2009 A n n u a l R e p o r t Orca Exploration Group Inc. strategic growth Orca Exploration Group Inc. is a well-financed, international public company engaged in hydrocarbon exploration, development and supply of gas in Tanzania. It is also currently evaluating a number of high potential oil exploration and production opportunities. Orca Exploration trades on the TSXV under the trading symbols ORC.B and ORC.A. Financial and Operating Highlights 1 Chairman & CEO’s letter to shareholders 2 Operations review 6 Management’s Discussion & Analysis 24 Management’s report to shareholders 44 Auditors’ report 45 Financial statements 46 Notes to the consolidated financial statements 50 Corporate Information 67 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$), unless otherwise noted. Glossary mcf MMcf Bcf Tcf MMcfd Mmbtu HHV LLV Thousands of standard cubic feet Millions of standard cubic feet Billions of standard cubic feet Trillions of standard cubic feet Millions of standard cubic feet per day Millions of British thermal units High heat value Low heat value 1P 2P 3P GIIP Kwh MW US$ Cdn$ bar Proven reserves Proven and probable reserves Proven, probable and possible reserves Flare Gas initially in place Addtional Gas Sales Kilowatt hour Protected Gas Sales Megawatt US dollars Canadian dollars Production Volumes Fifteen pounds pressure per square inch Financial and Operating Highlights YEARS EndEd / AS AT 31 dECEmBER Financial (US$ except where otherwise stated) Revenue Profit/(loss) before taxation Operating netback (US$/mcf) Cash and cash equivalents Working capital Shareholders’ equity Profit/(loss) per share - basic and diluted (US$) Funds from operations before working capital changes Funds per share from operations before working capital changes - basic (US$) Funds per share from operations before working capital changes - diluted (US$) Net cash flows from operating activities Net cash flows per share from operating activities - basic (US$) Net cash flows per share from operating activities - diluted (US$) Outstanding Shares (‘000) Class A shares Class B shares Options Operating Additional Gas sold (MMcf) - industrial Additional Gas sold (MMcf) - power Additional Gas sold (MMcf/d) - industrial Additional Gas sold (MMcf/d) - power Average price per mcf (US$) - industrial Average price per mcf (US$) - power 2009 25,317 6,882 2.21 14,543 16,835 68,860 0.11 12,674 0.43 0.41 12,284 0.42 0.40 1,751 27,743 2,797 2,096 8,326 5.7 22.8 8.36 2.40 Additional Gas, Company Gross Recoverable Reserves to end of licence (Bcf) Proved Probable Proved plus probable Present Value, discounted at 10% (US$ million) Proved Proved plus probable 385 105 490 248 291 2008 Change 23,782 (7,056) 2.60 10,586 9,727 64,712 (0.32) 9,751 0.33 0.31 5,185 0.18 0.17 1,751 27,863 2,814 1,475 7,185 4.0 19.7 11.98 2.37 389 102 491 258 299 6% n/a (15%) 37% 73% 6% n/a 30% 30% 32% 137% 133% 135% 0% 0% (1%) 42% 16% 42% 16% (30%) 1% (1%) 3% 0% (4%) (3%) 1 Chairman & CEO’s Letter to Shareholders During 2009 Orca Exploration strengthened its financial position generating US$12.7 million of funds flow before working capital changes, finishing the year with cash resources of US$14.5 million and no debt. The Company’s cash generative natural gas production and marketing operations in Tanzania continue to provide Orca with a solid financial and operating foundation. During 2010 the Tanzanian operations are forecast to generate between US$15 million and US$20 million. Orca is well positioned to expand its reserve base and to seek additional growth through the future acquisition and drilling of new oil exploration prospects in Africa, the Middle East or southern Europe. The Company is also planning the drilling in 2011 of a low risk, high potential exploration prospect adjacent to the Orca operated Songo Songo natural gas field. Exploration acquisition targets are currently under close review. They must meet carefully selected strategic growth criteria – a proven hydrocarbon basin, the ability to draw on a knowledge base about the region, significant upside potential and the ability to drill within two years. The preference is for oil interests that can be commercialised rapidly with low upfront capital expenditure. Orca has emerged from the financial turmoil of the past year in a strong operating, marketing and financial position. General and administrative expenses have been reduced and opportunities for growth in the market for Tanzanian natural gas continue to increase. The outlook for Orca Exploration is positive. After some consolidation in 2010 as the Company grows its asset base, 2011 is expected to be a significant year with the potential that relatively low risk exploration wells will be drilled. 2010 Tanzanian targets During 2010, the Company will work to build larger natural gas markets in Tanzania to maximise the utilisation of existing proven and probable reserves. Because significantly increased natural gas sales are now dependent on expanded natural gas processing and throughput from the Songo Songo field, work on resolving these issues will be a priority in 2010. The principal targets for 2010 are to: • • • • Increase the gas processing and transportation capacity to 105 MMcfd on a temporary basis by working with the infrastructure owners, Songas Limited, to ensure this is achievable; Assist Songas in planning a permanent expansion of the infrastructure system to 144 MMcfd so that the infrastructure development can commence in Q2 2011 (with the intention that the extra capacity will be operational by the end of 2012); Finalise long term power contracts that will underwrite the requirement for the infrastructure development; and Prepare for the drilling of a high impact exploration prospect in 2011 with the view to connecting this to the gas processing facilities on Songo Songo Island in 2012 if successful. 2 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t A plan to increase Songo Songo reserves Increasing gas deliverability As at 31 December 2009, the independent reserve evaluator, McDaniel and Associates Consultants Ltd. (“McDaniel”) assessed that the Company’s gross proven (1P) and proven and probable (2P) Songo Songo Additional Gas reserves to the end of the licence period to be 384.9 (2008: 389.4 Bcf) and 490.2 (2008: 491.4 Bcf) respectively. This represents a marginal decrease over 2008 due to produced volumes, but is an increase on original reserves. Since the field was brought on production in 2004, there has been a 125% increase in the 1P and a 92% increase in the 2P Company gross Additional Gas reserves to the end of the license period. The Company continues to collect pressure data to be used in future reserve evaluations. Based on the current reserves and anticipated field deliverability profiles, Orca intends to develop gas markets that will utilise approximately 100 to 120 MMcfd of Additional Gas (140 – 160 MMcfd including Protected Gas) on an average annual basis. To meet these sales levels, there is the need to drill two new development wells in the field. Orca anticipates that reserves can be further increased by the drilling of the Songo Songo West exploration prospect. McDaniel evaluated this prospect and assessed it to contain unrisked mean resources of 551 Bcf and an upside case in excess of 1 Tcf. This prospect will be drilled in 2011. In Q1 2009, Songas approved the re-rating of the Songo Songo gas processing plant from 70 MMcfd to 90 MMcfd, after the Company, as operator, successfully completed the installation of two new Joule-Thompson valves, associated pipework and process modifications. The importance of the re-rating was demonstrated in the last two quarters of 2009, when production was typically 70-80 MMcfd, peaking at over 85 MMcfd. Capacity constraints are expected to become more acute in 2010 as demand for gas increases in Dar es Salaam. In 2009, the Company continued its outstanding record of operational excellence, with over 5 years of continuous gas production without any unplanned downtime. During 2009, the Company proposed a new long term infrastructure expansion project (the “Expansion Project”) based on Songas financing two new gas processing trains and pipeline compression to increase the throughput capacity to 144 MMcfd (compared to the existing 90 MMcfd). This could be further enhanced in future years by the installation of a twin onshore pipeline that would increase the capacity to 200 MMcfd. Songas has accepted the initial design and feasibility work undertaken by Orca and is working with the energy regulator EWURA on financial terms. The target for notice to proceed to be given to the engineering contractor is Q1 2011. This would enable the Expansion Project to be operational by the end of 2012. It is envisaged that Songas may allow a short term increase in the infrastructure capacity to 105 MMcfd once commitments to the Expansion Project are in place and gas demand requires it. Lloyds Register inspected the gas heat exchangers on the gas processing plant in Q1 2009 and indicated a willingness to certify the plant to operate at 110 MMcfd. The limiting component would then be the high pressure pipeline that has an estimated deliverability of 105 MMcfd. Is est, iniminv endenesed et quunt ex estotatio. Loria siti volorro voluptus ant.Usam dolorem. Icia sinte nulluptat. FAR LEFT: The new Wazo Hill cement plant kiln #4 is operating on Additional Gas supplied by Orca. LEFT: A new pressure reduction station was constructed to expand the Company’s industrial gas distribution capacity. 3 Chairman & CEO’s Letter to Shareholders Expanding downstream distribution capability Additional Gas sales growth The most significant downstream developments in 2009 were the construction of a new pressure reduction station at the Wazo Hill cement plant, the connection of the new Tegeta 45 MW power plant and the completion of the initial phase of the compressed natural gas (CNG) project for vehicles. The total cost of these activities in 2009 was US$3.6 million. During 2009, the Company increased Additional Gas sales volumes by 20% to an average of 28.5 MMcfd. Sales to the newly commissioned Tegeta 45 MW power plant in Q4 2009 and the new US$100 million cement kiln at Wazo Hill in Q2 2009 were major factors in this upward trend. During Q4 2009 sales volumes increased to 33.8 MMcfd. With the addition of Tegeta there are now three large power stations connected to and consuming Additional Gas supplied by Orca. The industrial market also continues to expand. 35 industrial customers have now been connected, of which 27 were consuming the Company’s gas at the end of 2009. The commencement of CNG supply by truck to hotels in Dar es Salaam was a significant step in demonstrating the viability of transporting natural gas to customers that are not located on the existing low pressure pipeline network. These CNG projects are the first in East Africa. Based on the existing industrial contracts and the 189 MWs of permanent gas fired generation that is currently in place, it is forecast that demand will increase to an average of 35 – 40 MMcfd for 2010. Tanzania Portland Cement Company (“TPCC”) the owner of the Wazo Hill cement plant is forecast to increase its consumption to 4.0 MMcfd beginning in Q2 2010 when production of cement recommences from one of its kilns that was refurbished in 2009. There are still a number of growth opportunities that the Company would like to pursue in 2010 (auto power generation by industrial customers and CNG sales). However infrastructure capacity will limit growth until there is a further short term re-rating to 105 MMcfd. During 2011, it is forecast that there will be a step change in power plant demand. TANESCO is preparing for another 100 MWs to come on stream and this is likely to consume the majority of any spare infrastructure capacity even if the short term re-rating is approved. It is not expected that any further gas fired generation will be tendered in Tanzania until the notice to proceed has been given for the construction of the Expansion Project. 4 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Financial results Positive outlook Orca Exploration’s 2009 revenues increased 6% to US$25.3 million compared to 2008. Funds from operations before working capital changes increased 30% to US$12.7 million. The Company’s sales revenues were shielded from low oil price risks due to fixed gas price contracts, and floors tied to oil pricing. Cash flows benefitted from a 22% reduction in general and administrative costs to US$11.5 million. The majority of these costs involve the operation of the Songo Songo gas wells and gas processing operations rather than corporate overheads. During 2009, the Company continued to receive the maximum amount of Cost Gas. In the second half of 2010, cash flows may be sufficiently strong enough to see a reduction in the Cost Gas and a higher Profit Gas contribution. Management changes Orca wants to express its appreciation to Peter Clutterbuck for his leadership as CEO since the Company came into existence in 2004. He stepped down in late March 2010 to assume the role of Deputy Chairman. Mr. Clutterbuck has played a key role in advancing Orca’s growth and development over its first six years and on behalf of the Board of Directors and our shareholders we thank him for his many contributions. Orca Exploration enters 2010 in a strong financial, operating and expansion position, as a result of revenue growth, and tight financial discipline. The Company is expected to continue to increase its cash generation from the Tanzanian assets in 2010 and is excited about its potential to grow substantially through exploration drilling in Tanzania and other drilling programs involving acquisitions now under active review. The Company is well placed to add assets due to its strong financial base, and the utilisation of a management team that has the full range of expertise needed to manage oil and gas exploration and production at the highest standards. Orca appreciates the confidence and support of its loyal shareholders. Management remains very optimistic about your Company’s prospects in Tanzania and other countries. It will work hard to seek additional growth, expand Orca’s reserve base, and build more value for the Company. David Lyons Chairman and CEO 19 April, 2010 The Company is excited about its potential to grow substantially through exploration drilling in Tanzania and other drilling programs involving acquisitions now under active review. 5 Operations Review Production During 2009, 23.6 Bcf (2008: 20.1 Bcf) of natural gas was produced from the Songo Songo field offshore Tanzania or an average of 64.8 MMcfd (2008: 54.9 MMcfd). This brings total production since commercial operations commenced on 20 July 2004 to 100.7 Bcf. In the second half of the year production volumes were on average 12% higher than in 2008. In January 2009 the gas processing plant capacity at Songo Songo Island, was recertified to 90 MMcfd from 70 MMcfd by Lloyds Register following the installation of two new 3” Joule-Thompson valves. The recertification enabled the Company to increase production to meet higher demand for gas in the second half of 2009. Songo Songo production by well The production from the five Songo Songo wells between 2004 and 2009 has been as follows: 12,000 WELL Additional Gas volumes 2004 Power Sales 2005 Industrial Sales Bcf 1.3 1.9 3.9 3.8 3.8 2006 2007 2008 2009 Total Bcf 1.5 1.9 8.9 3.2 2.5 Bcf 1.9 1.1 8.5 3.4 4.8 Bcf 1.5 0.9 7.1 3.5 7.1 Bcf 2.3 1.5 8.4 3.9 7.5 Bcf 9.3 7.9 38.5 19.3 25.7 Bcf 0.8 0.6 1.7 1.5 – 10,000 SS-3 8,000 f c M M SS-4 6,000 SS-5 4,000 SS-7 2,000 SS-9 0 Total 2004 2005 2006 2007 2008 2009 4.6 14.7 18.0 19.7 20.1 23.6 100.7 The total gas production from the Songo Songo field between 2004 and 2009 was allocated as follows: 2007 2008 Production volumes Bcf Bcf 11.5 7.7 0.5 19.7 11.1 8.7 0.3 20.1 2009 Total Flare Bcf 13.0 10.4 0.2 23.6 Bcf Additional Gas sales 64.6 Protected 34.2 Gas sales 1.9 100.7 2004 2005 2006 2007 2008 2009 Production volumes Flare Additional Gas sales Protected Gas sales 2004 2005 2006 2007 2008 2009 25,000 2006 Bcf 20,000 13.0 4.8 15,000 f c M M 0.2 10,000 18.0 5,000 0 25,000 20,000 f c M M 15,000 10,000 5,000 0 15,000 12,000 Protected Gas volumes by year Additional Gas volumes 12,000 10,000 Protected Gas sales 8,000 Additional Gas sales 9,000 f c f c M M M M 6,000 Flare, generator at the processing plant and line pack 6,000 4,000 Total 3,000 2,000 2004 Bcf 4.1 0.1 0.4 4.6 2005 Wazo Hill Power Sales Bcf Ubungo Industrial Power Plant 11.9 Sales 2.5 0.3 14.7 0 0 2004 2004 2005 2005 2006 2006 2007 2007 2008 2008 2009 2009 80 15,000 70 12,000 60 50 d 9,000 f c M M 40 6,000 30 20 3,000 f c M M Protected Gas volumes by year Wazo Hill 2008 2009 Ubungo Power Plant Average daily production per month Jan Feb Mar April May June July Aug Sept Oct Nov Dec 0 The large fall off in the production witnessed in the second quarter of 2008 was due to the exceptionally heavy rains and a switch to hydro-electricity generation. 2009 2005 2004 2008 2007 2006 2008 2009 6 80 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t d f c M M 70 60 50 40 30 20 Average daily production per month Jan Feb Mar April May June July Aug Sept Oct Nov Dec 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: 1. 2. 3. The operation of five turbines at the Ubungo power plant; Onward sale to the Tanzanian Portland Cement Company (“TPCC”) for the operation of kilns 2 and 3 at its Wazo Hill cement plant; and Village electrification (at a rate not to exceed 1 MMcfd). The Protected Gas was allocated as follows: YEAR EndEd 31 dECEmBER Protected Gas user Ubungo power plant Wazo Hill cement plant Village electrification programme Total consumption Protected Gas consumed 2009 Utilisation rate Protected Gas consumed 2008 Utilisation rate Bcf MMcf/d % Bcf MMcf/d % 11.5 1.2 – 12.7 31.5 4.2 – 35.7 82% 71% – 80% 9.5 1.6 – 11.1 25.8 4.5 – 30.3 67% 76% – 67% Protected Gas utilisation increased at the Ubungo power plant in 2009 as the increase in the hydro generation capacity during the rainy season was offset by increasing demand for electricity in Tanzania. Since commercial operations commenced, the Protected Gas utilisation at the Ubungo power plant has been 77%. 12,000 At the Wazo Hill cement plant, the 2009 utilisation rate averaged 71% (2008: 76%). The village electrification program was not functional in 2009, but it is due to be operational during 2010. Industrial Sales Additional Gas volumes 10,000 Power Sales f c 8,000 The maximum gas required for the Protected Gas users over the remaining 14 years and seven months of the Gas Agreement was 240 Bcf as at 31 December 2009. 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. These assumptions are reviewed on an annual basis based on historic and projected usage. 6,000 M M 4,000 f c M M 2,000 0 15,000 12,000 9,000 6,000 3,000 0 80 70 60 50 40 30 20 d f c M M 2004 2005 2006 2007 2008 2009 Protected Gas volumes by year Wazo Hill Ubungo Power Plant 25,000 20,000 Production volumes Flare Additional Gas sales f c M M 15,000 In 2009, Protected Gas volumes were 12% higher than in 2008. 10,000 Protected Gas sales 2004 2005 2006 2007 2008 2009 2004 2005 2006 2007 2008 2009 5,000 0 2008 2009 7 Average daily production per month Jan Feb Mar April May June July Aug Sept Oct Nov Dec Operations Review The Protected Gas users and their forecast maximum and most likely demand are as follows: PROTECTEd GAS dEmAnd Six gas turbines at the Ubungo power plant 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) Theoretical maximum 100% load factor MMcfd 47.4 (9.2) 38.2 5.9 1.0 45.1 240 Consumption in 2009 MMcfd 39.2 (7.7) 31.5 4.2 – 35.7 Most likely MMcfd 39.1 (7.8) 31.3 4.2 1.0 36.5 195 The forecast theoretical maximum demand by the Protected Gas users is estimated to be 45.1 MMcfd based on technical tests of the Ubungo turbines and the Wazo Hill cement plant, though there are variations during the year and over time depending on ambient temperature and degradation. The ‘most likely’ utilisation, including the village electrification program, is forecast to be 80 - 85% over the remaining term of the Gas Agreement. This compares with an actual utilisation rate of 80% in 2009. The actual Protected Gas utilisation at the Ubungo power plant primarily depends on the availability of the Ubungo power units, the status of the water levels at the hydroelectricity dams and the capacity of the ‘run of river’ hydros. The run of river hydros can only generate when the rivers are flowing, typically during the short rains in November and December and the long rains in April and May. 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 2009 Additional Gas sales are reported in the ‘Markets’ section of this report. Flare, generator and line pack requirements A relatively small amount of gas is used in local electricity generation on Songo Songo Island. Gas is also required to maintain the Songo Songo Island gas plant flare at all times. This leads to a small annual loss of gas. There are also fluctuations in the line pack in the 232 kilometer high pressure pipeline to Dar es Salaam. The line is estimated to hold a maximum of 85 MMcf of gas. At current production levels the line pack holds sufficient gas for a few hours before it starts to impact Protected and Additional Gas sales in Dar es Salaam. Orca is supplying Additional Gas to the new 45 mW Tegeta power plant at dar es Salaam. 8 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 12,000 10,000 8,000 f c M M 6,000 4,000 2,000 0 f c M M 15,000 12,000 9,000 6,000 3,000 0 80 70 60 50 40 30 20 d f c M M Additional Gas volumes Power Sales Industrial Sales 2004 2005 2006 2007 2008 2009 Protected Gas volumes by year Wazo Hill Ubungo Power Plant Production volumes Flare Additional Gas sales Protected Gas sales 25,000 20,000 f c M M 15,000 10,000 5,000 0 2004 2005 2006 2007 2008 2009 2004 2005 2006 2007 2008 2009 2008 2009 Average daily production per month Jan Feb Mar April May June July Aug Sept Oct Nov Dec THE SONGO SONGO FIELD Summary of Orca Exploration’s assessment of Gas Initially in Place (GIIP) During 2009 no significant new geological or geophysical data was acquired to alter management’s detailed evaluation of the potential reserves and resources in the two Tanzanian Licence Blocks (“ Discovery Blocks”) that was undertaken in 2008. The reserves and resources are assessed for the following areas: 1. 2. The Songo Songo main producing field (“Songo Songo Field”, “SS Field”); The northern section of the field that has gas reserves established by the drilling of SS-1, but no current production (“Songo Songo North”, “SS North”); and 3. The exploration prospect west of the Songo Songo Field (“Songo Songo West”, “SS West”). A summary of management’s assessment of Best (mid) Case GIIP for the Songo Songo Field and Songo Songo North discoveries and the forecast unrisked resources of Songo Songo West are illustrated below. Songo Songo Field and Songo Songo North Management’s internal evaluation of the Best Case GIIP for the combined Songo Songo Field and Songo Songo North discovery is 1,571 Bcf. The GIIP estimates are based on the top reservoir depth structure maps generated in 2008. The low and high GIIP range is based on volumetric structural mapping utilising the Petrel modelling software, which incorporates the reservoir properties derived from the 2008 petrophysical reservoir analysis. Management’s Best Case GIIP of 1,571 Bcf for the Songo Songo Field and Songo Songo North compares with the McDaniel end 2009 GIIP estimates as presented below: Bcf McDaniels Songo Songo Field GIIP (Bcf) 1P 1,236 2P 1,433 3P 1,562 Songo Songo License Management estimate of Gas Initially In Place (GIIP) Songo Songo North Best Case GIIP 226 Bcf Songo Songo Main Best Case GIIP 1345 Bcf SS-1 SS-1 SS-9 SS-9 SS-10 SS-10 SS-4 SS-4 SS-5 SS-5 SS-3 SS-3 SS-6 SS-6 SS-7 SS-7 KN-1 KN-1 Songo Songo West Best Case GIIP 727 Bcf PROVEN PROVEN SECTION SECTION 5kms SS-8 SS-8 K-1 K-1 management’s internal evaluation of the Best Case GIIP for the combined Songo Songo Field and the Songo Songo north discovery is 1,571 Bcf. 9 Operations Review Reservoir management The static (Petrel™) and dynamic simulation (ECLIPSE™) reservoir models were rebuilt during 2008. This was necessary due to work undertaken on depth conversion during 2008 which had a significant positive impact on Gross Rock Volume (“GRV”), as well as the petrophysical analysis of well SS-10 which had a positive impact on the evaluation of net to gross (“N:G”) and permeability in low porosity reservoir. The Petrel geological model incorporates reservoir zonation and zonal facies distributions based on a revision of the stratigraphy, depositonal environments and palaeography of the Neocomian to Cenomanian reservoirs performed during 2008. In this early stage of field life, where only approximately 6.4% of GIIP has been produced from the reservoir, greater confidence is placed in the volumetric estimate of GIIP from the Petrel static model, than from dynamic estimates of GIIP based on Material Balance calculations. The ECLIPSE™ simulation model is used to monitor and continuously evaluate the reserves of the Songo Songo Field and Songo Songo North in order to ensure that the Protected Gas deliverability requirements can be met and to manage forecast Additional Gas sales. The model has been used to predict well performance and identify the investments in wells and field compression that will be required to meet forecast gas demand. It is used to assess the likely well response to uncertainties such as aquifer size and extent of reservoir compartmentalisation, if any. Reservoir surveillance Orca Exploration is required to deliver a peak supply of approximately 45.1 MMcfd of Protected Gas until 31 July 2024 from the Discovery Blocks as well as meet the Additional Gas sales contract obligations. The Company has in place a number of reservoir monitoring procedures aimed at constantly reviewing the field reserve estimates and well and field deliverability, based on established industry procedures and practices. Through these reservoir surveillance and management practices Orca Exploration is able to ensure delivery of the Protected Gas volumes to the end of the contract term and assist with the forecast of Additional Gas sales within the capability of the reservoir. The Company uses down hole pressure gauges to monitor and record bottom hole pressure. The gauges are installed on all producing wells with the exception of SS-9. A pressure gauge will be installed in the SS-10 development well upon connection to the gas processing facility in Q2 2010. Consideration is being given to the installation of a gauge in SS-9 in September 2010 during gauge pulling operations. The pressure data collected from the gauges is used for a variety of purposes including near well formation parameter assessment, well deliverability and estimates of field GIIP. The pressure gauges, which are retrieved annually, were last retrieved during September 2009 and at the same time re-installed to allow further ongoing data recording. The data collected in September has been interpreted for Pressure Transient Analysis (“PTA”), and Material Balance (MBAL™) and has also been used to update and history match production data in the simulation model. The performance of each individual well is in addition monitored throughout the year through a scheduled program of (multi-rate) well tests and build-up pressure tests. Songo Songo simulation (ECLIPSE™) model. Gas saturation at field start-up. 1 - S S 5 - S S 9 - S S 0 1 - S S 4 - S S 6 - S S 3 - S S 7 - S S n o i t a r u t a S s a G 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 Increased throughput capacity on Songo Songo Island was utilised to meet demand in the second half of 2009. 10 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 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. In addition, interference testing performed in 2007 confirms that SS-7 is also in communication with SS-5, further reducing the risk of compartmentalisation. The field is still in the early stages of it’s depletion with approximately 6.4% of the estimated Best Case GIIP produced to the end of 2009. The downhole pressure data suggests early signs for the possible presence of an aquifer, indicated by deviation of the pressure data away from the regression on the P/Z Material Balance plot. This observation is supported by addition of an aquifer to the Eclipse simulation model to improve the history match results. The Material Balance P/Z analysis has been extended to include diagnostic analysis for the presence of an aquifer using Cole and Havlena Odeh plots. At this early stage of production the data remains inconclusive for the presence of, or strength of an aquifer, but management will continue to monitor for this as more pressure data is available, and by continued monitoring for water production and potential changes in water salinity from the wells. Material Balance analysis Material balance analysis using the down hole pressure gauge data continues to support the total field volumetric GIIP estimate derived from the static Petrel model. In 2009, input to the material balance calculations was expanded in an effort to reflect the range in possible methods for deriving average reservoir pressure. In Songo Songo average reservoir pressure is difficult to determine since no well is ever shut in for a long enough period for equilibrium conditions to be established. The Final Build-up Pressure (“FBU”), Pi and P* estimates for average reservoir pressure used in the material balance calculations result in a range in total field GIIP of 1,545 to 1,834 Bcf. This range sits close to and above the Orca Management estimate of volumetric Best Case GIIP of 1,571 Bcf. Songo Songo Field and Songo Songo West prospect Estimates used in the material balance calculations result in a range of total field GIIP of 1,545 to 1,834 Bcf. 11 Operations Review Well and field deliverability The flow rates of the wells (including an estimated rate for SS-10 when it comes on production) based on the requirement to have 1,600 pounds per square inch of pressure in the gas processing plant are as follows: WELL dELIVERABILITY SUmmARY SS-3 SS-4 SS-5 SS-7 SS-9 SS-10 (Estimated) Total Maximum Protected Gas demand Available for Additional Gas 31 December 2009 maximum capacity (MMcfd) 15 12 60 20 55 55 217 (45) 172 Construction is proceeding to hook up well SS-10 to the gas processing facilities in Q2 2010. This well will be connected via the SS-4 flowline such that either SS-10 or SS-4 can be flowed at any one time, but not both wells simaltaneously. Provisions have been made to allow connection of SS-10 to the plant via its own flowline at a future date. A multi-rate test will be performed on SS-10 at the earliest to confirm its maximum capacity. The Songo Songo well pressures showed approximately a 1.3% decline over the course of 2009 in line with expectations. The current deliverability is sufficient to enable a maximum 172 MMcfd of Additional Gas production above the peak demand for Protected Gas if all wells are connected, and a maximum 160 MMcfd with SS-4 offline. This will allow the Company to produce more than 112 MMcfd (100 MMcfd with SS-4 offline) of Additional Gas for a period of time even in the unlikely event that the most productive well becomes unavailable at peak demand. Development of the Songo Songo Field and Songo Songo North The Company’s immediate objective is to maximise the sales of gas from the Songo Songo Field and Songo Songo North, as well as exploring for gas in the Songo Songo West prospect (“SS West”) (see under “Exploration’). In reviewing the potential of these reservoirs and the gas demand forecasts, it is assessed that the Company should develop the field and a potential discovery at SS West to be able to deliver a maximum peak of 200 MMcfd (including Protected Gas) and a maximum average of 160 MMcfd (including The Company’s immediate objective is to maximise the sales of gas from the Songo Songo Field and Songo Songo north. Trucked CnG could be used to replace industrial oil used in cities like morogoro 190 kilometers west of dar es Salaam. 12 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Protected Gas). The first well to be drilled is an exploration well on SS West in Q3 2011. In the event of success at SS West, further investment will be made to appraise, develop and bring on stream those new reserves to add to the production from Songo Songo Field and meet the demand forecasts. In the event of a dry hole at SS West further development of Songo Songo Field will be required. In this scenario it is planned that an additional main field development well will have to be drilled by the end of 2012. It is anticipated that the well will be drilled from an onshore location on Songo Songo Island and deviated to the north west where it will be landed as a high angle or horizontal producer at the top of the reservoir interval. The well would be tied back to the expanded Songo Songo gas processing facilities (see under Infrastructure). The current well stock will not drain the Songo Songo North reservoir. The reserves located in this area of the field are not required in the near term, and as a result there are no plans to drill this well before 2015. In addition to the above, field compression will need to be installed to maintain the deliverability of the wells. The first stage of compression will be installed along with the expanded gas processing facilities by the end of 2012. 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 March 2010 that assessed the Orca Exploration natural gas reserves based on information on the Songo Songo Field and Songo Songo North as at 31 December 2009 (the “McDaniel Report”). A summary of the remaining Additional Gas reserves on a life of license and life of field basis are presented in the tables on page 16. The 1P and 2P reserves are based on production to the end of the license period (October 2026) while the 3P reserves assume that the license will be extended to the end of the field life. During the course of 2009 no significant geological or geophysical data has been acquired on or close to the Songo Songo field that might allow a re-assesment of the volumetric GIIP and reserves. As a result, at the end of 2009 there has been little change to the certified numbers presented by McDaniel at the end of 2008. On a gross Company basis there has been a 1% decline in Songo Songo’s 1P Additional Gas reserves to the end of the license period, and a 9% increase on a life of field basis, despite Additional Gas sales of 10.4 Bcf being produced. There has been minimal change in the 2P Additional Gas reserves on a gross property life of license basis. Orca management estimates that the total recoverable Best (mid) Case reserves (Protected Gas plus Additional Gas) from the Songo Songo Field and the Songo Songo North discovery is 1,079 Bcf at 31 December 2009. 8°25'0"S New gas processing plant Songo Songo Field development options SSW (N) platform SSN single well SS-1 Legend Orca Exploration Group Gas field Prospect Reefs Gas processing plant Possible gas processing plant New drilling centres (proposed) New drilling centres (possible) Gas pipeline Proposed pipelines Possible pipelines Land / Sea 8°30'0"S 8°35'0"S SS-10 SS-4 Gas processing plant SS-9 SS-5 SS-3 SS-6 SSW (S) platform SS-7 Songo Songo Island KN-1 SS-8 K-1 0 Kilometers 5 TANZSS_02e1 39°20'0"E 39°25'0"E 39°30'0"E 39°35'0"E 13 Operations Review The gross and net Company Additional Gas reserves to end of license are as follows: SOnGO SOnGO Additional Gas reserves to October 2026 (Bcf) Independent reserves evaluation Proved producing Proved undeveloped Total proved (1P) Probable Total proved and probable (2P) Possible Total proved, probable and possible (3P) 2009 Gross (1) 300.7 84.2 384.9 105.3 490.2 338.6 828.8 2009 Net (2) 169.2 72.6 241.8 65.2 307.0 215.0 522.0 2008 Gross 253.5 135.9 389.4 102.0 491.4 340.7 832.1 2008 Net 146.9 99.8 246.7 67.3 314.0 219.2 533.2 (1) (2) Gross equals the gross reserves that are available for the Company after estimating the effect of the TPDC back in (see below). Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the Production Sharing Agreement. The gross and net Company Additional Gas reserves to end of field life are as follows: SOnGO SOnGO Additional Gas reserves to end of field life (Bcf) Independent reserves evaluation Proved producing Proved undeveloped Total proved (1P) Probable Total proved and probable (2P) Possible Total proved, probable and possible (3P) 2009 Gross (1) 474.2 (4.2) 470.0 174.1 644.1 184.7 828.8 2009 Net (2) 285.0 15.8 300.8 109.2 410.0 112.0 522.0 2008 Gross 434.7 (1.6) 433.1 215.6 648.7 183.4 832.1 2008 Net 263.2 15.4 278.6 144.2 422.8 110.4 533.2 (1) (2) Gross equals the gross reserves that are available for the Company after estimating the effect of the TPDC back in (see below). Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the Production Sharing Agreement. Orca Exploration has mapped and evaluated the Songo Songo West prospect and is in the early stages of planning to drill and test the prospect in Q3 2011. 14 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t The McDaniel Report has assumed that TPDC will exercise its right to ‘back in’ to the field development by contributing 20% of the costs of the future wells, including SS-10 and a proportion of the infrastructure and operating costs, in return for a 20% increase in the profit share for the production emanating from these wells. McDaniel has taken the view that this ‘back in’ right should be treated as a TPDC working interest and therefore the Gross reserves have been adjusted for the volumes of Additional Gas (29.8 Bcf at 2P) that are allocated to TPDC for their working interest share. The implications and workings of the ‘back in’ are currently being discussed with TPDC and may lead to future modifications in the way the Gross reserves are calculated. For the purpose of calculating the gross Additional Gas reserves, McDaniel has assumed in their 2P case that 195 Bcf (2008: 213 Bcf) or an average of 13.2 Bcf per annum will be required to meet the demands of the Protected Gas users from 1 January 2010 to 31 July 2024. During 2009, the Protected Gas users consumed 12.7 Bcf. The principal assumptions used by McDaniel in its evaluation of the Tanzanian PSA are as follows: Year 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Additional Gas price Gross Additional Gas volumes Additional Gas price Gross Additional Gas volumes 1P 1P 2P 2P US$/mcf MMcfd US$/mcf MMcfd 3.63 3.72 3.98 4.43 4.60 4.78 4.96 5.10 5.25 5.33 5.41 5.48 5.51 5.52 35.8 41.0 42.0 64.9 75.7 80.7 80.6 80.5 80.5 80.5 80.5 80.5 63.3 48.6 3.63 3.61 3.78 4.39 4.56 5.07 5.19 5.30 5.41 5.49 5.56 5.64 5.72 5.77 35.8 45.9 49.8 67.5 78.3 89.5 99.1 102.3 102.3 102.3 102.3 102.3 102.3 83.9 15 Operations Review Present value of reserves The estimated value of the Songo Songo reserves on a life of license basis based on the assumptions on production and pricing are as follows: US$ millions Proved producing Proved undeveloped Total proved (1P) Probable Total proved and probable (2P) Possible Total proved, probable and possible (3P) 2009 2008 5% 223.5 132.4 355.9 77.0 432.9 215.8 648.7 10% 157.1 90.6 247.7 43.4 291.1 90.0 381.1 15% 118.2 63.4 181.6 25.6 207.2 41.4 248.6 5% 168.9 203.0 371.9 81.1 453.0 238.8 691.8 10% 114.1 143.5 257.6 41.0 298.6 102.1 400.7 15% 83.8 103.4 187.2 21.0 208.2 48.7 256.9 There has been a 3% decrease on the 2P present value at a 10% discount basis from US$298.6 million to US$291.1 million on a life of licence basis. The decrease is primarily due to 2009 production, and change in the sales mix from CNG towards power. It should be noted that McDaniel has assumed in the 3P case, that the Company receives an extension to the PSA. Hence for this category only, the reserves are not restricted to the life of the licence. EXPLORATION Songo Songo West Orca Exploration has mapped and evaluated the Songo Songo West prospect adjacent to the Songo Songo Field and is in the early stages of planning to drill and test the prospect in Q3 2011. The prospect lies approximately 2.5 kilometers west of the main field and the prognosis is that the prospect is very similar in terms of trap and reservoir presence to the Songo Songo Field. The seismic on Songo Songo West indicates closure on an elongate north-south oriented tilted fault block trap at the same reservoir interval as the main field. Songo Songo West lies entirely within the Company’s Discovery Blocks. McDaniel conducted an independent assessment of natural gas resources in the Songo Songo West prospect in September 2008. Several cases were reviewed to estimate the size of the potential gas accumulation. As within the Songo Songo main field, two reservoirs are envisaged to be present within the SSW prospect– the Neocomian and the Cenomanian, although the primary exploration potential lies within the Neocomian interval. Songo Songo West is interpreted by mcdaniel to be a low risk prospect with a 52% chance of success in the neocomian and 35% in the Cenomanian. 16 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t The McDaniel’s Neocomian and Cenomanian GIIP and resources are summarised in the tables below: nEOCOmIAn (Bcf ) Unrisked OGIP Unrisked resources Risked mean resources CEnOmAnIAn (Bcf ) Unrisked OGIP Unrisked resources Risked mean resources Source: McDaniel September 2008 P90 232 170 – P90 12 9 – P50 566 418 – P50 43 32 – Mean 678 505 264 Mean 62 46 16 P10 1,381 1,028 – P10 158 118 – Songo Songo West is interpreted by McDaniel to be a low risk prospect with a 52% chance of success in the Neocomian and 35% in the Cenomanian. The chance of success is measured as the probability that a hydrocarbon accumulation exists that will demonstrate stabilised flow of hydrocarbons if tested. McDaniel assessed the P50, unrisked recoverable resources in the Songo Songo West prospect at 450 Bcf and the mean, unrisked recoverable resources at 551 Bcf. Management’s unrisked mean GIIP for the Songo Songo West prospect of 810 Bcf compares with the McDaniel combined Neocomian and Cenomanian unrisked mean GIIP of 740 Bcf. Songo Songo West represents a major potential source of reserves upside in the Songo Songo area, which could provide the resources to underwrite a significant expansion of the gas infrastructure and markets, both in Tanzania and beyond. Orca Exploration is planning to drill the initial exploration well (“Songo Songo West South”) closer to Songo Songo Island towards the south of the Songo Songo West structure. If it is successful and can flow at commercial rates, it is likely to be tied back immediately to the manifold in front of the processing plant and flowed for a period to prove up the long term deliverability of gas from the field. Following this confirmation, it is likely that an appraisal well will be drilled into the northern extent of Songo Songo West (“Songo Songo West North”) to get a better understanding of the areal extent of the reservoir and the recoverable reserves. The final field development decision would then be taken, but is likely to involve a significant expansion of the existing facilities. Songo Songo West Prospect Songo Songo Field SS-5 (projected) SS-3 Composite seismic line through SS West prospect and Songo Songo Field TWT SW Base Miocene 0.5 1.0 Near Base Eocene 1.5 Top Cenomanian 2.0 Top Neocomian 2.5 TANZSS-59 TWT E 0.5 1.0 1.5 2.0 2.5 17 2 kms Operations Review Songo Songo West is located in water depths of approximately 18 – 35m and will require a jack-up drilling rig to explore the prospect. Rig availability is a key focus in well planning, and Orca Exploration is actively engaged with other operators in East Africa who have a requirement for a jack-up rig to drill in shallow water along similar timeframe. The intent is to encourage a rig share opportunity which would reduce rig and support vessel mobilization and demobilization costs, as well as associated shared service costs. INFRASTRUCTURE The infrastructure that processes and transports the gas from the Songo Songo Field to Dar es Salaam was commissioned in July 2004. The initial infrastructure for the Songo Songo gas to electricity project incorporated the following elements: • • • Completion and tie back of the original five producing wells; Construction of a gas processing facility on Songo Songo Island (“SSI”) with two gas processing trains; Construction of a high pressure offshore and onshore pipeline system; a) b) c) a 25 kilometer 12” offshore pipeline from the field to the Somanga Funga landfall; a 207 kilometer 16” onshore pipeline to the Ubungo power plant; a 16 kilometer 8” lateral pipeline to the Wazo Hill cement plant. • Conversion of four existing turbines at the Ubungo power plant (2 x 19 MW and 2 x 34 MW) from diesel to gas. Orca Exploration is the operator of the wells and the gas processing plant. Songas Limited (“Songas”) is the operator of the high pressure pipeline system and the Ubungo power plant. SSI gas processing plant There are two trains at the gas processing facilities with a design specification of 35 MMcfd. The Songo Songo raw gas is relatively dry and requires minimal processing. The gas treatment is a simple dew point control process which uses the energy in the raw gas to chill the gas through a Joule-Thompson valve. Liquid condensate is removed from the cold gas, leaving the dry gas to be transported to Dar es Salaam. The condensate is owned by TPDC. With the growth in the market for Additional Gas, the Company signed an agreement (“Re-rating Agreement”) with Songas and TANESCO that enabled the Company, as operator of the gas processing plant, to install two larger Joule-Thompson valves and modify the relief systems on the two existing gas processing trains. The work was successfully implemented without significant disruption to the supply of gas to customers in Dar es Salaam. The increase in the capacity of the plant to 90 MMcfd was certified by Lloyds Register and the Company received formal approval from Songas to operate at this level in Q1 2009. Orca has designed a new long term Expansion Project to increase the capacity of the Songo Songo gas processing plant and the high pressure pipeline. 18 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t During the plant tests, each of the gas processing trains was operated at 55 MMcfd. Lloyds Register inspected the heat exchangers during 2009 and may yet certify the plant to operate at 110 MMcfd. This interim measure will be pursued with Songas in 2010 as the capacity of the gas processing plant is likely to impact the supply of gas to Dar es Salaam over the course of the next eighteen months. In the event that the gas processing is re-rated at 110 MMcfd, the capacity of the infrastructure that processes and transports the gas to Dar es Salaam will be limited by the capacity of the pipeline at 105 MMcfd as discussed below. High pressure pipeline network The main pipeline from Songo Songo Island to the Ubungo power plant in Dar es Salaam including both the offshore section and the onshore section has an estimated maximum capacity in its current configuration of 105 MMcfd. The limiting upstream pressure at the exit of the gas processing facilities on Songo Songo Island is between 84 bar and 87 bar while the minimum delivery pressure at Ubungo is 53 bar. Expansion Project During 2009, and following the breakdown of Songas’ application to the energy regulator, EWURA for the construction of two new gas processing units, Orca Exploration designed a new long term expansion project (“Expansion Project”) that combines enlarging the capacity of the gas processing plant and the high pressure pipeline. The Expansion Project has been well received by EWURA and Songas and all parties are working to conclude terms so that notice to proceed can be issued by Q1 2011. This would enable the project to be operational by the end of 2012. In the initial phase of the Expansion Project, two new gas processing units will be installed that can process 200 MMcfd. This will be combined with the installation of compression downstream of the gas processing plant. The dual purpose of this compression is to allow there to be a drop in the pressure requirements for the gas at the inlet to the gas processing plant (initially down to 65 bar) that can be increased to the maximum design pressure of the pipeline at its outlet. In addition, by dropping the pressure requirements at Dar es Salaam to 30 bar (from 53 bar), the pipeline throughput can be increased to 144 MMcfd. To increase the overall capacity of the infrastructure system to operate at 200 MMcfd, a twin onshore pipeline will need to be constructed. The timing of this will be dependent on the increase in gas demand, but it is forecast to be required by 2015/16. Low pressure distribution system The low pressure distribution system has been designed so that there is significant spare capacity and security of supply. There are three pressure reduction stations (“PRS”) and two separate connections to the 16” high pressure pipeline. A fourth PRS was installed in Q1 2009 specifically to handle the Additional Gas sales to the Wazo Hill cement plant. Since 2004, the Company has constructed in excess of 50 kilometres of low pressure pipeline in Dar es Salaam and at the end of 2009 35 industrial customers were connected. FAR RIGHT: The new pressure reduction station supplies gas to an expanded network of industrial customers. 19 Operations Review MARKET DEVELOPMENT Summary The current target profile for the sales of gas in Tanzania (including Protected Gas) is based on the forecast gas reserves in the Songo Songo Field and Songo Songo North. It is dependent on the investment in the drilling of two new wells and the expansion of the infrastructure system that transports the gas to Dar es Salaam. In the event that gas is discovered in Songo Songo West, then there is assessed to be sufficient demand, especially from the power sector, to absorb the majority of the P50 resources. Power sector Sales to the power sector averaged approximately 22.8 MMcfd in 2009. Until the end of 2012, the demand for gas from the power sector will be determined by the quantum of gas fired generation capacity in Tanzania and the availability of the hydro and infrastructure capacity. Thereafter, the take or pay provisions in the long term initialled power contracts will set a floor on the annual gas volumes sold to the power sector. There is expected to be significant growth in electricity demand in Tanzania and gas is likely to be the feedstock provided the right contractual terms can be agreed. This is discussed below. Demand by the power sector until the end of 2010 As at 31 December 2009, there was 189 MWs of installed gas fired generation in Tanzania that is being powered by Additional Gas (maximum demand of approximately 38 MMcfd). IPTL 100MW Tegeta 45MW Wazo Hill Kiln 4 UGT-6 42MW Ubungo 102MW Simba Steel Nida Textile Murzah 3 Murzah 4 Yuasa Battery A-one Pepsi Kinyerezi [250MW] Namera Bautech OK Plast Murzah 1&2 Azam Bakhresa food Tanzania Cutleries Steel Masters Silafrica Gas Pipeline Existing Ringmain Planned Pipelines 8 “ L i n e 1 6 “ L i n e D A R E S S A L A A M MMI Tanpack Iron & Steel CNG Hub TPDC CNG for Vehicles Chinese Textile mills African Pride Tanzania Breweries Nampack Muhimbili Hospital CNG Hub Movenpick Keko Prison VOT ECO Kioo Glass Kamal Steel Alaf Bora TCC Serengeti Breweries Karibu Textile Dar es Salaam area power and industrial customers. 0 Kilometres 1 0 Town / City Power Generation Stations PNG - supplied PNG - to be supplied CNG - supplied Pressure Reduction Stations (PRS) Power Generation Stations - to be supplied CNG - to be supplied TANZCW-02b 20 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t The following lists the capacity of the gas fired generation consuming Additional Gas as at 31 December 2009: STATUS Operational Operational Operational Total as at 31 December 2009 Power Plant Ubungo power plant (Unit 6) TANESCO at Ubungo Tegeta Installed capacity MWs 42 102 45 189 A further 100 MWs of additional generation is due to be connected and commissioned during 2011 (maximum demand of approximately 20 MMcfd). Demand by the power sector from 2011 under the ARGA and PGSA The supply of Additional Gas to the power sector is currently governed by two interim power agreements. It is forecast that these will be superseded by two long term contracts with Songas and TANESCO that were initialled in June 2008; the Amended and Restated Gas Agreement (“ARGA”) and the Portfolio Gas Supply Agreement (“PGSA”). Under the ARGA, 19.5% of the gas supplied to the six turbines at Ubungo is considered to be Additional Gas. Whilst there is no explicit take or pay in the agreement the utilisation at the Ubungo power plant is expected to be high given the low cost of the Protected Gas (US$0.55/Mmbtu LHV escalating with US CPI) that makes up the remaining 80.5% of the supply to the plant. The maximum volume of Protected and Additional Gas delivered to the Ubungo power plant is capped at approximately 47.4 MMcfd. At an 84% utilisation rate, it is expected that 7.8 MMcfd will be supplied to the Ubungo power plant as Additional Gas until the termination of the agreement on 31 July 2024. The PGSA covers the supply of Additional Gas to a portfolio of gas generation facilities (that currently consists of the TANESCO Ubungo 102 MW and Tegeta 45 MW power plants). Further delivery points may be added in the future subject to the consent of the Company and TPDC, and provided that the gas volumes do not exceed the maximum permissible under the contract as detailed below. Under the terms of the initialled PGSA, it is forecast that in the periods prior to the installation of the third and fourth gas processing trains, the Company will supply TANESCO’s existing gas fired generation as nominated subject to there being available gas processing capacity. The maximum daily quantity (“MDQ”) that the Company has to supply under the initialled PGSA is approximately 37 MMcfd provided there is sufficient generation capacity in place to consume the gas. FAR LEFT: The industrial market for natural gas continues to expand. OK Plastics was added as a customer in 2009. LEFT: Orca is vigorously promoting the use of CnG as replacement fuel for buses and trucks. RIGHT: OK Plastics in dar es Salaam is one of 33 companies supplied with Additional Gas from Orca. 21 Operations Review Growth in electricity demand and the potential for further gas fired generation As at 31 December 2009 there was approximately 1,127 MWs of available power generation in Tanzania though only 925 MWs was operational due to contractual disputes with Dowans and IPTL. In the last few years there has been a rebalancing of power generation mix in Tanzania resulting in hydro generation accounting for less than 50% of the available generation. The only major water storage is at the Mtera reservoir which supplies the 80 MW Mtera and 200 MW Kidatu hydro plants. The remaining 261 MWs of hydro generation is “run of river” which is only operational on average for 4-5 months in the year. Accordingly, the level of the Mtera reservoir is integral to the generation of 280 MWs of electricity. Since 2006 there have been good rainfalls in the rainy seasons which occur between April and May and November and December each year and the Mtera reservoir is still relatively full. It is estimated that under the base case assumptions of the TANESCO’s power sector master plan (“PSMP”) that peak demand (before adding in any capacity margin to provide a more normal level of security of supply) will be 1,700 MWs in 2016 (growth of 7.8% per annum from 2006) and 4,800 MWs in 2031 (growth of 7.2% from 2016). Total current aggregate available capacity (with all hydro facilities producing) is expected to between 925 MWs by the end of 2009 though this could increase to a maximum of 1,172 MWs if contractual issues are resolved with IPTL and Dowans. Of this amount, 150 MWs is operating on expensive Heavy Fuel Oil (“HFO”) (100 MWs) or Industrial Diesel Oil (“IDO”) (50 MWs). Based on this forecast availability at the end of 2009, there has to be an increase of between 528 MWs and 775 MWs in the period 2010-2016 to meet forecast demand increased in Tanzania or in excess of 100 MWs per annum. It is therefore reasonable to assume that an additional 20 MMcfd of peak demand will be required for each year between 2010 and 2016 to meet power sector demand in Tanzania in addition to the existing available generation. Whilst the rate of growth slows marginally after 2016, there is still a requirement for in excess of 100 MWs per annum of new generation (adding 20 MMcfd of peak potential gas demand). If it is assumed that TANESCO would want to maximise the use of gas in its generation mix, dispatching gas generation after the hydro and Protected Gas and would like to displace the existing HFO or IDO generation, then this is the forecast gas requirements over the period to 2026 in excess of the gas requirements outlined in the PGSA and the ARGA assuming a 70% utilisation rate for the gas fired generation. It is forecast that whilst there are sufficient gas reserves in the country, gas fired generation will be the preferred choice for new capacity. In addition, the current gas is priced at a level that makes gas fired generation competitive with the all-in-cost of coal generation. TANESCO has indicated that they intend to construct a 240 MW generation plant at Kinyerezi, Dar es Salaam by 2013/2014. The Company has commenced discussions to assess how gas may be made available for these units, recognising the need for additional drilling and infrastructure to be able to deliver the volumes contemplated for these units. The sales projections assume that a contract will be negotiated with TANESCO for the supply of gas to 240 MWs at Kinyerezi in incremental amounts starting 2013 when the infrastructure developments contemplated by the Expansion Project are forecast to be complete. during 2009 the Company installed a CnG vehicle filing station at a busy intersection in the Ubungo power plant. 22 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Prospective industrial sales Sales to the industrial sector averaged approximately 5.7 MMcfd in 2009. The Company continues to sign and connect other smaller industrial customers to the low pressure pipeline system that is now in excess of 50 kilometres. However, there is limited opportunity to connect any material new customers and therefore growth in industrial volumes in the short term will primarily be driven by organic growth from within the existing customer base. The Company has been approached by a number of industrial customers who want reliable power and are prepared to finance some small generation capacity. The Company is keen to pursue this growth opportunity, but is reluctant to commit until it is clear that the Expansion Project will proceed. Demand for cement in Tanzania has increased significantly over the last few years with extensive construction of new offices and accommodation in Dar es Salaam. This is forecast to lead to an increase in the gas consumption at the Wazo Hill cement plant. This plant is owned by Tanzania Portland Cement Company (“TPCC”) a subsidiary of HeidelbergCement. Currently Additional Gas is only being consumed by one of its kilns (kiln 4). In Q2 2010, TPCC is due to fire up kiln 2 after a major refurbishment. This should lead to the kilns consuming 3-4 MMcfd for the remainder of 2010. This is expected to increase to 6 MMcfd when kiln 3 is brought back on production in 2012. Compressed Natural Gas (CNG) CNG is widely used around the world, including India and China. There is a strong push by the Government of Tanzania to utilise CNG and during 2009 the Company installed a compressor and a vehicle dispenser adjacent to its pressure reduction station at a busy intersection at the Ubungo power plant. Two daughter stations were also constructed at the Movenpick hotel and the TPDC compound to distribute the gas along with a second vehicle dispenser. Currently CNG is being consumed by the Movenpick hotel and a few vehicles in Dar es Salaam. During 2010, it is expected that two additional hotels will convert their facilities to consume gas, a further daughter station will be constructed in the Mikocheni area to enable the Company to supply two new industrial customers and a several more vehicles will be converted. The CNG market is expected to grow gradually primarily fuelled by industries not located on the existing pipeline system and large vehicle users (e.g. Pepsi who has a large fleet of trucks). It is anticipated that once the market is established in the medium term, the local petrol retailers will retail the CNG. Accordingly there will be no need for significant capital after this time, but the price realised for the CNG will be reduced. Corporate Social Responsibility The Board of Directors regularly reviews the aims of the corporate social responsibility strategy and how this translates into practical and beneficial community relations support in Tanzania. A budget is established with agreed ongoing assistance covering education, health and the provision of water and power on Songo Songo Island. Particular emphasis is given to providing educational materials and equipment for the existing school, with support being given to the setting up of a new secondary school. The overall aim is to improve the quality of life for all the local inhabitants and maintain good community relations. RIGHT: Two CnG stations were constructed to distribute gas to customers who are not on the pipeline route. 23 Management’s Discussion & Analysis Operations Review FORWARD LOOKING STATEMENTS THIS MDA OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS SHOULD BE READ IN CONJUNCTION WITH THE AUDITED FINANCIAL STATEMENTS AND NOTES THERETO FOR YEAR ENDED 31 DECEMBER 2009. THIS MDA IS BASED ON THE INFORMATION AVAILABLE ON 19 APRIL 2010. INTENTION OR OBLIGATION TO UPDATE OR REVISE ANY FORWARD-LOOKING STATEMENTS, WHETHER AS A RESULT OF NEW INFORMATION, FUTURE EVENTS OR OTHERWISE. ALL FORWARD-LOOKING STATEMENTS CONTAINED IN THIS DOCUMENT ARE EXPRESSLY QUALIFIED BY THIS CAUTIONARY STATEMENT. INCLUDING IN THIS MD&A (I) CERTAIN STATEMENTS STATEMENTS THAT MAY CONTAIN WORDS SUCH AS “ANTICIPATE”, “COULD”, “EXPECT”, “SEEK”, “MAY” “INTEND”, “WILL”, “BELIEVE”, “SHOULD”, “PROJECT”, “FORECAST”, INCLUDING THE “PLAN” AND SIMILAR EXPRESSIONS, NEGATIVES THEREOF, (II) STATEMENTS THAT ARE BASED ON CURRENT EXPECTATIONS AND ESTIMATES ABOUT THE MARKETS IN WHICH ORCA EXPLORATION OPERATES AND (III) STATEMENTS OF BELIEF, INTENTIONS AND EXPECTATIONS ABOUT DEVELOPMENTS, RESULTS AND EVENTS THAT WILL OR MAY OCCUR IN THE FUTURE, CONSTITUTE “FORWARD-LOOKING STATEMENTS” AND ARE BASED ON CERTAIN ASSUMPTIONS AND ANALYSIS MADE BY ORCA EXPLORATION. FORWARD- LOOKING STATEMENTS IN THIS MD&A INCLUDE, BUT ARE NOT LIMITED TO, STATEMENTS WITH RESPECT TO FUTURE CAPITAL INCLUDING THE AMOUNT, NATURE AND EXPENDITURES, TIMING THEREOF, NATURAL GAS PRICES AND DEMAND. SUCH FORWARD-LOOKING STATEMENTS ARE SUBJECT TO IMPORTANT RISKS AND UNCERTAINTIES, WHICH ARE DIFFICULT TO PREDICT AND THAT MAY AFFECT ORCA EXPLORATION’S OPERATIONS, INCLUDING, BUT NOT LIMITED TO: THE IMPACT OF GENERAL ECONOMIC CONDITIONS IN TANZANIA AND CANADA; INDUSTRY CONDITIONS, INCLUDING THE ADOPTION OF NEW ENVIRONMENTAL, SAFETY AND OTHER LAWS AND REGULATIONS AND CHANGES IN HOW THEY ARE INTERPRETED AND ENFORCED; VOLATILITY OF CRUDE OIL AND NATURAL GAS PRICES; NATURAL GAS PRODUCT SUPPLY AND DEMAND; RISKS INHERENT IN ORCA EXPLORATION’S ABILITY TO GENERATE SUFFICIENT CASH FLOW FROM OPERATIONS TO MEET ITS CURRENT AND FUTURE OBLIGATIONS; INCREASED COMPETITION; THE FLUCTUATION IN FOREIGN EXCHANGE OR INTEREST RATES; STOCK MARKET VOLATILITY; AND OTHER FACTORS, MANY OF WHICH ARE BEYOND THE CONTROL OF ORCA EXPLORATION. ORCA EXPLORATION’S ACTUAL RESULTS, PERFORMANCE OR ACHIEVEMENTS COULD DIFFER MATERIALLY FROM THOSE EXPRESSED IN, OR IMPLIED BY, THESE FORWARD-LOOKING STATEMENTS AND, ACCORDINGLY, NO ASSURANCE CAN BE GIVEN THAT ANY OF THE EVENTS ANTICIPATED BY THE FOR- WARD-LOOKING STATEMENTS WILL TRANSPIRE OR OCCUR, OR IF ANY OF THEM DO TRANSPIRE OR OCCUR, WHAT BENEFITS ORCA EXPLORATION WILL DERIVE THEREFROM. SUBJECT TO APPLICABLE LAW, ORCA EXPLORATION DISCLAIMS ANY 24 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t NON-GAAP MEASURES THE COMPANY EVALUATES ITS PERFORMANCE BASED ON FUNDS FLOW FROM OPERATING ACTIVITIES AND OPERATING NETBACKS. FUNDS FLOW FROM OPERATING ACTIVITIES IS A NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES) TERM THAT REPRESENTS CASH FLOW FROM OPERATIONS BEFORE WORKING CAPITAL ADJUSTMENTS. IT IS A KEY MEASURE AS IT DEMONSTRATES THE COMPANY’S ABILITY TO GENERATE CASH NECESSARY TO ACHIEVE GROWTH THROUGH CAPITAL INVESTMENTS. ORCA EXPLORATION ALSO ASSESSES ITS PERFORMANCE UTILIZING OPERATING NETBACKS. OPERATING NETBACKS REPRESENT THE PROFIT MARGIN ASSOCIATED WITH THE PRODUCTION AND SALE OF ADDITIONAL GAS AND IS CALCULATED AS REVENUES LESS RINGMAIN TARIFF, GOVERNMENT PARASTATAL’S REVENUE SHARE, OPERATING AND DISTRIBUTION COSTS FOR ONE THOUSAND STANDARD CUBIC FEET OF ADDITIONAL GAS. THIS IS A KEY MEASURE AS IT DEMONSTRATES THE PROFIT GENERATED FROM EACH UNIT OF PRODUCTION, AND IS WIDELY USED BY THE INVESTMENT COMMUNITY. THESE NON-GAAP MEASURES ARE NOT STANDARDISED AND THEREFORE MAY NOT BE COMPARABLE TO SIMILAR MEASUREMENTS OF OTHER ENTITIES. ADDITIONAL INFORMATION REGARDING ORCA EXPLORATION GROUP INC IS AVAILABLE UNDER THE COMPANY’S PROFILE ON SEDAR AT www.sedar.com. Background Orca Exploration’s principal operating asset is its interest in a Production Sharing Agreement (“PSA”) with the Tanzania Petroleum Development Corporation (“TPDC”) in Tanzania. This PSA covers the production and marketing of certain gas from the Songo Songo gas field. The gas in the Songo Songo field is divided between Protected Gas and Additional Gas. The Protected Gas is owned by TPDC and is sold under a 20-year gas agreement to Songas Limited (“Songas”). Songas is the owner of the infrastructure that enables the gas to be delivered to Dar es Salaam, namely a gas processing plant on Songo Songo Island, 232 kilometers of pipeline to Dar es Salaam and a 16 kilometer spur to the Wazo Hill Cement Plant. Songas utilizes the Protected Gas (maximum 45.1 MMcfd) as feedstock for its gas turbine electricity generators at Ubungo, for onward sale to the Wazo Hill cement plant and for electrifica- tion 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 licenses in which the Songo Songo field is located (“Discovery Blocks”). (c) The Proven Section is essentially the area covered by the Songo Songo field within the Discovery Blocks. No sales of Additional Gas may be made from the Discovery Blocks if in Orca Exploration’s reasonable judgment such sales would jeopardise the supply of Protected Gas. Any Additional Gas contracts entered into 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 (d) below). In June 2008, the Company initialled two long term power contracts with TANESCO, the owner of the Ubungo power plant, Songas Limited and the Ministry of Energy and Minerals for the supply of approximately 30 - 45 MMcfd for power generation. The first of the contracts (Amended and Restated Gas Agreement (“ARGA”)) covers the supply of gas to the sixth turbine at the Ubungo power plant and provides for a maximum of approximately 9 MMcfd until July 2024. The second initialled contract (Portfolio Gas Sales Agreement (“PGSA”)) covers the supply of Additional Gas sales to a portfolio of gas fired generation in Tanzania. The ARGA provides clarification of the Protected Gas volumes and removes all terms dealing with the security of the Protected Gas and the consequences of any insufficiency to a new Insufficiency Agreement (“IA”). The IA specifies terms under which Songas may demand cash security in order to keep them whole in the event of a Protected Gas insufficiency. Once the IA is signed, it will govern the basis for determining security. Under the provisional terms of the IA, when it is calculated that funding is required, the Company shall fund an escrow account at a rate of US$2/Mmbtu on all industrial Additional Gas sales out of its and TPDC’s share of revenue and TANESCO shall contribute the same amount on Additional Gas sales to the power sector. The funds provide security for Songas in the event of an insufficiency of Protected Gas. The Company is actively monitoring the reservoir and does not anticipate that a liability will occur in this respect. (d) “Insufficiency” occurs if there is insufficient gas from the Discovery Blocks to supply the Protected Gas requirements or is so expensive to develop that its cost exceeds the market price of alternative fuels at Ubungo. Where there have been third party sales of Additional Gas by Orca Exploration and TPDC from the Discovery Blocks prior to the occurrence of the Insufficiency, Orca Exploration and TPDC shall be jointly liable for the Insufficiency and shall satisfy its related liability by either replacing the Indemnified Volume (as defined in (e) 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. 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 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. (e) 25 Management’s Discussion & Analysis Operations Review As discussed in (c) above a Insufficiency Agreement has been negotiated with TPDC, Songas and TANESCO that reduces these potential liabilities. The Insufficiency Agreement is expected to be signed at the same time as the long term power contracts. Access and development of infrastructure (f) is able to utilise The Company 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 (g) 75% of the gross revenues less processing and pipeline tariffs and direct sales taxes in any year (“Net Revenues”) can be used to recover past costs incurred. Costs recovered out of Net Revenues are termed “Cost Gas”. The Company pays and recovers all costs of exploring, developing and operating the Additional Gas with two exceptions: (i) TPDC may recover reasonable market and market research costs as defined under the PSA; and (ii) TPDC has the right to elect to participate in the drilling of at least one well for Additional Gas in the Discovery Blocks for which there is a development program as detailed in the Additional Gas plans as submitted to the Ministry of Energy and Minerals (“Additional Gas Plan”) subject to TPDC being able to elect to participate in a development program only once and TPDC having to pay a proportion of the costs of such development program by committing to pay between 5% and 20% of the total costs (“Specified Proportion”). If TPDC does not notify the Company within 90 days of notice from the Company that the Ministry of Energy and Minerals (“MEM”) has approved the Additional Gas Plan, then TPDC is deemed not to have elected. If TPDC elects to participate, then it will be entitled to a rateable proportion of the Cost Gas and their profit share percentage increases by the Specified Proportion for that development program. 26 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development by contributing 20% of the cost of SS-10 and the cost of future wells 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 currently being discussed with TPDC and there may be the need for reserve modifications once these discussions are concluded. For the purpose of the reserves certification as at 31 December 2009, it has been assumed that they will ‘back in’ for 20% for all future developments and this is reflected in the Company’s net reserve position. However, the financial statements have not taken account of any reimbursement for the SS-10 capital expenditure incurred, pending the finalisation of the terms of the ‘back in’. (h) The price payable to Songas for the general processing and transportation of the gas in 2009 is 17.5% of the price of gas delivered to a third party less any direct taxes payable by the customer that are included in the gas price less any tariffs paid for non-Songas owned distribution facilities (“Songas Outlet Price”). (i) (j) On 27 February 2009, EWURA issued an order that sees the introduction of a flat rate tariff of US$0.59/ mcf from 1 January 2010. The Company’s long term gas price to the power sector as set out in the short term and initialed long term agreements is based on the price of gas at the Wellhead. As a consequence, the Company is not impacted by the changes to the tariff paid to Songas in respect of sales to the power sector. 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. 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%. Operatorship Average daily sales of Additional Gas Cumulative sales of Additional Gas MMcfd 0 - 20 Bcf 0 – 125 > 20 <= 30 > 125 <= 250 > 30 <= 40 > 250 <= 375 > 40 <= 50 > 375 <= 500 > 50 > 500 TPDC’s share of Profit Gas Company’s share of Profit Gas (l) % 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%. (m) (k) 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. 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. 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 Gas 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. The Company is appointed to develop, produce and process Protected Gas and operate and maintain the gas production facilities and processing plant, including the staffing, procurement, capital improvements, contract maintenance, maintain books and records, prepare reports, maintain permits, handle waste, liaise with GoT and take all necessary safe, health and environmental precautions all in accordance with good oilfield practices. In return, the Company is paid or reimbursed by Songas so that the Company neither benefits nor suffers a loss as a result of its performance. In the event of loss arising from Songas’ failure to perform and the loss is not fully compensated by Songas, Orca Exploration, CDC or insurance coverage, then Orca Exploration is liable to a performance and operation guarantee of US$2.5 million when (i) the loss is caused by the gross negligence or wilful misconduct of the Company, its subsidiaries or employees, and (ii) Songas has insufficient funds to cure the loss and operate the project. Consolidation The companies that are being consolidated are: Company Incorporated Orca Exploration Group Inc. British Virgin Islands Orca Exploration (Ventures) Inc British Virgin Islands Orca Exploration Uganda (Holdings) Inc British Virgin Islands Orca Exploration Uganda Inc British Virgin Islands PAE PanAfrican Energy Corporation Mauritius PanAfrican Energy Tanzania Limited Jersey 27 Management’s Discussion & Analysis Operations Review Results for the year ended 31 December 2009 Operating Volumes The sales volumes for the year were 10,422 MMcf or 28.5 MMcfd. This represents an overall increase of 20% over the previous year. The Company’s sales volumes were split between the industrial and power sectors as follows: (MMcf) Permanent generation Ubungo power plant (42 MWs) TANESCO Ubungo (102 MWs) Tegeta (45 MWs) 2009 2008 Total volumes 2009 2008 2,790 5,385 151 8,326 – – – 2,339 2,125 – 4,464 1,908 813 2,721 7,185 Emergency generation Aggreko Dowans A and B Total volumes Total power sector volumes 8,326 During the third and fourth quarter of 2009 the Ubungo and TANESCO gas power generation units were operating at over 27 MMcfd against a maximum capacity of 29 MMcfd, reflecting high demand for gas fired generation during the dry months when there was limited hydro generation. Commodity Prices US$/mcf Average sales price Industrial sector Power sector Weighted average price Industrial sector 2009 2008 8.36 2.40 3.60 11.98 2.37 4.01 The average gas price for the year was US$8.36/mcf (2008: US$11.98/mcf). The decline in the price achieved during the year is a consequence of the decrease in world oil prices experienced during the first six months of the year compared to 2008 and the commencement of sales to the Wazo Hill cement plant which are priced by reference to lower value imported coal, their alternative fuel supply. The sales to Wazo Hill accounted for 25% of the total industrial volumes sold for the year. Power sector The average sales price to the power sector was US$2.40/mcf for the year, compared to US$2.37/mcf in 2008. The increase in price is a combination of the annual indexation and the termination of the emergency power contracts in 2008. Gross sales volume (MMcf): Industrial sector Power sector Total volumes Gross daily sales volume (MMcfd): Industrial sector Power sector Total daily sales volume Industrial sector 2,096 8,326 10,422 5.7 22.8 28.5 1,475 7,185 8,660 4.0 19.7 23.7 Industrial sales volume increased by 42% to 2,096 MMcf compared to 1,475 MMcf in 2008. The increase is primarily due to the connection in March 2009 of Kiln 4 at the Wazo Hill cement plant operated by the Tanzanian Portland Cement Company (“TPCC”). Sales to TPCC accounted for 85% of the total increase in industrial sales during 2009, the other 15% being attributed to the six new customers who were connected to the low pressure gas distribution system throughout the year. Industrial sales for the year averaged 5.7 MMcfd (2008: 4.0 MMcfd). Power sector The power sector sales volumes increased by 16% to 8,326 MMcf compared to 7,185 MMcf in 2008. The majority of the increase occurred during the second half of the year as a result of the greater utilization of the 102 MW TANESCO power plant during the dry season that continued into the fourth quarter of 2009. Power sector sales for the year averaged 22.8 MMcfd (2008: 19.7 MMcfd). There were no emergency power generation units in operation during 2009. These units were replaced by the 102 MW TANESCO power plant which became fully operational in August 2008 and the Tegeta 45 MW plant that commenced operations in November 2009. The allocation of the gas volumes between the different power generation units is as follows: 28 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Operating Revenue Under the terms of the PSA with TPDC, Orca Exploration is responsible for invoicing, collecting and allocating the revenue from Additional Gas sales. Orca Exploration is able to recover all costs incurred on the exploration, development and operations of the project out of 75% of the Net Revenues (“Cost Gas”). Any costs not recovered in any period are carried forward to be recovered out of future revenues. During 2009, Additional Gas sales volumes were in excess of 20 MMcfd for the first two quarters of the year and above 30 MMcfd per day for the last two quarters. Consequently, the revenue less cost recovery share of revenue (“Profit Gas”) increased from 30% to 35% for the last two quarters of 2009. In 2008 the Profit Gas percentage increased from 25% to 30% for the last three quarters of the year as the sales volumes increased to in excess of 20 MMcfd. Orca Exploration had recoverable costs throughout 2008 and 2009 and accordingly was allocated 82.9% (2008: 82.5%) of the Net Revenues as follows: Figures in US$’000 Gross sales revenue 2009 2008 37,475 34,727 Gross tariff for processing plant and pipeline infrastructure (6,340) (5,664) Gross revenue after tariff 31,135 29,063 Analysed as to: Company Cost Gas Company Profit Gas Company operating revenue TPDC Profit Gas 23,352 2,488 25,840 5,295 31,135 21,797 2,119 23,916 5,147 29,063 The Company’s total revenues for the year amounted to US$25,317,000 after adjusting the Company’s operating revenue of US$25,840,000 by: i) ii) US$ nil for income tax in the current year. The Company is liable for income tax in Tanzania, but the income tax is recoverable out of TPDC’s Profit Gas when the tax is payable. To account for this, revenue is adjusted to reflect the current year income tax charge or loss. US$489,000 for the deferred effect of Additional Profits Tax. This tax is considered a royalty and is netted against revenue. iii) US$34,000 for bad debts see note 3 (iv). Revenue per the income statements may be reconciled to the operating revenue as follows: (Figures in US$’000) Industrial sector Power sector Gross sales revenue Processing and transportation tariff TPDC share of revenue 2009 17,526 19,949 37,475 (6,340) (5,295) 2008 17,673 17,054 34,727 (5,664) (5,147) Company operating revenue 25,840 23,916 Additional Profits Tax Current income tax adjustment Provision for bad debts (489) – (34) (383) 249 – Revenue 25,317 23,782 Processing and Transportation Tariff Under the terms of the project agreements, the 2009 tariff paid for processing and transporting the Additional Gas 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, an average amount of US$0.69/mcf (“Ringmain Tariff”) (2008: US$1.69/mcf) has been deducted from the achieved (2008: industrial sales price of US$8.36/mcf US$11.98/mcf) to reflect the gas price that would be achievable at the Songas main pipeline. The Ringmain Tariff represents the amount that would be required to compensate a third party distributor of the gas for constructing the connections from the Songas main pipeline to the industrial customers. The decline in the Ringmain Tariff is the consequence of the introduction of a flat rate charge in 2009 following a directive from EWURA. No deduction has been made for sales to the power sector or to Wazo Hill since the gas is not transported through the Company’s own infrastructure. A flat rate gas processing and transportation tariff of US$0.59/ mcf has been introduced from 1 January 2010 that will enable Songas to make a rate of return on their investment as determined by EWURA. The Company will pass on any increase or decrease in the EWURA approved charges to TANESCO/Songas in respect of sales to the power sector. This protocol insulates Orca Exploration from any increases in the gas processing and pipeline infrastructure costs. 29 Management’s Discussion & Analysis Operations Review Production and Distribution Expenses Operating Netback The production and distribution expenses are summarised in the table below: (Figures in US$’000) Share of well maintenance Other field and operating costs 2009 601 798 Ring main distribution pipeline 1,408 2008 243 566 668 Production and distribution expenses 2,807 1,477 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$1,124,000 (2008: US$541,000) of which US$601,000 (2008: US$243,000) was allocated for the Additional Gas. The higher cost recorded during the year are a result of a preventative maintenance program being undertaken together with the increase in the volume of Additional Gas sales. Other field operating costs include an apportionment of the annual PSA license costs and some costs associated with the evaluation of the reserves. The direct cost of maintaining the ringmain distribution pipeline and pressure reduction station (security, insurance and personnel) have increased during 2009 as a consequence of the employment of dedicated personnel to maintain the high level of service given to customers together with an increase in maintenance activity. The direct costs have also increased, due to repairs undertaken at the pressure reduction stations to ensure the continuity of gas supply. The overall increase in costs during the year is reflective of the 42% increase in the level of sales to industrial customers in 2009. The operating netback per mcf before general and administrative costs, overheads, income tax and Additional Profits Tax may be analysed as follows: (Amounts in US$/mcf) Gas price – industrial Gas price – power Weighted average price for gas Tariff (after allowance for the Ringmain Tariff) TPDC Profit Gas Net selling price Well maintenance and other operating costs Ringmain distribution pipeline Operating netback 2009 8.36 2.40 2008 11.98 2.37 3.60 4.01 (0.61) (0.51) 2.48 (0.13) (0.14) 2.21 (0.65) (0.59) 2.77 (0.09) (0.08) 2.60 The operating netback for the year has fallen by 15% to US$2.21/mcf from US$2.60/mcf in 2008. The fall in the weighted average sales price is a consequence of a reduction in the average sales price to the industrial sector. This was the result of the general fall in the global energy prices and the commencement of Additional Gas sales to the Wazo Hill cement plant. There was no material change in the relative sales mix between power and industrial sectors between 2008 and 2009. The combination of these events resulted in the fall in the net selling price from US$2.77/mcf in 2008 to US$2.48/mcf in 2009, with both the Tariff and TPDC Profit Gas rates on a per mcf basis being directly related to the average sales price achieved. The slight fall in TPDC Profit Gas as a percentage of the weighted average sales price is a consequence of the higher level of sales achieved resulting in the TPDC share of Profit Gas falling from 70% to 65%. The increase in the well maintenance and other operating costs and the ring main distribution costs (as explained above) have led to a higher rate on a per mcf basis, though this is partially offset by the 20% increase in overall sales volumes compared to 2008. The operating netback continues to benefit from the recovery of 75% of the Net Revenues as Cost Gas. 30 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t General and Administrative Expenses Travel and accommodation The general and administrative expenses (“G&A”) may be analysed as follows: (Figures in US$’000) Employee costs Consultancy Travel & accommodation Communications Office Insurance Auditing & taxation Depreciation Reporting, regulatory and corporate finance Marketing and legal costs New ventures Stock based compensation Net general and administrative expenses 2009 1,981 2,474 667 83 1,120 250 219 215 305 7,314 2,511 239 1,401 2008 2,107 3,184 912 66 936 238 166 76 290 7,975 4,663 294 1,754 11,465 14,686 The G&A primarily consists of costs of running the gas distribution business in Tanzania and the majority of it is recoverable as Cost Gas. G&A averaged approximately US$0.96 million per month in 2009 (2008: US$1.22 million). G&A per mcf was US$1.10/mcf (2008: US$1.70/mcf). This represents an overall decrease in general administrative expenses of 22%. The main variances are summarised below: Employee costs The decline in employee costs is the result of the reclassification to production costs of US$0.3 million following the establishment of a dedicated downstream team during the year. Consultancy cost The decline in consultancy cost is a consequence of a concerted effort to reduce the level of dependency on third party consultants during 2009. The decrease in the level of travel and accommodation is a result of the decrease in the number of business trips to Tanzania by Company officials and other marketing and legal professionals in relation to the negotiation of the long-term power and related contracts. Office costs The overall increase in office costs is a result of the expansion of the downstream activities which led to the establishment of a second office location in Dar es Salaam. Marketing and legal costs include marketing costs, These costs legal, corporate promotion and costs of training Government officials in accordance with the terms of the PSA. The costs were significantly higher during 2008 as a result of costs incurred in negotiating the long term power and related contracts and in preparing pricing applications for the regulatory authority, EWURA. While costs have continued to be incurred in these areas in 2009 they have been at a greatly reduced rate. Stock based compensation The breakdown of the costs incurred in relation to stock based compensation is detailed in the table below: (Figures in US$’000) Stock options Stock appreciation rights Treasury stock Capitalized 2009 1,052 279 70 1,401 – 1,401 2008 2,086 (570) 606 2,122 (368) 1,754 A total of 2,797,000 stock options were issued and outstanding at the end of 2009 compared to 2,814,000 at the end of 2008, the decline being a result of forfeiture during the first quarter of 2009. Of the total options 1,662,000 were fully expensed by the end of 2007. The remaining 1,135,000 were issued during 2007. The decline in the charge in 2009 is a consequence of the IFRS-2 accounting treatment which sees the majority of the costs being charged in the first two years from the date of grant. 31 Management’s Discussion & Analysis Operations Review A total of 810,000 stock appreciation rights were outstanding at the end of 2009 of which 105,000 expired in February 2010. As stock appreciation rights are settled in cash, they are re-valued at each reporting date using the Black-Scholes option pricing model. As at 31 December 2009, the following assumptions were used; stock volatility 104%, a risk free interest rate of 2.05% and a closing stock price of Cdn$3.70. The credit recorded in 2008 in respect of these stock appreciation rights was the result of the share price falling from Cdn$10.87 to Cdn$2.30 per share following the collapse of the world stock markets. The charge in 2009 is a consequence of the 61% increase in the share price during the year. In April 2007, 200,000 Class B treasury stock were awarded to a newly appointed officer. These shares were fully vested at the end of the first quarter of 2009. Net Financing Charges Interest income has fallen from 2008 as a consequence of a reduction in the rate of interest received. The relatively small gain on foreign exchange experienced during the year is a consequence of the strengthening US Dollar against the British Pound. The loss on foreign exchange incurred in the year is in relation to the conversion of funds held in British Pounds and the strengthening of the US Dollar against the Tanzanian Shilling. (Figures in US$’000) Finance income Interest income Foreign exchange gain Finance charges Overdraft charges Foreign exchange loss Net financing charges 2009 2008 44 105 149 (23) (279) (302) (153) 145 56 201 (62) (578) (640) (439) Taxation Income Tax Under the terms of the PSA with TPDC, the Company is liable for income tax in Tanzania at the corporate tax rate of 30%. However, where income tax is payable, this is recovered from TPDC by deducting an amount from TPDC’s profit share. This is reflected in the accounts by adjusting the Company’s revenue by the appropriate amount. As at 31 December 2009, 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$9.1 million which represents an additional deferred future income tax charge of US$3.6 million for the year. This tax has no impact on cash flow until it becomes a current income tax at which point the tax is paid to the Commissioner of Taxes and recovered from TPDC’s share of Profit Gas. Additional Profits Tax Under the terms of the PSA, in the event that all costs have been recovered with an annual return of 25% plus the percentage change in the United States Industrial Goods Producer Price Index, an Additional Profits Tax (“APT”) is payable. The Company provides for APT by forecasting the total APT payable as a proportion of the forecast Profit Gas over the term of the PSA license. The effective APT rate has been calculated to be 20%. Accordingly, US$0.5 million (2008: US$0.4 million) has been netted off revenue for the year ended 31 December 2009. Management does not anticipate that any APT will be payable in 2010, as the forecast revenues will not be sufficient to cover the un-recovered costs brought forward as inflated by 25% plus the PPI percentage change and the forecast expenditures for 2010. 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 program. 32 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Depletion and Depreciation Expense Funds Generated by Operations 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 2009, the proven reserves as evaluated by the independent reservoir engineers McDaniel & Associates Consultants Ltd (“McDaniel”) were 384.9 Bcf after TPDC ‘back in’ on a life of license basis. This leads to an average depletion charge of US$0.37/mcf for the year (2008: US$0.54/mcf). Non-Natural Gas Properties are depreciated as follows: Funds from operations before working capital changes were US$12.7 million for the year ended 31 December 2009 (2008: US$9.8 million). (Figures in US$’000) Profit/(loss) after taxation Adjustments (i) Funds from operations before working capital changes 2009 3,324 9,350 12,674 2008 (9,523) 19,274 9,751 (4,566) Leasehold improvements Over remaining life of the lease Working capital adjustments (i) (390) Computer equipment 3 years Vehicles Fixtures and fittings 3 years 3 years 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. A total of US$9.5 million was written off to the statement of comprehensive income in the prior year in recognition of the impairment of the exploration assets in Uganda. Subsequent to this write off an additional charge to the income statement has been made in the last quarter in relation to a claim by the Ugandan tax authorities for withholding tax that was withheld by the operator during the seismic program pending clarification of the tax regime. Under the terms of the agreement, the Company is liable to accept this 2009 invoice from the operator and consequently a further US$0.2 million has been recognized in exploration and evaluation assets and has been written off in full to the income statement in the last quarter of 2009. Net cash flows from operating activities Net cash flows used in investing activities Net cash flows used in financing activities 12,284 5,185 (8,029) (11,113) (298) (1) Net increase/(decrease) in cash and cash equivalents 3,957 (5,929) (i) See consolidated statements of cash flows The increase in cash and cash equivalents is primarily a consequence of a reduced cost base notably in relation to general and administrative expenses against a background of stable revenue streams between the two years. There was no significant change in working capital excluding cash during the year as the increased receipts have been used to pay down creditors. The resulting net cash flows generated from operations of US$12.3 million has been re-invested in property, plant and equipment and the payment of associated creditors together with the repurchase of shares under the Company’s normal course issuer bid. Capital Expenditures Capital expenditures amounted to US$5.3 million during the year (2008: US$7.7 million). The capital expenditures may be analysed as follows: (Figures in US$’000) Geological and geophysical and well drilling Pipelines and infrastructure Power development Other equipment 2009 2008 (199) 4,443 635 433 3,473 4,147 38 82 5,312 7,740 33 Management’s Discussion & Analysis Operations Review Geological and geophysical and well drilling – US$(0.2) million A total of US$0.3 million was incurred on reservoir studies from the information gathered from pressure data sets. The aim of these studies is to get a better understanding of the connectivity between the wells, establish optimum well performance with a view to get a better understanding of well deliverability, and assessing the GIIP reserves in place. A total of US$0.1 million was incurred on well preparation work for the future drilling of exploration wells on the Songo Songo west prospect. The Songo Songo west prospect is classified as an exploration and evaluation asset. A total of US$0.3 million was incurred on acquiring and interpreting a new 2D seismic line that was shot over the existing Songo Songo field in the third quarter of 2009. A total of US$0.2 million was accrued in relation to the late receipt of an invoice for withholding tax in respect of the acquisition of seismic data over the Exploration 5 licence in Uganda. Following the decision in 2008 not to proceed with continued investment in this prospect, the associated costs incurred in 2009 have been written off in full to the income statement. In April 2010 an agreement was reached with a third party contractor, for breach of contract during the drilling of the SS-10 well in 2007. As a result a credit of US$1.1 million has been recognized in property, plant and equipment for the cancellation of invoices that had not been paid by the Company to the third party. Pipelines and infrastructure – US$4.4 million A total of US$1.2 million was incurred during the year in connecting 10 new customers, 8 of which were consuming Additional Gas by the end of the year. A total of US$0.9 million was incurred on the installation of a new pressure reduction station including the upgrading of pipe work at the Wazo Hill cement plant operated by TPCC. Sales to the cement plant accounted for 20% of the total industrial gas volumes consumed during the year. A total of US$1.5 million was incurred in the year on the continued installation of compressed natural gas (“CNG”) facilities. The facilities include a mother station at the Ubungo power plant , two vehicle dispenser and two daughter stations. The initial CNG project is targeting local hotels and industries and the conversion of motor vehicles to CNG. Orca Exploration incurred a total of US$0.8 million on expansion studies and the re-rating of the Songo Songo gas processing plant. The re-rating of the gas processing facilities at Songo Songo Island from 70 MMcfd to 90 MMcfd in the first quarter of 2009 was critical to allowing the continued growth in the sales of Additional Gas. The Company has continued to investigate additional ways of further increasing the gas processing and pipeline capacity. Power development – US$0.6 million A total of US$0.5 million was incurred in connecting the new TANESCO Tegeta 45 MW power generation unit which was commissioned in Q4 2009. A further US$0.1 million was incurred in upgrading the connections to the Ubungo power plant and the 102 MW TANESCO power generation unit. Working Capital Working capital as at 31 December 2009 was US$16.8 million (31 December 2008: US$9.7 million) and may be analysed as follows: (Figures in US$’000) Cash and cash equivalents Trade and other receivables Trade and other payables Working capital 2009 14,543 9,181 23,724 6,889 16,835 2008 10,586 13,196 23,782 14,055 9,727 The increase in working capital by US$7.1 million during 2009 is primarily due to the generation of US$4.0 million in cash during the year after capital expenditure of US$5.3 million. There has also been a steady movement during the year towards positive non-cash working capital as the overall level of expenditure has declined during the year and there has been an improvement in the collection period of receivables from the power customers. The majority of the cash is held in US and Cdn Dollars in Mauritius, and in Tanzanian Shillings in Tanzanian bank accounts. There are currently no restrictions in Tanzania for converting Tanzania Shillings into US Dollars. Any surplus cash is held in a fixed rate interest earning deposit account. Trade and other receivables at 31 December 2009 represent US$7.1 million of trade receivables (2008: US$11.9 million), US$0.5 million of prepayments (2008: US$0.9 million) and other US$1.6 million (2008: US$0.4 million). 34 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 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 2009, US$4.2 million (2008: US$3.0 million) was due from industrial customers, which has all subsequently been received. The balance of US$2.9 million (2008: US$8.9 million) is made up of amounts due from the two power customers, TANESCO and Songas. The contracts with Songas and TANESCO accounted for 53% (2008: 49%) of the Company’s operating revenue in 2009. Songas’ financial security is, in turn, heavily reliant on the payment of capacity and energy charges by TANESCO. TANESCO is dependent on the Government of Tanzania for some of its funding. While some payments have been delayed, the Company has subsequently collected the majority of the amounts due from Songas and TANESCO as at 31 December 2009. Of the trade and other payables, US$0.6 million related to capital expenditure (2008: US$3.8 million). Outstanding Share Capital There were 29.5 million shares outstanding as at 31 December 2009 which 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 2009 2008 1,751 27,743 29,494 1,751 27,863 29,614 2,797 2,814 32,291 32,428 Class A and Class B shares 29,541 29,614 Convertible securities Options 1,163 1,425 Weighted average diluted Class A and Class B shares 30,704 31,039 The movement in Class B shares during the year is analysed in the table below: Number of shares (‘000) As at 1 January 2009 2008 27,863 27,863 Normal course issuer bid (120) – As at 31 December 27,743 27,863 A normal course issuer bid has been operational since January 2007. A total of 120,200 Class B shares were purchased during 2009 at an average price of Cdn$2.86 per share. 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 IFRS 2, the Company records a charge to the profit and loss account using the Black-Scholes fair valuation option pricing model. The valuation is dependent on a number of estimates, including the risk free interest rate, the level of stock volatility, together with an estimate of the level of forfeiture. The level of stock volatility is calculated with reference to the historic closing share price at the date of issue. The movement in stock options for the year is analysed in the table below: Number of options (‘000) As at 1 January 2009 Forfeited As at 31 December 2009 Options 2,814 (17) 2,797 35 Management’s Discussion & Analysis Operations Review CONTRACTUAL OBLIGATIONS AND COMMITTED CAPITAL INVESTMENT Contractual Obligations Protected Gas Under the terms of the original gas agreement for the Songo Songo project (“Gas Agreement”), in the event that there is a shortfall/insufficiency 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 (34.2 Bcf as at 31 December 2009). The Gas Agreement has been amended by an initialled Amended and Restated Gas Agreement (“ARGA”). The ARGA provides clarification of the Protected Gas volumes and removes all terms dealing with the security of the Protected Gas and the consequences of any insufficiency to a new Insufficiency Agreement (“IA”). The IA specifies terms under which Songas may demand cash security in order to keep them whole in the event of a Protected Gas insufficiency. Once the Insufficiency Agreement is signed, it will govern the basis for determining security. Under the provisional terms of the IA, when it is calculated that funding is required, the Company shall fund an escrow account at a rate of US$2/Mmbtu on all industrial Additional Gas sales out of its and TPDC share of revenue, and TANESCO shall contribute the same amount on Additional Gas sales to the power sector. The funds provide security for Songas in the event of an insufficiency of Protected Gas. The Company is actively monitoring the reservoir and does not anticipate that a liability will occur in this respect. Back in TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development by contributing 20% of the costs of the future wells including SS-10 in return for a 20% increase in the profit share percentage for the production ema- nating from these wells. The implications and workings of the ‘back in’ are currently being discussed with TPDC and there may be the need for reserve modifications once these discussions are concluded. For the purpose of the reserves certification, it has been assumed that they will ‘back in’ for 20% for all future development and this is reflected in the Company’s net reserve position. However, the financial statements do not take account of any reimbursement for the SS-10 capital expenditure, pending the finalisation of the terms of the ‘back in’. Operating leases The Company has two office rental agreements in Dar es Salaam, expiring on 30 November 2012 and 31 October 2013 at an annual rental of US$122,000 and US$110,000 per annum respectively. 36 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Capital Investment Re-rating of the Songas processing plant Orca Exploration is committed to pay Songas US$0.5 million for continuing to allow the gas processing plant to operate at a re-rated 90 MMcfd. This payment was made in March 2010. Funding Management forecasts that the Company will be able to meet its 2010 Tanzanian capital expenditure program through the use of existing cash balances and self-generated cash flows. The Company currently has no bank borrowings and there is scope for utilising debt funding once the longer term contracts for the supply of gas to the power sector are in place. New funding will be required for any future material acquisition. Off-Balance Sheet Transactions Please refer to Notes 20 and 21 of the consolidated financial statements. Related Party Transactions One of the non executive Directors is a partner at a law firm. During the year, the Company incurred US$168,000 to this firm for services provided. The transactions with this related party was made at the exchange amount. Subsequent Events In January 2010, the Company signed a Production Sharing Contract (“PSC”) in relation to an exploration licence. In the event that the PSC is ratified the Company will have exploration work commitments. In April 2010 an agreement was reached with a third party contractor, for breach of contract during the drilling of the SS-10 well in 2007. As a result a credit of US$1.1 million has been recognized in property, plant and equipment for the cancellation of invoices that had not been paid by the Company to the third party. Contingency During the last quarter of the year, the Company received an invoice in relation to a claim made by the Ugandan tax authorities for withholding tax that was withheld by the operator during the seismic program pending clarification of the tax regime. There is a further potential claim for US$0.3 million for additional withholding tax. Whilst it is not considered probable that an additional payment will be made and as such no additional provision has been recognized, the Company cannot go so far as to say that the possibility is remote. SUMMARY QUARTERLY RESULTS The following is a summary of the results for the Company for the last eight quarters: 2009 2008 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 (Figures in US$’000 except where otherwise stated) Financial Revenue Profit/(loss) after taxation Operating netback (US$/mcf) 7,837 1,564 2.29 7,536 1,549 2.17 5,501 4,443 6,371 7,301 4,826 5,284 379 2.17 (168) 2.18 12 2.32 816 (10,208) 2.79 8,705 3.44 6,094 (143) 2.21 8,297 Working capital 16,835 12,147 9,939 9,154 9,727 Shareholders’ equity 68,860 67,159 65,477 64,684 64,712 64,142 62,824 72,053 Profit/(loss) per share – basic and diluted (US$) Capital expenditures Geological and geophysical and well drilling Pipeline and infrastructure Power development Other equipment Operating Additional Gas sold – industrial (MMcf) Additional Gas sold – power (MMcf) Average price per mcf – industrial (US$) Average price per mcf – power (US$) 0.06 0.05 0.01 (0.01) 0.00 0.03 (0.35) 0.00 (890) 338 222 131 157 343 69 1,339 1,317 1,630 289 27 3 207 – 130 (987) 2,217 13 31 419 705 4 51 2,851 1,190 979 21 – 246 – – 542 581 613 360 392 425 336 322 2,570 2,493 1,693 1,570 2,149 2,097 956 1,983 9.49 9.02 7.02 7.91 10.08 13.29 12.97 11.55 2.41 2.41 2.36 2.39 2.39 2.41 2.93 2.05 The principal developments in Q4 2009 were as follows: • • • Achieved a quarterly sales volume of 3,112 MMcf or 33.8 MMcfd which represents the best quarter since sales began in 2004, with the sales revenue at US$7.8 million also being the highest figure recorded. Commenced the sale of Additional Gas to the newly commissioned Tegeta 45 MW power plant. Commenced the sale of Compressed Natural Gas to a major hotel in Dar es Salaam. This is significant as it represents the first supply of CNG in East Africa. 37 Historically the gas price paid by Songas for use at the Ubungo power plant has varied month by month depending on the availability of the gas turbines at the Ubungo power plant. However from January 2008 the price was fixed at US$2.37/ mcf with an annual inflationary increase. The higher average sales price for the power sector recorded in Q2 2008 is due to the higher sales price paid by TANESCO for the supply of Additional Gas to the emergency power units operated by Dowans Tanzania Limited (“Dowans”). TANESCO cancelled the contract with Dowans at the end of July 2008. Profit after taxation Profitability in the first and fourth quarters of each year is affected by the seasonality of gas demand by the textile customers. In addition, there tends to be lower demand for gas by the power sector in the first two quarters of each year as the hydro generation utilisation increases with the seasonal rainfall. A profit of US$1.6 million was recorded in Q4 2009 compared to a profit of US$0.01 million in Q4 2008. The increase in profits between the two quarters is a combination of the commencement of sales to the Wazo Hill cement plant during 2009 higher power sales due to limited hydro generation capacity and the decrease in the overall level of administrative costs that was consistently achieved throughout 2009. Working capital The increase in working capital by US$7.1 million during 2009 is primarily due to the generation of US$4.0 million of cash in the year after capital expenditure of US$5.3 million. There has also been a steady movement during the year towards positive non-cash working capital as the overall level of expenditure has declined during the year and there has been an improved collection of receivables from the power customers. Management’s Discussion & Analysis Operations Review 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 MMcfd in Q4 2004 to 5.9 MMcfd in Q4 2009 (Q4 2008: 4.3 MMcfd). Industrial sales peak in the third quarters of each year as textile customers take advantage of low cotton prices during the harvest season. The average sales in Q3 2009 were 6.3 MMcfd compared to 4.6 MMcfd in Q3 2008. The higher volume recorded in 2009 is primarily due to the sale of Additional Gas to the Wazo Hill cement plant. Excluding Wazo Hill average sales in Q3 2009 were 4.9 MMcfd. The average price to the industrial sector has varied in line with the price of crude oil as the gas is priced at a discount to the price of Heavy Fuel Oil in Dar es Salaam. The average price ranged from US$5.23/mcf in Q1 2005 peaking at US$13.29/ mcf in Q3 2008. During the second half of 2008, the Company extended the term of customers contracts accounting for the majority of the industrial gas sales volumes for an additional five years from the dates that existing contracts were due to expire (the earliest termination date is now September 2014). In return the Company has agreed to cap the price of gas to these customers whilst also incorporating a floor price. This is expected to keep the price of gas in the range of US$7.38/mcf to US$11.49/mcf (increasing at 2% per annum). During 2009 as new customers took delivery of Additional Gas and existing customers contracts have come up for renewal all customers are migrating to the cap and floor contracts with varying level of discounts being offered. The average sales price achieved in Q4 was US$9.49/mcf compared to US$10.08/mcf in Q4 2008. The sale of Additional Gas to the power sector commenced in Q3 2005 and this contributed towards a significant step increase in revenue from that quarter. In Q4 2009 sales averaged 27.9 MMcfd compared to 23.4 MMcfd in Q4 2008. This represents the highest daily rate recorded. Traditionally the highest level of sales to the power sector is recorded in the third quarter of each year when there is limited hydro generation. However as the dry season extended into Q4 2009, the level of sales to the power sector continued at the same rate. 38 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Selected Financial Information Selected annual financial information derived from the audited consolidated financial statements for the years ended 31 December 2007, 2008 and 2009 is set out below: (Figures in US$’000 except per share amount) 2009 2008 2007 Revenue 25,317 23,782 18,777 Funds from operations before working capital changes Profit/(loss) after taxation 12,674 9,751 8,696 Total assets 86,277 85,248 3,324 (9,523) 1,745 92,789 Profit/(loss) per share: Basic and diluted 0.11 (0.32) 0.06 Revenue increased by 6% to US$25.3 million in 2009 from US$23.8 million in 2008, as a result of a 20% increase in sales volume against a background of a 10% decrease in the weighted average sales price. There was a 42% increase in Additional Gas volumes sold to industrials with the majority of the increase being a consequence of the commencement of sales to the Wazo Hill cement plant operated by TPCC in March 2009, with industrial sales accounting for 20% of the total volumes in 2009 compared to 17% in 2008. The level of sales to the power sector having increased by 16% in 2009 to 8,326 MMcf from 7,185 MMcf in 2008 as a consequence of an extended dry season in 2009 and the increased demand for electricity. Revenue increased by 27% in 2008 compared to 2007, as a consequence of a 12% increase in both sales volume, and the weighted average sales price. Funds from operations before working capital changes increased by 30% from US$9.8 million to US$12.7 million in 2009 as a consequence of increased sales revenue and a decrease in the level of general administrative expenses. The decrease in administrative expenses was the result of a lower level of dependency on external consultants and lower levels of expenditure on market development costs associated with regulatory authorities. The 2008 loss after taxation of US$9.5 million was due to the write off of US$9.5 million in relation to the withdrawal from exploration activities in Uganda and the increase in general administrative costs. During 2009, the Company’s assets increased by 1% to US$86.3 million (2008: decreased by 8% to US$85.2 million). The Company’s assets are made up as follows: (Figures in US$’000) Current assets Cash and cash equivalents Trade and other receivables Fixed assets Exploration and evaluation assets Plant, property and other equipment Total assets 2009 2008 2007 14,543 10,586 16,515 9,181 23,724 13,196 23,782 8,236 24,751 760 648 6,881 61,793 62,553 86,277 60,818 61,466 85,248 61,157 68,038 92,789 The increase in cash and cash equivalents is primarily a consequence of a reduction in general and administrative expenses against a background of similar revenue streams between the two years. There has been no significant change in working capital, excluding cash, during the year as increased receipts have been used to pay down creditors. The decrease in the cash and cash equivalents in 2008 is primarily the result of reducing the trade and other payables and the payment of capital expenditure in both Uganda and Tanzania. The decrease in trade and other receivables in 2009 is due to the improved collection of receivables form the power sector, with the overall level of trading activity being consistent between 2009 and 2008. The increase in trade and other receivables in 2008 is due to the increased trading activities in the power sector and the delay in payments from TANESCO. The level of capital expenditure in 2009 has been similar to 2008. The focus in 2009 has been on the development of the CNG market and its associated facilities, continued geological studies of the existing gas reservoir, increasing the overall processing capacity of the existing facilities and connecting the Tegeta 45 MW power generation station. 39 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 including the energy regulator, EWURA. 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 adminis- trations or governmental regulations in Tanzania will not materially adversely affect the operations or future cash flows of Orca Exploration. Additional Financing Depending on future exploration, development, and marketing plans, Orca Exploration may require additional financing. The ability of Orca Exploration to arrange such financing in the future will depend in part upon the prevailing capital market conditions as well as the business performance of Orca Exploration. There can be no assurance that Orca Exploration will be successful in its efforts to arrange additional financing on terms satisfactory to Orca Exploration. If additional financing is raised by the issuance of shares from treasury of Orca Exploration, control of Orca Exploration may change and shareholders may suffer additional dilution. From time to time Orca Exploration may enter into transactions to acquire assets or the shares of other companies. These transactions may be financed partially or wholly with debt, which may temporarily increase Orca Exploration’s debt levels above industry standards. Management’s Discussion & Analysis Operations Review Business Risks 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 environment, as well as interrupt operations. In addition, all of Orca Exploration’s operations will be subject to the risks normally incident to drilling of natural gas wells and the operation and development of gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blowouts, equipment failures and other accidents, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution and other environmental risks. Drilling conducted by 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. Foreign Operations All of Orca Exploration’s operations and related assets are located in Tanzania which may be considered to be politically and/or economically unstable. Exploration or development activities in Tanzania may require protracted negotiations with host governments, national oil companies and third parties and are frequently subject to economic and political considerations, such as, the risks of war, actions by terrorist or insurgent groups, expropriation, nationalization, renegotiation or nullification of existing contracts, taxation policies, foreign exchange restrictions, changing political conditions, international monetary fluctuations, currency controls and foreign governmental regulations that favour or require the awarding of drilling contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. In addition, if a dispute arises with foreign operations, Orca Exploration may be subject to the exclusive jurisdiction of foreign courts. 40 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Industry Conditions 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. Replacement of Reserves Orca Exploration’s natural gas reserves and production and, therefore, its cash flows and earnings are highly dependent upon Orca Exploration developing and increasing its current reserve base and discovering or acquiring additional reserves. Without the addition of reserves through exploration, acquisition or development activities, Orca 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 six wells. There has been limited production from the six 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. The oil and gas industry is intensely competitive and Orca Exploration competes with other companies which possess greater technical and financial resources. Many of these competitors not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum, natural gas products and other products on an international basis. Oil and gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and invasion of water into producing formations. Currently, Orca Exploration operates the Songo Songo natural gas property. There is a risk that in the future either the operatorship could change and the property operated by third parties or operations may be subject to control by national oil companies, Songas, or parastatal organisations and, as a result, Orca Exploration may have limited control over the nature and timing of exploration and development of such properties or the manner in which operations are conducted on such properties. 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. in each of the The oil and natural gas industry is subject to varying environmental regulations 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. 41 Management’s Discussion & Analysis Operations Review 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 Orca Exploration. As party to various licenses, Orca Exploration has an obligation to restore producing fields to a condition acceptable to the authorities at the end of their commercial lives. While management believes that Orca Exploration is currently in compliance with environmental laws and regulations applicable to Orca Exploration’s operations in Tanzania, no assurances can be given that Orca Exploration will be able to continue to comply with such environmental laws and regulations without incurring substantial costs. Orca Exploration’s petroleum and natural gas operations are subject to extensive governmental legislation and regulation and increased public awareness concerning environmental protection. No provision has been recognised for future decommis- sioning costs which are anticipated to be minimal as it is forecast that there will still be commercial gas reserves once Orca Exploration relinquishes the license in 2026. Orca Exploration expects that the cost of complying with environmental legislation and regulations will increase in the future. Compliance with existing environmental legislation and regulations has not had a material effect on capital expenditures, earnings or competitive position of Orca Exploration to date. Although management believes that Orca Exploration’s operations and facilities are in material compliance with such laws and regulations, future changes in these laws, regulations or interpretations thereof or the nature of its operations may require the Company to make significant additional capital expenditures to ensure compliance in the future. Volatility of Oil and Gas Prices and Markets Orca Exploration’s financial condition, operating results and future growth will be dependent on the prevailing prices for its natural gas production. Historically, the markets for oil and natural gas have been volatile and such markets are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes to the demand for oil and natural gas, whether the result of uncertainty or a variety of additional factors beyond the control of Orca Exploration. Any substantial decline in the prices of oil and natural gas could have a material adverse effect on Orca Exploration and the level of its natural gas reserves. Additionally, the economics of producing from some wells may change as a result of lower prices, which could result in a suspension of production by Orca Exploration. No assurance can be given that oil and natural gas prices will be sustained at levels which will enable Orca Exploration to operate profitably. From time to time Orca Exploration may avail itself of forward sales or other forms of hedging activities with a view to mitigating its exposure to the risk of price volatility. The term of the Company’s six largest gas supply contracts has been recently extended for five years. The new contracts contain pricing caps and floors that limit the industrial downside price to US$7.38/mcf. The Company also entered into fixed price contracts with TANESCO and Songas for the supply of Additional Gas to the power sector. The steps taken by the Company in 2008 were very important steps in mitigating the exposure to price volatility. 42 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t The Songo Songo field was the first gas field to be developed in East Africa and was followed by a commercial gas discovery in the south of Tanzania at Mnazi Bay. The Company is the only supplier of gas into the main demand centre of Dar es Salaam and 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 and coal. There has been an increase in exploration activity in Tanzania that could, if successful, 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. 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, TPDC “back-in” methodology 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 commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the claim of Orca Exploration which could result in a reduction of the revenue received by Orca Exploration. Acquisition Risks Orca Exploration intends to acquire natural gas infrastructure and possibly additional oil and gas properties. Although Orca Exploration performs a review of the acquired properties that it believes is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, Orca Exploration will focus its due diligence efforts on the higher valued properties and will sample the remainder. However, even an in depth review of all properties and records may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not be performed on every well, and structural or environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. 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 unexpected loss of the services of any of these individuals could have a detrimental effect on Orca Exploration. Orca Exploration does not maintain key life insurance on any of its employees or officers. Controlling Shareholder W David Lyons, the Company’s Chairman and CEO, is the beneficial controlling shareholder of Orca Exploration and holds approximately 99.5% of the outstanding Class A shares and approximately 15.9% of the Class B shares. Consequently, Mr. Lyons is the beneficial holder of approximately 20.7% of the equity (22.0% fully diluted) and controls 62.5% of the total votes of Orca Exploration. 43 Management’s Report to Shareholders Operations Review The accompanying consolidated financial statements of Orca Exploration Group Inc. 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 Deputy Chairman and Chief Financial Officer, has evaluated the effectiveness of the Com- pany’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 Sharehold- ers, 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 Commit- tee. The committee has met with external auditors and Management in order to determine if Management has fulfilled its responsibili- ties 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 Deputy Chairman 19 April 2010 Nigel Friend Chief Financial Officer 19 April 2010 44 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Auditors’ Report 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 statement of financial position as at 31 December 2009 and 31 December 2008 and the consolidated statement of comprehensive income, consolidated statement of cash flows and statement of changes in shareholders’ equity for the years then ended, a summary of significant accounting policies and notes to the consolidated financial statements. Management’s Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards. This responsibility includes: designing, implementing and maintaining internal controls relevant to the preparation and fair presentation of the financial statements that are free from material misstatements, whether due to fraud or error; selecting and applying appropriate accounting policies; and making accounting estimates that are reasonable in the circumstances. Auditors’ Responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the International Standards on Auditing. Those standards require that we comply with the relevant ethical requirements and plan and perform the audit to obtain a reasonable assurance whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgement, including the assessments of the risks of material misstatements of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal controls relevant to the entity’s preparation and fair presentation of the financial statements in order 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 2009 and 31 December 2008, and of its consolidated financial performance and its statement of consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards. Calgary, Canada 19 April 2010 Is est, iniminv endenesed et quunt ex estotatio. Loria siti volorro voluptus ant.Usam dolorem. Icia sinte nulluptat. O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 45 Financial Statements Operations Review Consolidated Statement of Comprehensive Income YEARS EndEd 31 dECEmBER NOTE (thousands of US dollars except per share amounts) Revenue Cost of sales Production and distribution expenses Depletion expense Impairment of exploration and evaluation assets General and administrative expenses Net financing charges Profit/(loss) before taxation Taxation Profit/(loss) and comprehensive income/(loss) for the year Earnings per share Basic and diluted (US$) See accompanying notes to the consolidated financial statements. 5 12 11 7 8 2009 25,317 (2,807) (3,830) (180) 18,500 (11,465) (153) 6,882 (3,558) 3,324 2008 23,782 (1,477) (4,716) (9,520) 8,069 (14,686) (439) (7,056) (2,467) (9,523) 17 0.11 (0.32) Flare Addtional Gas Sales Protected Gas Sales 46 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Production Volumes Consolidated Statement of Financial Position AS AT 31 dECEmBER (thousands of US dollars) ASSETS Current assets Cash and cash equivalents Trade and other receivables Non-current assets Exploration and evaluation assets Property, plant and equipment EQUITY AND LIABILITIES Current liabilities Trade and other payables Non-current liabilities Deferred income taxes Deferred additional profits tax Equity attributable to owners of parent Capital stock Other components of equity Accumulated loss NOTE 2009 2008 9 10 11 12 13 8 15 16 14,543 9,181 23,724 760 61,793 62,553 86,277 10,586 13,196 23,782 648 60,818 61,466 85,248 6,889 14,055 9,068 1,460 17,417 66,267 4,809 (2,216) 68,860 86,277 5,510 971 20,536 66,537 3,715 (5,540) 64,712 85,248 See accompanying notes to the consolidated financial statements. Contractual obligations and committed capital investment (Note 20) Subsequent events (Note 21) Contingency (Note 22) Is est, iniminv endenesed et quunt ex estotatio. Loria siti volorro voluptus ant.Usam dolorem. Icia sinte nulluptat. The consolidated financial statements were approved by the Board of Directors on 19 April 2010. Director Director O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 47 Financial Statements Operations Review Consolidated Statement of Cash Flows YEARS EndEd 31 dECEmBER (thousands of US dollars) CASH FLOWS FROM OPERATING ACTIVITIES Profit/(loss) after taxation Adjustment for: Depletion and depreciation Impairment of exploration and evaluation assets Stock-based compensation Deferred income taxes Deferred additional profits tax Interest income Decrease/(increase) in trade and other receivables (Decrease)/increase in trade and other payables Net cash flows from operating activities CASH FLOWS USED IN INVESTING ACTIVITIES Exploration and evaluation expenditures Property, plant and equipment expenditures Interest income Decrease in trade and other payables Net cash used in investing activities CASH FLOWS USED IN FINANCING ACTIVITIES Normal course issuer bid Net cash flow used in financing activities Increase/(decrease) 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. NOTE 2009 2008 3,324 (9,523) 12 11 15 8 11 12 15 9 4,045 180 1,122 3,558 489 (44) 12,674 4,015 (4,405 ) 12,284 (292) (5,020) 44 (2,761) (8,029) (298) (298) 3,957 10,586 14,543 4,792 9,520 2,419 2,305 383 (145) 9,751 (4,960) 394 5,185 (3,014) (4,453) 145 (3,791) (11,113) (1) (1) (5,929) Flare 16,515 10,586 Addtional Gas Sales Protected Gas Sales 48 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Production Volumes Statement of Changes in Shareholders’ Equity Capital stock Other components of equity Accumulated Income/ (loss) (thousands of US dollars) Note Balance as at 1 January 2008 Stock-based compensation Normal course issuer bid Total comprehensive (loss) for the year Balance as at 31 December 2008 Stock-based compensation Normal course issuer bid Total comprehensive income for the year 15 66,538 – (1) – 66,537 – (270) – 16 1,023 2,692 – – 3,715 1,122 (28) – Balance as at 31 December 2009 66,267 4,809 See accompanying notes to the consolidated financial statements. 3,983 – – (9,523) (5,540) – – 3,324 (2,216) Total 71,544 2,692 (1) (9,523) 64,712 1,122 (298) 3,324 68,860 Is est, iniminv endenesed et quunt ex estotatio. Loria siti volorro voluptus ant.Usam dolorem. Icia sinte nulluptat. O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 49 Notes to the Consolidated Financial Statements General Information Orca Exploration Group Inc. (“Orca Exploration” or the “Company”) was incorporated on 28 April 2004 under the laws of the British Virgin Islands. The Company is a participant in a gas-to-electricity project in Tanzania. The Company’s operations at the Songo Songo gas field in Tanzania include the operation of six producing wells and two 45 MMcfd dehydration and refrigeration gas processing units on Songo Songo Island on behalf of Songas Limited (“Songas”). Gas produced and sold from the Songo Songo field is classified as either Protected Gas or Additional Gas. Protected Gas is 100% owned by Tanzania Petroleum Development Corporation (“TPDC”) and is sold to Songas under a twenty year Gas Agreement primarily for use at the Ubungo power plant and the Wazo Hill cement plant. The Protected Gas is principally used as feedstock for specified turbines and kilns. Gas sales in excess of the Protected Gas users’ requirements is classified as Additional Gas. The Company has the exclusive right to explore, develop, produce and market all Additional Gas. Revenues from the sale of Additional Gas, net of transportation tariff, are shared with TPDC in accordance with the terms of the Production Sharing Agreement (“PSA”) until October 2026. 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 2 3 4 Summary of Significant Accounting Policies STATEMENT OF COMPLIANCE A) 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 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. 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 Functional currency Orca Exploration Group Inc British Virgin Islands Parent Company Orca Exploration Ventures Inc British Virgin Islands Orca Exploration Uganda (Holdings) Inc British Virgin Islands Orca Exploration Uganda Inc British Virgin Islands PAE PanAfrican Energy Corporation PanAfrican Energy Tanzania Limited Mauritius Jersey ii) Transactions eliminated upon consolidation 100% 100% 100% 100% 100% US dollar US dollar US dollar US dollar US dollar US dollar Inter-company balances and transactions, and any unrealised gains arising from inter-company transactions, are eliminated in preparing the consolidated financial statements. 50 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t C) FOREIGN CURRENCY Foreign currency transactions are recorded at the rate of exchange prevailing at the date of the transaction. Monetary assets and liabilities in foreign currencies are translated at period-end rates. Non-monetary items are translated at historic rates, unless such items are carried at market value, in which case they are translated using the exchange rates that existed when the values were determined. Any resulting exchange rate differences are taken to the income statement. D) EXPLORATION AND EVALUATION ASSETS, PROPERTY, PLANT AND EQUIPMENT i) Exploration and evaluation assets Exploration and evaluation costs are capitalised as intangible assets. Intangible assets includes lease and license acquisition costs, geological and geophysical costs and other direct costs of exploration and evaluation which the directors consider to be unevaluated until reserves are appraised as commercial, at which time they are transferred to property, plant and equipment following an impairment review and depleted accordingly. Where properties are appraised to have no commercial value or are appraised at values less than book values, the associated costs are treated as an impairment loss in the period in which the determination is made. ii) Property, plant and equipment Property, plant and equipment comprises the Company’s tangible natural gas assets, development wells, together with leasehold improvements, computer equipment, motor vehicles and fixtures and fittings and are carried at cost, less any accumulated depletion, depreciation and accumulated impairment losses. Cost includes purchase price and construction costs for qualifying assets. Depletion of these assets commences when the assets are ready for their intended use. Only costs that are directly related to the discovery and development of specific oil and gas reserves are capitalised. The cost associated with tangible natural gas assets are amortised on a field by field unit of production method based on commercial proven reserves. The calculation of the unit of production amortisation takes into account the estimated future development cost of the field. iii) Impairment of exploration and evaluation assets, property, plant and equipment At each balance sheet date, the Company reviews the carrying amounts of its property, plant and equipment and intangible assets to determine whether there is any indication that those assets have suffered an impairment loss. Individual assets are grouped together as a cash generating unit for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are independent from other group assets. In the case of exploration and evaluation assets, this will normally be at the Company’s field level. If any such indication of impairment exists, the Company makes an estimate of its recoverable amount. The recoverable amount is the higher of fair value less costs to sell and value in use. Where the carrying amount of a cash generating unit exceeds its recoverable amount, the cash generating unit is considered impaired and is written down to its recoverable amount. In assessing the value in use, the estimated future cash flows are adjusted for the risks specific to the cash generating unit and are discounted to their present value with a discount rate that reflects the current market indicators. Where an impairment loss subsequently reverses, the carrying amount of the asset cash generating unit is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the cashgenerating unit in prior years. A reversal of an impairment loss is recognised as income immediately. 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 against revenue. O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 51 Notes to the Consolidated Financial Statements F) TRADE AND OTHER RECEIVABLES Trade and other receivables are stated at their recoverable amount. G) CASH AND CASH EQUIVALENTS Cash and cash equivalents include cash on deposit and highly liquid investments with original maturities of three months or less. H) EMPLOYMENT BENEFITS 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 market value at the date of grant. When the options are exercised, equity is increased by the amount of the proceeds received. The fair value of stock 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, officers and employees. The fair value of stock appreciation rights is expensed to the income statement in accordance with the service period. The fair value of the stock appreciation rights is revalued every reporting date with the change in the value expensed to the income statement. I) ASSET RETIREMENT OBLIGATIONS No provision has been made for future site restoration costs since the Company has no legal or contractual obligation under the PSA to restore the fields at the end of their commercial lives. J) REVENUE RECOGNITION, PRODUCTION SHARING AGREEMENTS AND ROYALTIES The Company recognises revenue from natural gas sales when title passes to a customer. The Company conducts operations jointly with the Tanzanian government and “parastatal entities” in accordance with production sharing agreements (“PSA”). Under these agreements, the Company pays both its share and the parastatal’s share of operating, administrative and capital costs. The Company recovers all the operating, administrative and capital costs including the parastatal’s share of these costs from future revenues over several years (“Cost Gas”). The parastatal’s share of operating and administrative costs, are recorded in operating and general and administrative costs when incurred and capital costs are recorded in ‘Property, plant and equipment’. All recoveries are recorded as revenue in the year of recovery. The Company is entitled to a share of production in excess of the Cost Gas (“Profit Gas”). Operating revenue represents the Company’s share of Cost Gas and Profit Gas during the period, net of the transportation tariff. K) ADDITIONAL PROFITS TAX Under the terms of the PSA, in the event that all costs have been recovered with an annual return of 25% plus the percentage change in the United States Industrial Goods Producer Price Index, an additional profits tax (“APT”) is payable to the Government of Tanzania. This tax is considered to be a royalty and is netted against revenue. APT is provided for by forecasting the total APT payable as a proportion of the forecast Profit Gas over the term of PSA license. 52 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t L) TAXATION Income tax on the profit for the year comprises current and deferred tax. The Company is liable for Tanzanian income tax, but this is recovered from TPDC through the profit-sharing arrangement. Where current income tax is payable, revenue is adjusted for the tax and the income tax is shown as current tax. Deferred tax is provided using the balance sheet asset and liability method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. The amount of deferred tax provided is based on the expected manner of realisation or settlement of carrying amounts of assets and liabilities using tax rates substantively enacted at the balance sheet date. A deferred tax asset is recognised only to the extent that it is probable that future taxable profits will be available against which the asset can be utilised. Deferred tax assets are reduced to the extent that it is no longer probable that the related tax benefits will be realised. M) SEGMENTAL REPORTING The Company currently operates only in Tanzania. N) 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 O) NEW ACCOUNTING STANDARDS AND INTERPRETATIONS Certain new accounting standards and interpretations have been published that are not mandatory for the 31 December 2009 reporting period. The following standards are assessed not to have any impact on the Company’s financial statements: • • • • IAS 24 Related Party Disclosure: effective for accounting periods commencing on or after 1 January 2011; IAS 32, Amendment for Classification of Rights Issues: effective for accounting periods commencing on or after 1 February 2010; IFRS 9 Financial Instruments: effective for accounting periods commencing on or after 1 January 2013; IFRIC 19 Extinguishing Financial Liabilities with Equity Instruments: effective for accounting periods commencing on or after 1 July 2010; P) FINANCIAL INSTRUMENTS The Company’s financial instruments reflected on the balance sheet consist of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities. The fair value of these instruments approximates their carrying amount due to their short terms to maturity. O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 53 Notes to the Consolidated Financial Statements 1 2 3 6 CRITICAL ACCOUNTING ESTIMATES 5 4 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 In applying the Company’s accounting policies, which are described in note 1, management makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, vary to the actual results. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below: I) RESERVES There are numerous uncertainties inherent in estimating quantities of proved and probable reserves and cash flows to be derived 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, TPDC “back-in” methodology and other government levies that may be imposed over the producing life of the reserves. These assumptions were based on price forecasts in use at the date of the relevant evaluations were prepared and many of these assumptions are subject to change and are beyond the control of Orca Exploration. Reserves are integral to the amount of depletion charged to the income statement. II) EXPLORATION AND EVALUATION ASSETS Under the Company’s accounting policy expenditures incurred on the exploration for, and evaluation of, reserves are capitalized as intangible assets. These intangibles assets are then assessed for impairment when circumstances suggest that the carrying amount may exceed its recoverable value. Such circumstances include but are not limited to: • • • • • • the period for which the Company has the right to explore in the specific area has expired during the period, or will expire in the near future, and is not expected to be renewed; no further expenditure on exploration and evaluation is budgeted or planned; no reserves have been encountered; the evaluation of seismic data indicates that the reserves are unlikely to be of a commercial quantity; the quantity of mineral reserves are deemed not to be of commercially viable quantities and the entity has decided to discontinue further activities, and sufficient data exists to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale. The assessment for impairment involves estimates as to (i) the likely future commerciality of the asset and when such commerciality should be determined, (ii) future revenues and costs associated with the asset, and (iii) the discount rate to be applied to such revenues and costs for the purpose of deriving a recoverable value. III) FAIR VALUE OF STOCK BASED COMPENSATION All stock options issued or stock appreciation rights granted by the Company have to be valued at their fair value. In assessing the fair value of the equity based compensation, estimates have to be made as to i) the volatility in share price, ii) risk free rate of interest and iii) the level of forfeiture. In the case of stock options, this fair value is estimated at the date of issue and is not revalued, where as the fair value of stock appreciation rights is recalculated at each reporting period. 54 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 1 2 3 4 RISK MANAGEMENT 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 The Company, by its activities in oil and gas exploration, development and production, is exposed to the risk associated with the unpredictable nature of the financial markets. The Company seeks to manage its exposure to these risks where ever possible. I) FOREIGN EXCHANGE RISK Foreign exchange risk arises when transactions and recognised assets and liabilities of the Company are denominated in a currency that is not the U.S. dollar functional currency. The Company operates internationally and is exposed to foreign exchange risk arising from currency exposures to U.S. dollars. The main currencies to which the Company has an exposure are: Tanzanian shillings, British pounds sterling and Canadian dollars. The majority of the expenditure associated with the operation of the gas distribution system is denominated in Tanzanian shillings. The majority of the consultants’ contracts are denominated in British pounds sterling. All of the capital stock, equity financing and any associated stock based compensation are denominated in Canadian dollars. All of the operational revenue and the majority of capital expenditure are denominated in US dollars. There are no forward exchange rate contracts in place. A 10% increase in the USD against the relevant foreign currency would result in an overall reduction in working capital by US$0.5 million to US$16.3 million. The sensitivity includes only outstanding foreign currency denominated monetary items and adjusts their translation at period end for a 10% change in the foreign currency rates. A 10% sensitivity rate is used when reporting foreign currency risk internally to key management personnel and represents management’s assessment of the reasonable possible change in foreign exchange rates. II) COMMODITY PRICE RISK The Songo Songo gas 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, primarily Heavy Fuel Oil (“HFO”). The price of HFO is exposed to the volatility in the market price of oil. III) INTEREST RATE RISK The Company currently does not have any debt or borrowings so it is therefore not exposed to any interest rate risk. IV) CREDIT RISK All of the Company’s production is currently derived in Tanzania. The sales are made to the power sector and the industrial sector. In relation to sales to the power sector, the Company has a short term contract with Songas for the supply of gas to the Ubungo power plant and a contract with TANESCO to supply 147 MWs of power generation. The contracts with Songas and TANESCO accounted for 53% of the Company’s operating revenue during 2009 and US$2.9 million of the receivables at the year end. Songas itself is heavily reliant on the payment of capacity and energy charges by TANESCO for its liquidity. TANESCO is dependent on the Government of Tanzania for some of its funding. While some payments have been delayed, the Company has subsequently received all the amounts due from Songas. TANESCO has paid the majority of the amounts due. Sales to industrial sector are subject to an internal credit review to minimize the risk of non payment. The Company does not anticipate any default with these customers. During the year one customer defaulted and the small debt was subsequently written off. O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 55 Notes to the Consolidated Financial Statements V) LIQUIDITY RISK Liquidity risk is the risk that the Company will not have sufficient funds to meet its liabilities. Cash forecasts identifying liquidity requirements of the Company are produced on a quarterly basis. These are reviewed on a regular basis to ensure sufficient funds exist to finance the Company’s current operational and investment cash flow requirements. The Company has no financial liabilities other than the trade and other payables indentified in note 13 of which US$4.8 million is due within one to three months, US$1.8 million is due within three to six months, and US$0.3 million is due within six to twelve months. The Company currently has a short term US$3 million overdraft facility. The Company currently has no bank borrowings and there is scope for utilising debt funding once the longer term contracts for the supply of gas to the power sector are in place. VI) CAPITAL RISK MANAGEMENT The Company’s objectives when managing capital are to safeguard the Company’s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Company currently has no borrowings. 1 2 3 4 8 7 5 6 SEGMENTAL INFORMATION The Company has a single class of business which is international exploration, development and production of petroleum and natural gas. The Company currently operates in Tanzania having ceased its operations in Uganda during 2008. 13 16 12 11 10 14 15 9 17 18 19 20 21 22 23 YEARS EndEd 31 dECEmBER (Figures in US$’000) 2009 Tanzania Uganda 2008 Tanzania Uganda External revenue Segment income/ (loss) Total assets Total liabilities Capital additions Depletion, depreciation & Impairment 25,317 – 25,317 23,782 – 23,782 3,504 (180) 3,324 86,277 17,237 – 180 86,277 17,417 (3) 85,248 20,536 (9,520) (9,523) – – 85,248 20,536 5,132 180 5,312 5,101 2,639 7,740 4,045 180 4,225 4,792 9,520 14,312 1 2 3 4 5 6 REVENUE 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 YEARS EndEd 31 dECEmBER (Figures in US$’000) Operating revenue Current income tax adjustment Deferred additional profits tax Provision for bad debts Revenue 56 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 2009 2008 25,840 23,916 – (489) (34) 249 (383) – 25,317 23,782 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$25,317,000 after adjusting the Company’s operating revenue of US$25,840,000 by: i) ii) US$ nil for income tax for the current year. The Company is liable for income tax in Tanzania, but the income tax is recoverable out of TPDC’s Profit Gas when the tax is payable. To account for this, revenue is adjusted to reflect the current income tax charge or loss. US$489,000 for the deferred effect of additional profits tax. This tax is considered a royalty and is netted against revenue. iii) US$34,000 as outlined in note 3(iv) above. 1 2 3 4 5 6 8 7 PERSONNEL EXPENSES 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 The average number of employees during the year was 28 (2008: 21). The costs are as follows: YEARS EndEd 31 dECEmBER (Figures in US$’000) Wages and salaries Social security costs Other statutory costs 2009 1,582 308 522 2,412 2008 1,434 288 385 2,107 1 2 3 4 5 6 7 8 10 9 NET FINANCING CHARGES 11 12 13 14 15 16 17 18 19 20 21 22 23 YEARS EndEd 31 dECEmBER (Figures in US$’000) Finance income Interest income Foreign exchange gain Finance charges Overdraft charges Foreign exchange loss Net financing charges 2009 2008 44 105 149 (23) (279) (302) (153) 145 56 201 (62) (578) (640) (439) O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 57 Notes to the Consolidated Financial Statements 1 2 3 4 5 6 7 8 9 TAXATION 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Under the terms of the Production Sharing Agreement with TPDC, the Company is liable to pay income tax at the corporate rate of 30% on profits generated in Tanzania. The amount paid is then recovered in full from TPDC by adjusting their share of profit gas. The tax charge is as follows: YEARS EndEd 31 dECEmBER (Figures in US$’000) Current tax Deferred tax Tax Rate Reconciliation YEARS EndEd 31 dECEmBER (Figures in US$’000) Profit/(loss) before taxation Provision for income tax calculated at the statutory rate of 30% Add the tax effect of non-deductible income tax items: Administrative and operating expenses Stock- based compensation Other income Impairment of exploration and evaluation assets Permanent differences 2009 – 3,558 3,558 2008 162 2,305 2,467 2009 2008 6,882 2,065 981 420 (42) 54 80 3,558 (7,056) (2,117) 1,187 504 (22) 2,856 59 2,467 As at 31 December 2009, there were temporary differences between the carrying value of the assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Accordingly a deferred tax liability has been recognized for the year ended 31 December 2009. The deferred income tax liability includes the following temporary differences: AS AT 31 dECEmBER (Figures in US$’000) Differences between tax base and carrying value of property, plant and equipment Provision for stock option bonuses Income tax recoverable Other liabilities Additional profits tax Tax losses 2009 9,639 – 167 (54) (435) (249) 9,068 2008 6,338 (2) 221 (196) (291) (560) 5,510 58 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 1 2 3 4 5 6 7 8 9 1 2 3 4 5 6 7 8 9 10 1 2 3 4 5 6 7 8 9 10 11 10 11 CASH AND CASH EQUIVALENTS 12 13 14 15 16 17 18 19 20 21 22 23 AS AT 31 dECEmBER (Figures in US$’000) Cash and short term deposits 2009 2008 14,543 10,586 Included in the cash and cash equivalents is US$159,000 advanced from Songas under the terms of the Operatorship Agreement to pay for the costs of operating these wells and gas processing plant. This amount is also included in trade and other payables. 11 12 TRADE AND OTHER RECEIVABLES 13 14 AS AT 31 dECEmBER (Figures in US$’000) Trade receivables Prepayments Other receivables 15 16 17 18 19 20 21 22 23 2009 7,100 465 1,616 9,181 2008 11,896 950 350 13,196 The Company’s exposure to credit, currency and interest risk related to trade and other receivables is disclosed in note 3. 12 13 EXPLORATION AND EVALUATION ASSETS 15 14 (Figures in US$’000) Costs As at 1 January 2009 Additions As at 31 December 2009 Depletion/Impairment As at 1 January 2009 Impairment As at 31 December 2009 Net Book Values As at 31 December 2009 As at 31 December 2008 16 17 18 19 20 21 22 23 Uganda Tanzania Total – 180 180 – (180) (180) – – 648 112 760 – – – 760 648 648 292 940 – (180) (180) 760 648 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 59 Notes to the Consolidated Financial Statements TANZANIA The exploration and evaluation asset relates to initial evaluation of the Songo Songo West prospect which is pending the determination of proven and probable reserves. UGANDA As a result of the seismic acquired in 2007, it was decided in June 2008 not to progress with the drilling of two exploration wells. Accordingly, the Company did not exercise its option to acquire a 50% working interest in Exploration Area 5 in Uganda. A total cost of US$9.5 million was subsequently recognized, as an impairment and written off in full to the income statement. Subsequent to this write off an additional charge was recorded in the last quarter of 2009 following the late receipt of an invoice in relation to a potential claim by the Ugandan tax authorities for withholding tax that was withheld by the operator during the seismic program pending clarification of the tax regime. Accordingly, the full amount has been recognized and written off in full to the income statement in Q4 2009. 1 2 3 4 5 6 7 8 9 10 11 12 13 16 PROPERTY, PLANT AND EQUIPMENT 14 15 17 18 19 20 21 22 23 Tanzania Leasehold improvements Computer equipment Vehicles Fixtures & Fittings Total Figures in US’000 Costs As at 1 January 2009 Additions Disposals 72,732 4,587 – As at 31 December 2009 77,319 Depletion/Depreciation As at 1 January 2009 Charge for period Depreciation on disposals 12,072 3,830 – As at 31 December 2009 15,902 Net Book Values As at 31 December 2009 As at 31 December 2008 61,417 60,660 185 80 – 265 156 64 – 220 45 29 207 248 – 455 126 104 – 230 225 81 122 65 (26) 161 85 43 (26) 102 59 37 52 40 – 92 41 4 – 45 47 11 73,298 5,020 (26) 78,292 12,480 4,045 (26) 16,499 61,793 60,818 In determining the depletion charge, it is estimated by the independent reserve engineers that future development costs of US$57.5 million (2008: US$89.1 million) will be required to bring the total proved reserves to production. 60 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 1 2 3 4 5 6 7 8 9 10 11 12 13 1 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 1 9 10 11 13 14 10 11 12 14 15 12 13 14 15 TRADE AND OTHER PAYABLES 16 17 18 19 20 21 22 23 AS AT 31 dECEmBER (Figures in US$’000) Trade payables Accrued liabilities Related party (note 19) 2009 4,270 2,594 25 6,889 2008 11,799 2,256 – 14,055 The Company’s exposure to credit, currency and interest risk related to trade and other payables is disclosed in note 3. 15 16 BANK FACILITY The Company currently has a short-term undrawn US$3.0 million overdraft facility. 22 20 21 19 18 17 23 16 17 CAPITAL STOCK a) Authorised 18 19 20 21 22 23 50,000,000 Class A Common Shares 50,000,000 Class B Subordinate Voting Shares No par value No par value The Class A and Class B shares rank pari passu in respect of dividends and repayment of capital in the event of winding-up. Class A shares carry twenty votes per share and Class B shares carry one vote per share. The Class A shares are convertible at the option of the holder at any time into Class B shares on a one-for-one basis. The Class B shares are convertible into Class A shares on a one-for-one basis in the event that a take-over bid is made to purchase Class A shares which must, by reason of a stock exchange or legal requirements, be made to all or substantially all of the holders of Class A shares and which is not concurrently made to holders of Class B shares. b) Changes in the capital stock of the Company were as follows: 2009 2008 Authorised Issued Valuation Authorised Issued Valuation 50,000 1,751 983 50,000 1,751 983 Thousands of shares or US$’000 Class A shares As at 1 January and 31 December Class B shares As at 1 January 50,000 27,863 65,554 50,000 27,863 65,555 Normal course issuer bid – (120) (270) – – (1) As at 31 December 50,000 27,743 65,284 50,000 27,863 65,554 Total Class A & B shares as at 31 December 100,000 29,494 66,267 100,000 29,614 66,537 A normal course issuer bid has been operational since January 2007. A total of 120,200 Class B shares were purchased during 2009 at an average price of Cdn$2.86 per share. A total of US$270,000 has been reflected in share capital with the premium of US$28,000 being recognized in another component of equity. O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 61 Notes to the Consolidated Financial Statements STOCK-BASED COMPENSATION The stock option plan provides for the granting of stock options to directors, officers and employees. The exercise price of each stock option is determined at the closing market price of the common shares on the day prior to the day of grant. Each stock option granted permits the holder to purchase one common share at the stated exercise price. The Company records a charge to the profit and loss account using the Black-Scholes fair valuation option pricing model. The valuation is dependent on a number of estimates, including the risk free interest rate, the level of stock volatility, together with an estimate of the level of forfeiture. The level of stock volatility is calculated with reference to the historic traded daily closing share price at the date of issue. STOCK OPTIOnS Thousands of options or Cdn$ Outstanding as at 1 January Forfeited 2009 2008 Options 2,814 (17) Exercise Price 1.00 to 13.55 12.00 Options 2,847 (33) Exercise Price 1.00 to 13.55 12.00 Outstanding as at 31 December 2,797 1.00 to 13.55 2,814 1.00 to 13.55 The weighted average remaining life and weighted average exercise prices of options at 31 December 2009 were as follows: Number Outstanding as at 31 December 2009 Weighted Average Remaining Contractual Life Number Exercisable as at 31 December 2009 Weighted Average Exercise Price (Cdn$) Exercise Price (Cdn$) 1.00 8.00 - 13.55 1,662 1,135 2,797 4.67 2.36 1,662 698 2,360 1.00 11.36 There were no new stock options issued during the year. A total charge of US$1.1 million has been recognised for the year in relation to the stock options. 2009 2008 Thousands of stock appreciation rights or Cdn$ Outstanding as at 1 January Granted (i) Granted (ii) Exercised (ii) SAR 810 – – – Exercise Price 8.0 to 13.55 – – – Outstanding as at 31 December 810 8.0 to 13.55 SAR 1,090 15 105 (400) 810 Exercise Price 4.00 to 13.55 5.30 11.05 4.00 8.0 to 13.55 (i) (ii) These stock appreciation rights have a term of 5 years and vest in three equal annual installments, the first third vesting on the anniversary of the grant date. There is no maximum liability associated with these rights. These stock appreciation rights have a liability of Cdn$3.00 per right or Cdn$0.3 million in total with a two year term. The stock appreciation rights exercised in 2008 also had a maximum liability of Cdn$3.0 per right or Cdn$1.2 million in total. 62 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 5 6 7 8 9 10 11 12 13 14 15 16 1 6 7 8 9 10 11 12 13 14 15 16 17 1 2 2 3 3 4 4 5 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 The Company records a charge to the income statement using the Black-Scholes fair valuation option pricing model every reporting period with a resulting liability being recognised in the balance sheet. In the valuation of these stock appreciation rights at the reporting date, the following assumptions have been made: the risk free rate of interest equal to 2.05%, stock volatility 104%, 0% dividend yield and a range of forfeiture from 0% to 33% and a closing stock price of Cdn$3.70 per share. As at 31 December 2009, a total liability of US$0.4 million (2008: US$0.2 million) has been recognised in relation to the stock appreciation rights. A total charge of US$0.2 million has been recorded during 2009. In April 2007, 0.2 million Class B shares were awarded to a newly appointed officer. These shares were held in escrow and vested to the officer in three equal installments starting 7 April 2007. The shares were fully vested by 7 April 2009 and a charge of US$0.1 million was recorded in 2009 (2008: US$0.6 million). 17 18 OTHER COMPONENTS OF EQUITY This is used to record two types of transactions: 19 20 21 22 23 (i) (ii) To recognise the fair value of equity settled stock based compensation expensed in the year. To account for the difference between the aggregated book value of the shares purchased under the normal course issuer bid and the actual consideration. 21 20 22 18 19 EARNINGS/(LOSS) PER SHARE The calculation of basic earnings/(loss) per share is based on the total comprehensive income/(loss) attributable to the owners of the parent company of US$3.3 million (2008: US$9.5 million loss) and a weighted average number of Class A and Class B shares outstanding during the period of 29,540,339 (2008: 29,614,423). 23 In computing the diluted earnings/(loss) per share, the dilutive effect of the stock options was 1,163,181 (2008: 1,425,253) shares. These are added to the weighted average number of common shares outstanding during the year resulting in a diluted weighted average number of Class A and Class B shares of 30,703,520 for the year ended 31 December, 2009. No adjustments were required to the reported earnings from operations in computing diluted per share amounts. 19 20 21 22 23 OPERATING LEASES The Company has two office rental agreements in Dar es Salaam, expiring on 30 November 2012 and 31 October 2013 at an annual rental of US$122,000 and US$110,000 per annum respectively. AS AT 31 dECEmBER (Figures in US$’000) Less than one year Between one and five years 2009 2008 232 546 778 204 714 918 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 63 1 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 1 Notes to the Consolidated Financial Statements 9 10 11 12 13 14 15 16 17 18 19 22 20 23 21 RELATED PARTY TRANSACTIONS One of the non executive Directors is a partner at a law firm. During the year, the Company incurred US$168,000 to this firm for services provided. The transactions with this related party were made at the exchange amount. 10 11 12 13 14 15 16 17 18 19 20 21 22 23 CONTRACTUAL OBLIGATIONS AND COMMITTED CAPITAL INVESTMENT Contractual Obligations Protected Gas Under the terms of the original gas agreement for the Songo Songo project (“Gas Agreement”), in the event that there is a shortfall/insufficiency 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 (34.2 Bcf as at 31 December 2009). The Gas Agreement has been amended by an initialled Amended and Restated Gas Agreement (“ARGA”). The ARGA provides clarification of the Protected Gas volumes and removes all terms dealing with the security of the Protected Gas and the consequences of any insufficiency to a new Insufficiency Agreement (“IA”). The IA specifies terms under which Songas may demand cash security in order to keep them whole in the event of a Protected Gas insufficiency. Once the Insufficiency Agreement is signed, it will govern the basis for determining security. Under the provisional terms of the IA, when it is calculated that funding is required, the Company shall fund an escrow account at a rate of US$2/Mmbtu on all industrial Additional Gas sales out of its and TPDC share of revenue, and TANESCO shall contribute the same amount on Additional Gas sales to the power sector. The funds provide security for Songas in the event of an insufficiency of Protected Gas. The Company is actively monitoring the reservoir and does not anticipate that a liability will occur in this respect. Back in TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development by contributing 20% of the costs of the future wells including SS-10 in return for a 20% increase in the profit share 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 and there may be the need for reserve modifications once these discussions are concluded. For the purpose of the reserves certification, it has been assumed that they will ‘back in’ for 20% for all future development and this is reflected in the Company’s net reserve position. However, the financial statements do not take account of any reimbursement for the SS-10 capital expenditure, pending the finalisation of the terms of the ‘back in’. Capital Commitments Re-rating of the Songas processing plant Orca Exploration is committed to pay Songas US$0.5 million for continuing to allow the gas processing plant to operate at a re-rated 90 MMcfd. This payment was made in March 2010. Funding Management forecasts that the Company will be able to meet its 2010 Tanzanian capital expenditure program through the use of existing cash balances and self-generated cash flows. The Company currently has no bank borrowings and there is scope for utilising debt funding once the longer term contracts for the supply of gas to the power sector are in place. New funding will be required for any future material acquisition. 64 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 22 23 SUBSEQUENT EVENTS In January 2010, the Company signed a Production Sharing Contract (“PSC”) in relation to an exploration licence. In the event that the PSC is ratified the Company will have exploration work commitments. In April 2010 an agreement was reached with a third party contractor, for breach of contract during the drilling of the SS-10 well in 2007. As a result a credit of US$1.1 million has been recognized in property, plant and equipment for the cancellation of invoices that had not been paid by the Company to the third party. 23 CONTINGENCY During the last quarter of the year, the Company received an invoice in relation to a claim made by the Ugandan tax authorities for withholding tax that was withheld by the operator during the seismic program pending clarification of the tax regime. There is a further potential claim for US$0.3 million for additional withholding tax. Whilst it is not considered probable that an additional payment will be made and as such no additional provision has been recognized, the Company cannot go so far as to say that the possibility is remote. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 DIRECTORS AND OFFICERS EMOLUMENTS USD’000 except for number of share options, stock appreciation rights and treasury stock Year Base Bonus Total Outstanding Stock appreciation rights Stock options Treasury stock Directors W. David Lyons (i) Chairman and CEO Peter R. Clutterbuck (i) Deputy Chairman Nigel A. Friend (i) Vice President, Executive Officer and CFO James Smith (i) Vice President Exploration Pierre Raillard Vice President Operations David W. Ross Non Executive Director John Patterson (i) Non Executive Director 2009 2008 2009 2008 2009 2008 2009 2008 2009 2008 2009 2008 2009 2008 15 15 360 393 275 353 253 408 397 359 – – 63 67 – – 118 135 80 95 73 92 76 125 – – – – 15 15 478 528 1,000,000 1,000,000 490,000 490,000 – – – – 355 265,000 90,000 448 326 500 473 484 – – 63 67 265,000 300,000 300,000 325,000 325,000 75,000 75,000 125,000 125,000 90,000 300,000 300,000 – – – – – – – – – – – – – 66,667 – – – – – – (i) The ‘Base compensation’ for W.D. Lyons, P.R. Clutterbuck, N. Friend, J. Smith, and J. Patterson are in respect of consultancy fees. O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 65 Notes to the Consolidated Financial Statements FORWARD LOOKING STATEMENTS This disclosure contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Orca Exploration’s control, including the impact of general economic conditions in the areas in which Orca Exploration operates, civil unrest, industry conditions, changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced, increased competition, the lack of availability of qualified personnel or management, fluctuations in commodity prices, foreign exchange or interest rates, stock market volatility and obtaining required approvals of regulatory authorities. In addition there are risks and uncertainties associated with oil and gas operations, therefore Orca Exploration’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking estimates and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking estimates will transpire or occur, or if any of them do so, what benefits, including the amounts of proceeds, that Orca Exploration will derive therefrom. For further information please contact: Nigel A. Friend, CFO +255 (0)22 2138737 nfriend@orcaexploration.com or visit the Company’s web site at www.orcaexploration.com. 66 O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t Corporate Information BOARD OF DIRECTORS W. David Lyons Chairman and Chief Executive Officer Winchester United Kingdom Peter R. Clutterbuck Nigel A. Friend Pierre Raillard Deputy Chairman Haslemere United Kingdom Executive Vice President and Chief Financial Officer London United Kingdom Vice President Operations Dar es Salaam Tanzania John Patterson Non-Executive Director David Ross Non-Executive Director James Smith Vice President Exploration Nanoose Bay Canada Calgary Canada Hurst United Kingdom OPERATING OFFICE REGISTERED OFFICE INVESTOR RELATIONS ORCA EXPLORATION GROUP INC. ORCA EXPLORATION GROUP INC. P.O. Box 3152 Road Town Tortola 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 Executive Vice President and Chief Financial Officer Tel: + 255 22 2138737 nfriend@orcaexploration.com British Virgin Islands www.orcaexploration.com INTERNATIONAL SUBSIDIARIES PANAFRICAN ENERGY TANZANIA LIMITED PAE PANAFRICAN ENERGY CORPORATION Barclays House, 5th Floor 1st Floor Ohio Street, P.O. Box 80139 Cnr St George/Chazal Streets Dar es Salaam Tanzania Port Louis Mauritius Tel: + 255 22 2138737 Tel: + 230 207 8888 Fax: + 255 22 2138938 Fax: + 230 207 8833 ORCA EXPLORATION (VENTURES) INC. ORCA EXPLORATION UGANDA (HOLDING) INC. ORCA EXPLORATION UGANDA INC P.O. Box 3152, Road Town Tortola British Virgin Islands AUDITORS McDaniel & Associates ENGINEERING CONSULTANTS Is est, iniminv endenesed et quunt ex estotatio. Loria siti volorro voluptus ant.Usam dolorem. Icia sinte nulluptat. Calgary, Canada Calgary, Canada Calgary, Canada Burnet, Duckworth & Palmer LLP KPMG LLP LAWYERS TRANSFER AGENT CIBC Mellon Trust Company Toronto & Montreal, Canada O r c a E x p l o r a t i o n G r o u p I n c . | 2 0 0 9 A n n u a l R e p o r t 67 Flare Addtional Gas Sales Protected Gas Sales w w w . o r c a e x p l o r a t i o n . c o m Production Volumes