Orchid Island Capital
Annual Report 2006

Plain-text annual report

cover_sd:Layout 1 5/3/07 9:59 PM Page 1 growth w w w . o r c a e x p l o r a t i o n . c o m cover_sd:Layout 1 5/3/07 9:59 PM Page 2 Orca Exploration Group Inc. is a well-financed, international public company engaged in hydrocarbon exploration, development and marketing. The Company’s operations 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. At the Company’s Annual General Meeting 17 November 2006, shareholders approved a name change from EastCoast Energy Corporation to Orca Exploration Group Inc. 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 ($US), unless otherwise noted. 2 President & CEO’s Letter to Shareholders 8 Operations Review 25 Management’s Discussion and Analysis 56 Management’s Report to Shareholders 57 Auditors’ Report 58 Financial Statements 62 Notes to the Consolidated Financial Statements 76 Corporate Information s Cover Photo: A rig on contract to Orca Exploration is drilling a new production well in the Songo Songo field. When completed SS-10 is expected to increase field deliverability by 50 mmscf/d. annual 2006.qxp 5/3/07 10:37 PM Page 1 Financial and Operating Highlights Year ended 31 December 2006 2005 Change Financial (US$’000 except where otherwise stated) Revenue 13,828 5,759 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$) 4,261 2.45 20,678 20,430 953 2.11 3,198 2,211 37,889 16,662 0.11 0.10 0.02 0.02 Funds from operations before working capital changes 6,030 2,268 140% 347% 16% 547% 824% 127% 450% 400% 166% Funds per share from operations before working capital changes – basic (US$) 0.26 0.10 160% Funds per share from operations before working capital changes – diluted (US$) 0.24 0.09 167% Outstanding Shares (‘000) Class A shares Class B shares Options Operating Additional Gas sold – industrial (mmscf) Additional Gas sold – power (mmscf) Average price per mcf – industrial (US$) 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 1,751 1,751 25,023 21,513 2,022 1,987 1,466 3,371 8.22 1.90 266 149 415 109.0 158.7 777 1,672 7.07 1.66 241 79 320 67.7 83.8 – 16% 2% 89% 102% 16% 14% 10% 89% 30% 61% 89% G L O S S A R Y Mcf t Thousands of standard cubic feet Mmscf t Millions of standard cubic feet Bcf t Billions of standard cubic feet Tcf t Trillions of standard cubic feet Mmscf/d t Millions of standard cubic feet per day 1P t Proven reserves 2P t Proven and probable reserves 3P t Proven, probable and possible reserves GIIP t Gas initially in place Kwh t Kilowatt hour MW t Megawatt US$ t US dollars Cdn$ t Canadian dollars 2006 ANNUAL REPORT 2 President & CEO’s Letter to Shareholders 2006 was another good year for Orca Exploration Group Inc. (formerly EastCoast Energy Corporation). The Company continued development of the Songo Songo gas field in Tanzania with positive results. Reserves have increased, a substantial development programme is underway, sales are ahead of forecast and markets continue to grow as significant gas-fired generation is installed at Dar es Salaam over the next 12 months. The Company has also developed a strengthened exploration capability through the recruitment of key individuals with substantial international oil and gas experience especially in West Africa. Building on this, the Company has indicated its intention to identify and acquire oil opportunities by the end of 2007 as well as continuing to develop its existing business in Tanzania. During 2006 Orca Exploration delivered substantial performance results in all key areas. a Increased profit before tax by 347% to US$4.3 million (2005: US$1.0 million) and funds flow from operations before working capital changes by 166% to US$6.0 million. a Produced 18.0 bcf from the Songo Songo field (2005: 14.7 bcf), increasing the volume produced since the commencement of commercial operations in 2004 to 37.3 bcf. Over 2006 Orca Exploration did not record any downtime that impacted gas supply to major customers. a Increased the certified gross proved (1P) and proved and probable (2P) recoverable Additional Gas reserves by 10% to 266 bcf and 30% to 415 bcf respectively. a Expanded the Company’s industrial gas distribution network to 28 kilometers by constructing 3 kilometers of new pipeline. a Commenced gas sales to six new industrial customers and increased annual sales to the industrial sector by 89% to an average of 4.0 mmscf/d. a Signed a two-year contract to sell Additional Gas to the 48 MWs of emergency power generation operated by Aggreko plc at Dar es Salaam. In 2006 sales to the power sector increased 102% to an average of 9.2 mmscf/d. a Initiated remedial downhole work on SS-9 to increase Songo Songo production by 30 mmscf/d. This was successfully completed in Q1 2007. a Negotiated a contract for the drilling of a new Songo Songo develop ment well (SS-10) to further increase production capability in 2007. a Raised Cdn$21.5 million gross through a fully subscribed one-for- seven rights offering of 3.3 million Class B shares. Market Development The power and industrial markets continue to develop in line with expectations with a 102% and 89% increase in volumes respectively. During 2006 average gas sales increased 98% to 13.3 mmscf/d. By Q4 2006 Additional Gas sales had increased to 17.4 mmscf/d (industrial sector 4.3 mmscf/d, power sector 13.1 mmscf/d) as a result of the installation of some emergency power plants. Industrial and power demand is expected to increase further as new gas fired generation is installed. Opposite t Orca has entered into negotiations with Songas and TANESCO for the installation of a third and fourth gas processing train at the Songo Songo Island gas plant. During 2006 the lower than average rainfalls experienced for the This emergency generation is now forecast to be operational until last three years severely impeded TANESCO’s ability to operate at least the end of 2008. In addition, a Wärtsilä 100 MW unit is its 561 MWs of installed hydro generation capacity at normal still on target to be operational by the end of Q3 2007 and a levels. This restriction, combined with an increase in overall new 45 MW plant at Tegeta in Dar es Salaam is forecast to be demand for electricity, led to a significant shortfall in power operational by mid-2008. If the Dowans emergency units remain generation and the need to load shed for up to 14 hours a day. in country after the end of 2008, the conversion of the 100 MW The Government of Tanzania and TANESCO moved swiftly to IPTL plant (that currently uses heavy fuel oil) may be delayed. rectify the problem and entered into two contracts with Aggreko As a result of the acceleration of the installation of the plc (“Aggreko”) and Dowans Tanzania Limited (“Dowans”) for emergency units the Company may be supplying Additional Gas the supply of 140 MWs of temporary gas-fired generation. to up to 310 MWs of power generation (including 42 MWs of Aggreko fulfilled its obligations in October 2006 with the startup existing generation at the Ubungo Power Plant) by the end of of 40 MWs of generation (48 MWs installed). Dowans was 2007. At a peak, these units would require approximately 68 contracted to supply the remaining 100 MWs. A 20 MW mmscf/d (or 41 mmscf/d at a 60% utilisation rate). temporary generator was installed in January 2007 and a further 60 MWs is currently being assembled and should be operational during Q3 2007. A final 40 MWs is being shipped to Tanzania and is expected to be installed during Q4 2007. This will increase the total installed emergency generation to 168 MWs, of which the suppliers are obligated to supply 140 MWs. 2006 ANNUAL REPORT 4 PRESIDENT & CEO’S LETTER TO SHAREHOLDERS The Company is negotiating a long term portfolio contract with the electricity utility, TANESCO, for the supply of gas to these units. TANESCO is in the process of determining their volume requirements given the improved hydrology in the country. A contract is forecast to be in place in the next three months. Whilst Tanzania will have significant gas fired generation in country by December 2007, above average rainfall in January 2007 (thought to be attributable to El Nino) significantly changed the outlook for the 561 MWs of Tanzania’s installed hydro generation. The Mtera dam which supplies water to the 80 MW Mtera and the 204 MW Kidatu hydro stations, rose from a non operational level of 687 meters above sea level to its maximum capacity of 698 meters. As a result, it is antic- ipated that these hydro units will have sufficient water to run at high utilisation rates during 2007 and 2008. The remaining 277 MWs of hydro generation is “run of river” and will only be available for four to five months of a year based on average rainfalls. Accordingly, the Company is forecast- ing that sales to the power sector will average approximately 15 - 20 mmscf/d during 2007. Whilst the power sector provides a solid base load of gas sales, the Company is embarking on an aggressive programme to increase sales to the industrial sector. The Company now has 13 indus- trial customers in 15 locations. A 16-kilometer expansion of the existing 28-kilometer distribution system is planned for 2007 at a cost of US$4.5 million. It is forecast that this will increase indus- trial sales to 7.5 mmscf/d by the end of 2007. In addition, the Company, in conjunction with TPDC, is planning to commence the sale of Compressed Natural Gas (“CNG”) by Q1 2008. The intention is to transport CNG to industrial customers and markets that are not located near the existing distribution pipeline. This could be an exciting new market that has the potential to develop to over 10 mmscf/d in the coming years. The Company is also looking at constructing high pressure pipelines to other industrial towns in Tanzania including Tanga and Morogoro. Whilst the infrastructure costs will be high and will take at least two years to develop, the netbacks will be better than sales to the power sector at current oil prices. The Company is also reviewing the possibility of applying for an electricity generation licence and selling power directly to industrial customers. This will be progressed during 2007. Infrastructure Planning was initiated in 2006 to expand the infrastructure to meet this forecast increase in demand. The Company commissioned Petrofac Engineering Limited to undertake a capacity re-rating and debottlenecking review of the existing Songo Songo gas processing plant to determine how to meet immediate and future projected demands. As a result of this work, Songas Limited (“Songas”) appointed Bureau Veritas to re-rate the gas plant capacity. Whilst work is ongoing and this is still to be agreed with the insurers, the indications are that the gas process- ing plant could be run at 85 mmscf/d for a short period of time compared with its present nameplate capacity of 70 mmscf/d. The Company also entered into discussions with Songas and TANESCO for the installation of a third and fourth gas processing train. This would lead to in excess of 140 mmscf/d of gas processing capacity. A Memorandum of Understanding (‘MOU’) was signed with Songas, TANESCO and the Ministry of Energy and Minerals in December 2006 identifying the key issues that needed to be addressed to enable the expansion to take place. Under the terms of the MOU, Orca Exploration will continue to pay 17.5% of the achieved sales price of gas and part of this will be allocated to Top u Welders connect a pipeline to supply “Additional Gas” to an emergency power generation unit at Dar es Salaam. Bottom u The Aggreko 48 MW generation units rely on “Additional Gas” supplied by Orca Exploration. Songas to compensate for their investment in the trains. This is Exploration still the subject of an application by Songas to the Electricity, Water, Utilities Regulatory Authority (‘EWURA’) and is also subject to the agreements of gas terms and prices with TANESCO to justify the expansion. The capacity of the 232-kilometer pipeline system to Dar es Salaam is estimated at 105 mmscf/d and is limited by the 12” 25-kilometer offshore line. Additional compression or a new offshore pipeline may be required during 2008/2009 to meet peak loads. Work will be undertaken in 2007 to assess the most cost effective means of achieving the forecast peak rates. Reserves Increase The Songo Songo reservoir continues to perform above expecta- tions. During the year, further pressure testing has generated positive results. The independent reserves engineers, McDaniel & Associates Consultants Ltd, have reviewed all the data and have assessed that the gross proven and probable reserves (“2P”) for Reserves and deliverability need to be ahead of demand so that commitments to power and infrastructure developments can be planned with greater certainty. The Company continues to review ways of increasing the reserve base. The drilling of the Songo Songo West prospect approxi- mately 2 kilometers west of the existing Songo Songo field is an excellent target and the Company intends to drill at least one well on this location as soon as practicable. The well could be drilled using a jack up rig or a land rig from the same artificial island that may be used to drill Songo Songo North. Work is currently being undertaken to assess the feasibility of this approach as well as identifying a suitable jack up rig. The Company relinquished seven Adjoining Blocks neighbouring the Songo Songo field during the year as the only identified lead was considered small and expensive to drill and therefore less attractive than the Songo Songo West prospect. the total field on a life-of-licence basis increased by 14% to 648 New Ventures The Company recruited several key individuals in 2006 including James Smith who was integral to the growth of PanOcean Energy Corporation. The Company is now evaluating several oil oppor- tunities in sub Saharan Africa with a view to acquiring exploration and/or development assets by the end of 2007. bcf (2005: 569 bcf). The proportion in which the Company has a financial interest, under the Songo Songo PSA (“Additional Gas”), increased by 30% to 415 bcf (2005: 320 bcf). A majority of the 2P reserves can be delivered from the existing well stock. However, to deliver all the reserves will require signif- icant capital expenditure over the next five years. This includes the drilling of a well in the northern portion of the field (“Songo Songo North”) which will require a jack up rig or the drilling of a deviated well using a land rig from an artificial island. To meet immediate forecast deliverability requirements, the Company signed a drilling contract with Caroil SA in February 2007 and commenced the drilling operations in April 2007. The well is being drilled with a land rig on Songo Songo Island and will deviate 1 kilometer offshore into the main reservoir. It should be completed by mid June 2007 and is forecast to add deliverability of 50 mmscf/d. In addition, the Company successfully completed the removal of over 5,000 feet of wireline and two pressure gauges that were left in the hole in 1997 and which were severely impacting the deliverability of the SS9 well. The deliverability has subsequently increased from 20 mmscf/d to a maximum of 50 mmscf/d. The cost of the remedial work was US$1.9 million. 2006 ANNUAL REPORT 6 PRESIDENT & CEO’S LETTER TO SHAREHOLDERS 2007 Targets Over 2007, the Company will continue to focus on growth, with an increasing emphasis on new project development. a Negotiate and sign a number of long term contracts to supply gas for use in the 120 MWs of gas fired plants owned and operated by Dowans, the 100 MW Wärtsilä plant, the 45 MW Wärtsilä plant at Tegeta and the 42 MW plant that is operational at the Ubungo Power Plant. a Expand sales to the industrial markets to 6-7 mmscf/d by Q4 2007 through the construction of an additional 16 kilometers of the Company’s low pressure distribution system. a Prepare for the commencement of CNG sales to industrial and retail customers who are not located along existing pipeline infrastructure and assess feasibility for the supply of electricity direct to industrial customers. a Finalise drilling plans for the Songo Songo West exploration well and the Songo Songo North appraisal well. a Increase the 2007 deliverability of the Songo Songo gas field from 130 mmscf/d at 31 December 2006 to approximately 210 mmscf/d as a result of the remedial work on SS-9 and the drilling of a new development well, SS-10. a Farm-in, licence or acquire high potential oil properties with significant exploration potential. Over the past two and one half years, the Company has exceeded its targets. This achievement has been made possible by all those who have stood with us and helped us to achieve the results that this Annual Report presents. We have relied on the investment of our shareholders; the skill, dedication and innovative spirit of our employees; the wise counsel of our Board of Directors; the commitment of our partners; the support of our customers and in particular the opportunities provided to us by the Government of Tanzania. Our commitment to growth is based on clear goals, the necessary resources and a deter- mination to succeed. There is much to be done as we continue to grow through 2007. Peter R. Clutterbuck President & CEO 30 April 2007 Top u A land rig was erected on Songo Songo Island in March 2007 to drill SS-10, a new development well that is expected to substantially increase field deliverability. Opposite t Additional Gas supplied by Orca Exploration feeds emergency power units. 2006 ANNUAL REPORT 8 OPERATIONS REVIEW Operations Review Production ops1 ops2 ops3 ops3 During 2006, 18.0 bcf (2005: 14.7 bcf) of gas was produced from the Songo Songo field offshore Tanzania or an average of 49.3 mmscf/d (2005: 40.3 mmscf/d). This brings total production since Cumulative production from each well Protected Gas Volumes Gross Additional Gas reserves on a life of licence basis 2007 build up of gas fired generation not sure Average daily production per month in 2006 commercial operations commenced on 20 July 2004 to 37.3 bcf. Production peaked at 66 mmscf/d in December 2006. 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 f c B supply of gas to major customers in Dar es Salaam. Songo Songo wells The production from the five Songo Songo wells was as follows: Well SS-3 SS-4 SS-5 SS-7 SS-9 Total 2004 2005 2006 Bcf 0.8 0.6 1.7 1.5 – 4.6 Bcf 1.3 1.9 3.9 3.8 3.8 Bcf 1.5 1.9 8.9 3.2 2.5 14.7 18.0 The total gas production from the Songo Songo field was allocated as follows: md2 2006 Additional Gas industrial and power sales volumes 2004 Bcf 4.1 0.1 0.4 4.6 2005 Bcf 11.9 2.5 0.3 14.7 2006 Bcf 13.0 4.8 0.2 18.0 700 Protected Gas sales Additional Gas sales Flare, generator at the processing plant and line pack 600 Total 500 400 300 narrower copy of below 200 100 0 J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c Industrial Power Total Bcf 3.6 4.4 14.5 8.5 6.3 37.3 Total Bcf 29.0 7.4 0.9 37.3 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 0 0 0 $ S U f c s M M 700 600 500 400 300 200 100 0 16 14 12 10 8 6 4 2 0 SS-3 SS-4 SS-5 SS-7 SS-9 2004 2005 2006 2004 2005 2006 J a n F e b M a r c h A p r i l M a y J u n e J u l y A u g S e p O c t N o v D e c Month Wazo Hill Ubungo Power Plant d / f c s M M 56 54 52 50 48 46 44 42 40 200 s W M 150 350 300 250 100 50 0 3 1 - D e c - 0 6 Q 1 2 0 0 7 Q 2 2 0 0 7 Q 3 2 0 0 7 Q 4 2 0 0 7 Ubungo 42 MW Aggreko 48 MW Dowans 20 MW Dowans 60 MW Wartsila 100 MW Dowans 40 MW 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990 14000 12000 10000 f c s m M 8000 6000 4000 2000 0 Probable Proven 300 f c b 500 400 200 100 0 2007 4 0 0 2 2 0 0 5 2006 ) s r e t e m ( l e v e l a e s e v o b a l e v e L 700 699 698 697 696 695 694 693 692 691 690 689 688 687 f c s M M 200 180 160 140 120 100 80 60 40 20 0 md1 Revenue md4 2006 Additional Gas Prices Power Industrial Opposite y A major workover of the SS-9 offshore well was completed in early 2007. 2006 ANNUAL REPORT f c m / $ S U 10 9 8 7 6 5 4 3 2 1 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2005 2006 J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c md2 md3 2006 Additional Gas industrial and power sales volumes 2006 Additional Gas industrial sales Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Industrial Power Nampak Nida ECO&F Bora Murzah III Murzah II Murzah I Lakhani Mukwano TCC Chinese ALAF TBL Kioo Karibu 700 699 698 697 696 695 694 693 692 691 690 689 688 687 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 10 OPERATIONS REVIEW 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 (“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. Over the year ended 31 December, 2006, the Protected Gas utilisation rate was 80% (2005: 73%). The Protected Gas was allocated as follows: Year ended 31 December Protected Gas Volumes Protected Gas user Ubungo Power Plant Wazo Hill Cement Plant Village Electrification Programme Total consumption 2006 Protected Gas consumed Utilisation rate 2005 Utilisation rate Bcf mmscf/d 11.4 31.3 1.6 – 4.3 – 13.0 35.6 % 81 73 – 80 % 74 73 – 73 Protected Gas utilisation in 2006 at the Ubungo Power Plant increased primarily because the fifth turbine was operational from March 2005 and the severe drought in Tanzania in 2006 required the turbines to be dispatched at higher rates. There was some considerable downtime at the plant caused by problems with the 34 MW fifth and 42 MW sixth turbines in September 2006. Since commercial operations commenced, the Protected Gas utilisation at the Ubungo Power Plant has been 76%. At the Wazo Hill Cement Plant, the monthly utilisation ranged from 52% to 86% over 2006 and averaged 73% (2005: 73%). This plant is intending to expand its capacity in 2009 and this should lead to some Additional Gas sales. Since commercial operations commenced, the Protected Gas utilisation at the Wazo Hill cement plant has been 68%. The Village Electrification Program was not operational in 2006 and is now due to commence in the second half of 2007. The maximum gas required for the Protected Gas users over the remaining 17 years and seven months of the Gas Agreement was reduced to 289 bcf as at 31 December 2006. For the purposes of calculating the level of gas available as Additional Gas, an assumption has to be made as to the expected utilisation of the Protected Gas over the remaining term of the Gas Agreement. 2004 2005 2006 These assumptions are reviewed on an annual basis based on historic and projected usage. The Protected Gas users and their forecast maximum and most likely demand are as follows: f c s m M 14000 12000 10000 8000 6000 4000 2000 0 Wazo Hill Ubungo Power Plant Protected Gas consumer Six gas turbines at the Ubungo Power Plant Theoretical maximum 100% load factor Mmscf/d Most likely Mmscf/d Utilisations in 2006 Mmscf/d 47.4 (9.2) 38.2 5.9 1.0 45.1 38.9 (7.6) 31.3 4.3 1.0 36.6 38.9 (7.6) 31.3 4.3 – 35.6 Less gas supplied to the sixth turbine which is Additional Gas Total Protected Gas at Ubungo Wazo Hill Cement Plant Village Electrification Programme Total daily Protected Gas demand Protected Gas Reserves to end of the Songas power purchase agreement (Bcf) 289 233 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 plant. The ‘most likely’ utilisation including the village electrification programme is forecast to be 81% over the remaining term of the Gas Agreement. This compares with an actual utilisation rate of 80% in 2006 and a cumula- tive utilisation of 73% since commercial operations commenced. Additional Gas 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 marketed as Additional Gas. The details of the 2006 Additional Gas sales are set out under ‘Markets’ below. Flare, generator and line pack requirements A relatively small amount of gas is required to be 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 loss of gas each year. 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 a day of Protected and Additional Gas sales in Dar es Salaam. Songo Songo field During 2006, Orca Exploration focussed on utilising the 2005 remapping and reservoir geology studies combined with pressure data from the wells to construct a series of numerical simulation models to assist in evaluating subsurface sensitivities, in planning gas offtake rates and in fore- casting likely future investments to maintain and increase deliverability. Songo Songo remapping In 2005, geophysical work concentrated on reviewing 569 kilometers of reprocessed 2D seismic and 212 kilometers of newly acquired 2D seismic gathered over the main Songo Songo field. In 2006, this new and reprocessed dataset has allowed a considerably improved subsurface mapping which has been integrated with petrophysical analyses of the wells, revised biostratigraphic corre- lation and evaluation of core data to create a detailed, static reservoir model for each of the two main reservoir intervals in the field. The assessed GIIP is consistent with the values of GIIP used by McDaniel & Associates Consultants Ltd. (“McDaniel”) in their independent reserve evaluation. During Q1 2007, 30 kilometers of transition zone seismic was shot primarily over the northern aspect of the Songo Songo field. This is currently being interpreted. Reservoir surveillance and management In 2006, the Company continued to acquire excellent information on the Songo Songo field from the down hole gauges that were installed in all wells (except SS-9). These highly accurate gauges record pressure changes and allow the Company to estimate the volume of gas in contact with each well and to calibrate dynamic models to optimise production strategies. The pressure gauges were most recently retrieved from the wells during December 2006 and will be re-installed to allow further evaluation in 2007. Additionally, it is intended to install gauges in SS9 now that the downhole debris has been removed. Top u Gas piping at Songo Songo Island feeds well production to the gas plant for processing and compression. Bottom u Large manufacturing operations, like Nida Textiles, are befitting from the availability of natural gas to replace the use of fuel oil. 2006 ANNUAL REPORT 12 OPERATIONS REVIEW Above u TANESCO’s Ubungo plant at Dar es Salaam produces electrical power from six units. Shown above is UGT6, the most recent addition to the plant. 19.5% of the natural gas used at Ubungo is Additional Gas supplied by Orca Exploration. annual 2006.qxp 5/3/07 10:37 PM Page 13 To predict the well performance and allow planning of gas offtake and future deliverability investments such as wells and wellhead compression, the static reservoir model was imported into reservoir simulation software to history match production rates and pressures recorded for each well. A good match has been obtained with the static GIIP determined in the geological and geophysical model, leading to confidence in the simulation model as a reservoir management tool. Future work will focus on analysing the pressure transients obtained from production and the downhole pressure data, and the incorporation of these data into revised material balance models. 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 compartmentalisation, if any. So far, the pressure behaviour of the wells is not showing evidence of any material compartmentalisation or aquifer influx, and pressure data suggests a likely GIIP towards the upper end of the Company’s computed range. Based on preliminary reservoir material balance calculations, the field’s GIIP was computed in 2005 to be 1,080 bcf (most likely) to 1,224 bcf, dependent on aquifer behaviour. Orca Exploration’s 2006 evaluation of static GIIP ranges from 1,071 to 1,184 bcf (including the northern portion of the field which may not be drained by the existing well stock) and compares favourably with the 1,215 bcf computed by McDaniels in its independent reserve report as at 31 December 2006 for the 3P case. 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 communication with other wells. There is the possibility that SS-7 may be partially isolated from the other wells and this will continue to be monitored during 2007, although compartmentalisation is not expected to be material. The flow rates of the wells 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 (Note 1) Total Maximum Protected Gas demand Available for Additional Gas Well flow rates (mmscf/d) 1997 initial capacity 31 December 2005 capacity 31 December 2006 capacity 10 10 60 20 40 140 (45) 95 18 17 63 22 25 145 (45) 100 16 12 62 20 20 130 (45) 85 Note 1: Remedial work was performed on SS-9 subsequent to the year end. This led to an increase in its maximum deliverability to 50 mmscf/d. 2006 ANNUAL REPORT 14 OPERATIONS REVIEW The Songo Songo wells showed an 8% decline over the course of 2006, in line with or slightly better than expectations. With the inclusion of productivity arising from remedial work on SS-9, performed after year-end, the deliverability is sufficient to enable 115 mmscf/d of Additional Gas production above the peak demand for Protected Gas. This will allow the Company to produce more than 50 mmscf/d of Additional Gas for a period of time even if the largest well, SS-5, becomes unavailable at peak demand. Because of the possibility of interference between producing wells, this sort of flow rate with the largest well off-line is unlikely to be sustainable over the medium term. Additional 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 2007 that assessed not sure the Orca Exploration natural gas reserves based on information on the Songo Songo field as at ops3 31 December 2006 (the “McDaniel Report”). 2007 build up of gas fired generation Average daily production per month in 2006 Over the course of 2006, there has been a 10% increase in Songo Songo’s gross 1P reserves from 240.6 bcf to 265.8 bcf despite Additional Gas sales of 4.8 bcf being produced in 2006. Gross 2P 350 56 reserves increased 30% from 320.0 bcf to 415.1 bcf. The reserves summary to the end of the license period (October 2026) for the gross Additional Gas was as follows: 54 300 Songo Songo Additional Gas reserves to October 2026 (Bcf) Independent reserves evaluation 250 Proved producing Proved undeveloped 200 Total proved (1P) Probable s W M Total proved and probable (2P) 150 2006 Gross (1) 2006 Net (2) 52 2005 Gross 219.5 46.3 265.8 149.3 415.1 129.4 56.0 d / f 185.4 c s M M 98.9 284.3 50 48 179.9 60.7 240.6 79.4 320.0 2005 Net 108.5 44.0 152.5 72.3 224.8 (1) Gross reserves are based on 100% of the property’s gross Additional Gas reserves (excluding Protected Gas). (2) Net reserves are based on the Company’s share of the Cost Gas and Profit Gas revenues. 46 The McDaniel Report has assumed that TPDC will exercise their right to ‘back in’ to the field devel- 44 100 opment 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. This impacts the net reserves. The implications and workings of the ‘back in’ are still to be discussed in detail with TPDC. 42 40 For the purpose of calculating the gross Additional Gas reserves, McDaniel has assumed that 233 bcf or an average of 13.4 bcf per annum will be required to meet the demands of the Protected A u g J u l y S e p F e b J a n O c t M a y J u n e N o v D e c M a r c h A p r i l Gas users from 1 January 2007 to October 2026. This compares with 249 bcf as at 1 January 2006. Month 3 1 - D e c - 0 6 Q 1 2 0 0 7 Q 2 2 0 0 7 Q 3 2 0 0 7 Q 4 2 0 0 7 During 2006 Protected Gas users consumed 13.0 bcf. 50 0 Ubungo 42 MW Aggreko 48 MW Dowans 20 MW Dowans 60 MW Wartsila 100 MW Dowans 40 MW 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990 md2 2006 Additional Gas industrial and power sales volumes 700 600 500 400 300 200 100 0 narrower copy of below J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c Industrial Power f c s m M 14000 12000 10000 8000 6000 4000 2000 0 f c m / $ S U 10 9 8 7 6 5 4 3 2 1 0 f c B 16 14 12 10 8 6 4 2 0 0 0 0 $ S U 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 f c s M M 700 600 500 400 300 200 100 0 ops1 ops2 ops3 Cumulative production from each well Protected Gas Volumes Gross Additional Gas reserves on a life of licence basis Probable Proven 500 400 300 f c b 200 100 0 2004 2005 2006 Wazo Hill Ubungo Power Plant SS-3 SS-4 SS-5 SS-7 SS-9 2004 2005 2006 md1 Revenue md4 2006 Additional Gas Prices Power Industrial 2007 4 0 0 2 2 0 0 5 2006 ) s r e t e m ( l e v e l a e s e v o b a l e v e L 700 699 698 697 696 695 694 693 692 691 690 689 688 687 f c s M M 200 180 160 140 120 100 80 60 40 20 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2005 2006 J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c md2 md3 2006 Additional Gas industrial and power sales volumes 2006 Additional Gas industrial sales Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Industrial Power Nampak Nida ECO&F Bora Murzah III Murzah II Murzah I Lakhani Mukwano TCC Chinese ALAF TBL Kioo Karibu 700 699 698 697 696 695 694 693 692 691 690 689 688 687 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec annual 2006.qxp 5/3/07 10:37 PM Page 15 The principal assumptions used by McDaniel in its evaluation of the Tanzanian PSA are as follows: Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Gross Additional Additional Gas price Gas volumes 1P 1P Gross Additional Additional Gas Price Gas volumes 2P 2P Brent crude Annual inflation US$/BBL US$/mcf mmscf/d US$/mcf mmscf/d % 60.5 59.2 57.7 56.3 54.6 55.8 56.8 58.0 59.2 60.3 61.6 62.8 64.1 65.3 66.7 68.0 69.4 70.8 72.2 73.6 3.65 3.43 3.34 3.42 3.56 3.64 3.72 3.80 3.89 3.98 4.19 4.31 4.41 4.51 4.61 4.71 4.82 4.93 5.04 5.15 21.0 33.0 45.0 52.5 55.0 55.0 55.0 55.0 55.0 55.0 50.0 36.0 36.0 25.8 17.0 9.4 2.9 15.6 29.1 25.0 3.52 3.38 3.25 3.23 3.36 3.54 3.62 3.71 3.79 3.87 3.96 3.82 4.25 4.35 4.45 4.55 4.65 4.76 4.86 4.97 23.0 39.0 56.5 74.5 77.5 80.0 80.0 80.0 80.0 80.0 80.0 75.0 55.0 55.0 41.8 30.5 28.8 30.8 42.0 35.9 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Additional Gas reserves reconciliation Bcf Gross Gross proved proved and probable Net Net proved proved and probable Reserves at 1 January 2006 240.6 320.0 152.5 224.8 Extensions Improved recovery Technical revisions Discoveries Acquisitions Dispositions Economic factors Production – – – – – – – – 30.0 99.9 35.2 62.7 – – – – – – – – – – – – – – – – (4.8) (4.8) (3.2) (3.2) Reserves at 31 December 2006 265.8 415.1 184.5 284.3 There was no drilling activity on the Songo Songo field during 2006. The increase in the proven and probable reserves has arisen from improved volumetric structural mapping, the 2006 pressure and gas production data and the acceleration of field depletion through greater capital expenditure. Above u Natural gas deliverability was increased in early 2007 by the workover of the SS-9 well offshore Songo Songo Island. 2006 ANNUAL REPORT 16 OPERATIONS REVIEW It is expected that the 2007 work program, including the acquisition of 30 kilometres of 2D transitional zone seismic will help to delineate the structure to the north of the field. Present value of reserves The estimated value of the Songo Songo reserves based on the assumptions on production and pricing are as follows: US$ millions Proved producing Proved undeveloped Total proved (1P) Probable 2006 10% 78.1 30.9 5% 113.5 41.4 154.9 109.0 86.8 49.7 15% 58.2 21.4 79.6 28.9 5% 76.4 26.7 103.1 38.1 Total proved and probable (2P) 241.7 158.7 108.5 141.2 2005 10% 47.4 20.3 67.7 16.1 83.8 15% 33.4 13.8 47.2 7.1 54.3 The present values are primarily higher in 2006 due to the increase in the reserves and the fact that there has been an increase in the forecast capital expenditure which has the effect of deferring the time when Additional Profits Tax becomes payable. 2007 Development Programme At the end of 2006, a total of 90 MWs (UGT 6: 42 MWs and Aggreko: 48 MWs) of gas fired gener- ation was operational in Tanzania. During the course of 2007, it is anticipated that an additional 220 MWs will be introduced onto the system taking the maximum capacity in country to 310 MW. At full load, 310 MWs would require approximately 68 mmscf/d (or 41 mmscf/d at a 60% utilisation rate) of Additional Gas. To ensure there is adequate deliverability to meet any potential gas demand, the Company has commenced a programme to increase the current deliverability from 130 mmscf/d (85 mmscf/d available for the Additional Gas) to a forecast 210 mmscf/d (165 mmscf/d for Additional Gas). This is to be achieved by some remedial work on SS-9 and the drilling of a development well, SS-10. In January 2007, the Company commenced a US$1.9 million 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 has now been successfully completed with the result that the maximum flow rate has increased from 20 mmscf/d to an estimated 50 mmscf/d. The Company has signed a contract with Caroil SA for the drilling of a development well, SS-10. The well will be drilled with a land rig from the Songo Songo Island. It will deviate one kilometre offshore into the main reservoir. The well was spud in April 2007 and is forecast to be complete by mid June 2007. This well is forecast to cost in the range of US$11-US$13 million in 2007. During the year the Company purchased sufficient long lead items to drill a second well. The lead items will be stored on Songo Songo Island until required for additional drilling activity. The Company forecasts that another development well will be drilled in 2008/2009 and will commence planning in 2007. This could either be a deliverability well in the main Songo Songo field (similar to SS-10) or an appraisal well in the north of the field (“Songo Songo North”) which may not be drained by the existing well stock. Technically this well is more challenging, as it is several kilometers from the Songo Songo Island and in water depths that may require a jack up rig. Exploration At the beginning of the year, the Company was party to nine licences under the terms of the PSA with the Tanzanian Petroleum Development Corporation (“TPDC”), namely the two blocks within which the Songo Songo field lies (“Discovery Blocks”) and seven blocks in adjacent areas (“Adjoining Blocks”). During the year, the Company relinquished the Adjoining Blocks as the 377 kilometers of seismic that was shot in 2005 revealed only a small prospect with some uncertainty with the fault seal. Discovery Blocks During Q1 2006, a review of the seismic on the Discovery Blocks identified a promising prospect approximately 2 kilometers west of the existing Songo Songo field. This has been designated as Songo Songo West (“SSW”). The seismic on SSW indicates a tilted fault trap at the same reservoir interval (Neocomian) as the main field. Management has estimated the potential for this prospect as follows: Estimated Songo Songo West Minimum Most likely GIIP GIIP Maximum GIIP Bcf 90 Bcf 600 Bcf 1,070 The intention is to drill SSW as soon as practicable. SSW lies in 20 meters of water and the Company is currently considering the following drilling options: a a Drill the prospect with a jack up rig (recognising that there is a shortage of such rigs that are prepared to mobilise to East Africa); Construct a man made island on a reef within 2 kilometers of the prospect and then drill a deviated well utilising a land rig; a Use a rig mounted on a barge to drill near, or on location. These options are being evaluated with the view to drilling the well during 2008/2009. The total cost of drilling SSW is estimated at US$17 – US$20 million, with an additional US$4 million to complete. In addition, there would be substantial infrastructure costs to tie the well into the existing gas processing and pipeline system if successful. Nyuni “A” In September 2005, Orca Exploration entered into an agreement with Ndovu Resources Limited (“Ndovu”), a subsidiary of Aminex plc, to farm-in to part of its offshore Nyuni Production Sharing Agreement (“Nyuni PSA”) adjacent to the producing Songo Songo gas field. Orca Exploration acquired 328 kilometers of 2D seismic over Nyuni “A” in October 2005 taking advantage of the cost savings gained by extending the Songo Songo area 2D seismic program. A few small prospects were identified but were not considered of sufficient size to justify the Company electing by 30 September 2006 to drill a well in their licence acreage, when SSW in the Discovery Blocks had greater potential. In early 2007, Ndovu ran some additional transitional zone seismic over their licence acreage and in the prospective areas. The Company is still in discussions with Ndovu, but it is considered unlikely at this stage that the Company will participate in the drilling of two wells on their licence acreage. Above u A 2006 seismic program identified exploration opportunities for Orca Exploration on lands adjacent to the Songo Songo field. 2006 ANNUAL REPORT 18 OPERATIONS REVIEW Infrastructure The infrastructure that 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 approximately 70 mmscf/d, limited by the two gas processing trains that have a design specification of 35 mmscf/d each and the pipeline system that is assessed by Songas to have a capacity of 105 mmscf/d. The current forecasts indicate that peak loads of approximately 80 mmscf/d - 90 mmscf/d (including Protected Gas) will be required in 2007. Orca Exploration commissioned Petrofac Engi- neering Limited to undertake a capacity re-rating and debottlenecking review of the gas processing plant to assess how to meet the immediate and future projected demand. As a consequence of this work, Songas appointed Bureau Veritas to re-rate the capacity of the plant. Whilst work is ongoing and this is still to be agreed with the insurers, the indications are that the gas process- ing plant could be run at approximately 85 mmscf/d for a short period of time compared with its present nameplate capacity of 70 mmscf/d. The Company also entered into discussions with Songas and TANESCO for the installation of a third and fourth gas processing train. This would lead to in excess of 140 mmscf/d of gas processing capacity. A Memorandum of Understanding (‘MOU’) was signed with Songas, TANESCO and the Ministry of Energy and Minerals in December 2006 identifying the key issues that needed to be addressed to enable the expansion to take place. Under the terms of the MOU, Orca Exploration will continue to pay 17.5% of the achieved sales price of gas and part of this will be allocated to Songas to compensate for their investment in the trains. This is still the subject of an application by Songas to the Electricity, Water, Utilities Regulatory Authority (‘EWURA’) and is also subject to the agreements of gas terms and prices with TANESCO to justify the expansion. 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 tested. It is forecast that compression or a new offshore line will be required during the latter half of 2008 to meet peak loads. Work will be undertaken in 2007 to assess the most cost effective means of achieving the forecast peak rates. At Dar es Salaam, Orca Exploration continued to expand its distribution system during 2006. The 4 kilometer extension to Lakhani Industries Limited Textile and Murzah Oil Mills Limited was completed during Q1 2006 and a 3 kilometer extension was constructed to connect Serengeti Breweries and East Coast Oils and Fats Limited. The Company has committed to increase the capacity of the existing infrastructure system in the first half of 2007 by installing an additional pressure reduction station and constructing a further 8 kilometers of pipeline. This is required to meet the peak demand of the Company’s existing customers between June and September 2007. In addition, the Company forecasts that a further 8 kilometer extension to the Mwenge area will be installed during Q4 2007 adding an additional 1-2 mmscf/d of load. The forecast cost of the capex required in 2007 for the industrial expansion is US$4.5 million. During 2006, the Company connected 68 MWs of emergency power generation at a cost of US$0.8 million. Markets Current Industrial Sales The Company continued to expand sales to the industrial sector during 2006. Industrial gas sales in 2006 averaged 4.0 mmscf/d (2005: 2.1 mmscf/d) and peaked at 5.7 mmscf/d in August 2006 when the textile mills were operating at a higher capacity. As at 31 December 2006, the Company was selling gas to 13 customers (2005: 7) in 15 locations. The largest customers are Kioo Limited, Tanzania Breweries Limited, Karibu Textile Mills Ltd, Tanzania China Friendship Textile Co Ltd and Nida Textile Mills Ltd. In the peak summer months in 2007, the existing industrial customers are expected to take approximately 6.5 mmscf/d. By the end of 2007, it is forecast that an addi- tional average load of approximately 1-2 mmscf/d will be added primarily through the extension of the existing system to the Mwenge area, 8 kilometers north of the Ubungo Power Plant. As a consequence, the Company is assuming that the average load during the year will be approximately 6.0 mmscf/d allowing for seasonal variations. The price achieved for the industrial sales averaged US$8.22/mcf during 2006 (2005: US$7.07/mcf). The Company sells the gas to the industrial sector at a 20% – 25% discount to the price of Heavy Fuel Oil (“HFO”) in Dar es Salaam. The price of HFO in Dar is linked to the world prices for oil with a slight time lag. Current power sales During the year, 3.4 bcf of Additional Gas was sold to the power sector at an average of 9.2 mmscf/d. The Company continued to sell Additional Gas to Songas under an Interim Agreement that states that 19.5% of all the gas that is supplied to the six turbines at the Ubungo Power Plant is consid- ered Additional Gas. This percentage represents the volume of gas required for UGT 6 in proportion to the total consumption of the six turbines. This led to 2.8 bcf being sold at an average of 7.6 mmscf/d (maximum load 9.2 mmscf/d). In October 2006, the Company commenced sales to the Aggreko 48 MW emergency power plant (44 units at 1.1 MW each). Under the terms of the power purchase agreement with TANESCO, Aggreko has to be able to supply 40 MWs. The maximum load for 40 MWs is approximately 11.0 mmscf/d. By 31 December 2006, the Company had sold 0.6 bcf to these units. The average daily consumption of these units in November and December 2006 was 9.0 mmscf/d. During 2006, the price of Additional Gas to the power sector averaged US$1.90/mcf (2005: US$1.66/mcf). Under the terms of the Interim Agreement, the sales to the Ubungo Power Plant have a maximum price of US$2.32/mmbtu (US$2.14/mcf) and a minimum of US$0.67/mmbtu (US$0.62/mcf) depending on the availability of the units at the plant. As a consequence of the failure of certain turbines during 2006, the price achieved for these sales averaged US$1.85/mcf. Under the terms of the two year gas supply contract that was signed in December 2006, the price of Additional Gas to the Aggreko units is set at US$2.22/mcf and this will increase with consumer price inflation in 2008. There are no liabilities or take or pay provisions in the contract. Top u Orca Exploration employees regularly maintain producing wells offshore Songo Songo Island. Bottom u Orca Exploration's pressure reduction station feeds Additional Gas to the company's industrial customers in the Dar es Salaam area. 2006 ANNUAL REPORT 20 OPERATIONS REVIEW Above u The Aggreko emergency generation in Dar es Salaam consumes Additional Gas supplied by Orca Exploration. Prospective Markets Current demand exceeds the reserves as assessed by McDaniel and accordingly new gas reserves will be needed to satisfy market demand. In the 2005 annual report, the Company set a target to sell 12.6 mmscf/d of Additional Gas in 2006. The actual results exceeded this target with an average of 13.3 mmscf/d. The following summarises forecast sales volumes for 2007 and 2008. MMscf/d Industrial Power Compressed Natural Gas 2007 Target 2008 Target 6.0 (Note 1) 8.0 - 9.0 15.0 - 17.0 30.0 - 39.0 – 1.0 21.0 - 23.0 39.0 - 49.0 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 installation of two new gas processing trains. Prospective industrial sales The Company’s target is to increase industrial gas sales from an average of 4.0 mmscf/d in 2006 to an average of 6.0 mmscf/d during 2007. The current customers are forecast to consume in excess of 5.0 mmscf/d during 2007 with this increasing to 6.0 mmscf/d in 2008 as a result of the expansion of their operations. In addition, new customers will be hooked up as a result of the US$4.5 million, 16 kilometer distribution expansion during 2007. This is expected to add an average of 1.0 mmscf/d in 2007 and approximately 2.0 - 3.0 mmscf/d in 2008. The Company is also looking at the possibility of applying for a generation licence in order to supply electricity directly to large industrial customers located in Dar es Salaam. There are a number of industries located outside of Dar es Salaam that are commercially accessible by pipelines in a US$40/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 to them. If there are sufficient gas reserves and infrastructure capacity, there is the potential for 20 - 30 mmscf/d to be sold to the industrial sector in Tanzania. 2006 ANNUAL REPORT ops1 ops2 ops3 ops3 Cumulative production from each well Protected Gas Volumes 22 OPERATIONS REVIEW 14000 f c s m M 12000 10000 8000 6000 4000 2000 0 SS-3 SS-4 SS-5 SS-7 SS-9 2004 2005 2006 Gross Additional Gas reserves on a life of licence basis 2007 build up of gas fired generation 500 400 Probable Proven Prospective power sales 350 300 250 As at 31 December 2006, Tanzania had approximately 911 MWs of installed and operational electrical power generation as follows: 300 Feedstock f c b Power Plant Hydro: 200 100 0 Gas fired: 200 s W M Principal water source 150 Mtera dam Mtera dam 100 Run of river Run of river Run of river 50 Run of river Kidatu Mtera Hale Pangani Falls Kihansi Others Installed capacity MW 204 80 21 68 180 8 561 190 48 Q 3 2 0 0 7 250 12 not sure Average daily production per month in 2006 d / f c s M M 56 54 52 50 48 46 44 42 40 Ubungo Power Plant (units 1-6) 0 2004 2005 Aggreko 2006 Mtwara 3 1 - D e c - 0 6 Q 1 2 0 0 7 Q 2 2 0 0 7 Q 4 2 0 0 7 J a n F e b M a r c h A p r i l M a y J u n e J u l y A u g S e p O c t N o v D e c Month md2 2006 Additional Gas industrial and power sales volumes Wazo Hill Ubungo Power Plant Other thermal: Total Independent Power of Tanzania Limited (“IPTL”) Ubungo 42 MW Aggreko 48 MW Dowans 20 MW 100 911 md4 Top u Orca employees installing a new power cable on the Songo Songo Gas Processing Plant. 2006 Additional Gas Prices Power 10 Industrial Bottom u The Dowans power generation plant was under construction in early 2007. The majority of Tanzania’s installed generation is hydro, though over the past three years there has Dowans 60 MW Wartsila 100 MW been a rebalancing of the portfolio. The only major water storage is at the Mtera reservoir that Dowans 40 MW supplies the 80 MW Mtera and the 204 MW Kidatu hydro plants. 277 MWs of the hydro is primarily run of river and 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. Mtera Water Levels 1990-2007 ) s r e t e m ( l e v e l a e s e v o b a l e v e L 700 699 698 697 696 695 694 693 692 691 690 689 688 687 2007 4 0 0 2 2 0 0 5 2006 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Until December 2006, the lower than average rainfalls had led to the collapse of the output from the hydro stations and the country was reliant on thermal generation. The level of the Mtera dam fell to 687 meters above sea level and was shut in. The short rains were significant in January 2007 and led to the Mtera dam rising to its maximum level of 698 meters above sea level and 2005 2006 J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c at the fastest rate since 2001. md2 md3 2006 Additional Gas industrial and power sales volumes 2006 Additional Gas industrial sales f c s M M 200 180 160 140 120 100 80 60 40 20 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Industrial Power Nampak Nida ECO&F Bora Murzah III Murzah II Murzah I Lakhani Mukwano TCC Chinese ALAF TBL Kioo Karibu 700 699 698 697 696 695 694 693 692 691 690 689 688 687 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec f c B 16 14 12 10 8 6 4 2 0 md1 Revenue 0 0 0 $ S U 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 f c s M M 700 600 500 400 300 200 100 0 700 600 500 400 300 200 100 0 narrower copy of below J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c Industrial Power f c m / $ S U 9 8 7 6 5 4 3 2 1 0 d / f c s M M 56 54 52 50 48 46 44 42 40 J a n F e b M a r c h A p r i l M a y J u n e J u l y A u g S e p O c t N o v D e c Month md2 2006 Additional Gas industrial and power sales volumes 700 600 500 400 300 200 100 0 narrower copy of below J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c Industrial Power ops1 Cumulative production from each well f c B 16 14 12 10 8 6 4 2 0 md1 Revenue 0 0 0 $ S U 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 f c s M M 700 600 500 400 300 200 100 0 f c m / $ S U 10 9 8 7 6 5 4 3 2 1 0 It is now forecast that TANESCO will be able to run the Mtera and Kidatu hydro plants throughout 2007 at high utilisation rates (between 55% and 75%). This is welcome news for Tanzania and will alleviate some of the financial pressures on TANESCO. The following sets out the generation that TANESCO has indicated will be installed or decommis- sioned in Tanzania during 2007 and 2008: ops2 Feedstock Estimated commencement/ termination date ops3 Term Years Gross Additional Gas reserves on a life of licence basis Installed generation at 31 December 2006 Protected Gas Volumes Gas fired: 14000 12000 10000 Dowans Dowans Dowans Wärtsilä Wärtsilä Aggreko Coal fired: 8000 Kiwira Q1 2007 500 Q3 2007 Q4 2007 Q4 2007 400 Q2 – Q4 2008 Q4 2008 2 2-20 Probable 2-20 Proven 20 2-20 2008/2009 300 20 f c s m M Installed generation at 31 December 2008 f c b ops3 2007 build up of gas fired generation not sure Average daily production per month in 2006 Installed capacity MW 911 20 60 40 100 45 (48) 217 350 300 250 50-200 200 1,178 – 1,328 s W M 6000 In the 2005 annual report, the Company forecast that 245 MWs of permanent new gas fired 150 100 50 0 3 1 - D e c - 0 6 Q 1 2 0 0 7 Q 2 2 0 0 7 Q 3 2 0 0 7 Q 4 2 0 0 7 Ubungo 42 MW Aggreko 48 MW Dowans 20 MW Dowans 60 MW Wartsila 100 MW Dowans 40 MW 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998 2006 ANNUAL REPORT 1997 1996 1995 1994 1993 1992 1991 1990 4000 2000 0 SS-3 SS-4 SS-5 SS-7 SS-9 generation would be commissioned by the end of 2007. This was assuming that there would be 200 two new permanent plants from Wärtsilä (100 MWs and 45 MWs) and that the 100 MW IPTL plant would be converted to consume gas. It is now forecast that there will be 268 MWs of new gas fired generation installed by 31 December 2007 and that IPTL will continue to use HFO. 100 There is still uncertainty as to the length of time that the 120 MWs of emergency power generation operated by Dowans will remain in country. TANESCO has indicated that some of the units may remain in Tanzania on a permanent basis. TANESCO is keen to diversify their generation mix and accordingly it is forecast that up to 200 0 2004 2005 2006 2004 2005 2006 MW of coal fired generation will be installed during the next two/three years. Wazo Hill The maximum gas consumption of the 310 MWs of gas fired generation that are forecast to be in place and supplied with Additional Gas at the end of 2007 is estimated at 68 mmscf/d. Whilst Ubungo Power Plant the installation of gas fired generation is ahead of the Company’s forecasts, there is considerable difficulty in assessing the utilisation of these units during 2007 to 2010 given the improved hydrology particularly with respect to the Mtera dam and the potential for some coal fired md4 generation at Kiwira. During the rainy season (approximately 4-5 months of the year), there could 2006 Additional Gas Prices tional Gas being sold to the power sector in 2007. However, in the first fourteen weeks of 2007, be sufficient hydro and gas fired generation on Protected Gas to see only small amounts of Addi- Power Industrial an average of approximately 15 mmscf/d was sold to the power sector. This average is expected to continue, or slightly increase for the remainder of 2007, though there will be some months when the ‘run of river’ hydros will be operating at a high rate and there will be limited need to utilise the gas fired generation. 2007 4 0 0 2 2 0 0 5 2006 ) s r e t e m ( l e v e l a e s e v o b a l e v e L 700 699 698 697 696 695 694 693 692 691 690 689 688 687 f c s M M 200 180 160 140 120 100 80 60 40 20 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2005 2006 J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c md2 md3 2006 Additional Gas industrial and power sales volumes 2006 Additional Gas industrial sales Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Industrial Power Nampak Nida ECO&F Bora Murzah III Murzah II Murzah I Lakhani Mukwano TCC Chinese ALAF TBL Kioo Karibu 700 699 698 697 696 695 694 693 692 691 690 689 688 687 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec annual 2006.qxp 5/3/07 10:37 PM Page 24 24 OPERATIONS REVIEW 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%. Tanzania is expected to require 50 MWs of new generation per annum to meet demand in country. Export of power The reliance on hydro in Kenya and the relatively high cost of alternative oil fired generation, has increased the likelihood that Dar es Salaam will become the thermal hub for East Africa provided there are sufficient gas reserves. Kenya currently has approximately 1,140 MWs of permanent generation (671 MWs hydro, 343 MWs thermal and 126 MWs geothermal) and 100 MWs of emergency generation. Demand is estimated to be increasing at 150 MWs per annum. At current oil prices, Tanzania could export electricity at a significantly lower cost than Kenya could generate electricity with oil fired units. Compressed Natural Gas (“CNG”) The use of CNG is a proven technology that is widely used around the world including India and China. To examine the potential to use CNG in Tanzania, the Company and TPDC visited China in 2006 to see how CNG markets have been established and operated. In China, CNG is also used to supply domestic demand through the establishment of local distribution networks connected to CNG storage tanks. In 2007, the Company is looking to accelerate the development of the CNG market. In particular, the Company targets to: a a Convert one of the industrial customers’ distribution fleet to CNG; Plan for the selling of CNG to customers in Dar es Salaam who are not located on the existing pipeline system. This will include the larger hotels as well as industrial customers; and a Evaluate whether CNG could be transported in larger volumes to other industrial centres including Tanga and Morogoro. The potential CNG market in Tanzania is estimated to be approximately 10 - 15 mmscf/d. The Company targets to have a market of 1 mmscf/d during 2008. Opposite t Crews unload steel casing at Songo Songo Island for the new SS-10 well. Orca expects to complete this development well by the end of Q2 2007. Management’s Discussion & Analysis 2006 ANNUAL REPORT 26 Management’s Discussion & Analysis FORWARD LOOKING STATEMENTS THIS MDA OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS SHOULD BE READ IN CONJUNCTION WITH THE COMPANY’S FINANCIAL STATEMENTS AND NOTES THERETO FOR THE YEAR ENDED 31 DECEMBER 2006. THIS MDA IS BASED ON THE INFORMATION AVAILABLE ON 30 APRIL 2007. 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” – FORMERLY EASTCOAST ENERGY CORPORATION) 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 AUTHOR- ITIES. 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. 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 AND STOCK-BASED COMPENSATION. IT IS A KEY MEASURE AS IT DEMONSTRATES 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. 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 electrifi- cation 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. (c) No sales of Additional Gas may be made from the Discovery Blocks if in Orca Exploration’s reasonable judgement such sales would jeopardise the supply of Protected Gas. Any Addi- tional 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 two years 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 Protected Gas insufficiency. It is forecast that the security mechanism will be finalised by the end of Q2 2007. (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 nomina- tion 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. (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 2006 ANNUAL REPORT 28 MANAGEMENT’S DISCUSSION & ANALYSIS 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 transportation 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 Insufficiency and the Insufficiency Volume. “Insufficiency Volume” means the volume of natural gas determined by multiplying the average of the annual Protected Gas volumes for the three years prior to the Insufficiency (where the fifth turbine has been installed, but has not been operational for three years an imputed amount of annual gas consumption for the fifth turbine is incorporated) by 110% and multiplied by the number of remaining years (initial term of 20 years) of the power purchase agreement entered into between Songas and TANESCO in relation to the five gas turbine electricity generators at Ubungo from the date of the Insufficiency. Access and development of infrastructure (g) The Company is able to utilise the Songas infrastructure 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 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 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 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 develop- ment 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 have not taken account of any re-imbursement 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 distri- bution 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. 17.5% of the Songas Outlet Price is also the rate that is expected to apply to cover the financing and operating costs of the third and fourth train which will increase the gas processing capacity to 140 mmscf/d. (j) The cost of maintaining the wells and flowlines 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 Gas Cumulative sales of Additional Gas TPDC’s share of Profit Gas Company’s share of Profit Gas mmscf/d 0 - 20 >20 <=30 >30 <=40 >40 <=50 >50 bcf 0 - 125 >125<=250 >250<=375 >375<=500 >500 % 75 70 65 60 45 % 25 30 35 40 55 For Additional Gas produced outside of the Proven Section, the Company’s profit share increases to 55%. Where TPDC elects to participate in a development program, their profit share percentage increases by the Specified Proportion (for that development program) with a corresponding decrease in the Company’s percentage share of Profit Gas. 2006 ANNUAL REPORT 30 MANAGEMENT’S DISCUSSION & ANALYSIS 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. (l) Additional Profits Tax is payable where the Company has recovered its costs plus a specified return out of Cost Gas revenues and Profit Gas revenues. As a result: (i) no Additional Profits Tax is payable until the Company recovers all its costs out of Additional Gas revenues plus 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, procure- ment, 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 compen- sated 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. Consolidation The companies that are being consolidated are: Company Incorporated Orca Exploration Group Inc. (formerly EastCoast Energy Corporation) British Virgin Islands PAE PanAfrican Energy Corporation PanAfrican Energy Tanzania Limited 2006 Results Revenue and Operating Costs Mauritius Jersey 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 2006, revenue less cost recovery was allocated 75% to TPDC and 25% to Orca Exploration (“Profit Gas”). ops1 ops2 ops3 ops3 Cumulative production from each well Protected Gas Volumes Gross Additional Gas reserves on a life of licence basis 2007 build up of gas fired generation not sure Average daily production per month in 2006 f c B 16 14 12 10 8 6 4 2 0 SS-3 SS-4 SS-5 SS-7 SS-9 2004 2005 2006 2004 2005 2006 J a n F e b A p r i l M a y J u n e M a r c h J u l y A u g S e p O c t N o v D e c Month Wazo Hill Ubungo Power Plant md1 Revenue md4 2006 Additional Gas Prices Power Industrial f c m / $ S U 10 9 8 7 6 5 4 3 2 1 0 2005 2006 J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c f c s m M 14000 12000 10000 8000 6000 4000 2000 0 d / f c s M M 56 54 52 50 48 46 44 42 40 200 s W M 150 350 300 250 100 50 0 Q 1 2 0 0 7 Q 2 2 0 0 7 Q 3 2 0 0 7 Q 4 2 0 0 7 3 1 - D e c - 0 6 Ubungo 42 MW Aggreko 48 MW Dowans 20 MW Dowans 60 MW Wartsila 100 MW Dowans 40 MW 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Probable Proven 300 f c b 500 400 200 100 0 2007 4 0 0 2 2 0 0 5 2006 ) s r e t e m ( l e v e l a e s e v o b a l e v e L 700 699 698 697 696 695 694 693 692 691 690 689 688 687 f c s M M 200 180 160 140 120 100 80 60 40 20 0 700 699 698 697 696 695 694 693 692 691 690 689 688 687 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec (US$’000) Industrial sector Power sector Gross sales revenue Processing and transportation tariff TPDC share of revenue Operating revenue Additional Profits Tax Gross-up for income tax Revenue 2006 12,048 6,397 18,445 (2,889) (2,918) 12,638 (183) 1,373 13,828 2005 5,494 2,768 8,262 (1,308) (1,302) 5,652 (80) 187 5,759 f c s M M 700 600 500 400 300 200 100 0 md2 md3 2006 Additional Gas industrial and power sales volumes 2006 Additional Gas industrial sales 2006 ANNUAL REPORT Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Industrial Power Nampak Nida ECO&F Bora Murzah III Murzah II Murzah I Lakhani Mukwano TCC Chinese ALAF TBL Kioo Karibu Orca Exploration had recoverable costs throughout the year and accordingly was allocated 81.25% of the Net Revenues as follows: (US$’000 except production and per mcf data) Gross sales volume (mmcf): Industrial sector Power sector Total volumes md2 2006 1,466 3,371 4,837 Average sales price (US$/mcf): 2006 Additional Gas industrial and power sales volumes Industrial sector Power sector Average price Gross sales revenue Gross tariff for processing plant and pipeline infrastructure Gross revenue after tariff Analysed as to: Company Cost Gas Company Profit Gas 700 600 500 400 Company operating revenue (see Note 1 below) TPDC Profit Gas 300 narrower copy of below Production and distribution expenses: Ring main distribution pipeline costs Share of well maintenance costs Other field and operating costs Production and distribution expenses Depletion 200 100 0 8.22 1.90 3.81 18,445 2,889 15,556 11,665 973 12,638 2,918 15,556 336 213 244 793 2,027 2005 777 1,672 2,449 7.07 1.66 3.37 8,262 1,308 6,954 5,216 436 5,652 1,302 6,954 187 108 200 495 818 Note 1 M a r The Company’s total revenues for the year amounted to US$13,828,000 after adjusting the Company’s operating S e p D e c F e b A p r N o v J u n J a n O c t A u g J u l M a y 16,000 14,000 12,000 10,000 8,000 6,000 4,000 0 0 0 $ S U revenue of US$12,638,000 by: Industrial Power i) US$1,373,000 for income tax. The Company is liable for income tax in Tanzania but the income tax is 2,000 recoverable out of TPDC’s Profit Gas when the tax is payable. To account for this, revenues are grossed up for the current income tax; ii) US$183,000 for the deferred effect of Additional Profits Tax. This tax is netted off revenue as a royalty. 0 Revenue per the income statements may be reconciled to the operating revenue as follows: ops1 ops2 Cumulative production from each well Protected Gas Volumes Gross Additional Gas reserves on a life of licence basis 2007 build up of 2000 gas fired generation Average daily production per month in 2006 md2 2006 Additional Gas industrial and power sales volumes SS-3 SS-4 SS-5 SS-7 SS-9 Probable Proven Wazo Hill Ubungo Power Plant 0 2004 2005 2006 0 2004 2005 2006 J a n F e b M a r c h A p r i l M a y J u n e J u l y A u g S e p O c t N o v D e c Month ops1 ops2 ops3 ops3 Cumulative production from each well Protected Gas Volumes Gross Additional Gas reserves on a life of licence basis 2007 build up of gas fired generation not sure Average daily production per month in 2006 16 14 12 10 8 6 2 0 4 ops3 f c B 500 400 100 0 300 md1 f c b Revenue 0 0 0 $ S U 14,000 12,000 10,000 8,000 6,000 4,000 2,000 14000 12000 10000 f c s m M 8000 6000 4000 ops3 350 300 250 100 50 0 d / f c s M M 56 54 52 50 48 46 44 42 40 200 s W M 150 350 300 250 100 50 0 3 1 - D e c - 0 6 Q 1 2 0 0 7 Q 2 2 0 0 7 Q 3 2 0 0 7 Q 4 2 0 0 7 Ubungo 42 MW Aggreko 48 MW Dowans 20 MW Dowans 60 MW Wartsila 100 MW Dowans 40 MW Probable Proven 500 400 300 f c b 200 not sure 100 56 54 52 50 48 46 44 42 40 d / f c s M M 700 699 698 697 696 695 694 693 692 691 690 689 688 687 ) s r e t e m ( l e v e l a e s e v o b a l e v e L 2007 J a n F e b A p r i l M a y J u n e M a r c h J u l y A u g S e p O c t N o v D e c Month 2 0 0 5 4 0 0 2 2006 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 700 600 500 400 300 100 0 f c m / $ S U 10 9 8 7 6 5 4 3 2 1 0 f c B 16 14 12 10 8 6 4 2 0 md1 Revenue 0 0 0 $ S U 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 md2 f c s M M 700 600 500 400 300 200 100 0 f c s m M 14000 12000 10000 8000 6000 4000 2000 0 md4 200 2006 Additional Gas Prices s W M Power 150 Industrial 16,000 200 10 SS-3 SS-4 SS-5 SS-7 SS-9 200 2004 2005 2006 2004 2005 2006 f c m / $ S U Q 1 2 0 0 7 Q 2 2 0 0 7 Q 3 2 0 0 7 Q 4 2 0 0 7 3 1 - D e c - 0 6 narrower copy of below Wazo Hill Ubungo Power Plant J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c md4 Industrial Power 2006 Additional Gas Prices Power Industrial 0 32 MANAGEMENT’S DISCUSSION & ANALYSIS 2005 2006 9 8 7 6 5 4 3 2 1 0 Ubungo 42 MW Aggreko 48 MW Dowans 20 MW Dowans 60 MW Wartsila 100 MW Dowans 40 MW J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c ) s r e t e m ( l e v e l a e s e v o b a l e v e L 2007 700 699 698 697 md2 696 Volumes 695 2006 Additional Gas industrial and power sales volumes 4 0 0 2 2 0 0 5 2006 694 693 692 700 600 691 500 400 690 689 f c 688 s M M 687 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990 300 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 200 100 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec md3 2006 Additional Gas industrial sales f c s M M 200 180 160 140 120 100 80 60 40 20 0 2005 2006 J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c Industrial Power Industrial During the year, the Company commenced gas sales to six new industrial customers. By the year- end, the Company had thirteen industrial customers who were consuming Additional Gas in fifteen different locations. Industrial sales averaged 4.0 mmscf/d (2005: 2.1 mmscf/d) and peaked at 5.7 mmscf/d in August 2006. md3 2006 Additional Gas industrial and power sales volumes 2006 Additional Gas industrial sales Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Industrial Power f c s M M 200 180 160 140 120 100 80 60 40 20 0 Power Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Nampak Nida ECO&F Bora Murzah III Murzah II Murzah I Lakhani Mukwano TCC Chinese ALAF TBL Kioo Karibu An Interim Agreement with Songas for the sale of Additional Gas to Ubungo Power Plant was signed on 1 October 2005. In accordance with the terms of the Interim Agreement, 19.5% of the gas volumes supplied to the six turbines at the Ubungo Power Plant are considered Additional Gas. The Interim Agreement expires on 31 May 2007. This will probably be extended for a short period after which it is forecast that it will be superceded by a long term contract. During the year, consumption of Additional Gas at the Ubungo Power Plant increased to 2,774 mmscf (an average of 7.6 mmscf/d) against 1,672 mmscf for the period from 8 June to 31 December 2005 (an average of 8.1 mmscf/d). Despite Tanzania facing severe drought in 2006, a number of the Songas operated generation units at the Ubungo Power Plant were down for repair or maintenance during the year and this impacted the consumption. Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Nampak Nida ECO&F Bora Murzah III Murzah II Murzah I Lakhani Chinese ALAF TBL Kioo Mukwano Karibu 700 TCC Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990 699 698 697 696 695 694 693 692 691 690 689 688 687 md2 2006 Additional Gas industrial and power sales volumes 700 600 500 400 300 200 100 0 narrower copy of below J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c Industrial Power 700 699 698 697 696 695 694 693 692 691 690 689 688 687 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec ops1 ops2 ops3 ops3 Cumulative production from each well Protected Gas Volumes Gross Additional Gas reserves on a life of licence basis 2007 build up of gas fired generation not sure Average daily production per month in 2006 16 14 12 10 8 6 4 2 f c B The severe curtailment of the 561 MWs of hydro generation and the subsequent power rationing led TANESCO and the Government of Tanzania to enter into two contracts with Aggreko Plc SS-9 (“Aggreko”) and Dowans Tanzania Limited (“Dowans”) for the installation and supply of a SS-5 SS-4 SS-7 SS-3 0 md2 guaranteed 140 MWs of gas-fired emergency power plants. Aggreko installed 44 units of 1.1 MWs each (total 48 MWs) and started to generate power in October 2006. By the year end 597 mmscf 2006 Additional Gas industrial and power sales volumes of Additional Gas had been consumed or an average of 7.9 mmscf/d. None of the Dowans units were operational before the year end, but 20 MWs commenced gas consumption in January 2007. The remainder of the units are forecast to be operational during 2007. 700 600 500 400 300 Pricing Industrial md1 Revenue md4 2006 Additional Gas Prices The price of gas for the industrial sector continued to be at a discount to the price of Heavy Fuel Power Industrial Oil (“HFO”) in Dar es Salaam. This resulted in average gas prices of US$8.22/mcf (2005: 16,000 10 US$7.07/mcf) during the year. The gas price achieved for the industrial sector will fluctuate with world oil prices and the discount agreed with the customers. The monthly Additional Gas price 14,000 sold to industrial customers in Dar es Salaam in 2006 ranged from US$7.35/mcf in January 2006 to US$8.96/mcf in June 2006. The price in December 2006 was US$7.70/mcf. 12,000 narrower copy of below Power The price of gas to the power sector during the year averaged US$1.90/mcf (2005: US$1.66/mcf). 10,000 0 0 0 $ S U 200 100 0 J a n F e b M a r 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 8,000 of US$0.67/mbtu (US$0.62/mcf) to the maximum of US$2.32/mbtu (US$2.15/mcf). UGT5 and UGT6 developed mechanical problems in Q1 and Q3 but were subsequently repaired. Accordingly, 6,000 in accordance with the terms of the Interim Agreement with Songas, the lower availability of the units led to prices below US$2.32/mmbtu (US$2.15/mcf) being achieved in four months of the year. 4,000 A p r M a y J u n J u l A u g S e p O c t N o v D e c The supply to the Aggreko 48 MWs emergency unit was at US$2.32/mmbtu (US$2.15/mcf) for Industrial Power October and November 2006 and then increased to US$2.39/mmbtu (US$2.22/mcf) from 2,000 December when a two year contract was signed. The price will increase with US consumer price inflation on 1 January 2008. 0 The Company is still in negotiations with TANESCO, the Ministry of Energy (“MEM”) and EWURA, 2006 2005 f c s m M 14000 12000 10000 8000 6000 4000 2000 0 2004 2005 2006 2004 2005 2006 Wazo Hill Ubungo Power Plant J a n F e b M a r c h A p r i l M a y J u n e J u l y A u g S e p O c t N o v D e c Month d / f c s M M 56 54 52 50 48 46 44 42 40 200 s W M 150 350 300 250 100 50 0 3 1 - D e c - 0 6 Q 1 2 0 0 7 Q 2 2 0 0 7 Q 3 2 0 0 7 Q 4 2 0 0 7 Ubungo 42 MW Aggreko 48 MW Dowans 20 MW Dowans 60 MW Wartsila 100 MW Dowans 40 MW 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990 Probable Proven 300 f c b 500 400 200 100 0 2007 4 0 0 2 2 0 0 5 2006 md3 2006 Additional Gas industrial sales ) s r e t e m ( l e v e l a e s e v o b a l e v e L 700 699 698 697 696 695 694 693 692 691 690 689 688 687 f c s M M 200 180 160 140 120 100 80 60 40 20 0 700 699 698 697 696 695 694 693 692 691 690 689 688 687 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec f c m / $ S U 9 8 7 6 5 4 3 2 1 0 J a n F e b M a r A p r M a y J u n J u l A u g S e p O c t N o v D e c Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec the energy utility regulator, over the long term price to be applied to gas sold to power sector. In December 2006, the Company and TPDC lodged an application (“Application”) with EWURA for the supply of gas to the power sector. The price of the gas was divided between the wellhead, distribution and marketing prices. Subsequent to the submission, EWURA notified the Company that whilst the regulator had jurisdiction over the downstream distribution and marketing prices, md2 there was some uncertainty as to whether this also applied to the wellhead price. As a result the Company withdrew the Application and is currently negotiating the price with TANESCO under the 2006 Additional Gas industrial and power sales volumes guidance of MEM. f c s M M 700 600 500 400 300 200 100 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2006 ANNUAL REPORT Industrial Power Nampak Nida ECO&F Bora Murzah III Murzah II Murzah I Lakhani Mukwano TCC Chinese ALAF TBL Kioo Karibu 34 MANAGEMENT’S DISCUSSION & ANALYSIS Tariff The tariff is calculated as 17.5% of the price of gas at the Songas main pipeline in Dar es Salaam (“Songas Outlet Price”). In calculating the Songas Outlet Price for the industrial customers, US$1.30/mcf (2005: US$0.75/mcf) (“Ringmain Tariff”) has been deducted from the achieved sales price of US$8.22/mcf (2005: US$7.07/mcf) to reflect the gas price that would be achievable at the Songas main pipeline. The Ringmain Tariff represents the amount that would be required to compensate a third party distributor of the gas for constructing the connections from the Songas main pipeline to the industrial customers. No deduction has been made for sales to the Ubungo Power Plant or the Aggreko emergency units since the gas is not transported through the Company’s own infrastructure. Production and distribution expenses The cost of maintaining the ring main distribution pipeline and pressure reduction station (security, insurance and personnel) is forecast to be approximately US$0.3 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$627,000 (2005: US$437,000) of which US$213,000 (2005: US$108,000) was allocated for the Additional Gas. Other field and operating expenses primarily includes the operating costs for the low pressure distribution pipeline system and the energy regulator’s fee. The regulator’s fee commenced in November 2006 and is calculated monthly as to 1% of gross revenue to the Company. Operating netback The operating netback per mcf before general and administrative costs, overheads, tax and Additional Profits Tax may be analysed as follows: (Amounts in US$/mcf) Gas price – industrial Gas price – power Average price for gas Tariff (after allowance for the Ringmain Tariff) TPDC profit share Net selling price Well maintenance and other operating costs Ringmain distribution pipeline costs Operating netback 2006 8.22 1.90 3.81 (0.60) (0.60) 2.61 (0.08) (0.08) 2.45 2005 7.07 1.66 3.37 (0.53) (0.53) 2.31 (0.12) (0.08) 2.11 Operating netback was slightly higher in 2006 as a result of the increase in average prices to both the industrial and power customers. In addition the higher sales volumes have reduced the well maintenance and other operating costs per mcf. The operating netback continues to benefit from the recovery of 75% of the Net Revenues as Cost Gas. General and Administrative Expenses The general and administrative expenses (“G&A”) may be analysed as follows: (Figures in US$’000) Personnel expenses Stock based compensation (options) Consultants Travel & accommodation Communications Office Insurance Auditing & taxation Depreciation Reporting, regulatory and corporate finance Marketing costs including legal fees Directors’ fees Total general and administrative expenses 2006 1,836 418 1,191 435 128 456 146 96 102 157 1,671 88 6,724 2005 846 383 626 181 75 412 166 97 93 173 434 69 3,555 G&A averaged approximately US$0.56 million per month (2005: US$0.29 million). G&A per mcf fell to US$1.39/mcf (2005: US$1.45/mcf). Whilst a large proportion of G&A is relatively fixed in nature and therefore declines on an mcf basis as volumes increase, significant costs are being incurred in the negotiation of the power contracts. This has led to the G&A costs being relatively high per mcf. It is expected that these will fall as volumes increase and long term power contracts are signed. Personnel expenses During 2006, the Company implemented a bonus scheme that incorporates some stock appreciation rights for senior management staff that are still employed by the Company as at 31 December 2007. The value of these stock appreciation rights are calculated using the Black- Scholes option pricing model and have a maximum pay out of Cdn$1.2 million. US$450,000 has been expensed during the year and the remainder will be expensed in 2007. There has also been an increase in the average number of staff paid for by the Company to 15 (2005: 12) and in pay rates. One expatriate, who was one of the site managers at the gas processing plant and whose employment costs were met by Songas in accordance with the terms of the Operatorship agreement, was assigned new duties in November 2005 to bolster the Company’s reserves and engineering capability. Consequently, his expatriate package and other costs were met by the Company for a longer comparable period in 2006. Stock based compensation (options) The Company uses the Black-Scholes option pricing model in determining the fair value of options. The options which were granted on 1 September 2004 vested in full on 1 September 2006. On 1 September 2006, the Company issued 200,000 options to a new recruit. These options will vest in three equal installments starting on 1 September 2007. The Company makes a monthly charge to the income statement of US$28,000 in respect of these options. 2006 ANNUAL REPORT 36 MANAGEMENT’S DISCUSSION & ANALYSIS Consultancy costs During the year, the Company revised the pay rates for its consultants to reflect market rates. The Company also appointed an exploration and business development consultant with effect from 1 September 2006. Travel and accommodation The increase in travel and accommodation costs is primarily due to the increase in number of business trips to Tanzania by Company officials and other marketing and legal professionals for the negotiation of the power 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 contracts with Songas, TANESCO and the regulatory authority, EWURA. Total marketing and legal costs for the year relating to the negotiation including the drafting of a power tariff application to EWURA amounted to US$1.3 million. Taxes Under the terms of the PSA with TPDC, the Company is liable for income tax in Tanzania at a corporate tax rate. 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 grossing up the Company’s revenue for the current income tax. During the year, the Company paid income tax amounting to US$1,049,000 for the 2006 provisional taxes (against a current tax charge of US$961,000) and US$59,000 final income tax for 2005. The US$88,000 overpayment of the 2006 current tax will be set against future tax liabilities. The Company has recovered US$954,000 from TPDC’s profit share during 2006 and the remainder of US$154,000 will be recovered in 2007. As at 31 December 2006, 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$1.2 million. 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. 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. As at 31 December 2006, the effective APT rate was calculated to be 20% (2005: 18%). Accordingly, US$183,000 (2005: US$80,000) has been netted off revenue for the year ended 31 December 2006. As at 31 December 2006, there were un-recovered costs of US$14.6 million (2005: US$11.6 million). Management does not anticipate that any APT will be payable in 2007, as the forecast revenues will not be sufficient to cover the un-recovered costs brought forward as inflated by 25% plus the percent- age change in the United States Industrial Goods Producer Price Index and the forecast expenditures for 2007. 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. 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 2006, the proven reserves as evaluated by the independent reservoir engineers, McDaniel & Associates Consultants Ltd. (“McDaniel”) were 265.8 bcf (2005: 240.6 bcf) on a life of licence basis. This leads to a depletion charge of US$0.55/mcf in 2006 (2005: US$0.33/mcf). Non-Natural Gas Properties are depreciated as follows: Leasehold improvements Computer equipment Vehicles Fixtures and fittings Recoverable Costs Over remaining life of the lease 3 years 3 years 3 years As at 31 December 2006, the Company had US$14.6 million (2005: US$11.6 million) of costs that are recoverable out of 75% of the future Net Revenues. The costs associated with the remedial work on SS-9 are not recoverable as TPDC has stated that the work should have been rectified by a predecessor company of Orca Exploration at the time of the 1997 work programme. As at 31 December 2006, US$0.3 million was not able to be recovered in this respect. Carrying Value of Assets Capitalised costs are periodically assessed to determine whether it is likely that such costs will be recovered in the future. To the extent that these capitalised costs are unlikely to be recovered in the future, they are written off and charged to earnings. Funds Flow Funds from operations before working capital changes were US$6.0 million for the year ended 31 December 2006 (2005: US$2.3 million). (Figures in US$’000) Profit after taxation Adjustment for non cash items 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 Increase in cash and cash equivalents 2006 2,577 3,453 6,030 (873) 5,157 (5,909) 18,232 17,480 2005 388 1,880 2,268 (465) 1,803 (5,020) 4,375 1,158 2006 ANNUAL REPORT 38 MANAGEMENT’S DISCUSSION & ANALYSIS The cash flows generated during the year were reinvested in developing the Songo Songo field and related infrastructure. Accordingly, the US$17.5 million increase in the net cash and cash equivalents during the year was primarily due to the net receipt of US$18.1 million from the rights issue on 29 December 2006. Capital Expenditures Capital expenditures amounted to US$6.0 million during the year (2005: US$5.6 million). The capital expenditure may be analysed as follows: (Figures in US$’000) Geological, geophysical and well drilling Pipelines and infrastructure Power development Other equipment 2006 4,460 975 573 35 6,043 2005 2,757 2,090 789 12 5,648 During 2006, the Company commenced preparations to drill the development well, SS-10, to increase gas deliverability and ensure security of supply in the event of failure of any single well. The Company purchased US$3.4 million of casing and other long lead items, US$1.6 million of which was for a potential second development or exploration well that is forecast to be drilled in 2008/2009. 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 do not take account of any re-imbursement for the SS-10 capital expenditure, pending the finalisation of the terms of the ‘back in’. The Company also commenced work to remove over 5,000 feet of wireline and two pressure gauges that were left downhole in SS-9 at the time of the 1997 well tests. The debris was causing the well to produce below its production capability at 20 mmscf/d. The remedial work was successfully completed in Q1 2007 and the well now has a maximum deliverability of 50 mmscf/d. During the year, the Company completed the processing and interpretation of data from the seismic acquisition on the Songo Songo licence area and the Nyuni farm-in licence acreage at a cost of US$0.5 million. The actual seismic work was conducted in 2005. The Company expanded its gas distribution network by 3 kilometers to 28 kilometers during the year through the connection of eight additional industrial customers at a cost of US$0.7 million. Most of the customers connected during the year were located alongside the ringmain. In addition, the Company started to prepare for an 8 kilometer pipeline extension to the distribution system and the construction of an additional pressure reduction system (“PRS”). This will improve the security of supply, enable the Company to hook up 3-4 new customers and increase deliverabil- ity to its existing industrial base. The Company incurred US$0.3 million in 2006 for this work and is expected to incur an additional US$1.9 million in 2007. The Company also completed the installation of a second PRS and a pipeline connection in order to supply gas to the 48 MW Aggreko power plant that became operational in Q4 2006. Working Capital Working capital as at 31 December 2006 was US$20.4 million (31 December 2005: US$2.2 million) and may be analysed as follows: (Figures in US$’000) Cash and cash equivalents Trade and other receivables Total current liabilities Working capital 2006 20,678 4,275 24,953 4,523 20,430 2005 3,198 2,862 6,060 3,849 2,211 The significant increase in the year end cash balance is due to the net receipt of US$18.1 million from a rights issue on 29 December 2006. Also included in cash and cash equivalents was US$185,000 advanced by Murzah Oil Industries Limited, East Coast Oils & Foods Limited, Nampak Tanzania Limited and Yuasa Batteries (East Africa) Limited as deposits for their connections. This amount will be repaid to the companies after they have consumed in excess of a total of US$370,000 of Additional Gas. This amount is shown in current liabilities. 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. 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 2006, US$1.9 million was due for the month of November and December (including VAT) from the industrial customers. A signifi- cant part of this amount has been subsequently received. Trade and other receivables also includes an amount of US$0.7 million due from Songas for the supply of Additional Gas to the Ubungo Power Plant and US$0.8 million from TANESCO for supply of Additional Gas to the 48 MW Aggreko units. The contracts with Songas and TANESCO accounted for 35% (2005: 34%) of the Company’s operating revenue in 2006. Songas’ financial security is, in turn, heavily reliant on the payment of capacity and energy charges by the electricity utility, TANESCO. Despite the improve- ment in hydrology, TANESCO is still experiencing financial difficulties. As a result, 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 and US$198,000 remains outstanding from TANESCO in respect of the amounts due at 31 December 2006. The level of receivables will be closely monitored to minimise any potential default by any of the Company’s customers. 2006 ANNUAL REPORT 40 MANAGEMENT’S DISCUSSION & ANALYSIS Under the terms of the PSA and other Songo Songo agreements: a The profit share owed to TPDC is payable within 30 days of each quarter end. Accordingly, the Company benefits from holding the cash receipts for this period. Under the PSA, income tax paid by the Company is recoverable from TPDC’s share of profit share. During the year, the Company paid provisional income tax of US$1,049,000. As at 31 December 2006, US$154,000 (2005: US$629,000 due to TPDC) was yet to be recovered from TPDC’s profit share. This was recovered in full in Q1 2007. a The tariff for the use of the gas processing plant and pipeline infrastructure is payable to Songas within 30 days of each month end. As at 31 December 2006 the Company owed Songas US$605,000 (2005: US$420,000) for the tariff. The amount due at the year end represents an outstanding balance of two months, which matches the time that Songas is taking to pay for the Additional Gas used at the Ubungo Power Plant. Included in the current liabilities is US$0.5 million being an accrual for a bonus scheme introduced during the year that incorporates stock appreciation rights, and US$0.3 million for the rights issue costs. Current liabilities also includes US$2.3 million (2005: US$1.8 million) of accrued liabilities. These include staff and consultants annual bonuses of US$0.6 million, a share of well mainte- nance and field production cost of US$0.3 million payable to Songas, US$0.3 million for VAT and other taxes payable to central Government and local authorities, customer deposits of US$0.2 million and other year end accruals. Per a short term agreement with TANESCO for the supply of gas to the 20 MW Dowans unit, US$138,000 was due to be received in December 2006 in advance of gas being consumed. This has been included in current liabilities. The payment has subsequently been received. Management forecasts that the Company will be able to meet its 2007 capital expenditure programme through the use of proceeds from the rights issue and self-generated cash flows. In addition, the Company 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. Outstanding Share Capital There were 26.8 million shares outstanding at 31 December 2006 and may be analysed as follows: Number of shares (‘000) Shares outstanding Class A shares Class B shares Convertible securities Options Fully diluted Class A and Class B shares Weighted average Class A and Class B shares Options 2006 2005 1,751 25,023 26,774 2,022 28,796 23,395 1,514 1,751 21,513 23,264 1,987 25,251 22,903 1,419 24,322 Weighted average diluted Class A and Class B shares 24,909 The Company issued 3,345,540 Class B shares at Cdn$6.43 per share following a fully subscribed rights issue that closed on 29 December 2006. Net proceeds of US$18.1 million were raised for the Company and collected by 31 December 2006 (gross proceeds US$18.5 million, costs US$0.4 million). The funds will be primarily used for the drilling of the SS-10 development well, the expansion of the low pressure distribution system and new growth opportunities. Under the terms of the rights issue: a each holder of Class B shares was entitled to receive one right for each Class B held and seven rights entitled the holder to subscribe for one Class B share at a price of Cdn$6.43. a each holder of Class A shares was entitled to receive one right for each Class A share held and seven rights entitled the holder to subscribe for on Class B share at a price of Cdn$6.43. a each holder of rights who exercised all of their rights was entitled to subscribe for additional Class B shares that had not been subscribed and paid for at the closing date (“Additional Subscription Privilege”). The subscription price of Cdn$6.43 represented a 15% discount to the closing price of the Class B shares on 7 September 2006. As at 30 April 2007, there were 1,751,195 A shares and 25,253,128 B shares in issue. Stock Based Compensation 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. 2,000,000 options were issued to certain Directors and Officers on 1 September 2004 at a price of Cdn$1.00 per option. These options have a term of 10 years. The fair value of these options had been expensed in full as at 31 December 2006. During the year, 165,000 of these 2004 options were exercised at a price of Cdn$1.00 per option. A total of 1,822,400 of these options remained outstanding at the year end. On 1 September 2006, 200,000 options were issued at a price of Cdn$6.80 per option. These options have a term of 5 years and vest in three equal annual instalments starting on 1 September 2007. The fair value of these options were estimated at the grant date using the Black-Scholes option pricing model with the following assumptions: risk free rate of 2.6% dividend yield of 0%, expected life of 5 years and volatility of 80%. As at 30 April 2007, the Company had granted 2,292,400 options. In addition, there were 1,000,000 stock appreciation rights, 400,000 of which are capped. Contractual Obligations and Committed Capital Investment During the year, the Company committed to drilling a development well, SS-10 and to undertake some remedial work on the offshore well, SS-9. Preparations for these operations, including the purchase of long-lead materials and equipment, started during the year. The remedial work on SS-9 was successfully completed in Q1 2007. SS-10 was spud in April 2007. The Company has committed to spend a total of US$12.9-US$14.9 million on these projects. 2006 ANNUAL REPORT 42 MANAGEMENT’S DISCUSSION & ANALYSIS The Company has committed to the installation of an additional pressure reduction station and the laying of 8 kilometers of new low pressure pipeline in the first half of 2007. This work is required to increase security of supply and to meet forecast increases in demand from both existing and new industrial customers. The work is estimated to cost US$2.2 million. As at the year end, the Company had already spent US$0.3 million for the purchase of long lead equipment and project management. 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. Under the terms of the PSA, in the event that there is a shortfall in Protected Gas as a conse- quence 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 (7.4 bcf as at 31 December 2006). 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 two years 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 circum- stances, the Company and TPDC may have to allocate a proportion of the Additional Gas revenues to an escrow account, in the event of a Protected Gas insufficiency. It is forecast that the security mechanism will be finalised by the end of Q2 2007. 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 do not take account of any re-imbursement for the SS-10 capital expenditure, pending the finalisation of the terms of the ‘back in’. Management expects to fund its committed capital investments in 2007 from the proceeds of the rights issue and cash generated from operations. Post Balance Sheet Events On 14 January 2007, the Company issued 300,000 options to a newly appointed officer at a price of Cdn$8.00 per option. These options have a term of 5 years and vest in three equal annual instalments starting on 14 January 2008. In addition, 300,000 stock appreciation rights were issued to the same officer at an exercise price of US$8.00 per right. These stock appreciation rights have a term of 5 years and vest in three equal annual instalments starting on 14 January 2008. In April 2007, 200,000 Treasury Shares were awarded to the same officer. These vest in three equal annual instalments starting 7 April 2007. On 2 January 2007, the Company issued 300,000 stock appreciation rights to a consultant at an exercise price of Cdn$8.70 per right. The consultant is facilitating the search for new venture opportunities for the Company. These stock appreciation rights have a term of 5 years and vest in three equal annual instalments starting on 2 January 2008. 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. There are no other Post Balance Sheet Events other than those disclosed under ‘Contractual Obligations and Committed Capital Investment’. Off-Balance Sheet Transactions As at 31 December 2006, the Company had no off-balance sheet arrangements. Operating Leases The Company has entered into a five year rental agreement that expires on 30 November 2007 for the use of the offices in Dar es Salaam at a cost of approximately US$102,000 per annum. Related Party Transactions The following transactions were carried out with related parties: i) During the year, the Company entered into an agreement with a company owned by the non-Executive Chairman, to underwrite all the rights issue at a fixed fee of US$300,000. ii) One of the non executive Directors is a partner at a law firm. During the year, the Company incurred US$176,000 to this firm for services provided on rights issue and other legal services. The transactions with these related parties were made at the exchange amount. 2006 ANNUAL REPORT 44 MANAGEMENT’S DISCUSSION & ANALYSIS 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, summa- rized 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 2006 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: (a) the Company is dependant upon its advisors and 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 require- ments, 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 reli- ability 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: (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 prepa- ration 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 2006 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 the Company’s 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 incompatible 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 a 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. 2006 ANNUAL REPORT 46 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 Q1 Q4 Q3 Q2 Q1 2006 2005 FINANCIAL Revenue Profit/(loss) after taxation Operating netback (US$/mcf) Working capital Shareholders’ equity 4,722 1,025 2.13 3,835 3,198 2,073 2,741 2,156 512 350 809 2.88 660 2.71 83 2.05 396 2.51 785 1.68 (275) (518) 3.86 3.24 20,430 3,298 2,448 2,118 2,211 3,559 2,789 4,895 37,889 18,676 17,715 16,928 16,662 16,096 15,240 15,444 Profit/(loss) per share – basic (US$) Profit/(loss) per share – diluted (US$) 0.05 0.04 CAPITAL EXPENDITURES Geological and geophysical and well drilling 2,747 Pipeline and infrastructure Power development Other equipment OPERATING Additional Gas sold – industrial (mmscf) Additional Gas sold – power (mmscf) Average price per mcf – industrial (US$) Average price per mcf – power (US$) 131 531 – 398 1,206 7.64 1.95 0.03 0.03 473 234 42 – 491 744 8.63 1.69 0.03 0.03 726 305 – 3 347 739 8.69 2.13 – – 0.02 0.02 0.03 0.03 (0.01) (0.02) (0.01) (0.02) 514 305 – 32 230 682 7.63 1.79 2,000 868 34 (1) 299 766 7.86 2.15 148 110 224 3 261 905 7.26 1.24 520 902 531 5 120 – 88 210 – 5 97 – 6.19 5.23 – – The principal developments in Q4 were as follows: a Signed a two year contract, connected (US$0.4 million) and commenced the supply of an average of 6.5 mmscf/d of Additional Gas to the Aggreko emergency gas fired power units at an average price of US$2.05/mcf. These units can take a maximum of 11.6 mmscf/d and are expected to be operational until December 2008. The price of gas to these units from 1 January 2007 increased to US$2.22/mcf. a Installed the connection to the 20 MW Dowans unit at a cost of US$0.1 million. This unit commenced commercial operations on 23 January 2007 and has a maximum gas usage of 6.0 mmscf/d. a a Achieved average Additional Gas sales of 6.4 mmscf/d to the Ubungo Power Plant at an average price of US$1.80/mcf. Started Additional Gas supply to two new industrial customers, East Coast Oils & Fats Limited and Nampak Tanzania Limited. An additional customer connected during the quarter, Serengeti Breweries Limited, had yet to commence gas consumption by the year end. a Incurred capital expenditure of US$3.7 million on the purchase of long lead items for the drilling of the SS-10 development well that will spud in April 2007 and the remedial work on the offshore well, SS-9. a Continued with preparation to construct a new pressure reduction system and the laying of 8 kilometers of new low pressure pipeline. US$0.3 million was incurred during the quarter for the purchase of long lead pipeline. a a Successfully raised US$18.1 million (net) through a one for seven rights issue. Recruited James Smith as an executive officer and director to head up the Company’s exploration and new ventures. Variance analysis between quarters 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 4.3 mmscf/d in Q4 2006, peaking at 5.3 mmscf/d in Q3 2006. Industrial sales peak in third quarters of each year as textile customers take advantage of low cotton prices during the harvest season. At the same time 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 and peaked in Q2 2006 at US$8.69/mcf. 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. The gas price to the power sector from Q3 2005 to Q3 2006 was set at a sliding scale between US$0.62/mcf and US$2.15/mcf depending on the availability of gas turbines at the Ubungo Power Plant. The maximum price was only achieved in Q4 2005 and Q2 2006 as a result of operational problems at Ubungo Power Plant in other quarters. In Q4 2006, 48 MWs of emergency power units operated by Aggreko plc commenced commer- cial operations. These units took an average of 7.9 mmscf/d during Q4 so increasing the volume of Additional Gas sold. Revenue in Q4 2006 increased as a result of the commencement of gas sales to the Aggreko emergency power plant. Profit/(loss) after taxation The majority of the Company’s costs are fixed in nature though there have been step changes in the general and administrative costs as new personnel are recruited to meet the expanding activities. The Company recorded its first profit in Q3 2005 as a result of commencement of gas sales to power sector. Profitability in the first and fourth quarters of each year is affected by the seasonality of gas demand by the textile customers. The increase in profit in Q4 2006 is primarily the result of the increased sales to the power sector, though this was partially offset by an increase in costs to negotiate long term power contracts and work performed for the regulator, EWURA. A detailed Additional Gas price application for the power sector was made to EWURA in December 2006. 2006 ANNUAL REPORT annual 2006.qxp 5/3/07 10:37 PM Page 48 48 MANAGEMENT’S DISCUSSION & ANALYSIS Working capital The working capital for Q4 2006 increased to US$20.9 million as a result of the receipt of rights issue proceeds on 29 December 2006. In Q1 2005, the Company raised US$4.4 million through a rights issue. This helped to increase the working capital to US$4.9 million over the previous quarter. Funds raised in Q4 2006 will be primarily used in completing the drilling programme, extending the low pressure distribution system and in pursuing new options for growth. SELECTED FINANCIAL INFORMATION Selected annual financial information derived from the audited consolidated financial statements for the period ended 31 December 2004 and the years ended 31 December 2005 and 2006 is set out below: (Figures in US$’000 except per share amount) Revenue Funds from operations before working capital changes Profit/(loss) after taxation Profit/(loss) per share: Basic Diluted Total assets Year ended 31 December 2006 13,828 Year ended 31 December 2005 5,759 6,030 2,577 0.11 0.10 2,268 388 0.02 0.02 Period ended 31 December 2004 441 (311) (727) (0.03) (0.03) 43,904 21,097 12,781 Revenue increased by 140% 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. An increase of 1,206% in 2005 over 2004 is primarily the result of a longer comparative period. The 2004 comparatives are for the four months ended 31 December 2004. Funds from operations before working capital changes increased by 166% in 2006 and 829% in 2005 primarily as a result of the increase in revenues. The majority of the Company’s costs are fixed in nature. Therefore costs do not increase in proportion to the increase in revenues. Accordingly, the increase in profitability is mainly due to increasing revenues. annual 2006.qxp 5/3/07 10:37 PM Page 49 The Company’s assets increased by 108% to US$43.9 million (2005: 65% to US$21.1 million) in the year ended 31 December 2006. The Company’s assets are made up as follows: (Figures in US$’000) Cash and cash equivalents Trade and other receivables Natural gas properties and other equipment Year ended 31 December 2006 Year ended 31 December 2005 Period ended 31 December 2004 20,678 4,275 24,953 18,951 43,904 3,198 2,862 6,060 15,037 21,097 2,040 441 2,481 10,300 12,781 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 2005 was the result of the one-for-ten rights issue in March 2005. The increase in trade and other receivables is in line with the increase in trading activities and is more fully discussed in ‘Working Capital’ above. In 2006, the Company incurred costs in the preparation for well drilling, expanding its distribution network including the installation of a second pressure reduction station and the connection of the Aggreko and Dowans emergency power plants. This is discussed under ‘Capital Expenditure’ above. The increase in the natural gas properties and other equipment in 2005 was primarily the result of the US$1.9 million seismic acquisition in 2005 and the US$2.1 million extension of the distri- bution network around Dar es Salaam. 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, transportation and marketing of oil and gas. These risks include blowouts, explosions, fire, gaseous leaks, migration of harmful substances and oil spills, any of which could cause personal injury, result in damage to, or destruction of, oil and gas wells or formations or production facilities and other property, equipment and the environ- ment, 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 devel- opment of gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blowouts, equipment failures and other accidents, sour gas releases, uncon- trollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution and other environmental 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 unfavourable 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. 2006 ANNUAL REPORT 50 MANAGEMENT’S DISCUSSION & ANALYSIS 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, expropriation, nationalization, renegotiation or nullification of existing contracts, taxation policies, foreign exchange restrictions, changing political conditions, international monetary fluctuations, currency controls and foreign governmental regulations that favour or require the awarding of drilling contracts to local contrac- tors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. 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 govern- mental 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 organisa- tions 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. 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. Environmental regulations place restrictions and prohibitions on emissions of various substances produced concurrently and oil and natural gas and can impact on the selection of drilling sites and facility locations, potentially 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. 2006 ANNUAL REPORT 52 MANAGEMENT’S DISCUSSION & ANALYSIS 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 explo- ration, acquisition or development activities, Orca Exploration'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 Exploration'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 five 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 difficulties relating to the operation or performance of the field would have a material adverse effect on Orca Exploration. 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 environmental quality, provide for penalties and other liabilities for the violation of such standards and establish in certain circumstances obligations to remediate current and former facilities and locations where operations are or were conducted. In addition, special provisions may be appropriate or required in environmentally sensitive areas of operation. There can be no assurance that 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 EastCoast. 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 governmental legislation and regulation and increased public awareness concerning environmental protection. No provision has been recognised for future decommissioning costs which are anticipated to be immaterial as it is forecast that there will still be commercial gas reserves once EastCoast relin- quishes the licence in 2026. EastCoast 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. 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 availability and capacity of oil and gas gathering systems and pipelines, the effect of foreign regulation of production and transportation, general economic conditions, changes in supply due to drilling by other producers and changes in demand may adversely affect 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. 2006 ANNUAL REPORT 54 MANAGEMENT’S DISCUSSION & ANALYSIS 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 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 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. 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 commence- ment 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 sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not be performed on every well, and structural or environmental problems, such as ground water contam- ination, 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. Reliance on Key Personnel Orca Exploration is highly dependent upon its executive officers and key personnel. The unex- pected 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 99.3% of the outstanding Class A shares and approximately 17.5% of the Class B shares. Consequently, Mr. Lyons holds approximately 22.8% of the equity (24.6% fully diluted) and controls 65.2% of the total votes of Orca Exploration. Financial Statements 2006 ANNUAL REPORT 56 CONSOLIDATED FINANCIAL STATEMENTS Management’s Report to Shareholders 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 transactions 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 and a Reserves Committee. The committees have 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 Independent Auditors’ Report Shareholders 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 subsidiaries (the ‘Group’), which comprise the consolidated balance sheet as at 31 December 2006 and 31 December 2005 and the consolidated income statements, cash flow statements and Statements of Changes in Shareholders’ Equity for the years then ended, and a summary of significant accounting policies and other explanatory notes. 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, implementing and maintaining internal control 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 2006 and 31 December 2005, and of its consolidated financial performance and its consolidated cash flow for the years then ended in accordance with International Financial Reporting Standards. Calgary, Canada 30 April 2007 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 30 April 2007 2006 ANNUAL REPORT 58 CONSOLIDATED FINANCIAL STATEMENTS Consolidated Income Statements ORCA EXPLORATION GROUP INC. (formerly EastCoast Energy Corporation) Y E A R S E N D E D 3 1 D E C E M B E R (thousands of US dollars except per share amounts) NOTE Revenue COST OF SALES Production and distribution expenses Depletion expense Gross profit Other income Administrative expenses Foreign exchange losses Profit before taxation Taxation Profit after taxation Profit per share Basic (US$) Diluted (US$) 2 7 4 11 See accompanying notes to the consolidated financial statements. 2006 13,828 (793) (2,027) 11,008 61 (6,724) (84) 4,261 (1,684) 2,577 0.11 0.10 2005 5,759 (495) (818) 4,446 64 (3,555) (2) 953 (565) 388 0.02 0.02 Consolidated Balance Sheets ORCA EXPLORATION GROUP INC. (formerly EastCoast Energy Corporation) A S A T 3 1 D E C E M B E R (thousands of US dollars) ASSETS Current assets Cash and cash equivalents Trade and other receivables Natural gas properties and other equipment LIABILITIES Current liabilities Trade and other payables Non current liabilities Deferred tax Additional profits tax SHAREHOLDERS’ EQUITY Capital stock Capital reserve Accumulated profit/(loss) Note 2006 2005 5 6 7 8 4 10 20,678 4,275 24,953 18,951 43,904 3,198 2,862 6,060 15,037 21,097 4,523 3,849 1,229 263 34,469 1,182 2,238 37,889 43,904 506 80 16,237 764 (339) 16,662 21,097 Post Balance Sheet Events (Note 14) Contractual Obligations and Committed Capital Investment (Note 16) See accompanying notes to the consolidated financial statements. The consolidated financial statements were approved by the Board on 30 April 2007. Director Director 2006 ANNUAL REPORT annual 2006.qxp 5/3/07 10:38 PM Page 60 60 CONSOLIDATED FINANCIAL STATEMENTS Consolidated Statements of Cash Flows ORCA EXPLORATION GROUP INC. (formerly EastCoast Energy Corporation) Y E A R E N D E D 3 1 D E C E M B E R (thousands of US dollars) CASH FLOWS FROM OPERATING ACTIVITIES Profit after taxation Adjustments for: Depletion and depreciation Stock-based compensation Deferred taxation Additional profits tax Increase in trade and other receivables Increase in trade and other payables Net cash flows from operating activities CASH FLOWS USED IN INVESTING ACTIVITIES Acquisition of natural gas properties and other equipment Increase in trade and other payables Net cash flows used in investing activities CASH FLOWS FROM FINANCING ACTIVITIES Net proceeds from rights issue Proceeds from exercise of options Net cash flows from financing activities Increase in cash and cash equivalents Cash and cash equivalents at the beginning of the year Cash and cash equivalents at the end of the year See accompanying notes to the consolidated financial statements. 2006 2,577 2,129 418 723 183 6,030 (1,413) 540 5,157 (6,043) 134 (5,909) 18,087 145 18,232 17,480 3,198 20,678 2005 388 911 383 506 80 2,268 (2,421) 1,956 1,803 (5,648) 628 (5,020) 4,365 10 4,375 1,158 2,040 3,198 Statements of Changes in Shareholders’ Equity ORCA EXPLORATION GROUP INC. (formerly EastCoast Energy Corporation) Capital reserve Accumulated profit (loss) Total 381 (727) (thousands of US dollars) Note Balance as at 31 December 2004 Rights issue net of share issue costs Options exercised Profit for the year Stock-based compensation Balance as at 31 December 2005 Rights issue Options exercised Profit for the year Stock-based compensation Capital stock 10 11,862 4,365 10 – – 16,237 18,087 145 – – Balance as at 31 December 2006 34,469 See accompanying notes to the consolidated financial statements. – – – 383 764 – – – 418 1,182 – – 388 – (339) – – 2,577 – 11,516 4,365 10 388 383 16,662 18,087 145 2,577 418 2,238 37,889 2006 ANNUAL REPORT 62 Notes to the Consolidated Financial Statements 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 five 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 can only be used principally 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. 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 PO LICIES 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 12. 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 Registered Holding Orca Exploration Group Inc. (formerly British Virgin Islands Parent Company EastCoast Energy Corporation) PAE PanAfrican Energy Corporation PanAfrican Energy Tanzania Limited ii) Transactions eliminated upon consolidation Mauritius Jersey 100% 100% 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 trans- lated using the exchange rates that existed when the values were determined. Any resulting exchange rate differences are taken to the income statement. d) Natural gas properties The Company follows the full cost method of accounting for natural gas operations. Capitalised costs include land acquisition, geological and geophysical activities, lease rentals on non-producing properties, drilling both productive and non-productive wells, pipeline and related gas distribution equipment, and overhead charges directly related to exploration and development activities. Costs are depleted on the unit-of-production method based on the estimated proved reserves as estimated by independent reservoir engineers. Costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties, or impairment occurs. Costs incurred are not depleted until commercial production commences. These capitalised costs are periodically assessed to determine whether it is likely that such costs will be recovered in the future. To the extent that there are costs that are unlikely to be recovered in the future, they are written off and charged to income. The carrying amounts are assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves exceed the carrying amount of the natural gas properties. When the carrying amount is not assessed as recoverable, an impairment loss is recognized to the extent that the carrying amount of the natural gas properties exceeds the sum of the discounted cash flows from the production of proved and probable reserves. The cash flows are estimated using expected future product prices and costs and discounted using a risk-free rate. Proceeds from the sale of natural gas properties are applied against capital costs with no gain or loss recognized, unless the sale would alter the depletion and depreciation rate by 20% or more. 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. 2006 ANNUAL REPORT 64 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS h) Employment benefits i) Pension The Company does not operate a pension plan, but it does make defined contributions to the statutory pension fund for employees in Tanzania. Obligations for contributions to the statutory pension fund are recognised as an expense in the income statement as incurred. ii) 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 under the rules of IFRS2, Accounting for Share-Based Payments, whereby the fair value of such options is expensed to the income statement in accordance with the specific vesting periods. The fair value of the options is calculated on the grant date using the Black-Scholes option pricing model. iii) Stock appreciation rights Stock appreciation rights are issued to certain key managers and employees. The Company accounts for stock appreciation rights under the rules of IFRS2, Accounting for Share-Based Payments, 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 obligation under the PSA to restore the fields at the end of their commercial lives. 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 produc- tion 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 ‘Natural Gas Properties’. 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 grossed up 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 assets can be utilised. Deferred tax assets are reduced to the extent that it is no longer probable that the related tax benefits will be realised. m) Segmental reporting No segmental information has been presented, since all the revenue generating operations and assets are located in Tanzania. n) Measurement uncertainty The amounts recorded for depletion and depreciation of natural gas properties and the cost recovery ceiling test are based on estimates. These estimates include proven and probable reserves, production rates, natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect of changes in such estimates on the financial statements of future periods could be significant. 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 2006 ANNUAL REPORT 66 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2 REVENUE Years ended 31 December Figures in US$’000 Operating revenue Gross-up for current income tax Deferred additional profits tax Revenue 2006 12,638 1,373 (183) 13,828 2005 5,652 187 (80) 5,759 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$13,828,000 after adjusting the Company’s operating revenue of US$12,638,000 by: i) US$1,373,000 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, revenues are grossed up for the current income tax; ii) US$183,000 for the deferred effect of Additional Profits Tax. This tax is netted off revenue as a royalty. 3 PERSONNEL EXPENSES The average number of employees during the year was 15 (2005: 12). The costs are as follows: Years ended 31 December Figures in US$’000 Wages and salaries Social security costs Other statutory staff costs 4 TAXATION 2006 1,451 159 226 1,836 2005 701 87 58 846 Under the terms of the PSA with TPDC, the Company is liable for income tax in Tanzania at a corporate tax rate of 30%. However, where income tax is payable, the profit available to TPDC is reduced by this amount. This is reflected in the accounts by grossing up the amount of the Company’s net revenue for the current income tax and showing the income tax as a current tax expense. Under the terms of the Tanzanian Income Tax Act, the Company generated 2006 tax profits and accordingly is liable to pay income tax. During the year, the Company paid income tax amounting to US$1,049,000 for the 2006 provisional taxes (against a current tax charge of US$961,000) and US$59,000 for the final income tax for 2005. The US$88,000 overpayment of the 2006 current tax will be set against future tax liabilities. The Company has recovered US$954,000 from TPDC’s profit share during 2006 and the remainder of US$154,000 will be recovered in 2007. The tax charge may be analysed as follows: Years ended 31 December Figures in US$’000 Current tax Deferred tax Tax Rate Reconciliation Years ended 31 December Figures in US$’000 Profit before taxation Provision for income tax calculated at the statutory rate Add/(deduct) the tax effect of non-deductible income tax items: Other income Administrative and operating expenses Stock based compensation Permanent differences Reversal of previously unrecognised deferred tax asset 2006 961 723 1,684 2006 4,261 1,278 (15) 170 125 126 – 1,684 2005 59 506 565 2005 953 286 (19) 161 115 82 (60) 565 At 31 December 2006, there were temporary differences between the carrying value of the assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Accordingly a deferred tax liability has been recognized for the year ended 31 December 2006. The deferred income tax liability includes the following temporary differences: Years ended 31 December Figures in US$’000 Differences between tax base and carrying value of natural gas properties Income tax grossed-up in revenue Provision for stock option bonuses Additional profits tax 5 CASH AND CASH EQUI VALENTS As at 31 December Figures in US$’000 Cash and short term deposits 2006 992 451 (135) (79) 1,229 2005 474 56 – (24) 506 2006 20,678 2005 3,198 Included in the cash and cash equivalents are: - - US$36,000 advanced from Songas under the terms of the Operatorship Agreement to pay for the costs of operating the wells and gas processing plant. US$185,000 advanced from Murzah Oil Industries Limited, East Coast Oils & Foods Limited, Nampak Tanzania Limited and Yuasa Batteries (East Africa) Limited, as a deposit for their pipeline connections. This will be repaid once they have consumed in excess of US$375,000 of Additional Gas. These amounts are also included in trade and other payables. 2006 ANNUAL REPORT 68 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 6 TRADE AND OTHER RECEIVABLES As at 31 December Figures in US$’000 Trade receivables Prepayments Other receivables 7 NATURAL GAS PR OPERTIES AND OTHER EQUIPMENT 2006 3,441 159 675 4,275 2005 2,419 150 293 2,862 Figures in US$’000 Costs As at 1 January 2006 Additions As at 31 December 2006 Depletion/Depreciation As at 1 January 2006 Charge for the year As at 31 December 2006 Net Book Values As at 31 December 2006 As at 31 December 2005 Natural gas properties Leasehold improvements Computer equipment Vehicles Fixtures & fittings Total 15,693 6,008 21,701 853 2,027 2,880 18,821 14,840 156 – 156 49 45 94 62 107 59 4 63 19 23 42 21 40 38 27 65 13 20 33 32 25 37 4 41 12 14 26 15 25 15,983 6,043 22,026 946 2,129 3,075 18,951 15,037 In determining the depletion charge, it is estimated by the independent reserve engineers that future development costs of US$123.8 million (2005: US$69.6 million) will be required to bring the total proved reserves to production. 8 TRADE AND OTHER PAYABLES As at 31 December Figures in US$’000 Trade payables Accrued liabilities Related party (note 15) Deferred income Income tax Deposits 2006 1,733 2,083 472 138 (88) 185 4,523 2005 1,812 1,750 118 – 59 110 3,849 9 FINANCIAL INSTRUMENTS The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in its operations. Credit risk 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 34.7% of the Company’s operating revenue during 2006 and US$1.5 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 currently experiencing financial difficulties principally caused by the loss of hydro electricity generation capacity during 2006. Whilst some payments have been delayed, the Company collected all amounts due from Songas for all gas sales to 31 December 2006. US$198,000 remains outstanding from TANESCO being the VAT element for the supply of Additional Gas to the emergency power plants. TANESCO is not disputing this balance and the management believes that the balance is recoverable. Foreign currency risk The Company’s exposure to foreign currency risk is limited to exchange rate fluctuations on foreign currency cash balances and the expenditure in currencies other than the US dollar. Commodity prices The Company did not enter into any financial contracts during the year. Fair values Financial instruments of the Company carried on the balance sheet consist mainly of current assets and current liabilities. There were no significant differences between the carrying value of these financial instruments and their estimated fair value due to their short term to maturity. 10 CAPITAL STOCK a) Authorised 50,000,000 Class A Common Shares 50,000,000 Class B Subordinate Voting Shares No par value No par value The Class A and Class B shares rank pari passu in respect of dividends and repayment of capital in the event of winding-up. Class A shares carry twenty votes per share and Class B shares carry one vote per share. The Class A shares are convertible at the option of the holder at any time into Class B shares on a one-for-one basis. The Class B shares are convertible into Class A shares on a one-for-one basis in the event that a take over bid is made to purchase Class A shares which must, by reason of a stock exchange or legal require- ments, 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. 2006 ANNUAL REPORT 70 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS b) Changes in the capital stock of the Company were as follows: Thousands of shares or US$000 Authorised Issued Valuation Authorised Issued Valuation 2006 2005 Class A shares As at 1 January & 31 December 50,000 1,751 983 50,000 1,751 983 Class B shares As at 1 January Issued, net of share issue costs Options exercised As at 31 December 50,000 21,513 15,254 50,000 19,386 10,879 – – 3,345 18,087 165 145 – – 2,114 4,365 13 10 50,000 25,023 33,486 50,000 21,513 15,254 Total Class A & B shares at 31 December 100,000 26,774 34,469 100,000 23,264 16,237 The Company issued 3,345,540 Class B shares at Cdn$6.43 per share following a successful one for seven rights issue that completed on 29 December 2006. Net proceeds of US$18.1 million were raised for the Company. The funds will be primarily used for the drilling of the SS-10 development well, the expansion of the low pressure distribution system and new growth opportunities. Under the terms of the rights issue: a each holder of Class B shares was entitled to receive one right for each Class B held and seven rights entitled the holder to subscribe for one Class be share at a price of Cdn$6.43. a each holder of Class A shares was entitled to receive one right for each Class A share held and seven rights entitled the holder to subscribe for on Class B share at a price of Cdn$6.43. a each holder of rights who exercised all of their rights was entitled to subscribe for additional Class B shares that had not been subscribed and paid for at the closing date (“Additional Subscription Privilege”). The subscription price of Cdn$6.43 represented a 15% discount to the closing price of the Class B shares on 7 September 2006. 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. 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 movement of share options may be summarised as follows: Outstanding as at 1 January Granted Exercised 2006 2005 Options 1,987,400 200,000 (165,000) Price 1.00 6.80 1.00 Options 2,000,000 – (12,600) Outstanding as at 31 December 2,022,400 1.00 – 6.80 1,987,400 Price 1.00 – 1.00 1.00 2,000,000 options were issued to certain Directors and Officers on 1 September 2004 at a price of Cdn$1.00 per option. These options have a term of 10 years. US$306,000 was expensed in 2006 (2005: U$383,000) in relation to these options which are now fully vested. During the year, 165,000 of these 2004 options were exercised at a price of Cdn$1.00 per option. A total of 1,822,400 of these options remained outstanding at the year end. On 1 September 2006, 200,000 options were issued at a price of Cdn$6.80 per option. These options have a term of 5 years and vest in three equal annual instalments starting on 1 September 2007. The fair value of these options were estimated at the grant date using the Black-Scholes option pricing model with the following assump- tions: risk free rate of 2.6%, dividend yield of 0%, expected life of 5 years and volatility of 80%. US$112,000 was expensed in 2006 in relation to these options. The total remaining to be expensed at 31 December 2006 amounted to US$899,000. 11 PROFIT PER SHARE The calculation of basic profit per share is based on the net profit attributable to ordinary shareholders of US$2,577,000 (2005: US$388,000) and a weighted average number of ordinary shares outstanding during the period of 24,908,940 (2005: 22,902,699). In computing the diluted earnings per share, the dilutive effect of the Options was 1,513,463 (2005: 1,418,875) shares. These were added to the weighted average number of common shares outstanding during the year ended 31 December, 2006. No adjustments were required to reported earnings from operations in computing diluted per share amounts. 2006 ANNUAL REPORT 72 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 12 RECONCILIATION O F IFRS TO ACCOUNTI NG PR INCIPLES GENERALLY ACCEPTED IN CANADA The consolidated financial statements have been prepared in accordance with the IFRS basis of accounting, which differ in some respects from those in Canada. This reconciliation discloses the differences between IFRS and Canadian Generally Accepted Accounting Principles (“GAAP”). On 31 August 2004, the Company was spun off from a predecessor company pursuant to a scheme of arrange- ment. Under Canadian GAAP, a deferred tax liability has to be recognised for the taxable temporary differences arising from the initial recognition of an asset or liability under any scenario. IFRS does not permit the setting up of a deferred tax liability for all taxable temporary differences arising from the initial recognition of an asset or liability except in a business combination. The Company has implemented a bonus scheme that incorporates stock appreciation rights ("rights") that have a maximum pay out of Cdn$ 1.2 million as at 31 December 2007. Under IFRS, 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 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 following are the differences in accounting principles: As at 31 December Figures in US$’000 Current assets Natural gas properties and other equipment Current liabilities Non-current liabilities Capital stock Reserves 2006 2005 IAS 24,953 18,951 43,904 4,523 1,492 34,469 3,420 43,904 CDN 24,953 20,594 45,547 4,523 3,266 34,469 3,289 45,547 IAS 6,060 15,037 21,097 3,849 586 16,237 425 21,097 CDN 6,060 16,852 22,912 3,849 2,385 16,237 441 22,912 Profit before taxation 4,261 4,114 953 969 13 OP ERATING LEASES Non-cancellable operating lease rentals are payable as follows: As at 31 December Figures in US$’000 Less than one year Between one and five years 2006 88 – 88 2005 92 107 199 The Company has rented office property under a five year operating lease expiring 30 November 2007. 14 POST BALANCE SHEET EVENTS On 14 January 2007, the Company issued 300,000 options to a newly appointed officer at a price of Cdn$8.00 per option. These options have a term of 5 years and vest in three equal annual instalments starting on 14 January 2008. In addition, 300,000 stock appreciation rights were issued to the same officer at an exercise price of US$8.00 per right. These stock appreciation rights have a term of 5 years and vest in three equal annual instal- ments starting on 14 January 2008. 200,000 Treasury Shares were awarded to the same officer in April 2007. These vest in three equal annual instalments starting 7 April 2007. On 2 January 2007, the Company issued 300,000 stock appreciation rights to a consultant at an exercise price of US$8.70 per right. The consultant is facilitating the search for new venture opportunities for the Company. These stock appreciation rights have a term of 5 years and vest in three equal annual installments starting on 2 January 2008. 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. There are no other Post Balance Sheet Events other than those disclosed under ‘Contractual Obligations and Committed Capital Investment’. 15 RELATED PARTY TRANSACTIONS The following transactions were carried out with related parties: i) During the year, the Company entered into an agreement, a company owned by the non-Executive Chairman, to underwrite all the rights issue at a fixed fee of US$300,000. ii) One of the non executive Directors is a partner at a law firm. During the year, the Company incurred US$176,000 to this firm for services provided on rights issue and other legal services. The transactions with these related parties were made on the exchange amount. 2006 ANNUAL REPORT 74 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 16 CONTRACTUAL O BLIGATIONS AND COMMITTED CAPITAL INVESTMENT During the year, the Company committed to drilling a development well, SS-10 and to undertake some remedial work on the offshore well, SS-9. Preparations for these operations, including the purchase of long-lead materials and equipment, started during the year. The remedial work on SS-9 was successfully completed in Q1 2007. SS-10 was spud in April 2007. The Company has committed to spend a total of US$12.9-US$14.9 million on these projects of which US$3.7 million had already been incurred by 31 December 2006. The Company has committed to expanding the distribution system including the installation of an additional pressure reduction station and the laying of 8 kilometers of new low pressure pipeline in the first half of 2007. This work is required to increase security of supply and to meet forecast increases in demand from both existing and new industrial customers. The work is estimated to cost US$2.2 million. As at the year end, the Company had already spent US$0.3 million for the purchase of long lead equipment and project management. 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. 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 (7.4 bcf as at 31 December 2006). 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 two years 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 Protected Gas insufficiency. It is forecast that the security mechanism will be finalised by the end of Q2 2007. 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 produc- tion 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’. 17 DIRECTORS AND OFFICERS EMOLUMENTS USD’000 except no. of share options Base compensation Year Bonus Other compensation Total Outstanding Share options 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), (iii) Non Executive Director David W. Ross Non Executive Director Robert Spence (i), (iv) Non Executive Director Other Pierre Raillard (ii) Vice President Operations 2006 2005 2006 2005 2006 2005 2006 2005 2006 2005 2006 2005 2006 2005 2006 2005 19 21 406 313 283 220 30 19 8 – – – 16 18 182 133 – – 75 60 55 43 – – – – – – – – 65 23 – – – – – – – – – – – – – – 19 21 481 373 338 263 30 19 8 – – – 16 18 1,000,000 1,000,000 300,000 400,000 180,000 200,000 50,000 50,000 – – – – 50,000 50,000 30 – 277 156 200,000 200,000 (i) (ii) 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. In 2005, 50% of the costs of P. Raillard were recharged to Songas for the work undertaken on operating the gas processing plant and maintaining the wells. Accordingly, the emoluments for 2005 outlined above represent the costs paid directly by the Company. During 2006, Songas paid the Company a fixed cost of US$28,650 per month for these services. (iii) J. Smith was elected to the Board at the Annual General Meeting on 14 November 2006. (iv) R. Spence did not seek re-election at the Annual General Meeting on 14 November 2006. 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 EXPLORATIONS'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 Peter R. Clutterbuck, CEO +44 (0) 7768 120727 nfriend@orcaexploration.com prclutterbuck@orcaexploration.com or visit the Company's web site at www.orcaexploration.com. annual 2006.qxp 5/3/07 10:38 PM Page 76 76 Corporate Information Board of Directors W. DAVID LYONS Non-Executive Chairman St. Helier Jersey JOHN PATTERSON Non-Executive Director Nanoose Bay Canada Officers PIERRE RAILLARD Vice President Operations Operating Office ORCA EXPLORATION GROUP INC. Barclays House, 5th Floor Ohio Street, P.O. Box 80139 Dar es Salaam Tanzania Tel: + 255 22 2138737 Fax: + 255 22 2138938 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 NIGEL A. FRIEND Chief Financial Officer London United Kingdom JAMES SMITH Vice President Exploration Hurst United Kingdom PETER R. CLUTTERBUCK President & Chief Executive Officer Haslemere United Kingdom DAVID ROSS Non-Executive Director Calgary Canada DAVID W. ROSS Company Secretary Registered Office ORCA EXPLORATION GROUP INC. P.O. Box 3152, Road Town Tortola British Virgin Islands Investor Relations NIGEL A. FRIEND Chief Financial Officer Tel: + 255 22 2138737 nfriend@orcaexploration.com www.orcaexploration.com PAE PanAfrican Energy Corporation 1st Floor Cnr St George/Chazal Streets Port Louis Mauritius Tel: + 230 207 8888 Fax: + 230 207 8833 Engineering Consultants McDaniel & Associates Consultants Ltd. Calgary Canada Auditors KPMG LLP Calgary Canada Lawyers Burnet, Duckworth & Palmer LLP Calgary Canada Transfer Agent CIBC Mellon Trust Company Toronto, Montreal and Calgary, Canada 2006 ANNUAL REPORT w w w . o r c a e x p l o r a t i o n . c o m 

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