Orchid Island Capital Annual Report 2013

Plain-text annual report

O R C A E X P L O R A T I O N G R O U P I N C . 2013 ANNUAL REPORT 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 2013 OPERATING HIGHLIGHTS . . . . . 2 CHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS . . . . . 4 GAS RESERVES . . . . . 10 MANAGEMENT’S DISCUSSION & ANALYSIS . . . . . 13 MANAGEMENT’S REPORT TO SHAREHOLDERS . . . . . 50 AUDITORS’ REPORT . . . . . 51 FINANCIAL STATEMENTS . . . . . 52 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS . . . . . 56 CORPORATE INFORMATION . . . . . 87 GLOSSARY mcf MMcf Bcf Tcf MMcfd MMbtu HHV LHV Thousands of standard cubic feet Millions of standard cubic feet Billions of standard cubic feet 1P 2P 3P Proven reserves Proven and probable reserves Proven, probable and possible reserves Trillions of standard cubic feet Kwh Millions of standard cubic feet per day MW Millions of British thermal units US$ Kilowatt hour Megawatt US dollars High heat value Low heat value CDN$ Canadian dollars bar Fifteen pounds pressure per square inch FINANCIAL AND OPERATING HIGHLIGHTS 1 YEARS ENDED/AS AT 31 DECEMBER 2012 % Change US$’000 except where otherwise stated Revenue (Loss)/profit before tax Operating netback (US$/mcf) Cash Working capital (1) Shareholders’ equity Total comprehensive (loss)/income per share - basic (US$) per share - diluted (US$) Funds flow from operating activities (2) per share - basic (US$) per share - diluted (US$) Net cash flows from operating activities per share - basic (US$) per share - diluted (US$) 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 Additional Gas sold (MMcfd) Average price per mcf (US$) - Industrial Average price per mcf (US$) - Power Average price per mcf (US$) - Industrial & Power Additional Gas Gross Recoverable Reserves to end of licence (BCF) (3) Proved Probable Proved plus probable Net Present Value, discounted at 10% (US$ millions) (3) Proved Proved plus probable 2013 54,718 (3,722) 2.20 32,588 27,756 120,252 (5,857) (0.17) (0.17) 77,259 35,454 2.82 16,047 46,820 125,935 18,418 0.53 0.52 39,840 46,264 1.15 1.15 1.33 1.30 22,491 30,883 0.65 0.65 1,751 33,072 1,742 4,478 17,957 12.3 49.2 61.5 8.27 3.76 4.66 476 52 527 365 403 0.88 0.86 1,751 32,892 1,922 3,813 16,832 10.4 46.0 56.4 9.30 3.18 4.31 429 60 489 354 386 (29) n/m (22) 103 (41) (5) n/m n/m n/m (14) (14) (12) (27) (26) (24) – 1 (9) 17 7 18 7 9 (11) 18 8 11 (13) 8 3 4 1. Working capital as at 31 December 2013 includes a TANESCO receivable of US$9.6 million (31 December 2012: US$33.3 million). Given the payment pattern, the TANESCO receivables have been discounted by US$17.1 million and receivables from TANESCO in excess of 60 days of US$47 million have been classified as long-term receivables. Total long and short-term TANESCO receivables as at 31 December 2013 were US$56.6 million prior to discounting. Subsequent to the end of the year, TANESCO paid US$6.4 million, and as at 24 April 2014 the TANESCO balance was US$64.9 million of which arrears total US$60.2 million. 2. See MD&A – Non-GAAP Measures. 3. Based on a report prepared by independent petroleum engineers McDaniel & Associates Consultants Ltd. dated 31 December 2013, which was prepared on 3 April 2014 in accordance with National Instrument 51-101 and definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook. 2 2013 OPERATING HIGHLIGHTS • Orca Exploration operated its Tanzania Songo Songo gas field in 2013 at near plant and pipeline capacity generating record results from production operations. Additional Gas sales volumes increased 9% over 2012 to average 61.5 MMcfd. Overall production of Protected Gas and Additional Gas was essentially flat over 2012 at 96.3 MMcfd (2012: 95.8 MMcfd) and current average production is approximately 94 MMcfd. • The situation with respect to the outstanding accounts receivable from TANESCO is increasingly urgent. In the event that the Company does not collect from TANESCO the balance of the receivables and TANESCO continues to be unable to pay the Company for subsequent gas deliveries, the Company will need additional funding for its ongoing operations by the end of the 2014 fiscal year. • Working capital was US$27.8 million at year-end, down 41% over 2012 (US$46.8 million), a result of reclassifying US$47.0 million (prior to discount) of TANESCO debt as a long-term receivable. As at 31 December 2013, TANESCO owed the Company US$56.6 million of which US$51.5 million was in arrears. • TANESCO currently owes the Company US$64.9 million, of which US$60.2 million is in arrears. Neither TANESCO nor the Government has proposed any plan to address arrears and/or ongoing payments. The Company has served notice to TANESCO and is actively pursuing all legal options available to collect the arrears, and arrest the increase in TANESCO receivables, including but not limited to the suspension of gas deliveries to TANESCO. • Earnings suffered in 2013 with the Company posting a US$5.9 million loss after tax, or US$0.17 loss per share diluted (2012: income US$18.4 million or US$0.52 per share), a result of provisions of US$17.1 million against TANESCO receivables to account for the cost of timing, and US$10.5 million against doubtful debts, primarily Songas. • Average gas prices were up 8% in 2013 to US$4.66/ Mcf (2012: US$4.31/Mcf), Industrial gas prices were down 11% in 2013 to US$8.27/Mcf (2012: US$9.30/ Mcf) from changes in the sales mix, and average Power sector gas prices increased 18% over 2012 to US$3.76/Mcf from US$3.18/Mcf, a result of increased take at higher marginal prices. • The 9% increase in Additional Gas sales volumes together with an 8% increase in the average gas price generated increased gross revenue, but the lack of Cost Pool recoveries due to minimal capital spending during the year reduced the Company’s share of revenue to US$54.7 million (2012: US$77.3 million). • Funds flow from operating activities was down 14% to US$39.8 million or US$1.15 per share (2012: US$46.3 million or US$1.33 per share), a result of lower net revenues partially offset by reduced operating and G&A costs. • The Company ended the year with US$32.6 million in cash and US$1.7 million in debt, double the cash balances of the prior year. Notwithstanding the stronger cash position, the continued TANESCO and Songas non-payments still threaten the Company’s viability and the Company has maintained a going concern note in its 2013 Consolidated Financial Statements. The Company currently has US$35 million in cash and no debt. • During 2013 the Company received a number of assessments for additional tax from the Tanzania Revenue Authority (“TRA”), which together with interest penalties total US$18.4 million. Management together with tax advisors have reviewed each of the assessments and believe them to be without merit. The Company has appealed against assessments for additional withholding tax and employment related taxes, and has filed formal objections against TRA’s claims for additional corporation tax and VAT. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTCHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS3 • The Company ended negotiations on Songo Songo PSA and GNT issues having obtained a full retraction by TPDC of the alleged over-recovery of US$21 million in Cost Pools. The claim was the cornerstone of Parliament’s 2011 resolution advising the Government to terminate the PSA. The Company has committed to use the dispute mechanisms in its agreements to resolve any and all issues going forward, including Cost Pool audits and downstream unbundling. • Establishing commercial terms for future incremental gas sales remains a key condition to the Company’s commitment to Songo Songo development – after a year of proposals from the Company on gas pricing, there has yet to be agreement with TPDC. In the absence of an agreement in the near future, the Company intends to develop other markets for Songo Songo gas. • Despite the stalled efforts to reach commercial terms, the Company continued planning the full development of Songo Songo to reach 190 MMcfd deliverability by mid-2015, beginning designs for workovers of SS-3, SS-5 and SS-9, followed by the drilling of SS-12 and infrastructure, for projected total capital spending of approximately US$165 million. The Company is currently working with a multilateral lending agency International Finance Corporation (“IFC”) to finance the development programme. All development work remains contingent upon (i) satisfactory resolution of TANESCO arrears; (ii) acceptable commercial terms; and (iii) payment guarantees for future gas deliveries to TANESCO. • The Tanzania National Natural Gas Infrastructure Project (“NNGIP”) made significant progress during 2013, with the pipeline currently 72% complete and gas processing facilities 58% complete. Expected onstream date is mid-2015. • In October 2013, the Government of Tanzania issued a National Natural Gas Policy which contemplates a restructuring of the Tanzania Petroleum Development Corporation (“TPDC”), strategic participation throughout the upstream, midstream and downstream sectors, ownership and control over gas infrastructure and setting domestic natural gas prices. The Company expects its rights under the PSA to be respected at such time as the policy is enacted by law in Tanzania. • Songo Songo gas reserves on a Gross Company basis remain solid with an 11% increase in Songo Songo’s Total Proved Additional Gas reserves to the end of the license period, after production of 22.4 Bcf during the year (2012: 20.6 Bcf); an 8% increase in the Proved plus Probable Additional Gas reserves from 489 Bcf to 527 Bcf (based on a report prepared by Orca’s independent reserves evaluator as at 31 December 2013 and dated 3 April 2014 in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook) The increase is primarily due to increased recoverability and adjustments to TPDC back-in, offset by a reduction in the remaining life of the licence. NPV10% 2P was estimated at US$403 million (2012: US$386 million). 4 CHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS With over 20 years in Tanzania, Orca and its predecessors are proud to have played an integral part in establishing the first natural gas-to-electricity development and the first industrial natural gas market in Sub-Saharan Africa. Today production from the Songo Songo gas field supplies 99% of the natural gas used in Tanzania which is in turn used to generate over 65% of the power in the national power grid as well as meeting the energy needs of 37 industrial customers. However until production from recent discoveries of significant offshore gas reserves can be brought online Tanzania faces a steadily growing gap between demand and supply. With first production from the offshore discoveries a decade away, Tanzania has a significant challenge to bridge this gap. It is here that Orca can make the greatest contribution to the country’s future and we welcome the opportunity. We continue to believe that the interests of the Company and the Government are in fact completely aligned. Orca has worked extraordinarily hard to collaborate with all our stakeholders to overcome the obstacles to our success in Tanzania. Unfortunately, this past year saw little reciprocity. Whilst we believe that the Company is making headway, we have yet to be able to deliver to shareholders concrete evidence of substantive progress in Tanzania. The year ended 31 December 2013 saw increases in reserves, the net present value of reserves and increases in Additional Gas volumes. The resulting increase in gross revenue contrasted sharply with reductions in net revenue, funds from operating activities and a total comprehensive loss for the year. The principal factors contributing to reductions in net revenue, funds from operating activities and a total comprehensive loss in the face of improvements in fundamentals include: (i) reduced Cost Gas recovery relative to 2012, the result of insignificant capital expenditure during the year; (ii) a provision against income reflecting the cost of delayed TANESCO receipts; and (iii) a provision against Songas receivables reflecting delays in collection. The situation with respect to the outstanding accounts receivable from TANESCO is increasingly urgent. In the event that the Company does not collect from TANESCO the balance of the receivables and TANESCO continues to be unable to pay the Company for subsequent gas deliveries, the Company will need additional financing to fund its ongoing operations before the end of the 2014 fiscal year. A year of mixed results During 2013 Orca Exploration has continued to operate its Tanzania Songo Songo gas field at maximum deliverability and 99% efficiency. During 2013 the Company delivered record Additional Gas sales of 61.5 million standard cubic feet per day (“MMcfd”). This is an increase of 9% over 2012. TANESCO Receivables continue unabated to US$65 million TANESCO Receivable TANESCO payments s n o i l l i m $ S U 80 70 60 50 40 30 20 10 0 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Apr-14 ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTCHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS With Cost Pools depleted at the beginning of the year, and development work generating only US$1.3 million in capital spending (2012: US$54.7 million), the Company was in full Profit Gas mode throughout the year. This reduced funds flow from operations by 14% to US$39.5 million or US$1.14 per share diluted (2012: US$46.3 million, or US$1.30 per share). Comparing operating results between 2012 and 2013, funds flow can be normalized by taking out capital cost recoveries. This suggests a 33% increase in normalized funds flow over 2012 (US$25 million), reflective of increases in gas prices and volumes along with reduced operating and G&A costs. At year-end, working capital was US$27.8 million, down 41% from 2012 (US$46.8 million) with cash balances of US$32.6 million ( 2012: US$16.0 million). During the year, the Company reclassified US$47 million of the TANESCO receivable as a long-term receivable to reflect the uncertainty of payment within the year. In light of the history of irregular payments and in the absence of a payment plan, a discount of US$17.1 million has been applied to this receivable to reflect the estimated carrying cost as a result of delayed payment. As at the date of this report, the Company has US$35 million in cash and no debt. During 2013 the Company received a number of assessments for additional tax from the Tanzania Revenue Authority (“TRA”), which together with interest penalties total US$18.4 million. Management together with tax advisors have reviewed each of the assessments and believe them to be without merit. The Company has appealed against assessments for additional withholding tax and employment related taxes, and has filed formal objections against TRA’s claims for additional corporation tax and VAT. Average natural gas sales prices increased 8.1% in 2013 to US$4.66/Mcf compared with US$4.31/Mcf the prior year prior, largely as a result of higher prices under the Portfolio Gas Sales Agreement (“PGSA”) with TANESCO. While world energy prices were essentially flat year over year, industrial gas prices in Tanzania were down 11% in 2013 to US$8.27/Mcf (2012: US$9.30/ Mcf). Average power sector gas prices increased 18% over 2012 to US$3.76/Mcf (2012: US$3.18/Mcf). This was primarily as a result of a full year of the step change in the wellhead price in July 2012 (after an annual 2% indexation). The impact of lower revenues due to the full recovery of Cost Pools at the end of 2012, combined with the provisions taken for both the discount on the TANESCO receivable and the allowance against Songas, resulted 5 in a total comprehensive loss of US$5.9 million in 2013, or US$0.17 per share (2012: income of US$18.4 million or US$0.52 per share). Operations and Songo Songo Development Total Songo Songo production for the year averaged 96 MMcfd, essentially flat over 2012 (96 MMcfd). The field is experiencing a natural decline and current average production is approximately 94 MMcfd. Total field and plant uptime was 99%, allowing for planned maintenance. Industrial ) d f c M M 60 40 70 50 Power Additional Gas Volumes ( n o i t c u d o r P s a G Reserves remained solid at Songo Songo with Company gross Proved (1P) and Proved plus Probable (2P) reserves assessed by independent engineers at 476 Bcf and 527 Bcf respectively (2012: 429 Bcf and 489 Bcf). Estimated net present value of the Company’s Songo Songo 2P reserves at a 10% discount rate was US$403 million (2012: US$386 million). The increase in reserves and net present value is due to (i) the continuing increase in performance of the reservoir and (ii) the treatment of the Tanzania Petroleum Development Corporation (“TPDC”) back-in rights on a going forward basis for new wells only. l a n o i t i d d A y l i a d e g a r e v A 30 20 10 0 s n o i l l i m $ S U 50 40 30 20 10 0 2009 2010 2011 2012 2013 Funds flow from operating activities Funds Flow 2009 2010 2011 2012 2013 Despite the financial and commercial challenges faced by the Company, planning for the full development of Songo Songo has continued with the Company and TPDC agreeing on a development plan in Q3. The development of the gas field is constrained by the existing Songas infrastructure (105 MMcfd) and the new NNGIP infrastructure (120 MMcfd net available to the Company). The field development plan contemplates working over the existing high capacity shut-in Songo Songo wells, SS-5 and SS-9, first. This would be followed by the drilling of a new onshore development well, SS-12, along with the installation of the necessary flowlines, inlet compression and inter- connections, to bring total Songo Songo production to approximately 190 MMcfd by mid-2015. 6 However delays in reaching commercial terms for the incremental gas sales through the NNGIP, plus the financial duress brought on by continued TANESCO non-payments, have delayed the start of the programme by a minimum eight months. Had TANESCO made significant arrears payments, the Company could have initiated the workovers as this production could be used to fill the existing Songas capacity and increase sales to Industrial customers. Total capital spending to achieve this plan is estimated to be approximately US$165 million. In order to finance this programme, the Company has engaged IFC to evaluate and potentially fund the project. Financing the development is expected to be dependent on satisfactory commercial terms for a Gas Sales Agreement, including the provision of an acceptable payment security for future gas deliveries. TANESCO payments and arrears 2013 remained a very challenging year financially. The Company billed the state utility and major customer, TANESCO, US$72.9 million in 2013 for gas deliveries including interest on overdue amounts. During the year, the Company received a total of US$49.6 million in seven payments. By year-end TANESCO arrears had reached record heights of US$51.5 million as the utility continued to be unable to make current payments. The payment situation has continued to deteriorate during Q1 2014. As of the date of this report TANESCO owed the Company US$64.9 million. Of this amount, approximately US$23 million will be used to settle the liability to TPDC for its share of the revenue. Since the end of 2013, the Company has received four payments totaling US$6.4 million. Continued non-payment of arrears and current gas sales by TANESCO is not a sustainable situation. At current sales volumes and prices, the Company remains able to maintain operations from Industrial Gas sales alone. However in Tanzania, VAT and Excise Tax are payable by the end of the month following the month in which the delivery of good or services is made, irrespective of any receipts of payment. Orca is not in a position to indefinitely fund VAT and Excise Tax payments without TANESCO receipts. The Government of Tanzania has made no further representations to the Company as to any plans for payment of TANESCO arrears. The Company has notified TANESCO and the Government of Tanzania (the “Government”) of this fact and is reviewing legal options available to collect the arrears and mitigate any further increase in arrears, including but not limited to suspending gas deliveries to TANESCO. To mitigate the potential for a disruption in TANESCO sales, the Company has been supporting the efforts of the World Bank to establish a payment guarantee structure to ensure that payments for future gas deliveries are kept current and arrears do not continue to increase. In late 2013, the Government requested the World Bank to establish payment guarantees for gas producers to ensure continuity of operations and facilitate urgently needed ongoing development. With TANESCO’s failure to make current payments and reduce arrears the World Bank has recognized the connection between the financial distress of TANESCO and the need to develop gas supplies. The World Bank has noted that: “At the same time, a new opportunity is presented by major off-shore natural gas reserves. Existing near-shore natural gas reserves will be critical to enabling the shift to more efficient power generation over the coming three years. Over the longer-term, the abundant quantity of natural gas off-shore reserves that exist in Tanzania represent a potentially transformational opportunity for the country. Beyond serving as a critical source of energy for future power generation plants in Tanzania, natural gas is also a major future source of government revenue and driver of private sector development through the very large investments anticipated in natural gas exploitation. A key challenge is to prepare the country for the natural gas economy and establish strong foundations to take advantage of this potential resource wealth and maximize benefits for Tanzania.” At the end of Q1 2013, the World Bank announced that it had approved a First Power and Gas Development Policy Operation (“DPO”) of US$100 million, the first of three contemplated operations. The objective of the program is to: (i) (ii) (iii) strengthen Tanzania’s ability to bridge the financial gap in its power sector; reduce the cost of power supply and promote private sector participation in the power sector; and strengthen the policy and institutional framework for the management of the country’s natural gas resources. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTCHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS7 TANESCO made tangible progress during 2013 towards sustainability in securing a 39% power tariff increase from the energy regulator, the Energy Water Utilities Regulatory Authority (“EWURA”). This was an important condition of the advancement of the second US$100 million Power and Gas DPO, approved on 26 March 2014 and expected to be disbursed in Q2 2014. Following the first disbursement of the first DPO in 2013, the Company received approximately US$18.7 million from TANESCO towards its arrears and as at the date of this report the Company has yet to be informed as to the quantum of payments if any which may be made as a result of the second DPO. Gas Sales Agreement stalled The Company’s current production capacity is approximately 94 MMcfd, with Songas infrastructure limited to 102 MMcfd. The Songo Songo Field has the potential to more than double current deliverability with producing well workovers and additional drilling. In order to move development forward, in April 2013 the Company initiated discussions for a Gas Sales Agreement (“GSA”) with TPDC for a contemplated 110 MMcfd over the life of the licence (to October 2026) and prepared a development plan which would deliver these volumes into the new NNGIP infrastructure by mid-2015. This new agreement would replace the existing PGSA with TANESCO under which the Company currently delivers approximately 37 MMcfd. Whilst the Government clearly needs to acquire gas supply to fill the NNGIP and substitute natural gas for liquid fuels in country, it has demonstrated throughout a year of negotiations that it is not prepared to accept that economics drive prices. Capital costs, operating costs, timing and PSA terms ultimately dictate the prices required to justify private sector investment. The Company has put forward several proposals over the year, but the Government has not moved from its price expectations. As a result the situation is at an impasse and the Company has recommended TPDC retain an expert advisor and in the interim the Company is investigating alternative markets to sell the incremental gas volumes. A need to respect contract and negotiation terms The Company has been under attack for the last two years, beginning with false accusations in Parliament in late 2011. The pressure continued into 2012 with a Government Negotiating Team (“GNT”) seeking to renegotiate the Songo Songo PSA. From talks between the Company and the GNT an initial framework for an agreement was drafted in mid-2012 subject to a number of conditions. The Company proposed resolution of several major issues including PSA profit sharing ratios, TPDC back-in rights, TANESCO payments, downstream unbundling and disputed Cost Pool recoveries. With none of the Government undertakings that had been agreed in mid-2012 fulfilled by the end of 2013, the Company took the decision to stop negotiating under threat and revert to the terms of the agreements which had been negotiated over a 10-year period and finally approved by Cabinet. With a number of issues overhanging the Company, particularly the alleged US$34 million Cost Pool over- recovery and the alleged US$21 million Songas tariff claim, the Company invoked the dispute resolution mechanisms available under the PSA to put the matters on a definitive timeline for resolution by either mutual agreement or by arbitration. The Company is also committed to utilize the dispute resolution mechanisms in the PGSA to enforce the collection of TANESCO arrears and mitigate increases in arrears, including the right to suspend deliveries of natural gas to the utility. Tangible progress appears to be unfolding. In March 2014, following a Notice of Dispute issued to TPDC, the state corporation acknowledged that the alleged US$21 million Songas tariff claim was erroneous and agreed to make no further claims against the Company on the matter. This allegation was the key foundation of the November 2011 Parliamentary resolution that the Company should repay these monies and that the PSA be terminated. The Company had in fact been wrongly accused and its reputation seriously damaged by this process and the claims that were made. Withdrawal of this claim will help the Company to reestablish its reputation in Tanzania. In other matters there had been no progress by the Controller Auditor General (“CAG”) in reviewing the alleged US$34 million claim of Cost Pool over- recoveries from 2002 to 2009. In response, the Company has initiated a Notice of Dispute with TPDC to conclude the matter. CAG has now appointed an independent auditor from a leading firm to audit the exceptions report, which audit has now commenced. If a mutual agreement is not reached with the aid of the independent review, the Company will refer the matter to ICSID arbitration. 8 Natural Gas Policy issued Responding to the need for Tanzania to develop a comprehensive framework for natural gas exploration and development, the Government of Tanzania issued The National Natural Gas Policy of Tanzania – 2013. From a policy perspective, the Government of Tanzania is seeking to participate across the upstream, mid-stream and downstream sectors of the industry through a national oil company (TPDC) and to regulate the industry through a new regulatory body, formerly under the auspices of TPDC. The Government’s objective is also to promote the development of facilities for natural gas processing, liquefaction, transportation, storage and distribution. To achieve this, the policy contemplates a restructured TPDC, acting as a national aggregator of natural gas, owning and managing natural gas infrastructure. The policy does not contemplate a market-driven gas price structure, but rather a government role in establishing “an appropriate pricing structure” which can both encourage economic use of the system capacities as well as provide incentives for promoting investment. The policy also contemplates strategic involvement by the Government in the LNG value chain and the promotion of efficient LNG production. As part of the Government’s role, as stewards of the country’s national resources, the policy also addresses the management of natural gas revenues, local content, community & social responsibilities and issues of transparency and accountability. Management changes We would like to thank Beer van Straten, who stepped down at the end of 2013 from the role of Chief Operating Officer to join the Advisory Board, for his contribution to the Company. The Company recently appointed Stephen Huckerby as Chief Accounting Officer. Mr. Huckerby has been with Orca since 2007 and has been instrumental in supporting the Company’s economics and business analysis, treasury management and accounting needs. The Company had also discussed unbundling the downstream business as part of the original GNT negotiations and had tabled a proposal with TPDC on the matter. As there is no obligation to unbundle the downstream under the PSA and there was no progress with the proposal, the Company has notified TPDC that the downstream business will remain part of the PSA. National Natural Gas Infrastructure Project on schedule Since the Songo Songo Expansion Project was rejected by the Government in 2011, the Company has been dependent on the Government to execute its own expansion of natural gas infrastructure in the country. In 2012, the Government of Tanzania succeeded in arranging a US$1.2 billion project financing with the Export-Import Bank of China to deliver a major infrastructure expansion project. The 547km Mnazi Bay to Dar es Salaam Gas Pipeline Project is designed to process and transport 785 MMcfd of gas starting at Mnazi Bay (initially three trains of 70 MMcfd for a total of 210 MMcfd initial capacity) as well as a planned tie into a new gas processing facility on Songo Songo (initially two trains of 70MMcfd for a total of 140 MMcfd new capacity). After the NNGIP expansion, Songo Songo is expected to have a total of 210 MMcfd processing and transportation capacity. TPDC contemplates approximately 20 MMcfd capacity to be allocated to production from Kilwa North well operated by Ndovu Resources. The Company is contemplating producing up to 190 MMcfd into the aggregate facilities, of which up to 45 MMcfd would be Protected Gas at no cost/no profit and 145 MMcfd Additional Gas for sale. The plan contemplates leaving the existing Songas system as a separate processing and transportation facility with a capacity of 105 MMcfd. The NNGIP made significant progress during 2013. In November 2012, His Excellency Jakaya Kikwete, President of the United Republic of Tanzania, formally commissioned the start of pipeline construction. According to project manager TPDC substantially all the pipe is in country with 363 km welded and 168 km backfilled. The pipeline construction is 58% complete and 72% weighted average overall pipeline completion prior to commissioning processes. Gas plant construction is 37% and weighted average overall gas plant completion is 58% prior to commissioning processes. The current expectation of TPDC is for construction completion by February 2015 and commissioning in June 2015. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTCHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS9 The Company has also funded completion of a community Dispensary in Kilwa, which includes the construction of an Out Patient Department, a Maternal & Child Health Ward, and Maternity Wing. Once operating, the Dispensary will have a significant positive effect on the local community, providing easily accessible medical support to locals and also to pregnant mothers and children in the region who currently have to walk long distances to access medical services. In recognition of the work Orca has done the Company was the 2013 winner of the first Presidential Award on Corporate Social Responsibility and Empowerment (CSRE), in the category of Oil and Gas Production projects. The objective of the award is to promote and enhance a win-win situation for the extractive industries projects, local communities and Government. The award was given to the Company for its excellent performance in observing the social responsibilities and empowerment in the areas of community wellbeing and sustainability, human resource development and training; social infrastructure such as housing and health services; and infrastructure development. Where do we go from here? Over the past year Orca has worked extraordinarily hard to collaborate with all our stakeholders to overcome obstacles to our mutual success. Going forward we have a responsibility to the people of Tanzania that is reflected in our determination to find solutions that address short term needs and long term aspirations. We also have a responsibility to our shareholders to manage our business responsibly and profitably. Orca is in Tanzania to do business – fairly, equitably and transparently. We take our contractual rights very seriously and will defend them vigorously if need be. Our transparency and commitment is beginning to show progress in early 2014, and I look forward to reporting some significant accomplishments during the year. Corporate Social Responsibility With a 20-year history in Tanzania, the Company feels strongly about giving back to the communities in which we operate. Building upon its existing high impact social development projects, designed to deliver sustainable enhancements to the Songo Songo and Kilwa District communities, Orca has continued to expand its Corporate Social Responsibility Programme in Tanzania during 2013. The Government of Tanzania recognizes that education is the cornerstone of achieving the country’s development goals, and accordingly the Government has invested heavily in education. Orca feels similarly and the Company has focused on its communities’ critical educational and health needs. Orca has committed in excess of US$300,000 to its existing projects, which include sponsoring a further 10 students from Songo Songo through secondary education in Dar es Salam bringing a total number of sponsored students to 38. To increase and broaden the range of positive benefits in the programmes it supports Orca has continued to fund, develop, and coordinate the delivery of an innovative bespoke technology-based English language course that is available in 10 secondary schools in the Kilwa District. The six-week intensive training course is delivered at the start of a child’s secondary education and is designed to aide learning for students transitioning from a primary, Kiswahili- based curriculum to a secondary, English-based curriculum. Encouraging test results from last year’s courses suggests the course delivers a dramatic increase in a child’s ability to learn and will provide significant enhancement of a child’s prospects on graduation. The Company’s intent is to continue to roll out the course across all 28 secondary schools in the district by the year 2015. Orca’s investment in the education of the Tanzanian youth in was also demonstrated in November 2013 by handing over to the community a brand new and fully furnished girl’s dormitory on Songo Songo Island. Accessing high quality education has become extremely expensive for most parents and families on the island, and it is difficult for them to fully invest in the process. The Island’s new dormitory offers young adults on Songo Songo Island the opportunity to attain qualifications close to home in a modern learning environment. W. David Lyons Chairman & CEO 24 April 2014 10 GAS RESERVES In accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (COGEH), independent petroleum engineers McDaniel & Associates Consultants Ltd. prepared a report dated 3 April 2014 that assessed the Company’s natural gas reserves based on information on the Songo Songo Main Field and Songo Songo North as at 31 December 2013 (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 Total Proved (1P) and Proved plus Probable (2P) reserves are based on production to the end of the license period (October 2026). During the course of 2013 no significant geological or geophysical data has been acquired on or close to the Songo Songo field that might allow a re-assessment of the volumetric gas initially in place (“GIIP”) and reserves. On a Gross Company basis there has been a 11% increase in Songo Songo’s Total Proved Additional Gas reserves to the end of the license period, with 9% increase on a life of field basis, with a total Additional Gas production of 22.4 Bcf during the year. There has been an 8% increase in the Proved plus Probable Additional Gas reserves on a Gross Company life of license basis from 489.3 Bcf to 527.3 Bcf. The increase is due to the increased recoverability of reserves and an adjustment to TPDC back-in rights to reflect the strict interpretation of the PSA. The gross and net Company Additional Gas reserves to end of license and end of field life are as follows: Songo Songo 2013 2012 Additional Gas reserves to October 2026 (Bcf) Gross (1) Net (2) Gross Net Independent reserves evaluation Proved producing Proved undeveloped Total proved (1P) Probable Total proved and probable (2P) 304.9 170.8 475.7 51.6 527.3 212.2 100.4 312.6 36.9 349.5 280.0 149.2 429.2 60.1 489.3 181.2 87.8 269.0 37.3 306.3 (1) Gross equals the gross reserves that are available for the Company after estimating the effect of 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. (3) Based on a report prepared by Orca’s independent reserves evaluator as at 31 December 2013 and dated 3 April 2014 in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook. Songo Songo 2013 2012 Additional Gas reserves to end of field life (Bcf) Gross (1) Net (2) Gross Net Independent reserves evaluation Proved producing Proved undeveloped Total proved (1P) Probable Total proved and probable (2P) 573.5 62.3 635.8 113.5 749.3 381.6 39.6 421.2 75.9 497.1 492.6 54.2 546.8 111.4 658.2 314.8 34.6 349.4 68.2 417.6 (1) Gross equals the gross reserves that are available for the Company after estimating the effect of 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. (3) Based on a report prepared by Orca’s independent reserves evaluator as at 31 December 2013 and dated 3 April 2014 in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTOPERATIONS REPORT 11 TPDC has previously indicated an intention to exercise its right under the PSA to ‘back in’ to the Songo Songo field development and a further wish to convert this into a carried interest in the PSA. The current terms of the PSA require TPDC to provide a notice within a defined period of time and contribute a proportion of the costs of any development, sharing in the risks in return for an additional share of the gas. To date, TPDC has neither elected to back in within the prescribed notice period nor contributed any costs associated with backing in and accordingly the Company has determined that to date there has been no working interest earned by TPDC. TPDC back-in rights and the potential conversion of these rights into a carried working interest were discussed with the GNT along with other issues, however nothing was agreed between the parties. Until such time as an agreement is reached, the Company will apply the terms of the original PSA. Should an amendment to the PSA be agreed in future relating to back-in rights, the impact on reserves and accounting estimates will be assessed at that time and reflected prospectively. For the purpose of the reserves certification as at 31 December 2013, the McDaniel Report has assumed that TPDC will only be able to exercise its right to ‘back in’ to the proposed field development plan for Songo Songo and consequently will receive a 20% increase in the profit share for the production emanating from future production from the planned wells SS-12 and SSN-1. 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 its working interest share. For the purpose of calculating the Gross Additional Gas reserves, McDaniel has assumed in its 2P case that 144 Bcf (2012: 162 Bcf) or an average of 13.5 Bcf per annum will be required to meet the demands of the Protected Gas users from 1 January 2014 to 31 July 2024. During 2013, the Protected Gas users consumed 12.7 Bcf. McDaniel forecast gas sales prices and volumes Year 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Additional Gas price Gross Additional Gas volumes Additional Gas price Gross Additional Gas volumes 1P 1P 2P 2P US$/mcf MMcfd US$/mcf MMcfd 4.07 4.12 4.29 4.42 4.50 4.58 4.68 4.77 4.84 4.87 5.03 5.21 5.29 54.86 55.85 96.44 131.09 131.09 131.09 131.09 131.09 119.68 95.89 96.05 98.25 84.72 4.10 4.18 4.39 4.48 4.56 4.65 4.75 4.84 4.94 5.05 5.18 5.36 5.45 54.86 55.85 131.09 131.09 131.09 131.09 131.09 131.09 131.09 131.09 122.31 131.27 110.82 12 Present value of reserves The estimated value of the Songo Songo reserves on a life of license basis based on the assumptions on production and pricing are as follows: US$ millions Proved producing Proved undeveloped Total proved (1P) Probable Total proved and probable (2P) 2013 10% 186.4 178.8 365.2 37.9 5% 265.2 237.3 502.5 57.1 15% 136.0 136.9 272.9 26.8 2012 10% 226.2 127.7 353.9 31.6 5% 312.8 148.5 461.3 51.9 15% 172 107.5 279.5 19.4 559.6 403.1 299.7 513.2 385.5 298.9 There has been a 4% increase on the 2P present value at a 10% discount from US$386 million to US$403 million on a life of licence basis. In 2013 there was change to the proposed development plan, which has seen a greater focus on the work-over of the SS-3, SS-4, SS-5 and SS-9 wells which has in turn led to a delay in the expected timing of the SSN-1 and SS-12 wells. This has resulted in a reduction in the production eligible for TPDC back-in. The timing and quantum of the proposed capital expenditure has changed resulting in a 32% reduction in Additional Profit Tax which has helped to offset the 80% increase in capital expenditure from the 2012 proposed development plan. The 2P life of licence undiscounted cash flow has increased by 14% over 2012. The valuation contemplates the roll out of the current Portfolio Gas Sales Agreement with TANESCO and is consistent with 2012. The reduction in the sales price is a consequence of the assumption that from the commencement of the National Natural Gas Infrastructure Project (“NNGIP”) which for valuation purposes,is contemplated to be on stream by January 2016, future sales to TPDC will be at the well head. As a consequence no estimate has been made for the transportation tariff under the NNGIP. It should not be assumed that the estimates of future net revenues presented in the table above represents the fair market value of the reserves. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTOPERATIONS REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 13 FORWARD LOOKING STATEMENTS This managements’ discussion and analysis (“MD&A”) contains forward-looking statements. More particularly, this MD&A contains statements concerning, but not limited to: repayment of the TANESCO receivables; the need for additional funding by year end for the Company’s ongoing operations if the Company is unable to collect the TANESCO receivables; the actions taken and to be taken by the Company to collect the TANESCO receivables; the Company’s viability and its ability to meet its obligations as they come due; the potential taxes and penalties payable by the Company to the TRA and the Company’s beliefs regarding the assessments and the steps taken and to be taken by the Company to appeal and object to such assessments; status of negotiations with the TPDC regarding a sales agreement for incremental gas volumes and the Company’s plans if an agreement is not reached in the near future; status of execution of a full field development plan for Songo Songo, including the anticipated gas sales volumes, the funding of the development plan, and the contingencies related to the development work; the targeted onstream date for the National Natural Gas Infrastructure Project; anticipated effect of the National Natural Gas Policy on the Company’s rights under the PSA; and the Company’s strategic plans. In addition, statements relating to “reserves” are by their nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. The recovery and reserve estimates of Orca’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward looking statements. Although management believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, operational, competitive, political and social uncertainties and contingencies. These forward-looking statements involve substantial known and unknown risks and uncertainties, certain of which are beyond Orca’s control, and many factors could cause Orca’s actual results to differ materially from those expressed or implied in any forward-looking statements made by Orca, including, but not limited to: failure to receive payments from TANESCO; failure to obtain adequate funding to meet the Company’s obligations as they come due; failure to reach a sales agreement with TPDC for incremental gas volumes; potential negative effect on the Company’s rights under the PSA as a result of the National Natural Gas Policy; risk that the contingencies related to the development work for the full field development plan for Songo Songo are not satisfied; risk that the onstream date for the National Natural Gas Infrastructure Project is delayed; failure to obtain funding for full field development plan for Songo Songo; risk that the Company will be required to pay additional taxes and penalties; the impact of general economic conditions in the areas in which Orca 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; competition for, among other things, capital, drilling equipment and skilled personnel; failure to obtain required equipment for drilling; delays in drilling plans; failure to obtain expected results from drilling of wells; effect of changes to the PSA on the Company; changes in laws; imprecision in reserve estimates; the production and growth potential of the Company’s assets; obtaining required approvals of regulatory authorities; risks associated with negotiating with foreign governments; inability to access sufficient capital; failure to successfully negotiate agreements; and risk that the Company will not be able to fulfill its obligations. In addition there are risks and uncertainties associated with oil and gas operations, therefore Orca’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 that Orca will derive therefrom. Readers are cautioned that the foregoing list of factors is not exhaustive. Such forward-looking statements are based on certain assumptions made by Orca in light of its experience and perception of historical trends, current conditions and expected future developments, as well as other factors Orca believes are appropriate in the circumstances, including, but are not limited to: that the Company will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Company will have adequate funding to continue operations; that the Company will successfully negotiate agreements; receipt of required regulatory approvals; the ability of Orca to add production at a consistent rate; infrastructure capacity; commodity prices will not deteriorate significantly; the ability of Orca to obtain equipment in a timely manner to carry out exploration, development and exploitation activities; future capital expenditures; availability of skilled labour; timing and amount of capital expenditures; uninterrupted access to infrastructure; the impact of increasing competition; conditions in general economic and financial markets; effects of regulation by governmental agencies; that the Company will obtain funding for full field development plan for Songo Songo; that the Company’s appeal of the tax assessment by the TRA will be successful; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; and other matters. The forward-looking statements contained in this MD&A are made as of the date hereof and Orca undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. 14 NON-GAAP MEASURES THE COMPANY EVALUATES ITS PERFORMANCE USING A NUMBER OF NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRIN- CIPLES) MEASURES. THESE NON-GAAP MEASURES ARE NOT STANDARDISED AND THEREFORE MAY NOT BE COMPARABLE TO SIMILAR MEASUREMENTS OF OTHER ENTITIES. • • • • FUNDS FLOW FROM OPERATING ACTIVITIES IS A 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. OPERATING NETBACKS REPRESENT THE PROFIT MARGIN ASSOCIATED WITH THE PRODUCTION 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. FUNDS PER SHARE FROM OPERATING ACTIVITIES IS CALCUALATED ON THE BASIS OF THE FUNDS FLOW FROM OPERATIONS DIVIDED BY THE WEIGHTED AVERAGE NUMBER OF SHARES. NET CASH FLOWS PER SHARE FROM OPERATING ACTIVITIES IS CALCULATED AS CASH FLOW FROM OPERATIONS DIVIDED BY THE WEIGHTED AVERAGE NUMBER OF SHARES. ADDITIONAL INFORMATION REGARDING ORCA EXPLORATION IS AVAILABLE UNDER THE COMPANY’S PROFILE ON SEDAR AT www.sedar.com. BACKGROUND Tanzania The Company’s principal operating asset is its interest in a Production Sharing Agreement (“PSA”) with the Tanzania Petroleum Development Corporation (“TPDC”) and the Government of Tanzania in the United Republic of 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, which includes a gas processing plant on Songo Songo Island, 232 kilometres of pipeline to Dar es Salaam and a 16 kilometre spur to the Wazo Hill Cement Plant. Songas utilizes the Protected Gas (maximum 45.1 MMcfd on any given day, non-cumulative) 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. The Company receives no revenue for the Protected Gas delivered to Songas and operates the field and gas processing plant on a ‘no gain no loss’ basis. Under the PSA, the Company has the right to produce and market all gas in the Songo Songo field in excess of the Protected Gas requirements (“Additional Gas”). ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS15 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. No activity has occurred on the Adriatic Sea block during 2013. In 2012, a new law modified restrictions on offshore oil and gas exploration and production originally introduced by DLGS 128/2010 in August 2010. The Elsa-2 appraisal well is now expected to be drilled in 2015 following finalisation of an environmental impact study. The Company will not be liable to any costs associated with the drilling of Elsa-2 until a rig contract is signed. PRINCIPAL TERMS OF THE TANZANIA 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 sale of Additional Gas may be made from the Discovery Blocks if in the Company’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 reason- ably 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). (d) “Insufficiency” occurs if there is insufficient gas from the Discovery Blocks to supply the Protected Gas requirements or is so expensive to develop that its cost exceeds the market price of alternative fuels at Ubungo. Where there have been third party sales of Additional Gas by the Company and TPDC from the Discovery Blocks prior to the occurrence of the Insufficiency, the Company and TPDC shall be jointly liable for the Insufficiency and shall satisfy its related liability by either replacing the Indemnified Volume (as defined in (e) below) at the Protected Gas price with natural gas from other sources; or by paying money damages equal to the difference between: (a) the market price for a quantity of alternative fuel that is appropriate for the five gas turbine electricity generators at Ubungo without significant modification together with the costs of any modification; and (b) the sum of the price for such volume of Protected Gas (at US$0.55/MMbtu escalated) and the amount of transportation revenues previously credited by Songas to the state electricity utility, the Tanzania Electric Supply Company (“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. 16 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, a subsidiary of Aminex PLC, with support from TPDC and the Ministry of Energy and Mines, had previously indicated that it wished to tie into the gas processing plant on Songo Songo Island and sell up to 10 MMcfd from its Kiliwani North field. Aminex announced in October 2013 that it has engaged in negotiations with TPDC leading to a gas sales agreement which would provide for gas from Kilwa North to be tied in to the new National Natural Gas Infrastructure Project (“NNGIP”) facilities on Songo Songo Island and not be connected into the Songas facilities. 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; 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 an Additional Gas plan (“Additional Gas Plan”) as submitted to the Ministry of Energy and Minerals (“MEM”) 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. To date, TPDC has neither elected to back in within the prescribed notice period nor contributed any costs associated with backing in and accordingly the Company has determined that to date there has been no working interest earned by TPDC. TPDC back-in rights and the potential conversion of these rights into a carried working interest were discussed with the GNT along with other issues, however nothing was agreed between the parties. Until such time as an agreement is reached, the Company will apply the terms of the original PSA. Should an amendment to the PSA be agreed in future relating to back-in rights, the impact on reserves and accounting estimates will be assessed at that time and reflected prospectively. For the purpose of the reserves certification as at 31 December 2013, it was assumed that TPDC will ‘back-in’ for 20% for all future new drilling activities as determined by the current development plan and this is reflected in the Company’s net reserve position. (h) In 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 Amended and Restated Gas Agreement (“ARGA”) and the Portfolio Gas Sales Agreement (“PGSA”) 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. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 17 In 2011, the Company signed a re-rating agreement with TANESCO and Songas (the “Re-Rating Agreement”) 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 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. The Re-rating Agreement expired on 31st December 2012 and in September was extended by Songas to 31 December 2013. There is no need to de-rate the Songas plant. Since then production has continued at the higher rated limit and, given the Gov- ernment’s interest in pursuing further development and increasing gas production, the Company expects this to continue. However there are no assurances that this will occur. (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, based on the higher the cu- mulative production or the average daily sales. 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, its profit share percentage increases by the Specified Proportion (for that development program) with a corresponding decrease in the Company’s per- centage share of Profit Gas. The Company is liable to income tax in Tanzania. Where income tax is payable, the Company pays the tax and there is a corresponding deduction in the amount of the Profit Gas payable to TPDC. (k) Additional Profits Tax (“APT”) 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 APT is payable until the Company recovers its costs out of Additional Gas revenues plus an annual operating return under the PSA of 25% plus the percentage change in the United States Industrial Goods Producer Price Index (“PPI”); and (ii) the maximum APT 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 Gas share can increase with larger daily gas sales and that the costs will be recovered with a 25% plus PPI annual return before APT becomes payable. APT can have a significant negative impact on the project economics if only limited capital expenditure is incurred. 18 Operatorship (l) The Company is appointed to develop, produce and process Protected Gas and operate and maintain the Songas gas production facilities and processing plant, including the staffing, procurement, capital improve- ments, contract maintenance, maintain books and records, prepare reports, maintain permits, handle waste, liaise with the Government of Tanzania and take all necessary safe, health and environmental precautions all in accordance with good oilfield practices. In return, the Company is paid or reimbursed by Songas so that the Company neither benefits nor suffers a loss as a result of its performance. (m) In the event of loss arising from Songas’ failure to perform and the loss is not fully compensated by Songas, the Company, or insurance coverage, then the Company 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 Orca Exploration UK Services Limited Incorporated British Virgin Islands British Virgin Islands British Virgin Islands Mauritius Jersey United Kingdom ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS19 RESULTS FOR THE YEAR ENDED 31 DECEMBER 2013 SUMMARY The year ended 31 December 2013 saw increases in reserves and the net present value of reserves as well as increases in Additional Gas volumes. The resulting increase in gross revenue contrasted sharply with reductions in net revenue, funds from operating activities and a total comprehensive loss for the year. The principal factors contributing to reductions in net revenue, funds from operating activities and a total comprehensive loss in the face of improvements in fundamentals include: (i) reduced Cost Gas recovery relative to 2012, the result of insignificant capital expenditure during the year; (ii) a provision against income reflecting the cost of delayed TANESCO receipts; (iii) a provision against Songas receivables re- flecting delays in collection. OPERATING VOLUMES The total production volume of Protected Gas and Additional Gas for the year was 35,153 MMcf (2012: 35,070 MMcf) or 96.3 MMcfd (2012: 95.8 MMcfd), net of approximately 0.4 MMcfd consumed locally for fuel gas. The Additional Gas sales volumes for the year were 22,435 MMcf (2012: 20,645 MMcf) or 61.5 MMcfd (2012: 56.4 MMcfd). This represents an increase of 9% over 2012. The Company’s sales volumes were split between the Industrial and Power sectors as follows: Gross sales volume (MMcf) Industrial sector Power sector Total volumes Gross average daily sales volume (MMcfd) Industrial sector Power sector Total average daily sales volume YEARS ENDED 31 DECEMBER 2013 2012 4,478 17,957 22,435 12.3 49.2 61.5 3,813 16,832 20,645 10.4 46.0 56.4 Industrial sector Industrial sales volume increased by 17 % to 4,478 MMcf (12.3 MMcfd) from 3,813 MMcf (10.4 MMcfd) in 2012. This is primarily due to (i) increased sales to the two biggest Industrial customers, a major cement producer and a glass producer in the Dar es Salaam area, which in total accounted for 64% of Industrial volumes and (ii) a 12% decrease in Protected Gas consumption as a result of maintenance work on Songas’ power generating turbines, which resulted in increased Additional Gas volumes available for sales. Power sector Power sector sales volumes increased by 7% to 17,957 MMcf or 49.2 MMcfd, compared to 16,832 MMcf or 46.0 MMcfd in 2012. This is a result of continued reliance on gas by TANESCO, the Government owned power utility, to generate power and the increased Additional Gas volumes available for supply following maintenance work on Songas power generating turbines. 20 Capacity constraints As a result of the plant re-rating which occurred in June 2011 the capacity of the Songas gas processing plant was increased to 110 MMcfd, limited by pipeline capacity of 102 MMcfd. The Re-rating Agreement which was signed between the Company, Songas and TPDC, expired on 31 December 2012, but was extended in September 2013 to 31 December 2013, whilst a new agreement is negotiated. Without the Re-rating Agreement in place, Songas may de-rate plant capacity to the original 70 MMcfd, which would result in a material reduction in the Company’s sales volumes of Additional Gas. Large dams feeding TANESCO hydro generation plants are still lacking enough water. As a consequence, the utility is still heavily reliant on natural gas and expensive liquid fuels for generation of electricity. In the event of de-rating of the gas processing plant, the country would likely face severe power rationing whilst it establishes additional liquid fuel generation capability, and incur an even greater cost for power from thermo generation plants, a situation which in the opinion of management is neither in the country’s interest nor economically sustainable. Now rated at 110 MMcfd, management believes that there is no reason to de-rate the Songas Plant and as at the date of this report Songas has not indicated any desire to do so. SONGO SONGO DELIVERABILITY As at 31 December 2013, the Company had a production capacity of approximately 97 MMcfd, with expansion of production volumes currently restricted to 102 MMcfd by the available infrastructure. The high productivity wells drilled by the Company, SS-10 and SS-11, are currently producing approximately 36.7 MMcfd and 38.1 MMcfd respectively. SS-3, SS-5 and SS-9 have been suspended due to production tubing integrity issues and rising casing annulus pressure. SS-4 continues to be monitored and it may have to be suspended in the future. There will, however, be no redundant capacity in the facility or pipeline until additional wells can be drilled in the field or existing wells worked over and facilities expanded. A loss or material reduction in the production of any given well will have a material adverse effect on the total production and funds flow from operations of the Company. Production equipment originally installed in the SS-9, SS-5, SS-4 and SS-3 wells drilled by TPDC between 1976 and 1983 has reached the end of its useful life. The SS-10 well was drilled by the Company in 2007 and SS-11 was drilled in 2012. Expanding the field productive capacity requires the work-over and recompletion of SS-9, SS-5, SS-4 and SS-3, as well as the drilling of an additional development well, SS-12. Significant additional capital expenditure will be required to enable the Songo Songo field to produce 190 MMcfd in line with the anticipated infrastructure expansion. There are no contractual commitments either in the PSA or otherwise agreed for capital expenditure at Songo Songo. Any significant additional capital expenditure by the Company in Tanzania is discretionary and remains dependent on: (i) agreeing commercial terms with TPDC or other buyers regarding the sale of incremental gas volumes from Songo Songo; (ii) TANESCO receivables being brought up to date, guaranteed or other arrangements for payment satisfactory to the Company, (iii) the establishment of payment guarantees with the World Bank or other multi-lateral lending agencies to secure future receipts under any contracts with Government entities; and (iv) the arrangement of finance with the IFC or other lenders. Whilst the Company continues to refine a full field development plan based on expanded infrastructure submitted to the Ministry of Energy and Minerals (“MEM”) during the year, it is not possible to proceed with the plan until the issues outlined above are resolved. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSISCOMMODITY PRICES The commodity prices achieved in the different sectors during the year are shown in the table below: 21 US$/mcf Average sales price Industrial sector Power sector Weighted average price Industrial sector YEARS ENDED 31 DECEMBER 2013 2012 8.27 3.76 4.66 9.30 3.18 4.31 The average gas price achieved for the year was US$8.27/mcf down 11% from (2012: US$9.30/mcf). This is a consequence of sales mix wherein more volumes were sold to customers with relatively lower contractual prices. Power sector The average sales price to the Power sector was US$3.76/mcf for the year (2012: US$ 3.18 /mcf). The 18% increase is due to annual indexation of base price and the result of increased gas sales volumes sold at higher marginal prices under the Amended and Restated Gas Agreement (“ARGA”) and the Portfolio Gas Supply Agreement (“PGSA”). OPERATING REVENUE Under the terms of the Songo Songo PSA, the Company is responsible for invoicing, collecting and allocating the revenue from Additional Gas sales. The Company 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 for recovery out of future revenues. Once the cost pool has been recovered, TPDC is able to recover any pre-approved marketing costs. TPDC marketing costs are treated as a reduction to the Company’s Cost Gas entitlement. The Additional Gas sales volumes for both 2013 and 2012 were in excess of 50 MMcfd entitling the Company to a 55% share of Profit Gas Revenue (less cost recovery share of revenue). The Company was allocated a total of 61% in 2013 (2012: 87%) of the Net Revenues as follows: US$’000 Gross sales revenue Gross tariff for processing plant and pipeline infrastructure Gross revenue after tariff (“Net Revenues”) Analysed as to: Company Cost Gas Company Profit Gas Company operating revenue TPDC share of revenue YEARS ENDED 31 DECEMBER 2013 2012 104,474 (16,138) 88,336 10,231 43,624 53,855 34,481 88,336 89,053 (15,290) 73,763 53,473 10,719 64,192 9,571 73,763 22 The Company’s total revenues for 2013 amounted to US$54,718 after adjusting the Company’s operating revenue of US$53,855 by: i) ii) adding US$14,292 for income tax in the 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 and to account for this, revenue is adjusted to reflect the current year income tax charge, which represents a 30% gross up of the current tax for the year (Note 10); and subtracting US$13,429 for the deferred effect of Additional Profits Tax – this tax is considered a royalty and is netted against revenue. Revenue presented on the Consolidated Statement of Comprehensive Income may be reconciled to the operating revenue as follows: US$’000 Industrial sector Power sector Gross sales revenue Processing and transportation tariff TPDC share of revenue Company operating revenue Deferred Additional Profits Tax Current income tax adjustment Revenue YEARS ENDED 31 DECEMBER 2013 37,040 67,434 104,474 (16,138) (34,481) 53,855 (13,429) 14,292 54,718 2012 35,463 53,590 89,053 (15,290) (9,571) 64,192 (3,463) 16,530 77,259 Revenue is down 29% compared to 2012 from US$77.3 million to US$54.7 million despite a 17% increase in gross sales revenue. This is a consequence of the Company having fully recovered its Cost Pool at the end of 2012 together with limited additions arising from capital expenditure during the year. As a result there has been a 260% increase in TPDC’s share of revenue which has risen to US$34.5 million (2012: US$9.6 million). Additionally there has been a similar increase in deferred Additional Profits Tax provision which has increased to US$13.4 million in 2013 from US$3.5 million in the prior year. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS23 PROCESSING AND TRANSPORTATION TARIFF Since 2011, the Company has paid 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 passes on any increase or decrease in the EWURA approved charges to its customers. This protocol insulates the Company from any increases in the gas processing and pipeline infrastructure costs. In 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 2013 charge for the additional tariff was US$3.2 million (2012: US$3.1 million). PRODUCTION AND DISTRIBUTION EXPENSES The well maintenance costs are allocated between Protected Gas and Additional Gas based on the proportion of their respective sales volumes during the period. The total costs of maintenance for the year was US$864 (2012: US$1,008) of which US$546 (2012: US$954) was allocated for the Additional Gas. The reduction in is primarily due to the absence of major maintenance activities. Other field and operating costs include an apportionment of the annual PSA licence costs, regulatory fees, insurance and some costs associated with the evaluation of the reserves and the cost of personnel that are not recoverable from Songas. Distribution costs represent the direct cost of maintaining the ringmain distribution pipeline and pressure reduction station (security, insurance and personnel). The 57% reduction in costs is primarily due to lower levels of activity. The separation or unbundling of the downstream assets from the production assets has been an objective of TPDC and MEM for some time. The PSA specifically provides for the downstream business and will have to be amended if the downstream assets are to be unbundled. In connection with the 2012 GNT negotiations and Government policy, as expressed in the National Natural Gas Policy issued during the year, TPDC and MEM have indicated that they wish the Company to unbundle the downstream distribution business in Tanzania. Whilst the PSA gives the Company the right to conduct downstream business, methodologies for unbundling which keep the Company economically whole have been discussed. The Company presented potential methodologies during the year for this and is awaiting a response from TPDC. The PSA provides for the Company to be kept economi- cally whole in the event of changes in law. If a mechanism is agreed on mutually acceptable terms, this may lead to change in the presentation of the financial statements, however until such time the Company will retain the downstream business in the PSA. These production and distribution costs are summarized in the table below: US$/mcf Share of well maintenance Other field and operating costs Ringmain distribution costs Production and distribution expenses YEARS ENDED 31 DECEMBER 2013 546 2,474 3,020 1,406 4,426 2012 954 1,744 2,698 3,255 5,953 24 OPERATING NETBACKS The netback per mcf before general and administrative costs, overhead, tax and APT may be analysed as follows: US$’000 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 YEARS ENDED 31 DECEMBER 2013 8.27 3.76 4.66 (0.72) (1.54) 2.40 (0.14) (0.06) 2.20 2012 9.30 3.18 4.31 (0.74) (0.46) 3.11 (0.13) (0.16) 2.82 An 8% increase in the weighted average gas price, from US$4.31/mcf to US$4.66/mcf and savings in operating and distribution costs were more than offset by the Cost Pool recovery effect which resulted in a 260% increase in TPDC share of revenue. This was a consequence of low levels of capital expenditure in 2013 and full recovery of accumulated costs in 2012, resulting in an operating netback for 2013 of US$2.20/mcf compared to US$2.82/mcf in 2012, a reduction of 22%. The 8% increase in the weighted average selling price from US$4.31/mcf to US$4.66/mcf in 2013 is partly a conse- quence of a change in the sales mix resulting in lower average Industrial prices, offset by a 17% increase in Industrial gas volumes, and partly the result of a 18% increase in the Power price as a consequence of contractual step change in wellhead price effective July 2012. The reduction in the well maintenance and other operating costs and distribution costs on a per mcf basis is primarily the result of higher sales volumes and reduced activities during the year. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS25 GENERAL AND ADMINISTRATIVE EXPENSES Administrative expenses (“G&A”) may be analysed as follows: US$’000 Employee & related costs Stock based compensation Office costs Marketing & business development cost including legal fees Reporting, regulatory & corporate General and administrative expenses YEARS ENDED 31 DECEMBER 2013 7,399 (209) 4,635 773 2,830 15,428 2012 8,289 1,152 3,903 1,283 3,362 17,989 The G&A includes the costs of running the natural gas distribution business in Tanzania which is recoverable as Cost Gas and is relatively fixed in nature. G&A averaged approximately US$1.3 million per month in 2013 compared to US$1.5 million in 2012. On a unit basis, G&A per mcf decreased to US$0.69/mcf (2012: US$0.87/mcf) the result of increased sales volumes and lower overall G&A expense. Manpower costs are down, partly offset by higher office costs; as a consequence of setting up new offices in Dar es Salaam and replacing the financial reporting and control systems. Reductions in marketing reporting, regulatory and corporate costs are a consequence of reduced levels of activity. STOCK BASED COMPENSATION The breakdown of the costs incurred in relation to stock based compensation is detailed in the table below: US$’000 Stock options Stock appreciation rights Stock-based compensation YEARS ENDED 31 DECEMBER 2013 – (209) (209) 2012 720 432 1,152 A total of 1,742,400 stock options were outstanding at the end of 2013 compared to 1,922,400 at the end of 2012, a result of 180,000 options being exercised during the year. No options were granted during the year (2012: 400,000). A total of 1,030,000 stock appreciation rights (“SARs”) were outstanding at the end of 2013 compared to 745,000 at the end of 2012. This was the result of 15,000 expiries and the issue in July 2013 of 300,000 SARs with an exercise price of CDN$2.12, a five-year term and which vest in three equal instalments, the first third on the anniversary of the grant date. As SARs are settled in cash, they are re-valued at each reporting date using the Black-Scholes option pricing model. In the valuation of SARS at the reporting date, the following assumptions have been made: a risk free rate of interest of 1.25% stock volatility of 50% to 53%; 0% dividend yield; 0% forfeiture; and a closing price of CDN$2.35 per Class B share. As at 31 December 2013, a total accrued liability of US$0.4 million (2012: US$0.6 million) has been recognised in relation to the SARs in other payables. The liability decreased by US$0.2 million during the year compared to an increase of US$0.4 million in 2012. The decrease in the cost of SARs year over year is due to the decline in the weighted average remaining life of the SARs, a lower share price and a lower volatility of the underlying shares. 26 NET FINANCE INCOME AND FINANCE COSTS The movement in net financing costs is summarized in the table below: US$’000 Interest income Gain on disposal of motor vehicle Finance income Interest expense Net foreign exchange loss Provision for doubtful debts Discount on long-term receivable (see Note 11) Finance costs Net finance costs YEARS ENDED 31 DECEMBER 2013 2,636 10 2,646 (678) (626) (10,531) (17,073) (28,908) (26,262) 2012 23 – 23 (315) (319) – – (634) (611) Interest income of US$2.6 million is due from TANESCO, under the terms of the PGSA, for late payment of gas supplied. This forms part of the TANESCO account receivable balance and has been fully provided against to reflect the uncertainty over the timing of collection. The increase in interest expense is the result of paying interest on a bank loan for the full year. The foreign exchange loss reflects the impact of a fall in the value of the Tanzanian Shilling against the US Dollar over the year on outstanding customer/supplier balances and bank accounts denominated in Tanzanian Shillings. As at 31 December 2013, Songas owed the Company US$24.8 million (2012: US$24.6 million), whilst the Company owed Songas US$16.9 million (2012: US$18.6 million). There is no contractual right to offset these amounts, although in practice the companies have set off receivables and payables. As at the year-end, Songas and the Company formally offset payable and receivable balances of US$17.5 million. Subsequent to the end of the year, the Company has neither received nor paid any amounts in settlement of these balances. Amounts due to Songas primarily relate to pipeline tariff charges of US$15.4 million (2012: US$17.5 million), whereas the amounts due to the Company are mainly for sales of gas of US$11.6 million (2012: US$14.3 million) and for the operation of the gas plant for US$13.3 million (2012: US$10.3 million). The operation of the gas plant is conducted at cost and the charges are billed to Songas on a flow through basis without profit margin. Due to the time for which the set off has been outstanding and the lack of evidence of cash payments from Songas, the Company was unable to recognize the net Songas receivable as at the end of the year and accordingly provided a provision against same (see Note 9). Management continues to negotiate with Songas to reach an offsetting agreement and if, and when, such agreement is reached, the related provision for bad debts will be reversed. Any amounts which are not agreed will be pursued by the Company through the dispute mechanisms provided in its agreements with Songas. Management continues to believe that TANESCO will ultimately settle its debts with the Company. As at the date of this report, however, there is no set schedule or repayment plan for TANESCO arrears proposed or agreed with the Company and payments have been irregular and unpredictable. Based on the actual repayment history as at 31 December 2013, US$9.6 million (2012: US$33.3 million) of the TANESCO receivable was classified as current and US$47.0 million (2012: nil) was classified as long-term. A discount of US$17.1 million has been taken against the long-term receivable to reflect the estimated finance cost of delays in collection. The long-term portion of the trade receivable was discounted using a risk adjusted discount rate of 15% to reflect the cost of delayed timing of collec- tions from TANESCO. The discount rate and the expected timing of the collections are reviewed at each period end with any adjustments recorded in the period that the estimates are changed. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS27 TAXATION Income Tax Under the terms of the PSA 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 increasing the Company’s revenue by the appropriate amount. As at 31 December 2013, 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$12.1 million (2012: US$20.4 million) which represents a decrease in deferred future income tax charges of US$8.3 million for the year (2012: increase of US$5.2 million). This tax has no impact on cash flow until it becomes a current income tax at which point the tax is paid to the Commissioner of Taxes and recovered from TPDC’s share of Profit Gas. Additional Profits Tax Under the terms of the PSA, in the event that all costs have been recovered with an annual return of 25% plus the percentage change in the United States Industrial Goods Producer Price Index (“PPI”) at the operating level, 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. The effective APT rate of 30.8% (2012: 32.3%) was applied to Profit Gas of US$43.6 million (2012: US$10.7 million), accordingly, US$13.4 million (2012: US$3.5 million) has been netted off revenue for the year ended 31 December 2013. As a consequence of having to defer the development programme in 2012 as a direct result of the unsustainable growth in TANESCO receivables and the attempted renegotiation of the PSA initiated by Parliament in late 2011, all previously incurred costs have now been recovered and at an operating level under the PSA the Company has earned a rate of return in excess 25%. Accordingly management expects APT to become payable in 2014. The actual APT that will become payable of the life of the PSA will depend on the achieved value of the Additional Gas sales and the quantum and timing of the operating costs and capital expenditure programme. The APT can have a significant negative impact on the Songo Songo project economics as measured by the net present value of the cash flow streams. Higher revenue in the initial years leads to a rapid payback of the project costs and consequently accelerates the payment of the APT that can account for up to 55% of the Company’s profit share. Therefore, the terms of the PSA rewards the Company for taking higher risks by incurring capital expenditure in advance of revenue generation. DEPLETION AND DEPRECIATION The Natural Gas Properties are depleted using the unit of production method based on the production for the period as a percentage of the total future production from the Songo Songo proven reserves. As at 31 December 2013 the proven reserves as evaluated by the independent petroleum engineers were 475.7 Bcf, on a life of licence basis. A depletion expense of US$12.2 million (2012: US$9.0 million) has been charged, the increase is due to a combination 9% increase in sales volumes and 26% increase in the weighted average depletion rate to US$0.54/ mcf (2012: US$0.43/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 28 CARRYING AMOUNT 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 impaired and recorded in the Consolidated Statement of Comprehensive Income. FUNDS GENERATED BY OPERATIONS Funds from operations before working capital changes were US$39.8 million for 2013 (2012: US$46.3million). US$’000 (Loss)/profit after taxation Adjustments (1) Funds flow from operating activities Working capital adjustments (1) Net cash flows from operating activities Net cash used in investing activities Cash flows (used in)/from financing activities Increase/(decrease) in cash Effect of change in foreign exchange on cash in hand Net increase/(decrease) in cash (1) See Consolidated Statement of Cash Flows YEARS ENDED 31 DECEMBER 2013 (5,465) 45,305 39,840 (17,349) 22,491 (1,288) (4,687) 16,516 25 16,541 2012 18,329 27,935 46,264 (15,381) 30,883 (55,388) 5,665 (18,840) 207 (18,633) The 14% decrease in funds flow from operating activities over 2012 is due primarily to a reduction in revenues. Although gross revenues increased 17% the Company’s share dropped by 16% as a consequence of having fully recovered costs, resulting in a significant increase in TPDC’s share of revenue. Operating revenue with respect to TANESCO and Songas are not fully reflected in the overall cash as a consequence of non-payment by TANESCO of its current invoices during the period and the outstanding Songas payment which is pending agreement on setting off inter-company payables and receivables. The US$16.5 million increase in cash for the year is a result of the US$39.8 million of funds flow from operating activities during the period, offset by an overall net decrease in working capital of US$17.3 million, net loan repayments of US$4.7 million and capital expenditure of US$1.3 million. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS29 CAPITAL EXPENDITURES Capital expenditures amounted to US$1.3 million during the year (2012: US$54.7 million). The significant reduction in capital expenditures is due to the suspension of field development in 2012 pending resolution of TANESCO non- payments and commercial issues. The capital expenditure may be analysed as follows: US$’000 Geological and geophysical and well drilling Pipelines and infrastructure Power development Other equipment YEARS ENDED 31 DECEMBER 2013 (608) 724 – 1,172 1,288 2012 53,059 785 182 669 54,695 Geological and geophysical and well drilling The credit in 2013 reflects cost recoveries achieved from a number of contractors involved in the drilling of SS-11 development well. Pipelines and infrastructure A total of US$0.7 million was incurred during the year on the installation of new customers and enhancing existing customer connections. Other equipment US$0.9 million was incurred to fit out and furnish a new office in Tanzania, a further US$0.3 million was incurred upgrading the Company’s computing and communications network. 30 WORKING CAPITAL Working capital as at 31 December 2013 was US$27.8 million (2012: US$46.8 million) and may be analysed as follows: US$’000 Cash Trade and other receivables TANESCO Songas Other trade debtors Other receivables Provision for doubtful accounts Tax receivable Prepayments Trade and other payables TPDC Songas payables Other trade payables Accrued liabilities Related parties Bank loan Tax payable Working capital (1) Notes: YEARS ENDED 31 DECEMBER 2013 2012 32,588 37,215 16,047 73,495 33,256 14,283 12,791 13,165 – 4,378 17,459 4,458 19,030 171 9,624 11,560 10,874 15,688 (10,531) 20,644 15,355 3,857 13,440 – 14,585 281 84,669 53,296 1,659 1,958 27,756 14,692 246 104,480 45,496 5,842 6,322 46,820 1) Working capital as at 31 December 2013 includes a TANESCO receivable of US$9.6 million (31 December 2012: US$33.3 million). Given the payment pattern, the TANESCO receivables have been discounted by US$17.1 million and receivables from TANESCO in excess of 60 days of US$47 million have been classified as long-term receivables. Total long and short-term TANESCO receivables as at 31 December 2013 were US$56.6 million prior to discounting. Subsequent to the end of the year, TANESCO paid US$6.4 million, and the current TANESCO balance as at 24 April 2014 was US$64.9 million of which arrears total US$60.2 million. Working capital as at 31 December 2013 decreased by 41% during the year, primarily as a result of management’s decision to reclassify US$47.0 million of the receivable from TANESCO as long-term, which has been discounted by US$17.1 million, and to make a provision of US$10.5 million against other receivables which are considered doubtful. Other significant points are: • • • • • At 31 December 2013 the majority of the Company’s cash was held in Mauritius. There are no restrictions on the movement of cash from Mauritius or Tanzania. Since the year end the Company has received US$6.4 million from TANESCO. However, management remains confident that the full amount due from TANESCO will ultimately be received. In addition to the Songas payable and receivable balances highlighted above, other receivables and other payables include a net US$13.3 million due from Songas in relation to the gas plant operation. No contractual right exists allowing the Company to offset these balances. The balance of US$10.9 million relating to other trade debtors has been received in full as at the date of this report. The balance of US$20.6 million payable to TPDC represents the remaining balance of their share of revenue as at 31 December 2013. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 31 BANK LOAN In September 2012, the Company closed a US$10 million 18-month bridge loan facility with a Tanzanian bank to finance the Company’s working capital requirements in Tanzania. The facility is secured by an assignment of accounts receivable and a fixed and floating charge on the assets of the Company. The Company drew the final US$4.0 million in February 2013. The principal drawn under the facility was repayable in 12 equal monthly instalments which commenced in March 2013. Interest was payable monthly at three-month US LIBOR plus 8%. An additional interest rate of 2% would have been applied for any period in which the TANESCO receivable was greater than 240-days. As at 31 December 2013, principal of US$1.7 million was outstanding under the loan, with the remaining balance fully paid in February 2014. GOING CONCERN The Company’s financial statements have been prepared on a going concern basis. The going concern basis of presentation assumes that the Company will continue in operation for the foreseeable future and be able to realize its assets and discharge its liabilities and commitments in the normal course of business. The financial statements do not reflect adjustments that would be necessary if the going concern assumption were not appropriate. If the going concern basis were not appropriate for these financial statements, then adjustments would be necessary in the carrying amounts of assets and liabilities, the reported revenues and expenses, and the balance sheet classifications. The ability of the Company to continue as a going concern is dependent on the Company’s ability to collect its receivables from Government entities to fund on-going operations and the exploration and development programme. The continuing weakness in the financial position of the state utility, TANESCO, has created uncertainty as to whether the Company will be able to collect cash to continue operations and meet its commitments. The immediate need to collect from its debtors may create significant doubt about the Company’s ability to continue as a going concern. In the event that Company does not collect from TANESCO the balance of the outstanding receivables at 31 December 2013 and TANESCO continues to be unable to pay the Company for subsequent 2014 gas deliveries, the Company will need additional funding for its ongoing operations before the end of the current fiscal year. There are no guarantees that such additional funding will be available when needed, or will be available on suitable terms. The Company has served notice to TANESCO demanding payment in full and is reviewing legal options available to collect the arrears and mitigate a further increase in arrears, including but not limited to suspending gas deliveries to TANESCO. The material uncertainties that may cast significant doubt on the Company’s ability to continue as a going concern are set forth below.The Company generates in excess of 65% of its operating revenue from sales to the Power sector companies, Songas and TANESCO. The financial security of Songas is heavily reliant on the payment of capacity and energy charges by TANESCO, which in turn is dependent on the Government of Tanzania to subsidise a significant portion of TANESCO’s operating budget. Prior to 2012, despite having a history of delayed payments, TANESCO had settled in full the outstanding balance subsequent to each quarter end. At 31 December 2013, TANESCO owed the Company US$56.6 million gross prior to discount (including arrears of US$51.5 million) compared to US$33.3 million (including arrears of US$28.4 million) as at 31 December 2012. During the year the Company received a total of US$49.6 million (2012: US$16.4 million) from TANESCO and, subsequent to year-end, TANESCO paid the Company a further US$6.4 million. As of the date of this report, the outstanding balance is US$64.9 million of which US$60.2 million is in arrears. 32 At the end of Q1 2013, the World Bank approved a Tanzania First Power and Gas Development Policy Operation (“DPO”) of US$100 million, the first in a programme of three contemplated operations. The objective of the programme is to: (i) strengthen the Tanzania’s ability to bridge the financial gap in its power sector; (ii) reduce the cost of power supply and promote private sector participation in the power sector; and (iii) strengthen the policy and institutional framework for the management of the country’s natural gas resources. TANESCO made tangible progress in late 2013 towards sustainability in securing a 39% power tariff increase from the energy regulator, the Energy Water Utilities Regulatory Authority (“EWURA”). This was an important condition of the advancement of the Second US$100 million Power and Gas DPO, approved on 26 March 2014 and expected to be disbursed in Q2 2014. The Company received payment of approximately US$18.7 million in 2013 from TANESCO around the time of the disbursement of the First DPO and as at the date of this report has yet to be informed as to the quantum of payments if any which may be made as a result of the Second DPO. Management continues to believe that TANESCO will ultimately settle its debts with the Company. As at the date of this report, however, there is no set schedule or repayment plan for TANESCO arrears proposed or agreed with the Company and payments have been irregular and unpredictable. Based on the actual repayment history as at 31 December 2013, US$9.6 million (2012: US$33.3 million) of the TANESCO receivable was classified as current and US$47.0 million (2012: nil) was classified as long-term. A discount of US$17.1 million has been taken against the TANESCO receivable to reflect the estimated finance cost of delays in collections. The trade receivable was discounted using a risk adjusted discount rate of 15% to reflect the delayed timing of collections from TANESCO. The discount rate and the expected timing of the collections are reviewed at each period end with any adjustments recorded in the period that the estimates are changed. As at 31 December 2013, Songas owed the Company US$24.8 million (2012: US$24.6 million), whilst the Company owed Songas US$16.9 million (2012: US$18.6 million). There is no contractual right to offset these amounts, although in practice the companies have set off receivables and payables. As at the year-end, Songas and the Company formally offset payable and receivable balances of US$17.5 million. Subsequent to the end of the year, the Company has neither received nor paid any amounts in settlement of these balances. Amounts due to Songas primarily relate to pipeline tariff charges of US$15.4 million (2012: US$17.5 million), whereas the amounts due to the Company are mainly for sales of gas of US$11.6 million (2012: US$14.3 million) and for the operation of the gas plant for US$13.3 million (2012: US$10.3 million). The operation of the gas plant is conducted at cost and the charges are billed to Songas on a flow through basis without profit margin. Due to the time for which the set off has been outstanding and the lack of evidence of cash payments from Songas, the Company was unable to recognize the net Songas receivable as at the end of the year and accordingly provided a provision against same (see Note 9). Management continues to negotiate with Songas to reach an offsetting agreement and if, and when, such agreement is reached, the related provision for bad debts will be reversed. Any amounts which are not agreed will be pursued by the Company through the dispute mechanisms provided in its agreements with Songas. In 2012, to help alleviate the funding gap caused by the delays in TANESCO payments, the Company entered into a US$10 million debt facility with a bank in Tanzania. By February 2013, the Company had drawn down the facility. Repayments commenced in March 2013 and the loan balance as at 31st December 2013 was US$1.7 million. By February 2014, the loan had been fully repaid. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS33 SHAREHOLDERS’ EQUITY AND OUTSTANDING SHARE DATA There were 34.8 million shares outstanding as at 31 December 2013 which may be analysed as follows: Number of shares (‘000) Shares outstanding Class A shares Class B shares Class A and Class B shares Convertible securities Options Fully diluted Class A and Class B shares Weighted average Class A and Class B shares Convertible securities Options Weighted average diluted Class A and Class B shares The movement in Class B shares during the year is analysed in the table below: Number of shares (‘000) As at 1 January Stock options exercised Normal course issuer bid As at 31 December 2013 2012 1,751 33,072 34,823 1,742 36,565 1,751 32,892 34,643 1,922 36,565 34,719 34,642 – 34,719 2013 32,892 180 – 33,072 811 35,453 2012 32,746 150 (4) 32,892 As at 24 April 2014, there were a total of 33,072,015 Class B shares and 1,751,195 Class A shares outstanding. Stock Options Thousands of options or CDN$ Options Exercise Price Options Exercise Price 2013 2012 Outstanding as at 1 January 1,922 1.00 to 3.60 Forfeited/Expired Exercised Issued – (180) – – 1.00 – Outstanding as at 31 December 1,742 1.00 to 3.60 3,057 (1,385) (150) 400 1,922 1.00 to 13.55 4.75 to 13.55 1.00 3.18 1.00 to 3.60 34 The weighted average remaining life and weighted average exercise prices of options at 31 December 2013 were as follows: Exercise Price (CDN$) Number outstanding as at 31 Dec 2013 (‘000) Weighted Average Remaining Contractual Life (years) Number Exercisable as at 31 Dec 2013 (‘000) Weighted Average Exercise Price (CDN$) 1.00 3.18 3.60 1,092 400 250 1,742 0.67 4.00 2.75 1,092 400 250 1,742 1.00 3.18 3.60 No new stock options were issued during the year . Stock Appreciation Rights 2013 2012 Thousands of stock appreciation rights or CDN$ Outstanding as at 1 January Expired Granted (1) SAR 745 (15) 300 Exercise Price 2.35 to 5.30 5.30 2.12 Outstanding as at 31 December 1,030 2.12 to 4.20 SAR 1,005 (690) 430 745 Exercise Price 4.20 to 13.55 8.70 to 13.55 2.35 to 2.70 2.35 to 5.30 (1) A total of 300,000 stock appreciation rights were issued in July 2013 with an exercise price of CDN$2.12. These rights have a term of five years and vest in three equal instalments, the first third vesting on the anniversary of the grant date. There is no maximum liability associated with these rights. The Company records a charge to the income statement using the Black-Scholes fair valuation option pricing model every reporting period with a resulting liability being recognised in trade and other payables. In the valuation of the stock appreciation rights at the reporting date, the following assumptions have been made: a risk free rate of interest of 1.25%; stock volatility of 50% to 53%; a 0% dividend yield; 0% forfeiture; and a closing stock price of CDN$2.35 per share. As at 31 December 2013, a total accrued liability of US$0.4 million (2012: US$0.6 million) has been recognised in relation to the stock appreciation rights. The liability decreased by US$0.2 million during the year compared to an increase of US$0.4 million in 2012. Earnings per share The calculation of basic earnings per share is based on the comprehensive loss for the year of US$5.9 million (2012: income US$18.4 million) and a weighted average number of Class A and Class B shares outstanding during the period of 34,718,622 (2012: 34,641,593). In computing the diluted earnings per share, the effect of stock options is added to the weighted average number of common shares outstanding during the year. For 2013 the effective number was nil (2012: 811,386) shares, resulting in a diluted weighted average number of Class A and Class B shares of 34,718,622 for the year ended 31 December 2013 (2012: 35,452,979). No adjustments were required to the reported earnings from operations in computing diluted per share amounts. A total of 617,444 options were excluded as a result of being anti-dilutive to earnings per share. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS35 RELATED PARTY TRANSACTIONS One of the non-executive Directors is a partner at a law firm. During the year, the Company incurred US$0.1 million (2012: US$0.4 million) to this firm for services provided. The transactions with this related party were made at the exchange amount. As at 31 December 2013 the Company has a total of US$nil (2012 : US$0.2 million) recorded in trade and other payables in relation to the related party. The Chief Financial Officer provided services to the Company through a consulting agreement with a personal services company. During the year the Company incurred fees and bonus compensation of US$0.6 million in respect of these services (2012: US$0.5 million). In 2012 the Chief Executive Officer also provided services to the Company through a consulting agreement and the Company incurred US$0.2 million in costs. The full Chief Executive Officer’s remuneration is included in Directors’ Emoluments (see Note 21). 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 escalating) 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 (108.3 Bcf as at 31 December 2013). The Company did not have a shortfall during the reporting period and does not anticipate a shortfall arising during the term of the Protected Gas delivery obligation to July 2024. The Gas Agreement may be superseded by an initialed 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 it whole in the event of a Protected Gas insufficiency. Should the IA be 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 is required to fund an escrow account at a rate of US$2.00/MMbtu on all Industrial Ad- ditional 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, supported by the report of its independent engineers, does not anticipate that a liability will occur in this respect. Re-rating Agreement During 2011, the Company signed a re-rating agreement with TANESCO and Songas (the “Re-Rating Agreement”) 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 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. The Re-rating Agreement expired on 31 December 2012 and in September was extended by Songas to 31 December 2013. At this time, the Company knows of no reason to de-rate the Songas plant. Since 31 December 2013 production has continued at the higher rated limit and, given the Government’s interest in pursuing further development and increasing gas production, the Company expects this to continue. However there are no assurances that this will occur. 36 Portfolio Gas Supply Agreement In June 2011, a long term (to June 2023) PGSA was signed between the Company, TPDC and TANESCO. Under the PGSA, the seller 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. Under the agreement, the current basic wellhead gas price is approximately US$2.88/mcf which price will increase to US$2.94/mcf on 1 July 2014. Any volumes of gas delivered under the PGSA in excess of 36 MMcfd are subject to a 150% increase in the basic wellhead gas price. Operating leases The Company has two office rental agreements, one in Dar es Salaam, Tanzania and one in Winchester, United Kingdom. The agreement in Dar es Salaam was entered into on 1 November 2013 and expires on 31 October 2015 at an annual rent of US$401 thousand. The agreement in Winchester expires in September 2022 and is at an annual rental of GBP35 thousand (US$58 thousand) per annum during 2012 and 2013 and GBP71 thousand (US$115 thousand) per annum thereafter. The costs of these leases are recognised in the General and Administra- tive expenses. 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. There- after, 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. No activity has occurred on the Adriatic Sea block during 2013. In 2012, a new law modified restrictions on offshore oil and gas exploration and production originally introduced by DLGS 128/2010 in August 2010. The Elsa-2 appraisal well is now expected to be drilled in 2015 following finalisation of an environmental impact study. The Company will not be liable to any costs associated with the drilling of Elsa-2 until a rig contract is signed. There are no further capital commitments in Italy at this time. Songo Songo Significant additional capital expenditure will be required to enable the Songo Songo field to produce 190 MMcfd in line with the anticipated infrastructure expansion. There are no contractual commitments either in the PSA or otherwise agreed for capital expenditure at Songo Songo. Any significant additional capital expenditure in Tanzania is discretionary and remains dependent on: (i) agreeing commercial terms with TPDC or other buyers regarding the sale of incremental gas volumes from Songo Songo; (ii) TANESCO receivables being brought up to date, guaranteed or other arrangements for payment satisfactory to the Company, (iii) the establishment of payment guarantees with the World Bank or other multi-lateral lending agencies to secure future receipts under any contracts with Government entities; and (iv) the arrangement of finance with the IFC or other lenders. The Company currently plans to finance Songo Songo development with a combination of cash, collection of TANESCO and Songas receivables, funds flow from operations, bank debt and financing to be arranged by IFC. There are no assurances that financing will be available or on reasonable terms to fund all or a portion of the Songo Songo development programme. The Company does not currently have any off-balance sheet financing arrangements. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS37 CONTINGENCIES Downstream unbundling The separation or unbundling of the downstream assets from the production assets has been an objective of TPDC and MEM for some time. The PSA specifically provides for the downstream business and will have to be amended if the downstream assets are to be unbundled. Unbundling was an issue raised by TPDC in the 2012 GNT negotiations and in the recently issued National Natural Gas Policy which policy contemplates TPDC as a monopoly aggregator and distributor of gas in Tanzania. In the context of the gas policy, TPDC and MEM have indicated that they wish the Company to unbundle the downstream distribution business in Tanzania. The methodology for this has been discussed with TPDC in the course of GNT negotiations. During the year, the Company tabled a proposal with alternative mechanisms to unbundle the downstream from the PSA which were economically neutral to the parties. TPDC did not respond to the proposal and it was later withdrawn by the Company in connection with the Company’s terminating negotiations arising from the GNT. TPDC was advised that the downstream would remain in the PSA until mutually agreed otherwise. TPDC Back-in TPDC has previously indicated a desire to exercise its right under the PSA to ‘back in’ to the Songo Songo field development and a further desire to convert this into a carried interest in the PSA. The current terms of the PSA require TPDC to provide formal notice in a defined period and contribute a proportion of the costs of any develop- ment, sharing in the risks in return for an additional share of the gas. To date, TPDC has not contributed any costs. TPDC back-in rights and the potential conversion of these rights into a carried working interest were discussed with the GNT along with other issues, however conditions precedent to any potential change in the terms of the PSA as a result of the GNT were not met by the Government and as such until an agreement is reached the Company will continue to rely upon the original terms of the PSA. The issue of any change to TPDC’s back-in rights has therefore not been resolved. Should an amendment to the PSA be agreed in future relating to back-in rights, the impact on reserves and accounting estimates will be assessed at that time and reflected prospectively. For the purpose of the reserves certification as at 31 December 2013, it was assumed that TPDC will elect to ‘back-in’ for 20% for all future new drilling activities with-in the prescribed period as determined by the current development plan on the basis of economically rational behaviour and this is reflected in the Company’s net reserve position. Cost recovery The Company’s Cost Pool in Tanzania has been fully recovered resulting in a reduction in the percentage of net revenue attributable to the Company. TPDC conducted an audit of the historic Cost Pool and in 2011 disputed approximately US$34 million of costs that had been recovered from the Cost Pool from 2002 through to 2009. The Company has contended that the disputed costs were appropriately incurred on the Songo Songo project in accordance with the terms of the PSA. Undertakings to resolve this matter were an outcome of GNT negotiations and the matter was referred to the Controller and Auditor General (“CAG”), head of the National Audit Office of Tanzania. With no progress on resolving the matter, the Company served a Notice of Dispute on TPDC to put the matter to a definitive timeline for resolution, following which the CAG appointed an international independent audit firm to review the disputed costs; this team commenced work in March 2014 and has yet to report. If the matter is not resolved to the Company’s satisfaction, it will proceed to ICSID arbitration pursuant to the terms of the PSA. This matter has had no impact on the results for the period. 38 TPDC marketing costs Under the Songo Songo PSA, all reasonable marketing costs including those incurred by TPDC, with the prior approval by the Company are recoverable. TPDC has to date attempted to claim US$3.6 million in marketing costs from the Company. Management reviewed the claims and can demonstrate that there was no prior approval for such costs, no supporting documentation provided evidencing the expenditure, and further believes the nature of the costs to be unreasonable and not related to marketing the downstream business. Accordingly the Company has rejected the claim by TPDC. Taxation During 2013 the Company received a number of assessments for additional tax from the Tanzania Revenue Authority (“TRA”), which together with interest penalties total US$18.4 million. Management, together with tax advisors, have reviewed each of the assesments as at 31 December 2013 and believe them to be without merit. The Company has appealed against assessments for additional withholding tax and employment related taxes, and has filed formal objections against TRA’s claims for additional corporation tax and VAT. The Tax Revenue Appeals Board considered the Company’s appeal against a withholding tax assessment of US$2.4 million in March 2013 and upheld the assessment. The Company then appealed to Tax Revenue Appeals Tribunal whose decision is awaited. Although a similar appeal to the Tribunal has been decided in favour of TRA, manage- ment continues to believe this assessment is flawed and, if necessary, will pursue the case in the Court of Appeal where a similar case is currently being heard. The Company, based on legal counsel’s advice, believes it has strong support, on the basis of tax legislation and the terms of the PSA, for its objection to the additional income tax assessment of US$7.8 million, including penalties. In the event that the Company’s objection is overturned, any additional tax payable will be recoverable from TPDC under the terms the PSA. The Company has filed an objection against a further assessment of VAT, which together with penalties totals US$7.5 million. Again, the Company based on legal counsel’s advice, believes that it has strong grounds for objecting to this assessment and accordingly has made no provision. The Company has received an assessment of US$0.7 million in respect of employment related taxes which TRA believe to have been underpaid. The Company does not accept TRA’s finding and has appealed. Management continues to review the progress of the above appeals and objections and, as of the date of this report, does not believe any provision is required. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS39 NEW ACCOUNTING STANDARDS AND INTERPRETATIONS On 1 January 2013, the Group adopted new standards with respect to IFRS 10 Consolidated Financial State- ments, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of Interests in Other Entities, as well as the consequential amendments to IAS 28 Investments in Associates and Joint Ventures (2011), IFRS 13 Fair Value Measurement and IFRS 7 Amendments to Financial Instrument Disclosures. The adoption of these standards had no impact on the amounts recorded in the financial statements. FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENT Credit risk The Company’s maximum credit risk is equal to the carrying value of its trade, other and long-term receivables. Trade receivables are comprised predominantly of amounts due in respect of gas sales to two power companies – the state owned utility TANESCO and Songas, and amounts due from a number of Industrial customers. Other receivables are mainly due from Songas for operation of its gas plant. The long-term receivable represents amounts due from TANESCO for supplies of gas which have remained outstanding for more than 60 days. Given the irregular and unpredictable pattern of payments the TANESCO receivable has been discounted using a risk adjusted discount rate of 15% (see Note 1, “Going Concern”). Financial instrument classification and measurement The Company’s financial instruments that are carried at fair value on the consolidated statement of financial position include long-term receivables. The Company classifies the fair value of these financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instrument: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing infor- mation on an ongoing basis. Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including expected interest rate, share prices, and volatility factors, which can be substantially observed or corroborated in the marketplace. Level 3 – Valuation in this level are those with inputs for the asset or liabilities that are not based on observable market data. Valuation of the Company’s long-term receivable is considered a Level 3 measurement. Fair value is estimated as the present value of future cash flows, discounted at the risk-adjusted rate at the reporting date. 40 SUMMARY QUARTERLY RESULTS The following is a summary of the results for the Company for the last eight quarters: (US$’000 except where otherwise stated) Financial Revenue Comprehensive (loss) /income after tax (Loss)/earnings per share - diluted (US$) Funds flow from operating activities Funds flow per share - diluted (US$) Operating netback (US$/mcf) Working capital 2013 2012 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 14,866 14,659 11,996 13,197 20,712 22,425 16,915 17,207 (3,918) 1,928 (6,817) 2,950 5,504 1,266 5,167 6,392 (0.11) 0.05 (0.19) 0.08 0.15 0.04 0.15 0.18 8,744 11,851 10,546 8,699 12,015 14,379 9,982 9,888 0.26 0.34 0.30 0.25 0.33 0.41 0.28 0.28 2.29 2.26 2.10 2.15 3.01 3.14 2.56 2.55 27,756 31,585 22,527 54,758 46,820 37,730 38,689 47,063 Shareholders’ equity 120,252 124,170 122,068 128,885 125,935 120,204 118,938 113,051 Capital expenditures Geological and geophysical and well drilling Pipeline and infrastructure Power development Other equipment Operating Additional Gas sold – industrial (MMcf) Additional Gas sold – power (MMcf) Average price per mcf – industrial (US$) Average price per mcf – power (US$) (1,370) 391 103 268 2,160 14,749 17,732 18,418 397 – 1,111 296 – 57 31 – 4 – – – (258) (15) 562 261 22 1 563 84 86 219 91 20 1,143 1,092 1,067 1,176 1,127 1,022 829 835 4,385 4,959 4,250 4,363 4,417 4,270 4,172 3,973 8.38 8.43 8.60 7.78 8.56 9.21 10.14 9.63 3.68 4.10 3.63 3.55 3.61 3.55 2.80 2.72 ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 41 PRINCIPLE DEVELOPMENTS IN Q4 2013. • • • • • Revenue remained constant compared with Q3 despite a reduction in Power sales, but fell US$5.8 million compared to Q4 2012, the result of the Company’s Cost Pool being fully recovered in 2012. The final result for Q4 was a loss after tax of US$3.9 million which contrasts with a Q3 profit of US$1.9 million and a Q4 2012 profit of US$5.5 million. The loss in Q4 was the result of management applying an additional discount to the TANESCO receivable of US$6.3 million and increasing the Company’s provision for doubtful debts by US$2.3 million, there were no corresponding charges in Q4 2012. TANESCO receivables grew US$3.6 million during the quarter, the Company having received US$13.5 million in payments. The Company continued to negotiate with the Government, seeking a resolution to various disputes and a new gas sales agreement. In Q4 the Company received a number of tax assessments from the Tanzanian Revenue Authority, which together with penalties totalled US$16.2 million. Management has taken the view, supported by advisors, that these are without merit and has filed formal objections. No provision has been made at this time. SELECTED FINANCIAL INFORMATION Selected annual financial information derived from the audited consolidated financial statements for the years ended 31 December 2011, 2012 and 2013 is set out below: Figures in US$’000 except per share amount 2013 2012 2011 Revenue Funds flow from operating activities Net cash flows from operating activities (Loss)/Profit after tax Total assets Bank loan (Loss)/earnings per share: Basic (US$) Diluted (US$) 54,718 39,840 22,491 (5,465) 210,976 1,659 (0.17) (0.17) 77,259 46,264 30,883 18,329 212,244 5,842 0.53 0.52 45,893 22,658 4,577 7,986 151,844 – 0.23 0.22 Revenue decreased by 29% to US$54.7 million in 2012 from US$77.3 million in 2012. The sales volumes were 9% higher in 2013 than 2012, with the weighted average price increasing from US$4.31/mcf to US$4.66/mcf. In 2013, current taxation of US$10.0 million was payable (2012: US$11.6 million) which in accordance with the terms of the PSA is recoverable from TPDC. Consequently revenue in 2013 has been uplifted by the gross amount of US$14.3 million. The level of Industrial volumes increased by 17% to 4,478 MMcf in 2013 from 3,813 MMcf in 2012, mainly as a consequence of reducing supplies of Protected Gas whilst Songas carried out maintenance on power generating turbines. The level of Power volumes increased by 7% to 17,957 MMcf (2012: 16,832 MMcf). The increase in Power sales is attributable to increased demand for gas from TANESCO. The 14% decrease in funds from operations before working capital changes over 2012 is due primarily to a reduction in revenues. Although gross revenues increased 17% the Company’s share dropped by 16% as a consequence of having fully recovered costs, this resulted in a significant increase in TPDC’s share of revenue. 42 BUSINESS RISKS Additional Financing Depending on future exploration, development, and marketing plans, and the status of and outlook for the TANESCO and Songas receivables, the Company may require additional financing. In the event that Company does not collect from TANESCO the balance of the outstanding receivables at 31 December 2013 and TANESCO continues to be unable to pay the Company for subsequent 2014 gas deliveries, the Company will need additional funding to maintain its current ongoing operations before the end of the current financial year. The ability of the Company to arrange such financing in the future will depend in part upon the prevailing capital market condi- tions as well as the business performance of the Company. There can be no assurance that the Company will be successful in its efforts to arrange additional financing on terms satisfactory to the Company. If additional financing is raised by the issuance of shares from treasury of the Company, control of the Company may change and shareholders may suffer additional dilution. From time to time the Company may enter into transactions to acquire assets or the shares of other companies. These transactions may be financed partially or wholly with debt, which may temporarily increase the Company’s debt levels above industry standards. Collectability of Receivables The Company considers the Songas and TANESCO receivables to be collectable, despite being long overdue. Both Songas and the Company have been impacted by TANESCO’s inability to pay. There have been acknowledge- ments by TANESCO and MEM of the debt and the importance of addressing same. The recent Tanzania First and Second Power and DPOs by the World Bank to ensure TANESCO’s viability support management’s view that the debts will be paid (see “Going Concern”). Given the irregularity and unpredictability of payments, the timing of repayment remains uncertain. Consequently management has reclassified an element of the TANESCO debt as long-term and has discounted the value of the receivable. The discount applied to the TANESCO receivable is based on a probabilistic assessment by management of a multi-scenario discounted cash flow model which incorporates a number of assumptions as to the timing and amount of cash receipts from TANESCO, timing of World Bank DPO disbursements to the Government of Tanzania, status of negotiations with the Government and/or World Bank for partial risk guarantees, expected operational start date for the NNGIP in Tanzania and the potential for an arbitration settlement. These assumptions are subject to change due to factors which are beyond the control of the Company. The Company has made a provision against the net Songas receivable, as ultimately the ability of Songas to pay is in turn dependent upon TANESCO settling is liabilities to Songas. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS43 Operating Hazards and Uninsured Risks The business of the Company 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 forma- tions or production facilities and other property, equipment and the environment, as well as interrupt opera- tions. In addition, all of the Company’s operations will be subject to the risks normally incident to drilling of natural gas wells and the operation and development of gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blowouts, equipment 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 the Company 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 the Company is increased due to the fact that the Company currently only has one producing property. The Company 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 the Company’s financial condition, results of operations and cash flows. Furthermore, the Company cannot predict whether insurance will continue to be available at a reasonable cost or at all. Foreign Operations The Company’s operations and related assets are located in Italy and Tanzania which may be considered to be politically 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, nationalization, creeping nationalization, 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 governmen- tal regulations that favour or require the awarding of drilling and construction contracts to local contrac- tors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. In addition, if a dispute arises with foreign operations, the Company may be subject to the exclusive jurisdic- tion of foreign courts. In Tanzania, the state retains ownership of the minerals and consequently retains control of, the exploration and production of hydrocarbon reserves. Accordingly, these operations may be materially affected by the Government through royalty payments, export taxes and regulations, surcharges, value added taxes, produc- tion bonuses and other charges. The Government of Tanzania issued a National Natural Gas Policy in 2013, which policy contemplates greater government control over the industry and in some areas conflicts with the Company’s rights under the Songo Songo PSA. There can be no assurance that the rights of the Company under the PSA will be grandfathered with respect to any future natural gas legislation arising from this policy. The Company’s development properties and its current proved natural gas reserves located offshore on the Songo Songo Island in Tanzania, are subject to regulation and control by the government of Tanzania and certain of its national and parastatal organizations including the energy regulator, EWURA and TPDC. The Company and its predecessors have operated in Tanzania for a number of years and believe that it had reasonably good relations with the current Tanzanian Government. However, there can be no assurance that present or future administrations or governmental regulations in Tanzania will not materially adversely affect the operations or future cash flows of the Company. 44 The Tanzania Revenue Authority is responsible for the collection of taxes in Tanzania. TRA is not party to the Songo Songo PSA and there is no assurance that the TRA will consider itself bound by its terms. Accordingly, there is a risk that the TRA will take interpretations of issues distinct from the PSA and result in assessments, penalties and fines which have not been contemplated by the Company and result in additional costs which are not recoverable under the PSA. The TRA has significant powers in Tanzania and is capable of causing the Company’s operations in that country to cease. The Company requires additional gas processing and transportation infrastructure to allow additional devel- opment and the ultimate monetisation of the Company’s reserves through additional gas sales. In 2012, the Government of Tanzania announced a US$1.2 billion natural gas infrastructure expansion project, the scope of which would provide sufficient capacity to process and transport the necessary volumes of gas. After a year of negotiations with TPDC, there has been no progress on commercial terms for the sale of incremental gas volumes and there is no assurance that the Company’s gas could be processed and transported to markets on economic terms. PSA Negotiations In November 2011 Parliament passed a resolution advising the Government to terminate the Company’s Songo Songo PSA on the grounds of an allegation by TPDC that the Company had over recovered approximate- ly US$21 million in Cost Gas revenue. On the recommendation of MEM in February 2012, the Government announced that it was establishing a Government Negotiating Team (“GNT”) to discuss a number of issues raised in Parliament in relation to the Company’s Songo Songo PSA. In Tanzania, government negotiating teams are a common mechanism to negotiate with business. The scope of the GNT was to discuss a number of issues that were raised by the Parliamentary Committee for Energy into the workings of the PSA. This included, but is not limited to, TPDC back in rights, profit sharing arrangements, the unbundling of the downstream assets, cost recovery and the Company’s management of the upstream operations. After making submissions to the GNT, the Company commenced discussions in April 2012 and further in July 2012, at which time a condi- tional agreement in principle was been reached on a number of major points to resolve the issues. The GNT completed its mandate, and the responsibility for finalisation, documentation and implementation moved back to MEM. The conditional agreement in principle contemplated completion of this process by the end of 2012 as well as a number of deliverables from TPDC and the Government. As at the date of this report none of TPDC or Government undertakings have been met and other than the alleged US$21 million over recovery discussed below, none of the issues have been resolved. In response to a Notice of Dispute delivered by the Company, in March 2014 TPDC retracted its claim that the Company had over-recovered approximately US$21 million in Cost Gas, which management believes has sub- stantially exonerated the Company of allegations made by Parliament. Accordingly, the Company continues to rely upon its rights under the existing PSA and has initiated notices of dispute to resolve any remaining issues. Industry Conditions The oil and gas industry is intensely competitive and the Company competes with other companies which possess greater technical and financial resources. Many of these competitors not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum, natural gas products and other products on an international basis. Oil and gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and invasion of water into producing formations. Currently, the Company 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, the Company 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. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS45 The marketability and price of natural gas which may be acquired, discovered or marketed by the Company 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 the Company and Songas. The ability of the Company 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. The Company is also subject to market fluctua- tions in the prices of oil and natural gas, uncertainties related to the delivery and proximity of its reserves to pipelines and processing facilities and extensive government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and gas and many other aspects of the oil and gas business. The Company 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 the Company 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 The Company 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 the Company’s ability to produce, transport and sell volumes of Additional Gas if the Company’s obligations to Songas under the Gas Agreement are not met. In particular, Songas has the right in specific circumstances to request reasonable security on all Additional Gas sales. The Government of Tanzania has issued a National Natural Gas Policy in October 2013, which policy contem- plates TPDC becoming sole aggregator of natural gas in the country. This policy objective conflicts with the Company’s prior right under the PSA to directly market Additional Gas, and there is a risk that this prior right will not be recognized and that the Company’s ability to maximize revenue on Additional Gas sales may be impaired by a requirement at law to sell gas to TPDC as aggregator. Replacement of Reserves The Company’s natural gas reserves and production and, therefore, its cash flows and earnings are highly dependent upon the Company developing and increasing its current reserve base and discovering or acquiring additional reserves. Without the addition of reserves through exploration, acquisition or development activi- ties, the Company’s reserves and production will decline over time as reserves are depleted. To the extent that cash flow from operations is insufficient and external sources of capital become limited or unavailable, the Company’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 the Company will be able to find and develop or acquire additional reserves to replace production at commercially feasible costs. 46 Asset Concentration The Company’s natural gas reserves are currently limited to one producing property, the Songo Songo field, and the productive potential from this field is limited to seven wells, of which three are currently suspended. There has been limited production from the Songo Songo field to date. There is no assurance that the Company will have sufficient deliverability through the existing wells to provide Additional 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 difficulties relating to the operation or performance of the field would have a material adverse effect on the Company. The Company is currently producing the existing wells at maximum capacity. There will be no redundant capacity in the facility or pipeline until workovers of existing wells can be performed and/or additional wells can be drilled in the field and facilities expanded. A loss or material reduction in the production of any given well will have a material adverse effect on the total production and funds flow from operations of the Company. The Italian licences in which the Company has an interest are currently in the exploration phase of their cycle and it may be several years before the Company 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 the Company’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 the Company will not incur substantial financial obligations in connection with environmental compliance. Significant liability could be imposed on the Company 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 the Company or non-compliance with environmental laws or regulations. Such liability could have a material adverse effect on the Company. Moreover, the Company cannot predict what environmental legislation or regulations will be enacted in the future or how existing or future laws or regulations will be administered or enforced. Com- pliance with more stringent laws or regulations, or more vigorous enforcement policies of any regulatory authority, could in the future require material expenditures by the Company for the installation and operation of systems and equipment for remedial measures, any or all of which may have a material adverse effect on the Company. As party to various licenses, the Company 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 the Company is currently in compliance with environmental laws and regu- lations applicable to the Company’s operations in Tanzania and Italy, no assurances can be given that the Company will be able to continue to comply with such environmental laws and regulations without incurring substantial costs. The Company’s petroleum and natural gas operations are subject to extensive governmental legislation and regulation and increased public awareness concerning environmental protection. In accordance with the terms of the PSA, no provision has been recognised for future decommissioning costs in Tanzania as it is forecast that there will still be commercial gas reserves when the Company relinquishes the license in 2026. The Company 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 the Company to date. Although management believes that the Company’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 compli- ance in the future. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS47 Volatility of Oil and Gas Prices and Markets The Company’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 the Company. Any substantial decline in the prices of oil and natural gas could have a material adverse effect on the Company and the level of its natural gas reserves. Additionally, the economics of producing from some wells may change as a result of lower commodity prices, which could result in a suspension of production by the Company. No assurance can be given that oil and natural gas prices will be sustained at levels which will enable the Company to operate profitably. From time to time the Company may avail itself of forward sales or other forms of hedging activities with a view to mitigating its exposure to the risk of price volatility. The Songo Songo field 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 Heavy Fuel Oil and coal. There has an increase in exploration activity in Tanzania, which has yielded significant discoveries of natural gas that could, when developed, 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 the Company’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 the Company. The reserve and cash flow information contained herein represents estimates only. The reserves and estimated future net cash flow from the Company’s properties have been independently evaluated by McDaniel & Associates Consul- tants Ltd. These evaluations include a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, crude oil price differentials to benchmarks, future prices of oil and natural gas, operating costs, transportation costs, cost recovery provisions and royalties, TPDC “back-in” methodology and other government levies that may be imposed over the producing life of the reserves. These assumptions were based on price forecasts in use at the date of the relevant evaluations were prepared and many of these assumptions are subject to change and are beyond the control of the Company. 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 the Company which could result in a reduction of the revenue received by the Company. 48 Acquisition Risks The Company intends to acquire natural gas infrastructure and possibly additional oil and gas properties. Although the Company 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 indi- vidual property involved in each acquisition. Ordinarily, the Company will focus its due diligence efforts on the higher valued properties and will sample the remainder. However, even an in depth review of all properties and records may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not be performed on every well, and structural or environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. The Company 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 the Company’s acquisitions will be successful. Reliance on Key Personnel The Company 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 the Company. The Company 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 the Company and holds approximately 99.5% of the outstanding Class A shares and approximately 16.5% of the Class B shares. Consequently, Mr. Lyons is the beneficial holder of approximately 20.7% of the equity (22.5% fully diluted) and controls 59.3% of the total votes of the Company. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS49 CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS In applying the Company’s accounting policies, which are described in Note 3 to the Consolidated Financial Statements, 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 the Company. The reserve and cash flow information contained herein represents estimates only. The reserves and estimated future net cash flow from the Company’s Exploration’s properties have been evaluated by McDaniel & Associates Consultants Ltd., independent petroleum engineers. 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 the Company. 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 hydrocarbon 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. 50 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, whereas the fair value of stock apprecia- tion 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 these costs are subject to government audit and potential reassessment in certain circumstances after the elapse of a considerable period of time. Currently approximately US$34 million in cost recoveries for the period 2002 to 2009 have been denied by TPDC, which audit finding is now the subject of a Notice of Dispute by the Company. v) Collectability of Receivables The Company considers the Songas and TANESCO receivables to be collectable, despite being long overdue. Both Songas and the Company have been impacted by TANESCO’s inability to pay. There have been acknowledgements by TANESCO and MEM of the debt and the importance of addressing same. Management has no reason to believe that the receivables will not be paid in full, however the Company has yet to receive any plan or proposal from TANESCO or the Government on behalf of TANESCO regarding the timing and quantum of such repayments. The recent Tanzania First and Second Power and Gas DPO by the World Bank to ensure TANESCO’s viability support management’s view that the debts will be paid (see Note 1 “Going Concern”). Given the irregularity and unpredictability of payments, the timing of repayment remains uncertain. Consequently management has reclassified an element of the TANESCO debt as long-term and has discounted the value of the receivable. The Company has made a provision against the net Songas receivable, as ultimately the ability of Songas to pay is in turn dependent upon TANESCO settling is liabilities to Songas. The Company has a substantial “Tax Receivable” balance. This arises from the revenue sharing mechanism within the PSA which entitles the Company to a share of revenue equivalent to its tax charge, grossed up at the prevailing rate. These amounts are collected by way of an offset against TPDC’s share of revenue, as and when the Company pays its tax. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS51 vi) TPDC Back-in TPDC has previously indicated a wish to exercise its right under the PSA to ‘back in’ to the Songo Songo field development and a further wish to convert this into a carried interest in the PSA. The current terms of the PSA require TPDC to provide formal notice in a defined period and contribute a proportion of the costs of any development, sharing in the risks in return for an additional share of the gas. To date, TPDC has not contributed any costs. TPDC back-in rights and the potential conversion of these rights into a carried working interest were discussed with the GNT along with other issues, however conditions precedent to any potential change in the terms of the PSA as a result of the GNT were not met by the Government and as such the Company continues to stand behind the original terms of the PSA. The issue of any change to TPDC’s back-in rights has therefore not been resolved. Should an amendment to the PSA be agreed in future relating to back-in rights, the impact on reserves and accounting estimates will be assessed at that time and reflected prospectively. For the purpose of the reserves certification as at 31 December 2013, it was assumed that, on the basis of economically rational behavior, TPDC will elect to ‘back-in’ for 20% for all future new drilling activities with-in the prescribed period as determined by the current development plan and this is reflected in the Company’s net reserve position. vii) TPDC marketing costs Under the Songo Songo PSA, all reasonable marketing costs including those incurred by TPDC, with the prior approval by the Company are recoverable. TPDC has to date attempted to claim US$3.6 million in marketing costs from the Company. Management reviewed the claims and can demonstrate that there was no prior approval for such costs, no supporting documentation provided evidencing the expenditure, and further believes the nature of the costs to be unreasonable and not related to marketing the downstream business. Accordingly the Company has rejected the claim by TPDC. viii) Taxation During 2013 the Company received a number of assessments for additional tax from the Tanzania Revenue Authority (“TRA”), which together with interest penalties total US$18.4 million. Management together with tax advisors have reviewed each of the assessments and believe them to be without merit. The Company has appealed against assessments for additional withholding tax and employment related taxes, and has filed formal objections against TRA’s claims for additional corporation tax and VAT. The Tax Revenue Appeals Board considered the Company’s appeal against a withholding tax assessment of US$2.4 million in March 2013 and upheld the assessment. The Company then appealed to Tax Revenue Appeals Tribunal whose decision is awaited. Although a similar appeal to the Tribunal has been decided in favour of TRA, management continues to believe this assessment is flawed and, if necessary, will pursue the case in the Court of Appeal where a similar case is currently being heard. The Company based on advice believes it has strong support, on the basis of tax legislation and the terms of the PSA, for its objection to the additional income tax assessment of US$7.8 million, including penalties. In the event that the Company’s objection is overturned, any additional tax payable will be recoverable from TPDC under the terms the PSA. The Company has filed an objection against a further assessment of VAT, which together with penalties totals US$7.5 million. Again, the Company based on advice believes that it has strong grounds for objecting to this assessment and accordingly has made no provision. The Company has received an assessment of US$0.7 million in respect of employment related taxes which TRA believe to have been underpaid. The Company does not accept TRA’s finding and has appealed. Management continues to review the progress of the above appeals and objections and, as of the date of this report, does not believe any provision is required. 52 MANAGEMENT’S REPORT TO SHAREHOLDERS The accompanying consolidated financial statements of Orca Exploration Group Inc. are the responsibility of the Directors. The financial and operating information presented in this annual report is consistent with that shown in the consolidated financial statements. The consolidated financial statements have been prepared by management, on behalf of the Board, in accordance with the accounting policies disclosed in the notes to the consolidated financial statements. Where necessary, management has made informed judgments and estimates in accounting for transactions which were not complete at the balance sheet date. In the opinion of management, the consolidated financial statements have been prepared within acceptable limits of materiality and are in accordance with International Financial Reporting Standards appropriate in the circumstances. Management, with the participation of the 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 and International Auditing Standards to enable them to express an opinion on the fairness 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 of the Company principally through an Audit Committee. The committee has met with external auditors and Management in order to determine if Management has fulfilled its responsibilities in the preparation of the consolidated financial statements. The consolidated financial statements have been approved by the Board of Directors on the recommendation of the Audit Committee. W. David Lyons Chairman and Chief Executive Officer Robert S. Wynne Chief Financial Officer and Director 24 April 2014 24 April 2014 ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS INDEPENDENT AUDITORS’ REPORT 53 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, 2013 and December 31, 2012, the consolidated statements of comprehensive (loss)/income, changes in equity and 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 accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, 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 in our audits 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, 2013 and December 31, 2012, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. Emphasis of matter Without modifying our opinion, we draw attention to Note 1 to the consolidated financial statements which describes that there is no certainty that the company will be able to collect its receivables to fund ongoing operations and exploration and development program. This condition set forth in Note 1, indicates the existences of a material uncertainty that may cast significant doubt about the company’s ability to continue as a going concern. Chartered Accountants 24 April 2014 Calgary, Canada 54 FINANCIAL STATEMENTS CONSOLIDATED STATEMENT OF COMPREHENSIVE (LOSS)/INCOME US$’000s except per share amounts REVENUE Cost of sales Production and distribution expenses Depletion expense General and administrative expenses Exploration asset impairment Finance income Finance costs (Loss)/profit before tax Income taxes (Loss)/profit after tax Foreign currency translation (loss)/gain from foreign operations Total comprehensive (loss)/income for the period (Loss)/earnings per share Basic (US$) Diluted (US$) YEAR ENDED 31 DECEMBER NOTE 2013 2012 6,7 54,718 77,259 (4,426) (12,166) 38,126 (15,428) (158) 2,646 (28,908) (3,722) (1,743) (5,465) (392) (5,857) (0.17) (0.17) 13 12 9 9 10 17 17 (5,953) (8,968) 62,338 (17,989) (8,284) 23 (634) 35,454 (17,125) 18,329 89 18,418 0.53 0.52 See Going Concern (Note 1) and accompanying notes to the consolidated financial statements. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTFINANCIAL STATEMENTS CONSOLIDATED STATEMENT OF FINANCIAL POSITION 55 US$’000s ASSETS Current Assets Cash Trade and other receivables Tax receivable Prepayments Non-Current Assets Long-term trade receivable Exploration and evaluation assets Property, plant and equipment Total Assets EQUITY AND LIABILITIES Current Liabilities Trade and other payables Bank loan Tax payable Non-Current Liabilities Deferred income taxes Deferred additional profits tax Total Liabilities Equity Capital stock Contributed surplus Accumulated other comprehensive (loss)/income Accumulated income Total Equity and Liabilities See accompanying notes to the consolidated financial statements. Going concern (Note 1) Contractual obligations and committed capital investment (Note 19) Contingencies (Note 20) AS AT NOTE 31 Dec 2013 31 Dec 2012 3 11 10 11 12 13 14 15 10 10 16 32,588 37,215 14,585 281 84,669 29,911 5,564 90,832 126,307 210,976 53,296 1,659 1,958 56,913 12,132 21,679 33,811 90,724 85,428 6,482 (303) 28,645 120,252 210,976 16,047 73,495 14,692 246 104,480 – 5,720 102,044 107,764 212,244 45,496 5,842 6,322 57,660 20,399 8,250 28,649 86,309 84,983 6,753 89 34,110 125,935 212,244 The consolidated financial statements were approved by the Board of Directors on 24 April 2014. Director Director 56 CONSOLIDATED STATEMENT OF CASH FLOWS US$’000s CASH FLOWS FROM OPERATING ACTIVITIES (Loss)/Profit after tax Adjustment for: Depletion and depreciation Exploration asset impairment Provision for doubtful debt Discount on long-term receivable Stock-based compensation Deferred income taxes Deferred additional profits tax Interest income Interest expense Unrealised loss on foreign exchange Funds flow from operating activities Decrease/(increase) in trade and other receivables Decrease/(increase) in tax receivable (Increase)/decrease in prepayments Increase in trade and other payables (Decrease)/increase in taxation payable Increase in long-term receivable Net cash flows from operating activities CASH FLOWS USED IN INVESTING ACTIVITIES Exploration and evaluation expenditures Property, plant and equipment expenditures Interest received Increase in trade and other payables Net cash used in investing activities CASH FLOWS (USED IN)/FROM FINANCING ACTIVITIES Normal course issuer bid Bank loan proceeds Bank loan repayments Interest paid Proceeds from exercise of options Net cash flow (used in)/from financing activities Increase/(decrease) in cash Cash at the beginning of the year Effect of change in foreign exchange on cash in hand Cash at the end of the year See accompanying notes to the consolidated financial statements. YEAR ENDED 31 DECEMBER NOTE 2013 2012 (5,465) 18,329 13 12 9 9 16 10 7, 10 9 9 12 13 13 9 16 15 15 9 12,498 158 10,531 17,073 (209) (8,267) 13,429 – 678 (586) 39,840 25,845 107 (35) 8,082 (4,364) (46,984) 22,491 (2) (1,286) – – 9,281 8,284 – – 1,152 5,205 3,463 (23) 315 258 46,264 (33,133) (8,812) 56 22,589 3,919 – 30,883 (11,083) (43,612) 23 (716) (1,288) (55,388) – 4,000 (8,183) (678) 174 (4,687) 16,516 16,047 25 32,588 (12) 5,842 – (315) 150 5,665 (18,840) 34,680 207 16,047 ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTFINANCIAL STATEMENTS CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY 57 Capital stock Contributed surplus Cumulative Translation adjustment Accumulated Income US$’000 Balance as at 1 January 2013 Options exercised Foreign currency translation adjustment on foreign operations Loss after tax for the period 84,983 445 – – 6,753 (271) – – Balance as at 31 Dec 2013 85,428 6,482 89 – (392) – (303) 34,110 – – (5,465) 28,645 Total 125,935 174 (392) (5,465) 120,252 US$’000 Capital stock Contributed surplus Cumulative Translation adjustment Accumulated Income Total Balance as at 1 January 2012 84,610 6,268 Stock based compensation Options exercised Normal course issuer bid Foreign currency translation adjustment on foreign operations Profit after tax for the period – 383 (10) – – 720 (233) (2) – – Balance as at 31 Dec 2012 84,983 6,753 See accompanying notes to the consolidated financial statements. – – – – 89 – 89 15,781 106,659 – – – – 720 150 (12) 89 18,329 34,110 18,329 125,935 58 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS General Information Orca Exploration Group Inc. was incorporated on 28 April 2004 under the laws of the British Virgin Islands. The Company produces and sells natural gas to the power and industrial sectors in Tanzania and has gas and oil exploration interests in Italy. The consolidated financial statements of the Company as at and for the year ended 31 December 2013 comprise accounts of the Company and all its wholly owned subsidiaries (collectively, the “Company” or “Orca Exploration”) and were authorised for issue in accordance with a resolution of the directors on 24 April 2014. 1 GOING CONCERN These financial statements have been prepared on a going concern basis. The going concern basis of pre- sentation assumes that the Company will continue in operation for the foreseeable future and be able to realize its assets and discharge its liabilities and commitments in the normal course of business. The financial statements do not reflect adjustments that would be necessary if the going concern assumption were not appropriate. If the going concern basis were not appropriate for these financial statements, then adjustments would be necessary in the carrying amounts of assets and liabilities, the reported revenues and expenses, and the balance sheet classifications. The ability of the Company to continue as a going concern is dependent on the Company’s ability to collect its receivables from Government entities to fund on-going operations and the exploration and development program. The continuing weakness in the financial position of the state utility, TANESCO, has created uncertainty as to whether the Company will be able to collect cash to continue operations and meet its commitments. The immediate need to collect from its debtors may create significant doubt about the Company’s ability to continue as a going concern. In the event that Company does not collect from TANESCO the balance of the outstanding receivables at 31st December 2013 and TANESCO continues to be unable to pay the Company for subsequent 2014 gas deliveries, the Company will need additional funding for its ongoing operations before the end of the current fiscal year. There are no guarantees that such additional funding will be available when needed, or will be available on suitable terms. The Company has served notice to TANESCO demanding payment in full and is reviewing legal options available to collect the arrears and mitigate a further increase in arrears, including but not limited to suspending gas deliveries to TANESCO. The material uncertainties that may cast significant doubt on the Company’s ability to continue as a going concern are set forth below. The Company generates in excess of 65% of its operating revenue from sales to the Power sector companies, Songas and TANESCO. The financial security of Songas is heavily reliant on the payment of capacity and energy charges by TANESCO, which in turn is dependent on the Government of Tanzania to subsidise a significant portion of TANESCO’s operating budget. Prior to 2012, despite having a history of delayed payments, TANESCO had settled in full the outstanding balance subsequent to each quarter end. At 31 December 2013, TANESCO owed the Company US$56.6 million gross prior to discount (including arrears of US$51.5 million) compared to US$33.3 million (including arrears of US$28.4 million) as at 31 December 2012. During the year the Company received a total of US$49.6 million (2012: US$16.4 million) from TANESCO and, subsequent to year-end, TANESCO paid the Company a further US$6.4 million. As of the date of this report, the outstanding balance is US$64.9 million of which US$60.2 million is in arrears. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 201359 At the end of Q1 2013, the World Bank approved a Tanzania First Power and Gas Development Policy Operation (“DPO”) of US$100 million, the first in a programme of three contemplated operations. The objective of the program is to: (i) strengthen the Tanzania’s ability to bridge the financial gap in its power sector; (ii) reduce the cost of power supply and promote private sector participation in the power sector; and (iii) strengthen the policy and institutional framework for the management of the country’s natural gas resources. TANESCO made tangible progress in late 2013 towards sustainability in securing a 39% power tariff increase from the energy regulator, the Energy Water Utilities Regulatory Authority (“EWURA”). This was an important condition of the advancement of the Second US$100 million Power and Gas DPO, approved on 26 March 2014 and expected to be disbursed in Q2 2014. The Company received significant payments of ap- proximately US$18.7 million in 2013 from TANESCO around the time of the disbursement of the First DPO and as at the date of this report has yet to be informed as to the quantum of payments if any which may be made as a result of the Second DPO. Management continues to believe that TANESCO will ultimately settle its debts with the Company. As at the date of this report, however, there is no set schedule or repayment plan for TANESCO arrears proposed or agreed with the Company and payments have been irregular and unpredictable. Based on the actual repayment history as at 31 December 2013, US$9.6 million (2012: US$33.3 million) of the TANESCO receivable was classified as current and US$47.0 million (2012: nil) was classified as long-term. A discount of US$17.1 million has been taken against the TANESCO receivable to reflect the estimated finance cost of delay in collections. The trade receivable was discounted using a risk adjusted discount rate of 15% to reflect the cost of delayed timing of collections from TANESCO. The discount rate and the expected timing of the collections are reviewed at each period end with any adjustments recorded in the period that the estimates are changed. As at 31 December 2013, Songas owed the Company US$24.8 million (2012: US$24.6 million), whilst the Company owed Songas US$16.9 million (2012: US$18.6 million). There is no contractual right to offset these amounts, although in practice the companies have set off receivables and payables. As at the year-end, Songas and the Company formally offset payable and receivable balances of US$17.5 million. Subsequent to the end of the year, the Company has neither received nor paid any amounts in settlement of these balances. Amounts due to Songas primarily relate to pipeline tariff charges of US$15.4 million (2012: US$17.5 million), whereas the amounts due to the Company are mainly for sales of gas of US$11.6 million (2012: US$14.3 million) and for the operation of the gas plant for US$13.3 million (2012: US$10.3 million). The operation of the gas plant is conducted at cost and the charges are billed to Songas on a flow through basis without profit margin. Due to the time for which the set off has been outstanding and the lack of evidence of cash payments from Songas, the Company was unable to recognize the net Songas receivable as at the end of the year and accordingly provided a provision against same (see Note 9). Management continues to negotiate with Songas to reach an offsetting agreement and if, and when, such agreement is reached, the related provision for bad debts will be reversed. Any amounts which are not agreed will be pursued by the Company through the dispute mechanisms provided in its agreements with Songas. In 2012, to help alleviate the funding gap caused by the delays in TANESCO payments the Company entered into a US$10 million debt facility with a bank in Tanzania. By February 2013, the Company had drawn down the facility. Repayments commenced in March 2013 and the loan balance as at 31st December 2013 was US$1.7 million. By February 2014, the loan had been fully repaid. 60 2 BASIS OF PREPARATION These consolidated financial statements have been prepared on a historical cost basis and have been prepared using the accrual basis of accounting. The consolidated financial statements are presented in US dollars. A) Statement of Compliance The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”). B) Basis of consolidation i) Subsidiaries The consolidated financial statements include the accounts of Orca Exploration Group Inc. 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 100% Orca Exploration Italy Onshore Inc. British Virgin Islands 100% PAE PanAfrican Energy Corporation Mauritius PanAfrican Energy Tanzania Limited Jersey Orca Exploration UK Services Limited United Kingdom 100% 100% 100% Euro Euro US dollar US dollar UK Pound Sterling ii) Transactions eliminated upon consolidation Inter-company balances and transactions, and any unrealised gains or losses arising from in- ter-company transactions, are eliminated in preparing the consolidated financial statements. C) Foreign currency i) Foreign currency transactions Transactions in foreign currencies 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. ii) Foreign currency translation Orca Exploration Italy Inc. and Orca Exploration Italy Onshore Inc. use the Euro and Orca UK Services uses Pound Sterling as their functional currencies. The assets and liabilities of these companies are translated into US dollars at the period-end exchange rate. The income and expenses of the companies are translated into US dollars at the average exchange rate for the period. Translation gains and losses are included in other comprehensive income. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2013 61 3 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The accounting policies set out below have been applied consistently to all periods presented in these con- solidated financial statements, and have been applied consistently by the Company. A) 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 determination is made. ii) Property, plant and equipment Property, plant and equipment comprises the Company’s tangible natural gas assets, development wells, together with leasehold improvements, computer equipment, motor vehicles and fixtures and fittings and are carried at cost, less any accumulated depletion, de- preciation 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 (“CGU”) for impairment assessment purposes at the lowest level at which there are identifi- able cash flows that are independent from other group assets. In the case of exploration and evaluation assets, this will normally be at the CGU 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 CGU exceeds its recoverable amount, the CGU 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 pre-tax discount rate that reflects the current market indicators. The fair value less costs to sell is the amount that would be obtained from the sale of a CGU in an arm’s length transaction between knowledgeable and willing parties. Where an impairment loss subsequently reverses, the carrying amount of the asset CGU 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 CGU in prior years. A reversal of an impairment loss is recognised as income immediately. 62 B) OPERATORSHIP The Company operates the Songo Songo gas field, flow lines and gas processing plant. The Songas wells, flowlines and gas plant are operated by the Company on behalf of Songas on a no cost no profit basis. The cost of operating and maintaining the wells and flow lines is paid for by the Company and Songas in proportion to the respective volumes of Protected Gas and Additional Gas sales. The costs of operating and maintaining the wells and flow lines are reflected in the accounts to the extent that the costs were incurred to accomplish Additional Gas sales. The cost of operating the gas processing plant and pipeline to Dar es Salaam is paid by Songas. When there are Additional Gas sales, a tariff is paid to Songas as compensation for using the gas processing plant and pipeline. This tariff is netted against revenue. C) 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 stock option plan provides for the granting of stock options to directors, Company officers, key personnel and employees to acquire shares at an exercise price determined by the market value at the date of grant. The exercise price of each stock option is determined at the closing market price of the Class B shares on the day prior to the day of grant. Each stock option granted permits the holder to purchase one Class B 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. 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. D) ASSET RETIREMENT OBLIGATIONS No provision has been made for future site restoration costs in Tanzania because the Company currently has no legal or contractual or constructive obligation under the Songo Songo Production Sharing Agreement (“PSA”) to restore the fields at the end of their commercial lives, should such occur within the term of the PSA. At such a time as the Company may be granted an extension of the term of the PSA, which encompasses the end of the field life, or other amendment to the PSA which requires the Company to do so, a provision will be made for future site restoration costs. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 201363 E) REVENUE RECOGNITION, PRODUCTION SHARING AGREEMENTS AND ROYALTIES Pursuant to the terms of the PSA , the Company has exclusive rights to (i) to carry on Exploration Operations in the Songo Songo Gas Field; (ii) to carry on Development Operations in the Songo Songo Gas Field and (iii) jointly with Tanzania Petroleum Development Corporation (“TPDC”), a “parastatal entity” to sell or otherwise dispose of Additional Gas. Additional Gas is all the gas produced in excess of Protected Gas. Songas utilizes the Protected Gas (maximum 45.1 MMcfd on any given day, non- cumulative) as feedstock for its gas turbine electricity generators at Ubungo, for onward sale to the Wazo Hill cement plant and for electrification of certain villages along the pipeline route. The Company receives no revenue for the Protected Gas delivered to Songas. The Company recognises revenue related to Additional Gas sales when title passes to a customer. Under the terms of the PSA, the Company pays both its share and the parastatal’s share of operating, administrative and capital costs. The Company recovers all reasonably incurred operating, admin- istrative 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 Cost Gas in the year of recovery. In any given year, the Company is entitled to recover as Cost Gas up to 75% of the net revenue (gross revenue less processing and pipeline tariffs). Any net revenue in excess of the Cost Gas (“Profit Gas”) is shared between the Company and TPDC in accordance with the terms of the PSA. Revenue represents the Company’s share of Cost Gas and Profit Gas during the period. F) ADDITIONAL PROFITS TAX Under the terms of the PSA, in the event that all costs have been recovered with an annual return from the PSA 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 programme. G) INCOME TAXES 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 Gas sharing arrangement embedded in the PSA. 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. H) DEPRECIATION Depreciation for non-natural gas properties is charged to the income statement on a straight line basis over the estimated useful economic lives of each class of asset. The estimated useful lives are as follows: Leasehold improvement Computer equipment Vehicles Fixtures and fittings Over remaining life of the lease 3 years 3 years 3 years 64 I) FINANCIAL INSTRUMENTS All financial instruments are initially recognized at fair value on the consolidated statement of financial position. The Company has classified each financial instrument into one of the following categories: (i) fair value through profit and loss, (ii) loans and receivables, and (iii) other financial liabilities. Subsequent measurement of financial instruments is based on their classification. Financial assets and liabilities are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets are derecognized when the rights to receive cash flows from the assets have expired or have been transferred and the Company has transferred substantially all risks and rewards of ownership. Financial assets and liabilities are offset and the net amount is reported on the statement of financial position when there is a legally enforceable right to offset the recognized amounts and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously. Initial recognition At initial recognition, the Company classifies its financial instruments in the following categories depending on the purpose for which the instruments were acquired: (i) Financial assets and liabilities at fair value through profit and loss: A financial asset or liability classified in this category is recognized at each period at fair value with gains and losses from revaluation being recognized in net income. A financial asset or liability is classified in this category if acquired principally for the purpose of selling or re- purchasing in the short-term. Derivatives are also included in this category unless they are designated as hedges. (ii) Loans and receivables: Loans and receivables are initially measured at fair value plus directly attributable transaction costs and are subsequently recorded at amortized cost using the effective interest method. Long-term receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Long-term receivables are initially recognized at fair value based on the discounted cash flows. The discount rate is based on the credit quality and term of the financial instrument. The financial instrument is subsequently valued at amortized costs by accreting the instrument over the expected life of the assets. The accretion associated with instrument valued at amortized cost is reported on the statement of comprehensive loss each reporting period. The carrying amount of the long-term receivable less discounts represents the fair value of the receivable. The fair value of the Company’s trade and other receivables approximates their carrying values due to the short-term nature of these instruments. (iii) Other financial liabilities: Trade and other payables and the bank loan are classified as other financial liabilities and are initially measured at fair value less directly attributable transaction costs and are subsequent- ly recorded at amortized cost using the effective interest method. The fair value of the other financial liabilities approximates the carrying amounts due to the short-term nature of these instruments. Cash and cash equivalents Cash and cash equivalents include cash on hand, term deposits and short term highly liquid investments with the original term to maturity of three months or less, which are convertible to known amounts of cash and which, in the opinion of management, are subject to an insignificant risk of changes in value. The fair value of cash and cash equivalents approximates their carrying amount. As at 31 December 2013 US$9.8 million was held in Tanzania and there are no restrictions on the movement of funds out of Tanzania. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 201365 Impairment of financial assets A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in profit or loss. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in profit or loss. J) CONTRIBUTED SURPLUS This is used to record two types of transactions: (i) (ii) To recognise the fair value of equity settled stock based compensation expensed in the year. To account for the difference between the aggregated book value of the shares purchased under the normal course issuer bid and the actual consideration. K) EARNINGS OR LOSS PER SHARE (“EPS”) Basic earnings or loss per share is calculated by dividing profit or loss attributable to owners of the Company (the numerator) by the weighted average number of ordinary shares outstanding (the denominator) during the period. The denominator is calculated by adjusting the shares outstanding at the beginning of the period by the number of shares bought back or issued during the period, multiplied by a time-weighting factor. Diluted EPS is calculated by adjusting the earnings and number of shares for the effects of all dilutive potential ordinary shares deemed to have been converted at the beginning of the period or if later, the date of issuance. The effects of anti-dilutive potential ordinary shares are ignored in calculating diluted EPS. All options are considered anti-dilutive when the Company is in a loss position. L) NEW ACCOUNTING STANDARDS AND INTERPRETATIONS On 1st January 2013, the Company adopted new standards with respect to IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of Interests in Other Entities, as well as the consequential amendments to IAS 28 Investments in Associates and Joint Ventures (2011), IFRS 13 Fair Value Measurement and IFRS 7 Amendments to Financial Instrument Disclosures. The adoption of these standards had no impact on the amounts recorded in the financial statements. M) RECENT ACCOUNTING PRONOUNCEMENTS The following standards, amendments and interpretations applicable to the Company are in issue but not yet effective and have not been adopted in these consolidated financial statements. The Company has not yet determined the impact of the adoption of these amendments. NEW AND AMENDED STANDARDS Effective for annual periods beginning on or after IAS 19 (amendments) Employee Contributions 1 July 2014 IAS 32 (amendments) Offsetting Financial Assets and Liabilities 1 January 2014 IFRIC 21 Liability for Levies 1 January 2014 66 4 USE OF ESTIMATES AND JUDGEMENTS In applying the Company’s accounting policies, which are described in Note 3, 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 the Company. The reserve and cash flow information contained herein represents estimates only. The reserves and estimated future net cash flow from the Company’s properties have been independently evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”), independent petroleum engineers. 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 the Company. For the purpose of the reserves certification as at 31 December 2013, based on an assumption of economically rational behaviour, it was assumed that TPDC will ‘back-in’ for 20% for all future new drilling activities as determined by the current development plan and this is reflected in the Company’s net reserve position. Reserves are integral to the amount of depletion charged to the profit or loss. II) CARRYING VALUE OF EXPLORATION AND EVALUATION ASSETS AND PROPERTY, PLANT AND EQUIPMENT Under the Company’s accounting policy expenditures incurred on the exploration for, and evaluation of, reserves are capitalized as intangible assets. These intangibles assets are then assessed for impairment when circumstances suggest that the carrying amount may exceed its recoverable value. Such circumstances include but are not limited to: • • • • • • the period for which the Company has the right to explore in the specific area has expired during the period, or will expire in the near future, and is not expected to be renewed; no further expenditure on exploration and evaluation is budgeted or planned; no reserves have been encountered; the evaluation of seismic data indicates that the reserves are unlikely to be of a commercial quantity; the quantity of hydrocarbon 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. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 201367 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 de- terminable 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. Management performs impairment tests on the Company’s property, plant and equipment assets if indicators of impairment are present. The assessment of impairment indicators is subjective and considers the various internal and external factors such as the financial performance of individual CGUs, market capitalization and industry trends. If impairment indictors are present an impairment test is required to be performed and the CGU is written down to its recoverable amount. Key assumptions to determine the recoverable amount relate to prices that are based on forward curves, long-term assumptions and discount rates that are risked to reflect conditions specific to individual assets. III) FAIR VALUE OF STOCK BASED COMPENSATION All stock options issued or stock appreciation rights granted by the Company are required 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) the 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, whereas 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 these costs are subject to government audit and in exceptional circumstances a potential reassessment after the elapse of a considerable period of time. Currently approximately US$34 million in cost recoveries for the period 2001 to 2009 have been denied by TPDC, which audit finding is now the subject of a Notice of Dispute by the Company. 68 V) COLLECTABILITY OF RECEIVABLES The Company considers the Songas and TANESCO receivables to be collectable, despite being long overdue. Both Songas and the Company have been impacted by TANESCO’s inability to pay. There have been acknowledgements by TANESCO and the Ministry of Energy and Minerals (“MEM”) of the debt and the importance of addressing same. The recent Tanzania First and Second Power and Gas DPOs by the World Bank to ensure TANESCO’s viability support management’s view that the debts will be paid (see “Going Concern”). Given the irregularity and unpredictability of payments, the timing of repayment remains uncertain. Consequently management has reclassified an element of the TANESCO debt as long-term and has discounted the value of the receivable. The discount applied to the TANESCO receivable is based on a probabilistic assessment by management of a multi-scenario discounted cash flow model which incorporates a number of assumptions as to the timing and amount of cash receipts from TANESCO, timing of World Bank DPO disbursements to the Government of Tanzania, status of negotiations with the Government and/or World Bank for partial risk guarantees, expected operational start date for the NNGIP in Tanzania and the potential for an arbitration settlement. These assumptions are subject to change due to factors which are beyond the control of the Company. The Company has made a provision against the net Songas receivable, as ultimately the ability of Songas to pay is in turn dependent upon TANESCO settling is liabilities to Songas. The Company has a substantial “Tax Receivable” balance. This arises from the revenue sharing mechanism within the PSA which entitles the Company to a share of revenue equivalent to its tax charge, grossed up at the prevailing rate. These amounts are collected by way of an offset against TPDC’s share of revenue, as and when the Company pays its tax. VI) TPDC BACK-IN TPDC has previously indicated a wish to exercise its right under the PSA to ‘back in’ to the Songo Songo field development and a further wish to convert this into a carried interest in the PSA. The current terms of the PSA require TPDC to provide formal notice in a defined period and contribute a proportion of the costs of any development, sharing in the risks in return for an additional share of the gas. To date, TPDC has not contributed any costs. TPDC back-in rights and the potential conversion of these rights into a carried working interest were discussed with the GNT along with other issues, however conditions precedent to any potential change in the terms of the PSA as a result of the GNT were not met by the Government and as such the Company continues to stand behind the original terms of the PSA. The issue of any change to TPDC’s back-in rights has therefore not been resolved. Should an amendment to the PSA be agreed in future relating to back-in rights, the impact on reserves and accounting estimates will be assessed at that time and reflected prospectively. For the purpose of the reserves certification as at 31 December 2013, it was assumed that, on the basis of economically rational behavior, TPDC will elect to ‘back-in’ for 20% for all future new drilling activities with-in the prescribed period as determined by the current development plan and this is reflected in the Company’s net reserve position. VII) TPDC MARKETING COSTS Under the Songo Songo PSA, all reasonable marketing costs including those incurred by TPDC, with the prior approval by the Company are recoverable. TPDC has to date attempted to claim US$3.6 million in marketing costs from the Company. Management reviewed the claims and can demonstrate that there was no prior approval for such costs, no supporting documentation provided evidencing the expenditure, and further believes the nature of the costs to be unreasonable and not related to marketing the downstream business. Accordingly the Company has rejected the claim by TPDC. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 201369 VIII) TAXATION During 2013 the Company received a number of assessments for additional tax from the Tanzania Revenue Authority (“TRA”), which together with interest penalties total US$18.4 million. Management together with tax advisors have reviewed each of the assessments and believe them to be without merit. The Company has appealed against assessments for additional withholding tax and employment related taxes, and has filed formal objections against TRA’s claims for additional corporation tax and VAT. The Tax Revenue Appeals Board considered the Company’s appeal against a withholding tax assessment of US$2.4 million in March 2013 and upheld the assessment. The Company then appealed to Tax Revenue Appeals Tribunal whose decision is awaited. Although a similar appeal to the Tribunal has been decided in favour of TRA, management continues to believe this assessment is flawed and, if necessary, will pursue the case in the Court of Appeal where a similar case is currently being heard. The Company based on advice believes it has strong support, on the basis of tax legislation and the terms of the PSA, for its objection to the additional income tax assessment of US$7.8 million, including penalties. In the event that the Company’s objection is overturned, any additional tax payable will be recoverable from TPDC under the terms the PSA. The Company has filed an objection against a further assessment of VAT, which together with penalties totals US$7.5 million. Again, the Company based on advice believes that it has strong grounds for objecting to this assessment and accordingly has made no provision. The Company has received an assessment of US$0.7 million in respect of employment related taxes which TRA believe to have been underpaid. The Company does not accept TRA’s finding and has appealed. Management continues to review the progress of the above appeals and objections and, as of the date of this report, does not believe any provision is required. 5 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 as well as political risk associated with conducting operations in an emerging market. The Company seeks to manage its exposure to these risks wherever possible. I) FOREIGN EXCHANGE RISK Foreign exchange risk arises when transactions and recognised assets and liabilities of the Company are denominated in a currency that is not the US dollar functional currency. The Company operates internationally and is exposed to foreign exchange risk arising from currency exposures to US dollars. The main currencies to which the Company has an exposure are: Tanzanian shillings, UK 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 UK pounds sterling. All of the capital stock, equity financing and any associated stock based com- pensation 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. 70 A 10% increase in the US dollar against the relevant foreign currency would result in an overall increase in working capital of US$0.6 million to US$28.3 million and a reduction in the loss before tax to US$3.1 million. The sensitivity includes only outstanding foreign currency denominated monetary items and adjusts their translation at period end for a 10% change in the foreign currency rates. A 10% sensitivity rate is used when reporting foreign currency risk internally to key management personnel and represents management’s assessment of the reasonable possible change in foreign exchange rates. The following balances are denominated in foreign currency (stated in US Dollars at period end exchange rates): Balances as at December 31, 2013 US$’000s Canadian Dollars Tanzanian Shillings Other currencies Cash Trade and other receivables Trade and other payables II) COMMODITY PRICE RISK 96 – (139) (44) 1,394 19,506 (27,724) (6,824) 1,066 400 (992) 474 Total 2,556 19,906 (28,855) (6,393) 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”) and coal. The price of HFO is exposed to the volatility in the market price of crude oil. III) INTEREST RATE RISK The Company has a medium term loan which is repayable in twelve instalments, beginning in March 2013. The interest rate is defined in relation to LIBOR and the exposure to rate changes is considered minor. The final instalment of this loan was repaid in February 2014. IV) CREDIT RISK Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company’s receivables from TANESCO and Songas. The carrying amount of accounts receivable and the long-term receivable represents the maximum credit exposure. As of December 31, 2013 and 2012, other than the discount applied to the TANESCO receivable, the provision against receivable from Songas whilst set off is being negotiated and interest accrued from TANESCO arrears, the Company does not have an allowance for doubtful accounts against any other receivables nor was it required to write-off any other receivables. 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 contract with Songas for the supply of gas to the Ubungo power plant and a contract with TANESCO to supply approximately 37 MMcfd in 2013 to fire 147 MW of TANESCO power generation. The contracts with Songas and TANESCO accounted for 65% of the Company’s operating revenue during 2013 and US$68 million1 of the trade receivables at year-end. Songas itself is heavily reliant on the payment of capacity and energy charges by TANESCO for its liquidity. 1 Includes long-term TANESCO receivable of US$47.0 million. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 201371 Although TANESCO has a long history of delayed payments, it has prior to mid-2011, settled in full subsequent to the quarter end. However, during both 2012 and 2013, there has been a marked deterio- ration in the situation. Despite the Company receiving numerous assurances from TANESCO and the Government of Tanzania regarding payment, the outstanding balance has continued to grow. Since 31st December 2013, the Company has received US$6.4 million from TANESCO. As at the date of this report TANESCO owes the Company US$64.9 million. To reflect the uncertainly over timing of receipts the Company has discounted TANESCO receivables and reclassified a proportion as a long-term receivable. Sales to the Industrial sector, currently 37 customers, are subject to an internal credit review to minimize the risk of non-payment. As of the date of this report, all amounts outstanding at the year end have been collected from Industrial customers. The Company is currently in discussions with TPDC, acting in its proposed capacity as a gas aggregator, concerning the commercial terms for the sale of gas volumes associated with a planned expansion of Songo Songo production, the conditions for which are described under V) below. The Company has no history with TPDC as a debtor. Any contract with TPDC will expose the Company to additional credit risk with a parastatal entity in Tanzania. Management intends to manage such credit exposure by acquiring Partial Risk Guarantees against future payments under such contracts from the World Bank or other institutions. The Company manages the credit exposure related to cash and cash equivalents by selecting coun- terparties based on credit ratings and monitoring all investments to ensure a stable return, avoiding complex investment vehicles with higher risk such as asset backed commercial paper. V) LIQUIDITY RISK Liquidity risk is the risk that the Company will not have sufficient funds to meet its liabilities. Cash forecasts identifying liquidity requirements of the Company are produced on a 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$53.3 million of financial liabilities with regards to trade and other payables identified in Note 14 of which US$45.9 million is due within one to three months, nil is due within three to six months, and US$7.4 million is due within six to twelve months. The Company has a current taxation liability of US$1.9 million payable within six months. A significant proportion of the current liabilities relate to Songas and TPDC. Transactions between the Company and Songas currently show a net receivable from Songas. Management does not expect to fund settlement of the amount due in advance of collecting the receivable. The amounts due to TPDC represent a distribution of its share of Profit Gas; however given the difficulties in collecting from TANESCO, management expects to settle this liability on a pro rata basis in accordance with amounts received from TANESCO. Management anticipates that unless regular payments are secured from TANESCO over coming months, it will have to seek other sources of finance in order to maintain operations, which financing may be expensive or unavailable. In order to achieve collection of the TANESCO receivable the Company may have to have to utilise dispute resolution mechanisms and other remedies within the PGSA, including but not limited to possible suspension of gas supplies. In March 2014, the Company served TANESCO with a Notice of Dispute regarding arrears as a first contractual step in the collection process. 72 The development of additional productive capacity at Songo Songo, through the drilling of the SS-12 development well and work-overs of SS-3, SS-4, SS-5 and SS-9, is dependent upon: (i) agreeing commercial terms with TPDC or other buyers regarding the sale of incremental gas volumes from Songo Songo; (ii) TANESCO receivables being brought up to date, guaranteed or other arrangements for payment satisfactory to the Company; (iii) the establishment of payment guarantees with the World Bank or other multi-lateral lending agencies to secure future receipts under any contracts with Government entities; and (iv) the arrangement of finance with the IFC or other lenders. VI) CAPITAL RISK MANAGEMENT The Company’s objectives when managing capital are to safeguard the Company’s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to achieve an optimal capital structure to reduce the cost of capital. The level of risk currently in Tanzania prohibits the optimisation of capital structure as many sources of traditional capital are unavailable. The Company had a medium-term loan facility of US$10 million with a local Tanzanian bank which was drawn down in 2012 and 2013. At the year end, US$1.7 million was still outstanding, and since the year end this has been fully repaid. VII) COUNTRY RISK In late 2011, there was resolution by Parliament advising the Government to terminate the Company’s Songo Songo PSA on the gounds of an allegation by TPDC that the Company had over-recovered approximately US$21 million in Cost Gas revenue. Parliament itself does not have the authority to amend or terminate PSAs in Tanzania and in February 2012 on the recommendation of MEM, the Government announced that it was establishing a Government Negotiating Team (“GNT”) to discuss a number of issues raised in parliament in relation to the Company’s Songo Songo PSA. In Tanzania, government negotiating teams are a common mechanism to negotiate with business. The scope of the GNT was to discuss a number of issues that were raised by the Parliamentary Committee for Energy into the workings of the PSA. This included, but is not limited to, TPDC back in rights, profit sharing arrangements, the unbundling of the downstream assets, cost recovery and the Company’s management of the upstream operations. After making submissions to the GNT, the Company commenced discussions in April 2012 and further in July 2012, at which time a conditional agreement in principle was reached on a number of major points to resolve the issues. The GNT completed its mandate, and the responsibility for finalisation, documentation and implementation moved back to MEM. The conditional agreement in principle contemplated completion this process by the end of 2012 as well as a number of undertakings from TPDC and the Government. As at the date of this report none of undertakings of the Government or TPDC have been met and, with the exception of the alleged US$21 million Cost Gas over recovery discussed below, none of the issues are resolved. In response to a Notice of Dispute delivered by the Company, in March 2014, TPDC retracted its claim that the Company had over-recovered approximately US$21 million in Cost Gas, which in the opinion of management substantially exonerated the Company of allegations made by Parliament. Accordingly, the Company continues to rely upon its rights under the existing PSA and has initiated notices of dispute to resolve any remaining issues. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 201373 VIII) EVOLVING REGULATORY ENVIRONMENT The fiscal and regulatory environment for oil & gas exploration and development in Tanzania is in its infancy. Following the discovery of significant offshore natural gas resources by international exploration and development companies, there was pressure on the Government to create a clear fiscal and regulatory framework for the industry. In October 2013, the Government of Tanzania introduced a National Natural Gas Policy. The policy contemplates, among other things, a restruc- turing of TPDC, increasing government ownership and control over infrastructure and resources, strategic involvement in the LNG value chain, the establishment of TPDC as monopoly gas aggregator in the country, and the establishment of Government controlled natural gas prices. The policy as con- templated conflicts in a number of areas with the rights of the Company under the PSA and has the potential, if implemented by law in its current form to materially affect the Company’s business. The PSA has provisions to cause the parties to meet and agree changes in terms which would offset any changes in economic entitlement associated with a change in law. 74 IX) FINANCIAL INSTRUMENT CLASSIFICATION AND MEASUREMENT The Company classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instrument: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including expected interest rate, share prices, and volatility factors, which can be substan- tially observed or corroborated in the marketplace. Level 3 – Valuation in this level are those with inputs for the asset or liabilities that are not based on observable market data. The Company’s long-term trade receivable is considered a Level 3 measurement. 6 SEGMENT INFORMATION The Company has one reportable segment being international exploration, development and production of petroleum and natural gas. The Company currently has exploration and producing assets in Tanzania and exploration interests in Italy. US$’000 External Revenue (Loss)/profit after tax Non-cash charge1 Total Assets Total Liabilities Capital Additions Depletion & Depreciation Exploration assets impairment 2013 Italy Tanzania – (676) 54,718 (4,789) Total 54,718 (5,465) 27,604 27,604 210,719 210,976 90,503 1,288 12,498 90,724 1,288 12,498 – 257 221 – – 158 2012 Italy Tanzania – (8,284) – 834 714 7,531 – 77,259 26,613 – 211,410 85,595 47,164 9,281 Total 77,259 18,329 – 212,244 86,309 54,695 9,281 1 Material non-cash charges include a discount on long-term receivables of US$17.1 million and a provision of US$10.5 million for doubtful receivable accounts. – 158 8,284 – 8,284 ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 20137 REVENUE US$’000 Operating revenue Current income tax adjustment Deferred additional profits tax Revenue 75 YEARS ENDED 31 DECEMBER 2013 53,855 14,292 (13,429) 54,718 2012 64,192 16,530 (3,463) 77,259 The Company’s total revenues for the year amounted to US$54,718 after adjusting the Company’s operating revenue of US$53,855 by: i) ii) adding US$14,292 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 tax is payable. To account for this, revenue is adjusted to reflect the current income tax charge, which represents a 30% gross up of the current tax for the year (Note 10); and, subtracting US$13,429 for the deferred effect of Additional Profits Tax – this tax is considered a royalty and is netted against revenue. 8 PERSONNEL EXPENSES The average number of employees during the year was 91 (2012: 86). The costs are as follows: US$’000 Wages and salaries Social security costs Other statutory costs Stock based compensation YEARS ENDED 31 DECEMBER 2013 5,113 1,021 158 6,285 (209) 6,083 2012 4,725 239 312 5,276 1,152 6,428 Stock based compensation is recorded under general and administrative expenses in the statement of com- prehensive income. The balance of personnel expenses for 2013 of US$6.3 million (2012: US$5.3 million) is recorded in distribution and production expenses and general administrative expenses at US$0.2 million (2012: US$0.8 million) and US$6.1 million (2012: US$4.5 million) respectively. 76 9 NET FINANCE INCOME AND FINANCE COSTS US$’000 Interest income Interest charged on overdue trade receivables Gain on disposal of motor vehicle Finance income Interest expense Net foreign exchange loss Provision for doubtful accounts Discount of long-term receivable (see Note 11) Finance costs Net finance costs YEARS ENDED 31 DECEMBER 2013 – 2,636 10 2,646 (678) (626) (10,531) (17,073) (28,908) (26,262) 2012 23 – – 23 (315) (319) – – (634) (611) Interest income of US$2.6 million is due from TANESCO, under the terms of the PGSA, for late payment of gas supplied. This forms part of the TANESCO account receivable balance and has been fully provided against to reflect the uncertainty over the timing of collection. 10 INCOME TAXES Under the terms of the PSA the Company is liable to pay income tax at the corporate rate of 30% on profits generated in Tanzania. The amount paid is then recovered in full from TPDC by reducing its share of Profit Gas by the amount of current tax paid. The tax charge is as follows: US$’000 Current tax Deferred tax YEARS ENDED 31 DECEMBER 2013 10,010 (8,267) 1,743 2012 11,920 5,205 17,125 Total taxes of US$14.4 million (2012: US$7.7 million) were paid during the year, including provisional tax payments relating to current year profits amounting to US$8.4 million (2012: US$4.5 million). These are presented as a reduction in Tax Payable on the balance sheet. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2013 Tax Rate Reconciliation US$’000 (Loss)/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 Financing charge Stock-based compensation Exploration asset impairment Permanent differences 77 2013 (3,722) (1,117) 2,697 (16) (104) 47 236 1,743 2012 35,454 10,636 2,954 29 346 2,485 675 17,125 As at 31 December 2013, there were temporary differences between the carrying amount 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 2013. A deferred tax asset of US$2.2 million (2012: US$2.2 million) in respect of the Longastrino Italy exploration costs has not been recognised because it is not probable that there will be future profits against which this can be utilised. The deferred income tax liability includes the following temporary differences: US$’000 Differences between tax base and carrying value of property, plant and equipment Income tax recoverable Discount on receivable & provision for doubtful debt Other liabilities Employee bonuses, rent and insurance TPDC additional Profit Gas Deferred Additional Profits Tax AS AT 31 DECEMBER 2013 2012 17,081 10,182 (8,281) (341) – (6,509) 12,132 16,341 6,744 – (109) (102) (2,475) 20,399 78 Additional Profits Tax Under the terms of the PSA, in the event that all costs have been recovered with an annual return from the PSA of 25% plus the percentage change in the United States Industrial Goods Producer Price Index (“PPI”), 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. The effective APT rate of 30.8% (2012: 32.3%) was applied to Profit Gas of US$43.6 million (2012: US$10.7 million), accordingly, US$13.4 million (2012: US$3.5 million) has been netted off revenue for the year ended 31 December 2013. As a consequence of having to defer the development programme in 2012 all costs have now been recovered and at an operating level under the PSA the Company has earned a rate of return in excess 25%. Accordingly management estimates that APT of US$2.2 million will become payable in 2014 in accordance with the timing of the future development capital spending as set out in the independent engineering evaluation by McDaniel. The actual APT that will become payable over the life of the PSA will depend on the achieved value of the Additional Gas sales and the quantum and timing of the operating costs and capital expenditure program. Tax Receivable The Company has a “Tax Receivable” balance of US$14.6 million (2012: US$14.7 million). This arises from the revenue sharing mechanism within the PSA, which entitles the Company to a share of revenue equivalent to its tax charge, grossed up at the prevailing rate. This amount is collected by way of an offset against TPDC’s share of revenue, as and when the Company pays its tax. 11 TRADE AND OTHER RECEIVABLES Current Receivables US$’000 TANESCO Songas Other debtors Trade receivables Other receivables Less provision for doubtful accounts AS AT 31 DECEMBER 2013 9,624 11,560 10,874 32,058 15,688 (10,531) 37,215 2012 33,256 14,283 12,791 60,330 13,165 - 73,495 In addition to the trade receivable from Songas of US$11.6 million, an additional US$13.3 million (2012: US$10.3 million) is due from Songas with respect to Gas Plant operations, which is included in Other Receivables. All receivable amounts from Songas have been included in the net Songas balance of US$7.9 million (see Note 14) and a provision for doubtful debts is recognised for the full net receivable amount (see Note 9). ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2013 79 Trade Receivables Age Analysis As at 31 December, 2013 Current >30 <60 >60 <90 TANESCO Songas Other debtors Trade receivables 5,071 1,076 3,663 9,810 4,553 1,016 2,822 8,391 – 927 1,661 2,588 As at 31 December, 2012 Current >30 <60 >60 <90 TANESCO Songas Other debtors Trade receivables 4,894 1,134 7,935 13,963 5,655 992 2,491 9,138 5,321 1,114 1,816 8,251 >90 – 8,541 2,728 11,269 >90 17,386 11,043 549 28,978 Total 9,624 11,560 10,874 32,058 Total 33,256 14,283 12,791 60,330 Subsequent to 31 December 2013, US$6.4 million has been received from TANESCO, and US$10.9 million from other debtors. During the year, as a result of irregular and unpredictable payments by TANESCO, management reclassified the TANESCO balance more than 60 days as a long-term receivable and has discounted the value of the TANESCO receivable (see Note 1). The Songas trade receivable is less than equivalent trade payable and no contractual right of set off exists. Long-Term Receivables US$’000 TANESCO receivable > 60 days Discount on long-term receivable Net long-term receivable As at 31 December 2013 46,984 (17,073) 29,911 2012 – – – 80 12 EXPLORATION AND EVALUATION ASSETS US$’000 Costs As at 1 January 2013 Additions Impairment As at 31 December 2013 US$’000 Costs As at 1 January 2012 Additions Impairment As at 31 December 2012 TANZANIA Italy Tanzania Total 158 – (158) – 5,562 2 – 5,564 5,720 2 (158) 5,564 Italy Tanzania Total 911 7,531 (8,284) 158 2,010 3,552 – 5,562 2,921 11,083 (8,284) 5,720 The exploration and evaluation asset represents site survey costs and materials purchased in preparation for the drilling of the first Songo Songo West well (“SSW-1”). SSW-1 is part of the initial evaluation of the Songo Songo West prospect which is required to determine the existence of proven and probable reserves. Italy Pursuant to the terms of the Company’s Longastrino Block farm-in in the Po Valley Basin the Company spent a US$8.4 million related to the drilling of the La Tosca exploration well. The well was unsuccessful and in 2012 the Company treated US$8.3 million as impaired. The balance, relating to some residual materials has been treated as impaired in 2013. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 201381 13 PROPERTY, PLANT AND EQUIPMENT Oil and natural gas interests Leasehold improvements Computer equipment Vehicles Fixtures & Fittings Total US$’000 Costs As at 1 January 2013 138,958 Additions Disposals 114 – As at 31 December 2013 139,072 Depletion and Depreciation As at 1 January 2013 Charge for period Depreciation on disposals As at 31 December 2013 Net Book Values 37,801 12,166 – 49,967 256 629 – 885 219 26 – 245 747 325 – 1,072 649 112 – 761 202 – (65) 137 194 8 (65) 137 950 218 – 141,113 1,286 (65) 1,168 142,334 206 186 – 392 39,069 12,498 (65) 51,502 As at 31 December 2013 89,105 640 311 – 776 90,832 Oil and natural gas interests 96,014 42,944 – 138,958 28,833 8,968 – 37,801 US$’000 Costs As at 1 January 2012 Additions Disposals As at 31 December 2012 Depletion and Depreciation As at 1 January 2013 Charge for period Depreciation on disposals As at 31 December 2012 Net Book Values Leasehold improvements Computer equipment Vehicles Fixtures & Fittings Total 320 – (64) 256 271 12 (64) 219 701 46 – 747 520 129 – 649 249 – (47) 202 196 45 (47) 194 334 622 (6) 97,618 43,612 (117) 950 141,113 85 127 (6) 29,905 9,281 (117) 206 39,069 As at 31 December 2012 101,157 37 98 8 744 102,044 In determining the depletion charge, it is estimated that future development costs of US$239 million (31 December 2012: US$107.1 million) will be required to bring the total proved reserves to production. During the year the Company recognized depreciation of US$0.3 million (2012: US$0.3 million) in General and Administrative expenses. 82 14 TRADE AND OTHER PAYABLES US$’000 Songas Other trade payables Trade payables TPDC Accrued liabilities Related party (Note 18) AS AT 31 DECEMBER 2013 15,355 3,857 19,212 20,644 13,440 – 53,296 2012 17,459 4,458 21,917 4,378 19,030 171 45,496 The balances payable to Songas are net of amounts receivable from Songas that have been agreed as fully settled. The following table shows the amounts considered to have been settled by offsetting during the year. 1 January 2013 Transactions during the year (17,459) 14,283 10,287 (1,140) 5,971 (15,380) 11,607 6,208 (465) 1,970 Gross balance (32,839) 25,890 16,495 (1,605) 7,941 Set off 17,485 (14,329) (3,215) 59 – 31 December 2013 (15,354) 11,561 13,280 (1,546) 7,941 Pipeline tariff - payable Gas sales - receivable Gas plant operation - receivable Miscellaneous payable Net balances 15 BANK LOAN In September 2012, the Company closed a US$10 million 18-month bridge loan facility with a Tanzanian bank to finance the Company’s working capital requirements in Tanzania. The facility is secured by an assignment of accounts receivable and a fixed and floating charge on the assets of the Company. The Company drew the final US$4.0 million in February 2013. The principal drawn under the facility was repayable in 12 equal monthly instalments which commenced in March 2013. Interest was payable monthly at three-month US LIBOR plus 8%. An additional interest rate of 2% would have been applied for any period in which the TANESCO receivable was greater than 240-days. As at 31 December 2013, principal of US$1.7 million was outstanding under the loan, with the remaining balance fully paid by February 2014. Total payments of US$8.3 million were made during the year. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2013 83 16 CAPITAL STOCK a) Authorised 50,000,000 Class A Common Shares No par value 100,000,000 Class B Subordinate Voting Shares No par value 100,000,000 First Preference Shares No par value The Class A and Class B shares rank pari passu in respect of dividends and repayment of capital in the event of winding-up. Class A shares carry twenty (20) votes per share and Class B shares carry one vote per share. The Class A shares are convertible at the option of the holder at any time into Class B shares on a one-for-one basis. The Class B shares are convertible into Class A shares on a one-for-one basis in the event that a take-over bid is made to purchase Class A shares which must, by reason of a stock exchange or legal requirements, be made to all or substantially all of the holders of Class A shares and which is not concurrently made to holders of Class B shares. b) Changes in the capital stock of the Company were as follows: NUMBER OF SHARES Authorised Issued Amount Authorised Issued Amount 2013 2012 (000’s) Class A As at 1 January and 31 December Class B As at 1 January (US$’000) (US$’000) 50,000 1,751 983 50,000 1,751 983 100,000 32,892 84,000 100,000 32,746 83,627 Stock options exercised Normal course issuer bid – – 180 – 445 – – – 150 (4) 383 (10) As at 31 December 2013 100,000 33,072 84,445 100,000 32,892 84,000 FIRST PREFERENCE As at 31 December 100,000 – – 100,000 – – Total Class A, Class B and First Preference shares 250,000 34,823 85,428 250,000 34,643 84,983 All of the issued capital stock is fully paid. Stock Options Thousands of options or CDN$ Options Exercise Price Options Exercise Price 2013 2012 Outstanding as at 1 January 1,922 1.00 to 3.60 Forfeited/Expired Exercised Issued Outstanding as at 31 December – (180) – – 1.00 – 3,057 (1,385) (150) 400 1.00 to 13.55 4.75 to 13.55 1.00 3.18 1,742 1.00 to 3.60 1,922 1.00 to 3.60 84 The weighted average remaining life and weighted average exercise prices of options at 31 December 2013 were as follows: Exercise Price (CDN$) Number outstanding as at 31 Dec 2013 (‘000) Weighted Average Remaining Contractual Life (years) Number Exercisable as at 31 Dec 2013 (‘000) Weighted Average Exercise Price (CDN$) 1.00 3.18 3.60 1,092 400 250 1,742 0.67 4.00 2.75 1,092 400 250 1,742 1.00 3.18 3.60 Stock Appreciation Rights Thousands of stock appreciation rights or CDN$ SAR Exercise Price SAR Exercise Price Outstanding as at 1 January 2013 745 2.35 to 5.30 1,005 4.20 to 13.55 Expired Granted (i) (15) 300 5.30 2.12 Outstanding as at 31 December 2013 1,030 2.12 to 4.20 (690) 8.70 to 13.55 430 745 2.35 to 2.70 2.35 to 5.30 (i) A total of 300,000 stock appreciation rights were issued in July 2013 with an exercise price of CDN$2.12. These rights have a term of five years and vest in three equal instalments, the first third vesting on the anniversary of the grant date. There is no maximum liability associated with these rights. The Company records a charge to the income statement with respect to the stock appreciation rights using the Black-Scholes option pricing model every reporting period with a resulting liability being recognised in trade and other payables. In the valuation of stock appreciation rights at the reporting date, the following assumptions have been made: a risk free rate of interest of 1.25% stock volatility of 50% to 53%; 0% dividend yield; 0% forfeiture; and a closing price of CDN$2.35 per Class B share. As at 31 December 2013, a total accrued liability of US$0.4 million (2012: US$0.6 million) has been recognised in relation to the stock appreciation rights in other payables. The liability decreased by US$0.2 million during the year compared to an increase of US$0.4 million in 2012, due to the decline in the weighted average remaining contractual life, a lower share price and a lower volatility of the underlying shares. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 201317 EARNINGS PER SHARE Number of shares (‘000) Weighted average number of shares outstanding Class A and Class B shares Convertible securities Stock options Weighted average diluted Class A and Class B shares 85 AS AT 31 DECEMBER 2013 2012 34,719 34,642 – 34,719 811 35,453 The calculation of basic earnings per share is based on the comprehensive loss for the year of US$5.9 million (2012: income US$18.4 million) and a weighted average number of Class A and Class B shares outstanding during the period of 34,718,662 (2012: 34,641,593). In computing the diluted earnings per share, the effect of stock options is added to the weighted average number of Class A and Class B outstanding during the year. For 2013 the effective number was nil (2012: 811,386) shares, resulting in a diluted weighted average number of Class A and Class B shares of 34,718,662 for the year ended 31 December 2013 (2012: 35,452,979). No adjustments were required to the reported earnings from operations in computing diluted per share amounts. A total of 617,444 options were excluded as a result of being anti-dilutive to earnings per share. 18 RELATED PARTY TRANSACTIONS One of the non-executive Directors is a partner at a law firm. During the year, the Company incurred US$0.1 million (2012: US$0.4 million) to this firm for services provided. The transactions with this related party were made at the exchange amount. As at 31 December 2013 the Company has a total of US$ nil (2012:US$0.2 million) recorded in trade and other payables in relation to the related party. The Chief Financial Officer provided services to the Company through a consulting agreement with a personal services company. During the year the Company incurred fees and bonus compensation of US$0.6 million in respect of these services (2012: US$0.5 million). In 2012 the Chief Executive Officer also provided services to the Company through a consulting agreement and the Company incurred US$0.2 million in costs. The full Chief Executive Officer’s remuneration is included in Directors’ Emoluments (see Note 21). 86 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 escalated) 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 (108.3 Bcf as at 31 December 2013). The Company did not have a shortfall during the reporting period and does not anticipate a shortfall arising during the term of the Protected Gas delivery obligation to July 2024. The Gas Agreement may be superseded by an initialed 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 it whole in the event of a Protected Gas insufficiency. Should the IA be 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 is required to fund an escrow account at a rate of US$2.00/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, supported by the report of its independent engineers, 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 (the “Re-Rating Agreement”) 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 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. The Re-rating Agreement expired on 31st December 2012 and in September was extended by Songas to 31 December 2013. At this time, the Company knows of no reason to de-rate the Songas plant. Since 31 December 2013 production has continued at the higher rated limit and, given the Government’s interest in pursuing further development and increasing gas production, the Company expects this to continue. However there are no assurances that this will occur. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2013 87 Portfolio Gas Supply Agreement On 17 June 2011, a long term (to June 2023) PGSA was signed between the Company, TPDC and TANESCO. Under the PGSA, the seller 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. Under the agreement, the current basic wellhead is approximately US$2.88/mcf on 1 July 2014 this will increase to US$2.94/mcf. Any volumes of gas delivered under the PGSA in excess of 36 MMcfd are subject to a 150% increase in the basic wellhead gas price. Operating leases The Company has two office rental agreements, one in Dar es Salaam, Tanzania and one in Winchester, United Kingdom. The agreement in Dar es Salaam was entered into on 1 November 2013 and expires on 31 October 2015 at an annual rent of US$401 thousand. The agreement in Winchester expires on 25 September 2022 and is at an annual rental of GBP35 thousand (US$58 thousand) per annum during 2012 and 2013 and GBP71 thousand (US$115 thousand) per annum thereafter. The costs of these leases are recognised in the General and Administrative expenses. 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. No activity has occurred on the Adriatic Sea block during 2013. In 2012, a new law modified restrictions on offshore oil and gas exploration and production originally introduced by DLGS 128/2010 in August 2010. The Elsa-2 appraisal well is now expected to be drilled in 2015 following finalisation of an environmental impact study. The Company will not be liable for any costs associated with the drilling of Elsa-2 until a rig contract is signed. There are no further capital commitments in Italy at this time. Songo Songo Significant additional capital expenditure will be required to enable the Songo Songo field to produce 190 MMcfd in line with the anticipated infrastructure expansion. There are no contractual commitments either in the PSA or otherwise agreed for capital expenditure at Songo Songo. Any significant additional capital expenditure in Tanzania is discretionary and remains dependent on: (i) agreeing commercial terms with TPDC or other buyers regarding the sale of incremental gas volumes from Songo Songo; (ii) TANESCO receivables being brought up to date, guaranteed or other arrangements for payment satisfactory to the Company, (iii) the establishment of payment guarantees with the World Bank or other multi-lateral lending agencies to secure future receipts under any contracts with Government entities; and (iv) the arrangement of finance with the IFC or other lenders. The Company currently plans to finance Songo Songo development with a combination of cash, collection of TANESCO and Songas receivables, funds flow from operations, bank debt and financing to be arranged by IFC. There are no assurances that financing will be available or on reasonable terms to fund all or a portion of the Songo Songo development programme. The Company does not currently have any off-balance sheet financing arrangements. 88 20 CONTINGENCIES Downstream unbundling The separation or unbundling of the downstream assets currently in the PSA has been an objective of TPDC and MEM for some time. Unbundling was an issue raised by TPDC in the 2012 GNT negotiations and in the recently issued National Natural Gas Policy which contemplates TPDC as a monopoly aggregator and distributor of gas. In the context of the gas policy, TPDC and MEM have indicated that they wish Orca Exploration to unbundle the downstream distribution business in Tanzania. The methodology for this has been discussed with TPDC in the course of GNT negotiations. During the year, the Company tabled a proposal with alternative mechanisms to unbundle the downstream from the PSA which were economical- ly neutral to the parties. TPDC did not respond to the proposal and it was later withdrawn by the Company in connection with the termination of negotiations arising from the GNT and TPDC was advised that the downstream would remain in the PSA until mutually agreed otherwise. TPDC Back-in TPDC has previously indicated a wish to exercise its right under the PSA to ‘back in’ to the Songo Songo field development and a further wish to convert this into a carried interest in the PSA. The current terms of the PSA require TPDC to provide formal notice in a defined period and contribute a proportion of the costs of any development, sharing in the risks in return for an additional share of the gas. To date, TPDC has not contributed any costs. TPDC back-in rights and the potential conversion of these rights into a carried working interest were discussed with the GNT along with other issues, however conditions precedent to any potential change in the terms of the PSA as a result of the GNT were not met by the Government and as such the Company continues to stand behind the original terms of the PSA. The issue of any change to TPDC’s back-in rights has therefore not been resolved. Should an amendment to the PSA be agreed in future relating to back-in rights, the impact on reserves and accounting estimates will be assessed at that time and reflected prospectively. For the purpose of the reserves certification as at 31 December 2013, it was assumed that, on the basis of economically rational behavior, TPDC will elect to ‘back-in’ for 20% for all future new drilling activities with-in the prescribed period as determined by the current development plan and this is reflected in the Company’s net reserve position. Cost recovery The Company’s Cost Pool in Tanzania has been fully recovered resulting in a reduction in the percentage of net revenue attributable to the Company. TPDC conducted an audit of the historic Cost Pool and in 2011 disputed approximately US$34 million of costs that had been recovered from the Cost Pool from 2002 through to 2009. The Company has contended that the disputed costs were appropriately incurred on the Songo Songo project in accordance with the terms of the PSA. Undertakings to resolve this matter were an outcome of GNT negotiations and the matter was referred to the Controller and Auditor General (“CAG”), head of the National Audit Office of Tanzania. With no progress on resolving the matter, the Company served a Notice of Dispute on TPDC to put the matter to a definitive timeline for resolution, following which the CAG appointed an international independent audit firm to review the disputed costs; this team commenced work in March 2014 and has yet to report. If the matter is not resolved to the Company’s satisfaction, it intends to proceed to ICSID arbitration pursuant to the terms of the PSA. This matter has had no impact on the results for the period. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 201389 TPDC marketing costs Under the Songo Songo PSA, all reasonable marketing costs including those incurred by TPDC, with the prior approval by the Company are recoverable. TPDC has to date attempted to claim US$3.6 million in marketing costs from the Company. Management reviewed the claims and can demonstrate that there was no prior approval for such costs, no supporting documentation provided evidencing the expenditure, and further believes the nature of the costs to be unreasonable and not related to marketing the downstream business. Accordingly the Company has rejected the claim by TPDC. Taxation During 2013 the Company received a number of assessments for additional tax from the Tanzania Revenue Authority (“TRA”), which together with interest penalties total US$18.4 million at 31 December 2013. Management, together with tax advisors, have reviewed each of the assessments and believe them to be without merit. The Company has appealed against assessments for additional withholding tax and employment related taxes, and has filed formal objections against TRA’s claims for additional corporation tax and VAT. The Tax Revenue Appeals Board considered the Company’s appeal against a withholding tax assessment of US$2.4 million in March 2013 and upheld the assessment. The Company then appealed to Tax Revenue Appeals Tribunal whose decision is awaited. Although a similar appeal to the Tribunal has been decided in favour of TRA, management continues to believe this assessment is flawed and, if necessary, will pursue the case in the Court of Appeal where a similar case is currently being heard. The Company, based on legal counsel’s advice, believes it has strong support, on the basis of tax legislation and the terms of the PSA, for its objection to the additional income tax assessment of US$7.8 million, including penalties. In the event that the Company’s objection is overturned, any additional tax payable will be recoverable from TPDC under the terms the PSA. The Company has filed an objection against a further assessment of VAT, which together with penalties totals US$7.5 million. Again, the Company, based on legal counsel’s advice, believes that it has strong grounds for objecting to this assessment and accordingly has made no provision. The Company has received an assessment of US$0.7 million in respect of employment related taxes which TRA believe to have been underpaid. The Company does not accept TRA’s finding and has appealed. Management continues to review the progress of the above appeals and objections and, as of the date of this report, does not believe any provision is required. 90 21 DIRECTORS AND OFFICERS EMOLUMENTS US$’000 Directors Directors Officers Officers Year 2013 2012 2013 2012 Base 1,454 1,655 1,227 2,060 Share based Compensation Expense Bonus Total 335 510 175 470 – 1,789 402 2,567 – 1,402 750 3,280 The table above provides information on compensation relating to the Company’s officers and directors. Five officers and two non-executive directors comprised the key management personnel during the year ended 31 December 2013 (2012: six officers and four non-executive directors). Two of the officers are also directors and as such their remuneration has been included under directors emoluments in the table above. ORCA EXPLORATION GROUP INC. | 2013 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2013CORPORATE INFORMATION 91 W. David Lyons Chairman and Chief Executive Officer Winchester United Kingdom W. David Lyons Chairman and Chief Executive Officer Winchester United Kingdom OPERATING OFFICE PanAfrican Energy Tanzania Limited Oyster Plaza Building, 4th Floor Haile Selassie Road P.O. Box 80139, Dar es Salaam Tanzania Tel: + 255 22 2138737 Fax: + 255 22 2138938 William H. Smith Non-Executive Director Calgary, Alberta Canada David W. Ross Non-Executive Director Calgary, Alberta Canada Robert S. Wynne Chief Financial Officer Calgary, Alberta Canada REGISTERED OFFICE Orca Exploration Group Inc. P.O. Box 3152 Road Town Tortola British Virgin Islands BOARD OF DIRECTORS Robert S. Wynne Chief Financial Officer Calgary, Alberta Canada OFFICERS Stephen Huckerby Chief Accounting Officer St. Peters, Jersey Channel Islands INVESTOR RELATIONS W. David Lyons Chairman and Chief Executive Officer WDLyons@orcaexploration.com www.orcaexploration.com PanAfrican Energy Tanzania Limited PAE PanAfrican Energy Corporation Oyster Plaza Building, 4th Floor Haile Selassie Road P.O. Box 80139, Dar es Salaam Tanzania Tel: + 255 22 2138737 Fax: + 255 22 2138938 1st Floor Cnr St George/Chazal Streets Port Louis Mauritius Tel: + 230 207 8888 Fax: + 230 207 8833 INTERNATIONAL SUBSIDIARIES Orca Exploration Italy Inc. Orca Exploration Italy Onshore Inc. P.O. Box 3152, Road Town Tortola British Virgin Islands ENGINEERING CONSULTANTS McDaniel & Associates Consultants Ltd. Calgary, Canada AUDITORS KPMG LLP Calgary, Canada WEBSITE orcaexploration.com LAWYERS TRANSFER AGENT Burnet, Duckworth & Palmer LLP Calgary, Canada CIBC Mellon Trust Company Toronto & Montreal, Canada www.orcaexploration.com

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