unlocking value Orca Exploration Group Inc. A n n uAl R e p oR t 2 0 0 7 Orca ExplOratiOn GrOup inc. is a well-financed, international public company engaged in hydrocarbon exploration, development and marketing. the company’s 0perations are directed from offices in Dar es Salaam, tanzania. Orca’s immediate focus is on the exploration, production, development and marketing of tanzanian natural gas. Orca is also committed to growth in assets and value through the acquisition of oil interests with significant exploration potential. Orca Exploration trades on the tSxV under the trading symbols Orc.B and Orc.a. highlights pResident & Ceo’s letteR to shAR eholdeRs opeRAtions Review md&A mAnA gement’s RepoRt to shAReholdeRs AuditoRs’ RepoRt finAnC iAl stAtements notes to the ConsolidAted finAnC iAl stAtements contents 1 2 6 22 46 47 48 52 This annual report contains certain forward-looking statements based on current expectations, but which involve risks and uncertainties. Actual results may differ materially. All financial information is reported in U.S. dollars (US$), unless otherwise noted. YeARs ended 31 deC embeR 2007 2006 ChAnge financial and operating highlights Financial (US$’000 except where otherwise stated) Revenue Profit before taxation Operating netback (US$/mcf) Cash and cash equivalents Working capital Shareholders’ equity Profit per share - basic (US$) Profit per share - diluted (US$) Funds from operations before working capital changes Funds per share from operations before working capital changes - basic (US$) Funds per share from operations before working capital changes - diluted (US$) Outstanding Shares (‘000) Class A shares Class B shares Options Operating Additional Gas sold - industrial (Mmscf) Additional Gas sold - power (Mmscf) Average price per mcf - industrial (US$) Average price per mcf - power (US$) Gross Recoverable Reserves to end of licence (Bcf) Proved Probable Proved plus probable Present Value, discounted at 10% (US$ million) Proved Proved plus probable 18,777 13,828 3,775 2.31 16,515 7,299 71,544 0.06 0.06 8,696 0.31 0.29 1,751 27,863 2,847 1,504 6,227 9.31 2.19 309 165 474 183 255 4,261 2.45 20,678 20,430 37,889 0.11 0.10 5,969 0.26 0.24 1,751 25,023 2,022 1,466 3,371 8.22 1.90 266 149 415 109 159 36% (11%) (6%) (20%) (64%) 89% (45%) (40%) 46% 19% 21% 0% 11% 41% 3% 85% 13% 15% 16% 11% 14% 68% 60% glossary mCf .................................................................................................................... Thousands of standard cubic feet mmsC f ................................................................................................................... Millions of standard cubic feet bCf .......................................................................................................................... Billions of standard cubic feet tCf ......................................................................................................................... Trillions of standard cubic feet mmsC f/d ................................................................................................... Millions of standard cubic feet per day mmbtu ................................................................................................................ Millions of British thermal units hhv ............................................................................................................................................... High heat value 1p ................................................................................................................................................... Proven reserves 2p ..............................................................................................................................Proven and probable reserves 3p ............................................................................................................... Proven, probable and possible reserves giip ........................................................................................................................................ Gas initially in place Kwh .................................................................................................................................................. Kilowatt hour mw ......................................................................................................................................................... Megawatt us$ ......................................................................................................................................................... US dollars Cdn$ ........................................................................................................................................... Canadian dollars tvdss ......................................................................................................................... Total vertical depth sub sea tvd .......................................................................................................................................... Total vertical depth md ................................................................................................................................................ Measured depth president & ceo’s letter to shareholders Orca ExplOratiOn continues to add to its natural gas reserves and increase cash flow from the Company’s operations in Tanzania. Since the Company’s incorporation in 2004 independent evaluation of the Songo Songo field’s Additional Gas reserve has increased proven and probable (“2P”) reserves 86% from 255 Bcf to 474 Bcf. The rapidly expanding Tanzanian markets for natural gas has driven the increase in cash flow seen from the sale of Additional Gas. In 2007 Orca generated cash flows before working capital changes of US$8.7 million an increase of 46% over 2006. In the past 18 months, 310 MWs of new gas-fired generation has been installed in the Dar es Salaam area, operating on Additional gas supplied by Orca. During Q4 2007, 23.4 Mmscf/d was sold to these units and the Company anticipates that 38 to 45 Mmscf/d will be sold to the power sector under long-term contracts once infrastructure capacity has been increased. It is forecast that Tanzania’s electricity demand will increase by approximately 50 MWs per annum for the foreseeable future absorbing all recoverable gas production from the Songo Songo development licence that is not sold to the higher margin industrial markets. The Company remains committed to exploration for new oil and gas reserves. Orca is excited by its Songo Songo West exploration prospect that could add approximately 350 Bcf of reserves if gas is discovered. The Company intends to drill a vertical well on this prospect once a suitable jack-up rig can be contracted. RESERVE IncREaSES At year end 2007, Orca’s independent reserve evaluator, McDaniel & Associates Consultants Ltd., increased its 2P estimate of Songo Songo recoverable reserves on a life of licence basis from 415 Bcf at year end 2006 to 474 Bcf. In addition McDaniel included a proven, probable and possible (“3P”) category on a life of licence basis of 783 Bcf of recoverable Additional Gas reserves. Provided the Songo Songo field pressure declines remain consistent with historical trends, and there is a successful drilling of an appraisal well at Songo Songo North, Orca anticipates that the 2P reserve estimates will increase to the level of the 3P number over time. Confirmation of Songo Songo’s increased reserves has been achieved through diligent monitoring of the sub surface. The drilling of SS-10 has provided extensive data has on the field for the first time in 25 years as well as adding 80 Mmscf/d of deliverability when combined with the remedial work undertaken on SS-9. The well also contributed the major portion of the increase in reserves in 2007. GaS MaRkEt addItIOnS The Tanzanian market for natural gas has expanded rapidly. Orca now supplies Additional Gas to 310 MWs of generation. During 2007, detailed discussions have taken place with the electricity utility, TANESCO, the owners of the Ubungo power plant, Songas Limited and the Ministry of Energy and Minerals (“MEM”) to secure two long term contracts for this expanded generation capacity. The first contract covers the supply of gas to the sixth turbine at the Ubungo power plant and has a maximum daily quantity of approx 9.2 Mmscf/d and is expected to be run at a utilisation rate of approximately 85% until July 2024. A further contract covers the sales to the remaining plants and has a maximum daily quantity of approximately 36 Mmscf/d and a take or pay quantity of 32 Mmscf/d until July 2023. Actual utilisation depends on the availability of the 561 MWs of Tanzania’s hydro generation and infrastructure capacity. It is expected that hydro utilisation will be high in Q2 2008 dropping thereafter, consistent with seasonal trends in Tanzania. The contract price is expected to be the same for both contracts at an estimated US$2.32/mcf based on the existing tariff rates. These prices are forecast to increase 2% per annum until July 2012 at which point there will be a step change to US$3.43/mcf based on existing tariff rates. These prices will then increase at 2% per annum. Right And opposite pAge The new SS-10 well was drilled adjacent to the Songo Songo gas processing plant. left Orca continues to add to its low pressure gas distribution network at Dar es Salaam. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O 3 president & ceo’s letter to shareholders The demand for electricity is currently increasing at 8% per annum and is forecast to increase at 12% over the course of the next two years. This will lead to additional gas fired plants being brought into the country. To meet the growing industrial demand for access to natural gas the Company has constructed 35 kilometers of low pressure pipeline since 2004 in and around Dar es Salaam. Current industrial Additional Gas sales of approximately 5 Mmscf/d are forecast to double by the end of 2009. A large part of that increase is expected to come from the cement industry whose installed production capacity in Dar es Salaam will increase significantly during the second half of 2009. During 2008 Orca expects to begin the sale of compressed natural gas (‘CNG’). The introduction of CNG will create ‘virtual pipelines’ and open the prospect of selling Additional Gas to industrials in Morogoro and Tanga, and to hotels and vehicles in Dar es Salaam and Zanzibar. A CNG market development team is in place. A compressor and CNG dispensing system are scheduled to be operational in Q4 2008. With equipment additions, Orca could serve a 4 to 8 Mmscf/d CNG market by the end of 2009. Around the clock transportation would be able to move CNG to markets up to 200 kilometers from Dar es Salaam. With further drilling success, additional new markets could be developed including the export of electricity to Uganda and Kenya where average generation costs are significantly higher than in Tanzania. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O InFRaStRuctuRE During Q4 2007, current infrastructure capacity limited sales of Additional Gas on a few occasions. The current gas processing plant configuration on Songo Songo Island limits the supply of gas to Dar es Salaam to 70 Mmscf/d. The two trains on Songo Songo Island are currently being upgraded and two new Joule-Thomson valves will be installed at the end of May. The insurers are working alongside the team to assess the allowable operating throughput volume for these units. It is expected that this would add 20 Mmscf/d to capacity, raising it to 90 Mmscf/d. During Q3 2007, Orca submitted a proposal to Songas (the owners of the infrastructure) to enable the Songo Songo Island gas processing capacity to be increased by a further 15 Mmscf/d by utilising a bypass system. It is planned that this work be completed in the second half of 2008 so that infrastructure doesn’t continue to be a limiting factor. Both the electricity utility TANESCO and Songas are seeking confirmation from the turbine manufacturers that their units can consume gas that commingles 15 Mmscf/d of non-processed gas with processed gas as a precursor for the installation of the by pass system. To address long-term growth Songas has submitted a second application to the Tanzanian regulatory authority, EWUrA, for the installation of two new gas processing trains to increase throughput capacity to more than 140 Mmscf/d. The tenders for the engineering, procurement and construction contract were received in Q3 2007 and all parties are working on the project agreements to enable Songas to give the ‘notice to proceed’. It is expected that construction will take 15 months from the time of awarding the tender until the new trains are operational. It is expected that the facility upgrades will allow full supply to projected gas markets during the period that the installation of the new trains is in process. left The new SS-10 well completed in 2007 is expected to produce up to 55 Mmscf/d when on production. Right Orca assists the Songo Songo Island school with funds for educational supplies and equipment. Additional studies are currently being undertaken to determine the best means of increasing the capacity of the pipeline infrastructure from its current estimated capacity of 105 Mmscf/d to the full capacity of the gas processing trains (once the third and fourth train are operational). This should be possible in the short term with some compression. addInG nEw IntEREStS The Company’s strategy to acquire two new oil interests in Africa was initiated in 2007 with the negotiation of an option to enter a high potential oil play in the Albertine Graben sedimentary basin in Uganda. 300 kilometers of seismic was acquired in the Uganda rhino Camp basin area of Exploration Area 5 (“EA 5”) during Q4 2007 and Q1 2008. Some modest delays were experienced during the campaign caused principally by the prolonged and unseasonable wet-season that affected the whole of the central African belt. Processing of this seismic data has now commenced, and is due to be completed in the coming weeks. The initial evaluation of the data has indicated that a number of potential structures exist. Technical analysis is still on going with particular attention being paid to the relationship of these structures and any potential hydrocarbon maturation that could have occurred within the basin. As yet it is too early to indicate the level of prospectivity. However initial analysis indicates that the block is more risky than initially thought. As the processing of the seismic data continues, the details of the prospectivity will become clearer. The Company has until June 2008 to determine whether to commit to drill two exploration wells to secure a 50% interest in EA 5. The Company’s exploration and acquisitions team is working to identify a suitable prospect in Africa that can be developed within a two year time period. The main area of focus is West Africa. FInancIal RESultS Orca’s revenues increased 36% to US$18.8 million during the year. Profit before taxation decreased by 11% to US$3.8 million primarily as a result of the additional costs of strengthening and expanding the Company’s business development team and the costs of negotiating the long term power contracts. left Over 2007 Orca increased the capacity of its low-pressure gas distribution system by adding a second pressure reduction station. In 2007 Orca’s operations generated cash flows before working capital changes of US$8.7 million, an increase of 46% on 2006. This is forecast to grow in 2008 as gas sales increase and marketing costs decrease. During the year Orca raised net proceeds of Cdn$30.5 million through a private placement of 2.5 million Class B shares. At year end, the Company had cash of approximately US$16.5 million on hand after financing the Uganda seismic programme in Q4 2007. It is anticipated that a further US$1.5 million will be required to complete the seismic programme in 2008. OutlOOk Orca’s increasingly valuable Tanzanian asset base continues to offer excellent growth opportunities that will generate strong cash flows through to 2026. Once long-term contracts are signed for the supply of gas to the power sector, the Company plans to seek a term loan facility to continue to grow its Tanzanian asset base and to pursue additional opportunities in Africa. The increase in the Songo Songo reserves is extremely encouraging and demonstrates the long-term value that your Company has already unlocked in East Africa. There is increasing confidence that Songo Songo will ultimately be able to produce at a level that equates to the 3P reserves. This would generate excellent cash flows. This is absolutely the right time to be developing oil and gas resources in Africa. There are many excellent opportunities for smaller companies like Orca. Management continues to evaluate opportunities to acquire an interest in oil properties that fit our financial and human resources capabilities. Management is mindful that our Company’s continued growth and vitality are always dependent on an exceptional team of skilled employees and our loyal shareholders. We thank both for their support. The future glows even more brightly as Orca’s reserves increase and markets continue to grow. Peter r.Clutterbuck President and CEO April 28, 2008 5 (cid:70) (cid:67) (cid:66) (cid:24) (cid:17)(cid:22) (cid:17)(cid:20) (cid:17)(cid:18) (cid:17)(cid:16) (cid:22) (cid:20) (cid:18) (cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:23)(cid:12)(cid:16)(cid:16)(cid:16) (cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:21)(cid:12)(cid:16)(cid:16)(cid:16) (cid:19)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:12)(cid:16)(cid:16)(cid:16) (cid:16) (cid:35)(cid:85)(cid:77)(cid:85)(cid:76)(cid:65)(cid:84)(cid:73)(cid:86)(cid:69)(cid:0)(cid:80)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0) (cid:70)(cid:82)(cid:79)(cid:77)(cid:0)(cid:69)(cid:65)(cid:67)(cid:72)(cid:0)(cid:87)(cid:69)(cid:76)(cid:76) (cid:48)(cid:82)(cid:79)(cid:84)(cid:69)(cid:67)(cid:84)(cid:69)(cid:68)(cid:0)(cid:39)(cid:65)(cid:83)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83)(cid:0)(cid:66)(cid:89)(cid:0)(cid:89)(cid:69)(cid:65)(cid:82) (cid:48)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83) (cid:17)(cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) operations review production (cid:51)(cid:51)(cid:13)(cid:19) (cid:51)(cid:51)(cid:13)(cid:20) (cid:51)(cid:51)(cid:13)(cid:21) (cid:51)(cid:51)(cid:13)(cid:23) (cid:51)(cid:51)(cid:13)(cid:25) (cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:53)(cid:66)(cid:85)(cid:78)(cid:71)(cid:79)(cid:0)(cid:48)(cid:79)(cid:87)(cid:69)(cid:82)(cid:0)(cid:48)(cid:76)(cid:65)(cid:78)(cid:84) (cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:23) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) During 2007, 19.7 Bcf (2006: 18.0 Bcf) of gas was produced from the Songo Songo field offshore (cid:18)(cid:16)(cid:16)(cid:21) Tanzania or an average of 54.0 Mmscf/d (2006: (cid:33)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0) 49.3 Mmscf/d). This brings total production since (cid:39)(cid:65)(cid:83) commercial operations commenced on 20 July 2004 to 57.0 Bcf. Production peaked at 70 Mmscf/d (the capacity of the gas processing plant) on a few occasions in the last quarter of 2007. (cid:48)(cid:82)(cid:79)(cid:84)(cid:69)(cid:67)(cid:84)(cid:69)(cid:68)(cid:0) (cid:39)(cid:65)(cid:83) (cid:55)(cid:65)(cid:90)(cid:79)(cid:0)(cid:40)(cid:73)(cid:76)(cid:76) (cid:18)(cid:16)(cid:16)(cid:22) (cid:33)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0)(cid:39)(cid:65)(cid:83)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83) (cid:33)(cid:86)(cid:69)(cid:82)(cid:65)(cid:71)(cid:69)(cid:0)(cid:68)(cid:65)(cid:73)(cid:76)(cid:89)(cid:0)(cid:80)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:80)(cid:69)(cid:82)(cid:0)(cid:77)(cid:79)(cid:78)(cid:84)(cid:72) SOnGO SOnGO PROductIOn The production from the five Songo Songo wells was as follows: (cid:18)(cid:16)(cid:16)(cid:23) well (cid:38)(cid:76)(cid:65)(cid:82)(cid:69) SS-3 SS-4 SS-5 SS-7 SS-9 total 2004 2005 2006 2007 totAl Bcf 1.3 Bcf 1.5 Bcf 1.9 1.9 1.9 1.1 (cid:35)(cid:79)(cid:77)(cid:80)(cid:65)(cid:78)(cid:89)(cid:0)(cid:71)(cid:82)(cid:79)(cid:83)(cid:83)(cid:0)(cid:82)(cid:69)(cid:67)(cid:79)(cid:86)(cid:69)(cid:82)(cid:65)(cid:66)(cid:76)(cid:69)(cid:0) (cid:65)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0)(cid:71)(cid:65)(cid:83)(cid:0)(cid:82)(cid:69)(cid:83)(cid:69)(cid:82)(cid:86)(cid:69)(cid:83)(cid:0) (cid:79)(cid:78)(cid:0)(cid:65)(cid:0)(cid:76)(cid:73)(cid:70)(cid:69)(cid:0)(cid:79)(cid:70)(cid:0)(cid:76)(cid:73)(cid:67)(cid:69)(cid:78)(cid:67)(cid:69)(cid:0)(cid:66)(cid:65)(cid:83)(cid:73)(cid:83) 8.5 8.9 3.9 3.8 3.8 14.7 3.2 2.5 3.4 4.8 18.0 19.7 Bcf 5.5 5.5 23.0 11.9 11.1 57.0 Bcf 0.8 0.6 1.7 1.5 (cid:21)(cid:16)(cid:16) – 4.6 (cid:20)(cid:16)(cid:16) (cid:89) (cid:65) (cid:68) (cid:0)(cid:15)(cid:0) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:24)(cid:16) (cid:23)(cid:16) (cid:22)(cid:16) (cid:21)(cid:16) (cid:20)(cid:16) (cid:19)(cid:16) (cid:18)(cid:16) The total gas production from the Songo Songo field was allocated as follows: AlloCAtions (cid:19)(cid:16)(cid:16) (cid:70) (cid:67) (cid:34) Protected Gas sales (cid:18)(cid:16)(cid:16) Additional Gas sales Flare, generator at the processing plant (cid:17)(cid:16)(cid:16) and line pack total 2004 2005 2006 2007 totAl Bcf 4.1 0.1 0.4 4.6 Bcf Bcf Bcf 11.9 13.0 11.5 2.5 4.8 7.7 Bcf 40.5 15.1 0.3 0.2 0.5 1.4 14.7 18.0 19.7 57.0 (cid:42)(cid:65)(cid:78) (cid:38)(cid:69)(cid:66) (cid:45)(cid:65)(cid:82)(cid:67)(cid:72) (cid:33)(cid:80)(cid:82)(cid:73)(cid:76) (cid:45)(cid:65)(cid:89) (cid:42)(cid:85)(cid:78)(cid:69) (cid:42)(cid:85)(cid:76)(cid:89) (cid:33)(cid:85)(cid:71) (cid:51)(cid:69)(cid:80) (cid:47)(cid:67)(cid:84) (cid:46)(cid:79)(cid:86) (cid:36)(cid:69)(cid:67) (cid:17)(cid:20) (cid:17)(cid:22) (cid:17)(cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:35)(cid:85)(cid:77)(cid:85)(cid:76)(cid:65)(cid:84)(cid:73)(cid:86)(cid:69)(cid:0)(cid:80)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0) (cid:70)(cid:82)(cid:79)(cid:77)(cid:0)(cid:69)(cid:65)(cid:67)(cid:72)(cid:0)(cid:87)(cid:69)(cid:76)(cid:76) OPERatORShIP Orca Exploration is the operator of the reservoir, wells and gas processing plant on Songo Songo Island on behalf of the stakeholders, including Songas Limited (“Songas”). Operatorship is on a ‘no gain/ no loss’ basis. Two internationally experienced staff manage the site operations on a rotational basis with 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. Since commencement of commercial operations, there has been 100% uptime in relation to the supply of gas to major customers. (cid:17)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:77) (cid:45) (cid:70) (cid:67) (cid:66) (cid:70) (cid:67) (cid:83) (cid:17)(cid:16) (cid:17)(cid:18) (cid:24) (cid:22) (cid:16) (cid:18)(cid:16)(cid:16)(cid:23) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:48)(cid:82)(cid:79)(cid:86)(cid:69)(cid:68) (cid:48)(cid:82)(cid:79)(cid:66)(cid:65)(cid:66)(cid:76)(cid:69) (cid:48)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83) PROtEctEd GaS PROductIOn Under the terms of a Gas Agreement signed in 2001, the Protected Gas from Songo Songo is 100% owned by the Tanzanian Petroleum Development Corporation (cid:48)(cid:82)(cid:79)(cid:84)(cid:69)(cid:67)(cid:84)(cid:69)(cid:68)(cid:0)(cid:39)(cid:65)(cid:83)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83)(cid:0)(cid:66)(cid:89)(cid:0)(cid:89)(cid:69)(cid:65)(cid:82) (“TPDC”) and is sold to Songas under a 20-year Gas Agreement for the operation of five turbines at the Ubungo power plant or for onward sale to the Wazo Hill cement plant or village electrification. (cid:17)(cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:77) (cid:45) (cid:70) (cid:67) (cid:83) Over the year ended 31 December 2007, the Protected Gas utilisation rate was 70% (2006: 80%). (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:55)(cid:65)(cid:90)(cid:79)(cid:0)(cid:40)(cid:73)(cid:76)(cid:76) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:48)(cid:82)(cid:79)(cid:84)(cid:69)(cid:67)(cid:84)(cid:69)(cid:68)(cid:0) (cid:39)(cid:65)(cid:83) (cid:33)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0) (cid:39)(cid:65)(cid:83) (cid:38)(cid:76)(cid:65)(cid:82)(cid:69) (cid:53)(cid:66)(cid:85)(cid:78)(cid:71)(cid:79)(cid:0)(cid:48)(cid:79)(cid:87)(cid:69)(cid:82)(cid:0)(cid:48)(cid:76)(cid:65)(cid:78)(cid:84) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:51)(cid:51)(cid:13)(cid:19) (cid:51)(cid:51)(cid:13)(cid:20) (cid:51)(cid:51)(cid:13)(cid:21) (cid:51)(cid:51)(cid:13)(cid:23) (cid:51)(cid:51)(cid:13)(cid:25) (cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:41)(cid:78)(cid:68)(cid:85)(cid:83)(cid:84)(cid:82)(cid:73)(cid:65)(cid:76)(cid:0)(cid:51)(cid:65)(cid:76)(cid:69)(cid:83) (cid:48)(cid:79)(cid:87)(cid:69)(cid:82)(cid:0)(cid:51)(cid:65)(cid:76)(cid:69)(cid:83) t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O (cid:20) (cid:18) (cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:23)(cid:12)(cid:16)(cid:16)(cid:16) (cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:21)(cid:12)(cid:16)(cid:16)(cid:16) (cid:19)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:12)(cid:16)(cid:16)(cid:16) (cid:16) (cid:33)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0)(cid:39)(cid:65)(cid:83)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83) (cid:33)(cid:86)(cid:69)(cid:82)(cid:65)(cid:71)(cid:69)(cid:0)(cid:68)(cid:65)(cid:73)(cid:76)(cid:89)(cid:0)(cid:80)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:80)(cid:69)(cid:82)(cid:0)(cid:77)(cid:79)(cid:78)(cid:84)(cid:72) (cid:35)(cid:79)(cid:77)(cid:80)(cid:65)(cid:78)(cid:89)(cid:0)(cid:71)(cid:82)(cid:79)(cid:83)(cid:83)(cid:0)(cid:82)(cid:69)(cid:67)(cid:79)(cid:86)(cid:69)(cid:82)(cid:65)(cid:66)(cid:76)(cid:69)(cid:0) (cid:65)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0)(cid:71)(cid:65)(cid:83)(cid:0)(cid:82)(cid:69)(cid:83)(cid:69)(cid:82)(cid:86)(cid:69)(cid:83)(cid:0) (cid:79)(cid:78)(cid:0)(cid:65)(cid:0)(cid:76)(cid:73)(cid:70)(cid:69)(cid:0)(cid:79)(cid:70)(cid:0)(cid:76)(cid:73)(cid:67)(cid:69)(cid:78)(cid:67)(cid:69)(cid:0)(cid:66)(cid:65)(cid:83)(cid:73)(cid:83) (cid:89) (cid:65) (cid:68) (cid:0)(cid:15)(cid:0) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:24)(cid:16) (cid:23)(cid:16) (cid:22)(cid:16) (cid:21)(cid:16) (cid:20)(cid:16) (cid:19)(cid:16) (cid:18)(cid:16) (cid:21)(cid:16)(cid:16) (cid:20)(cid:16)(cid:16) (cid:19)(cid:16)(cid:16) (cid:70) (cid:67) (cid:34) (cid:18)(cid:16)(cid:16) (cid:17)(cid:16)(cid:16) (cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:41)(cid:78)(cid:68)(cid:85)(cid:83)(cid:84)(cid:82)(cid:73)(cid:65)(cid:76)(cid:0)(cid:51)(cid:65)(cid:76)(cid:69)(cid:83) (cid:48)(cid:79)(cid:87)(cid:69)(cid:82)(cid:0)(cid:51)(cid:65)(cid:76)(cid:69)(cid:83) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:48)(cid:82)(cid:79)(cid:66)(cid:65)(cid:66)(cid:76)(cid:69) (cid:48)(cid:82)(cid:79)(cid:86)(cid:69)(cid:68) (cid:42)(cid:65)(cid:78) (cid:38)(cid:69)(cid:66) (cid:45)(cid:65)(cid:82)(cid:67)(cid:72) (cid:33)(cid:80)(cid:82)(cid:73)(cid:76) (cid:45)(cid:65)(cid:89) (cid:42)(cid:85)(cid:78)(cid:69) (cid:42)(cid:85)(cid:76)(cid:89) (cid:33)(cid:85)(cid:71) (cid:51)(cid:69)(cid:80) (cid:47)(cid:67)(cid:84) (cid:46)(cid:79)(cid:86) (cid:36)(cid:69)(cid:67) The Protected Gas was allocated as follows: pRoteCted gAs utilisAtion YeAR ended 31 deC embeR 2007 YeAR ended 31 deC embeR 2006 pRoteCted gAs useR Ubungo power plant Wazo Hill cement plant Village electrification programme total consumption pRoteCted gAs Consumed utilisAtion RAte pRoteCted gAs Consumed utilisAtion RAte Bcf 9.9 1.6 – 11.5 Mmscf/d 27.3 4.4 – 31.7 % 71 74 – 70 Bcf 11.4 1.6 – 13.0 Mmscf/d 31.3 4.3 – 35.6 % 81 73 – 73 Protected Gas utilisation in 2007 decreased at the Ubungo power plant primarily because there were significant rains in the first five months of 2007 that enabled TANESCO to increase utilisation of their hydro electricity generation capacity. (cid:17)(cid:22) (cid:17)(cid:20) (cid:35)(cid:85)(cid:77)(cid:85)(cid:76)(cid:65)(cid:84)(cid:73)(cid:86)(cid:69)(cid:0)(cid:80)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0) (cid:70)(cid:82)(cid:79)(cid:77)(cid:0)(cid:69)(cid:65)(cid:67)(cid:72)(cid:0)(cid:87)(cid:69)(cid:76)(cid:76) (cid:17)(cid:18) At the Wazo Hill cement plant, the monthly utilisation ranged from 53% to 84% over 2007 and averaged 74% (2006: 73%). This plant is expanding its capacity in 2009 with the introduction of a further kiln and this will lead to some Additional Gas sales. The Village electrification program was not functional in 2007 and is now due to commence in the second half of 2008. (cid:70) (cid:67) (cid:66) (cid:17)(cid:16) (cid:24) (cid:22) The maximum gas required for the Protected Gas users over the remaining 16 years and seven months of the Gas Agreement was 273 Bcf as at 31 December 2007. For the purposes of calculating the level of gas available as Additional Gas, assumptions have been made as to the expected utilisation of the Protected Gas over the remaining term of the Gas Agreement. These assumptions are reviewed on an annual basis (cid:51)(cid:51)(cid:13)(cid:25) based on historic and projected usage. (cid:51)(cid:51)(cid:13)(cid:20) (cid:51)(cid:51)(cid:13)(cid:21) (cid:51)(cid:51)(cid:13)(cid:19) (cid:51)(cid:51)(cid:13)(cid:23) (cid:16) (cid:20) (cid:18) The Protected Gas users and their forecast maximum and most likely demand are as follows: pRoteCted gAs demAnd (cid:33)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0)(cid:39)(cid:65)(cid:83)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) Six gas turbines at the Ubungo power plant Less gas supplied to the sixth turbine which is Additional Gas (cid:23)(cid:12)(cid:16)(cid:16)(cid:16) Total Protected Gas at Ubungo Wazo Hill cement plant Village electrification programme total daily Protected Gas demand (cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:21)(cid:12)(cid:16)(cid:16)(cid:16) Protected Gas reserves to end of the Songas power purchase agreement (Bcf) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) The forecast theoretical maximum of Protected Gas is estimated at 45.1 Mmscf/d based on technical tests of the Ubungo turbines and the Wazo Hill cement plant. The ‘most likely’ utilisation, including the village electrification programme, is forecast to be 80 - 85% over the remaining (cid:19)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:12)(cid:16)(cid:16)(cid:16) (cid:16) (cid:17)(cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:16) (cid:48)(cid:82)(cid:79)(cid:84)(cid:69)(cid:67)(cid:84)(cid:69)(cid:68)(cid:0)(cid:39)(cid:65)(cid:83)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83)(cid:0)(cid:66)(cid:89)(cid:0)(cid:89)(cid:69)(cid:65)(cid:82) (cid:48)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83) (cid:18)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:53)(cid:66)(cid:85)(cid:78)(cid:71)(cid:79)(cid:0)(cid:48)(cid:79)(cid:87)(cid:69)(cid:82)(cid:0)(cid:48)(cid:76)(cid:65)(cid:78)(cid:84) (cid:55)(cid:65)(cid:90)(cid:79)(cid:0)(cid:40)(cid:73)(cid:76)(cid:76) (cid:48)(cid:82)(cid:79)(cid:84)(cid:69)(cid:67)(cid:84)(cid:69)(cid:68)(cid:0) (cid:33)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0) (cid:38)(cid:76)(cid:65)(cid:82)(cid:69) (cid:39)(cid:65)(cid:83) (cid:39)(cid:65)(cid:83) theoRetiCAl mAximum 100% loAd fACtoR Mmscf/d most liKelY utilisAtions in 2007 (cid:33)(cid:86)(cid:69)(cid:82)(cid:65)(cid:71)(cid:69)(cid:0)(cid:68)(cid:65)(cid:73)(cid:76)(cid:89)(cid:0)(cid:80)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:80)(cid:69)(cid:82)(cid:0)(cid:77)(cid:79)(cid:78)(cid:84)(cid:72) Mmscf/d Mmscf/d (cid:35)(cid:79)(cid:77)(cid:80)(cid:65)(cid:78)(cid:89)(cid:0)(cid:71)(cid:82)(cid:79)(cid:83)(cid:83)(cid:0)(cid:82)(cid:69)(cid:67)(cid:79)(cid:86)(cid:69)(cid:82)(cid:65)(cid:66)(cid:76)(cid:69)(cid:0) (cid:65)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0)(cid:71)(cid:65)(cid:83)(cid:0)(cid:82)(cid:69)(cid:83)(cid:69)(cid:82)(cid:86)(cid:69)(cid:83)(cid:0) (cid:79)(cid:78)(cid:0)(cid:65)(cid:0)(cid:76)(cid:73)(cid:70)(cid:69)(cid:0)(cid:79)(cid:70)(cid:0)(cid:76)(cid:73)(cid:67)(cid:69)(cid:78)(cid:67)(cid:69)(cid:0)(cid:66)(cid:65)(cid:83)(cid:73)(cid:83) 47.4 (9.2) 38.2 5.9 1.0 45.1 273 (cid:89) (cid:65) (cid:68) (cid:0)(cid:15)(cid:0) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:24)(cid:16) (cid:23)(cid:16) (cid:22)(cid:16) (cid:21)(cid:16) (cid:20)(cid:16) (cid:19)(cid:16) (cid:18)(cid:16) 39.8 (7.8) 32.0 4.4 1.0 37.4 227 33.7 (6.4) 27.3 4.4 – 31.7 7 (cid:42)(cid:65)(cid:78) (cid:38)(cid:69)(cid:66) (cid:45)(cid:65)(cid:82)(cid:67)(cid:72) (cid:33)(cid:80)(cid:82)(cid:73)(cid:76) (cid:45)(cid:65)(cid:89) (cid:42)(cid:85)(cid:78)(cid:69) (cid:42)(cid:85)(cid:76)(cid:89) (cid:33)(cid:85)(cid:71) (cid:51)(cid:69)(cid:80) (cid:47)(cid:67)(cid:84) (cid:46)(cid:79)(cid:86) (cid:36)(cid:69)(cid:67) (cid:21)(cid:16)(cid:16) (cid:20)(cid:16)(cid:16) (cid:19)(cid:16)(cid:16) (cid:70) (cid:67) (cid:34) (cid:18)(cid:16)(cid:16) (cid:17)(cid:16)(cid:16) (cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:41)(cid:78)(cid:68)(cid:85)(cid:83)(cid:84)(cid:82)(cid:73)(cid:65)(cid:76)(cid:0)(cid:51)(cid:65)(cid:76)(cid:69)(cid:83) (cid:48)(cid:79)(cid:87)(cid:69)(cid:82)(cid:0)(cid:51)(cid:65)(cid:76)(cid:69)(cid:83) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:48)(cid:82)(cid:79)(cid:66)(cid:65)(cid:66)(cid:76)(cid:69) (cid:48)(cid:82)(cid:79)(cid:86)(cid:69)(cid:68) (cid:35)(cid:85)(cid:77)(cid:85)(cid:76)(cid:65)(cid:84)(cid:73)(cid:86)(cid:69)(cid:0)(cid:80)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0) (cid:70)(cid:82)(cid:79)(cid:77)(cid:0)(cid:69)(cid:65)(cid:67)(cid:72)(cid:0)(cid:87)(cid:69)(cid:76)(cid:76) (cid:48)(cid:82)(cid:79)(cid:84)(cid:69)(cid:67)(cid:84)(cid:69)(cid:68)(cid:0)(cid:39)(cid:65)(cid:83)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83)(cid:0)(cid:66)(cid:89)(cid:0)(cid:89)(cid:69)(cid:65)(cid:82) (cid:48)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83) (cid:70) (cid:67) (cid:66) (cid:24) (cid:17)(cid:22) (cid:17)(cid:20) (cid:17)(cid:18) (cid:17)(cid:16) (cid:22) (cid:20) (cid:18) (cid:16) (cid:51)(cid:51)(cid:13)(cid:19) (cid:51)(cid:51)(cid:13)(cid:20) operations review (cid:51)(cid:51)(cid:13)(cid:23) (cid:51)(cid:51)(cid:13)(cid:25) (cid:51)(cid:51)(cid:13)(cid:21) (cid:17)(cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:16) (cid:18)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:53)(cid:66)(cid:85)(cid:78)(cid:71)(cid:79)(cid:0)(cid:48)(cid:79)(cid:87)(cid:69)(cid:82)(cid:0)(cid:48)(cid:76)(cid:65)(cid:78)(cid:84) (cid:55)(cid:65)(cid:90)(cid:79)(cid:0)(cid:40)(cid:73)(cid:76)(cid:76) (cid:48)(cid:82)(cid:79)(cid:84)(cid:69)(cid:67)(cid:84)(cid:69)(cid:68)(cid:0) (cid:39)(cid:65)(cid:83) (cid:33)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0) (cid:39)(cid:65)(cid:83) (cid:38)(cid:76)(cid:65)(cid:82)(cid:69) (cid:35)(cid:79)(cid:77)(cid:80)(cid:65)(cid:78)(cid:89)(cid:0)(cid:71)(cid:82)(cid:79)(cid:83)(cid:83)(cid:0)(cid:82)(cid:69)(cid:67)(cid:79)(cid:86)(cid:69)(cid:82)(cid:65)(cid:66)(cid:76)(cid:69)(cid:0) (cid:65)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0)(cid:71)(cid:65)(cid:83)(cid:0)(cid:82)(cid:69)(cid:83)(cid:69)(cid:82)(cid:86)(cid:69)(cid:83)(cid:0) (cid:79)(cid:78)(cid:0)(cid:65)(cid:0)(cid:76)(cid:73)(cid:70)(cid:69)(cid:0)(cid:79)(cid:70)(cid:0)(cid:76)(cid:73)(cid:67)(cid:69)(cid:78)(cid:67)(cid:69)(cid:0)(cid:66)(cid:65)(cid:83)(cid:73)(cid:83) (cid:21)(cid:16)(cid:16) (cid:20)(cid:16)(cid:16) (cid:19)(cid:16)(cid:16) (cid:70) (cid:67) (cid:34) (cid:18)(cid:16)(cid:16) (cid:17)(cid:16)(cid:16) (cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:48)(cid:82)(cid:79)(cid:66)(cid:65)(cid:66)(cid:76)(cid:69) (cid:48)(cid:82)(cid:79)(cid:86)(cid:69)(cid:68) (cid:33)(cid:86)(cid:69)(cid:82)(cid:65)(cid:71)(cid:69)(cid:0)(cid:68)(cid:65)(cid:73)(cid:76)(cid:89)(cid:0)(cid:80)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:80)(cid:69)(cid:82)(cid:0)(cid:77)(cid:79)(cid:78)(cid:84)(cid:72) Songo Songo Field (cid:33)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0)(cid:39)(cid:65)(cid:83)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:41)(cid:78)(cid:68)(cid:85)(cid:83)(cid:84)(cid:82)(cid:73)(cid:65)(cid:76)(cid:0)(cid:51)(cid:65)(cid:76)(cid:69)(cid:83) (cid:48)(cid:79)(cid:87)(cid:69)(cid:82)(cid:0)(cid:51)(cid:65)(cid:76)(cid:69)(cid:83) (cid:24)(cid:16) term of the Gas Agreement. This compares with an actual utilisation rate of 70% in 2007. (cid:23)(cid:16) (cid:21)(cid:16) (cid:19)(cid:16) (cid:20)(cid:16) (cid:77) (cid:45) (cid:89) (cid:65) (cid:68) (cid:0)(cid:15)(cid:0) (cid:70) (cid:67) (cid:83) addItIOnal GaS (cid:22)(cid:16) PROductIOn Under the terms of a Gas Agreement signed in 2001, the gas from the Songo Songo field in excess of the volume reserved as Protected Gas, is available to Orca Exploration to be (cid:38)(cid:69)(cid:66) marketed as Additional (cid:18)(cid:16)(cid:16)(cid:22) Gas. The details of the 2007 Additional Gas sales are reported in the “Markets” section of this report. (cid:42)(cid:65)(cid:78) (cid:18)(cid:16) FlaRE, GEnERatOR and lInE Pack REquIREMEntS A relatively small amount of gas is used in local electricity generation on Songo Songo Island. Gas is also required to maintain the Songo Songo Island gas plant flare at all times. This leads to a small annual loss of gas. There are also fluctuations in the line pack in the 232 kilometer pipeline to Dar es Salaam. The line is estimated to hold a maximum of 85 Mmscf of gas. At current production levels the line pack holds sufficient gas for approximately one day of Protected and Additional Gas sales in Dar es Salaam. During 2007, Orca Exploration subsurface activities were focussed on the drilling, completion and testing of field development well SS-10 and the remedial work on SS-9. Both were conducted to increase deliv- erability to meet increasing gas demand. dEVElOPMEnt wEll SS-10 The main objective of drilling well SS-10 was to gain a completed reservoir penetration with an initial productive capacity in excess of 50 Mmscf/d. In addition, SS-10 provided the opportunity to acquire a comprehensive and modern wireline dataset on the field for the first time in 25 years. The new data has allowed a re-evaluation of reservoir properties for (cid:51)(cid:69)(cid:80) input to Gas Initially In Place (“GIIP”) and reserve estimation, resulting in a substantial increase in the Songo Songo reserves. (cid:33)(cid:80)(cid:82)(cid:73)(cid:76) (cid:18)(cid:16)(cid:16)(cid:23) (cid:42)(cid:85)(cid:78)(cid:69) (cid:45)(cid:65)(cid:89) (cid:33)(cid:85)(cid:71) (cid:46)(cid:79)(cid:86) (cid:42)(cid:85)(cid:76)(cid:89) (cid:36)(cid:69)(cid:67) (cid:47)(cid:67)(cid:84) (cid:45)(cid:65)(cid:82)(cid:67)(cid:72) Well SS-10 was a deviated well drilled from a location onshore Songo Songo Island, and extending offshore to the east northeast. The maximum stepout was 880 meters and the maximum deviation 40 degrees. The target was the main Neocomian reservoir sands in a structurally high position in the heart of the field. Due to mechanical problems with the rig and borehole instability in the shale dominated overburden, the reservoir was ultimately penetrated with a second sidetrack to the original well. The well was drilled to a total measured depth of 2,426 meters within the main Neocomian reservoir. The top reservoir was encountered at 1,909.5m MD (-1,701m TVDSS) and 265m MD (239m TVD) of gross gas bearing reservoir was drilled. A comprehen- sive suite of wireline logs was successfully acquired and 101 meters of perforation interval was selected in the upper reservoir. Orca made further upgrades to its low pressure distribution system in 2007 and now serves 17 industrial customers in the Dar es Salaam area. Cutlines could go here. (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:23)(cid:12)(cid:16)(cid:16)(cid:16) (cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:21)(cid:12)(cid:16)(cid:16)(cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:19)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:12)(cid:16)(cid:16)(cid:16) (cid:16) t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O A twenty-four hour test was performed on the well, with an initial clean up rate of 52 Mmscf/d through a 80/64” choke. The final flow rate was 40 Mmscf/d through a 64/64” choke. Since the well was still cleaning up when the test was terminated and the rates were restricted by surface facilities, it is estimated that the well will be able to flow at an initial rate in excess of 55 Mmscf/d when on production. This makes it one of the most productive wells in the field and takes the maximum total deliver- ability of the six wells to in excess of 200 Mmscf/d. Post-well evaluation of the wireline log data has demonstrated the value of these modern logs. The Nuclear Magnetic resonance in particular has provided critical information on reservoir parameters which have historically been difficult to estimate due to complex mineralogy and differing water salinities between the pay zone and the aquifer. The results have shown that a revision of historical reservoir parameters and petrophysical cut-offs was required. This has lead to a substantial increase in net pore volumes, GIIP and reserves. The well has been accurately tied to seismic using the velocity information and short Vertical Seismic Profile gathered. The reservoir depth maps have been updated accordingly. Together with the enhanced and re-processed seismic database of 2005/2006, the information gathered from SS-10 provides for a robust structural interpretation of the field from which we derive Gross rock Volume. Combined with the revised reservoir parameters. Orca Exploration has updated the static geological model to provide GIIP estimation. The assessed GIIP to 31 December 2007 is consistent with the values of GIIP used by McDaniel & Associates Consultants Ltd. (“McDaniel”) in their independent reserve evaluation. Ruvu Dodsal Kimbiji Petrodel ammmmmmmmm Dar es Salaam Block 07 Dominion O Songo Songo Gas Field I N D I A N SS Songo 1 Son o Songo ngongogo Songo 1111 Songo 10 Songo 9 Songo 4 O C E A N Songo 5 Songo 7 Gas Plant Songo 3 Songo 6 Songo Songo Island KN1 Kisangire Dominion O Bigwa-Rufiji / Mafia Maurel PR T A N Z A N I A Kwale Songo 8 K1 0 Kilometers 10 Latham Lathamm L thLatha Petrodel Petrodel Block 05 Petrobras Mafia Jibondo Block 04 Ophir En Mandawa Dominion O Nyuni Ndovu Res Songo Songo Songo Songo Jewe Block 03 Ophir En Legend Orca Exploration Group Gas Field Gas Pipeline Possible Pipeline Gas Pipeline Land / Sea TANZSS-01c Songo Songo field and pipelines 0 Kilometers 50 East Pande Rakgas REMEdIal wORk On SS-9 During Q1 2007, the Company commenced a work programme to remove over 5,000 feet of wireline and two gauges that were left downhole in SS-9 at the time of the 1997 well testing programme. This was restricting the flow to 20 Mmscf/d. The remedial work was successfully completed with the result that the maximum SS-9 flow rate increased from 20 Mmscf/d to an estimated 55 Mmscf/d. RESERVOIR SuRVEIllancE and ManaGEMEnt In 2007, the Company continued to acquire high quality information on the Songo Songo field from the downhole gauges that were installed in all wells except SS-9. These gauges record bottom hole pressure changes and allow the Company to use these data for a variety of purposes including estimates of GIIP, near well formation parameter assessment and well deliverability. The pressure gauges were most recently retrieved from the wells during December 2007 and then were re-installed to allow further evaluation in 2008. A pressure gauge will also be installed in SS-10 after it has been connected to the gas processing facility and the well has been cleaned up. 9 operations review The static and dynamic reservoir models have been updated to incorporate the results of development wells SS-10 and SS-9. These continue to be used to predict well performance and to identify the investments in wells and wellhead compression that will be required to meet forecast gas demand. Well performance is monitored throughout the year and a revised well test schedule was adopted in 2007 consisting of 10-day tests on individual wells including a 5-day/120 hour minimum build-up period. The results were analysed monthly as part of the sub-surface reporting. Annual field monitoring studies include well test Pressure Transient Analysis, Combined Material Balance (MBAL™), and regular updates to the simulation model (ECLIPSE™). The simulation model has been used to assess the likely well response to uncertainties such as the rate of aquifer influx and extent of reservoir compart- mentalisation, if any. So far, the pressure behaviour of the wells is not showing evidence of any material compartmentalisation or significant aquifer influx. Pressure data acquired in development well SS-10 suggests there has been no movement in the gas water contact since field start-up, which when interpreted alongside pressure data from the offset wells, supports a likely GIIP towards the upper end of the Company’s computed range. Orca Exploration’s 2007 internal evaluation of static GIIP ranges from 986 Bcf (1P) to 1,274 Bcf (3P) including the northern portion of the field which may not be drained by the existing well stock and compares favourably with the 1,036 Bcf to 1,353 Bcf computed by McDaniel in its independent reserve report as at 31 December 2007 for the 1P and 3P cases respectively. The McDaniel estimate shows a 10-20% increase on 2006 evaluation and a clear trend towards the Material Balance GIIP estimate in the 3P category. Both McDaniel and Orca Exploration’s static GIIP are based on volumetric structural mapping of the different reservoir zones rather than relying on the pressure data at this early stage in the field’s development. To obtain the most reliable data for reservoir management, the Songo Songo gas plant is equipped with a test separator that allows production from individual wells to be measured and important surface pressures and temperatures to be captured using Keller wellhead gauges. This information has been combined with the results of the downhole pressure gauges to show that SS-3, SS-4, SS-5 and SS-9 demonstrate conclusive evidence of communica- tion with other wells. In addition, interference testing in early 2007 appears to confirm that SS-7 is also in communication with SS-5, further reducing the risk of compartmentalisation. Further interference testing is planned for 2008. The flow rates of the wells (including an estimated amount for SS-10 when it comes on production in 2009) based on the requirement to have 1,600 pounds per square inch of pressure in the gas processing plant are as follows: songo songo wells SS-3 SS-4 SS-5 SS-7 SS-9 SS-10 (Estimated) total Maximum Protected Gas demand available for additional Gas well flow RAtes (Mmscf/d) 1997 initiAl CApACitY 31 deC embeR 2006 CApACitY 31 deC embeR 2007 CApACitY 10 10 60 20 40 – 140 (45) 95 16 12 62 20 20 – 130 (45) 85 16 14 65 20 55 55 225 (45) 180 Remedial work on SS-9 has increased the estimated maximum flow rate from 20 Mmscf/d to 55 Mmscf/d. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O Management has estimated the potential for this prospect as follows: estimAted minimum giip most liKelY giip mAximum giip Songo Songo west Bcf 90 Bcf 500 Bcf 800 The intention is to drill SSW using the same jack-up rig that will be required to drill SSN. SS-10 Neocomian formation data set The Songo Songo well pressures showed a 1% decline over the course of 2007, in line with expectations and previous years, as demonstrated by the Material Balance analysis. With the inclusion of productivity arising from remedial work on SS-9, performed after year-end, the deliverability is sufficient to enable 180 Mmscf/d of Additional Gas production above the peak demand for Protected Gas. This will allow the Company to produce more than 115 Mmscf/d of Additional Gas for a period of time even if the most productive well becomes unavailable at peak demand. aPPRaISal dRIllInG Orca Exploration’s assessment is that a majority of the 2P reserves can be delivered from the existing well stock. However, a deepening of the mapped structure between the main field and the northern portion of the field where well SS-1 is located and referred to as Songo Songo North (“SSN”) means that SSN may not currently be drained. The static geological and dynamic Eclipse models indicate that approximately 140 Bcf of recoverable 2P reserves are present in this northern area of the field. Therefore, this represents a target for the drilling of an appraisal well that would be tied back into the Songo Songo Island facilities. The intention is to drill SSN as soon as practicable with a jack-up rig and as part of the same campaign to drill the Songo Songo West exploration prospect. The total cost of drilling SSN is estimated at US$20 – US$30 million, with an additional US$4 million to complete. In addition, there would be infrastructure costs to tie the well into the existing gas processing and pipeline system. Exploration Orca Exploration has mapped and evaluated the Songo Songo West (“SSW”) prospect adjacent to the Songo Songo field. The prospect is located entirely within the Company’s Discovery Blocks. The seismic on SSW indicates closure on an elongate north-south oriented tilted fault block trap at the same reservoir interval (Neocomian and possibly Cenomanian) as the main field. The southern portion of this low-risk prospect lies approximately 4.3 kilometers west of the Songo Songo Island facilities. 11 operations review Gas reserves In accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, the independent petroleum engineers, McDaniel prepared a report dated April 2008 that assessed the Orca Exploration natural gas reserves based on information on the Songo Songo field as at 31 December 2007 (the “McDaniel report”). Over the course of 2007, the total 2P Additional Gas reserves on a gross property basis (i.e. all natural gas in the Songo Songo field excluding Protected Gas) have increased 20% in the year from 415.1 Bcf to 499.5 Bcf on a life of licence basis and 24% from 470.5 Bcf to 583.6 Bcf on a life of field basis. On a gross Company basis there has been a 16% increase in Songo Songo’s 1P Additional Gas reserves during the year from 265.8 Bcf to 308.6 Bcf despite Additional Gas sales of 7.7 Bcf being produced. Gross 2P reserves increased 14% from 415.1 Bcf to 473.6 Bcf. The 1P and 2P reserves are based on production to the end of the licence period (October 2026) while the 3P reserves assume that licence will be extended to the end of the field life. The reserves summary for the gross Additional Gas was as follows: AdditionAl songo songo gAs ReseRves to oCtobeR 2026 (Bcf) Independent reserves evaluation Proved producing Proved undeveloped total proved (1P) Probable total proved and probable (2P) Possible total proved, probable and possible (3P) 2007 Net (2) 159.1 51.0 210.1 113.8 323.9 191.4 2006 Net 129.4 55.1 184.5 99.8 Gross 219.5 46.3 265.8 149.3 415.1 284.3 n/a n/a Gross (1) 247.6 61.0 308.6 165.0 473.6 307.1 780.7 515.3 n/a n/a (1) Gross equals the gross reserves that are available for the Company after the TPDC back in (see below). (2) Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the Production Sharing Agreement. Songo Songo Gas Field Songo 1 Songo Songo West Prospect Songo 10 Songo 9 Songo 5 Songo 7 Songo 4 Gas Plant Songo 3 Songo 6 Songo Songo Island KN1 Songo 8 K1 0 Kilometers 10 TANSS-05 Whilst only 57.0 Bcf had been produced from the field by the end of 2007, there is increasing confidence in the Company’s internally generated Material Balance GIIP of 1,379 Bcf. This compares favourably with McDaniel’s 3P category GIIP of 1,353 Bcf. The McDaniel report has assumed that TPDC will exercise its right to ‘back in’ to the field development by contributing 20% of the costs of the future wells, including SS-10 and a proportion of the infrastructure and operating costs, in return for a 20% increase in the profit share for the production emanating from these wells. In 2007, McDaniel has taken the view that this ‘back in’ right should be treated as a TPDC working interest and therefore the Gross reserves have been adjusted for the volumes of Additional Gas (26.0 Bcf at 2P) that are allocated to TPDC for their working interest share. The economic effect of this had been reflected in the Net Additional Gas reserves in 2006, but the working interest had not been shown in the Gross reserves. The implications and workings of the ‘back in’ are still to be discussed in detail with TPDC. For the purpose of calculating the gross Additional Gas reserves, McDaniel has assumed in their 2P case that 227 Bcf or an average of 13.8 Bcf per annum will be required to meet the demands of the Protected Gas users from 1 January 2007 to October 2026. This compares with 233 Bcf as at 1 January 2006. During 2007 Protected Gas users consumed 11.5 Bcf. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O The principal assumptions used by McDaniel in its evaluation of the Tanzanian PSA are as follows: AdditionAl gAs pRiCe 1p gRoss AdditionAl gAs volumes 1p AdditionAl gAs pRiCe 2p gRoss AdditionAl gAs volumes 2p AnnuAl inflAtion (cid:48)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83) US$/mcf Mmscf/d US$/mcf Mmscf/d (cid:70) (cid:67) (cid:66) (cid:24) (cid:17)(cid:22) (cid:17)(cid:20) (cid:17)(cid:18) (cid:17)(cid:16) (cid:22) (cid:20) (cid:18) (cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:23)(cid:12)(cid:16)(cid:16)(cid:16) (cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:21)(cid:12)(cid:16)(cid:16)(cid:16) (cid:19)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:12)(cid:16)(cid:16)(cid:16) (cid:16) 30.00 39.87 47.78 53.97 55.97 59.53 60.53 61.64 61.64 61.64 61.64 61.64 48.24 36.60 32.56 (cid:18)(cid:16)(cid:16)(cid:23) 26.48 (cid:38)(cid:76)(cid:65)(cid:82)(cid:69) (cid:35)(cid:85)(cid:77)(cid:85)(cid:76)(cid:65)(cid:84)(cid:73)(cid:86)(cid:69)(cid:0)(cid:80)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0) (cid:70)(cid:82)(cid:79)(cid:77)(cid:0)(cid:69)(cid:65)(cid:67)(cid:72)(cid:0)(cid:87)(cid:69)(cid:76)(cid:76) YeAR (cid:48)(cid:82)(cid:79)(cid:84)(cid:69)(cid:67)(cid:84)(cid:69)(cid:68)(cid:0)(cid:39)(cid:65)(cid:83)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83)(cid:0)(cid:66)(cid:89)(cid:0)(cid:89)(cid:69)(cid:65)(cid:82) (cid:17)(cid:20)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:22)(cid:12)(cid:16)(cid:16)(cid:16) 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) 2018 2019 (cid:18)(cid:12)(cid:16)(cid:16)(cid:16) 2020 2021 (cid:18)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:22)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:18)(cid:12)(cid:16)(cid:16)(cid:16) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) (cid:24)(cid:12)(cid:16)(cid:16)(cid:16) (cid:20)(cid:12)(cid:16)(cid:16)(cid:16) 3.71 3.67 3.82 4.00 4.52 5.02 5.18 5.28 5.37 5.46 5.56 5.65 5.75 5.85 (cid:51)(cid:51)(cid:13)(cid:19) (cid:51)(cid:51)(cid:13)(cid:20) (cid:51)(cid:51)(cid:13)(cid:21) (cid:51)(cid:51)(cid:13)(cid:23) (cid:51)(cid:51)(cid:13)(cid:25) (cid:16) 2022 (cid:18)(cid:16)(cid:16)(cid:20) Remainder (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:53)(cid:66)(cid:85)(cid:78)(cid:71)(cid:79)(cid:0)(cid:48)(cid:79)(cid:87)(cid:69)(cid:82)(cid:0)(cid:48)(cid:76)(cid:65)(cid:78)(cid:84) (cid:55)(cid:65)(cid:90)(cid:79)(cid:0)(cid:40)(cid:73)(cid:76)(cid:76) (cid:16) (cid:18)(cid:16)(cid:16)(cid:20) 5.96 (cid:18)(cid:16)(cid:16)(cid:21) 6.26 (cid:18)(cid:16)(cid:16)(cid:22) (cid:48)(cid:82)(cid:79)(cid:84)(cid:69)(cid:67)(cid:84)(cid:69)(cid:68)(cid:0) (cid:39)(cid:65)(cid:83) (cid:33)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0) (cid:39)(cid:65)(cid:83) addItIOnal GaS RESERVES REcOncIlIatIOn (cid:33)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0)(cid:39)(cid:65)(cid:83)(cid:0)(cid:86)(cid:79)(cid:76)(cid:85)(cid:77)(cid:69)(cid:83) Bcf (cid:33)(cid:86)(cid:69)(cid:82)(cid:65)(cid:71)(cid:69)(cid:0)(cid:68)(cid:65)(cid:73)(cid:76)(cid:89)(cid:0)(cid:80)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:80)(cid:69)(cid:82)(cid:0)(cid:77)(cid:79)(cid:78)(cid:84)(cid:72) proved proved and probable proved proved and probable gRoss gRoss net net Reserves at (cid:24)(cid:16) 1 January 2007 Extensions (cid:23)(cid:16) Improved recovery Technical revisions (cid:22)(cid:16) Discoveries Acquisitions Dispositions (cid:21)(cid:16) (cid:89) (cid:65) (cid:68) (cid:0)(cid:15)(cid:0) (cid:70) (cid:67) (cid:83) (cid:77) (cid:45) Economic factors Production (cid:20)(cid:16) Reserves at 31 december 2007 (cid:19)(cid:16) 265.8 415.1 184.5 284.3 – – – – 50.5 66.2 – – – – – – – – – – 31.8 – – – – – 45.9 – – – – (7.7) (7.7) (6.3) (6.3) 308.6 473.6 210.1 323.9 The increase in the proven and probable reserves has arisen from improved volumetric structural mapping, the 2007 pressure and gas (cid:45)(cid:65)(cid:89) (cid:42)(cid:85)(cid:78)(cid:69) production data and the SS-10 development well results. (cid:45)(cid:65)(cid:82)(cid:67)(cid:72) (cid:33)(cid:80)(cid:82)(cid:73)(cid:76) (cid:33)(cid:85)(cid:71) (cid:46)(cid:79)(cid:86) (cid:42)(cid:85)(cid:76)(cid:89) (cid:36)(cid:69)(cid:67) (cid:51)(cid:69)(cid:80) (cid:38)(cid:69)(cid:66) (cid:47)(cid:67)(cid:84) (cid:42)(cid:65)(cid:78) (cid:18)(cid:16) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:41)(cid:78)(cid:68)(cid:85)(cid:83)(cid:84)(cid:82)(cid:73)(cid:65)(cid:76)(cid:0)(cid:51)(cid:65)(cid:76)(cid:69)(cid:83) (cid:48)(cid:79)(cid:87)(cid:69)(cid:82)(cid:0)(cid:51)(cid:65)(cid:76)(cid:69)(cid:83) 3.52 3.74 3.85 3.76 4.12 4.62 4.80 5.00 5.18 5.27 5.36 5.46 5.55 5.65 5.75 6.03 (cid:21)(cid:16)(cid:16) (cid:20)(cid:16)(cid:16) (cid:19)(cid:16)(cid:16) (cid:70) (cid:67) (cid:34) (cid:18)(cid:16)(cid:16) (cid:17)(cid:16)(cid:16) (cid:16) 35.00 46.37 57.28 75.97 87.97 91.53 93.53 98.30 100.30 100.30 100.30 100.30 81.81 64.06 49.66 46.74 % 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 (cid:35)(cid:79)(cid:77)(cid:80)(cid:65)(cid:78)(cid:89)(cid:0)(cid:71)(cid:82)(cid:79)(cid:83)(cid:83)(cid:0)(cid:82)(cid:69)(cid:67)(cid:79)(cid:86)(cid:69)(cid:82)(cid:65)(cid:66)(cid:76)(cid:69)(cid:0) (cid:65)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0)(cid:71)(cid:65)(cid:83)(cid:0)(cid:82)(cid:69)(cid:83)(cid:69)(cid:82)(cid:86)(cid:69)(cid:83)(cid:0) (cid:79)(cid:78)(cid:0)(cid:65)(cid:0)(cid:76)(cid:73)(cid:70)(cid:69)(cid:0)(cid:79)(cid:70)(cid:0)(cid:76)(cid:73)(cid:67)(cid:69)(cid:78)(cid:67)(cid:69)(cid:0)(cid:66)(cid:65)(cid:83)(cid:73)(cid:83) (cid:18)(cid:16)(cid:16)(cid:20) (cid:18)(cid:16)(cid:16)(cid:21) (cid:18)(cid:16)(cid:16)(cid:22) (cid:18)(cid:16)(cid:16)(cid:23) (cid:48)(cid:82)(cid:79)(cid:66)(cid:65)(cid:66)(cid:76)(cid:69) (cid:48)(cid:82)(cid:79)(cid:86)(cid:69)(cid:68) 13 operations review PRESEnt ValuE OF RESERVES The estimated value of the Songo Songo reserves on a life of license basis based on the assumptions on production and pricing are as follows: US$ millions Proved producing Proved undeveloped total proved (1P) Probable total proved and probable (2P) Possible total proved, probable and possible 5% 191.1 65.7 256.8 114.8 371.6 185.1 556.7 10% 125.6 57.1 182.7 72.2 254.9 87.1 342.0 2007 15% 89.0 47.7 136.7 46.6 183.3 43.4 226.7 5% 113.5 41.4 154.9 86.8 241.7 n/a n/a 10% 78.1 30.9 109.0 49.7 158.7 n/a n/a 2006 15% 58.2 21.4 79.6 28.9 108.5 n/a n/a The 61% increase on the 2P present value at a 10% discount basis from US$158.7 million to US$254.9 million on a life of licence basis is primarily due to the increase in the reserves and the costs to be recovered as a result of high capital expenditure in 2007. It should be noted that McDaniel has assumed in the 3P case, that the Company receives an extension to the PSA. Hence for this category only, the reserves are not restricted to the life of the licence. infrastructure hIGh-PRESSuRE dIStRIbutIOn SyStEM The infrastructure that processes and transports the gas from the field to Dar es Salaam was commissioned in July 2004. The current infrastructure configuration has a name plate capacity of 70 Mmscf/d, limited by the two gas processing trains that have a design specifi- cation of 35 Mmscf/d each and the pipeline system that is assessed by the owner, Songas, to have a capacity of 105 Mmscf/d. During the last quarter of 2007, the sales of Additional Gas were occasionally limited by the gas processing capacity. This constraint is expected to continue through to the end of June 2008. In Q1 2007, Songas made an application to Tanzania’s regulatory authority, EWUrA, for the installation of two new gas processing trains to increase throughput capacity to more than 140 Mmscf/d. During Q3 2007 the tender documents for the engineering, procurement and construction (EPC) contract were received. However, the all-in cost of approximately US$58 million was significantly greater than forecast. Accordingly, in Q1 2008, Songas submitted a further application to EWUrA with the revised costs and an amended tariff structure. It is expected that this process will be concluded during Q2 2008 and that the commissioning will occur fifteen months from the time that Songas gives the notice to the EPC contractor to proceed. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O Orca provides low-pressure gas distribution to serve Dar es Salaam industrial customers. As currently submitted, the initial tariff structure for the two new trains and the existing infrastruc- ture remains the same for the Additional Gas sales to the non-power sector at 17.5% of the sales price. The sales to the power sector will attract a higher percentage tariff, but as the price is significantly lower, the tariff will still be less on a per Mcf basis than that for the industrial sector. The price of gas that is currently being negotiated with the power sector is net of any tariff and therefore is not sensitive to the tariff. In Q3 2007, Orca submitted proposals to Songas that would enable the gas processing capacity to be increased by approximately 20 – 35 Mmscf/d to 90 Mmscf/d – 105 Mmscf/d before the two trains are operational. This involves upgrading and re-rating the existing trains, utilising a bypass and modifying the pressure relief system. Songas has approved the work for the re-rating of the two existing trains and two new 3” Joule-Thomson valves are in the process of being installed. This is expected to increase the processing capacity to 90 Mmscf/d, however it will not be possible to operate the trains at the higher rate until the insurers have approved the re-rating. Introducing a bypass skid leads to changes to the gas specification including the moisture content. Letters have been sent to the manufacturers of the gas turbines by Songas and TANESCO to seek confir- mation that the units can operate at the amended specification. If successful, it is expected that this will provide an additional 15 Mmscf/d of gas throughput capacity though it is likely that the Company may have to provide indemnities in the event that the revised gas specification leads to problems with the turbines. This is under discussion with Songas. The 232 kilometer pipeline system to Dar es Salaam is limited by the 12” 25 kilometer offshore line at an estimated 105 Mmscf/d, though this is still to be confirmed. It is anticipated that installation of compression facilities or a new offshore line will eventually be required to meet future peak throughput rates. The Company’s objective is to increase the throughput capacity to 160 Mmscf/d by 2011. POwER cOnnEctIOnS During 2007, the Company connected four new power plants with an installed capacity of 220 MWs. This involved laying steel pipeline from the main high-pres- sure system and installing metering facilities. Wazo Hill Kiln 4 Tegeta Tegeta Wärtsilä 45MW 8 “ L i n e IPTL 100MW UGT-6 Mikocheni area 178MW leased EPPs Aggreko 48MW Dowans 100 + 20 = 120MW owans 100 + 20 = 120 Wärtsilä 100MW DAR ES SALAAM “ “ 6 6 1 1 3 Murzha 3 Mukwano Tuasa Batteryy Pepsi Metro Kinyerezi 250MW N Namera Airport Area Murzha 1&2 Lakhani Azam I n d i a n O c e a n Chinese Textile mills dNida Nida Textile Tanzania Breweries Bora Alaf Kioo Glass Kioo Glass Plasco Insign paint METL Associated Breweries Serengetig Karibu Textile Legend Gas Pipeline Existing Ringmain Pressure Reduction Stations (PRS) Power Generation Stations AG Customers Connected Next AG Industrial Customers Town / City 0 Kilometers 10 TANZCW-02a Dar es Salaam area gas distribution infrastructure During 2008, additional telemetry will be installed so that the Company can monitor the off-take pressures of the power customers. As the throughput of gas in the pipeline system nears capacity, there is an increasing risk that excessive demand by the power sector could lead to some of its units ‘tripping’ through a loss of pressure. In addition, some capital expenditure will be required to improve the filtration systems for each of the power plants. lOw-PRESSuRE dIStRIbutIOn SyStEM At Dar es Salaam, Orca Exploration continued to expand its distribution system during 2007. Shortly after the end of Q3 2007, Orca completed a further 8 kilometer extension of its low-pressure distribution system that now consists of 35 kilometers. In addition, a second pressure reduction station was installed. This provides the Company with greater security of deliverability to its existing customers and allows for growth. An 8 kilometer US$1.2 million extension to the Mikocheni area will be constructed in Q4 2008 once contracts with an average demand of 1 Mmscf/d are signed with local industries. 15 operations review Market Development The 14% increase in the 2P recoverable reserves in 2007 is providing the Company with an opportunity to develop new markets. There has been a renewed focus on the development of the higher value markets outside the power sector including the development of the markets for CNG. The following summarises the actual sales volumes for 2007 and the forecast sales volumes for 2008 and 2009. Mmscf/d Industrial Power Compressed Natural Gas total 2007 ACtuAl 2008 tARget 2009 tARget (Note 1) (Note 1) 4.1 17.1 5.0 - 7.0 7.0 - 11.0 27.0 - 35.0 35.0 - 41.0 – 0.2 - 0.5 1.0 - 5.0 21.2 32.2 - 42.5 43.0 - 57.0 Note 1: This is dependent on the signing of the current power contracts under discussion that may or may not materialise, average hydrology in Tanzania and the successful implementation of interim solutions to increase the capacity of the gas processing facilities to 90 Mmscf/d by 30 June 2008. PROSPEctIVE InduStRIal SalES Sales to the industrial sector averaged approximately 4.1 Mmscf/d in 2007 and are expected to increase to in excess of 5.0 Mmscf/d in 2008 through the con- struction of an 8 kilometer extension of the distribu- tion system to the Mikocheni area and the hook up of new customers in Dar es Salaam. It is then forecast that 1.0 Mmscf/d will be added each year through expansion of the industrials existing facilities and the connection of new industrial customers that have relocated to Dar es Salaam. Demand for cement in Tanzania has increased sig- nificantly and this is forecast to lead to an increase in the gas consumption at the Wazo Hill cement plant in Dar es Salaam. This entity is in the process of installing a new kiln (“Kiln 4”) that is forecast to be operational in Q2 2009. Kiln 4 consumes more gas than the existing two kilns (“Kilns 2 and 3”) that utilise Protected Gas. It is envisaged that Kilns 2 and 3 will undergo a major overhaul in 2009 before being re-commissioned in 2009/2010. The Company expects to average Additional Gas sales of approximately 2.0 Mmscf/d in 2009 from this source and a contract is currently being negotiated. Wazo Hill would require approximately 7.5 Mmscf/d of Additional Gas if all kilns were operational. A number of the Company’s industrial customers have expressed an interest in utilising their own power generation to ensure reliability of supply. This could lead to sales of 2-3 Mmscf/d by the end of 2009. There are a number of industries located outside of Dar es Salaam that are commercially accessible by pipelines in a US$60+/barrel environment. Tanga is 300 kilometers north of Dar es Salaam and only 60 kilometers from the Kenya border. It has approximately 10 Mmscf/d of peak gas demand, including the second largest cement plant in Tanzania. 180 kilometers west of Dar es Salaam is Morogoro where there are several industries with a forecast peak demand of 7-9 Mmscf/d. The Company will assess whether it is more viable to construct pipelines to these customers or transport Compressed Natural Gas. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O Orca supports educational, fresh water, health and community programs for residents of Songo Songo Island. PROSPEctIVE POwER SalES Sales to the power sector averaged approximately 17.1 Mmscf/d in 2007 and are expected to increase to in excess of 30 Mmscf/d in 2008, provided the interim solutions for increasing the gas processing facilities are implemented by June 2008. The rapid expansion of gas fired power generation in Tanzania continues to exceed Orca’s expectations. At the end of 2006, a total of 90 MWs (UGT 6: 42 MWs and Aggreko: 48 MWs) of gas fired generation was operational in Tanzania utilising the Company’s Ad- ditional Gas. During the course of 2007, an additional 220 MWs was introduced onto the system taking the maximum capacity operating on Additional Gas to 310 MWs. Of this 168 MWs is considered emergency gen- eration that was brought into the country in response to severe droughts that severely reduced the capacity of the hydro plants. 48 MWs of the emergency genera- tion (Aggreko) is forecast to be decommissioned in late 2008 at the same time as 45 MWs of permanent Wärtsilä generation is due to be installed close to the IPTL power plant at Tegeta. The remaining 120 MWs of emergency generation, operated by Dowans, has been contracted until October 2009. During 2007, there were detailed discussions with TANESCO/MEM to secure two long-term contracts for this expanded generation capacity. The first contract covers the supply of gas to the sixth turbine at the Ubungo power plant. This contract has a maximum daily quantity of approx 9.2 Mmscf/d and is expected to be run at a utilisation rate of approxi- mately 85% until July 2024. A further contract covers the sales to the remaining plants and has a maximum daily quantity of approximately 36 Mmscf/d and a take or pay quantity of 32 Mmscf/d until July 2023. The total contract quantity is approximately 200 Bcf. The contract price is expected to be the same for both contracts namely US$1.87/Mmbtu HHV (US$1.91/ mcf) after the deduction of the gas processing and pipeline tariff or an estimated US$2.27/Mmbtu HHV (US$2.32/mcf) before the tariff deduction (based on the existing tariff rates). These prices are forecast to increase 2% per annum until July 2012 at which point there will be a step change to US$2.77/ Mmbtu HHV (US$2.83/mcf) after the deduction of the gas processing and pipeline tariffs or US$3.36/ Mmbtu HHV (US$3.43/mcf) before tariff deduction (based on existing tariff rates). These prices will then increase at 2% per annum. As at 31 December 2007, Tanzania had approximate- ly 1,131 MWs of installed and operational electrical power generation as follows: poweR plAnt pRinCipAl wAteR souRCe instAlled CApACitY feedstoCK hydro Kidatu Mtera dam Mtera Mtera dam Hale run of river Pangani Falls run of river Kihansi run of river Others run of river Gas fired Protected Gas additional Gas Other Other thermal Ubungo power plant (units 1-5) Ubungo power plant (unit 6) Dowans Aggreko Wärtsilä at Ubungo Mtwara Independent Power of Tanzania Limited (“IPTL”) MWs 204 80 21 68 180 8 561 148 42 120 48 100 12 470 100 total 1,131 The majority of Tanzania’s installed generation is hydro, however over the past three years there has been a rebalancing of the portfolio. The only major water storage is at the Mtera reservoir that supplies the 80 MW Mtera and the 204 MW Kidatu hydro plants. 277 MWs of the hydro is primarily run of river and is operational on average for only 4-5 months a year. Accordingly, the level of the Mtera reservoir is integral to the generation of 284 MWs of electricity. During 2007 there was a significant amount of rain in Tanzania with the result that the Mtera reservoir rose to its maximum level of 698 meters above sea level compared with 686 meters at the end of 2006. This enabled TANESCO to run the Mtera and Kidatu hydro plants throughout 2007. This was welcome news for Tanzania and alleviated some of the financial pressures on TANESCO. 17 operations review The following sets out the generation that TANESCO has indicated will be installed or decommissioned in Tanzania during 2008: feedstoCK Installed generation at 31 december 2007 Gas fired Wärtsilä Aggreko coal fired Kiwira estimAted CommenCement/ teRminAtion dAte teRm YeARs instAlled CApACitY MWs 1,131 45 (48) (3) Q4 2008 Q4 2008 20 2008 20 50 Forecast installed generation at 31 december 2008 1,178 Whilst there is significant installed gas fired generation now operating in Tanzania, there is considerable difficulty in projecting the utilisation of these units between 2008 and 2010. In above average rain years such as 2007, the use of gas fired generation (including that operating on Protected Gas) can be significantly curtailed during the 4-5 rainy months of the year. The Mtera dam is currently at 698 meters, following recent heavy rains. Over the longer term (after 2010), it is forecast that demand will have sufficiently increased whereby gas fired generation will be base loaded with utilisation rates of circa 70% – 75%. The TANESCO power demand is currently increasing at 8% per annum and is forecast to increase at 12% over the course of the next two years. The current peak electricity demand is approximately 650 MWs. This leads to an increase in the generation capacity of approximately 50 MWs per annum or 9-10 Mmscf/d at full load. Gas fired generation can be added in incremental 50 MW units whereas coal and hydro projects are generally larger and require a significant commitment by TANESCO in order to facilitate the financing of the plants. In addition, the current gas is priced at a level that makes gas fired generation competitive with the all-in-cost of coal generation. Accordingly, it is forecast that whilst there are sufficient gas reserves in the country, gas fired generation will be the preferred choice for new capacity. For future power contracts it is anticipated that it will be possible to price the gas at a level that makes it competitive with coal. This sees initial prices in excess of US$4.00/mcf increasing with inflation. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O A 2-D seismic program was shot in Exploration Area 5 in Uganda to assess hydrocarbon potential. PROSPEctIVE POwER ExPORtS The countries of East Africa have the following electricity generation mix: Population (million) Installed generation (MWs) Hydro Gas fired Oil fired Geothermal total tAnzAniA ugAndA KenYA 39.4 30.9 36.9 561 470 100 – 1,131 300 – 100 – 400 677 – 408 115 1,200 Like Tanzania, Kenya and Uganda have histori- cally relied heavily on hydro for their electricity generation, but recent severe dry periods have lead to load shedding. To rebalance their generation mix, the countries have installed expensive oil fired plants. If increased volumes of gas are found in Tanzania, there is scope for Dar es Salaam to become the thermal gas generation hub for the region. uGanda There is currently only a small 20 MW transmis- sion line linking Tanzania to Uganda. There are a number of interested parties who are planning to finance a 400 kilometer transmission line to run from Bulyanhula past a number of the mines around Lake Victoria (e,g. Geita) to Masaka in Uganda. It is forecast that this could be constructed during 2011. Uganda had a peak supply demand of approximately 380 MWs and an average demand of 290 MWs. Its installed hydro capacity is 300 MWs (Nalubaale and Kiira), but due to the low water level of Lake Victoria, the output can be reduced to approximately 120 MWs. In addition to the hydro, there is currently 100 MWs of Aggreko emergency generation in-country run on liquid fuel that will be decommissioned at the end of 2009. Uganda is introducing a further 100 MWs of permanent plant in 2008 that will utilise automative diesel oil. K E N Y A K E N Y A SeS Seven Forks II NAIROBI Arusha to Nairobi Interconnector Legend Existing 220 kV Line Proposed 220 kV Line 132 kV Line Existing Gas Pipeline Possible Gas Pipeline Oil Pipeline Hydro-electric Plant Gas Markets Infrastructure Arusha aa 0 Kilometers 100 T A T A N Z A N I A AA N Z A N Singida idada Trunklines to Morogoro Trunklines to Tanga / Mombasa MorogMorogMorog Morogoro DAR ES SALAAM I N D I AN O C E A N Songo Songo Zambia Interconnector TANZCW-01 The World Bank is understood to have agreed to finance the strengthening of transmission lines between Iringa and Shinyanga in Tanzania which will facilitate the export of power Kenya has a peak supply demand of 1,030 MWs against an installed capacity of 1,200 MWs. Demand growth has been significant with peak demand increasing from 820 MWs in 2003 and is likely to increase at approximately 70-100 MWs per annum. In addition, there are 308 MWs (including 100 MWs of Aggreko emergency generation which is due to remain in country until the end of 2009) of thermal generation operating on heavy fuel oil in the country. It is forecast that 200 MWs could be exported to Kenya by the end of 2011. The average cost of generation in 2007 is estimated at US$0.26/kwh. With the introduction of the 250 MW Bujagali plant that is due to be commissioned in 2011/2012 (estimated output between 132 MWs and 227 MWs depending on hydrology), this is expected to fall to US$0.16/kwh. Despite a number of oil discoveries in western Uganda in recent years, it is anticipated that it would be economically more efficient to export oil at market prices in excess of US$100/barrel and import electricity with earned hard currency at lower prices. It is forecast that Uganda will have a peak demand of between 789 MWs and 1,104 MWs by 2020. Once Bujugali is constructed there will be 650 MWs of permanent generation, but average output is expected to be significantly less because of the hydrology. It is estimated that between the mines and Uganda, there could be an initial demand of 200 MWs by 2011. 19 operations review kEnya There are currently no transmission lines linking Tanzania to Kenya. The 260 kilometer interconnector between Arusha and Nairobi is due to be completed by 2011. cOMPRESSEd natuRal GaS (cnG) CNG is widely used around the world, including India and China. To introduce CNG use in Tanzania, the Company installed a small compressor in 2007 and converted some vehicles to run on CNG. The World Bank is understood to have agreed to finance the strengthening of transmission lines between Iringa and Shinyanga in Tanzania which will facilitate the export of power. Kenya has a peak supply demand of 1,030 MWs against an installed capacity of 1,200 MWs. Demand growth has been significant with peak demand increasing from 820 MWs in 2003 and is likely to increase at approxi- mately 70 -100 MWs per annum. In addition, there are 308 MWs of thermal generation operating on heavy fuel oil in the country (including 100 MWs of Aggreko emergency generation which is due to remain in country until the end of 2009). It is forecast that 200 MWs could be exported to Kenya by the end of 2011. There is a strong push by the Government of Tanzania to utilise CNG and the Company plans to expand CNG activities in 2008. By Q4 2008, the Company intends to install a compressor that will utilise approximately 0.7 Mmscf/d. The gas used in the first CNG dispensing system will supply vehicles and other customers in the local Dar es Salaam market. Orca is intended to rapidly expand the CNG market during the remainder of 2008 and 2009 with a particular focus on using this ‘virtual pipeline’ to supply the industrial markets of Morogoro and Tanga and the hotels and industries around Dar es Salaam. It is estimated that for the larger markets, capital expenditure of approximately US$1 million will be required for each 0.5 Mmscf/d of gas sales. It will involve acquiring compressors and a fleet of trucks and containers to deliver the CNG around the clock. The expenditure can be incurred piecemeal as the markets expand. The potential CNG market in Tanzania is estimated to be approximately 10 - 15 Mmscf/d. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O cORPORatE SOcIal The Board of Directors regularly reviews the aims of the corporate social responsibility strategy and how this translates into practical and beneficial community relations support in Tanzania. A budget is established with agreed ongoing assistance covering education, health and the provision of water and power on Songo Songo Island. Particular emphasis is given to providing educational materials and equipment for the existing school, with support being given to the setting up of a new secondary school. The overall aim is to improve the quality of life for all the local inhabitants and maintain good community relations. Right Cars, truck and buses can be converted to run on CNG instead of gasoline or diesel. Small CNG storage tanks are installed in the vehicles and can be refilled at CNG compressor stations. The use of CNG as a transportation fuel can significantly reduce air pollution and greenhouse gas emissions. 21 management’s discussion & analysis FORwaRd lOOkInG StatEMEntS THIS MDA OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS SHOULD BE READ IN CONJUCTION WITH THE COMPANY’S FINANCIAL STATEMENTS AND NOTES THERETO FOR YEAR ENDED 31 DECEMBER 2007. THIS MDA IS BASED ON THE INFORMATION AVAILABLE ON 28 APRIL 2008. IT CONTAINS CERTAIN FORWARD-LOOKING STATEMENTS THAT INVOLVE SUBSTANTIAL KNOWN AND UNKNOWN RISKS AND UNCERTAINTIES, CERTAIN OF WHICH ARE BEYOND ORCA EXPLORATION GROUP INC’S (“ORCA EXPLORATION” OR “THE COMPANY”) 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 ENVIRONMENTAL 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 REGULATORY AUTHORITIES. IN ADDITION THERE ARE RISKS AND UNCERTAINTIES ASSOCIATED WITH GAS OPERATIONS. THEREFORE, ORCA EXPLORATION’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 ORCA EXPLORATION WILL DERIVE THEREFROM. nOn-GaaP MEaSuRES THE COMPANY EVALUATES ITS PERFORMANCE BASED ON EARNINGS AND FUNDS FLOW. FUNDS FLOW FROM OPERATING ACTIVITIES IS A NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES) TERM THAT REPRESENTS EARNINGS BEFORE DEPLETION, DEPRECIATION, STOCK-BASED COMPENSATION, DEFERRED INCOME TAX, DEFERRED ADDITIONAL PROFITS TAX, INTEREST INCOME AND FOREIGN EXCHANGE GAINS IN RELATION TO FINANCING. THE INCLUSION OF CHANGES IN NON-CASH WORKING CAPITAL RESULTS IN CASH PROVIDED FROM OPERATING ACTIVITIES ON THE STATEMENT OF CASH FLOWS. IT IS A KEY MEASURE AS IT DEMONSTRATES THE COMPANY’S ABILITY TO GENERATE CASH NECESSARY TO ACHIEVE GROWTH THROUGH CAPITAL INVESTMENTS. ORCA EXPLORATION ALSO ASSESSES ITS PERFORMANCE UTILIZING OPERATING NETBACKS. OPERATING NETBACKS REPRESENT THE PROFIT MARGIN ASSOCIATED WITH THE PRODUCTION AND SALE OF ADDITIONAL GAS AND IS CALCULATED AS REVENUES LESS RINGMAIN TARIFF, GOVERNMENT PARASTATAL’S REVENUE SHARE, OPERATING AND DISTRIBUTION COSTS FOR ONE THOUSAND STANDARD CUBIC FEET OF ADDITIONAL GAS. THIS IS A KEY MEASURE AS IT DEMONSTRATES THE PROFIT GENERATED FROM EACH UNIT OF PRODUCTION, AND IS WIDELY USED BY THE INVESTMENT COMMUNITY. THESE NON-GAAP MEASURES ARE NOT STANDARDISED AND THEREFORE MAY NOT BE COMPARABLE TO SIMILAR MEASUREMENTS OF OTHER ENTITIES. ADDITIONAL INFORMATION REGARDING ORCA EXPLORATION GROUP INC IS AVAILABLE UNDER THE COMPANY’S PROFILE ON SEDAR AT www.sedar.com. Background Orca Exploration’s principal 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 agreement 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 kilometers of pipeline to Dar es Salaam and a 16 kilometer spur to the Wazo Hill cement plant. Songas utilises the Protected Gas (maximum 45.1 Mmscf/d) as feedstock for its gas turbine electricity generators at Ubungo, for onward sale to the Wazo Hill cement plant and for electrification of some villages along the pipeline route. Orca Exploration receives no revenue for the Protected Gas delivered to Songas and operates the field and gas processing plant on a ‘no gain no loss’ basis. Orca Exploration has the right to produce and market all gas in the Songo Songo field in excess of the Protected Gas requirements (“Additional Gas”). PRIncIPal tERMS OF thE PSa and RElatEd aGREEMEntS The principal terms of the Songo Songo PSA and related agreements are as follows: OblIGatIOnS and REStRIctIOnS (a) The Company has the right to conduct petroleum operations, market and sell all Additional Gas produced and share the net revenue with TPDC for a term of 25 years expiring in October 2026. (b) The PSA covers the two licences in which the Songo Songo field is located (“Discovery Blocks”). The Proven Section is essentially the area covered by the Songo Songo field within the Discovery Blocks. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O (e) “Insufficiency” occurs if 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 Orca Exploration and TPDC from the Discovery Blocks prior to the occurrence of the Insufficiency, Orca Exploration and TPDC shall be jointly liable for the Insufficiency and shall satisfy its related liability by either replacing the Indemnified Volume (as defined in (f) 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 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/Mmbtu) and the amount of trans- portation revenues previously credited by Songas to the electricity utility, TANESCO, for the gas volumes. (f) The “Indemnified Volume” means the lesser of the total volume of Additional Gas sales supplied from the Discovery Blocks prior to an Insuf- ficiency and the Insufficiency Volume. “Insuf- ficiency 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 incorpo- rated) 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. (c) No sales of Additional Gas may be made from the Discovery Blocks if in Orca Exploration’s reasonable judgment 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 acceptable 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 (e) below). Songas has written to Orca Exploration confirming that, subject to certain conditions, security will not be required for the supply of Additional Gas to the Ubungo power plant, for the supply of up to 15 Mmscf/d for a period of five years for additional power generation and up to 10 Mmscf/d for the industrial sector. As the current emergency power generation operating in the country could take demand above 15 Mmscf/d for power generation, Songas has confirmed that the Company may sell 17 Mmscf/d for power generation over the next year without the need for security. The Company is looking to agree a security mechanism with Songas that provides clear guidance as to how Songas will operate their rights to security. It is anticipated that, under certain circumstances, the Company and TPDC may have to allocate a proportion of the Additional Gas revenues to an escrow account, in the event of a forecast Protected Gas insufficiency. (d) By 31 July 2009, the Government of Tanzania (“GoT”) can request Orca Exploration 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 consumption 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. 23 management’s discussion & analysis accESS and dEVElOPMEnt OF InFRaStRuctuRE (g) The Company is able to utilise the Songas in- frastructure including the gas processing plant and main pipeline to Dar es Salaam. Access to the pipeline and gas processing plant is open and can be utilised by any third party who wishes to process or transport gas. Songas is 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 (h) 75% of the gross revenues less processing and 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 Discovery Blocks 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 (“MEM”) 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 their profit share percentage increases by the Specified Proportion for that development program. TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development by contributing 20% of the costs of the future wells including SS-10 in return for a 20% increase in the profit share percentage for the production emanating from these wells. The implications and workings of the ‘back in’ are still to be discussed in detail with TPDC. For the purpose of the reserves certification, it has been assumed that they will ‘back in’ for 20% and this is reflected in the Company’s net reserve position. However, the financial statements have not taken account of any reimbursement for the SS-10 capital expenditure, pending the finalisation of the terms of the ‘back in’. (i) 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 US$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 formally agreed, but the Company expects it to be 17.5% of the Songas Outlet Price. Songas has submitted a tariff application to the regulator, EWUrA, to cover the financing and operating costs of the third and fourth train which is forecast to increase the gas processing capacity to 140 Mmscf/d. The Songas application assumes that the industrial customers continue to pay 17.5% of the Songas Outlet Price, but that sales to the power sector will initially attract a higher percentage tariff. The Company is negotiating the long term gas price to the power sector based on the price of gas at the Wellhead. As a consequence, the Company is not impacted by the changes to the tariff paid to Songas in respect of sales to the power sector. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O (j) The cost of maintaining the wells and flowlines (l) Additional Profits Tax is payable where the is split between the Protected Gas and Additional Gas users in proportion 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. (k) 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 of AdditionAl gA s Mmscf/d 0 - 20 CumulAtive sAles of AdditionAl gAs Bcf 0 – 125 >20 <=30 >125<=250 >30 <=40 >250<=375 >40 <=50 >375<=500 >50 >500 tpdC’s shARe of pRofit gAs CompAnY’s shARe of pRofit gAs % 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 develop- ment program, their profit share percentage increases by the Specified Proportion (for that development program) with a corresponding decrease in the Company’s percentage share of Profit Gas. 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. 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 an annual return of 25% plus the percentage change in the United States Industrial Goods Producer Price Index (“PPI”); and (ii) the maximum Additional Profits Tax rate is 55% of the Company’s profit share when costs have been recovered with an annual return of 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 negative impact on the project economics if only limited capital expenditure is incurred. OPERatORShIP (m) The Company is appointed to develop, produce and process Protected Gas and operate and maintain the gas production 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. (n) In the event of loss arising from Songas’ failure to perform and the loss is not fully compensated by Songas, Orca Exploration, CDC or insurance coverage, then Orca Exploration 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. 25 management’s discussion & analysis consolidation The companies that are being consolidated are: CompAnY inCoRpoRAted Orca Exploration Group Inc. (formerly EastCoast Energy Corporation) PAE PanAfrican Energy Corporation PanAfrican Energy Tanzania Limited British Virgin Islands Mauritius Jersey Orca Exploration Uganda Inc British Virgin Islands Orca Exploration Uganda (Holding) Inc British Virgin Islands Orca Exploration (Ventures) Inc British Virgin Islands results for the year ended 31 December 2007 OPERatInG VOluMES The sales volumes for the year were 7,731 Mmscf or 21.2 Mmscf/d. This represents an overall increase of 59% over the previous year. The Company’s sales volumes were split between the industrial and power sectors as follows: Gross sales volume (Mmscf) Industrial sector Power sector total volumes Gross daily sales volume (Mmscf/d) Industrial sector Power sector total daily sales volume (Mmscf/d) 2007 2006 1,504 6,227 7,731 4.1 17.1 21.2 1,466 3,371 4,837 4.0 9.2 13.3 Industrial sector The level of sales to industrial companies remained static during the year, with the addition of one new industrial customer at the end of the second quarter. By the end of 2007 the Company had seventeen industrial customers. Industrial sales for the year averaged 4.1 Mmscf/d (2006: 4.0 Mmscf/d). The level of industrial sales peaked in September 2007 with sales of 5.1 Mmscf/d. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O Power sector Sales to the power sector for the year were 6,227 Mmscf or 17.1 Mmscf/d (2006: 3,371 Mmscf or 9.2 Mmscf/d). The 85% increase was a direct consequence of TANESCO and the government of Tanzania entering into contracts with Aggreko Plc (“Aggreko”) and Dowans Tanzania Limited (“Dowans”) for the installation and supply of approx- imately 168 MWs of gas-fired emergency power plants that commenced operations in Q4 2006. The emergency power units installed by Aggreko and Dowans consumed 2,735 Mmscf and 1,142 Mmscf of Additional Gas respectively during the year. The increased sales of Additional Gas to the emergency power units was offset by a 30% fall in the volume of Additional Gas consumed by the Ubungo power plant from 3,371 Mmscf in 2006 to 2,350 Mmscf in 2007. This fall was a consequence of the significant rains in the first half of 2007 that enabled Tanzania to generate the majority of its electricity from the 561 MWs of hydro generation. cOMMOdIty PRIcES US$/mcf Average sales price: Industrial sector Power sector Weighted average price 2007 2006 9.31 2.19 3.58 8.22 1.90 3.81 Industrial sector The price of gas for the industrial sector continued to be set at a discount to the price of Heavy Fuel Oil (“HFO”) in Dar es Salaam. This resulted in average gas prices of US$9.31/mcf (2006: US$8.22/mcf) during the year. The higher gas price achieved for the industrial sector is a consequence of the fluctuation of world oil prices and the discount agreed with the customers. The monthly Additional Gas price sold to industrial customers in Dar es Salaam in 2007 ranged from US$7.72/mcf in January 2007 to US$12.21/mcf in December 2007. Power sector The price of gas to the power sector during the year averaged US$2.19/mcf (2006: US$1.90/mcf). The Interim Agreement for the sale of Additional Gas to the Ubungo power plant provided for different gas prices, depending on the average availability of the six turbines, from the minimum of US$0.67/Mmbtu (US$0.62/mcf) to the maximum of US$2.32/Mmbtu (US$2.15/mcf). The maximum price US$2.32/Mmbtu was achieved during the year as the availability of the six turbines remained above the highest threshold throughout the period. The supply to the Aggreko 48 MWs emergency unit was at US$2.39/Mmbtu (US$2.22/mcf) during the year. The Company is concluding negotiations with TANESCO, the Ministry of Energy (“MEM”) and EWUrA, the energy utility regulator, over the long term price to be applied to gas sold to power sector. This is discussed in the Operations review. OPERatInG REVEnuE Under the terms of the PSA with TPDC, Orca Exploration is responsible for invoicing, collecting and allocating the revenue from Additional Gas sales. Orca Exploration is able to recover all costs incurred on the exploration, development and operations of the project out of 75% of the Net revenues (“Cost Gas”). Any costs not recovered in any period are carried forward to be recovered out of future revenues. During the last six months of 2007, Additional Gas sales volumes were in excess of 20 Mmscf/d for each quarter. Consequently, the revenue less cost recovery share of revenue (“Profit Gas”) increased to 30% from 25% in the first six months of the year. Orca Exploration had recoverable costs throughout 2006 and 2007 to date and accordingly was allocated 81.25% (2006: 81.2%) of the Net revenues as follows: (Figures in US$’000) Gross sales revenue Gross tariff for processing plant and pipeline infrastructure Gross revenue after tariff Analysed as to: Company Cost Gas Company Profit Gas Company operating revenue TPDC Profit Gas 2007 27,674 (4,493) 23,181 17,393 1,630 19,023 4,158 23,181 2006 18,445 (2,889) 15,556 11,665 973 12,638 2,918 15,556 The Company’s total revenues for the year amounted to US$18,777 after adjusting the Company’s operating revenue of US$19,023,000 by: i) US$78,000 for income tax. The Company is liable for income tax in Tanzania, but the income tax is recoverable out of TPDC’s Profit Gas when the tax is payable. To account for this, revenue is adjusted to reflect the current income tax charge or loss. ii) US$324,000 for the deferred effect of additional profits tax. This tax is considered a royalty and is netted against revenue. revenue per the income statements may be reconciled to the operating revenue as follows: ((Figures in US$’000) Industrial sector Power sector Gross sales revenue Processing and transportation tariff TPDC share of revenue Company operating revenue Additional Profits Tax Current income tax adjustment Revenue 2007 14,010 13,664 27,674 (4,493) (4,158) 19,023 (324) 78 18,777 2006 12,048 6,397 18,445 (2,889) (2,918) 12,638 (183) 1,373 13,828 27 management’s discussion & analysis Transportation Tariff Under the terms of the project agreements, the tariff paid for transporting the gas is calculated as 17.5% of the price of gas at the Songas main pipeline in Dar es Salaam (“Songas Outlet Price”) for the first 65 Mmscf/d of pipeline capacity. In calculating the Songas Outlet Price for the industrial customers, an amount of US$1.36/mcf (2006: US$1.12/mcf) (“ringmain Tariff”) has been deducted from the achieved industrial sales price of US$9.58/mcf (2006: US$8.61/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 and operating the connections from the Songas main pipeline to the industrial customers. No deduction has been made for sales to the power sector since the gas is not transported through the Company’s own infrastructure. It is envisaged that Songas will finance the construc- tion of a third and a fourth gas processing train to ensure there will be sufficient infrastructure capacity to meet the peak gas demand for the 310 MWs of gas fired generation plants that TANESCO has installed in Dar es Salaam. The new trains are not expected to be operational until 2009, but Orca has proposed a temporary solution to increase the capacity of the gas processing plants through a re-rating of the existing facilities and the introduction of a bypass. If Songas approve the proposal the gas processing capacity could be increased by 20 – 35 Mmscf/d during 2008. PROductIOn and dIStRIbutIOn ExPEnSES The direct cost of maintaining the ring main distribu- tion pipeline and pressure reduction station (security, insurance and personnel) is forecast to be approxi- mately US$0.5 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 year was US$989,000 (2006: US$627,000) of which US$403,000 (2006: US$213,000) was allocated for the Additional Gas. Other operating costs include an apportionment of the annual PSA licence costs and some costs associated with the evaluation of the reserves. These costs are summarised in the table below: (Figures in US$’000) Ring main distribution pipeline Share of well maintenance Other field and operating costs Production and distribution expenses Depletion 2007 484 403 306 1,193 4,476 2006 336 213 244 793 2,027 OPERatInG nEtback The operating netback per mcf before general and administrative costs, overheads, tax and additional profits tax may be analysed as follows: (Amounts in US$/mcf) Gas price – industrial Gas price – power weighted average price for gas Tariff (after allowance for the Ring main Tariff) TPDC Profit Gas net selling price Well maintenance and other operating costs Ring main distribution pipeline Operating netback 2007 9.31 2.19 3.58 (0.58) (0.54) 2.46 (0.09) (0.06) 2.31 2006 8.22 1.90 3.81 (0.60) (0.60) 2.61 (0.09) (0.07) 2.45 Operating netback was lower in 2007 as the weighted average price decreased as a consequence of the change in the sales mix, between the industrial and power sectors. Due to the relatively fixed nature of production and distribution expenses the higher sales volumes attained in 2007 have reduced the well maintenance and other operating costs on a US$/ mcf basis. The operating netback continues to benefit from the recovery of 75% of the Net revenues as Cost Gas. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O GEnERal and adMInIStRatIVE ExPEnSES The general and administrative expenses (“G&A”) may be analysed as follows: Employee costs There has been an increase in the staff pay rates and their accrued bonuses. Average number of staff remained the same at 15 (2006: 15). (Figures in US$’000) Employee costs Stock based compensation Consultants Travel & accommodation Communications Office Insurance Auditing & taxation Depreciation Marketing costs including legal fees Reporting, regulatory and corporate finance Directors’ fees net general and administrative expenses 2007 2,059 2,257 2,037 656 85 598 176 152 154 2006 1,567 868 1,010 435 128 456 146 96 102 2,224 1,671 229 81 157 88 10,708 6,724 During the year US$1.2 million of general administra- tive expenses (2006 US$ nil) were capitalized. These costs include consultancy fees and the proportionate share of options, treasury stock and stock apprecia- tion rights for the personnel directly responsible for the development of the option agreement and the continuing management of the project in Exploration Area 5 in Uganda (“EA5”). G&A averaged approximately US$0.89 million per month (2006: US$0.56 million). G&A per mcf was US$1.39/mcf (2006: US$1.39/mcf). Whilst a large proportion of G&A is relatively fixed in nature and therefore should decline on an mcf basis as volumes increase, significant costs are being incurred in the negotiation of the long term power contracts and the establishment of a business development department. This has led to the G&A costs being relatively high per mcf. It is expected that the level of G&A will fall once the long term power contracts are signed. Stock based compensation During the year a total of 1,185,000 new stock options were issued to certain directors, officers and employees of the Company. The fair value of these options have been determined using the Black-Scholes option pricing model. A total charge of US$0.8 million was recorded in relation to the new options issued of which US$0.1 million has been capitalized during the year. A credit of US$0.1 million was recognized in 2007 for the cancellation of options that were granted in September 2006. The current monthly charge for vesting stock options is US$0.1 million. A total of 690,000 uncapped stock-appreciation rights were issued in the year. These stock appreciation rights, are revalued at each reporting date using the Black-Scholes option pricing model. A total charge of US$0.7 million was recorded for the year in respect of the newly issued rights of which US$0.3 million has been capitalized. 400,000 stock appreciation rights that were issued in 2006 were fully expensed by the end of 2007 with a charge of US$0.75 million being recorded in the year. These stock appreciation rights were capped at a maximum payout of Cdn$3 per option. In April 2007, 200,000 Class B shares were awarded to a newly appointed officer. These shares are held in escrow and vest to the officer in three equal install- ments starting 7 April 2007. At the time the shares were awarded they had a market value of US$1.6 million (Cdn$1.7 million). A total charge of US$0.9 million has been recognized during 2007 of which US$0.4 million has been capitalized. Total charges for Class B shares, stock options and stock appreciation rights may be summarized as follows: (Figures in US$’000) Stock options Stock appreciation rights Treasury stock Capitalized 2007 691 1,475 930 3,096 (839) 2,257 2006 418 450 – 868 – 868 29 management’s discussion & analysis Consultancy costs There has been a two fold increase in the number of consultants contracted by the Company during 2007. The majority of the consultants are supporting the new business development and exploration initiatives of the Company. Travel and accommodation The increase in travel and accommodation costs is primarily due to the increase in the number of business trips to Tanzania by Company officials and other marketing and legal professionals for the negotiation of the power and related contracts. Marketing costs including legal fees These costs include marketing costs, legal, corporate promotion and cost of training Government officials in accordance with the terms of the PSA. During the year, higher costs were experienced in negotiating power and other contracts with Songas, and TANESCO and in preparing pricing applications for the regulatory authority, EWUrA. FInancInG IncOME/(chaRGES) Interest income increased to US$0.6 million (2006:US$0.1 million). The increase is due to interest associated with the receipt of U$30.4 million from the private placement of 2.5 million Class B shares at Cdn$13.80/share in July 2007 and US$18.1 million from a rights issue on 29 December 2006. Of the total gain on foreign exchange, US$0.4 million occurred as a result of the conversion of the funds received from the private placement. The movement in finance income and charges is summarized in the table below: (Figures in US$’000) Finance income Interest income Foreign exchange gain Finance charges Foreign exchange loss Net Financing income/(charges) 2007 2006 628 832 1,460 (85) 1,375 61 11 72 (95) (23) taxatIOn Income Tax Under the terms of the PSA with TPDC, the Company is liable for income tax in Tanzania at the corporate tax rate of 30%.However, where income tax is payable, this is recovered from TPDC by deducting an amount from TPDC’s profit share. This is reflected in the accounts by adjusting the Company’s revenue by the appropriate amount. As at 31 December 2007, there were temporary differences between the carrying value of the assets and liabilities for financial reporting purposes and the amounts used for taxation purposes under the Income Tax Act 2004. Applying the 30% Tanzanian tax rate, the Company has recognised a deferred tax liability of US$3.2 million which represents an additional charge of US$2.0 million for the year. This tax has no impact on cash flow until it becomes a current income tax at which point the tax is paid to the Commissioner of Taxes and recovered from TPDC’s share of Profit Gas. Additional Profits 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 (“APT”) is payable. The Company provides for APT by forecasting the total APT payable as a proportion of the forecast Profit Gas over the term of PSA licence. The effective APT rate has been calculated to be 20%. Accordingly, US$0.3 million (2006: US$0.2 million) has been netted off revenue for the year ended 31 December 2007. As at 31 December 2007, the Company had US$41.7 million (2006: US$14.6 million) of accrued costs that are recoverable out of 75% of the future Net revenues. Management does not anticipate that any APT will be payable in 2008, as the forecast revenues will not be sufficient to cover the un-recovered costs brought forward as inflated by 25% plus the percentage change in the United States Industrial Goods Producer Price Index and the forecast expen- ditures for 2008. The actual APT that will be paid is dependent on the achieved value of the Additional Gas sales and the quantum and timing of the operating costs and capital expenditure programme. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O The APT can have a significant negative 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 accelerates 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. dEPlEtIOn and dEPREcIatIOn 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 2007, the proven reserves as evaluated by the independent reservoir engineers, McDaniel & Associates Consultants Ltd. (“McDaniel”) were 308.6 Bcf after TPDC ‘back in’ on a life of licence basis. This leads to an average depletion charge of US$0.58/mcf for the year. Non-Natural Gas Properties are depreciated as follows: Leasehold improvements Computer equipment Vehicles Fixtures and fittings Over remaining life of the lease 3 years 3 years 3 years caRRyInG ValuE OF aSSEtS Capitalized costs are periodically assessed to determine whether it is likely that such costs will be recovered in the future. To the extent that these capitalized costs are unlikely to be recovered in the future, they are written off and charged to earnings. A total of US$6.9 million has been recorded in 2007 for the securing of an option agreement with Tower resources plc and the initial evaluation of Exploration Area 5 (“EA 5”) in Uganda. 300 kilometers of 2-D seismic was shot during Q4 2007 and Q1 2008. Processing of this seismic data has now commenced and is due to be completed in the coming weeks. The initial evaluation of the data has indicated that a number of potential structures exist. Technical analysis of the data is still on going with particular attention being paid to the relationship of these structures and any potential hydrocarbon maturation that could have occurred within the basin. As yet it is too early to indicate the level of prospectivity. However initial analysis indicates that the block is potentially more risky than initially thought. As the processing of the seismic data continues, the details of the prospectivity will become clearer. The Company has until June 2008 to determine whether to commit to drill two exploration wells to secure a 50% interest in EA 5. FundS GEnERatEd by OPERatIOnS Funds from operations before working capital changes were US$8.7 million for the year ended 31 December 2007 (2006: US$6.0 million). (Figures in US$’000) Profit after taxation adjustments (i) Funds from operations before working capital changes Working capital adjustments net cash flows from operating activities Net cash flows used in investing activities Net cash flows from financing activities 2007 1,745 6,951 8,696 2,071 2006 2,577 3,392 5,969 (873) 10,767 5,096 (45,633) (5,848) 30,703 18,232 net (decrease) / increase in cash and cash equivalents (4,163) 17,480 (i) See consolidated statement of cash flows The decrease in cash and cash equivalents is a consequence of the re-investment of the funds generated from operation together with a proportion of the funds raised from the private placement in July in the continued development of the Songo Songo field (including the remedial work on SS-9 and the drilling of SS-10) and the associated infrastructure. Accordingly the overall cash balances decreased by 20% over 2006 with the receipt of US$30.4 million from the private placement being offset by the high level of investment. The increase in funds generated by operations over 2006 is primarily the result of the 85% increase in the volume of Additional Gas sales to the power sector. 31 management’s discussion & analysis caPItal ExPEndItuRES Capital expenditures amounted to US$53.7 million during the year (2006: US$6.0 million). The capital expenditures may be analysed as follows: A total of US$1.3 million was incurred during the year on geological, geophysical and seismic studies in order to increase the level of understanding of the reservoir. In 2007 the Company signed an option agreement with Tower resources Plc (“Tower”). Under the terms of the agreement, the Company is committed to paying for 83.33% of the costs of a 300 kilometer 2-D seismic programme up to a gross cap of approximately US$6.4 million, together with certain historical costs. In the event that the costs are in excess of the cap, the Company will contribute 50% towards the excess. The Company has 40 days from the receipt of the interpreted seismic information to exercise its option to earn a 50% working interest, in return for funding 83.33% of the cost of two wells. A total of US$6.9 million has been incurred on the Ugandan project during 2007. This includes US$0.6 million on historical costs incurred by Tower, US$5.1 million on cost associated with the seismic survey and US$1.2 million of capitalized general administrative costs. Pipelines and infrastructure – US$2.3 million The Company installed a second pressure reduction station and completed an 8 kilometer extension to the existing low pressure distribution system at a cost of US$2.1 million, expanding the total network to some 36 kilometers. These additions to the network have increased the security of delivery to the existing industrial customers as well as allowing for future growth. A further US$0.2 million was incurred on connections to customers in 2007. The Company forecasts that at least five new industrial customers will take delivery of Additional Gas in 2008. (Figures in US$’000) 2007 2006 Geological and geophysical and well drilling Pipelines and infrastructure Power development Other equipment 51,129 2,267 146 175 4,460 975 573 35 53,717 6,043 Geological and geophysical and well drilling – US$51.1 million A total of US$51.1 million was incurred in 2007 on the Company’s activities in Tanzania and Uganda. A total of US$2.4 million was spent on the completion of remedial work on the SS-9 well to remove two pressure gauges and some 5,000 feet of wireline that were left down hole during well tests undertaken in 1997. As a consequence of this inter- vention, the gas deliverability of SS-9 was increased by 30 Mmscf/d to a maximum of 50 Mmscf/d. The SS-10 development well was completed in 8 November 2007 having been spudded on the 28 April 2007. The well was suspended in June for three months whilst essential repairs were undertaken on the Caroil-6 rig following several mechanical failures. A total of US$36.1 million was spent on the well in 2007. The drilling of the well provided the Company with a comprehensive suite of logs on the field for the first time in 25 years. This has enabled the Company to book increased reserves as well as increasing the deliverability of the field by over 50 Mmscf/d. A further U$4.4 million was incurred on the acquisition of well and drilling inventory in the event that a second well was required. This will either be used on a future drilling programme (e.g Songo Songo West) or will be sold. Currently the cost of this inventory is included within property, plant and equipment. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O wORkInG caPItal Working capital as at 31 December 2007 was US$7.3 million (31 December 2006: US$20.4 million) and may be analysed as follows: (Figures in US$’000) Cash and cash equivalents Trade and other receivables Trade and other payables working capital 2007 16,515 8,236 24,751 17,452 7,299 2006 20,678 4,275 24,953 4,523 20,430 The decrease in working capital by US$13.1 million during 2007 is due to the increase in trade and other payables balances relating to capital expenditure primarily on SS-10 as explained above. The majority of the cash is held in US and Cdn dollars in Mauritius and in Tanzanian Shillings in Tanzania bank accounts. There are no restrictions in Tanzania for converting Tanzania Shillings into US dollars. Any surplus cash is held in a fixed rate interest earning deposit account. Trade and other receivables at 31 December 2007 are represented by US$7.3 million of trade receivables (2006: US$3.4 million), US$0.8 million of prepayments (2006: US$0.2 million), US$0.1 of other receivables (2006: US$0.7 million). 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 2007, US$3.3 million (2006: US$1.9 million) was due from industrial customers and of this, 82% was received before the end of Q1 2008. The balance of US$4.0 million (2006: US$1.5 million) is made up of an amount due from the two power customers, TANESCO and Songas. The contracts with Songas and TANESCO accounted for 49% (2006: 35%) of the Company’s operating revenue in 2007. Songas’ financial security is, in turn, heavily reliant on the payment of capacity and energy charges by TANESCO. TANESCO is dependent on the Government of Tanzania for some of its funding. Whilst some payments have been delayed, the Company collected all amounts from Songas. US$0.2 million remains outstanding from TANESCO in respect of the amounts due at 31 December 2007. Of the trade and other payables US$7.7 million related to capital expenditure (2006: US$0.8 million). Trade and other payables also includes an amount of US$1.0 million in relation to 400,000 stock appreciation rights that were introduced in 2006 and US$0.7 million in relation to new stock appreciation rights that were issued in 2007. In the third quarter of 2007, the Company opened a bank guarantee of US$15 million in favour of Tower as part its obligations to acquire a 50% interest in Exploration Area 5. This guarantee is reduced by any payments made to Tower. As at 31 December 2007 the guarantee was standing at US$9.4 million. The guarantee is supported by existing cash balances deposited at the bank. OutStandInG ShaRE caPItal There were 29.6 million shares outstanding at 31 December 2007 which may be analysed as follows: Number of shares (‘000) Shares outstanding Class A shares Class B shares convertible securities Options 2007 2006 1,751 27,863 29,614 1,751 25,023 26,774 2,847 2,022 Fully diluted Class A and Class B shares 32,461 28,796 weighted average Class A and Class B shares convertible securities Options 28,259 23,395 1,543 1,514 Weighted average diluted Class A and Class B shares 29,802 24,909 33 management’s discussion & analysis The movement in Class B shares during the year is analysed in the table below: as at 31 december 2006 Issued Stock options exercised Normal course issuer bid as at 31 december 2007 numbeR of shARes ClAss b shAR es (‘000) 25,023 2,700 160 (20) 27,863 The Company issued 2,500,000 Class B shares at Cdn$13.80 per share following a fully subscribed private placement that closed in July 2007. Net proceeds of US$30.4 million were raised for the Company. A large proportion of the funds were used for the completion of the SS-10 well in Tanzania and for the funding of a new venture in Uganda. In April 2007 the Company issued 200,000 Class B shares to a newly appointed officer. These shares are held in escrow by the Company and vest to the officer in three equal annual installments starting 7 April 2007. In January 2007, the Company initiated a normal course issuer bid to purchase up to 1,085,379 Class B shares between 31 January 2007 and 31 December 2007, subject to a maximum usage of US$2.2 million of funds. A total of 19,800 Class B shares were purchased during the bid period. Convertible securities The stock option plan provides for the granting of stock options to directors, officers, employees and consultants. The exercise price of each stock option is determined as the closing market price of the common shares on the day prior to the day of grant. Each stock option granted permits the holder to purchase one common share at the stated exercise price. In accordance with IFrS2, the Company records a charge to the profit and loss account using the Black-Scholes fair valuation option pricing model. The valuation is dependent on a number of estimates, including the risk free interest rate, the level of stock volatility, together with an estimate of the level of forfeiture. The level of stock volatility is calculated with reference to the historic closing share price at the date of issue. During 2007 a total of 1,185,000 stock options were issued under the plan. All these options have a term of 5 years and vest in three equal instalments commencing on the anniversary of the grant date. The details of which are analysed in the table below: dAte of gRAnt 14-Jan 24-Apr 06-Jun 01-Oct 08-Nov options (thousands) exeRCise pRiCe Cdn$ RisK fRee RAte shARe volAtilitY foRfeituRe 300 150 510 75 150 8.70 3.75% 10.00 3.75% 13.55 3.75% 11.81 3.96% 12.00 3.96% 60% 51% 53% 41% 42% 33% 33% 33% 33% 33% The movement in stock options for the year is analysed in the table below: Number of options (‘000) as at 31 december 2006 Issued Exercised Forfeited as at 31 december 2007 options 2,022 1,185 (160) (200) 2,847 t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O cOntRactual OblIGatIOnS and cOMMIttEd caPItal InVEStMEnt Capital Investment In 2007 the Company signed an option agreement with Tower resources Plc (“Tower”). Under the terms of the agreement, the Company committed to pay for 83.33% of the costs of a 300 kilometer 2-D seismic programme up to a gross cap of approximately US$6.4 million, together with certain historical costs. The Company has 40 days from the receipt of the interpreted seismic information to exercise its option to earn a 50% working interest in Exploration Area 5 (“EA 5”) in return for funding 83.33% of the cost of two exploration wells. The cost of the wells is capped at between US$10 million and US$15 million depending on whether testing of the wells is required. In the event that the costs are higher than the caps for the seismic or the cost of the two wells, the Company will contribute 50% towards the excess. The Company provided a bank guarantee of US$15.0 million to cover its obligations under the option agreement which is reduced by any actual payments made to Tower. At the end of the year the bank guarantee was US$9.4 million of which a further US$1.5 million is anticipated to be required in 2008 to complete the seismic programme. 300 kilometers of 2-D seismic was shot during Q4 2007 and Q1 2008. Processing of this seismic data has now commenced, and is due to be completed in the coming weeks. The initial evaluation of the data has indicated that a number of potential structures exist. Technical analysis is still on going with particular attention being paid to the relationship of these structures and any potential hydrocarbon maturation that could have occurred within the basin. As yet it is too early to indicate the level of prospectivity. However initial analysis indicates that the block is potentially more risky than initially thought. As the processing of the seismic data continues, the details of the prospectiv- ity will become clearer. The Company has until June 2008 to determine whether to commit to drill two exploration wells to secure a 50% interest in EA 5. Management forecasts that the Company will be able to meet its 2008 capital expenditure programme through the use of existing cash balances, self-gener- ated cash flows and a US$5.0 million overdraft facility that is currently being put in place. The Company currently has no bank borrowings and there is scope for utilising debt funding once the longer term contracts for the supply of gas to the power sector are in place. Shortfall Gas Under the terms of the contracts with Kioo Ltd., Tanzania Breweries Ltd. 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 a total of US$1.1 million for these three contracts and the remedy is payable as a credit against future monthly invoices. Protected Gas 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/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 (15.1 Bcf as at 31 December 2007). The Company is actively monitoring the reservoir and does not anticipate that a liability will occur in this respect. However, Songas has the right to request reasonable security on all Additional Gas sales. Songas has written to Orca Exploration confirming that, subject to certain conditions, security will not be required for the supply of Additional Gas to the Ubungo power plant, for the supply of up to 15 Mmscf/d for additional power generation and up to 10 Mmscf/d for the industrial sector, for a period of five years. As the current emergency power generation operating in the country could take demand above 15 Mmscf/d for power generation, Songas has confirmed that the Company may sell 17 Mmscf/d for power generation over the next year without the need for security. 35 management’s discussion & analysis The Company is looking to agree a security mechanism with Songas that provides clear guidance as to how Songas will operate their rights to security. It is anticipated that in the long term, the Company and TPDC may have to allocate a proportion of the Additional Gas revenues to an escrow account, in the event of a forecast Protected Gas insufficiency. Back in TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development by contrib- uting 20% of the costs of the future wells including SS-10 in return for a 20% increase in the profit share percentage for the production emanating from these wells. The implications and workings of the ‘back in’ are still to be discussed in detail with TPDC. For the purpose of the reserves certification, it has been assumed that they will ‘back in’ for 20% and this is reflected in the Company’s net reserve position. However, the financial statements do not take account of any reimbursement for the SS-10 capital expenditure, pending the finalisation of the terms of the ‘back in’. Operating leases The Company has entered into a five year rental agreement that expires on 30 November 2012 at a cost of approximately US$102,000 per annum for the use of offices in Dar es Salaam. OFF-balancE ShEEt tRanSactIOnS As at 31 December 2007, the Company had no off-balance sheet arrangements. RElatEd PaRty tRanSactIOnS One of the non executive Directors is a partner at a law firm. During the year, the Company incurred US$156,000 to this firm for services provided on fund raising and other legal services. The transactions with this related party was made at the exchange amount. POSt balancE ShEEt EVEnt 300 kilometers of 2-D seismic was shot in Uganda area EA 5 during Q4 2007 and Q1 2008. Processing of this seismic data has now commenced and is due to be completed in the coming weeks. The initial evaluation of the data has indicated that a number of potential structures exist. Technical analysis of the data is still on going with particular attention being paid to the relationship of these structures and any potential hydrocarbon maturation that could have occurred within the basin. As yet it is too early to indicate the level of prospectivity. However initial analysis indicates that the block is potentially more risky than initially thought. As the processing of the seismic data continues the details of the prospectivity will become clearer. The Company has until June 2008 to determine whether to commit to drill two exploration wells to secure a 50% interest in EA 5. dISclOSuRE cOntROlS and PROcEduRES Disclosure controls and procedures are defined Under Multilateral Instrument 52-109 – Certification of Disclosure Controls in Issuers’ Annual and Interim Filings (“MI 52-109”) as “…controls and other procedures of an issuer that are designed to provide reasonable assurance that information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under provincial and territorial securities legislation is recorded, processed, summarized and reported within the time periods specified in the provincial and territorial securities legislation and include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed or submitted under provincial and territorial securities legislation is accumulated and communicated to the issuer’s management, including its chief executive officers and chief financial officers (or persons who perform similar functions to a chief executive officer or a chief financial officer), as appropriate to allow timely decisions regarding required disclosure.” The Company has conducted a review and evaluation of its disclosure controls and procedures, with the conclusion that as at 31 December 2007 the Company has an effective system of disclosure controls and procedures as defined under MI 52-109. In reaching this conclusion, the Company recognizes that two key factors must be and are present: t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O (a) the Company is dependant upon its advisors and (a) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer; (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the issuer’s GAAP, and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the issuer; and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer’s assets that could have a material effect on the annual financial statements or interim financial statements.” The Company has conducted a review and evaluation of its internal controls over financial reporting, with the conclusion that as at 31 December 2007 the Company’s system of internal controls over financial reporting, as defined under MI 52-109, is sufficiently designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. During the review of the design of the Company’s control system over financial reporting it was noted that, due to the limited number of staff at Orca Exploration, it is not feasible to achieve complete segregation of incompati- ble duties. The limited number of staff may also result in identifying weaknesses in accounting for complex and or/non routine transactions due to a lack of technical resources within the Company. While management of Orca Exploration has put in place certain procedures to mitigate the risk of material misstatement in the Company’s financial reporting, a system of internal controls can provide only reasonable, not absolute, assurance that the objectives of the control system are met, no matter how well conceived or operated. consultants (principally its legal counsels) to assist in recognizing, interpreting, understanding and complying with the various securities regulations disclosure requirements; and (b) an active Board of Directors and management with open lines of communication. The Company has a small staff with varying degrees of knowledge concerning the various regulatory disclosure requirements. In many circumstances, the various regulatory requirements are relatively new, subject to interpretation, and complex. The Company is not of a sufficient size to justify a separate department or one or more staff member specialists in this area. Therefore the Company must rely upon its advisors/consultants to assist it and as such they form part of the disclosure controls and procedures. Proper disclosure necessitates that one not only be aware of the pertinent disclosure requirements, but one is also sufficiently involved in the affairs of the Company and/or receives the communication of information to assess any necessary disclosure requirements. Accordingly, it is essential that there be proper communication among those people who manage and govern the affairs of the Company, this being the Board of Directors and senior management. The Company believes this communication exists. While the Company believes it has adequate disclosure controls and procedures in place, lapses in the disclosure controls and procedures could occur and/or mistakes could happen. Should such occur, the Company intends to take whatever steps necessary to minimize the consequences thereof. IntERnal cOntROlS OVER FInancIal REPORtInG Internal controls over financial reporting are defined in the Multilateral Instrument 52-109 as “… a process designed by, or under the supervision of, the issuer’s chief executive officers and chief financial officers, or persons performing similar functions, and effected by the issuer’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP and includes those policies and procedures that: 37 management’s discussion & analysis Summary Quarterly results The following is a summary of the results for the Company for the last eight quarters: (Figures in US$’000 except where otherwise stated) Q4 Q3 Q2 2007 Q1 Q4 Q3 Q2 2006 Q1 Financial Revenue Profit/(loss) after taxation Operating netback (US$/mcf) Working capital Shareholders’ equity Profit/(loss) per share – basic and diluted (US$) capital expenditures Geological and geophysical and well drilling Pipeline and infrastructure Power development Other equipment Operating Additional Gas sold – industrial (Mmscf) Additional Gas sold – power (Mmscf) Average price per mcf – industrial (US$) Average price per mcf – power (US$) 5,562 284 2.27 6,363 1,942 2.30 3,021 3,831 (609) 2.79 128 2.03 4,722 1,025 2.17 3,835 3,198 2,073 809 2.88 660 2.71 83 2.05 7,299 20,939 (3,050) 10,570 20,430 3,298 2,448 2,118 71,544 70,996 38,291 37,983 37,889 18,676 17,715 16,928 0.01 0.07 (0.02) – 0.04 0.03 0.03 – 16,323 10,426 13,723 10,657 2,748 469 4 – 364 2,152 11.08 2.19 314 7 108 442 1,974 9.58 2.19 1,205 26 35 397 745 8.61 2.17 279 109 32 301 1,356 7.70 2.19 130 531 – 398 1,206 7.64 1.95 473 234 42 – 491 744 8.63 1.69 726 305 – 3 347 739 8.69 2.13 514 305 – 32 230 682 7.63 1.79 The principal developments in Q4 were as follows: • Achieved a quarterly sales volume of 2,516 Mmscf or 27.3 Mmscf/d which represent the best quarter since sales began in 2004. • Completed the SS-10 development well. • Completed the installation of a second pressure reduction station and an 8 kilometer extension to the existing low pressure distribution system. • Commenced a 300 kilometer seismic programme in Exploration Area 5 in Uganda in association with Tower. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O VaRIancE analySIS bEtwEEn quaRtERS Working capital Revenue The Company commenced the sale of Additional Gas to industrial customers in September 2004. Since then, the volumes of Additional Gas sold to the industrial sector have increased from an average of 1.2 Mmscf/d in Q4 2004 to 4.0 Mmscf/d in Q4 2007 (Q4 2006: 4.3 Mmscf/d), peaking in Q3 2006 at 5.3 Mmscf/d. Industrial sales peak in third quarters of each year as textile customers take advantage of low cotton prices during the harvest season. The average price to the industrial sector has varied in line with the price of crude oil as the gas is priced at a 20% - 25% discount to the price of Heavy Fuel Oil in Dar es Salaam. The average price ranged from US$5.23/mcf in Q1 2005 to US$11.08/mcf in Q4 2007. The sale of Additional Gas to the power sector commenced in Q3 2005 and this contributed towards a significant step increase in revenue from that quarter. In Q4 2007 sales averaged 23.4 Mmscf/d (Q4 2006: 13.1 Mmscf/d) which represented the highest sales achieved in any quarter. The current gas price to the power sector varies month by month depending on the availability of the gas turbines at the Ubungo power plant. The maximum price of US$2.19/mcf was achieved in three of the four quarters in 2007. Profit/(loss) after taxation The majority of the Company’s costs associated with the production and distribution expenses are fixed in nature. There has been an increase in the level of expenditure on general and administrative costs as new personnel and consultants have been appointed to meet the expanding activities of the Company. Profitability in the first and fourth quarters of each year is affected by the seasonality of gas demand by the textile customers. Q3 2007 recorded the highest profit for the company due to the high level of sales to industrial customers of 4.3 Mmscf/d being comple- mented by the second highest level of sales recorded to the power sector of 21.5 Mmscf/d. The working capital for Q4 2007 decreased to US$7.3 million from $20.9 million in Q3 2007 as a result of the transfer of US$2.8 million of assets previously held for resale back into property, plant and equipment together with a US$10.9 million reduction in cash balances following the high level of capital expenditure in the Q4 2007 on the SS-10 well. The high level of working capital in Q3 2007 was a consequence of the funds raised from the completion of the private placement of 2.5 million Class B shares in July 2007. SElEctEd FInancIal InFORMatIOn Selected annual financial information derived from the audited consolidated financial statements the years ended 31 December 2005, 2006 and 2007 is set out below: ((Figures in US$’000) except per share amount) YeAR ended 31 deC embeR 2007 YeAR ended 31 deC embeR 2006 YeAR ended 31 deC embeR 2005 Revenue Funds from operations before working capital changes Profit after taxation Total assets Profit per share: Basic Diluted 18,777 13,828 5,759 8,696 1,745 5,969 2,577 2,268 388 92,789 43,904 21,097 0.06 0.06 0.11 0.10 0.02 0.02 revenue increased by 36% compared to 2006. Additional Gas volumes sold increased from 4,837 Mmscf in 2006 to 7,731 Mmscf in 2007 primarily due to the increase in sales to the power sector following the commissioning of emergency power generation units by Dowans and Aggreko in the last quarter of 2006. revenue increased by 140% in 2006 compared to 2005. Additional Gas volumes sold increased from 2,449 Mmscf in 2005 to 4,837 Mmscf in 2006 primarily due to an increase in the number of industrial customers, a longer comparative period for the sale of Additional Gas to the power sector which commenced in Q3 2005 and higher industrial prices. 39 management’s discussion & analysis Funds from operations before working capital changes increased by 46% in 2007 primarily as a result of the increase in revenues associated with sales to the power sector. Despite increased sales, profitability has remained in line with 2006 as the Company has established a business development and new markets team to generate growth outside of Tanzania. The Company’s assets increased by 112% to US$92.9 million (2006: 108% to US$43.9 million) in the year ended 31 December 2007. The Company’s assets are made up as follows: ((Figures in US$’000) ) current assets Cash and cash equivalents Trade and other receivables Fixed assets Exploration and evaluation assets Property, plant and equipment Total assets YeAR ended 31 deC embeR 2007 YeAR ended 31 deC embeR 2006 YeAR ended 31 deC embeR 2005 16,515 20,678 3,198 8,236 24,751 4,275 24,953 2,862 6,060 6,881 – – 61,157 92,789 18,951 43,904 15,037 21,097 The decrease in the cash and cash equivalents in 2007 is primarily the result of the high level of capital expenditure associated with the SS-10 development well and the expansion of activities into Uganda. This was financed by the net receipt of US$30.4 million from the issue of 2.5 million Class B shares at Cdn$13.80 per share in July 2007. The increase in the cash and cash equivalents in 2006 is primarily the result of the net receipt of US$18.1 million from the one for seven rights issue on 29 December 2006. The increase in trade and other receivables is due to the increased trading activities in the power sector and the delay in payments from TANESCO. This is more fully discussed in ‘Working Capital’ above. In 2007, the Company incurred a high level of expenditure on increasing the deliverability and security of Additional Gas Supply through a combination of development drilling and infrastruc- ture improvements as well as exploration activities outside of Tanzania. The increase in the plant property and equipment is discussed further in ‘Capital Expenditure’ above. OPERatInG hazaRdS and unInSuREd RISkS The business of Orca Exploration is subject to all of the operating risks normally associated with the exploration for, and the production, storage, trans- portation 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 Orca Exploration’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 encounter- ing unexpected formations or pressures, premature declines of reservoirs, blowouts, equipment failures and other accidents, sour gas releases, uncontrol- lable flows of oil, natural gas or well fluids, adverse weather conditions, pollution and other environ- mental risks. Drilling conducted by Orca Exploration 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 Orca Exploration is increased due to the fact that Orca Exploration currently only has one producing property. Orca Exploration 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 unfavour- able event not fully covered by insurance could have a material adverse effect on Orca Exploration’s financial condition, results of operations and cash flows. Furthermore, Orca Exploration cannot predict whether insurance will continue to be available at a reasonable cost or at all. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O FOREIGn OPERatIOnS All of Orca Exploration’s operations and related assets are 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, expropria- tion, nationalization, renegotiation or nullification of existing contracts, taxation policies, foreign exchange restrictions, changing political conditions, inter- national 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 ju- risdiction. In addition, if a dispute arises with foreign operations, Orca Exploration may be subject to the exclusive jurisdiction of foreign courts. In the foreign countries in which Orca Exploration 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 Orca Exploration’s development properties and all of its proved natural gas reserves are located offshore on the Songo Songo Island in Tanzania, and, consequently, Orca Exploration’s assets will be subject to regulation and control by the government of Tanzania and certain of its national and parastatal organizations. Orca Exploration 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 Orca Exploration. addItIOnal FInancInG Depending on future exploration, development, and marketing plans, Orca Exploration may require additional financing. The ability of Orca Exploration to arrange such financing in the future will depend in part upon the prevailing capital market conditions as well as the business performance of Orca Exploration. There can be no assurance that Orca Exploration will be successful in its efforts to arrange additional financing on terms satisfactory to Orca Exploration. If additional financing is raised by the issuance of shares from treasury of Orca Exploration, control of Orca Exploration may change and shareholders may suffer additional dilution. From time to time Orca Exploration 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 Orca Exploration’s debt levels above industry standards. InduStRy cOndItIOnS The oil and gas industry is intensely competitive and Orca Exploration 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, Orca Exploration operates the Songo Songo natural gas property. 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 parastatal organisations and, as a result, Orca Exploration 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. 41 management’s discussion & analysis The marketability and price of natural gas which may be acquired, discovered or marketed by Orca Exploration 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 Orca Exploration and Songas. The ability of Orca Exploration 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. Orca Exploration is also subject to market fluctuations 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. Orca Exploration 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 Orca Exploration may operate. Environ- mental regulations place restrictions and prohibi- tions 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 resulting in increased capital expenditures. addItIOnal GaS Orca Exploration has the right, under the terms of the PSA, to market volumes of Additional Gas subject to satisfying the requirements to deliver Protected Gas to Songas. There is a risk that Songas could interfere in Orca Exploration’s ability to produce, transport and sell volumes of Additional Gas if Orca Exploration’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. 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 a total of US$1.1 million for these three contracts and the remedy is payable as a credit against future monthly invoices. REPlacEMEnt OF RESERVES Orca Exploration’s natural gas reserves and production and, therefore, its cash flows and earnings are highly dependent upon Orca Exploration developing and increasing its current reserve base and discovering or acquiring additional reserves. Without the addition of reserves through exploration, acquisition or development activities, Orca Explora- tion’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, Orca Ex- ploration’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 Orca Exploration will be able to find and develop or acquire additional reserves to replace production at commercially feasible costs. aSSEt cOncEntRatIOn Orca Exploration’s natural gas reserves are limited to one property, the Songo Songo field, and the production potential from this field is limited to six wells. There has been limited production from the five wells in the Songo Songo field to date. There is no assurance that Orca Exploration 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 difficul- ties relating to the operation or performance of the field would have a material adverse effect on Orca Exploration. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O EnVIROnMEntal and OthER REGulatIOnS Extensive national, state, and local environmental laws and regulations in foreign jurisdictions will affect nearly all of Orca Exploration’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 en- vironmentally sensitive areas of operation. There can be no assurance that Orca Exploration will not incur substantial financial obligations in connection with environmental compliance. Significant liability could be imposed on Orca Exploration 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 Orca Exploration or non-compliance with environmental laws or regulations. Such liability could have a material adverse effect on Orca Exploration. Moreover, Orca Exploration 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 enforcement policies of any regulatory authority, could in the future require material expenditures by Orca Exploration for the installation and operation of systems and equipment for remedial measures, any or all of which may have a material adverse effect on Orca Exploration. As party to various licenses, Orca Exploration 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 Orca Exploration is currently in compliance with environmental laws and regulations applicable to Orca Exploration’s operations in Tanzania, no assurances can be given that Orca Exploration will be able to continue to comply with such environmental laws and regulations without incurring substantial costs. Orca Exploration’s petroleum and natural gas operations are subject to extensive governmen- tal legislation and regulation and increased public awareness concerning environmental protection. No provision has been recognised for future de- commissioning costs which are anticipated to be immaterial as it is forecast that there will still be commercial gas reserves once Orca Exploration relin- quishes the licence in 2026. Orca Exploration expects that the cost of complying with environmental legislation and regulations will increase in the future. Compliance with existing environmental legislation and regulations has not had a material effect on capital expenditures, earnings or competitive position of Orca Exploration to date. Although management believes that Orca Exploration’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. VOlatIlIty OF OIl and GaS PRIcES and MaRkEtS Orca Exploration’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 Orca Exploration. Any substantial decline in the prices of oil and natural gas could have a material adverse effect on Orca Exploration and the level of its 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 Orca Exploration. No assurance can be given that oil and natural gas prices will be sustained at levels which will enable Orca Exploration to operate profitably. From time to time Orca Exploration 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. 43 management’s discussion & analysis The Songo Songo field is the first gas field to be developed in East Africa. The Company has therefore been able to negotiate industrial 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. There has been a commercial gas discovery in the south of Tanzania at Mnazi Bay and during 2006 Maurel and Prom had a gas discovery approximately 50 kilometers south of Dar es Salaam. In addition, a number of Production Sharing Agreements have been negotiated for the drilling onshore and 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. In addition, various factors, including the avail- ability 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 Orca Exploration’s ability to market its gas production. Any significant decline in the price of oil or gas would adversely affect Orca Exploration’s revenues, operating income, cash flows and borrowing capacity and may require a reduction in the carrying value of Orca Exploration’s gas properties and its planned level of capital expenditures. uncERtaIntIES In EStIMatInG RESERVES and FutuRE nEt caSh FlOwS 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 Orca Exploration. The reserve and cash flow information contained herein represents estimates only. The reserves and estimated future net cash flow from Orca Explora- tion’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, marketabil- ity 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 Orca Exploration. Actual production and cash flows derived therefrom will vary from these evaluations, and such variations could be material. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O RElIancE On kEy PERSOnnEl Orca Exploration 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 Orca Exploration. Orca Exploration does not maintain key life insurance on any of its employees. cOntROllInG ShaREhOldER W. David Lyons, the Company’s non-executive Chairman, is the sole controlling shareholder of Orca Exploration and holds approximately 99.5% of the outstanding Class A shares and approximately 15.7% of the Class B shares. Consequently, Mr. Lyons holds approximately 20.6% of the equity (21.9% fully diluted) and controls 62.4% of the total votes of Orca Exploration. tItlE tO PROPERtIES 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 Orca Exploration which could result in a reduction of the revenue received by Orca Exploration. acquISItIOn RISkS Orca Exploration intends to acquire natural gas infrastructure and possibly additional oil and gas properties. Although Orca Exploration performs a review of the acquired properties that it believes is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, Orca Exploration 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 suf- ficiently 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 con- tamination, are not necessarily observable even when an inspection is undertaken. Orca Exploration 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 Orca Exploration’s acquisitions will be successful. 45 consolidated financial statements Management’s report to Shareholders ORca ExPlORatIOn GROuP Inc. The accompanying consolidated financial statements of Orca Exploration Group Inc. (formerly EastCoast Energy Corporation) are the responsibility of the Directors. The financial and operating information presented in this annual report is consistent with that shown in the consolidated financial statements. The consolidated financial statements have been prepared by management, on behalf of the Board, in accordance with the accounting policies disclosed in the notes to the consolidated financial statements. Where necessary, management has made informed judgments and estimates in accounting for transac- tions which were not complete at the balance sheet date. In the opinion of management, the consolidated financial statements have been prepared within acceptable limits of materiality and are in accordance with International Financial reporting Standards appropriate in the circumstances. Management, with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures and has concluded that such disclosure controls and procedures are effective. Management maintains appropriate systems of internal controls. Policies and procedures are designed to give reasonable assurance that transactions are properly authorised, assets are safeguarded and financial records are properly maintained to provide reliable information for the preparation of financial statements. An independent firm of Chartered Accountants, as appointed by the Shareholders, examines the consolidated financial statements in accordance with International Financial reporting Standards and provides an independent professional opinion. The Board of Directors carries out its responsibility for the financial reporting and internal controls principally through an Audit Committee. The committee has met with external auditors and Management in order to determine if Management has fulfilled its responsibilities in the preparation of the consolidated financial statements. The consolidated financial statements have been approved by the Board of Directors on the recommendation of the Audit Committee. P. r. Clutterbuck President & Chief Executive Officer Nigel Friend Chief Financial Officer t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O Auditors’ report ORca ExPlORatIOn GROuP Inc. REPORt On thE cOnSOlIdatEd FInancIal StatEMEntS We have audited the accompanying consolidated financial statements of Orca Exploration Group Inc. and its sub- sidiaries (the ‘Group’), which comprise the consolidated balance sheet as at 31 December 2007 and 31 December 2006 and the consolidated income statements, consolidated statement of cash flows and statements of changes in shareholders’ equity for the years then ended, a summary of significant accounting policies and notes to the consolidated financial statements. ManaGEMEnt’S RESPOnSIbIlIty FOR thE FInancIal StatEMEntS Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial reporting Standards. This responsibility includes: designing, imple- menting and maintaining internal controls relevant to the preparation and fair presentation of the financial statements that are free from material misstatements, whether due to fraud or error; selecting and applying appropriate accounting policies; and making accounting estimates that are reasonable in the circumstances. audItORS’ RESPOnSIbIlIty Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the International Standards on Auditing. Those standards require that we comply with the relevant ethical requirements and plan and perform the audit to obtain a reasonable assurance whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgement, including the assessments of the risks of material misstatements of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal controls relevant to the entity’s preparation and fair presentation of the financial statements in order in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting principles used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Opinion In our opinion, the consolidated financial statements give a true and fair view of the consolidated financial position of the Group as at 31 December 2007 and 31 December 2006, and of its consolidated financial performance and its statement of consolidated cash flows for the years then ended in accordance with Interna- tional Financial reporting Standards. Calgary, Canada 28 April 2008 COMMENTS BY AUDITOrS FOr CANADIAN rEADErS ON INTErNATIONAL – CANADIAN rEFErENCES Canadian reporting standards may differ from 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 standards on the aforementioned consolidated financial statements would not contain a qualification of opinion. Calgary, Canada 28 April 2008 47 consolidated financial statements Consolidated Income Statements ORca ExPlORatIOn GROuP Inc. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O years ended 31 decembernote20072006(thousands of US dollars except per share amounts)Revenue 518,77713,828Cost of salesProduction and distribution expenses(1,193)(793)Depletion expense12(4,476)(2,027)13,10811,008Administrative expenses(10,708)(6,724)Net financing income / (charges) 71,375(23)Profit before taxation3,7754,261Taxation8(2,030)(1,684)Profit after taxation 1,7452,577Profit per share16Basic (US$) 0.060.11Diliuted (US$) 0.060.10See accompanying notes to the consolidated financial statements. Consolidated Balance Sheet ORca ExPlORatIOn GROuP Inc. 49 as at 31 decemberNote20072006(thousands of US dollars)ASSETS Current assetsCash and cash equivalents916,51520,678Trade and other receivables108,2364,275 24,75124,953Exploration and evaluation assets116,881–Property, plant and equipment1261,15718,951 68,03818,951 92,78943,904LIABILITIESCurrent liabilitiesTrade and other payables1317,4524,523Non current liabilitiesDeferred income taxes83,2051,229Deferred additional profits tax588263SHAREHOLDERS’ EQUITYCapital stock1466,53834,469Capital reserve151,0231,182Accumulated income3,9832,238 71,54437,889 92,78943,904See accompanying notes to the consolidated financial statements.Contractual obligations and committed capital investment (Note 20)Post balance sheet events (Note 21)The consolidated financial statements were approved by the Board of Directors on 28 April 2008. Director Director consolidated financial statements Consolidated Statements of Cash Flows ORca ExPlORatIOn GROuP Inc. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O years ended 31 december20072006(thousands of US dollars)CASH FLOWS FROM OPERATING ACTIVITIES Profit after taxation1,7452,577Adjustments for: Depletion and depreciation4,6302,129 Stock-based compensation1,062418 Deferred income taxes1,976723 Deferred additional profits tax325183 Interest income(628)(61) Foreign exchange gain(414)–8,6965,969Increase in trade and other receivables(3,961)(1,413)Increase in trade and other payables6,032540Net cash flows from operating activities10,7675,096CASH FLOWS USED IN INVESTING ACTIVITIESExploration and evaluation expenditures(6,322)–Property, plant and equipment expenditures(46,836)(6,043)Interest income62861Increase in trade and other payables6,897134Net cash used in investing activities(45,633)(5,848)CASH FLOWS FROM FINANCING ACTIVITIESNormal course issuer bid(220)–Shares issued30,36618,087Foreign exchange gain414–Proceeds from exercise of options143145Net cash flow from financing activities30,70318,232(Decrease) / increase in cash and cash equivalents(4,163)17,480Cash and cash equivalents at the beginning of the year20,6783,198Cash and cash equivalents at the end of the year16,51520,678See accompanying notes to the consolidated financial statements. Statement of Changes in Shareholders’ Equity ORca ExPlORatIOn GROuP Inc. 51 (thousands of US dollars)Capital stoCkCapital reserveaCCumulated inCome/ (loss)totalNote1415 Balance as at 31 December 200516,237764(339)16,662Rights issue 18,087––18,087Options exercised145––145Stock-based compensation –418–418Profit for the year ––2,5772,577Balance as at 31 December 200634,4691,1822,23837,889Stock issued31,971(675)–31,296Options exercised143––143Stock-based compensation–691–691Normal course issuer bid(45)(175)–(220)Profit for the year––1,7451,745Balance as at 31 December 200766,5381,0233,98371,544See accompanying notes to the consolidated financial statements. notes to the consolidated financial statements Notes to the Consolidated Financial Statements ORca ExPlORatIOn GROuP Inc. GEnERal InFORMatIOn Orca Exploration Group Inc. (formerly EastCoast Energy Corporation) (“Orca Exploration” or the “Company”) was incorporated on 28 April 2004 under the laws of the British Virgin Islands.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 six producing wells and two 35 mmscf/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 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 is principally used as feedstock for specified turbines and kilns. Gas sales in excess of the Protected Gas users’ requirements is classified 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. In 2007 the Company initiated its strategy to acquire two new oil interest in Africa with the negotiation of an option to acquire a 50% interest in Exploration Area 5 in Uganda. 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] SuMMarY OF SiGniFicant accOuntinG pOliciES 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. These principles differ in certain respects from those in Canada. These differences are described in note 17. b) basis of consolidation i) Subsidiaries The consolidated financial statements include the accounts of the Company and all its wholly owned subsidiaries (collectively, the “Company”). Subsidiaries are those enterprises controlled by the Company. The following companies have been consolidated within the Orca Exploration financial statements: subsidiARY Orca Exploration Group Inc Orca Exploration (Ventures) Inc Orca Exploration Uganda (Holding) Inc Orca Exploration Uganda Inc PAE PanAfrican Energy Corporation PanAfrican Energy Tanzania Limited RegisteRed holding British Virgin Islands Parent Company British Virgin Islands British Virgin Islands British Virgin Islands Mauritius Jersey 100% 100% 100% 100% 100% t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O ii) Transactions eliminated upon consolidation Inter-company balances and transactions, and any unrealised gains arising from inter-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) Exploration and evaluation assets, property, plant and equipment Exploration and evaluation assets Exploration and evaluation costs are capitalized as intangible assets. Intangible assets includes lease and licence acquisition costs, geological and geophysical costs and other direct costs of exploration and evaluation which the directors consider to be unevaluated until reserves are appraised as commercial, at which time they are transferred to property, plant and equipment following an impairment review and depleted accordingly. Where properties are appraised to have no commercial value, the associated costs are treated as an impairment loss in the period in which the determination is made. Property, plant and equipment Property, plant and equipment comprises the Company’s tangible natural gas assets, together with leasehold improvements, computer equipment, motor vehicles and fixtures and fittings and are carried at cost, less any accumulated depletion, depreciation and accumulated impairment losses. Cost includes purchase price and construction costs for qualifying assets. Depletion of these assets commences when the assets are ready for their intended use. Only costs that are directly related to the discovery and development of specific oil and gas reserves are capitalized. The cost associated with tangible natural gas assets are amortised on a field by field unit of production method based on commercial proven reserves. The calculation of the unit of production amortisation takes into account the estimated future development cost of the field. Impairment of exploration and evaluation assets, property, plant and equipment At each balance sheet date, the Company reviews the carrying amounts of its property, plant and equipment and intangible assets to determine whether there is any indication that those assets have suffered an impairment loss. Individual assets are grouped together as a cash generating unit for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are independent from other group assets. In the case of exploration and evaluation assets this will normally be at a field level. If any such indication of impairment exists the Company makes an estimate of its recoverable amount. The recoverable amount is the higher of fair value less costs to sell and value in use. Where the carrying amount of a cash generating unit exceeds its recoverable amount, the cash generating unit is considered impaired and is written down to its recoverable amount. In accessing the value in use, the estimated future cash flows are adjusted for the risks specific to the cash generating unit and are discounted to their present value that reflects the current market indicators. Where an impairment loss subsequently reverses, the carrying amount of the asset cash generating unit is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the cash generating unit in prior years. A reversal of an impairment loss is recognised as income immediately. 53 notes to the consolidated financial statements e) Operatorship The Company operates the gas field, flow lines and gas processing plant on behalf of Songas at cost. The cost of operating and maintaining the wells and flow lines is paid for by Orca Exploration 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 and pipeline to Dar es Salaam is paid by Songas. When there are Additional Gas sales, a transportation tariff is paid to Songas as compensation for using the gas processing plant and pipeline. This transportation tariff is netted off revenue. f) trade and other receivables Trade and other receivables are stated at cost less impairment losses. g) cash and cash equivalents Cash and cash equivalents include cash on deposit and highly liquid investments with original maturities of three months or less. h) Employment benefits Pension i) 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) Stock options The share option plan 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 options, 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. iii) Stock appreciation rights Stock appreciation rights are issued to certain key managers and employees. The Company accounts for stock appreciation rights, whereby the fair value of such rights are expensed to the income statement in accordance with the service period. The fair value of the stock appreciation rights is revalued every reporting date with the change in the value expensed to the income statement. i) asset retirement obligations No provision has been made for future site restoration costs since the Company has no legal or contractual obligation under the PSA to restore the fields at the end of their commercial lives. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O j) Revenue recognition, production sharing agreements and royalties The Company recognises revenue from natural gas sales when title passes to a customer. The Company conducts operations jointly with the Tanzanian government and “parastatal entities” in accordance with production sharing agreements (“PSA”). 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 (“Cost Gas”). The parastatal’s share of operating and administrative costs are recorded in operating and general and administrative costs when incurred and capital costs are recorded in ‘Property, plant and equipment’. All recoveries are recorded as revenue in the year of recovery. The Company is entitled to a share of production in excess of the Cost Gas (“Profit Gas”). Operating revenue represents the Company’s share of Cost Gas and Profit Gas during the period, net of the transportation tariff. k) additional profits 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 (“APT”) is payable to the Government of Tanzania. This tax is considered to be a royalty and is netted against revenue. APT is provided for by forecasting the total APT payable as a proportion of the forecast Profit Gas over the term of PSA licence. l) taxation Income tax on the profit for the year comprises current and deferred tax. The Company is liable for Tanzanian income tax, but this is recovered from TPDC through the profit-sharing arrangement. Where current income tax is payable, revenue is adjusted for the tax and the income tax is shown as current tax. Deferred tax is provided using the balance sheet asset and 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 amounts 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 asset 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. m) Segmental reporting The Company currently operates in Tanzania and Uganda. All the revenue generating operations are located in Tanzania. o) depreciation Depreciation for non-natural gas properties is charged to the income statement on a straight line basis over the estimated useful economic lives of each class of asset. The estimated useful lives are as follows: Leasehold improvement Computer Equipment Vehicles Fixtures and fittings Over remaining life of the lease 3 years 3 years 3 years 55 notes to the consolidated financial statements p) new accounting standards and interpretations Certain new accounting standards and interpretations have been published that are not mandatory for the 31 December 2007 reporting period. The Company’s assessment of the impact of these new standards and interpretations which have not been adopted is set out below. IFrS 8, “Operating segments” (effective from 1 January 2009), replaces IAS 14 and aligns segment reporting with the requirements of the US standard SFAS 131, “Disclosures about segments of an enterprise and related information”. The new standard requires a “management approach”, under which segment information is presented on the same basis as that used for internal reporting purposes. The expected impact is still being assessed by management, but is expected to only impact the disclosures of the Company. The following standards are assessed not to have any impact on the Company’s financial statements: • • IAS 23 (Amendment), “Borrowing costs” (effective from 1 January 2009), requires the Company to capitalise borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset (one that takes a substantial period of time to get ready for use or sale) as part of the cost of that asset. IFRIC 11, “IFRS 2 – Group and treasury share transactions” (effective from 1 January 2008), provides guidance on whether share-based transactions involving treasury shares or involving group entities (for example, options over a parent’s shares) should be accounted for as equity-settled or cash-settled share-based payment transactions in the stand-alone accounts of the parent and group companies. The following amendments have been published, but have not been applied in these financial statements: • • • • • IFRS 2 (Amendment), Share based payment – Vesting Conditions and Cancellations: effective for accounting periods commencing on or after 1 January 2009; IFRS 3 (Amendment) Business Combinations: effective for accounting periods commencing on or after 1 July 2009; IAS 1 (Amendment), Presentation of Financial Statements: effective for accounting periods commencing on or after 1 January 2009; IAS 23 (Amendment), Borrowing Costs: effective for accounting periods commencing on or after 1 January 2009; IAS 27 (Amendment), Consolidated and Separate Financial Statements: effective for accounting periods commencing on or after 1 July 2009. The Directors have yet to establish whether the adoption of these amendments will have a material impact on the Company’s financial statements in the period of initial application. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O [2] critical accOuntinG EStiMatES In applying the Company’s accounting policies, which are described in note 1, management makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, vary to the actual results. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below: i) Reserves There are numerous uncertainties inherent in estimating quantities of proved and probable reserves and cash flows to be derived there from, including many factors beyond the control of Orca Exploration. The reserve and cash flow information contained herein represents estimates only. The reserves and estimated future net cash flow from Orca Exploration’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, TPDC “back-in” methology 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 Orca Exploration. reserves are integral to the amount of depletion charged to the income statement. ii) Exploration and evaluation assets • • • • • • Under the Company’s accounting policy expenditures incurred on the exploration for, and evaluation of reserves are capitalized as intangible assets. These intangibles assets are then assessed for impairment when circumstances suggest that the carrying amount may exceed its recoverable value. Such circumstances include but are not limited to: the period for which the Company has the right to explore in the specific area has expired during the period, or will expire in the near future, and is not expected to be renewed; no further expenditure on exploration and evaluation is budgeted or planned; no reserves have been encountered; the evaluation of seismic data indicates that the reserves are unlikely to be of a commercial quantity; the quantity of reserves are deemed not to be of commercially viable quantities and the entity has decided to discontinue further activities; sufficient data exists to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale. The assessment for impairment involves estimates as to (i) the likely future commerciality of the asset and when such commerciality should be determined, (ii) future revenues and costs associated with the asset, and (iii) the discount rate to be applied to such revenues and costs for the purpose of deriving a recoverable value. 57 notes to the consolidated financial statements iii) Fair value of stock based compensation All stock options issued or stock appreciation rights granted by the Company have to be valued at their fair value. In assessing the fair value of the equity based compensation estimates have to be made as to i) the volatility in share price, ii) risk free rate of interest and iii) the level of forfeiture. In the case of stock options this fair value is estimated at the date of issue and is not revalued, where as the fair value of stock appreciation rights is recalculated at each reporting period. [3] riSK ManaGEMEnt The Company, by its activities in oil and gas exploration, development and production is exposed to the risk associated with the unpredictable nature of the financial markets. The Company seeks to manage its exposure to these risks where ever possible. i) Foreign exchange risk Foreign exchange risk arises when transactions and recognised assets and liabilities of the Company are denominated in a currency that is not the U.S. dollar functional currency. The Company operates internationally and is exposed to foreign exchange risk arising from currency exposures to U.S. dollars. The main currencies to which the Company has an exposure to are; Tanzanian shillings, British pounds sterling and Canadian dollars. The majority of the expenditure associated with the operation of the gas distribution system is denominated in Tanzanian shillings. The majority of consultants contracts are denominated in British pounds sterling. All of the capital stock, equity financing and any associated stock based compensation are denominated in Canadian dollars. All of the operational revenue and the majority of capital expenditure is denominated in US dollars. There are no forward exchange rate contracts in place. ii) Commodity price risk The Songo Songo gas field is the first gas field to be developed in East Africa Company has therefore been able to negotiate industrial gas sales contracts with gas prices that are at a discount to the lowest cost alternative fuels in Dar es Salaam, namely Heavy Fuel Oil (“HFO”). The price of HFO is exposed to the volatility in the market price of oil and natural gas. iii) Interest rate risk The Company currently does not have any debt or borrowings so is therefore not exposed to any interest rate risk. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O iv) Credit risk All of the Company’s production is currently derived in Tanzania. The sales are made to the power sector and the industrial sector. In relation to sales to the power sector, the Company has a short term contract with Songas for the supply of gas to the Ubungo power plant and two contracts with TANESCO to supply Additional Gas sales to two emergency power plants. The contracts with Songas and TANESCO accounted for 49% of the Company’s operating revenue during 2007 and US$4.0 million of the receivables at the year end. Songas itself is heavily reliant on the payment of capacity and energy charges by TANESCO for its liquidity. TANESCO is dependent on the Government of Tanzania for some of its funding. Whilst some payments have been delayed, the Company has subsequently received all the amounts due from Songas for all gas sales to 31 December 2007. Sales to industrial sector are subject to an internal credit review to minimize the risk of non payment. The Company does not anticipate any default with these customers. v) Liquidity risk Liquidity risk is the risk that the Company will not have sufficient funds to meet its liabilities. Cash forecasts identifying liquidity requirements of the Company are produced on a quarterly basis. These are reviewed on a regular basis to ensure sufficient funds exist to finance the Company’s current operational and investment cash flow requirements. The Company has no financial liabilities other than the trade and other payables indentified in note 12 which are all due within 12 months. The Company is currently negotiating a short term US$5 million overdraft facility. The Company currently has no bank borrowings and there is scope for utilising debt funding once the longer term contracts for the supply of gas to the power sector are in place. vi) Capital risk management The Corporation’s objectives when managing capital are to safeguard the Company’s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Company currently has no borrowings. 59 notes to the consolidated financial statements [4] SEGMEntal inFOrMatiOn The Company has a single class of business which is international exploration, development and production of petroleum and natural gas. The Company currently operates in Tanzania and Uganda. (Figures in US$’000) 2007 Tanzania Uganda 2006 Tanzania exteRnAl Revenue segment Result totAl Assets totAl liAbilities CApitAl Additions depletion & depReCiAtion 18,777 – 18,777 13,828 13,828 1,745 – 1,745 2,577 2,577 85,908 6,881 92,789 43,904 43,904 21,245 – 21,245 6,015 6,015 46,836 6,881 53,717 6,043 6,043 4,630 – 4,630 2,129 2,129 [5] rEVEnuE YeARs ended 31 deC embeR (Figures in US$’000) Operating revenue Current income tax adjustment Deferred additional profits tax Revenue 2007 2006 19,023 78 (324) 12,638 1,373 (183) 18,777 13,828 The revenue reported is the Company’s proportionate share of revenue as calculated in accordance with the accounting policy 1(j). The Company’s total revenues for the year amounted to US$18,777,000 after adjusting the Company’s operating revenue of US$19,023,000 by: i) ii) US$78,000 for income tax. The Company is liable for income tax in Tanzania, but the income tax is recoverable out of TPDC’s Profit Gas when the tax is payable. To account for this, revenue is adjusted to reflect the current income tax charge or loss. US$324,000 for the deferred effect of additional profits tax. This tax is considered a royalty and is netted against revenue. [6] pErSOnnEl ExpEnSES The average number of employees during the year was 15 (2006: 15). The costs are as follows: YeARs ended 31 deC embeR (Figures in US$’000) Wages and salaries Social security costs Other statutory costs 2007 2006 1,550 237 272 2,059 1,182 159 226 1,567 t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O [7] nEt FinancinG incOME/(cHarGES) YeARs ended 31 deC embeR (Figures in US$’000) Finance income Interest income Foreign exchange gain Finance charges Foreign exchange loss Net financing income/(charge) [8] taxatiOn 2007 2006 628 832 1,460 (85) 1,375 61 11 72 (95) (23) Under the terms of the Production Sharing Agreement with TPDC, the Company is liable to pay income tax at the corporate rate of 30% on profits generated in Tanzania. The amount paid is then recovered in full from TPDC by adjusting their share of profit gas. The tax charge is as follows: YeARs ended 31 deC embeR (Figures in US$’000) Current tax Deferred tax tax RatE REcOncIlIatIOn YeARs ended 31 deC embeR (Figures in US$’000) Profit before taxation Provision for income tax calculated at the statutory rate of 30% Add the tax effect of non-deductible income tax items: Administrative and operating expenses Stock- based compensation Other income Permanent differences 2007 2006 54 1,976 2,030 961 723 1,684 2007 2006 3,775 1,133 676 450 (331) 102 4,261 1,278 170 125 (15) 126 2,030 1,684 As at 31 December 2007, there were temporary differences between the carrying value of the assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Accordingly a deferred tax liability has been recognized for the year ended 31 December 2007. 61 notes to the consolidated financial statements The deferred income tax liability includes the following temporary differences: As At 31 deC embeR (Figures in US$’000) Differences between tax base and carrying value of property, plant and equipment Provision for stock option bonuses Income tax recoverable Other liabilities Additional profits tax [9] caSH anD caSH EQuiValEntS As At 31 deC embeR (Figures in US$’000) Cash and short term deposits 2007 2006 3,542 (360) 230 (31) (176) 3,205 992 (135) 451 – (79) 1,229 2007 2006 16,515 20,678 Included in the cash and cash equivalents is US$501,000 advanced from Songas under the terms of the Operatorship Agreement to pay for the costs of operating the wells and gas processing plant. This amount is also included in trade and other payables. [10] traDE anD OtHEr rEcEiVaBlES As At 31 deC embeR (Figures in US$’000) Trade receivables Prepayments Other receivables 2007 2006 7,275 801 160 8,236 3,441 159 675 4,275 t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O [11] ExplOratiOn anD EValuatiOn aSSEtS (Figures in US’000) costs As at 1 January 2007 Additions As at 31 December 2007 depletion/depreciation As at 1 January 2007 Charge for the period As at 31 December 2007 net book Values as at 31 december 2007 As at 31 December 2006 ugAndA – 6,881 6,881 – – – 6,881 – General administrative expenses of US$1.2 million have been capitalized in the year (2006:U$nil) including: US$0.8 million of stock based compensation of which US$0.6 is in relation to stock options and US$0.2 million is in relation to stock appreciation rights. [12] prOpErtY, plant anD EQuipMEnt (Figures in US’000) costs As at 1 January 2007 Additions as at 31 december 2007 depletion/depreciation As at 1 January 2007 Charge for the period as at 31 december 2007 net book Values as at 31 december 2007 As at 31 December 2006 tAnzAniA leAsehold impRovements ComputeR equipment vehiCles fixtuRes & fittings totAl 21,701 46,661 68,362 2,880 4,476 7,356 61,006 18,821 156 – 156 94 62 156 – 62 63 101 164 42 42 84 80 21 65 74 139 33 35 68 71 32 41 – 41 26 15 41 – 15 22,026 46,836 68,862 3,075 4,630 7,705 61,157 18,951 In determining the depletion charge, it is estimated by the independent reserve engineers that future development costs of US$128.4 million (2006: US$123.8 million) will be required to bring the total proved reserves to production. 63 notes to the consolidated financial statements [13] traDE anD OtHEr paYaBlES As At 31 deC embeR (Figures in US$’000) Trade payables Accrued liabilities Related party (note 19) Deferred income Income tax Deposits [14] capital StOcK a) authorised 2007 2006 12,667 4,629 156 – – – 1,733 2,083 472 138 (88) 185 17,452 4,523 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. b) Changes in the capital stock of the Company were as follows: Thousands of shares or US$’000 AuthoRised issued vAluAtion AuthoRised issued vAluAtion class a shares as at 1 January and 31 december 50,000 1,751 983 50,000 1,751 983 2007 2006 class b shares As at 1 January Issue of new stock Stock options exercised Normal course issuer bid as at 31 december total class a & b shares as at 31 december 50,000 – – – 25,023 2,700 160 (20) 33,486 31,971 143 (45) 50,000 21,513 15,254 – – – 3,345 18,087 165 – 145 – 50,000 27,863 65,555 50,000 25,023 33,486 100,000 29,614 66,538 100,000 26,774 34,469 In April 2007, 0.2 million Class B shares were awarded to a newly appointed officer. These shares are held in escrow and they vest to the officer in three equal installments starting 7 April 2007. At the time the shares were awarded they had a market value of US$1.6 million (Cdn$1.7 million). The shares will be fully vested by 7 April 2009. A cost of US$0.9 million was recorded in 2007. In July 2007, 2.5 million Class B shares were issued at a price of Cdn$13.80 per share following the conclusion of a private placement, resulting in gross proceeds of Cdn$34.5 million. A total of US$30.4 million net proceeds have been recognized in capital stock. A large proportion of the funds were used for the completion of the SS-10 well in Tanzania and for the funding of a new venture in Uganda. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O Stock-based compensation The stock option plan provides for the granting of stock options to directors, officers and employees. The exercise price of each stock option is determined as the closing market price of the common shares on the day prior to the day of grant. Each stock option granted permits the holder to purchase one common share at the stated exercise price. The Company records a charge to the profit and loss account using the Black-Scholes fair valuation option pricing model. The valuation is dependent on a number of estimates, including the risk free interest rate, the level of stock volatility, together with an estimate of the level of forfeiture. The level of stock volatility is calculated with reference to the historic traded daily closing share price at the date of issue. Thousands of options or Cdn$ options exeRCise pRiCe options exeRCise pRiCe 2007 2006 Outstanding as at 1 January Granted Forfeited Exercised 2,022 1,185 (200) (160) 1.00 to 6.80 8.70 to 13.55 6.80 1.00 Outstanding as at 31 december 2,847 1.00 to 13.55 1,987 200 – (165) 2,022 1.00 6.80 – 1.00 1.00 to 6.80 The weighted average remaining life and weighted average exercise prices of options at 31 December 2007 were as follows: exeRCise pRiCe (Cdn$) 1.00 8.70 to 13.55 numbeR outstAnding As At 31 deC embeR 2007 weighted AveRAge RemAining ContRACtuAl life numbeR exeRCisAble As At 31 deC embeR 2007 weighted AveRAge exeRCise pRiCe 1,662 1,185 6.90 4.39 1,662 – (Cdn$) 1.00 11.57 The following assumptions have been made in establishing the fair value of the stock options issued in 2007: dAte of issue 14-Jan 24-Apr 06-Jun 01-Oct 08-Nov options (thousands) 300 150 510 75 150 1,185 exeRCise pRiCe RisK fRee RAte shAR e volAtilitY foRfeituRe Yield vAluAtion dividend unReCoRded ChARge As At 31 deC 07 ChARge in YeAR CDN$ 8.70 3.75% 10.00 3.75% 13.55 11.81 12.00 3.75% 3.96% 3.96% 60% 51% 53% 41% 42% 33% 33% 33% 33% 33% 0% 0% 0% 0% 0% US$(‘000) US$(‘000) US$(‘000) 750 435 2,144 251 464 4,044 241 100 419 20 23 803 509 335 1,725 231 441 3,241 A total charge of US$0.8 million has been recognised for the 1,185,000 stock options issued during the year and a reversal of US$0.1 million has been recognised for the 200,000 stock options forfeited in the year, resulting in a net charge of US$0.7 million. There was no charge recognised for the stock options outstanding as at 1 January 2007 as these had been fully expensed in 2006. 65 notes to the consolidated financial statements Stock appreciation rights Thousands of stock appreciation rights or Cdn$ options exeRCise pRiCe options exeRCise pRiCe 2007 2006 Outstanding as at 1 January (i) Granted (ii) Granted (ii) Granted (ii) 400 300 300 90 4.00 8.00 8.70 13.55 400 4.00 - - - - - - Outstanding as at 31 December 1,090 4.00 to 13.55 400 4.00 (iii) (ii) These stock appreciation rights have a liability of Cdn$3.00 per right or Cdn$1.2 million in total. The stock appreciation rights are all due to be paid in 2008. These stock appreciation rights have a term of 5 years and vest in three equal annual installments starting a year after they are granted. There is no maximum liability associated with these rights. The Company records a charge to the income statement using the Black-Scholes fair valuation option pricing model every reporting period with a resulting liability being recognised in the balance sheet. In the valuation of these stock appreciation rights at the reporting date, the following assumptions have been made: the risk free rate of interest equal to 3.96%, stock volatility 45%, 0% dividend yield and a 33% level of forfeiture. As at 31 December 2007 a total liability of US$1.9 million (2006: US$0.5 million) has been recognised in relation to the stock appreciation rights. A total charge of US$1.5 million has been recorded during 2007. [15] capital rESErVE The capital reserve is used to record two types of transactions: (i) To recognise the fair value of equity settled stock based compensation expensed in the year. In the case of the treasury shares issued in 2007, the reserve has been used to recognise the unexpensed fair value of the treasury shares, as the full fair value of the treasury stock issued has been recorded as capital stock. (ii) To account for the difference between the aggregated book value of the shares purchased under the normal course issuer bid and the actual consideration. [16] prOFit pEr SHarE The calculation of basic profit per share is based on the net profit attributable to ordinary shareholders of US$1,745,000 (2006: US$2,577,000) and a weighted average number of Class A and Class B shares outstanding during the period of 28,259,382 (2006: 23,395,477). In computing the diluted earnings per share, the dilutive effect of the stock options was 1,543,358 (2006: 1,513,463) shares. These were added to the weighted average number of common shares outstanding during the year ended 31 December, 2007. No adjustments were required to reported earnings from operations in computing diluted per share amounts. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O [17] rEcOnciliatiOn OF iFrS tO accOuntinG principlES GEnErallY accEptED in canaDa The consolidated financial statements have been prepared in accordance with IFrS, which differ in some respects from Canadian Generally Accepted Accounting Principles (“Canadian GAAP”). Any difference in accounting principles as they pertain to the accompanying consolidated financial statements were immaterial except as described below: a) taxation On 31 August 2004, the Company was spun off from a predecessor company pursuant to a scheme of arrangement. Under Canadian GAAP, a deferred tax liability has to be recognised for the taxable temporary differences arising from the initial recognition of an asset or liability under any scenario. IFrS does not permit the setting up of a deferred tax liability for all taxable temporary differences arising from the initial recognition of an asset or liability except in a business combination. b) Stock-based compensation There were 1,090,000 stock appreciation rights outstanding as at 31 December 2007 (see note 14). Under IFrS as these rights are a cash-settled share-based transaction, the fair value of the rights is calculated using a Black-Scholes option pricing model every reporting period. Under Canadian GAAP, the fair value is calculated using the intrinsic value method whereby the rights are valued at the quoted market price less the rights price at each reporting period. Under both IFrS and Canadian GAAP, the fair value is expensed over the service period of the rights. The application of Canadian GAAP would have the following effect on the balance sheet: As At 31 deC embeR (Figures in US$’000) Current assets Evaluation and exploration assets Property, plant and equipment Current liabilities Non current liabilities Capital stock Reserves Profit before taxation ifRs 24,751 6,881 61,157 92,789 17,452 3,793 66,538 5,006 92,789 3,775 2007 Cdn 24,751 – 69,500 94,251 17,187 5,541 66,538 4,985 94,251 3,886 ifRs 24,953 – 18,951 43,904 4,523 1,492 34,469 3,420 43,904 4,261 2006 Cdn 24,953 – 20,594 45,547 4,523 3,266 34,469 3,289 45,547 4,114 67 notes to the consolidated financial statements [18] OpEratinG lEaSES As At 31 deC embeR (Figures in US$’000) Less than one year Between one and five years 2007 2006 102 394 496 88 – 88 The Company had a five year rental agreement that expired on 30 November 2007 for the use of the offices in Dar es Salaam. The agreement has been renewed for another five years ending 30 November 2012 at a cost of approximately US$102,000 per annum. [19] rElatED partY tranSactiOnS One of the non executive Directors is a partner at a law firm. During the year, the Company incurred US$156,000 to this firm for services provided on fund raising and other legal services. The transactions with this related party were made at the exchange amount. [20] cOntractual OBliGatiOnS anD cOMMittED capital inVEStMEnt capital Investment In 2007 the Company signed an option agreement with Tower resources Plc (“Tower”). Under the terms of the agreement, the Company committed to pay for 83.33% of the costs of a 300 kilometer 2-D seismic programme up to a gross cap of approximately US$6.4 million, together with certain historical costs. The Company has 40 days from the receipt of the interpreted seismic information to exercise its option to earn a 50% working interest in Exploration Area 5 (“EA 5”) in return for funding 83.33% of the cost of two exploration wells. The cost of the wells is capped at between US$10 million and US$15 million depending on whether testing of the wells is required. In the event that the costs are higher than the caps for the seismic or the cost of the two wells, the Company will contribute 50% towards the excess. The Company provided a bank guarantee of US$15.0 million to cover its obligations under the option agreement which is reduced by any actual payments made to Tower. At the end of the year the bank guarantee was US$9.4 million of which a further US$1.5 million is anticipated to be required in 2008 to complete the seismic programme. 300 kilometers of 2-D seismic was shot during Q4 2007 and Q1 2008. Processing of this seismic data has now commenced, and is due to be completed in the coming weeks. The initial evaluation of the data has indicated that a number of potential structures exist. Technical analysis is still on going with particular attention being paid to the relationship of these structures and any potential hydrocarbon maturation that could have occurred within the basin. As yet it is too early to indicate the level of prospectivity. However initial analysis indicates that the block is potentially more risky than initially thought. As the processing of the seismic data continues the details of the prospectivity will become clearer. The Company has until June 2008 to determine whether to commit to drill two exploration wells to secure a 50% interest in EA 5. Management forecasts that the Company will be able to meet its 2008 capital expenditure programme through the use of existing cash balances, self-generated cash flows and a US$5.0 million overdraft facility that is currently being put in place. The Company currently has no bank borrowings and there is scope for utilising debt funding once the longer term contracts for the supply of gas to the power sector are in place. t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O Shortfall Gas Under the terms of the contracts with Kioo Ltd., Tanzania Breweries Ltd. 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 a total of US$1.1 million for these three contracts, payable as a credit against future monthly invoices. Protected Gas 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/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 (15.1 Bcf as at 31 December 2007). The Company is actively monitoring the reservoir and does not anticipate that a liability will occur in this respect. However, Songas has the right to request reasonable security on all Additional Gas sales. Songas has written to the Company confirming that, subject to certain conditions, security will not be required for the supply of Additional Gas to the Ubungo power plant, for the supply of up to 15 Mmscf/d for additional power generation and up to 10 Mmscf/d for the industrial sector for a period of five years. As the current emergency power generation operating in the country could take demand above 15 Mmscf/d for power generation, Songas has confirmed that the Company may sell 17 Mmscf/d for power generation over the next year without the need for security. The Company is looking to agree a security mechanism with Songas that provides clear guidance as to how Songas will operate their rights to security. It is anticipated that in the long term, the Company and TPDC may have to allocate a proportion of the Additional Gas revenues to an escrow account, in the event of a forecast Protected Gas insufficiency. back in TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development by contributing 20% of the costs of the future wells including SS-10 in return for a 20% increase in the profit share for the production emanating from these wells. The implications and workings of the ‘back in’ are still to be discussed in detail with TPDC. For the purpose of the reserves certification, it has been assumed that they will ‘back in’ for 20% and this is reflected in the Company’s net reserve position. However, the financial statements do not take account of any re-imbursement for the SS-10 capital expenditure, pending the finalisation of the terms of the ‘back in’. [21] pOSt BalancE SHEEt EVEntS 300 kilometers of 2-D seismic was shot in area EA 5 Uganda during Q4 2007 and Q1 2008. Processing of this seismic data has now commenced, and is due to be completed in the coming weeks. The initial evaluation of the data has indicated that a number of potential structures exist. Technical analysis is still on going with particular attention being paid to the relationship of these structures and any potential hydrocarbon maturation that could have occurred within the basin. As yet it is too early to indicate the level of prospectivity. However initial analysis indicates that the block is potentially more risky than initially thought. As the processing of the seismic data continues the details of the prospectivity will become clearer. The Company has until June 2008 to determine whether to commit to drill two exploration wells to secure a 50% interest in EA 5. 69 notes to the consolidated financial statements [22] DirEctOrS anD OFFicErS EMOluMEntS US$’000 except no. of share options YeAR bAse bonus otheR totAl outstAnding stoCK options stoCK AppReCiAtion Rights tReAsuRY stoCK directors W. David Lyons (i) Chairman Peter R. Clutterbuck (i) President and CEO Nigel A. Friend (i) Vice President and CFO John Patterson (i) Non Executive Director James Smith (i) Non Executive Director David W. Ross Non Executive Director Robert Spence Non Executive Director Other Pierre Raillard (ii) Vice President Operations 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 23 19 452 406 334 283 49 30 350 8 – – 16 241 182 – 75 55 – – – – – – – – – – – – – 23 19 452 481 334 338 49 30 1,000,000 1,000,000 490,000 300,000 265,000 180,000 125,000 50,000 – – – – 90,000 – – – – – – – – – – – 350 300,000 300,000 133,333 8 0 – – – 75,000 – – 16 50,000 – – – – – 0 – – – – – 0 200,000 200,000 65 30 241 277 325,000 200,000 (i) The ‘Base compensation’ for W.D. Lyons, P.R. Clutterbuck, N. Friend, J. Smith, J. Patterson and R. Spence are in respect of consultancy fees. (ii) During the year, Songas paid the Company a fixed cost of US$30,000 (2006: US$28,650) per month as a recharge for the time spent of Pierre Raillard and other staff for work undertaken on operating the gas processing plant and maintaining the wells. FORwaRd lOOkInG StatEMEntS This disclosure contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Orca Exploration’s control, including the impact of general economic conditions in the areas in which Orca Exploration operates, civil unrest, industry conditions, changes in laws and regulations including the adoption of new environmental 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 regulatory authorities. In addition there are risks and uncertainties associated with oil and gas operations, therefore Orca Exploration’s actual results, performance or achievement could differ materially from those expressed in, 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 Orca Exploration will derive therefrom. FOR FuRthER InFORMatIOn PlEaSE cOntact: Nigel A. Friend, CFO +255 (0)22 2138737 nfriend@orcaexploration.com Peter R. Clutterbuck, CEO +44 (0) 7768 120727 prclutterbuck@orcaexploration.com t r o p e r l a u n n a 7 0 0 2 • C N I I P U O r G N O T A r O L P x E A C r O Corporate Information Board of Directors w. daVId lyOnS Non-Executive Chairman St. Helier Jersey PEtER R. cluttERbuck President & Chief Executive Officer Haslemere United Kingdom nIGEl a. FRIEnd Chief Financial Officer London United Kingdom JOhn PattERSOn Non-Executive Director Nanoose Bay Canada daVId ROSS Non-Executive Director Calgary Canada JaMES SMIth Vice President Exploration Hurst United Kingdom Officers PIERRE RaIllaRd Vice President Operations daVId w. ROSS Company Secretary Operating Office Registered Office Investor Relations ORca ExPlORatIOn GROuP Inc. P.O. Box 3152, ORca ExPlORatIOn GROuP Inc. Barclays House, 5th Floor Ohio Street, P.O. Box 80139 road Town Dar es Salaam Tanzania Tel: + 255 22 2138737 Fax: + 255 22 2138938 Tortola British Virgin Islands nIGEl a. FRIEnd Chief Financial Officer Tel: + 255 22 2138737 nfriend@orcaexploration.com www.orcaexploration.com International Subsidiaries 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 ORca ExPlORatIOn (VEntuRES) Inc. ORca ExPlORatIOn uGanda (hOldInG) Inc. ORca ExPlORatIOn uGanda Inc PaE PanaFRIcan EnERGy cORPORatIOn 1st Floor Cnr St George/Chazal Streets P.O. Box 3152 Port Louis Mauritius Tel: + 230 207 8888 Fax: + 230 207 8833 road Town Tortola British Virgin Islands Engineering Consultants Auditors Lawyers McdanIEl & aSSOcIatES cOnSultantS ltd. Calgary Canada kPMG llP Calgary Canada buRnEt, duckwORth & PalMER llP Calgary Canada Transfer Agent cIbc MEllOn tRuSt tRuSt cOMPany Toronto, Montreal and Calgary Canada www.orcaexploration.com www.oRCAexploRAtion.Com