Orchid Island Capital
Annual Report 2011

Plain-text annual report

2011 ANNUAL REPORT O R C A E X P L O R A T O N G R O U P I I N C . HIGH VALUE SUSTAINABLE GROWTH T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O ORCA EXPLORATION GROUP INC. is an international public company engaged in hydrocarbon exploration, development and supply of gas in Tanzania and oil appraisal and gas exploration in Italy. 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 . . . . . . . . . . . . 3 OPERATIONS REVIEW . . . . . . 9 MANAGEMENT’S DISCUSSION & ANALYSIS . . . . . . 31 MANAGEMENT’S REPORT TO SHAREHOLDERS . . . . . . 60 AUDITORS’ REPORT . . . . . . 61 CONSOLIDATED FINANCIAL STATEMENTS . . . . . . 62 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS . . . . . 66 CORPORATE INFORMATION . . . . . . 85 mcf Thousands of standard cubic feet MMcf Millions of standard cubic feet MMcfd Millions of Mmbtu Millions of standard cubic feet per day 1P Proven reserves British thermal units 2P Proven and probable reserves Bcf Billions of standard cubic feet HHV High heat value Tcf Trillions of standard cubic feet LHV Low heat value 3P (i) Proven, probable and possible reserves GIIP Gas initially in place Kwh Kilowatt hour MW Megawatt US$ US dollars Cdn$ Canadian dollars Bar Fifteen pounds per square inch MMbbl Million barrels of oil £ Euro (i) 3P Possible reserves are those additional reserves that are less certain to be recovered than probable resources. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. I F I N A N C A L A N D O P E R A T N G H G H L I G H T S I I FINANCIAL AND OPERATING HIGHLIGHTS Year ended/As at 31 December 2011 2010 Change Financial (US$000 except where otherwise stated) Revenue Profit before taxation Operating netback (US$/mcf) Cash and cash equivalents Working capital Shareholders’ equity Earnings per share - basic (US$) Earnings per share - diluted (US$) Funds flow from operating activities Funds per share from operating activities - basic (US$) Funds per share from operating activities - diluted (US$) 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 (MMcfd) - industrial Additional Gas sold (MMcfd) - power Average price per mcf (US$) - industrial Average price per mcf (US$) - power Additional Gas Gross Recoverable Reserves to end of licence (Bcf) Proved Probable Proved plus probable Proved plus probable plus possible Present Value, discounted at 10% (US$ million) Proved Proved plus probable Proved plus probable plus possible 45,893 15,320 2.05 34,680 56,006 106,659 0.23 0.22 38,808 16,512 2.29 45,519 52,364 98,183 0.33 0.31 22,658 20,836 0.65 0.63 4,577 0.13 0.13 1,751 32,849 3,057 2,742 14,722 7.5 40.3 10.05 2.77 469 79 548 844 328 351 412 0.68 0.65 15,534 0.50 0.49 1,751 32,939 2,557 2,504 10,940 6.9 30.0 8.76 2.60 369 82 451 822 236 278 395 18% (7%) (10%) (24%) 7% 9% (30%) (29%) 9% (4%) (3%) (71%) (74%) (74%) 0% 0% 20% 10% 35% 9% 34% 15% 7% 27% (4%) 22% 3% 39% 26% 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 1 1 A N N U A L R E P O R T 1 2 . C N I P U O R G N O I T A R O L P X E A C R O T R O P E R HIGHLIGHTS L A U N N A 1 1 0 2 • • • • • • • • • • • • Increased proven reserves by 27% to 469 Bcf (2010: 369 Bcf) and proven and probable reserves by 22% to 548 Bcf (2010: 451 Bcf). Increased sales of Additional Gas by 30% to 17.5 Bcf or 47.8 MMcfd (2010: 13.4 Bcf or 36.9 MMcfd). This resulted in operating revenue of US$46.4 million. Increased funds from operations before working capital changes by 9% to US$22.7 million (2010: US$20.8 million) despite brought forward costs being fully recovered in the year. Increased working capital by 7% to US$56.0 million (2010: US$52.4 million). Agreed with the Government of Tanzania to increase deliverability from the Songo Songo field to 200 MMcfd in parallel with their investment in gas processing and pipeline infrastructure. Planned the drilling of two development wells in Tanzania in 2012 (SS-11 and SS-12). SS-11 was spud in February 2012 using the Sakson rig PR5 and SS-12 may be drilled once this has been completed. Held discussions with KCA Deutag to utilise their Ben Avon jack up rig for the drilling of the 551 Bcf (mean un-risked resource) exploration prospect, Songo Songo West, in Q4 2012. The rig is expected to be mobilised to Mozambique by another operator in Q3 2012. Signed a Re-rating Agreement with Songas and the electricity utility, TANESCO, that enabled the gas processing capacity to be increased from 90 MMcfd to 110 MMcfd. As a consequence, the overall infrastructure capacity increased to 102 MMcfd (limited by the pipeline diameter). Signed a Portfolio Gas Sales Agreement (PGSA) with TANESCO for the supply of a maximum of 37 MMcfd through to approximately 2023. Since June 2011, 217 MWs of new gas fired generation has been commissioned in Tanzania. There is now 406 MWs of gas fired generation that is dependent on the Company’s gas. Sales volumes are expected to increase in 2012 subject to the infrastructure limitations. Commenced the evaluation of the viability of selling liquid natural gas in Tanzania. Continued to plan for the drilling of the La Tosca well in the Longastrino exploration block in the Po Valley, northern Italy (operated by Northern Petroleum Plc). Under the terms of the farm in agreement, Orca will earn between 70% and 75% of the block in return for financing the drilling and the testing of the well up to predefined caps. The well is expected to be spud in Q3 2012. In 2011Orca celebrated an important milestone – the 10th anniversary of the Company’s role in bringing the Songo Songo gas field into production. Today Orca holds a unique position in the most prolific gas basin in East Africa. It is the operator of Tanzania’s first natural gas development and the largest supplier of natural gas helping to address Tanzania’s urgent power needs. Together with the Tanzania Petroleum Development Corporation (TPDC), Songas Limited, the Ministry of Energy and others, Orca is playing a signifi- cant role in developing and producing the Songo Songo reserves. The Songo Songo project is one of the most successful gas-to-energy projects in Africa and Orca is proud to be playing its part in it. Looking to the immediate future the Company is fully committed to the successful execution of its US$130 million Songo Songo exploration and development programme. To bring more gas for power generation as quickly as possible, Orca is working closely with the Government of Tanzania and other stakeholders to increase Songo Songo gas field production. In November 2011, Orca and the Government of Tanzania agreed an accelerated work programme to increase production from the Songo Songo gas field from 100 MMcfd to 200 MMcfd. The following month Orca took delivery of the Sakson PR5 drilling rig on Songo Songo Island. The Sakson rig is currently drilling the SS-11 develop- ment well which was spud in early February 2012 and, subject to funding, may drill a second development well (SS-12) once the first well is completed. CHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS Orca is working closely with the Government of Tanzania and other stakeholders to increase Songo Songo production. INCREASED REVENUES Revenue grew by 18% to US$45.9 million in 2011 (2010: US$38.8 million). The 2011 revenue increase was limited by the fact that brought forward costs had been fully recovered in the first half of 2011. This reduced the percentage of net revenue allocated between the Government and the Company from 75% in 2010 to 52% in 2011. Orca’s total cost recovery share will rise in 2012 as a result of funds invested by Orca in the current drilling programme. Funds from operations before working capital changes increased by 9% to US$22.7 million and the level of working capital grew from US$52.4 million to US$56.0 million. The Company finished the year with cash of US$34.7 million and no debt. The revenue growth was fuelled by Additional Gas sales of 47.8 MMcfd in 2011 which were made possible by an infrastructure system re-rating. In June 2011 infrastructure capacity was increased from 90 MMcfd to 102 MMcfd. Additional Gas sales are expected to remain strong through 2012. With the introduction of the new 105 MW Jacobsen power plant at Dar es Salaam in April 2012, there is now significantly more gas demand downstream than can be supplied through the existing infrastruc- ture system. I O L E P T E T R E A R T T O O N T S H R E E S P H O A R R T E H O L D E R S 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 1 1 A N N U A L R E P O R T 3 Orca has an excellent gas reservoir in the Songo Songo field that continues to perform above expectations. 4 CHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O FOCUSED ON INCREASING PRODUCTION Orca’s 2011 operations focus has been on maintaining the highest level of gas production possible within the current infrastructure limits. In June 2011 those limits were raised following the signing of a Re-rating Agreement with Songas Limited and the electricity utility, TANESCO. The Agreement enabled the Songo Songo gas processing capacity to be increased from 90 MMcfd to 110 MMcfd. However gas processing and pipeline capacity remains a restriction. To address this need the Government of Tanzania announced in September 2011 that it was in the final stages of negotiat- ing a 20-year term financing arrange- ment with the Chinese Exim Bank for the construction of a new gas processing plant on Songo Songo Island and an oversized onshore pipeline to accommodate future growth in gas production. This is expected to initially increase the Songo Songo infrastructure capacity to 200 MMcfd. Subsequent incre- mental investments in gas process- ing capacity and the construction of a new offshore pipeline to Songo Songo could increase gas deliverabil- ity. The target for project completion is currently the end of 2013. A GROWING RESERVE BASE Orca has an excellent gas reservoir in the Songo Songo field that continues to perform above expectations. As at 31 December 2011, the independent reserve evaluator McDaniel and Associates Consultants Ltd. (“McDaniel”) assessed that the Additional Gas gross proven (1P) and proven and probable (2P) Songo Songo reserves available to Orca to the end of the licence period are 469 Bcf (2010: 369 Bcf) and 548 Bcf (2010: 451 Bcf) respectively. These significant increases were recorded despite Additional Gas production of 17.5 Bcf during the year. In 2011 the Company re-evaluated the depth conversion techniques for the entire field and as a result the part of the field known as Songo Songo North (where the first well (SS-1) was drilled in 1974 by AGIP) is now believed to be larger than previously thought. SS-1 penetrated 1,200 metres of Neocomian sands and tested gas in the upper section, but the well was plugged and abandoned. Management recognises the importance of Songo Songo North for future reserves growth. A VIGOROUS EXPLORATION AND DEVELOPMENT AGENDA Development plans put in place in 2011 will be a major focus of the Company in 2012. The goal is to increase deliverability from the main field to 200 MMcfd in parallel with the infrastructure expansions being planned in country. To do this Orca is currently drilling the new SS-11 well. A second development well, SS-12, may be drilled using the same rig. Currently, the Company can produce approximately 113 MMcfd from the Songo Songo field though this is currently restricted by the capacity of the infrastructure to a maximum of 102 MMcfd. However, SS-9 (currently producing in the region of 30 MMcfd), will have to be taken out of production at the end of May 2012. The Company will perform a corrosion log and pressure test the annulus/casing to assess whether SS-9 can continue in production after the end of May 2012. In the event that SS-9 is taken off produc- tion there may be a period where the Company can only deliver ap- proximately 80 MMcfd until SS-11 is connected to the gas processing plant later in 2012. Orca is moving ahead vigorously with plans for the drilling of the Songo Songo West exploration prospect. The Company is in discus- sion with KCA Deutag to secure the Ben Avon jack-up rig to drill the well. The Ben Avon rig is being mobilised to Mozambique in Q3 2012 for a one well program and Orca is looking to mobilise the rig to Tanzania to drill Songo Songo West. The location is highly prospective and McDaniel has evaluated this prospect and assessed it to contain un-risked mean resources of 551 Bcf with an upside case in excess of 1 Tcf. The exploration and develop- ment programme is dependent on adequate funds being available. This is discussed below. SUSTAINED GAS MARKET GROWTH Sales of Additional Gas to the power sector increased by 34% during 2011 to 40.3 MMcfd (2010: 30.0 MMcfd), mainly as a result of the increase in the capacity of the gas infrastructure that enabled latent power demand to be met. The total gas fired generation in Tanzania, consuming Additional Gas, is currently 406 MWs having increased since June 2011 with the re-commis- sioning of the Symbion 112 MW plant and the recent start up of the 105 MW Jacobsen plant. At maximum capacity the power sector can utilise 90 MMcfd of Additional Gas. During 2011 Orca maintained service to existing customers but did not expand industrial sales. The priority was to ensure that gas was available to meet power sector needs at a time of crippling electric- ity shortages. This will continue until the gas infrastructure capacity is increased. I O L E P T E T R E A R T T O O N T S H R E E S P H O A R R T E H O L D E R S 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 1 1 A N N U A L R E P O R T 5 6 CHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O In Italy we are moving forward with a land- based exploration program in the Po Valley region of northern Italy. When new allocations of Addi- tional Gas can be made available for market expansion there is a significant untapped market to be developed. A number of the existing customers wish to establish a reliable electricity supply through the de- velopment of their own small scale generation capacity. There are also a number of other industries and hotels that are anxious to sign gas purchase contracts. The Company will be ready to expand the low pressure pipeline system and the capacity of the compressed natural gas (CNG) infrastructure to meet this demand when it can deliver more gas to Dar es Salaam. In addition, Orca is assessing the economic and logistical viability of using a small scale liquid natural gas (LNG) plant to provide gas to the mines around Lake Victoria. These are high margin opportunities that are particularly attractive. ITALIAN ONSHORE EXPLORATION In Italy we are moving forward with a land-based exploration programme. The drilling of the La Tosca farm-in well is scheduled to spud in Q3 2012. Northern Petroleum, as operator, will drill the well in the Longastrino Block in the Po Valley region of northern Italy. Under the terms of the farm-in agreement, Orca will pay 100% of the costs of the La Tosca 1 well up to €4.3 million and 70% thereafter for the drilling phase, together with back-in costs of €0.6 million to earn a 70% interest in the block. If the well is tested and completed, Orca will earn an additional 5% (taking it to 75%) by paying 100% of the testing costs up to €1.3 million and 75% thereafter. There are a number of other prospects on the Longastrino block that will be evaluated following the finalisation of the drilling of the La Tosca well. Offshore Italy Orca’s participation in a low risk, high potential appraisal well in the Adriatic remains on hold. However, it is assessed that this could be lifted during 2012. Orca has a farm-in agreement with Petroceltic International Plc to participate in the drilling of the well once the Italian Ministry of Envi- ronment issues a decree of environ- mental compatibility for the drilling programme. The area has significant oil exploration upside and as part of the farm-in Orca would earn the right to participate in 11 adjacent exploration blocks in the Central Adriatic. Orca is not liable for any costs associated with the drilling of Elsa-2 until a rig contract is signed. EXPANSION FINANCING The pace and extent of the Company’s 2012 work programme will be dependent on the availability of sufficient capital. The planned 2012 programme includes the drilling of two development wells (SS-11 and SS-12 on Songo Songo Island) and two exploration wells (Songo Songo West and La Tosca in Italy). The drilling of SS-12 is dependent on the immediate receipt of out- standing overdue payments of approximately US$20 million from TANESCO, the securing of a US$10 million overdraft facility and satis- factory progress by the Tanzanian Government on the infrastructure expansion. The drilling of Songo Songo West will, in addition, be dependent on the completion of a debt facility that is currently under discussion. This financing will be dependent on the satisfactory outcome of discussions with the Government Negotiation Team (‘GNT’) that was set up in February 2012 to address a number of issues raised by the Parliamentary Committee for Energy and Minerals Your management team is positive about Orca’s prospects in both Tanzania and Italy. in respect of the Company’s Production Sharing Agreement. This includes, but is not limited to, TPDC back in rights, profit sharing arrangements, the unbundling of the downstream assets, cost recovery and Orca’s management of the upstream operations. Orca will discuss these matters in good faith with the GNT which may lead to material changes in the economic terms of the PSA. However the Company reserves its rights to defend its position should no satis- factory agreement be reached. The Board may decide to defer the drilling of SS-12 and/or Songo Songo West if there has not been satisfactory resolution of any of the conditions outlined above. I O L E P T E T R E A R T T O O N T S H R E E S P H O A R R T E H O L D E R S 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 1 1 A N N U A L R E P O R T 7 8 CHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O MANAGEMENT CHANGES Beer van Straten has been named Chief Operating Officer replacing Dale Rollins who resigned in March 2012. Mr. van Straten is responsible for the Company’s field operations including the large scale develop- ment and exploration drilling program in Tanzania. He is a senior oil and gas industry executive with over 20 years high level exploration, production and commercial experience in the North Sea, Middle East and Africa. Mr. van Straten has been associated with Orca since June 2010 when he was elected to Orca’s Board of Directors. Prior to his work with Orca he managed an aggressive five-rig programme in Egypt that doubled Dana Gas’ reserves and raised production by 50%. PIVOTAL YEAR 2012 is a pivotal year for Orca. The Company is moving forward vigorously to increase gas production from Songo Songo Island and is working closely with the Government of Tanzania and other Songo Songo stakeholders to meet this need. Orca has already taken the first steps in the US$130 million expansion program it announced last November. The drilling of the first development well is nearing completion on Songo Songo Island and negotiations are proceeding to have a jack-up rig available for the drilling of Songo Songo West later this year. The drilling of Orca’s farm-in well in Italy will begin in Q3 2012. The Company is negotiating with the GNT in good faith. We are concerned about the allegations that have been made with respect to the sharing of Songo Songo revenues and are approaching the review in a spirit of transparency and full cooperation. Orca is proud of the role it is playing in Tanzania to develop the country’s natural gas resources and make them available for the power and industrial sectors to the ultimate benefit of all Tanzanians. We are also proud of the role the Company is playing in creating quality employment and giving back to communities through corporate educational and health initiatives. We are working hard to expand Orca’s reserve base, increase value for all stakeholders and build greater sustainable value. There is significant upside potential. With the continued support of our loyal shareholders, the strength of our Board, the experience of our management team and the skills of our dedicated employees, we look forward to a year of growth. W. David Lyons President and CEO April 25, 2012 OPERATIONS REPORT I O P E R A T O N S R E P O R T 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 1 1 A N N U A L R E P O R T 9 10 A HISTORY OF WORKING TOGETHER For the past ten years, Orca Exploration Group has played an important role in Tanzania’s shift from costly imported fuel oil to domestic natural gas. T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O Discovered in 1974 by AGIP, Tanzania’s Songo Songo gas field lease was acquired by an Orca predecessor company in 1991. Years of financial and operations planning followed. By 2001 a consortium to build the transportation infrastructure had been formed and financing secured. In July 2004 the first delivery of natural gas flowed from Songo Songo to Dar es Salaam. For Tanzania the development of Songo Songo gas has come at a very opportune time. Seasonal droughts have severely impacted the country’s ability to rely on power from hydro. At the same time demand for electricity has continued to grow every year. To meet this growing demand, Tanzania had originally introduced power generated by imported fuel oil in the 1980s. By the early 1990s oil prices and price volatility were rising. Even new thermal power plants at Dar es Salaam couldn’t close the power gap between demand and supply. Power shortages were impacting both Tanzania’s national power grid and the growing industrial base in the Dar es Salaam area. To create a long term sustainable solution Orca worked closely with the Government of Tanzania, Tanzania Petroleum Development Corporation, TANESCO, the Songas consortium and the World Bank. By the end of 2002 construction of gas processing facilities and a pipeline system was underway on Songo Songo Island. While the Songas-owned gas processing plant was being constructed on Songo Songo Island, Orca made sure the Songo Songo gas wells would be production ready when the time came. With contracts 1974 1974 The Songo Songo gas field was discovered by AGIP. 1997 A five well servicing program was completed at Songo Songo Island. 1999 Government of Tanzania approves the Songas Project. 2001 Songas Project achieves financial closure. 2003 Tanzanian workforce hired and trained to operate Songo Songo gas plant. to supply gas for power generation in place, Orca constructed a low pressure pipeline to sell Additional Gas from Songo Songo to Dar es Salaam industrial customers. The first two customers for the Additional Gas were Kioo Glass and Tanzanian Breweries and they were quickly followed early in 2005 by four more industrial customers. Orca was able to sell the gas to industrial customers at 20-25% less than the price of heavy fuel oil providing serious motivation for more customers to make the switch to natural gas. Today Orca serves 38 industrial customers. With gas production from the Songo Songo gas field flowing to Dar es Salaam a new level of Tanzanian energy self-sufficiency is being achieved. For the first time Tanzania has been able to use its domestic hydrocarbon resources to fuel power generators at the Ubungo plant. By 2006 an additional development program was underway to meet TANESCO’s need for more gas for power generation. Orca was contracted to sell Additional Gas to fuel 144 MWs of short term, emergency power generation at Dar es Salaam. By the 2007 rainy season the reservoirs were filled and increased hydro power generation was again possible for several months. With full reservoirs, the pressure for rapid expansion of Songo Songo was reduced. The Mtera dam which supplies water to the 80 MW Mtera and the 204 MW Kidatu hydro stations rose from a non-operational level of 687 meters above sea level to its maximum capacity of 698 meters. As a result, it was anticipated that these hydro units would have sufficient water to run at high utilisation rates during 2007 and 2008. This provided an opportunity for Orca to plan a 16-kilometer expansion of its 28-kilometer distribution system for 2007 at an investment by Orca of US$4.5 million. With the Government projecting power demand of up to 68 MMcfd at peak load Orca’s ability to meet the needs of both the power and industrial sectors was assured. During 2008 Songo Songo production had reached the physical limits of the Songas gas processing plant. Production was held to a maximum of 70 MMcfd. Committed to find ways to increase production to meet the needs of the power sector, Orca financed studies that demonstrated that the existing infrastructure could be re-rated to 90 MMcfd. Responding to these studies, Songas approved the installation of two new valves to allow the gas plant to be recertified to 90 MMcfd. 2004 Songo Songo in operation and first shipment of gas was received at Ubungo. 2005 2006 Orca (EastCoast Energy) launches exploration program to find more gas. Marine seismic program identifies Songo Songo West drilling prospect. Drought increases demand for gas-fired generation at Dar es Salaam. Orca expands service to industrial customers with 25 kilometer pipeline. I O P E R A T O N S R E P O R T 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 1 1 A N N U A L R E P O R T 11 12 T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O In early 2009, with the new valves installed, Orca received approval to operate the gas processing plant at the 90 MMcfd level increasing gas supply for urgently needed power generation. At the same time Orca invested US$2.5 million to construct CNG (Compressed Natural Gas) facilities in Dar es Salaam. The facilities consist of a “mother station” and three “daughter” stations for the supply of natural gas to industries and hotels as well as to be available as a fuel for trucks and buses. Committed to continue to increase Songo Songo reserves and availability of natural gas, Orca proposed a new long term expansion of Songo Songo. The studies showed that with two new processing trains and added pipeline compression production could be increased to 144 MMcfd. By twinning the onshore pipeline to Dar es Salaam production could be further increased to over 200 MMcfd. Internationally, the Songo Songo project was being well received. A World Bank study reported that “the Songo Songo project (has) performed well during it first six years of operation. The project had also stimulated gas markets: 35 local industries were connected for gas, replacing the use of heavy fuel oil and other types of petroleum fuels… It has been estimated that 1.8 million and 0.73 million tons of CO2 were reduced from power generation and local industries respectively since 2004 and up to December 2010.” The Songo Songo project was also credited by the World Bank with bringing additional social benefits to Tanzania. The World Bank reported that “Because of the relationship between power supply, economic development and poverty alleviation, the project intended to contribute to a reduction of poverty by unlocking an important and genuine new source for power generation. While the power cuts that occurred during various generation shortage crises had an impact on the country’s economic growth, those negative impacts would have been even larger without the project’s implementation. It is therefore likely that the project’s main component positively contributed to poverty alleviation.” During this entire period the Songo Songo gas reservoir continued to perform above expectations. To ensure future gas supply, Orca completed a workover of its SS-9 well in 2007 and committed to drill a new SS-10 well to further increase production. The timing of these upgrades by Orca proved to be very important. By mid-2011 gas supply for power generation had become of utmost importance to Tanzania. Providing more than 70% of fuel required for the national grid, Songo Songo gas presented an opportunity to further increase power generation and reduce load shedding. An infrastructure expansion is expected to proceed in 2012 and be completed by the end of 2013. Orca is fully committed to be able to supply the gas volumes that will be needed to fill the system. The ADVANCING NATURAL GAS DEVELOPMENT 2007 Orca drills first new Songo Songo well in 25 years. Orca US$4.5million expansion programme increases natural gas service to more industries. 2008 Long-term power contracts negotiated with TANESCO. 2009 Orca constructs new pressure reduction station to serve Wazo Hill. Orca completes construction of CNG facilities at Dar es Salaam. Company has signed a Portfolio Gas Supply Agreement (PGSA), jointly with TDPC to supply gas to TANESCO. At the same time Orca is continuing to expand corporate social responsibility programmes on Songo Songo Island. Focusing on education and health, the programs are delivered through Orca’s subsidiary PanAfrican Energy Tanzania. PanAfrican ensures that the Company’s activities meet environmental regulations and contribute to sustainable outcomes for both the Company and the Songo Songo Island community. PanAfrican is also committed to improving the quality of life of the island residents. For the past several years, PanAfrican has been developing and rolling out health and education programmes. The Company has assisted in upgrading the local elementary school facilities and providing much needed educational materials and equipment. Currently, PanAfrican is supporting the kindergarten, which is providing early learning facilities for children aged between 3 and 6 years. In addition, students are provided with meals and health check-ups. The Company has also recruited a professional instructor for the learning centre, to provide English language instruction, computer training and entrepreneurship skills to young adults on the island. In order to increase local education in a sustainable manner, PanAfrican is also sponsoring three teachers to attend Teacher Training College in Dar es Salaam. To meet the need for increased educational opportunities at the high school level, the Company is also sponsoring ten students from the island to attend Secondary School in Dar es Salaam. PanAfrican staff are actively involved – donating personal time to assist in the children’s clinic, where they provide community training in maternal healthcare, HIV awareness, nutrition and vaccination. 2010 2011 Orca funds study to increase Songo Songo production to at least 140 MMcfd. Orca increases aid to Songo Songo schools and provides scholarships. Orca announces US$130 million expansion program to increase gas production. Tanzania announces plan for 532 kilometer coastal pipeline. 2012 Orca begins drilling new Songo Songo well (SS-11) to increase gas production. 2012 I O P E R A T O N S R E P O R T 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 1 1 A N N U A L R E P O R T 13 14 OPERATIONS REPORT T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 35,000 30,000 25,000 20,000 f c M M 15,000 10,000 5,000 0 d f c M M 105 95 85 75 65 55 45 35 25 Production Volumes Protected Gas sales Additional Gas sales Flare, generator at the processing plant and line pack GAS PRODUCTION & SALES 2004 2005 2006 2007 2008 2009 2010 2011 During 2011, 30.7 Bcf (2010: 27.9 Bcf) of natural gas was produced from the Songo Songo field offshore Tanzania or an average of 84.1 MMcfd (2010: 76.4 MMcfd). This brings total production since commercial operations commenced on 20 July 2004 to 159 Bcf. The increase in production during the course of the year has mainly been the consequence of increased demand from the power sector. Average daily production per month PROTECTED GAS SALES Under the terms of a Gas Agreement signed in 2001, the Protected Gas from Songo Songo is 100% owned by the Tanzanian Petroleum Development Cor- poration (“TPDC”) and is sold to Songas under a 20 year Gas Agreement for: 1. The operation of five turbines at the Ubungo power plant; 2. Onward sale to the Tanzanian Portland Cement Company (“TPCC”) for the operation of its cement kilns; and 3. Village electrification (at a rate not to exceed 1 MMcfd). The Protected Gas was allocated as follows: 2010 2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2011 2010 Protected Gas consumed Utilisation rate Protected Gas consumed Utilisation rate Year ended 31 December Bcf MMcfd % Bcf MMcfd % Additional Gas Volumes Protected Gas user 20000 Ubungo power plant 18000 Industrial Sales Wazo Hill cement plant 16000 Power Sales Village electrification programme 14000 12000 Total consumption 10000 8000 6000 4000 2000 0 2004 2005 2006 2007 2008 2009 2010 2011 f c M M 11.4 1.8 – 13.2 31.4 4.9 – 36.3 82% 83% – 80% 12.4 1.8 – 14.2 34.0 4.9 – 38.9 89% 84% – 86% Protected Gas utilisation decreased at the Ubungo power plant to 82% during 2011 due to TANESCO utilizing other new gas fired plants for its electricity generation therefore reducing the demand for Protected Gas at the Ubungo power plant. The Wazo Hill cement plant utilization reduced to 83% during 2011(2010: 84%) as a consequence of the impact of electricity shortages that hindered production. No gas was consumed during 2011 on the village electrification program. GAS PRODUCTION The maximum gas required for the Protected Gas users over the remaining 12 years and seven months of the Gas Agreement was 207 Bcf as at 31 December 2011. For the purposes of calculating the level of gas available as Addition- al Gas, an assumption has to be made as to the expected utilisation of the f c M Protected Gas over the remaining term of the Gas Agreement. These assump- M tions are reviewed on an annual basis based on historic and projected usage. The Protected Gas users and their forecast maximum and most likely demand are as follows: Production Volumes Protected Gas sales Additional Gas sales Flare, generator at the processing plant and line pack 35,000 30,000 25,000 20,000 15,000 10,000 5,000 Theoretical maximum maximum 100% load factor 0 2004 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) 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 83% over the remaining term of the Gas Agreement. This compares with an actual utilisation rate of 80% in 2011. The actual Protected Gas utilisa- tion at the Ubungo power plant primarily depends on the availability of the Ubungo power units. ADDITIONAL GAS SALES 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. f c M M MMcfd 47.4 (9.2) 105 38.2 5.9 1.0 d f c 45.1 M M 207 Most likely 2005 2007 2006 MMcfd 2008 2009 2011 2010 2011 MMcfd 39.8 39.0 Average daily production per month (7.6) (7.8) 95 85 75 65 55 45 35 25 32.0 4.2 1.0 37.2 171 31.4 4.9 – 36.3 2010 2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Additional Gas Volumes Industrial Sales Power Sales 2004 2005 2006 2007 2008 2009 2010 2011 20000 18000 16000 14000 12000 10000 8000 6000 4000 2000 0 I O P E R A T O N S R E P O R T 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 1 1 A N N U A L R E P O R T 15 16 OPERATIONS REPORT T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O Power Sector With the recent gas discoveries offshore by BG plc and Statoil that are estimated to be in excess of 10 Tcf, the Government of Tanzania has been able to plan their future energy requirements around having plentiful indigenous gas capacity. The principal benefactor of this is the power sector. Sales to the power sector averaged 40.3 MMcfd in 2011 (2010: 30.0 MMcfd). The increase is primarily the result of the: • • Introduction of 112 MWs of new gas fired generation in June 2011 to coincide with the re-rating of the infrastructure capacity; and Failure of the hydro capacity in country due to lack of rains in the catchment areas. The following lists the capacity of the gas fired generation capable of consuming Additional Gas as at 31 December 2011 together with the expected growth in generation by 30 June 2012. DEMAND BY THE POWER SECTOR Status Operational Operational Operational Operational (gas & jet fuel) Total as at 31 December 2011 Power Plant Ubungo power plant (Unit 6) TANESCO at Ubungo Tegeta Symbion Commissioned in April 2012 Jacobsen at Ubungo Total potential as at 30 June 2012 Installed capacity MWs 42 102 45 112 301 105 406 Furture contracted power demand The supply of Additional Gas to the power sector is currently governed by the initialed Amended and Restated Gas Agreement (“ARGA”) and the signed 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 escalat- ing 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, Tegeta 45 MW and the Symbion 112 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 PGSA the maximum daily quantity (“MDQ”) that the Company is obligated to supply is approximately 37 MMcfd. Currently the Company is selling at much higher volumes than this. Growth in electricity demand and the potential for further gas fired generation As at 31 December 2011, there was approximately 1,144 MWs of installed power generation in Tanzania. Given that the popu- lation of Tanzania is approximately 40 million, this represents a very low electricity demand per capita. In the last few years there has been a rebalancing of power gen- eration mix in Tanzania resulting in hydro generation account- ing 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. There are still significant black outs in Tanzania as a result of insufficient electricity generation and issues with transmission. It is envisaged that once the infrastructure constraints are removed, nearly all the Songo Songo reserves could be absorbed by a growing electricity sector. I O P E R A T O N S R E P O R T 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 1 1 A N N U A L R E P O R T 17 18 OPERATIONS REPORT T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O INDUSTRIAL SALES Piped natural gas Sales to the industrial sector averaged approximately 7.5 MMcfd in 2011 (2010: 6.9 MMcfd). There is currently limited opportunity to connect any new material customers (due to the demands of the power sector) and therefore growth in the short term will primarily be driven by organic growth from within the existing customer base. There remains the potential for good growth from indus- tries in the future. In particular our industrial customers are increasingly looking at ways of generating their own power. Compressed Natural Gas (CNG) The Company currently has a compressor, a vehicle dispenser and three daughter stations. Through the CNG facilities, the Company sold 94 MMcf in 2011 (2010: 38 MMcf). is expected to grow The CNG market 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 sig- nificant capital after this time, but the price realised for the CNG will be reduced. INFRASTRUCTURE Since 2004 the Company has constructed over 50 kilometers of low pressure pipeline in Dar es Salaam connecting 36 industrial customers. The sales of gas from the Songo Songo field is currently being restricted by the capacity of the infrastructure that processes and transports the gas 232 kilometers from the field on Songo Songo Island to Dar es Salaam. During 2011, the Company signed a Re-rating Agreement with the owners of the infrastructure, Songas Limited and the electricity utility, TANESCO to increase the gas processing capacity from 90 MMcfd to 110 MMcfd. This increased the overall capacity of the system to 102 MMcfd with the pipeline diameter being the bottleneck. There are a number of initiatives being evaluated to increase the capacity: • Songas has received a tariff methodology order from the regulator EWURA in respect of its expansion project. This project will increase the capacity to 140 MMcfd by the installation of two new gas process- ing trains within their existing plant on Songo Songo Island and the addition of compression on the onshore section of the pipeline. • The Government of Tanzania is seeking finance from the Chinese Exim Bank to construct a separate gas processing plant on Songo Songo Island and a new onshore pipeline that will run parallel to the existing line from Somanga Funga to Dar es Salaam. This will increase the overall capacity of the system to 200 MMcfd. This could be increased with the addition of a new offshore pipeline and incremental gas processing units. The Government of Tanzania is confident that their initiative will proceed and will be operational by the end of 2013. The Company currently pays a flat rate regulated tariff of US$0.59/ mcf to Songas to utilize the infrastructure system plus (as an incentive for Songas to re-rate their gas processing capacity) an additional tariff of US$0.30/mcf for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd. 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. Since 2004, the Company has constructed in excess of 50 kilometers of low pressure pipeline in Dar es Salaam and 36 industrial customers were connected and consuming Additional Gas at the end of 2011. I O P E R A T O N S R E P O R T 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 1 1 A N N U A L R E P O R T 19 RESERVES 20 OPERATIONS REPORT T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O THE SONGO SONGO FIELD Summary of Orca Exploration’s assessment of Gas Initially in Place (GIIP) During 2011 Orca undertook a re- evaluation of all the subsurface data and, although no new geological or geophysical data was acquired, a revised geological model was developed which has significantly affected the way management views the Songo Songo North accumu- lation. Management’s view of the exploratory prospect Songo Songo West remains unchanged. The reserves and resources are assessed for the following areas: 1. The Songo Songo main producing field (“Songo Songo Field”, “SS Field”); 2. 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”, “SSW”). A summary of management assessment of the 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 Mid Case GIIP for the combined Songo Songo Field and Songo Songo North discovery is 2,021 Bcf. The GIIP estimates are based on the top reservoir depth structure maps generated as part of the overhaul of the entire geological model. When broken down managements assesses that the Songo Songo Field GIIP has increased 9% to 1,468 Bcf (2010:1,345 Bcf). However, significantly, management assesses that Songo Songo North GIIP has increased 144% to 553 Bcf (2010: 226 Bcf). 8°S 8°S Maurel Prom BG & Ophir Funguo PT Pan Af En Chewa Ndovu Res Pwenza Ndovu Res BG & Ophir Statoil & Exxon Zafarani Statoil & Exxon 10°S 10°S BG & Ophir Ndovu Res Hydro Tanz Maurel Prom BG & Ophir 3,000 Jodari Chaza 2 , 0 1 , 5 0 0 0 0 1 , 0 0 5 0 0 0 2 , 5 0 0 2 , 5 0 0 2 , 0 0 0 Ndovu Res Windjammer Anadarko Lagosta Tubarao Barquentine Camarao Mamba South I O P E R A T O N S R E P O R T Collier Ironclad Anadarko ENI Statoil Statoil Petronas Petronas 40°E 40°E 42°E 42°E March 2012 Songo Songo field is the first producing gas field in East Africa’s most intense gas prospecting area offshore Tanzania. The area has recorded numerous recent gas discoveries - shown in red. Management’s Mid Case GIIP of 2,021 Bcf for the Songo Songo Field and Songo Songo North compares with the McDaniel end 2011 GIIP estimates as presented below: 12°S Bcf 1P 2P 3P McDaniels Songo Songo Field GIIP (Bcf) 1,342 1,486 The McDaniel reserves evaluation are summarised in more detail below. Reservoir management and surveillance 1,562 Gas discovery Gas pipeline Water depth (m) 3,000 14°S 0 50 Kilometres TANZCO21a Songo Songo Field reservoir development and management is evaluated through the static geologic and dynamic reservoir simulation models. Total cumulative production from the field of 159.3 Bcf to the end of 2011, repre- sents 7.9% of Management’s Mid Case GIIP. The entire current production of 159.3 Bcf is from the Songo Songo Main area which management believes has a Mid Case GIIP of 1,468 Bcf, which represents 10.8% of the Songo Songo Main area GIIP. At this stage in field life, greater confidence continues to be placed in the volumetric estimate of GIIP from the static model, than from dynamic estimates of GIIP based on Material Balance calculations. The reservoir 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 compart- mentalisation, if any. The Company uses down hole pressure gauges to monitor and record bottom hole pressure. The recorded pressure data is used for a variety of purposes including near well formation parameter assessment, well deliverability and estimates of field GIIP. The data is also used to update and history match pro- duction 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. 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 1 1 A N N U A L R E P O R T 21 22 OPERATIONS REPORT T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O The downhole pressure data is showing early signs for the presence of an aquifer, although this is not yet definitive and as yet no water break through has occurred. 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 remain inconclusive for the presence of, or strength of an aquifer, it is therefore too early to assess the potential impact on reserves, if any. Management will continue to evaluate this as more pressure data is available, and by monitoring for the first signs of potential water production from the wells. 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 (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 to be able to deliver a maximum peak of 200 MMcfd (including Protected Gas). To achieve this and as detailed above, an additional main field development well (“SS-11”) is currently being 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. Following this a second well (“SS-12”), similarly designed will be drilled from a nearby location in a deviated manner to the south-west. The wells will be tied back to the Songo Songo gas processing fa- cilities. In addition larger tubing will be installed in the SS-10 well to increase deliverability. 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 immediate plans to drill this well. In addition to the above, field compression will need to be installed to maintain the deliverability of the wells. The first stage of compression is expected to be installed with the expanded gas processing fa- cilities by the end of 2013. GAS RESERVES In accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities, the independent petroleum engineers, McDaniel prepared a report dated April 2012 that assessed the Orca Exploration natural gas reserves based on information on the Songo Songo Field and Songo Songo North as at 31 December 2011 (the “McDaniel Report”). A summary of the remaining Additional Gas reserves on a life of license and life of field basis are presented below. 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. Dodoma Mombasa Mombasa 200 Tanga Tanga Afren Antrim 5 0 0 2 0 0 Dar Es Salaam Dar Es Salaam Dar Es Salaam Dodsal Petrodel Petrodel Shell Int Shell Int Shell Int Shell Int Petrobras Ophir Petrobras Maurel Prom Funguo PT Pan Af En Songo Songo Songo Songo Petrobras Well 2 Chewa-1 Discovery BG & Ophir Well 1 Pweza Discovery Ndovu Res BG & Ophir Statoil & Exxon Statoil & Exxon Zafarani BG & Ophir BG & Ophir Ndovu Res Hydro Tanz Well 4 Jodari-1 Discovery 3,000 Well 3 Chaza-1 Discovery , 2 5 2 0 0 0 0 1 5 1 , , Mnazi Bay Mnazi Bay Maurel Prom , 5 0 0 0 0 0 0 0 0 2 2 , , 5 0 0 0 0 0 Windjammer Lagosta Ndovu Res Barquentine Camarao Mamba South Tubarao Collier Collier Ironclad Ironclad 3 , 0 0 0 3,000 March 2012 Gas discovery Gas pipeline Water depth (m) 0 3,000 100 TANZCO22a Kilometres During the course of 2011 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. On a Gross Company basis there has been a 27% increase in Songo Songo’s 1P Additional Gas reserves to the end of the license period, and a 17% increase on a life of field basis, with a total Additional Gas production of 17.5 Bcf during the year. There has been a 22% increase in the 2P Additional Gas reserves on a Gross Company life of license basis from from 450.8 Bcf to 548.5 Bcf. The increase is primarily due to an improvement in the recovery factors. This has been possible as there has been an increase in the level of pressure data as a result of the high level of production volumes achieved during 2011. Orca management estimates that the total recoverable 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 2011. 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) 2011 Gross (1) 316.3 152.8 469.1 79.4 548.5 296.0 844.5 2011 Net (2) 215.4 82.2 297.6 48.9 346.5 192.5 539.0 2010 Gross 289.5 79.7 369.2 81.6 450.8 370.9 821.7 2010 Net 191.2 47.8 239.0 50.1 289.1 234.1 523.2 (1) Gross equals the gross reserves that are available for the Company after estimating the effect of the TPDC back in (see below). (2) Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the Production Sharing Agreement. I O P E R A T O N S R E P O R T 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 1 1 A N N U A L R E P O R T 23 24 OPERATIONS REPORT T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 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) The gross and net Company Additional Gas reserves to end of field life are as follows: 2011 Gross (1) 539.8 6.5 546.3 127.6 673.9 170.6 844.5 2011 Net (2) 355.0 0.4 355.4 79.2 434.6 104.3 539.0 2010 Gross 478.4 (11.6) 466.8 153.3 620.1 201.6 821.7 2010 Net 315.8 (10.4) 305.4 95.6 401.0 122.2 523.2 (1) Gross equals the gross reserves that are available for the Company after estimating the effect of the TPDC back in (see below). (2) Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the Production Sharing Agreement. 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 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 modifica- tions in the way the Gross Company reserves are calculated. For the purpose of calculating the Gross Additional Gas reserves, McDaniel has assumed in their 2P case that 171 Bcf (2010: 190 Bcf) or an average of 13.4 Bcf per annum will be required to meet the demands of the Protected Gas users from 1 January 2012 to 31 July 2024. During 2011, the Protected Gas users consumed 13.3 Bcf. The principal assumptions used by McDaniel in its evaluation of the Tanzanian PSA are as follows: Gross additional gas reserves Additional Gas price 1P Gross Additional Gas volumes 1P Additional Gas price 2P Gross Additional Gas volumes 2P Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023-2026 Present value of reserves US$/mcf 4.08 4.44 4.99 5.08 5.18 5.26 5.33 5.41 5.49 5.64 5.80 6.19 MMcfd 54.57 54.57 114.26 131.09 131.09 131.09 131.09 131.09 128.35 99.81 77.69 56.59 US$/mcf 4.06 4.43 5.07 5.15 5.27 5.39 5.51 5.59 5.67 5.76 5.90 6.09 The estimated value of the Songo Songo reserves on a life of license basis based on the assumptions on production and pricing are as follows: Present value of reserves US$ millions Proved producing Proved undeveloped Total proved (1P) Probable Total proved and probable (2P) Possible Total proved, probable and possible (3P) 2011 10% 209.3 118.9 328.2 22.8 351.0 60.7 411.6 5% 301.3 139.2 440.5 39.9 480.4 133.8 614.2 15% 152.4 99.2 251.6 13.5 265.1 29.6 294.7 There has been a 26% increase on the 2P present value at a 10% discount basis from US$277.6 million to US$351.0 million on a life of licence basis. The increase is primarily due to an increase in recoverable reserves and an accel- erated production profile as a result of increased investment in field deliver- ability. 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. 2010 10% 180.7 55.0 235.7 41.9 277.6 117.0 394.6 5% 267.2 82.7 349.9 71.3 421.2 269.6 690.8 MMcfd 57.11 57.11 118.12 136.04 136.04 136.04 136.04 136.04 136.04 136.04 115.10 88.79 15% 128.2 36.6 164.8 25.2 190.0 56.3 246.3 I O P E R A T O N S R E P O R T 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 1 1 A N N U A L R E P O R T 25 26 OPERATIONS REPORT T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O Songo Songo West represents a major potential upside source of reserves in the Songo Songo area. Songo Songo West Songo Songo North SS-1 SS-1 Songo Songo Main SS-9 SS-9 SS-10 SS-10 SS-4 SS-4 SS-6 SS-6 SS-5 SS-5 SS-3 SS-3 SS-7 SS-7 PROVEN PROVEN SECTION SECTION 5 kms KN-1 KN-1 SS-8 SS-8 K-1 K-1 EXPLORATION TANZANIA 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 2012. 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. As with 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. 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. The McDan- iel’s Neocomian and Cenomanian GIIP and resources are summarised in the tables below. Neocomian and Cenomanian GIIP and resources 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 accumu- lation 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 com- mercial rates, the well will be suspended at the mudline as a potential future producer while a field development plan is worked up. In the case of develop- ment with high angle to horizontal wells, a 3D seismic survey will be required. The most likely scenario is that the southern part of the field be developed first from a central hub tied back to the processing plant on the island, and while early field performance is monitored plans to drill up the northern sector of the field can be prepared. Songo Songo West is located in water depths of approximately 18 – 35 meters 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 re- quirement for a jack-up rig to drill in shallow water in a similar timeframe. The intent is to encourage a rig share opportunity which would reduce rig and support vessel mobiliza- tion and demobilization costs, as well as asso- ciated shared service costs. I O P E R A T O N S R E P O R T 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 1 1 A N N U A L R E P O R T 27 28 OPERATIONS REPORT T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O Corte Dei Signori Longastrino Longastrino Agosta Orca acreage Gas field Prospect Leads Agosta La Rotta Sub Thrust Sub Thrust Mantello Dosso Degli Angeli Dosso Degli Angeli Valli Di Comocchio Lake Tre Motte ITALY During November 2010, Orca Ex- ploration signed an agreement with Northern Petroleum plc. to acquire between 70% and 75% of the Longas- trino Block in the Po Basin onshore Italy. This acquisition was Orca’s second entry into Italy during 2010. In May, Orca acquired a 15% interest in the Petroceltic operated B.R268. RG Permit in the offshore Central Adriatic. Bando Alfonsine San Potito Ilaria Agosta Alfonsine Longastrino Tre Motte Dosso Degli Angeli Alfonsine Porto Corsini Zorabini Ravenna Abbadesse Cotignola Baldina 0 10km La Tosca La Tosca 0 San Marco 2 Under the terms of the farm in with Northern Petroleum, Orca will pay 100% of the costs of the La Tosca-1 well up to €4.3 million and 70% thereafter for the drilling phase of the well. If the well is tested and completed, then Orca will earn an additional 5% by paying 100% of the testing costs up to €1.3 million and 75% thereafter. The Company will also pay back costs of €0.6 million. 3km Earlier in 2010, Orca committed approximately US$13 million to earn a 15% interest in the Petroceltic operated Elsa discovery block and 11 adjacent licenses. The Elsa field has a large volume of known oil in place. The well cannot be drilled until the Italian Government reverses a law that excluded the drilling within 5 nautical miles of the coastline and 12 nautical miles in the region of protected marine parks (enacted following the blow out of the Macondo well in the U.S. Gulf). Italy is trying to reduce its dependence on imported fuels and it is expected to reverse this law during 2012. Orca is not liable to any costs associated with the drilling of Elsa-2 until such time as a rig contract is signed. Central Adriatic - B.R268.RG Permit The B.R268.RG Permit containing Elsa is located on and at the northern margin of the Jurassic-Miocene Apulian Carbonate Platform. Several com- mercial discoveries of oil are in close proximity including the Rospo Mare and Ombrina Mare fields on the platform, and the Miglianico field on the platform margin. The Elsa discovery is analogous to the neighbouring Miglianico field, and numerous additional prospects and leads have been identified both on the platform and at the platform margin in the adjacent acreage. The Elsa field is located off the eastern coast of Italy, approximately 7 kilome- ters offshore in around 35m water. The field was discovered by AGIP in 1992 with well Elsa-1, which encountered an oil column of approximately 65m in the Lower Cretaceous Maiolica Formation at a depth of around 4,500m. Due to casing restrictions, a sub-optimal open hole drill stem test was attempted with both water and oil zones exposed to the wellbore. Oil samples, contami- nated with water, recovered from the test string had a reported oil gravity of 15° API. Uncertainty remains over the oil gravity, especially in light of yel- low-gold fluorescence reported while drilling through the reservoir, and close proximity to the Ombrina Mare and Miglianico fields, which lie at depths of I O P E R A T O N S R E P O R T Top: Elsa Permit Area Bottom: Longastrino Permit Area Adriatic Sea d505B.R-EL d507B.R-EL d493B.R-EL d492B.R-EL d494B.R-EL around 2,900m and 4,800m respectively, but which have API gravities of 18° and 34° respectively. Both Orca and Petroceltic believe that the Elsa field will be commercial at 15° API oil, however several indications give rise to the expectation that the crude gravity may be higher than the 15° API. The Elsa-2 appraisal well has the primary objective of confirming the commercial produc- tion potential of the reservoir. Positive results from Elsa-2 will be followed by a 3D seismic survey over the field. The full field mid case stock tank oil initially in place (“STOIIP”) potential of Elsa is 410 MMbbl. The Operator’s estimates of recoverable reserves are in the region of 100 MMbbl, depending on oil gravity and viscosity. Production would be to a floating production storage and offloading (“FPSO”) and export via a shuttle tanker. The farm in agreement with Petroceltic includes the ability to earn equity in a number of offshore exploration permits, some of which are within the area subject to the currently imposed drilling ban. A number of prospects and leads have been identi- fied within the exploration acreage ranging in age from Jurassic, Cretaceous and Tertiary and having primarily oil and some gas potential. A further programme of seismic acquisition is planned to evaluate more fully the potential of these explora- tion permits. Po Basin - Longastrino Permit d500B.R-EL d496B.R-EL BR268.RG Miglianico Elsa West ElsaElsa Ombrina Mare d495B.R-EL S. Stefano Mare d499B.R-EL Rospo Mare Fiume TresteFiume Treste BR268 RG Elsa Permits within banned areas – contesting rejection notices Re-permitted blocks. Approved by MSE and await MATTM approval Awaiting positive VIA decrees from MATTM. Prospect with oil flows Oil field Gas field 12nm limit 5nm limit ITAELSA-08 Tresigallo Pomposa Sabbioncello Vallicella Vallezzetta Bottoni Migliarino Gallare Manara Porto Verrara Bando Alfonsine Ilaria Longastrino Tre Motte Dosso Degli Angeli San Potito Ravenna Cotignola Abbadesse 1DIR The Longastrino permit is situated onshore Italy in the Northern Apennine foredeep, commonly known as the Po Valley Basin. Numerous gas and gas-condensate fields are located close to the permit including Ravenna, Alfonsine, San Potito, Cotignola, Dosso degli Angeli and Baldina. Recent discoveries include Agosta and Abbadesse. There are a number of proven clastic reservoir horizons in the Pliocene and Upper Miocene. Offset well data indicates that these reservoir horizons have an average porosity of 20-25% (maximum 34%) and perme- ability in the range 10-400mD. Intraformational clays, shales and marls act as seals, while the clays also have source potential to generate biogenic gas. ITALGO-01 The principal target within the Longastrino Permit is the La Tosca prospect. A well defined amplitude anomaly seen on 3D seismic is present within mapped closure. The prospect is just 2 kilometers to the north-east of the Alfonsine gas field (300 Bcf) whose reservoir is the lower Pliocene Porto Corsini Formation. The Intra Lower Pliocene target reservoir is mapped as a 3-way dip closed structured trapped against a NW-SE trending thrust fault. While the primary reservoir objective is prognosed at -1,600m true vertical depth subsea (“TVDSS”), the La Tosca -1 well will be drilled to a prognosed total depth of approximately -2,500m TVDSS to test deeper secondary, probable Miocene, objectives. 0 15km March 2011 Orca acreage Gas field Condensate field Gas pipeline 5 nautical mile limit 5 n a u t i c al mile limit Adele Azzurra Porto Corsini Mare Ovest Porto Corsini Zorabini Baldina Armida Diana Porto Garibaldi Agostino Porto Corsini Mare E 0 0 0 5 Antares 5 10 5 15 kms 10 miles 10 nautical miles The La Tosca prospect is estimated to contain 45 Bcf of gross mean pro- spective resource with an upside of 85 Bcf of 99.5% methane gas. Work to secure a site from which to drill the La Tosca-1 well is now completed and the well is expected to spud in Q3 2012. Upon success at La Tosca, there is plenty of follow-up exploration potential, which initially will require additional 3D seismic coverage to confirm the potential. Numerous leads have been identified on older 2D seismic data that if established on a new 3D seismic dataset, could lead to significant further exploration. 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 1 1 A N N U A L R E P O R T 29 30 OPERATIONS REPORT T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O full take Orca Exploration is committed to responsibility for the Company’s actions and to incorporate socially responsible practices in all its operations and decision making. It is Orca’s intention to create positive impacts and operate sustainably with respect to the environment, employees, partners, communities, suppliers, governments and other stakeholders. CORPORATE SOCIAL RESPONSIBLITY Health and safety are top priorities in our operations. We also attach high priority to attracting, developing and retaining talented employees wherever we operate. Orca supports transparency in all its business and financial practices and promotes high standards of ethical conduct in all its dealings. Orca also welcomes the opportunity to give back to communities where we operate. On Songo Songo Island Orca is committed to improving the quality of life of island residents. Over the past several years Orca has developed and rolled out programmes that have improved the health of Songo Songo Islanders and provided education for youth, equipment for teachers and scholarships that are enabling island youth to complete high school in Dar es Salaam. Currently 10 pupils are benefitting from the Orca scholarship programme at a school in Dar es Salaam. These children then support organized reading groups and other development programmes when they return to Songo Songo Island. It is hoped that some of these graduates may enter university and Orca will continue to sponsor them through their degree courses. Orca provides assistance on an ongoing basis to the community school on Songo Songo Island. The Company has assisted in upgrading the elemen- tary school facilities and provided educational materials and equipment. Currently the Company is supporting a new kindergarten which it built during 2011 and is providing early learning facilities for children 3 to 6 years of age. The Company has also recruited a professional instructor for the Learning Centre to provide English language instruction, computer training and entrepreneurial skills to young adults and sponsored three teachers to attend Teacher Training College in Dar es Salaam. This year the company will further extend the kinder- garten and provide a fully equipped and secure play- ground. In addition Orca is building accommodation for the school teachers it has trained and this will incor- porate a new library and IT centre. Orca’s Board of Directors regularly reviews the corporate social responsibility aims of the Company and how this translates onto practical and beneficial practices. MANAGEMENT’S DISCUSSION & ANALYSIS I O P E R A T O N S R E P O R T 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 1 1 A N N U A L R E P O R T 31 32 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O FORWARD LOOKING STATEMENTS THIS MD&A OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS SHOULD BE READ IN CON- JUNCTION WITH THE AUDITED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES THERETO FOR YEAR ENDED 31 DECEMBER 2011. THIS MD&A IS BASED ON THE INFORMATION AVAILABLE ON 25 APRIL 2012. CERTAIN STATEMENTS IN THIS MD&A INCLUDING (I) STATEMENTS THAT MAY CONTAIN WORDS SUCH AS “ANTICIPATE”, “COULD”, “EXPECT”, “SEEK”, “MAY”, “INTEND”, “WILL”, “BELIEVE”, “SHOULD”, “PROJECT”, “FORECAST”, “PLAN” AND SIMILAR EXPRESSIONS, INCLUDING THE NEGATIVES THEREOF, (II) STATE- MENTS THAT ARE BASED ON CURRENT EXPECTATIONS AND ESTIMATES ABOUT THE MARKETS IN WHICH ORCA EXPLORATION OPERATES AND (III) STATEMENTS OF BELIEF, INTENTIONS AND EXPEC- TATIONS 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 EXPENDITURES, INCLUDING THE AMOUNT, NATURE AND 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 WORLD ECONOMIC CONDITIONS AND SPECIFCALLY IN TANZANIA, ITALY 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; SANCTITY OF CONTRACT; VOLATILITY OF OIL AND NATURAL GAS PRICES; OIL AND NATURAL GAS PRODUCT SUPPLY AND DEMAND, RIG AVAIL- ABILITY; RISKS INHERENT IN ORCA EXPLORATION’S ABILITY TO GENERATE SUFFICIENT CASH FLOW FROM OPERATIONS, THIRD PARTY FINANCE OR ASSETS SALES TO MEET ITS CURRENT AND FUTURE OBLIGATIONS; INCREASED COMPETITION; THE FLUCTUATION IN FOREIGN EXCHANGE OR INTEREST RATES; STOCK MARKET VOLATILITY; COST POOL AUDITS AND OTHER FACTORS, MANY OF WHICH ARE BEYOND THE CONTROL OF ORCA EXPLORATION. ORCA EXPLORATION’S ACTUAL RESULTS, PERFORMANCE OR ACHIEVEMENTS COULD DIFFER MATE- RIALLY 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 FORWARD-LOOKING STATEMENTS WILL TRANSPIRE OR OCCUR, OR IF ANY OF THEM DO TRANSPIRE OR OCCUR, WHAT BENEFITS ORCA EXPLORATION WILL DERIVE THEREFROM. SUBJECT TO APPLICA- BLE LAW, ORCA EXPLORATION DISCLAIMS ANY 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. NON-GAAP MEASURES THE COMPANY EVALUATES ITS PERFORMANCE BASED ON FUNDS FLOW FROM OPERATING AC- TIVITIES 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 PRO- DUCTION AND SALE OF ADDITIONAL GAS AND IS CALCULATED AS REVENUES LESS PROCESSING AND TRANSPORTATION TARIFFS, 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. THE OPERATIONS IN ITALY ARE CURRENTLY IN THE EXPLORATION PHASE AND HAVE NO ASSOCIATED OPERATING REVENUE. THESE NON-GAAP MEASURES ARE NOT STANDARDISED AND THEREFORE MAY NOT BE COMPARABLE TO SIMILAR MEA- SUREMENTS OF OTHER ENTITIES. ADDITIONAL INFORMATION REGARDING ORCA EXPLORATION GROUP INC IS AVAILABLE UNDER THE COMPANY’S PROFILE ON SEDAR AT www.sedar.com. Background Tanzania 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 (until July 2024) 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 electrification of some villages along the pipeline route. Orca Exploration receives no revenue for the Protected Gas delivered to Songas and operates the field and gas process- ing 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”). Italy During 2010 Orca Exploration farmed in to an oil appraisal block in the Adriatic Sea in Italy and to a gas exploration prospect in the Po Valley in north eastern Italy. Principal terms of the Tanzanian 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”). The Proven Section is essentially the area covered by the Songo Songo field within the Discovery Blocks. (c) No sales of Additional Gas may be made from the Discovery Blocks if in Orca Exploration’s reasonable 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 a long term power contract (Amended and Restated Gas Agreement (“ARGA”) with the electricity utility, Tanzania Electric Supply Company (“TANESCO”), the owner of the Ubungo power plant, Songas Limited and the Ministry of Energy and Minerals (“MEM”). This contract 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 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. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S 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 1 1 A N N U A L R E P O R T 33 34 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O (d) “Insufficiency” occurs if there is insufficient gas from the Discovery Blocks to supply the Protected Gas require- ments 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 modifi- cation; 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. (e) 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. As discussed in (c) above an 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) The Company is able to utilise the Songas infrastructure including the gas processing plant and main pipeline to Dar es Salaam. Access to the pipeline and gas processing plant is open and can be utilised by any third party who wishes to process or transport gas. Ndovu Resources Limited which has a small gas field on Songo Songo Island has indicated that it wishes to tie its production into the gas processing plant. It is considered unlikely that this will occur during 2012. 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 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 (US$1.4 million for the year ended 31 December 2011 for marketing costs that have been incurred by TPDC since start up); 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 MEM (“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 MEM has approved the Additional Gas Plan, then TPDC is deemed not to have elected. If TPDC elects to participate, then it will be entitled to a rateable proportion of the Cost Gas and their profit share percentage increases by the Specified Proportion for that development program. TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development. The implications and workings of the ‘back in’ are currently being discussed with the Government Negotiation Team (“GNT”) and there may be the need for reserve and accounting modifications once these discussions are concluded. For the purpose of the reserves certification as at 31 December 2011, it has been assumed that they will ‘back in’ for 20% for all future new wells and other developments and this is reflected in the Company’s net reserve position. (h) On 27 February 2009, the energy regulator, Energy and Water Utility Regulatory Authority (“EWURA”), issued an order that saw 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 initialed ARGA and the Portfolio Gas Sales Agreement 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 or other operators in respect of sales to the power sector. During Q2 2011, the Company signed a Re-rating Agreement with TANESCO and Songas to run the gas pro- cessing plant at levels of up to 110 MMcfd (the pipeline and pressure requirements at the Ubungo power plant restrict the infrastructure capacity to a maximum of 102 MMcfd). Under the terms of the Re-rating Agreement, the Company effectively pays an additional tariff of US$0.30/mcf for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd in addition to the tariff of US$0.59/mcf payable to Songas as set by the energy regulator, EWURA. (i) 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. (j) Profits on sales from the Proven Section (“Profit Gas”) are shared between TPDC and the Company, the pro- portion 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 Gas share is a minimum of 25% and a maximum of 55%. Average daily sales of Additional Gas Cumulative sales of Additional Gas TPDC’s share of Profit Gas Company’s share of Profit Gas MMcfd 0 - 20 > 20 <= 30 > 30 <= 40 > 40 <= 50 > 50 Bcf 0 – 125 > 125 <= 250 > 250 <= 375 > 375 <= 500 > 500 % 75 70 65 60 45 % 25 30 35 40 55 For Additional Gas produced outside of the Proven Section, the Company’s Profit Gas share is 55%. Where TPDC elects to participate in a development program, their profit share percentage increases by the Specified Proportion (for that development program) with a corresponding decrease in the Company’s percent- age 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. (k) 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 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. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S 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 1 1 A N N U A L R E P O R T 35 36 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O Operatorship (l) 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 the Gov- ernment of Tanzania (“GoT”) and take all necessary safe, health and environmental precautions all in accor- dance 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. (m) In the event of loss arising from Songas’ failure to perform and the loss is not fully compensated by Songas, Orca Exploration, 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 Orca Exploration Group Inc Orca Exploration Italy Inc Orca Exploration Italy Onshore Inc PAE PanAfrican Energy Corporation PanAfrican Energy Tanzania Limited Incorporated British Virgin Islands British Virgin Islands British Virgin Islands Mauritius Jersey Orca Exploration UK Services Limited United Kingdom Results for the year ended 31 December 2011 Operating Volumes The sales volumes for the year were 17,464 MMcf or 47.8 MMcfd. This represents an overall increase of 30% over the previous year. The Company’s sales volumes were split between the industrial and power sectors as follows: Operating Volumes 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 2011 2010 2,742 14,722 17,464 7.5 40.3 47.8 2,504 10,940 13,444 6.9 30.0 36.9 Industrial sales volume increased by 9% to 2,742 MMcf from 2,504 MMcf in 2010. The overall increase is predomi- nately a consequence of increased sales to Kioo Glass as a result of the supply of Additional Gas for their own power generation. Sales of Additional Gas to the Wazo Hill cement plant operated by the Tanzanian Portland Cement Company (“TPCC”) remained consistent between the two years. Industrial sales for the year averaged 7.5 MMcfd (2010: 6.9 MMcfd). Power sector The power sector sales volumes increased by 35% to 14,722 MMcf compared to 10,940 MMcf in 2010. The increase is a result of the decline in the use of hydro-generation due to the low levels of rain fall experienced during 2011 and a general increase in electricity demand. In order to meet the increased demand the Symbion power plant was re- commissioned in July 2011. Commodity Prices US$/mcf Average sales price Industrial sector Power sector Weighted average price Industrial sector 2011 2010 10.05 2.77 3.92 8.76 2.60 3.75 The average gas price for the year was US$10.05/mcf (2010: US$8.76/mcf). The overall increase in price achieved during the year is a consequence of an increase in world oil prices experienced compared to 2010, together with a relative decline in the level of Additional Gas sales to Wazo Hill. The sales to the Wazo Hill cement plant are priced by reference to imported coal (their alternative fuel supply) declined from 32% of total industrial volumes in 2010 to 27% in 2011. Power sector The average sales price to the power sector was US$2.77/mcf for the year, compared to US$2.60/mcf in 2010. The increase in price is a combination of the 2% annual price indexation and the higher prices achieved under the Portfolio Gas Sales Agreement (‘PGSA’) Under the terms of the PGSA Additional Gas consumed by TANESCO above 37 MMcfd is at a higher sales price. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S 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 1 1 A N N U A L R E P O R T 37 38 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 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. Under the terms of the PSA, TPDC is able to recover reasonably incurred marketing costs. During 2011, TPDC recovered US$1.4 million in respect of such marketing costs. The Company’s Costs Gas entitlement averaged 52% of the Net Revenues during the year (2010: 75%). The decline was due to the recovery of the historical cost pool during 2011 and the payment of the TPDC marketing costs. The Additional Gas sales volumes during the year have increased from 37.2 MMcfd in Q1 2011 to 57.7 MMcfd in Q4 2011. Consequently, the revenue less cost recovery share of revenue (“Profit Gas”) was 35% in Q1 2011, 40% in Q2 2011 and 55% for both Q3 and Q4 2011 before adjustments for the TPDC back-in discussed below. In 2011 a large proportion of the gas production was from the SS-10 well, which has been deemed to have been “backed into” by TPDC. As a consequence TPDC’s profit share increases by 20% for the production of gas emanating from the SS-10 well. Orca Exploration was allocated a total of 73.7% in 2011 (2010: 84%) of the Net Revenues as follows: Figures in US$’000 Gross sales revenue Gross tariff for processing plant and pipeline infrastructure Gross revenue after tariff Analysed as to: Company Cost Gas Company Profit Gas Company operating revenue TPDC share of revenue 2011 68,394 (11,672) 56,722 29,215 12.579 41,794 14,928 56,722 2010 50,348 (7,932) 42,416 31,812 3,853 35,665 6,751 42,416 The Company’s total revenues for the year amounted to US$45,893,000 after adjusting the Company’s operating revenue of US$41,794,000 by: i) US$6,626,000 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. ii) US$2,527,000 for the deferred effect of Additional Profits Tax. This tax is considered a royalty and is netted against revenue. Revenue per the income statements may be reconciled to the operating revenue as follows: Figures in US$’000 Industrial sector Power sector Gross sales revenue Processing and transportation tariff TPDC share of revenue Company operating revenue Additional Profits Tax Current income tax adjustment Revenue 2011 2010 27,562 40,832 68,384 (11,672) (14,928) 41,794 (2,527) 6,626 45,893 21,933 28,415 50,348 (7,932) (6,751) 35,665 (800) 3,943 38,808 Processing and Transportation Tariff The Company currently pays a flat rate regulated gas processing and transportation tariff of US$0.59/mcf to Songas. Under the terms of the gas contracts with the power sector, the Company will pass on any increase or decrease in the EWURA approved charges. This protocol insulates Orca Exploration from any increases in the gas processing and pipeline infrastructure costs. During Q2 2011, the Company signed a Re-rating Agreement with TANESCO and Songas to run the gas processing plant at levels of up to 110 MMcfd (the pipeline and pressure requirements at the Ubungo power plant restrict the infrastructure capacity to a maximum of 102 MMcfd). Under the terms of this agreement, the Company effectively pays an additional tariff of US$0.30/mcf for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd in addition to the regulated tariff of US$0.59/mcf payable to Songas. The charge for the additional tariff was US$1.4 million for the year. Production and distribution expenses The production and distribution expenses are summarised in the table below: Figures in US$’000 Share of well maintenance Other field and operating costs Distribution costs Production and distribution expenses 2011 806 2,829 3,635 2,453 6,088 2010 775 1,855 2,630 2,249 4,879 The well maintenance costs are allocated between Protected and Additional Gas based on the proportion of their re- spective sales during the year. The total costs for the maintenance for the year was US$1,453,000 (2010: US$1,235,000) of which US$806,000 (2010: US$775,000) was allocated for the Additional Gas. Other field operating costs include an apportionment of the annual PSA license costs regulatory fees, the annual evalu- ation of reserves and the cost of personnel and chemicals that are not recoverable from Songas. The increase in costs over 2010 is primarily a consequence of the payment for additional chemicals to deliver higher levels of Additional Gas production. Distribution costs represent the direct cost of maintaining the ring-main distribution pipeline and pressure reduction station (security, insurance and personnel). The increase over 2010 is a result of higher insurance premiums. TPDC and MEM have indicated that they wish Orca to unbundle the downstream business in Tanzania. The method- ology for this is still to be discussed in detail with both TPDC and MEM. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S O R C A E X P L O R A T I O N G R O U P I N C . 2 0 1 1 A N N U A L R E P O R T 39 40 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O Operating netback The operating netback per mcf before general and administrative costs, overheads, income tax and Additional Profits Tax may be analysed as follows: Amounts in US$/mcf Gas price – industrial Gas price – power Weighted average price for gas Tariff TPDC share of revenue Net selling price Well maintenance and other operating costs Distribution costs Operating netback 2011 10.05 2.77 3.92 (0.67) (0.85) 2.40 (0.21) (0.14) 2.05 2010 8.76 2.60 3.75 (0.59) (0.50) 2.66 (0.20) (0.17) 2.29 The operating netback decreased by 10% from US$2.29/mcf to US$2.05/mcf in 2011. The increase in the weighted average sales price from US$3.75/mcf to US$3.92/mcf is a consequence of the increase in gas price achieved in both the industrial and power markets. The increase in the price of power sales is in line with con- tractual arrangements. The rise in industrial sales is a consequence of the slight increase in global energy prices during 2011. As a consequence of the power crisis in Tanzania the volume of power sales accounted for 84% of the total Addi- tional Gas volumes in 2011 compared to 81% in 2010. The increase in the tariff rate from US$0.59/mcf to US$0.67/mcf is a consequence of the signing of the Re-rating Agreement with TANESCO and Songas as discussed above, with the EWURA regulated tariff remaining at US$0.59/ mcf for the year. The increase in TPDC’s revenue from US$0.50/mcf to US$0.85/mcf is a consequence of the recovery of the cost pool during 2011, TPDC’s recovery of past marketing costs and the increased profit share from the production of the SS-10 well. The increase in the well maintenance and other operating costs is a consequence of the use of additional chemicals associ- ated with the higher levels of Additional Gas production during the year. General and Administrative Expenses The general and administrative expenses (“G&A”) may be analysed as follows: Figures in US$’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 General and administrative expenses 2011 4,658 2,380 1,060 118 2,001 541 302 292 1,045 12,397 1,934 258 851 15,440 2010 2,558 2,745 883 113 1,116 323 215 208 637 8,798 1,876 378 664 11,716 The G&A includes the running of the gas business in Tanzania the majority of which is recoverable as Cost Gas. G&A averaged approximately US$1.3 million per month in 2011 (2010: US$1.0 million). G&A per mcf was US$0.88/ mcf (2010: US$0.87/mcf). The main variances are summarised below: Employee costs The increase in employment costs is a consequence of the hiring of additional staff, the upgrading of management in anticipation of the extensive development program in Tanzania, together with additional fees and bonus payments incurred in relation to new senior executive appointments. Office costs The level of office costs have increased due to the establishment of a separate serviced office and the increase in space required for the expansion of the Tanzanian operation. Reporting, regulatory and corporate finance The increase of costs is a result of the strengthening of the board of directors and the amount of time incurred in relation to the development of the drilling programme in response to the corrosion tubing issue identified in Q4 2010. Stock based compensation The breakdown of the costs incurred in relation to stock based compensation is detailed in the table below: Figures in US$’000 Stock options Stock appreciation rights 2011 1,171 (320) 851 2010 607 57 664 A total of 3,057,400 stock options were issued and outstanding at the end of 2011 compared to 2,557,400 at the end of 2010. A total of 500,000 stock options were issued during 2011 with exercise prices ranging from Cdn$3.60 to Cdn$4.75, a five year term and immediate vesting at the date of grant. A total one off charge of US$1.2 million was recorded in relation to these options. A total of 930,000 stock appreciation rights were outstanding at the end of 2011. In June 2010, 225,000 stock apprecia- tion rights were issued to the new non-executive directors with an exercise price of Cdn$4.20. The rights have a term of five years and vest in five equal instalments, the first fifth vesting on the anniversary of the grant date. 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 2011, the following assumptions were used; stock volatility between 42% and 75%, a risk free interest rate of 1.50% to 2.50% and a closing stock price of Cdn$2.90. A total credit of US$0.3 million was recorded in the year as a consequence of: a fall in the volatility of the stock price; a shorter contractual life of the majority of the rights to less than six months; together with a decline in the closing stock price. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S O R C A E X P L O R A T I O N G R O U P I N C . 2 0 1 1 A N N U A L R E P O R T 41 42 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O Net Finance Costs The loss on foreign exchange experienced in the year is a result of the strengthening US Dollar against the Tanzanian Shilling. Despite the gas sales price being denominated in US Dollars, the invoices are submitted in Tanzanian Shillings. Therefore, there is an exchange rate exposure between the time the invoices are submitted and the date the payment is received. Figures in US$’000 Finance income Interest income Foreign exchange gain Finance costs Overdraft charges Other finance costs Foreign exchange loss Net finance costs Taxation Income Tax 2011 2010 5 80 85 – (100) (938) (1,038) (953) 40 – 40 (12) – (890) (902) (862) 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 2011, 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$15.2 million which represents an additional deferred future income tax charge of US$2.4 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 percent- age change in the United States Industrial Goods Producer Price Index, an Additional Profits Tax (“APT”) is payable. The Company provides for Deferred 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 of 20% is then applied to profit gas of US$12.6 million in 2011 (2010: US$3.9 million), accordingly, US$2.5 million (2010: US$0.8 million) has been netted off revenue for the year ended 31 December 2011 Management does not anticipate that any APT will be payable in 2012, 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 expen- ditures for 2012. 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. The APT can have a significant negative impact on the Songo Songo project economics as measured by the net present value of the cash flow streams. Higher revenue in the initial years leads to a rapid payback of the project costs and con- sequently accelerates the payment of the APT that can account for up to 55% of the Company’s profit share. Therefore, the terms of the PSA reward the Company for taking higher risks by incurring capital expenditure in advance of revenue generation. Depletion and Depreciation Expense 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 2011, the proven reserves as evaluated by the independent reservoir engineers McDaniel & Associates Consultants Ltd (“McDaniel”) were 469.1 Bcf after TPDC ‘back in’ on a life of license basis. This leads to an average depletion charge of US$0.47/ mcf for the year (2010: US$0.36/mcf). Non-Natural Gas Properties are depreciated as follows: Leasehold improvements Computer equipment Vehicles Fixtures and fittings Over remaining life of the lease 3 years 3 years 3 years Carrying Value of Assets Capitalised costs are periodically assessed to determine whether it is likely that such costs will be recovered in the future. To the extent that these capitalised costs are unlikely to be recovered in the future, they are written off and charged to earnings. Funds Generated by Operations Funds from operations before working capital changes were US$22.7 million for the year ended 31 December 2011 (2010: US$20.8 million). Figures in US$’000 Profit after taxation Adjustments (i) Funds flow from operating activities Working capital adjustments (i) Net cash flows from operating activities Net cash flows used in investing activities Net cash flows from/(used in) financing activities Increase in cash and cash equivalents Effect of change in foreign exchange Net (decrease)/increase in cash and cash equivalents (i) See consolidated statements of cash flows 2011 7,986 14,672 22,658 (18,101) 4,577 (14,584) (681) (10,688) (151) (10,839) 2010 10,011 10,825 20,836 (5,302) 15,534 (2,923) 18,705 31,616 (340) 30,976 The overall increase in sales volumes achieved during 2011 has not been reflected in the funds flow from operation due to the recovery in the Tanzanian cost pool, the increase in G&A and the marginal increase in the costs of production associated with the record production levels. The net cash flow from operations has decreased due to the increase in the level of trade debtors following the dete- rioration in the level of payments received from TANESCO. The increase in capital expenditure during the year is a consequence of the commencement of the 2011/12 drilling programme. As a consequence of the factors described above the net cash has decreased by US10.8 million during the year. The increase in cash during 2010 was primarily a consequence of the increased funding from the successful completion of the rights issue in October 2010 (net funding after costs of US$18.5 million). O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S 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 1 1 A N N U A L R E P O R T 43 44 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O Capital Expenditures Capital expenditures amounted to US$18.1 million during the year (2010: US$3.4 million). The capital expenditures may be analysed as follows: Figures in US$’000 Geological and geophysical and well drilling Pipelines and infrastructure Power development Other equipment 2011 16,475 1,158 37 465 18,135 2010 1,598 1,582 6 195 3,381 Geological and geophysical and well drilling – US$16.5 million The SS-10 development well tie-in to the gas processing infrastructure was completed in the first quarter of the year at a cost of US$0.5 million. A total of US$12.0 million was incurred on the SS-11 development well, including the ordering of long lead items for both the drilling of the well and flow-lines. The drilling of the SS-11 development well commenced in February 2012 and is scheduled to be complete by mid May. A total of US$1.1 million was incurred on the ordering of long lead items for the Songo Songo West exploration well which is currently scheduled to be spud in Q4 2012. The balance of the expenditure in Tanzania was spent on studies in relation to the connection of the develop- ment wells to the infrastructure, well enhancement and the work-over programme, with a view to enabling the Songo Songo field to be able to produce in excess of 200 MMcfd by the end of 2012 (subject to infrastructure availability). A total of US$0.9 million was incurred in relation to the payment of past costs incurred by Northern Petroleum on its Longastrino block in the Po Valley in northern Italy. The exploration well is due to be spud in July 2012. Pipelines and infrastructure – US$1.2 million A total of US$0.7 million was incurred during the year on new customer connections together with a further US$0.2 million on enhancing the metering capabilities for both the power and industrial sectors. The installation of the meters has lead to a more efficient invoicing system and has enabled an accurate measure of usage by customers to be obtained on a daily basis. An additional US$0.3 million was incurred during the year on the continued expansion of compressed natural gas (“CNG”) facilities, with the installation of a daughter station at Mikocheni. Working Capital Working capital as at 31 December 2011 was US$56.0 million (31 December 2010: US$52.4 million) and may be analysed as follows: Figures in US$’000 Cash and cash equivalents Trade and other receivables Taxation receivable Prepayments Trade and other payables Taxation payable Working capital 2011 34,680 40,348 5,880 302 81,210 22,801 2,403 2010 45,519 13,583 4,009 409 63,520 9,156 2,000 56,006 52,364 The increase in working capital by US$3.6 million during 2011 is a consequence of the US$22.7 million of funds flow for the year being used to fund the US18.1 million capital programme. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S The majority of the cash is held in US and Cdn Dollars in Mauritius, and in Tanzanian Shillings in Tanzanian bank accounts and there are no restrictions to access any of these funds. There are no restrictions in Tanzania for converting Tanzania Shillings into US Dollars. Any surplus cash is held in a fixed rate interest earning deposit account. Trade and other receivables at 31 December 2011 represent US$35.7 million of trade receivables (2010: US$11.9 million), US$4.7 million of other receivables (2010: US$1.7 million) and taxation US$6.5 million (2010: US$4.0 million). The increase in other receivables is in relation to the increase in funds receivable from Songas for the opera- torship of the gas processing plant and associated projects. The increase in taxation is a consequence of the level of current taxation paid in the year, whereby any tax payable is recoverable form TPDC in accordance with the produc- tion sharing agreement. 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 2011, US$7.8 million (2010: US$4.2 million) was due from industrial customers, the majority of which has subsequently been received. The balance of US$28.0 million (2010: US$7.7 million) is made up of amounts due from the two power customers, TANESCO and Songas. As at 31 December 2011, the Company has US$22.8 million of financial liabilities with regards to trade and other payables of which US$17.1 million is due within one to three months, US$4.9 million is due within three to six months, and US$0.8 million is due within six to twelve months. The Company has a current taxation liability of US$2.4 million payable within three months. The Company sells 50% of its operating revenue (2011 - US$45.9 million) to TANESCO. Songas’ financial security is heavily reliant on the payment of capacity and energy charges by TANESCO. TANESCO is dependent on the Gov- ernment of Tanzania for some of its funding. Despite having a history of delayed payments, TANESCO has previously settled in full the outstanding balance subsequent to each quarter end. As at 31 December, 2011, TANESCO owes the Company US$24.2 million of which $11.1 million was collected subsequent to year end. As of the date of this report, the Company has not received payments from TANESCO with respect to any 2012 production and at the date of this report is owed US$22.9 million. There is a concern that TANESCO’s financial position may be deteriorating as it funds the emergency oil fired generation at a time of declining receipts for electricity from parastatal bodies. The Company has been assured by the Ministry of Energy that TANESCO will pay the outstanding invoices as soon as TANESCO has signed a new financing facility, and that this process is nearing completion. In the event that Company does not collect from TANESCO the outstanding receivables at year end and TANESCO continues to be unable to pay the Company for subsequent 2012 gas deliveries, the Company may need additional funding for its ongoing operations and to continue its committed exploration and development program in 2012. There are no guarantees that such ad- ditional funding will be available when needed, or will be available on suitable terms. Outstanding Share Capital There were 34.5 million shares outstanding as at 31 December 2011 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 Class A and Class B shares Convertible securities Options Weighted average diluted Class A and Class B shares 2011 2010 1,751 32,747 34,498 3,057 37,555 1,751 32,939 34,690 2,557 37,247 34,656 30,795 1,176 35,832 1,098 31,893 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 1 1 A N N U A L R E P O R T 45 46 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O The movement in Class B shares during the year is analysed in the table below: Number of shares (‘000) As at 1 January Shares issued Stock options exercised Normal course issuer bid As at 31 December 2011 32,939 – – (192) 32,747 2010 27,743 4,956 240 – 32,939 As at 25 April 2012, there were a total of 32,742,515 Class B shares and 1,751,195 Class A shares outstanding. 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. 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. Number of options (‘000) As at 1 January 2011 Granted Exercised As at 31 December 2011 Options 2,557 500 – 3,057 There were 500,000 new stock options issued during the year with a weighted average exercise price of Cnd$4.18. The new stock options vest on the date of issue and have a term of five years. A total charge of US$1.2 million has been recognised for the year in relation to the new stock options. 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 (65.1 Bcf as at 31 December 2011). The Gas Agreement may be superseded 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 new 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 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 insuf- ficiency of Protected Gas. The Company is actively monitoring the reservoir and does not anticipate that a liability will occur in this respect. Re-rating Agreement During Q2 2011, the Company signed a Re-rating Agreement with TANESCO and Songas Limited to increase the gas processing capacity to a maximum of 110 MMcfd (the pipeline and pressure requirements at the Ubungo power plant restrict the infrastructure capacity to a maximum of 102 MMcfd). Under the terms of the Re-rating Agreement, the Company effectively pays an additional tariff of US$0.30/mcf for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd in addition to the tariff of US$0.59/mcf payable to Songas as set by the energy regulator, EWURA. Under the terms of this agreement, the Company agreed to indemnify Songas Limited for damage to its facilities caused by the re-rating, up to a maximum of US$15 million, but only to the extent that this was not already covered by indemnities from TANESCO or Songas’ insurance policies. Portfolio Gas Sales Agreement On 17 June 2011, a long term (to June 2023) Portfolio Gas Sales Agreement (PGSA) was signed between Orca and TANESCO. Under the PGSA, Orca is obligated, subject to infrastructure capacity, to sell a maximum of approxi- mately 37 MMcfd for use in any of TANESCO’s current power plants except those operated by Songas at Ubungo. The current basic wellhead gas price of US$ 2.02/mcf is due to increase to approximately US$2.70/Mcf on 1 July 2012. 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. Capital Commitments Italy On 31 May 2010, the Company signed an agreement with Petroceltic International plc (“Petroceltic”) to farm in on Petroceltic’s Central Adriatic B.R268.RG Permit offshore Italy. The farm-in commits the Company to fund 30% of the Elsa-2 appraisal well up to a maximum of US$11.5 million to earn a 15% working interest in the permit. Thereafter, the Company will fund all future costs relating to the well and the permit in proportion to its participating interest. The Company has also agreed to pay Petroceltic fifteen per cent (15%) of the back costs in relation to the well up to a maximum of US$0.5 million. Petroceltic were due to spud the Elsa-2 well prior to 31 October 2010, but the Italian government passed a decree, following the blowout of the Macondo well in the U.S., that prevented the drilling in the Italian seas within 5 nautical miles of the coastline and within 12 nautical miles around the perimeter of protected Marine Parks. In view of this, Petroceltic suspended the permit until such time as the Ministry of Environment issues a decree of environmental com- patibility for the drilling program. The project in currently on hold and Orca is not liable to any costs associated with the drilling of Elsa-2 until a rig contract is signed. It is currently anticipated that the Elsa-2 well will be drilled in 2013. In December 2010, the Company announced a farm in to Northern Petroleum (UK) Limited’s Longastrino Block in the Po Valley Basin. Under the terms of the farm in, Orca will pay 100% of the costs of the La Tosca well up to a cap of ap- proximately €4.3 million and 70% of the costs thereafter. If the well is tested and completed, Orca will earn an additional 5% (taking it to 75%) by paying 100% of the testing costs up to €1.3 million and 75% thereafter. The La Tosca explora- tion well is expected to be drilled in July 2012 at an estimated cost to the Company of US$8 million. There are no further capital commitments in Italy. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S 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 1 1 A N N U A L R E P O R T 47 48 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O Songo Songo deliverability In Q4 2010 the Company reduced the deliverability from its Songo Songo wells following receipt of results of a corrosion logging survey. Orca suspended production from SS-5, reduced flow rates from the other wells and expedited the tie in of the new onshore well SS10. As of today, the Company can produce approximately 113 MMcfd though this is currently restricted by the infrastructure capacity to a maximum of 102 MMcfd. The original corrosion model forecast that the offshore well, SS-9 (currently producing in the region of 30 MMcfd), would have to be taken out of production at the end of Q1 2012. In October a new corrosion logging programme was undertaken to confirm its condition and it is now considered that the well may stay on production until 31 May 2012. The Company will perform a corrosion log and pressure test the annulus/casing to assess whether SS-9 can continue on production after the end of May 2012. The Company is currently drilling a new onshore deviated well (SS-11) which is expected to be connected to the gas processing plant by the end of July 2012. In the event that SS-9 is taken off production there may be a period where the Company can only deliver approximately 80 MMcfd until SS-11 is connected to the gas processing plant. Songo Songo commitments The total cost of the SS-11 well including its connection to the gas processing plant is estimated at US$33 million and US$12 million was incurred on this prior to 31 December 2011. The Company has also committed to purchasing long lead items for Songo Songo West exploration well, the SS-10 enhancement and one further well at a total cost in 2012 of US$18 million. Additional capital expenditure in Tanzania is dependent on the payments from TANESCO being brought up to date and the satisfactory conclusion of the GNT, satisfactory progress on infrstructure expansion and the subsequent raising of finance. The capital expenditure is required to enable the Songo Songo field to be able to produce 200 MMcfd in line with the anticipated infrastructure expansion. Cost Sharing Agreement In January 2011, the Company signed a cost sharing agreement with Songas, whereby the Company will fund 50% of the costs of getting the Songas Expansion Project (installation of gas processing capacity and downstream compression to increase the infrastructure capacity to 140 MMcfd) to financial close, up to a maximum of US$2.4 million. In the event that the costs are approved by the regulator, EWURA, the funds will be repaid by Songas at financial close. To date the company has funded US$0.6 million of expenditure. If the project is not successful, the costs will be recoverable by the Company under the terms of the PSA as a cost pool expense with TPDC and will be written off to the income statement. Funding The pace and extent of the Company’s 2012 work programme will be dependent on the availability of sufficient capital. The planned 2012 programme includes the drilling of two development wells (SS-11 and SS-12 on Songo Songo Island) and two exploration wells (Songo Songo West and La Tosca in Italy). The drilling of SS-12 is dependent on the immediate receipt of outstanding overdue payments of approximately US$20 million from TANESCO, the securing of a US$10 million overdraft facility and satisfactory progress by the Tanzanian Government on the infrastructure expansion. In addition, the drilling of Songo Songo West will require the Company to secure a debt facility, though this is likely to be dependent on the satisfactory outcome of discussions with the Government Negotiation Team as detailed below. Contingencies Access to infrastructure Ndovu Resources Limited, with support from TPDC and the Ministry of Energy, has indicated that they wish to tie into the gas processing plant on Songo Songo Island and sell up to 10 MMcfd from their Kiliwani North field. It is considered unlikely that this will occur during 2012. Government Negotiation Team In February 2012, the Government announced that it was setting up a Government Negotiation Team (‘GNT’) to discuss a number of issues in relation to the Company’s Production Sharing Agreement (‘PSA’) with the Tanzania Petroleum Development Corporation that was signed in October 2001. The scope of the GNT is to discuss a number of points that were raised by the Parliamentary Committee for Energy and Minerals into the workings of the PSA. This includes, but is not limited to, TPDC back in rights, profit sharing arrangements, the divestment of the downstream assets, cost recovery and Orca’s management of the upstream opera- tions. Orca will discuss these matters in good faith with the GNT, but reserves its rights to defend its position should no satisfactory agreement be reached. Back in TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development. The implications and workings of the ‘back in’ will be discussed with GNT and there may be the need for additional reserve and accounting 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 new drilling activities and other developments and this is reflected in the Company’s net reserve position. Unbundling TPDC and Ministry of Energy and Mines (“MEM”) have indicated that they wish Orca to unbundle the downstream distribution business in Tanzania. The methodology for this is still to be discussed in detail with the GNT. Cost recovery The Company’s cost pool in Tanzania was recovered early in Q2 2011. This resulted in a reduction in the percentage of net revenue attributable to the Company. The level of cost gas will increase during 2012 as a result of significant expen- diture on the drilling activities. TPDC is still in the process of auditing the historic cost recovery pool and is currently disputing US$34 million of costs that have been allocated to the cost pool for the period 2002 through to 2009. The Company contends that the disputed costs were appropriately incurred on the Songo Songo project in accordance with the terms of the PSA. To the extent that it is not possible to satisfactorily resolve the differences with the GNT, the Company will utilise the extensive dispute mechanisms outlined in the PSA which includes international arbitration. Off-Balance Sheet Transactions As at 31 December 2011, the Company had no off-balance sheet arrangements. Related Party Transactions One of the non executive Directors is a partner at a law firm. During the year, the Company incurred US$154,000 to this firm for services provided. The transactions with this related party was made at the exchange amount. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S O R C A E X P L O R A T I O N G R O U P I N C . 2 0 1 1 A N N U A L R E P O R T 49 50 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O SUMMARY QUARTERLY RESULTS The following is a summary of the results for the Company for the last eight quarters: 2011 2010 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 (Figures in US$’000 except where otherwise stated) Financial Revenue 17,500 10,457 8,296 Profit/(loss) after taxation Operating netback (US$/mcf) 5,267 2.41 (54) 1.78 383 1.80 9,640 2,390 2.16 10,557 10,975 1,885 2.28 3,579 2.32 9,017 2,608 2.37 8,259 1,940 2.19 Working capital 56,006 58,369 57,070 55,759 52,364 30,093 24,941 20,891 Shareholders’ equity 106,659 101,563 100,956 100,573 98,183 77,827 73,942 70,955 Profit/(loss) per share – basic (US$) Profit/(loss) per share – 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$) 0.15 0.00 0.01 0.07 0.05 0.12 0.09 0.07 0.15 0.00 0.01 0.07 0.05 0.12 0.08 0.06 10,989 3,463 11 22 239 421 – 41 1,124 364 11 94 899 362 4 91 607 383 – 45 502 692 6 23 320 492 – 77 169 15 – 50 786 719 688 550 687 770 562 485 4 521 4,442 2,965 2,794 2,926 2,918 2,440 2,656 9.94 10.47 10.28 9.42 8.67 8.01 9.45 9.32 2.97 2.76 2.64 2.62 2.63 2.63 2.56 2.56 The principal developments in Q4 2011 were as follows: • Achieved a quarterly sales volume of 5,307 MMcf or 57.6 MMcfd which represents the best quarter since sales began in 2004. Sales revenue amounted to US$17.5 million. • The Company took delivery of the Sakson PR5 drilling rig at Songo Songo Island. The rig commenced drilling the SS-11 (previously SS-A) in February 2012. The SS-11 well is the first well in an extensive drilling and devel- opment programme in Tanzania. • The Company continued to source a rig for the highly prospective Songo Songo West exploration well. • • On 7 October 2011 the Company activated a Normal Course Issuer Bid and received the TSX Venture Exchange approval to purchase upto 1,701,345 Class B shares during the period 10 October 2011 to 9 October 2012. As at the 31st December 2011 a total of 192,000 Class B shares had been re-purchased On 18 November 2011, the Tanzanian Parliament received a report from a special Parliamentary Committee that accused Orca’s subsidiary PanAfrican Energy Limited (“PanAfrican”) of certain irregularities and recom- mended that PanAfrican be removed from the Songo Songo Production Sharing Agreement (“PSA”). The Gov- ernment has set up a Government Negotiation Team to address the Parliamentary Committee concerns. It is assessed that this is the right forum to address and resolve the outstanding issues. However Orca reserves its right to defend its position should no satisfactory agreement be reached. 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 8.5 MMcfd in Q4 2011 (Q4 2010: 7.5 MMcfd). Industrial sales have traditionally peaked in the third quarter of each year as textile customers take advantage of low cotton prices during the harvest season. However the Q4 2011 sales were greater than the 7.8 MMcfd recorded in Q3 2011 as a result of industrial customers using gas for their own power generation. The average sales in Q3 2010 were 8.4 MMcfd. The higher volume recorded in 2011 is primarily due to the sale of Additional Gas to Kioo Glass for power generation, with the sales to Wazo Hill cement plant falling to 1.8 MMcfd in Q4 2011 compared to 2.9 MMcfd in Q4 2010. The average sales price achieved in Q4 was US$9.94/mcf compared to US$8.67/mcf in Q4 2010. 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 2011, sales averaged 49.1 MMcfd compared to 31.8 MMcfd in Q4 2010. This represents the highest daily rate recorded. The increase is a consequence of increased generation and infrastruc- ture capacity. The average price for power sales in Q4 2011 was US$2.97/mcf compared to US$2.63/mcf in Q4 2010. The price of gas to the power sector is set by reference to the initialed Amended and Restated Gas Agreement and the Portfolio Gas Sales Agreement. Profit before tax A profit before taxation of US$8.7 million was recorded in Q4 2011 compared to a profit of US$3.6 million in Q4 2010. The increase is attributable to the increase in Additional Gas sales. Working capital The increase in working capital by US$1.6 million during 2011 is primarily due to higher level of power sales achieved during 2011. SELECTED FINANCIAL INFORMATION Selected annual financial information derived from the audited consolidated financial statements for the years ended 31 December 2009, 2010 and 2011 is set out below: Figures in US$’000 except per share amount Revenue Funds flow from operating activities Profit after taxation Total assets Profit per share: Basic Diluted 2011 45,893 22,658 7,986 151,844 0.23 0.22 2010 38,808 20,836 10,011 124,408 0.33 0.31 2009 25,317 12,332 3,324 86,277 0.11 0.11 Revenue increased by 18% to US$45.9 million in 2011 from US$38.8 million in 2010. The sales volumes were 30% higher in 2011 than 2010, with the weighted average price increasing from US$3.75/mcf to US$3.92/mcf. In 2011, current taxation of US$5.1 million was payable (2010: US$ 2.7 million) which in accordance with the terms of the PSA is recoverable from TPDC. Consequently revenue in 2011 has been uplifted by the gross amount of US$7.3 million (2010: US$3.4 million). The level of industrial volumes increased by, 10% to 2,742 MMcf in 2011 from 2,504 MMcf in 2010, mainly as a consequence of the increase in sales to Kioo Limited. The level of power volumes increased by 35% to 14,722 MMcf (2010:10,940 MMcf). The increase in power sales is attributable to increased generation and infrastructure capacity. Revenue increased by 53% to US$38.8 million in 2010 from US$25.3 million in 2009. The increase was a result of an increase in production volumes of 22% together with a 4% increase in the weighted average realized price from US$3.60/mcf in 2009 to US$3.74/mcf in 2010. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S 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 1 1 A N N U A L R E P O R T 51 52 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O Funds from operations before working capital changes increased by 8% from US$20.8 million in 2010 to US$22.7 million in 2011 as a consequence of increased sales revenue, the impact of which has been reduced by an increase in the level of administrative expenses. The funds from operation grew from US$12.3 million in 2009 to US$20.8 million in 2010 mainly as a result of an increased level of sales. During 2011, the Company’s assets increased by 22% to US$151.8 million (2010: increased 44% to US$124.4 million). The Company’s assets are made up as follows: Figures in US$’000 Current assets Cash and cash equivalents Trade and other receivables Taxation receivable Prepayments Fixed assets Exploration and evaluation assets Plant, property and other equipment Total assets 2011 2010 2009 34,680 40,348 5,880 302 81,210 2,921 67,713 70,634 151,844 45,519 13,583 4,009 409 63,520 942 59,946 60,888 124,408 14,543 8,002 714 465 23,724 760 61,793 62,553 86,277 The decrease in cash and cash equivalents in 2011 is mainly the consequence of the commencement of a drilling programme to increase production to 200 MMcfd. The increase recorded in 2010 was a consequence of the rights issue and the increase in the level of operating revenue. The increase in trade and other receivables is primarily a consequence of the increase in the level of receivables from the electricity producers, TANESCO and Songas Limited, from US$7.7 million to US$27.9 million. Total capital expenditure of US$18.2 million was incurred in 2011 against US$3.4 million in 2010. The expenditure in 2010 was mainly incurred on the evaluation of the Songo Songo West prospect and the connection of the SS-10 well to the gas processing infrastructure. The capital expenditure in 2009 was 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 Songas facilities and connecting the Tegeta 45 MW power generation station. 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, downhole design and integrity, 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 opera- tions 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 and tubing 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. Further- more, Orca Exploration cannot predict whether insurance will continue to be available at a reasonable cost or at all. Foreign Operations Orca Exploration’s operations and related assets are located in Italy and Tanzania which may be considered to be politi- cally and/or economically unstable. Exploration or development activities in Tanzania and Italy 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, nationaliza- tion, renegotiation or nullification of existing contracts and production sharing agreements, 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. In Tanzania the, the state retains ownership of the minerals and consequently retains control of, the exploration and pro- duction 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. Orca’s development properties and its current proved natural gas reserves located offshore on the Songo Songo Island in Tanzania, 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. A Government Negotiation Team (‘GNT’) was set up in February 2012 to address a number of issues raised by the Parliamentary Committee for Energy and Minerals in respect of the Company’s Pro- duction Sharing Agreement (“PSA”). This includes, but is not limited to, TPDC back in rights, profit sharing arrange- ments, the divestment of the downstream assets, cost recovery and Orca’s management of the upstream operations. Orca will discuss these matters in good faith with the GNT and will look to reach a satisfactory agreement that may lead to a change in the economic terms of the PSA. However, the Company reserves its rights to defend its position should no satisfactory agreement be reached. However, there can be no assurance that present or future administrations or governmental regulations in Tanzania will not materially adversely affect the operations or future cash flows of Orca Exploration. Additional Financing Depending on future exploration, development, and marketing plans, Orca Exploration may require additional financing. The ability of Orca Exploration to arrange such financing in the future will depend in part upon the prevail- ing capital market conditions, the business performance of Orca Exploration and the satisfactory conclusion to the discussions with the GNT. 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. Industry Conditions The oil and gas industry is intensely competitive and Orca Exploration competes with other companies which possess greater technical and financial resources. Many of these competitors not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum, natural gas products and other products on an interna- tional 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 Explora- tion operates the Songo Songo natural gas property and has interests in two permits in Italy. 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. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S 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 1 1 A N N U A L R E P O R T 53 54 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 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 in Tanzania may depend upon its ability to develop natural gas markets in Tanzania and the surrounding region, obtain access to the necessary infrastructure to deliver sales gas volumes, including acquiring capacity on pipelines which deliver natural gas to commercial markets. Orca Exploration is also subject to market fluctuations in the prices of oil and natural gas, uncertainties related to the delivery and proximity of its reserves to pipelines and processing facilities and extensive government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and gas and many other aspects of the oil and gas business. Orca Exploration is also subject to a variety of waste disposal, pollution control and similar environmental laws. The oil and natural gas industry is subject to varying environmental regulations in each of the jurisdictions in which Orca Exploration may operate. Environmental regulations place restrictions and prohibitions on emissions of various substances produced concurrently and oil and natural gas and can impact on the selection of drilling sites and facility locations, potentially resulting in increased capital expenditures. Additional Gas Orca Exploration has the right, under the terms of the PSA, to market volumes of Additional Gas subject to satisfying the requirements to deliver Protected Gas to Songas. There is a risk that Songas could interfere in Orca Exploration’s ability to produce, transport and sell volumes of Ad- ditional 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 Explora- tion’s reserves and production will decline over time as reserves are depleted. To the extent that cash flow from opera- tions 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 produc- tion at commercially feasible costs. Asset Concentration Orca Exploration’s natural gas reserves are currently limited to one producing property, the Songo Songo field, and the production potential from this field is limited to five 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, workovers, or new drilling required to achieve deliverability. In addition, any dif- ficulties relating to the operation or performance of the field would have a material adverse effect on Orca Exploration. The Italian licences in which Orca has an interest are currently in the exploration phase of their cycle and it may be several years before Orca is able to obtain a revenue stream from these assets. 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 connec- tion 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 en- vironmental 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 and Italy, 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 regula- tion and increased public awareness concerning environmental protection. No provision has been recognised for future decommissioning costs in Tanzania 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 activi- ties with a view to mitigating its exposure to the risk of price volatility. The terms of the industrial gas supply contracts were extended in 2008 for a period of five years. These 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. 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. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S 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 1 1 A N N U A L R E P O R T 55 56 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O There has 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 infor- mation contained herein represents estimates only. The reserves and estimated future net cash flow from Orca Explo- ration’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 differen- tials 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 de- ficiencies 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 Explo- ration 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 Chief Executive Officer is the beneficial controlling shareholder of Orca Exploration and holds approximately 99.5% of the outstanding Class A shares and approximately 16.6% of the Class B shares. Consequently, Mr. Lyons is the beneficial holder of approximately 20.0% of the equity (22.0% fully diluted) and controls 59.5% of the total votes of Orca Exploration. CRITICAL ACCOUNTING ESTIMATES In applying the Company’s accounting policies, which are described in note 1, management makes estimates and as- sumptions 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, market- ability 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 profit or loss. 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 cir- cumstances 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. Exploration and evaluation assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, or (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation assets are grouped by concession. The technical feasibility and commercial viability of extracting a resource is considered to be determinable based on several factors including the assignment of proven reserves. A review of each exploration license or field is carried out, at least annually, to ascertain whether the project is technically feasible and commercially viable. Upon determination of technical feasibility and commercial viability, intangible exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to a separate category within property and equipment referred to as oil and natural gas interests. O M P A E N R A A G T I E O M N E S N R T E S P O D I R S T C U S S I O N ’ & A N A L Y S I S 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 1 1 A N N U A L R E P O R T 57 58 MANAGEMENT’S DISCUSSION & ANALYSIS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 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 recalcu- lated at each reporting period. IV) Cost recovery The Company is able to recover reasonable costs incurred on the development of the Songo Songo project out of 75% of the gross revenues less processing and pipeline tariffs (“Net Revenue). There are inherent uncertainties in estimating when costs have been recovered as the government has several years to review the reasonableness of the costs. 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 Explo- ration 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 FINANCIAL STATEMENTS & NOTES I O P E R A T O N S R E P O R T 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 1 1 A N N U A L R E P O R T 59 60 MANAGEMENT’S REPORT TO SHAREHOLDERS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 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 accept- able limits of materiality and are in accordance with International Financial Reporting Standards appropriate in the circumstances. Management, with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures and has concluded that such disclosure controls and procedures are effective. Management maintains appropriate systems of internal controls. Policies and procedures are designed to give reasonable assurance that transactions are properly authorised, assets are safeguarded and financial records are properly maintained to provide reliable information for the preparation of financial statements. An independent firm of Chartered Accountants, as appointed by the Shareholders, audited the consolidated financial statements in accordance with the Canadian generally accepted auditing standards to enable them to express an opinion on the fair presentation of the consolidated financial statements in accordance with International Financial Reporting Standards. The Board of Directors carries out its responsibility for the financial reporting and internal controls principally through an Audit Committee. The Audit Committee has met with external auditors and Management in order to determine if Management has fulfilled its responsibilities in the preparation of the consolidated financial statements. The con- solidated financial statements have been approved by the Board of Directors on the recommendation of the Audit Committee. W David Lyons Chairman and Chief Executive Officer 25 April 2012 Nigel Friend Chief Financial Officer 25 April 2012 AUDITORS’ REPORT To the Shareholders of Orca Exploration Group Inc. We have audited the accompanying consolidated financial statements of Orca Exploration Group Inc. which comprise the consolidated statements of financial position as at December 31, 2011 and 2010, the consolidated statements of comprehensive income, changes in shareholders’ equity cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information. Management’s Responsibility for the Consolidated Financial Statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in ac- cordance with International Financial Reporting Standards and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. 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 Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated 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 policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Orca Exploration Group Inc. as at December 31, 2011 and 2010, and its consolidated financial performance and its consolidated cash flows for the years ended December 31, 2011 and 2010 in accordance with International Financial Reporting Standards. Calgary, Canada 25 April 2012 I I O F I N P E A R N A C T O A L N S S T R A E T P E O M R E T N T S 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 1 1 A N N U A L R E P O R T 61 62 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O YEARS ENDED 31 DECEMBER NOTE 2011 2010 (thousands of US dollars except per share amounts) Revenue Cost of sales Production and distribution expenses Depletion expense General and administrative expenses Finance income Finance costs Profit before taxation Taxation Profit after taxation and comprehensive income for the year Earnings per share Basic Diluted See accompanying notes to the consolidated financial statements. 5 12 7 7 8 16 45,893 38,808 (6,088) (8,092) 31,713 (15,440) 85 (1,038) 15,320 (7,334) (4,879) (4,839) 29,090 (11,716) 40 (902) 16,512 (6,501) 7,986 10,011 0.23 0.22 0.33 0.31 CONSOLIDATED STATEMENTS OF FINANCIAL POSITION AS AT 31 DECEMBER (thousands of US dollars) ASSETS Current assets Cash and cash equivalents Trade and other receivables Taxation receivable Prepayments Non-current assets Exploration and evaluation assets Property, plant and equipment Total assets EQUITY AND LIABILITIES Current liabilities Trade and other payables Taxation payable Non-current liabilities Deferred income taxes Deferred additional profits tax Total liabilities Equity Capital stock Contributed surplus Accumulated income Total equity and liabilities NOTE 2011 2010 9 10 11 12 13 8 8 14 15 34,680 40,348 5,880 302 81,210 2,921 67,713 70,634 151,844 22,801 2,403 25,204 15,194 4,787 19,981 45,185 84,610 6,268 15,781 106,659 151,844 45,519 13,583 4,009 409 63,520 942 59,946 60,888 124,408 9,156 2,000 11,156 12,809 2,260 15,069 26,225 85,100 5,288 7,795 98,183 124,408 See accompanying notes to the consolidated financial statements. Future operations (Note 3) Contractual obligations and committed capital investments (Note 19) Contingencies (Note 20) Post balance sheet event (Note 21) The consolidated financial statements were approved by the Board of Directors on 25 April 2012. Director Director I I O F I N P E A R N A C T O A L N S S T R A E T P E O M R E T N T S 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 1 1 A N N U A L R E P O R T 63 NOTE 2011 2010 7,986 10,011 64 CONSOLIDATED STATEMENTS OF CASH FLOWS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O YEARS ENDED 31 DECEMBER (thousands of US dollars) CASH FLOWS FROM OPERATING ACTIVITIES Profit after taxation Adjustment for: Depletion and depreciation Gain on disposal of vehicle Stock-based compensation Deferred income taxes Deferred additional profits tax Interest income Unrealised loss on foreign exchange Increase in trade and other receivables Increase in taxation receivable Decrease in prepayments Increase in trade and other payables Increase in taxation payable Net cash flows from operating activities CASH FLOWS USED IN INVESTING ACTIVITIES Exploration and evaluation expenditures Property, plant and equipment expenditures Interest received Proceeds from sale of vehicle Increase in trade and other payables Net cash used in investing activities CASH FLOWS (USED IN)/FROM FINANCING ACTIVITIES Normal course issuer bid Shares issued Proceeds from exercise of options Net cash flow (used in)/from financing activities (Decrease)/increase in cash and cash equivalents Cash and cash equivalents at the beginning of the year Effect of change in foreign exchange 12 11 14 8 5/8 7 11 12 7 14/15 14 Cash and cash equivalents at the end of the year 9 See accompanying notes to the consolidated financial statements. 8,389 (5) 851 2,385 2,527 (5) 530 22,658 (27,171) (1,871) 107 10,451 403 4,577 (1,979) (16,156) 5 5 3,541 (14,584) (681) – – (681) (10,688) 45,519 (151) 34,680 5,046 – 664 3,741 800 (40) 614 20,836 (6,166) (3,295) 56 2,103 2,000 15,534 (182) (3,199) 40 – 418 (2,923) – 18,471 234 18,705 31,316 14,543 (340) 45,519 CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY (thousands of US dollars) Note Balance as at 1 January 2010 Shares issued Stock options exercised Stock-based compensation Total comprehensive income for the year Balance as at 31 December 2010 Stock-based compensation Normal course issuer bid Total comprehensive income for the year Balance as at 31 December 2011 CAPITAL STOCK CONTRIBUTED SURPLUS ACCUMULATED INCOME/ (LOSS) TOTAL 14 66,267 18,471 362 – – 85,100 – (490) – 84,610 15 4,809 – (128) 607 – 5,288 1,171 (191) – 6,268 (2,216) – – – 10,011 7,795 – – 7,986 15,781 68,860 18,471 234 607 10,011 98,183 1,171 (681) 7,986 106,659 See accompanying notes to the consolidated financial statements. I I O F I N P E A R N A C T O A L N S S T R A E T P E O M R E T N T S 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 1 1 A N N U A L R E P O R T 65 66 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 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 and has gas and oil exploration interests in Italy. The Company’s operations at the Songo Songo gas field in Tanzania include the operation of five 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 Orca has no economic interest in it. Protected Gas 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 Summary of significant accounting policies A) STATEMENT OF COMPLIANCE The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“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 US dollar Orca Exploration Italy Inc British Virgin Islands Orca Exploration Italy Onshore Inc British Virgin Islands PAE PanAfrican Energy Corporation Mauritius PanAfrican Energy Tanzania Limited Jersey Orca Exploration UK Services Limited United Kingdom 100% 100% 100% 100% 100% Euro Euro US dollar US dollar GB Sterling ii) Transactions eliminated upon consolidation Inter-company balances and transactions, and any unrealised gains or losses arising from inter-company transactions, are eliminated in preparing the consolidated financial statements. C) FOREIGN CURRENCY Foreign currency transactions are recorded at the rate of exchange prevailing at the date of the transaction. Monetary assets and liabilities in foreign currencies are translated at period-end rates. Non-monetary items are translated at historic rates, unless such items are carried at market value, in which case they are translated using the exchange rates that existed when the values were determined. Any resulting exchange rate differences are recognized in the profit and loss. 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 to be commercially viable and technologically feasible 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 determina- tion 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 cash generating unit in prior years. A reversal of an impairment loss is recognised as income immediately. I O N O P E T R E A S T T O O N T S H R E E C P O O N R T S O L D A T E D F I N A N C A L I I S T A T E M E N T S 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 1 1 A N N U A L R E P O R T 67 68 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 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 Additional Gas and Protected 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 tariff is paid to Songas as compensation for using the gas processing plant and pipeline. This tariff is netted against revenue. F) 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 in the profit or loss 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, directors and employees. The fair value of stock appreciation rights is expensed in the profit and loss 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 recognized in the income statement. G) ASSET RETIREMENT OBLIGATIONS No provision has been made for future site restoration costs in Tanzania since the Company has currently no legal or contractual or constructive obligation under the PSA to restore the fields at the end of their commercial lives. H) REVENUE RECOGNITION, PRODUCTION SHARING AGREEMENTS AND ROYALTIES The Company recognises revenue related to Additional 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 reasonably incurred 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. I) 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. Deferred APT is provided for by forecasting the total APT payable as a proportion of the forecast Profit Gas over the term of PSA license. 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. J) 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, the Company’s revenue is adjusted for the amount of current tax payable and the income tax is shown as current tax. Deferred tax is provided using the balance sheet 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. K) SEGMENTAL REPORTING The Company has interests in Tanzania and Italy. L) 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 Over remaining life of the lease Computer equipment Vehicles Fixtures and fittings 3 years 3 years 3 years M) NEW ACCOUNTING STANDARDS AND INTERPRETATIONS Certain new accounting standards and interpretations have been published that are not mandatory for the 31 December 2011 reporting period. The following standards are to be adopted for reporting periods beginning January 1, 2013, with the exception of IFRS-9 which has an effective date of January 1, 2015. • • • • • • IFRS 9 Financial Instruments, replaces the guidance of IAS 39 with regards to recognition and measurement. IFRS 10 Consolidated Financial Statements. This standard provides a single model to be applied in control analysis for all categories of investment. IFRS 11 Joint Arrangements are classified into two types, either joint operations or joint ventures, each with their own accounting treatment. All joint arrangements are to be reassessed on transition to IFRS11 to determine their type in oerder to apply the appropriate accounting treatment. IFRS 12 Disclosure of Interest in Other Entities, combines the disclosure requirements for subsid- iaries, associates and joint operations. IFRS 12 Fair Value Measurement establishes a framework for measuring fair value and sets out disclosure requirements. Amendments to IAS 12 Income taxes - Deferred Tax: Recovery of Underlying Assets: effective for annual periods beginning on or after 1 January 2012. Earlier application is permitted; The Company does not plan to adopt these standards early and the extent of their impact on the financial statements has not been determined. I O N O P E T R E A S T T O O N T S H R E E C P O O N R T S O L D A T E D F I N A N C A L I I S T A T E M E N T S 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 1 1 A N N U A L R E P O R T 69 70 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O N) FINANCIAL INSTRUMENTS Non-derivative financial instruments include cash and cash equivalents, trade and other receivables, and trade and other payables. Non-derivative financial instruments are recognized initially at fair value plus any directly attributable transaction costs. The Company has reported cash and cash equivalents at fair value. Cash and cash equivalents are comprised of cash on hand, term deposits held with banks, and other short-term highly liquid investments with original maturities of three months or less. Bank overdrafts that are repayable on demand and form an integral part of the Company’s cash management, whereby management has the ability and intent to net bank overdrafts against cash, are included as a component of cash and cash equivalents for the purpose of the statement of cash flows. The Company’s trade and other receivables, trade and other payables, are classified as other non-derivative financial instruments. Subsequent to the initial recognition, other non- derivative financial instruments are measured at amortized cost using the effective interest method, less any impairment losses. 2 CRITICAL ACCOUNTING ESTIMATES In applying the Company’s accounting policies, which are described in note 1, management makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, vary to the actual results. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below: I) RESERVES There are numerous uncertainties inherent in estimating quantities of proved and probable reserves and cash flows to be derived 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, abandonment provisions, 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 profit or loss. 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 circum- stances 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. Exploration and evaluation assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, or (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation assets are grouped by concession. The technical feasibility and commercial viability of extracting a resource is considered to be determinable based on several factors including the assignment of proven reserves. A review of each exploration license or field is carried out, at least annually, to ascertain whether the project is technically feasible and commer- cially viable. Upon determination of technical feasibility and commercial viability, intangible exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to a separate category within property and equipment referred to as oil and natural gas interests. 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. IV) COST RECOVERY The Company is able to recover reasonable costs incurred on the development of the Songo Songo project out of 75% of the gross revenues less processing and pipeline tariffs (“Net Revenue”). There are inherent uncertainties in estimating when costs have been recovered as the government has several years to review the reasonableness of the costs. 3 FUTURE OPERATIONS AND RISK MANAGEMENT The Company, by its activities in oil and gas exploration, development and production, is exposed to the risk associated with the unpredictable nature of the financial markets. The Company seeks to manage its exposure to these risks where ever possible. I) FUTURE OPERATIONS The Company sells 50% of its operating revenue (2011 - US$45.9 million) to the Tanzanian Electricity Supply Company (“TANESCO”). As at December 31, 2011, TANESCO owes the Company US$24.2 million of which $11.1 million was collected subsequent to year end. As of the date of this report, the Company has also not received payments from TANESCO with respect to any 2012 production. There is a concern that TANESCO’s financial position may be deteriorating as it funds the emergency oil fired generation at a time of declining receipts for electricity from parastatal bodies. The Company has been assured by the Ministry of Energy that TANESCO will pay the outstanding invoices as soon as TANESCO has signed a new financing facility, and that this process is nearing completion. In the event that Company does not collect from TANESCO the outstanding receivables at year end and TANESCO continues to be unable to pay the Company for subsequent 2012 gas deliveries, the Company may need additional funding for its ongoing operations and to continue its committed exploration and development program in 2012. There are no guarantees that such additional funding will be available when needed, or will be available on suitable terms. I O N O P E T R E A S T T O O N T S H R E E C P O O N R T S O L D A T E D F I N A N C A L I I S T A T E M E N T S 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 1 1 A N N U A L R E P O R T 71 72 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O II) 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, Euros 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 U.S. dollars against the relevant foreign currency would result in an overall reduction in working capital by US$1.3 million to US$54.7 million and a reduction in profit before tax to US$14.0 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. III) 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, namely Heavy Fuel Oil (“HFO”). The price of HFO is exposed to the volatility in the market price of oil. IV) INTEREST RATE RISK The Company currently does not have any debt or borrowings so it is therefore not exposed to any interest rate risk. V) 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 The Tanzanian Electricity Supply Company (“TANESCO”) to supply a maximum of 37 MMcfd through to approximately 2023. The contracts with Songas and TANESCO accounted for 60% of the Company’s operating revenue during 2011 and US$28.9 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. Despite having a history of delayed payments, TANESCO has previously settled in full subsequent to each year end. However there is concern that TANESCO financial position may be deteriorating as it funds the emergency oil fired generation at a time of declining receipts for electricity from parastatal bodies. Subsequent to the year end the Company has received US$11.1 million from TANESCO and Songas have settled in full. Sales to industrial sector are subject to an internal credit review to minimize the risk of non payment. The Company has been assured by the Ministry of Energy that TANESCO will pay the outstanding invoices as soon as it has signed a new financing facility which is nearing completion. At the date of this report, TANESCO owes the Company US$22.9 million. VI) 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 regular basis. These are reviewed to ensure sufficient funds exist to finance the Company’s current operational and investment cash flow requirements. The Company has US$22.8 million of financial liabilities with regards to trade and other payables indentified in note 13 of which US$17.1 million is due within one to three months, US$4.9 million is due within three to six months, and US$0.8 million is due within six to twelve months. The Company has a current taxation liability of US$2.4 million payable within three months. Management forecasts that the Company will be able to meet its current liabilities as they fall due through the use of existing cash balances and self generated cash flows. The drilling of SS-12 is dependent on the immediate receipt of outstanding overdue payments of approximately US$20 million from TANESCO, and the securing of a US$10 million overdraft facility and satisfactory progress by the Tanzanian Government on the infrastructure expansion. The drilling of Songo Songo West will, in addition, be dependent on the completion of a debt facility that is currently under discussion. This financing will be dependent on the satisfactory outcome of discussions with the Government Negotiation Team (‘GNT’) that was set up in February 2012 to address a number of issues raised by the Parliamentary Committee for Energy and Minerals in respect of the Company’s Production Sharing Agreement. VII) CAPITAL RISK MANAGEMENT The Company’s objectives when managing capital are to safeguard the Company’s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Company currently has no borrowings. VIII) MATERIAL UNCERTAINTY A Government Negotiation Team (‘GNT’) was set up in February 2012 to address a number of issues raised by the Parliamentary Committee for Energy and Minerals in respect of the Company’s Production Sharing Agreement (“PSA”). This includes, but is not limited to, TPDC back in rights, profit sharing arrangements, the unbundling of the downstream assets, cost recovery and Orca’s management of the upstream operations. Orca will discuss these matters in good faith with the GNT and will look to reach a satisfactory agreement that may lead to a material change in the economic terms of the PSA. However, the Company reserves its rights to defend its position should no satisfactory agreement be reached. 4 Segment Information The Company has one reportable segment which is international exploration, development and production of petroleum and natural gas. The Company currently has producing assets in Tanzania and exploration interests in Italy. Figures in US$’000 External revenue Segment income/(loss) Total assets Total liabilities Capital additions Depletion & depreciation 2011 Tanzania Italy 2010 Tanzania Italy 45,893 – 7,986 – 150,933 45,181 911 4 45,893 7,986 151,844 45,185 38,808 10,057 124,408 26,225 – (46) – – 38,808 10,011 124,408 26,225 17,224 911 18,135 3,381 – 3,381 8,389 – 8,389 5,046 – 5,046 I O N O P E T R E A S T T O O N T S H R E E C P O O N R T S O L D A T E D F I N A N C A L I I S T A T E M E N T S 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 1 1 A N N U A L R E P O R T 73 74 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 5 Revenue Years ended 31 December Figures in US$’000 Operating revenue Current income tax adjustment Deferred additional profits tax Revenue 2011 2010 41,794 6,626 (2,527) 45,893 35,665 3,943 (800) 38,808 The Company’s total revenues for the year amounted to US$45,893,000 after adjusting the Company’s operating revenue of US$41,794,000 by: i) ii) US$ 6,626,000 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$2,527,000 for the deferred effect of additional profits tax. This tax is considered a royalty and is netted against revenue. 6 Personnel expenses The average number of employees during the year was 43 (2010: 36). The costs are as follows: Years ended 31 December Figures in US$’000 Wages and salaries Social security costs Other statutory costs Stock based compensation 2011 4,745 677 312 5,734 851 6,585 2010 2,180 416 527 3,123 664 3,787 The personnel stock based compensation is recorded under general and administrative expenses in the statement of comprehensive income. The balance of personnel expenses for 2011 of US$5.7 million (2010: US$ 3.1million) are recorded in distribution and production expenses and general administrative expenses at US$1.1 million (2010: US$1.0 million) and US$4.6 million (2010: US$2.1 million) respectively. 7 Net financing costs Years ended 31 December Figures in US$’000 Finance income Interest income Foreign exchange gain Finance charges Overdraft charges Other finance costs Foreign exchange loss Net finance costs 2011 2010 5 80 85 – (100) (938) (1,038) (953) 40 – 40 (12) – (890) (902) (862) 8 Taxation 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 when the current tax liability is paid. The tax charge is as follows: Years ended 31 December Figures in US$’000 Current tax Deferred tax 2011 4,949 2,385 7,334 2010 2,760 3,741 6,501 Total taxes of US$4.5 million have been paid during the year in relation to the settlement of the 2010 tax liability and provisional payments for 2011. Total provisional tax payments of US$0.1 million were made in 2010. Tax Rate Reconciliation Years ended 31 December Figures in US$’000 Profit before taxation Provision for income tax calculated at the statutory rate of 30% Add the tax effect of non-deductible income tax items: Administrative and operating expenses Stock- based compensation Other income Permanent differences 2011 2010 15,320 4,596 2,042 255 – 441 7,334 16,512 4,954 1,262 199 (6) 92 6,501 As at 31 December 2011, 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 2011. No deferred tax asset has been recognized in relation to Longastrino Italy. 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 Income tax recoverable Other liabilities Employee bonuses TPDC Additional Profit Gas Additional profits tax 2011 2010 14,409 2,416 (145) (50) (1,436) 15,194 12,194 1,349 (56) – (678) 12,809 I O N O P E T R E A S T T O O N T S H R E E C P O O N R T S O L D A T E D F I N A N C A L I I S T A T E M E N T S 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 1 1 A N N U A L R E P O R T 75 76 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 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 Deferred 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 of 20% is then applied to Profit Gas of US$12.6 million in 2011 (2010: US$3.9 million), accordingly, US$2.5 million (2010: US$0.8 million) has been netted off revenue for the year ended 31 December 2011. Management does not anticipate that any APT will be payable in 2012, as the forecast revenues will not be sufficient to cover the un-recovered costs brought forward as inflated by 25% plus the PPI percentage change and the forecast expen- ditures for 2012. The actual APT that will be paid is dependent on the achieved value of the Additional Gas sales and the quantum and timing of the operating costs and capital expenditure program. The APT can have a significant negative impact on the Songo Songo project economics as measured by the net present value of the cash flow streams. Higher revenue in the initial years leads to a rapid payback of the project costs and con- sequently accelerates the payment of the APT that can account for up to 55% of the Company’s profit share. Therefore, the terms of the PSA reward the Company for taking higher risks by incurring capital expenditure in advance of revenue generation. 9 Cash and cash equivalents As at 31 December Figures in US$’000 2011 2010 Cash and cash equivalents 34,680 45,519 10 Trade and other receivables As at 31 December Figures in US$’000 Trade receivables Other receivables 11 Exploration and evaluation assets Figures in US’000 COSTS As at 1 January 2011 Additions As at 31 December 2011 Figures in US’000 COSTS As at 1 January 2010 Additions As at 31 December 2010 2011 2010 35,714 4,634 40,348 11,879 1,704 13,583 Italy Tanzania Total – 911 911 942 1,068 2,010 942 1,979 2,921 Tanzania Total 760 182 942 760 182 942 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. ITALY During 2010, the Company farmed in to two exploration licences in Italy. Capital costs of US$0.8million were incurred on Northern Petroleum (UK) Limited’s Longastrino Block in the Po Valley Basin. In accordance with the farm-in agreement, together with US$0.1 million of capitalized general administrative costs. All the costs associated with the negotiation of the farm-in in 2010 were recognized in the statement of comprehensive income during 2010. 12 Property, plant and equipment Tanzania Leasehold improvements Computer equipment Vehicles Fixtures & Fittings Total Figures in US’000 Costs As at 1 January 2011 Additions Disposals 80,323 15,691 – As at 31 December 2011 96,014 Depletion and depreciation As at 1 January 2011 Charge for period Depreciation on disposals 20,741 8,092 – As at 31 December 2011 28,833 Net Book Value Figures in US’000 Costs As at 1 January 2010 Additions 77,319 3,004 As at 31 December 2010 80,323 Depletion and depreciation As at 1 January 2010 Charge for period As at 31 December 2010 Net Book Value 15,902 4,839 20,741 320 – – 320 244 27 – 271 509 192 – 701 345 175 – 520 231 47 (29) 249 149 76 (29) 196 108 226 – 334 66 19 – 85 81,491 16,156 (29) 97,618 21,545 8,389 (29) 29,905 265 55 320 220 24 244 455 54 509 230 115 345 161 70 231 102 47 149 92 16 78,292 3,199 108 81,491 45 21 66 16,499 5,046 21,545 As at 31 December 2011 67,181 49 181 53 249 67,713 Tanzania Leasehold improvements Computer equipment Vehicles Fixtures & Fittings Total As at 31 December 2010 59,582 76 164 82 42 59,946 In determining the depletion charge, it is estimated by the independent reserve engineers that future development costs of US$127.8 million (2010: US$115.2 million) will be required to bring the total proved reserves to production. During the year the Company recognized depreciation of US$0.3 million (2010: US$0.2 million) in the general and administrative expenses. I O N O P E T R E A S T T O O N T S H R E E C P O O N R T S O L D A T E D F I N A N C A L I I S T A T E M E N T S O R C A E X P L O R A T I O N G R O U P I N C . 2 0 1 1 A N N U A L R E P O R T 77 78 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 13 Trade and other payables As at 31 December Figures in US$’000 Trade payables Accrued liabilities Related party (note 18) 2011 2010 18,735 3,912 154 22,801 5,896 3,260 – 9,156 The Company’s exposure to credit, currency and interest risk related to trade and other payables is disclosed in note 3. 14 Capital stock a) Authorised 50,000,000 Class A Common Shares 100,000,000 Class B Subordinate Voting Shares No par value No par value The Class A and Class B shares rank pari passu in respect of dividends and repayment of capital in the event of winding-up. Class A shares carry twenty votes per share and Class B shares carry one vote per share. The Class A shares are convertible at the option of the holder at any time into Class B shares on a one-for-one basis. The Class B shares are convertible into Class A shares on a one-for-one basis in the event that a take-over bid is made to purchase Class A shares which must, by reason of a stock exchange or legal requirements, be made to all or substantially all of the holders of Class A shares and which is not concurrently made to holders of Class B shares. b) Changes in the capital stock of the Company were as follows: Thousands of shares or US$’000 Authorised 2011 Issued/ Repurchased 2010 Amount Authorised Issued Amount Class A shares As at 1 January and 31 December Class B shares As at 1 January Shares issued net of costs Stock options exercised Normal course issuer bid 50,000 1,751 983 50,000 1,751 983 100,000 32,939 84,117 50,000 – – – – – – – (192) (490) – – – 27,743 4,956 240 – 65,284 18,471 362 – As at 31 December 100,000 32,747 83,627 50,000 32,939 84,117 Total Class A & B shares as at 31 December 150,000 34,498 84,610 100,000 34,690 85,100 All of the issued capital stock is fully paid. A total of 192,000 Class B Subordinated Voting shares were repurchased under the Normal Course Issuer Bid during 2011 at an average price of Cdn$3.56. STOCK-BASED COMPENSATION The stock option plan provides for the granting of stock options to directors, officers and employees. The exercise price of each stock option is determined at the closing market price of the common shares on the day prior to the day of grant. Each stock option granted permits the holder to purchase one common share at the stated exercise price. The Company records a charge to the profit and loss account using the Black-Scholes fair valuation option pricing model. The valuation is dependent on a number of estimates, including the risk free interest rate, the level of stock volatility, together with an estimate of the level of forfeiture. The level of stock volatility is calculated with reference to the historic traded daily closing share price at the date of issue. Stock Options Thousands of options or Cdn$ Outstanding as at 1 January Exercised Issued 2011 2010 Options Exercise Price Options Exercise Price 2,557 1.00 to 13.55 2,797 1.00 to 13.55 – – 500 3.60 to 4.75 (240) – 1.00 – Outstanding as at 31 December 3,057 1.00 to 13.55 2,557 1.00 to 13.55 The weighted average remaining life and weighted average exercise prices of options at 31 December 2011 were as follows: Exercise Price (Cdn$) 1.00 3.60 to 4.75 8.00 to 13.55 Number Outstanding as at 31 December 2011 Weighted Average Remaining Contractual Life (years) Number Exercisable as at 31 December 2011 Weighted Average Exercise Price (Cdn$) 1,422 500 1,135 3,057 2.67 4.74 0.36 1,422 500 1,135 3,057 1.00 4.18 11.36 There were 500,000 new stock options issued during the year with a weighted average exercise price of Cnd$4.18. The new stock options vest on the date of issue and have a term of five years. A total charge of US$1.2 million has been recognised for the year in relation to the new stock options. Stock Appreciation Rights 2011 2010 Thousands of stock appreciation rights or Cdn$ SAR Exercise Price SAR Exercise Price Outstanding as at 1 January 930 4.20 to 13.55 810 8.0 to 13.55 Expired Granted (i) – – – – Outstanding as at 31 December (ii) 930 4.20 to 13.55 (105) 225 930 11.05 4.20 4.20 to 13.55 (i) (ii) A total of 225,000 stock appreciation rights were issued in June 2010 with an exercise price of Cdn$4.20. These rights have a term of five years and vest in five equal instalments, the first fifth vesting on the anniversary of the grant date. There is no maximum liability associated with these rights. A total of 705,000 stock appreciation rights have a term of five years. All of these options vested over a period of three years and are now fully vested. There is no maximum liability associated with these rights. I O N O P E T R E A S T T O O N T S H R E E C P O O N R T S O L D A T E D F I N A N C A L I I S T A T E M E N T S 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 1 1 A N N U A L R E P O R T 79 80 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 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 trade and other payables. In the valuation of these stock appreciation rights at the reporting date, the following assumptions have been made: a risk free rate of interest of 1.50% to 2.50%, stock volatility of 42% to 75%, 0% dividend yield and 0% forfeiture with a closing stock price of Cdn$2.90 per share. As at 31 December 2011, a total accrued liability of US$0.2 million (2010: US$0.5 million) has been recognised in relation to the stock appreciation rights. The liability was reduced by US$0.3 million during the year as a result of an overall decline in the valuation of the stock appreciation rights. 15 Contributed surplus This is used to record two types of transactions: (i) To recognise the fair value of equity settled stock based compensation expensed in the year. (ii) To account for the difference between the aggregated book value of the shares purchased under the normal course issuer bid and the actual consideration. 16 Earnings per share The calculation of basic earnings per share is based on the profit after taxation and comprehensive income income for the year of US$8.0 million (2010: US$10.0 million) and a weighted average number of Class A and Class B shares outstanding during the period of 34,655,656 (2010: 30,795,013). In computing the diluted earnings per share, the dilutive effect of the stock options was 1,176,161 (2010: 1,098,391) 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 35,831,817 for the year ended 31 December, 2011 (2010: 31,893,104). No adjustments were required to the reported earnings from operations in computing diluted per share amounts. 17 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$110,000 per annum respectively recognized in the general and administrative expenses. As at 31 December Figures in US$’000 Less than one year Between one and five years 18 Related party transactions 2011 2010 222 92 314 232 314 546 One of the non executive Directors is a partner at a law firm. During the year, the Company incurred US$0.2 million (2010: US$0.3 million) to this firm for services provided. The transactions with this related party were made at the exchange amount. As at 31 December 2011 the Company has a total of US$0.2 million recorded in trade and other payables in relation to the related party. 19 Contractual obligations and committed capital investments 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 (65.1 Bcf as at 31 December 2011). The Gas Agreement may be superseded 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 new 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 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. Re-rating Agreement During Q2 2011, the Company signed a Re-rating Agreement with TANESCO and Songas Limited to increase the gas processing capacity to a maximum of 110 MMcfd (the pipeline and pressure requirements at the Ubungo power plant restrict the infrastructure capacity to a maximum of 102 MMcfd). Under the terms of the Re-rating Agreement, the Company effectively pays an additional tariff of US$0.30/mcf for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd in addition to the tariff of US$0.59/mcf payable to Songas as set by the energy regulator, EWURA. Under the terms of this agreement, the Company agreed to indemnify Songas Limited for damage to its facilities caused by the re-rating, up to a maximum of US$15 million, but only to the extent that this was not already covered by indemnities from TANESCO or Songas’ insurance policies. Portfolio Gas Sales Agreement On 17 June 2011, a long term (to June 2023) Portfolio Gas Sales Agreement (PGSA) was signed between Orca and TANESCO. Under the PGSA, Orca is obligated, subject to infrastructure capacity, to sell a maximum of approximately 37 MMcfd for use in any of TANESCO’s current power plants except those operated by Songas at Ubungo. The current basic wellhead gas price of US$ 2.02/mcf is due to increase to approximately US$2.70/ mcf on 1 July 2012. I O N O P E T R E A S T T O O N T S H R E E C P O O N R T S O L D A T E D F I N A N C A L I I S T A T E M E N T S 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 1 1 A N N U A L R E P O R T 81 82 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O CAPITAL COMMITMENTS Italy On 31 May 2010, the Company signed an agreement with Petroceltic International plc (“Petroceltic”) to farm in on Petroceltic’s Central Adriatic B.R268.RG Permit offshore Italy. The farm-in commits the Company to fund 30% of the Elsa-2 appraisal well up to a maximum of US$11.5 million to earn a 15% working interest in the permit. Thereafter, the Company will fund all future costs relating to the well and the permit in proportion to its participating interest. The Company has also agreed to pay Petroceltic fifteen per cent (15%) of the back costs in relation to the well up to a maximum of US$0.5 million. Petroceltic were due to spud the Elsa-2 well prior to 31 October 2010, but the Italian government passed a decree, following the blowout of the Macondo well in the U.S., that prevented the drilling in the Italian seas within 5 nautical miles of the coastline and within 12 nautical miles around the perimeter of protected Marine Parks. In view of this, Petroceltic suspended the permit until such time as the Ministry of Environment issues a decree of environmental compatibility for the drilling program. The project is currently on hold and Orca is not liable to any costs associated with the drilling of Elsa-2 until a rig contract is signed. It is currently anticipated that the Elsa-2 well will be drilled in 2013. In December 2010, the Company announced a farm in to Northern Petroleum (UK) Limited’s Longastrino Block in the Po Valley Basin. Under the terms of the farm in, Orca will pay 100% of the costs of the La Tosca well up to a cap of approximately €4.3 million and 70% of the costs thereafter. If the well is tested and completed, Orca will earn an additional 5% (taking it to 75%) by paying 100% of the testing costs up to €1.3 million and 75% thereafter. The La Tosca exploration well is expected to be drilled in July 2012 at an estimated cost to the Company of US$8 million. There are no further capital commitments in Italy. Songo Songo deliverability In Q4 2010 the Company reduced the deliverability from its Songo Songo wells following receipt of results of a corrosion logging survey. Orca suspended production from SS-5, reduced flow rates from the other wells and expedited the tie in of the new onshore well SS10. As of today, the Company can produce approximately 113 MMcfd though this is currently restricted by the infrastructure capacity to a maximum of 102 MMcfd. The original corrosion model forecast that the offshore well, SS-9 (currently producing in the region of 30 MMcfd), would have to be taken out of production at the end of Q1 2012. In October a new corrosion logging programme was undertaken to confirm its condition and it is now considered that the well may stay on production until 31 May 2012. The Company will perform a corrosion log and pressure test the annulus/casing to assess whether SS-9 can continue on production after the end of May 2012. The Company is currently drilling a new onshore deviated well (SS-11) which is expected to be connected to the gas processing plant later in 2012. In the event that SS-9 is taken off production there may be a period where the Company can only deliver approximately 80 MMcfd until SS-11 is connected to the gas processing plant. Songo Songo commitments The total cost of the SS-11 well including its connection to the gas processing plant is estimated at US$33 million and US$12 million was incurred on this prior to 31 December 2011. The Company has also committed to purchasing long lead items for Songo Songo West exploration well, the SS-10 enhancement and one further well at a total cost in 2012 of US$18 million. Additional capital expenditure in Tanzania is dependent on the payments from TANESCO being brought up to date and the satisfactory conclusion of the GNT, satisfactory progress on infrastrure expansion and the subsequent raising of finance. The capital expenditure is required to enable the Songo Songo field to be able to produce 200 MMcfd in line with the anticipated infrastructure expansion. Cost Sharing Agreement In January 2011, the Company signed a cost sharing agreement with Songas, whereby the Company will fund 50% of the costs of getting the Songas Expansion Project (installation of gas processing capacity and downstream compression to increase the infrastructure capacity to 140 MMcfd) to financial close, up to a maximum of US$2.4 million. In the event that the costs are approved by the regulator, EWURA, the funds will be repaid by Songas at financial close. To date the company has funded US$0.6 million of expenditure. If the project is not successful, the costs will be recoverable by the Company under the terms of the PSA as a cost pool expense with TPDC and will be written off to the income statement. 20 Contingencies Unbundling TPDC and the Ministry of Energy and Mines (“MEM”) have indicated that they wish Orca to unbundle the downstream distribution business in Tanzania. The methodology for this is still to be discussed in detail with the GNT. Access to infrastructure Ndovu Resources Limited, with support from TPDC and MEM, has indicated that they wish to tie into the gas processing plant on Songo Songo Island and sell up to 10 MMcfd from their Kiliwani North field. It is considered unlikely that this will occur during 2012. Government Negotiation Team In February 2012, the Government announced that it was setting up a Government Negotiation Team (‘GNT’) to discuss a number of issues in relation to the Company’s Production Sharing Agreement (‘PSA’) with the Tanzania Petroleum Development Corporation that was signed in October 2001. The scope of the GNT is to discuss a number of points that were raised by the Parliamentary Committee for Energy and Minerals into the workings of the PSA. This includes, but is not limited to, TPDC back in rights, profit sharing arrangements, the unbundling of the downstream assets, cost recovery and Orca’s management of the upstream operations. Orca will discuss these matters in good faith with the GNT, but reserves its rights to defend its position should no satisfactory agreement be reached. Back in TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development. The implications and workings of the ‘back in’ are currently being discussed with the Government Negotiation Team (“GNT”) and there may be the need for reserve and accounting modifications once these discussions are concluded. For the purpose of the reserves certification as at 31 December 2011, it has been assumed that they will ‘back in’ for 20% for all future new wells and other developments and this is reflected in the Company’s net reserve position. Cost recovery The Company’s cost pool in Tanzania was recovered early in Q2 2011. This resulted in a reduction in the percentage of net revenue attributable to the Company. The level of cost gas will increase during 2012 as a result of significant expenditure on the drilling activities. TPDC is still in the process of auditing the historic cost recovery pool and is currently disputing US$34 million of costs that have been allocated to the cost pool for the period 2002 through to 2009. The Company contends that the disputed costs were appropriately incurred on the Songo Songo project in accordance with the terms of the PSA. To the extent that it is not possible to satisfac- torily resolve the differences with the GNT, the Company will utilise the extensive dispute mechanisms outlined in the PSA which includes international arbitration. I O N O P E T R E A S T T O O N T S H R E E C P O O N R T S O L D A T E D F I N A N C A L I I S T A T E M E N T S 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 1 1 A N N U A L R E P O R T 83 84 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS T R O P E R L A U N N A 1 1 0 2 . C N I P U O R G N O I T A R O L P X E A C R O 21 Post balance sheet event In February 2012, the Government announced that it was setting up a Government Negotiation Team (‘GNT’) to discuss a number of issues in relation to the Company’s Production Sharing Agreement (‘PSA’) with the Tanzania Petroleum Development Corporation that was signed in October 2001. The scope of the GNT is to discuss a number of points that were raised by the Parliamentary Committee into the workings of the PSA. This includes, but is not limited to, TPDC back in rights, profit sharing arrangements, the unbundling of the downstream assets, cost recovery and Orca’s management of the upstream operations. Orca will discuss these matters in good faith with the GNT, but reserves its rights to defend its position should no satisfactory agreement be reached. 22 Directors and officers emoluments Figures in US$000 Directors Directors Officers Officers Year 2011 2010 2011 2010 Base 737 357 1,977 1,549 Share based compensation expense – 183 851 481 Bonus – – 580 100 Total 737 540 3,408 2,130 The table above provides information on compensation relating to the Company’s officers and directors. Six officers and six non executive directors comprised the key management personnel during the year ended 31 December 2011 (2010: five officers and five non executive directors). Board of Directors W. David Lyons Chairman and Chief Executive Officer Lord Howard of Lympne Non-Executive Director London United Kingdom Robert Wigley Non-Executive Director John Patterson Non-Executive Director Waterlooville, Hampshire United Kingdom Nanoose Bay Canada Winchester United Kingdom David Ross Non-Executive Director Calgary Canada Officers W. David Lyons Chairman and Chief Executive Officer Winchester United Kingdom Operating Office Orca Exploration Group Inc. Barclays House, 5th Floor Ohio Street, P.O. Box 80139 Dar es Salaam Tanzania Tel: + 255 22 2138737 Fax: + 255 22 2138938 International Subsidiaries PanAfrican Energy Tanzania Limited Barclays House, 5th Floor Ohio Street, P.O. Box 80139 Dar es Salaam Tanzania Tel: + 255 22 2138737 Fax: + 255 22 2138938 Beer van Straten Non-Executive Director Robin Gaeta Non-Executive Director Molkerum Netherlands Wassenaar Netherlands Nigel A. Friend Chief Financial Officer London United Kingdom Registered Office Orca Exploration Group Inc. P.O. Box 3152 Road Town Tortola British Virgin Islands Investor Relations W.D. Lyons Chairman and Chief Executive Officer ahanna@orcaexploration.com www.orcaexploration.com PAE PanAfrican Energy Corporation 1st Floor Cnr St George/Chazal Streets Port Louis Mauritius Tel: + 230 207 8888 Fax: + 230 207 8833 Orca Exploration Group Inc Orca Exploration Italy Inc Orca Exploration Italy Onshore Inc P.O. Box 3152, Road Town Tortola British Virgin Islands Engineering Consultants Auditors Lawyers McDaniel & Associates Calgary, Canada KPMG LLP Calgary, Canada Burnet, Duckworth & Palmer LLP Calgary, Canada Transfer Agent CIBC Mellon Trust Company Toronto & Montreal, Canada C O R P O R A T E I N F O R M A T O N I 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 1 1 A N N U A L R E P O R T 85 www.orcaexploration.com 

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