U n c e r t a i n t i e s i n E s t i m a t i n g Re s e r ve s a n d Fu t u re N e t C a s h F l ow s There are numerous uncertainties inherent in estimating quantities of proved and probable reserves and cash flows to be derived therefrom, including many factors beyond the control of EastCoast. The reserve and cash flow information contained herein represents estimates only. The reserves and estimated future net cash flow from EastCoast's properties have been independently evaluated by McDaniel & Associates Consultants Ltd. These evaluations include a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, crude oil price differentials to benchmarks, future prices of oil and natural gas, operating costs, transportation costs, cost recovery provisions and royalties and other government levies that may be imposed over the producing life of the reserves. These assumptions were based on price forecasts in use at the date of the relevant evaluations were prepared and many of these assumptions are subject to change and are beyond the control of EastCoast. Actual production and cash flows derived therefrom will vary from these evaluations, and such variations could be material. T i t l e to P ro p e r t i e s Although title reviews have been done and will continue to be done according to industry standards prior to the purchase of most oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the claim of EastCoast which could result in a reduction of the revenue received by EastCoast. Ac q u i s i t i o n R i s k s EastCoast intends to acquire natural gas infrastructure and possibly additional oil and gas properties. Although EastCoast performs a review of the acquired properties that it believes is consistent with industry practices, such reviews are inherent- ly incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, EastCoast will focus its due diligence efforts on the higher valued properties and will sample the remainder. However, even an in depth review of all properties and records may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not be performed on every well, and structural or environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. EastCoast may be required to assume pre-closing liabilities, including environmental liabilities, and may acquire interests in properties on an “as is” basis. There can be no assurance that EastCoast's acquisitions will be successful. Re l i a n c e o n Key Pe r s o n n e l EastCoast is highly dependent upon its executive officers and key personnel. The unexpected loss of the services of any of these individuals could have a detrimental effect on EastCoast. EastCoast does not maintain key man life insurance on any of its employees.W C o n t ro l l i n g S h a re h o l d e r W David Lyons, the Company’s Non Executive Chairman, is the sole controlling shareholder of EastCoast and holds approxi- mately 99.3% of the outstanding Class A shares and approximately 16.0% of the Class B shares. Consequently, Mr Lyons holds approximately 22.9% of the equity and controls 69.6% of the total votes of EastCoast. S u m m a r y o f Q u a r te r l y re s u l t s 3 5 EastCoast was a subsidiary of PanOcean until 31 August 2004. Accordingly, the following results are for the period ended 30 September 2004 and the quarter ending 31 December 2004. US$’000 except where otherwise stated Period ended 30 September 2004 Q4 2004 Gross Revenue Average sales (mmscf/d) Average price (US$/mcf) Loss for the period Operating cash flow before working capital changes Capital expenditure on natural gas properties Total assets Loss per share Basic (US$) Diluted (US$) Fo u r th q u a r te r 50 1.1 5.41 (84) (4) 158 391 1.2 5.31 (642) (307) 766 13,259 12,781 0.004 0.004 0.030 0.030 The principal developments in Q4 were as follows: .. Average Additional Gas sales increased marginally to 1.2 mmscf/d. In November, Tanzania Breweries Limited reduced its forecast consumption by approx 0.5 mmscf/d as a result of cracks in the boiler tubes on two of its boilers. These boilers are in the process of being replaced and TBL’s consumption should increase to 0.7 mmscf/d by June 2005. .. .. .. .. .. The average price of gas in Q4 was US$5.31/mcf against US$5.41 in Q3. The monthly range was US$5.21/mcf to US$5.50/mcf. An interruptible conditional contract was signed with Karibu Textile Mills Ltd for the supply of an expected 0.8 mmcf/d of gas in Q3 2005. Shortly after the year end, the Company committed to the construction of a gas pipeline to this customer at a cost of US$1.1 million. A pipeline connection to the 100 MW power plant, Independent Power of Tanzania Limited (financed by the World Bank) was completed in Q4. If this plant is converted to gas from HFO it would consume a maximum of 26 mmscf/d at a 100% utilisation rate, though this is uncertain. The depletion charge for the quarter decreased from US$0.44/mcf in Q3 to US$0.29/mcf in Q4 primarily as a result of the increase in the proven reserves from 85.3 bcf to 171.5 bcf. Capital expenditure increased to US$766,000 with the completion of the initial phase of the ring main distribution system and the commencement of work on the 2005 seismic program. | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | 3 6 M A N AG E M E N T ’ S R E P O RT The accompanying financial statements of EastCoast Energy Corporation and all other financial and operating information contained in this Annual Report are the responsibility of management. The financial statements have been prepared in accordance with accounting policies detailed in the notes to the financial statements and in accordance with the International Financial Reporting Standards. Financial statements are not precise as they include certain amounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the statements are prepared fairly, in all material respects. Financial information presented elsewhere in this annual report has been prepared on a basis consistent with that in the financial statements. The Company’s systems of internal control have been designed and maintained to provide reasonable assurance that assets are properly safeguarded and that the financial records are sufficiently well maintained to provide relevant, timely and reliable information to management. External auditors, appointed by the shareholders, have independently examined the financial statements. They have performed such tests as they deemed necessary to enable them to express an opinion on these financial statements. An Audit Committee of the Board of Directors, has reviewed these financial statements with management and external auditors. The Board of Directors, has approved the financial statements on the recommendation of the Audit Committee. | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | John Patterson Director Nigel Friend Chief Financial Officer AU D I TO R S ’ R E P O RT 3 7 We have audited the Consolidated Balance Sheet of EastCoast Energy Corporation as at 31 December 2004 and the Consolidated Statements of Income, Changes in Shareholders’ Equity and Cash Flows for the period from 31 August 2004 to 31 December 2004. These Consolidated Financial Statements are the responsibility of the Company’s Directors. Our respon- sibility is to express an opinion on these Consolidated Financial Statements based on our audits. We conducted our audits in accordance with International and Canadian Standards on Auditing. Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Consolidated Financial Statements. An audit also includes assessing the accounting principles used and significant estimates made by the Directors, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, these Consolidated Financial Statements give a true and fair view of the financial position of the Company as at 31 December 2004 and the results of its operations and its cash flows for the period from 31 August 2004 to 31 December 2004 in accordance with International Financial Reporting Standards. Calgary, Canada 15 April 2005 COMMENTS BY AUDITORS FOR CANADIAN READERS ON INTERNATIONAL – CANADIAN REPORTING DIFFERENCES Canadian reporting standards may differ from International Financial Reporting Standards and International Standards on Auditing in the form and content of the auditors' report, depending on the circumstances. However, had this auditors' report been prepared in accordance with Canadian reporting standards, there would be no material differences in the form and content of this auditors' report. Furthermore, an auditors' report prepared in accordance with Canadian reporting standards on the aforementioned consolidated financial statements would not contain a qualification of opinion. Calgary, Canada 15 April 2005 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | 3 8 CO N S O L I DAT E D I N CO M E S TAT E M E N T | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | (thousands of US dollars except per share amounts) Revenue Operating Cost of sales Production and distribution expenses Depletion Gross profit Other income Administrative expenses Other operating expenses Loss before taxation Taxation Loss for the period Loss per share Basic (US$) Diluted (US$) See accompanying notes to the consolidated financial statements. Period ended 31 December 2004 2 441 (78) (35) 328 7 (1,054) (8) (727) – (727) 0.034 0.034 3 5 13 CO N S O L I DAT E D B A L A N C E S H E E T 3 9 (thousands of US dollars) ASSETS Current assets Cash and cash equivalents Trade and other receivables Natural gas properties LIABILITIES Current liabilities Trade and other payables SHAREHOLDERS’ EQUITY Capital stock Capital reserve Accumulated loss See accompanying notes to the consolidated financial statements. The consolidated financial statements were approved by the Board on 15 April 2005. Director Director Note As at 31 December 2004 7 8 9 2,040 441 2,481 10,300 12,781 10 1,265 12 11,862 381 (727) 11,516 12,781 [ E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T ] 4 0 CO N S O L I DAT E D S TAT E M E N T O F C A S H F LOW S | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | (thousands of US dollars) CASH FLOWS FROM OPERATING ACTIVITIES Net loss Adjustments for: Depletion Stock-based compensation Operating loss before working capital changes Decrease in trade and other receivables Decrease in trade and other payables Net cash flow from operating activities CASH FLOWS FROM INVESTING ACTIVITIES Acquisition of natural gas properties Net increase in cash and cash equivalents Cash and cash equivalents at 31 August 2004 Cash and cash equivalents at 31 December 2004 See accompanying notes to the consolidated financial statements. Period ended 31 December 2004 (727) 35 381 (311) 1,962 (684) 967 (924) 43 1,997 2,040 S TAT E M E N T O F C H A N G E S I N E Q U I T Y 4 1 (thousands of US dollars) Capital stock Capital reserve Accumulated reserve Total loss Balance as at 31 August 2004 Loss for the period Stock-based compensation 11,862 – – Balance as at 31 December 2004 11,862 – – 381 381 – (727) – (727) 11,862 (727) 381 11,516 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | N OT E S TO T H E CO N S O L I DAT E D F I N A N C I A L S TAT E M E N T S 4 2 General Information | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | EastCoast Energy Corporation (“EastCoast” or the “Company”) was incorporated on 28 April 2004 under the laws of the British Virgin Islands. Between 28 April 2004 and 30 August 2004, EastCoast was a 100% subsidiary of PanOcean Energy Corporation Limited (“PanOcean”). On 31 August, as part of a Scheme of Arrangement, the Class A and Class B Subordinated Voting Shares of the Company were distributed to the PanOcean shareholders and the Company was listed on the TSX Venture Exchange under the symbols ECE.MV.A and ECE.SV.B. These financial statements are the first audited Consolidated Financial Statements to be prepared by the Company since it was spun out from PanOcean and covers the period 31 August 2004 to 31 December 2004. The Company is a participant in a gas-to-electricity project in Tanzania. The Company’s operations at the Songo Songo gas field in Tanzania include the operation of five producing wells and two 35 mmcf/d dehydration and refrigeration gas processing units on Songo Songo Island on behalf of Songas Limited (“Songas”). Gas produced and sold from the Songo Songo field is classified as either Protected Gas or Additional Gas. Protected Gas is 100% owned by Tanzania Petroleum Development Corporation (“TPDC”) and is being sold to Songas under a twenty year Gas Agreement primarily for use at the Ubungo Power Plant and the Wazo Hill cement plant. The Protected Gas can only be used principally as feedstock for specified turbines and kilns. Gas sales in excess of that required for the Protected Gas users is categorized as Additional Gas. The Company has the exclusive right to explore, develop, produce and market all Additional Gas. Revenues from the sale of Additional Gas, net of transportation tariff, are shared with TPDC in accordance with the terms of the Production Sharing Agreement (“PSA”) until October 2026. Basis of preparation These Consolidated Financial Statements are measured and presented in US dollars as the main operating cash flows are linked to this currency through the commodity price. Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the period. Actual results could differ from these estimates. 1 S U M M A R Y O F S I G N I F I C A N T A C C O U N T I N G P O L I C I E S a) Statement of compliance The Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”) and interpretations issued by the Standing Interpretations Committee of the IASB. In all material respects, these accounting principles are generally accepted in Canada except as described in Note 14. b) Basis of consolidation i) Subsidiaries The Consolidated Financial Statements include the accounts of the Company and all its subsidiaries (collectively, the “Company”). Subsidiaries are those enterprises controlled by the Company. Control exists when the Company has the power, directly or indirectly, to govern the financial or operating policies of those enterprises. The financial statements of subsidiaries are included in the Consolidated Financial Statements from the date that control commences until the date that control ceases. The following companies have been consolidated within the financial statements: Subsidiary PAE PanAfrican Energy Corporation PanAfrican Energy Tanzania Limited Mauritius Jersey Registered Holding 100 percent 100 percent ii) Transactions eliminated upon consolidation 4 3 Intra-company balances and transactions, and any unrealised gains arising from intra-company transactions, are eliminated in preparing the Consolidated Financial Statements. c) Foreign currency Foreign currency transactions are recorded at the rate of exchange prevailing at the date of the transaction. Monetary assets and liabilities in foreign currencies are translated at period-end rates. Non-monetary items are translated at historic rates, unless such items are carried at market value, in which case they are translated using the exchange rates that existed when the values were determined. Any resulting exchange rate differences are taken to the income statement. d) Derivative financial instruments The Company may use derivative financial instruments to hedge its exposure to foreign exchange, interest rate and commodity price risks arising from operational, financing and investment activities. In accordance with its treasury policy, the Company does not hold or issue derivative financial instruments for trading purposes. However, derivatives that do not qualify for hedge accounting are accounted for as trading instruments. Derivative financial instruments are initially recorded at cost. Subsequent to initial recognition, derivative financial instruments are stated at fair value. Recognition of any resultant gain or loss depends on the hedge accounting model applied. e) Carried Interest The Company conducts certain international operations jointly with foreign governments or parastatal entities in accordance with production sharing agreements. Under these agreements, the Company pays both its share and the parastatal’s share of operating, administrative and capital costs. The Company recovers all the operating, administrative and capital costs including the parastatal’s share of these costs from future revenues over several years. The paras- tatal’s share of operating and administrative costs are recorded in operating and general and administrative costs when incurred and capital costs are recorded in ‘Natural Gas Properties’. All recoveries are recorded as revenue in the year of recovery in accordance with accounting policy 1 (m). f) Natural gas properties The Company follows the full cost method of accounting for natural gas operations. Capitalised costs include land acquisition, geological and geophysical activities, lease rentals on non-producing properties, drilling both productive and non-productive wells, pipeline and related gas distribution equipment, market development and overhead charges directly related to exploration and development activities. Costs are depleted on the unit-of-production method based on the estimated proved reserves as estimated by independent reservoir engineers. Costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties, or impairment occurs. Costs incurred are not depleted until commercial production commences. These capitalised costs are periodically assessed to determine whether it is likely that such costs will be recovered in the future. To the extent that there are costs that are unlikely to be recovered in the future, they are written off and charged to earnings. Capitalised costs, less accumulated depletion are limited to an amount equal to the estimated discounted future net revenue from proven reserves plus the cost (net of impairments) of unproven properties. Proceeds from the sale of natural gas properties are applied against capital costs with no gain or loss recognized, unless the sale would alter the depletion and depreciation rate by 20% or more. g) Operatorship The Company operates the gas field, flow lines and gas processing plant on behalf of Songas at cost. | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | 4 4 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | N OT E S TO T H E CO N S O L I DAT E D F I N A N C I A L S TAT E M E N T S The cost of operating and maintaining the wells and flow lines is paid for by EastCoast and Songas in proportion to the respective volumes of Protected Gas and Additional Gas sales. The costs of operating and maintaining the wells and flow lines are reflected in the accounts to the extent that the costs were incurred to accomplish Additional Gas sales. The cost of operating the gas processing plant is paid by Songas. Where there are Additional Gas sales, a transportation tariff is paid to Songas as compensation for using the gas processing plant. This transportation tariff is netted off revenue in accordance with accounting policy 1 (m). h) Trade and other receivables Trade and other receivables are stated at cost less impairment losses. i) Cash and cash equivalents Cash and cash equivalents include cash on deposit and highly liquid investments with original maturities of three months or less. j) Impairment Consideration is given on each balance sheet date to determine whether there is any indication of impairment of the carrying value of the Company’s assets. If any indication exists, an asset’s recoverable amount is estimated. An impair- ment loss is immediately recognised in the income statement whenever the carrying value of an asset exceeds its estimated recoverable amount. The recoverable amount is the greater of the selling price and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a risk adjusted discount factor. k) Employment benefits i) Pension The Company does not operate a pension plan, but it does make defined contributions to the statutory pension fund for employees in Tanzania. Obligations for contributions to the statutory pension fund are recognised as an expense in the income statement as incurred. ii) Equity and equity-related compensation benefits The share option plan programme allows Company officers, directors and key personnel to acquire shares at an exercise price determined by the Company. When the options are exercised, equity is increased by the amount of the proceeds received. The Company accounts for stock based compensation under the rules of IFRS2, Accounting for Share-Based Payments, whereby the fair value of such options is expensed to the income statement in accordance with the specific vesting periods. The fair value of the options is calculated on the grant date using the Black-Scholes option pricing model and the assumptions described in note 12. iii) Bonuses Bonuses received by Company senior management are discretionary. Any bonuses specific to exploration and development activities are capitalized against the carrying value of the assets. Other period-end bonuses are recognised in the income statement for the period to which they relate. l) Provisions A provision is recognised in the balance sheet when the Company has a legal or constructive obligation as a result of a past event and it is probable that an outflow of economic benefits will be required in the future to settle the obligation. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre- tax rate that reflects the current market assessments of the time value of money and, where appropriate, the risks specific to the liability. No provision has been made for future site restoration costs since the Company has no obligation under the PSA to restore the fields at the end of their commercial lives. m) Revenue recognition 4 5 Revenue represents the Company’s share of gas sales during the period, net of the transportation tariff as described in note l (g). The revenue includes those costs that may be recovered under the terms of production sharing agree- ments including those paid on behalf of parastatal organisations. n) Operating lease payments Payments made under operating leases are recognised in the income statement on a straight-line basis over the term of the lease. o) Taxation Income tax on the profit for the period comprises current and deferred tax. The Company is liable to Tanzanian income tax, but this is paid through the profit sharing arrangements with TPDC. Where income tax is payable, the Company’s net revenue is grossed up for the tax and the income tax shown as current tax. Under the terms of the PSA, in the event that all costs have been recovered with an annual return of 25% plus the percentage change in the United States Industrial Goods Producer Price Index, an additional profits tax is payable to the Government of Tanzania. Deferred tax is provided using the balance sheet liability method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. The amount of deferred tax provided is based on the expected manner of realisation or settlement of carrying amount of assets and liabilities using tax rates substantively enacted at the balance sheet date. A deferred tax asset is recognised only to the extent that it is probable that future taxable profits will be available against which the assets can be utilised. Deferred tax assets are reduced to the extent that it is no longer probable that the related tax benefits will be realised. p) Segmental reporting No segmental information has been presented, since all the revenue generating operations and assets are located in Tanzania. q) Discontinued operations A discontinued operation is a clearly distinguishable component of the Company’s business that is abandoned or ter- minated pursuant to a single plan and, accordingly, the Company only reflects its proportionate interest in such activities. 2 R e v e n u e Operating revenue Period ended 31 December 2004 441 The Company started commercial gas sales on 18 September 2004. The revenue reported is the Company’s propor- tionate share of revenue as calculated in accordance with the accounting policy 1(m). 3 O t h e r O p e r a t i n g E x p e n s e s Foreign exchange loss Period ended 31 December 2004 8 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | N OT E S TO T H E CO N S O L I DAT E D F I N A N C I A L S TAT E M E N T S 4 6 4 P e r s o n n e l E x p e n s e s The average number of employees during the period was ten. The costs, net of Songas recharges for the operator- ship of the gas processing plant, are as follows: | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | Wages and salaries Social security costs Other statutory staff costs Capitalised pre-operating costs Period ended 31 December 2004 169 25 22 216 (33) 183 Staff costs prior to the commencement of commercial production of Additional Gas on 18 September 2004 have been capitalized. 5 Ta x a t i o n The Company is liable for income tax when costs incurred under the Production Sharing Agreement (“PSA”) with TPDC have been recovered out of net revenues. Where income tax is payable, the profit available to TPDC is reduced by a corresponding amount. This is reflected in the accounts by grossing up the amount of the Company’s net revenue for the income tax and showing the income tax as a current tax. During the period under review, the Company had not recovered the PSA costs out of Net Revenues and accordingly, the Company was not liable to any Tanzanian income tax. As at 31 December 2004, un-recovered costs on the PSA had accumulated to US$6.6 million. At December 31, 2004, there are no material temporary differences between the carrying value of the assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. 6 O p e n i n g B a l a n c e S h e e t As at 31 August 2004, PanOcean spun out its interests in Tanzania to its shareholders on completion of a Scheme of Arrangement. Accordingly, certain assets and liabilities of PanOcean relating to the Tanzanian business segment were transferred to the Company. The following table analyses the net assets distributed and the opening balance sheet for the Company as at 31 August 2004. Cash and cash equivalents Trade and other receivables Natural gas properties and other equipment Trade and other payables Total net assets 7 C a s h a n d C a s h E q u i v a l e n t s Cash and short term deposits 31 August 2004 1,997 2,403 9,411 (1,949) 11,862 31 December 2004 2,040 Included in the cash and cash equivalent are: .. US$251,000 advanced from Songas under the terms of the Operatorship Agreement to pay for the costs of 4 7 operating the wells and gas processing plant. .. US$100,000 advanced from Tanzania-China Friendship Textile Co. Ltd as a deposit for their pipeline connection. This will be repaid once they have consumed in excess of US$200,000 of gas. 8 Tr a d e a n d O t h e r R e c e i v a b l e s d u e i n l e s s t h a n o n e y e a r Trade receivables Prepayments Other receivables 9 N a t u r a l G a s P r o p e r t i e s Costs As at 31 August 2004 Additions As at 31 December 2004 Depletion As at 31 August 2004 Charge for the period As at 31 December 2004 Net Book Value As at 31 December 2004 As at 31 August 2004 31 December 2004 174 84 183 441 31 December 2004 9,411 924 10,335 – 35 35 10,300 9,411 The majority of the Company’s costs were capitalised until commercial sale of the Additional Gas commenced on 18 September 2004. Included in Natural Gas Properties at 31 December 2004 are US$6.3 million of capitalised costs that are recoverable out of 75% of the proceeds of the sale of Additional Gas net of transportation tariffs. The recovery of these costs is dependent on the future sales of commercial gas. The costs are included in Revenue in the period of recovery as set out in note 1 (m) and depleted in accordance with accounting policy 1 (f). The Company does not have any unproven property costs that are being excluded from the depletion calculation. 10 Tr a d e a n d O t h e r P a y a b l e s Trade payables Other payables 31 December 2004 308 957 1,265 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | N OT E S TO T H E CO N S O L I DAT E D F I N A N C I A L S TAT E M E N T S 4 8 11 F i n a n c i a l I n s t r u m e n t s | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. The Company monitors these risks. The Company may enter into financial instruments to manage its exposure to these risks. Credit risk Substantially all the accounts receivable are due from two customers and Songas. Since the commencement of sale, the Company has not experienced any problem in collecting amounts due from customers. The level of receivables will be closely monitored to minimize any potential default by any of the Company’s customers. Foreign currency risk The Company’s exposure to foreign currency risk is limited to exchange rate fluctuations on foreign currency cash balances and the expenditure in currencies other than the US dollar. Commodity prices The Company did not enter into any financial contracts during the period as there was limited exposure to commodity prices. Fair values Financial instruments of the Company carried on the balance sheet consist mainly of current assets and current liabilities. Except as noted, there were no significant differences between the carrying value of these financial instru- ments and their estimated fair value due to their short term to maturity. 12 C a p i t a l S t o c k Authorised 50,000,000 Class A Common Shares 50,000,000 Class B Subordinate Voting Shares No par value No par value The Class A and Class B shares rank pari passu in respect of dividends and repayment of capital in the event of winding-up. Class A shares carry twenty votes per share and Class B shares carry one vote per share. The Class A shares are convertible at the option of the holder at any time into Class B shares on a one-for-one basis. The Class B shares are convertible into Class A shares on a one-for-one basis in the event that a take over bid is made to purchase Class A shares which must, by reason of a stock exchange or legal requirements, be made to all or substantially all of the holders of Class A shares and which is not concurrently made to holders of Class B shares. Number of shares (thousands) Authorised Issued Valuation at par value Class A As at 31 August and 31 December 50,000 1,751 983 Class B As at 31 August and 31 December Total as at 31 December 50,000 100,000 19,386 21,137 10,879 11,862 All of the issued capital stock was considered fully paid at the time of spin off from PanOcean. Stock-based Compensation Plan On 1 September, 2,000,000 options (‘Options’) were issued to certain Directors, Officers and Consultants. These Options have a term of 10 years and vest as to a third on 1 September 2004 and a third on each of the anniversaries in the following two years. At 31 December 2004, 666,666 options were exercisable. The exercise price for the Options is Cdn$1 representing the closing price of the Class B subordinated Voting Shares on 31 August 2004. 4 9 The Company has elected to adopt the fair method value of option valuation IFRS 2. The fair value of each option was estimated as at the date of the grant using the Black-Scholes option pricing model with the following assumptions: risk-free interest rate of 2.6%, dividend yield of 0%, expected life of 10 years and volatility of 60%. On this basis, the fair value of the Options is US$0.9 million, with a compensation expense of US$381,000 for the period ended 31 December 2004 and a corresponding amount booked to a capital reserve. No Options were exercised during the period ended 31 December 2004. 13 L o s s P e r S h a r e The calculation of basic loss per share is based on the net loss attributable to ordinary shareholders of US$727,000 and a weighted average number of ordinary shares outstanding during the period of 21,137,439. In computing the diluted earnings per share, 2,000,000 shares were added to the weighted average number of commons shares outstanding during the period ended 31 December, 2004 for the dilutive effect of employee stock options. No adjustments were required to reported earnings from operations in computing diluted per share amounts. 14 R e c o n c i l i a t i o n o f I F R S t o A c c o u n t i n g P r i n c i p l e s G e n e r a l l y A c c e p t e d i n C a n a d a The Consolidated Financial Statements have been prepared in accordance with the IFRS basis of accounting, which differ in some respects from those in Canada. In Canada, the carrying value of natural gas properties is compared annually to the sum of the undiscounted cash flows expected to result from the company’s proved reserves. Should the ceiling test result in an excess of carrying value, the company would then measure the amount of impairment by comparing the carrying amounts of natural gas properties to an amount equal to the estimated net present value of future cash flows from proved plus probable reserves and the lower of cost and market of unproved properties. The Company’s risk-free interest rate is used to arrive at the net present value of the future cash flows. To date, application of the Canadian prescribed ceiling test has not resulted in a write-down of capitalized costs. There were no material differences in accounting principles as they pertain to the accompanying Consolidated Financial Statements. 15 O p e r a t i n g L e a s e s Non-cancellable operating lease rentals are payable as follows: Less than one year Between one and five years 31 December 2004 92 199 291 The Company has rented office property under the five year operating lease expiring 30 November 2007. 16 P o s t B a l a n c e S h e e t E v e n t s On 19 January the Board of EastCoast approved the construction of a pipeline to sell gas to Karibu Textile Mills Ltd. The pipeline is to be constructed by Terasen International at a cost of US$1.1 million. | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | 5 0 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | N OT E S TO T H E CO N S O L I DAT E D F I N A N C I A L S TAT E M E N T S On 4 March 2005, the Company successfully completed the Rights Issue through the issue of 2,113,744 Class B shares at a price of Cdn$ 2.60 per share. This raised Cdn$ 5.5 million for the Company (Cdn$5.4 million after expenses). 17 C o m m i t m e n t s a n d C o n t i n g e n c i e s There are no undisclosed commitments as at 31 December 2004. Under the terms of the PSA, in the event that there is a shortfall in Protected Gas as a consequence of the sale of Additional Gas, then the Company is liable to pay the difference between the price of Protected Gas (US$0.55 per mmbtu) and the price of an alternative feedstock multiplied by the volumes of Protected Gas up to a maximum of the volume of Additional Gas sold. Songas has the right to request reasonable security on all Additional Gas sales. No security has been requested for the initial industrial gas sales, but Songas still retains this right and may require security for larger volumes. 18 D i r e c t o r s a n d O f f i c e r s E m o l u m e n t s US’000 except no. of share options Base Salary Bonus Other compensation Total Share options Directors W. David Lyons (i) Chairman Peter R. Clutterbuck (i) Chief Executive Officer Nigel A. Friend (i) Vice President and CFO John Patterson (i) Non Executive Director Robert Spence (i) Non Executive Director Officers Pierre Raillard (ii) 4 89 80 7 6 – – – – – Vice President Operations 29 13 – – – – – 6 4 1,000,000 89 400,000 80 200,000 7 50,000 10 50,000 48 200,000 (i) The ‘Base Salary’ for W.D. Lyons, P.R. Clutterbuck, N. Friend, J. Patterson and R. Spence are in respect of consultancy fees. (ii) During the period, 50% of the costs of P. Raillard were recharged to Songas for the work undertaken on operat- ing the gas processing plant and maintaining the wells. Accordingly, the emoluments outlined above represent the costs paid directly by the Company. (iii) 100,000 Options were awarded to a consultant, R Wynne, Chief Financial Officer for PanOcean, for corporate advice. 19 R e l a t e d p a r t y t r a n s a c t i o n s The Company was spun off from PanOcean through a Scheme of Arrangement on 31 August 2004. W. David Lyons is the Chairman and controlling shareholder of both PanOcean and EastCoast. The Company has entered into an arms length agreement with PanOcean for the use of certain administrative and technical support services provided by PanOcean staff for the transitional period after the spin off. These services were not utilised in the period to 31 December 2004. There have been no other transactions undertaken with related parties during the period ended 31 December 2004. Nigel A. Friend Chief Financial Officer London United Kingdom CO R P O R AT E I N F O R M AT I O N B OA R D O F D I R E C TO R S W. David Lyons Non-Executive Chairman St. Helier Jersey John Patterson Non Executive Director Nanoose Bay Canada O F F I C E R S Pierre Raillard Vice President Operations Peter R. Clutterbuck President & Chief Executive Officer Haslemere United Kingdom Robert K. Spence Non-Executive Director Dar es Salaam Tanzania David W. Ross Company Secretary O P E R AT I N G O F F I C E R E G I S T E R E D O F F I C E EastCoast Energy Corporation Barclays House, 5th Floor Ohio Street, P.O. Box 80139 Dar es Salaam Tanzania Tel: + 255 22 2138737 Fax: + 255 22 2138938 I N T E R N AT I O N A L S U B S I D I A R I E S PanAfrican Energy Tanzania Limited Barclays House, 5th Floor Ohio Street, P.O. Box 80139 Dar es Salaam Tanzania Tel: + 255 22 2138737 Fax: + 255 22 2138938 EastCoast Energy Corporation P.O. Box 3152, Road Town Tortola British Virgin Islands PAE PanAfrican Energy Corporation 1st Floor Cnr St George/Chazal Streets Port Louis Mauritius Tel: + 230 207 8888 Fax: + 230 207 8833 E N G I N E E R I N G CO N S U LTA N T S AU D I TO R S L AW Y E R S McDaniel & Associates Consultants Ltd Calgary Canada KPMG LLP Calgary Canada Burnet, Duckworth & Palmer LLP Calgary Canada T R A N S F E R AG E N T I N V E S TO R R E L AT I O N S W E B S I T E CIBC Mellon Trust Company Toronto, Montreal and Calgary, Canada Nigel A. Friend Chief Financial Officer Tel: + 255 22 2138737 nfriend@eastcoast-energy.com www.eastcoast-energy.com 5 1 | E A S T C O A S T E N E R G Y C O R P O R A T I O N 2 0 0 4 A N N U A L R E P O R T | reverse only

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