Orchid Island Capital Annual Report 2016

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 . 2016 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 2016 OPERATING HIGHLIGHTS . . . . . 2 GAS RESERVES . . . . . 3 MANAGEMENT’S DISCUSSION & ANALYSIS . . . . . 5 MANAGEMENT’S REPORT TO SHAREHOLDERS . . . . . 42 AUDITORS’ REPORT . . . . . 43 FINANCIAL STATEMENTS . . . . . 44 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS . . . . . 48 CORPORATE INFORMATION . . . . . 75 GLOSSARY mcf Thousands of standard cubic feet MMcf Millions of standard cubic feet Bcf Tcf Billions of standard cubic feet Trillions of standard cubic feet MMcfd Millions of standard cubic feet per day MMbtu Millions of British thermal units 1P 2P 3P Kwh MW US$ Proven reserves Proven and probable reserves Proven, probable and possible reserves Kilowatt hour Megawatt US dollars HHV LHV High heat value Low heat value CDN$ Canadian dollars bar Fifteen pounds pressure per square inch Financial and Operating Highlights (Expressed in US$ unless indicated otherwise) OPERATING Daily average gas delivered and sold (MMcfd) Additional Gas Industrial Power Average price (US$/mcf) Industrial Power Weighted average Operating netback (US$/mcf) Additional Gas Gross Recoverable Reserves to end of license (Bcf) Proved Probable Proved plus probable Net Present Value, discounted at 10% (US$ millions) Proved Proved plus probable FINANCIAL Revenue Net cash flows from operating activities per share - basic and diluted (US$) Net income per share - basic and diluted (US$) Cash flow from operations (1) per share - basic and diluted (US$) Working capital (including cash) Cash Capital expenditures Long-term loan Outstanding Shares ('000) Class A Class B Total shares outstanding Weighted average diluted Class A and Class B shares (1) See MD&A – non-GAAP measures 1 fi n a n c a i l a n d o p e r a t i n g h g h i l i g h t s YEAR ENDED / AS AT DECEMBER 31 2016 2015 44.5 12.5 32.0 7.70 3.56 4.73 3.26 347 58 405 313 363 64,659 19,968 0.57 2,164 0.06 31,855 0.91 71,989 80,895 16,924 58,399 1,751 33,106 34,857 34,857 47.4 11.4 36.0 7.58 3.54 4.49 2.57 368 49 417 309 357 54,088 7,018 0.20 1,533 0.04 26,454 0.76 32,521 53,797 38,411 18,599 1,751 33,106 34,857 34,887 2 o p e r a t i n g h g h i l i g h t s 2016 Operating Highlights • • • Additional Gas deliveries and sales averaged 44.5 standard cubic feet per day (“MMcfd”) a decrease of 10% over the prior year (53.2 MMcfd). The decrease in Additional Gas volumes year over year is primarily the result of reduced nominations of natural gas volumes by TANESCO arising from cessation of a power generation contract with an independent power producer who was using the Company’s Additional Gas combined with the incremental natural gas supply to TANESCO from other gas suppliers. Total proved reserves for Additional Gas decreased 6% to 347 Bcf from 368 Bcf in the prior year and total proved plus probable reserves (“2P”) decreased 3% to 405 Bcf from 417 Bcf in the prior year. The decrease is a consequence of 2016 Additional Gas production of 16.3 Bcf off-setting the higher anticipated growth in Power demand in the latter half of the licence period. The net present value of the estimated future cash flows from the 2P reserves at a 10% discount rate (“NPV10”) increased 1.5% to US$363.0 million from US$357.4 million in the previous year. The increase is a result of the higher anticipated growth of the Power sector in the later part of the licence period and the deferral of the onshore workover program and the refrigeration project to 2018 from 2017. Revenue increased by 20% to US$64.7 million from US$54.1 million in the prior year. The increase in revenue is due to the impact of the capital expenditure associated with the Offshore Development Program which commenced in the third quarter of 2015. This entitled the Company to 85% of the field net revenue compared to 74% in 2015. This, along with the 5% increase in the weighted average price to US$4.73/Mcf from US$4.49/Mcf, more than offset the decline in sales volume. • Net income for the year increased by 41% to US$2.2 million or US$0.06 per share basic and diluted compared to US$1.5 million or US$0.04 per share in the prior year. The increase of US$10.0 million in revenue was offset by interest charges on the IFC loan as well as higher stock based compensation. • Net cash flow from operating activities increased by 185% to US$20.0 million (or US$0.57 per share diluted) from US$7.0 million (or US$0.20 per share diluted) in the prior year. The increase was primarily the result of higher revenue. • Cash flow from operations increased by 20% to US$31.9 million (or US$0.91 per share diluted) from US$26.5 million (or US$0.76 per share diluted) in the prior year. The increase was primarily the result of higher revenue. • Working capital increased 121% to US$72.0 million compared to US$32.5 million as at December 31, 2015. The increase is primarily the consequence of drawing down the US$40 million balance of the IFC loan offset by capital expenditures associated with the Offshore Program. The increase in cash to US$80.9 million from US$53.8 million as at December 31, 2015 accounted for 68% of the total increase in working capital over the twelve month period. • • At December 31, 2016 TANESCO owed the Company US$80.1 million excluding interest (including arrears of US$74.4 million) compared to US$69.8 million (including arrears of US$61.9 million) as at December 31, 2015. Current TANESCO receivables as at December 31 2016 amounted to US$5.7 million (2015: US$7.8 million). Prior to 2016 the Company had reached an understanding with TANESCO that it would continue to supply gas if TANESCO remained reasonably current with payments for gas deliveries. Based on a review of TANESCO’s payment history for the past three years performed in Q4 2016, the average cash received against invoices raised by TANESCO was 80%. Management concluded that this ratio would present a more accurate position with respect to TANESCO’s revenue and accounts receivable, and a decision was made to use this ratio to recognize TANESCO revenue. Effective October 1, 2016 the TANESCO accounts receivable will be recorded at 80% of the value of invoices raised. Since the year-end, TANESCO has paid the Company US$12.9 million, and as at the date of this report the total TANESCO receivable is US$74.8 million (of which US$74.4 million has been provided for). ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORT 3 g a s r e s e r v e s Gas Reserves The Company's natural gas reserves as at December 31, 2016 for the period to the end of its licence in October 2026 were evaluated by independent petroleum engineering consultants in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). The independent reserves evaluation is dated March 14, 2017 with the effective date of December 31, 2016. A reserves committee of the Company reviews the qualifications and appointment of the independent reserves evaluator and reviews the procedures for providing information to the evaluators. Reserves included herein are stated on a Company gross basis unless noted otherwise. All the Company's reserves are conventional natural gas reserves and are located in Tanzania. Additional reserves information required under NI 51-101 are included in Orca's reports relating to reserves data and other oil and gas information under NI 51-101, which have been filed on its profile on SEDAR at www.sedar.com. The completion of the SS-12 development well in February 2016 encountered the top reservoir approximately 100 meters high to prognosis. A petrophysical update was also undertaken taking into account the well results. On a gross Company basis there has been a 6% decrease in Songo Songo’s Total Proved Additional Gas reserves to the end of the license period, with no change on a life of field basis, with a total Additional Gas production of 16.3 Bcf during the year. There has been a 3% decrease in the Proved plus Probable Additional Gas reserves on a Gross Company life of license basis from 416.9 Bcf to 405.3 Bcf with no change on a life of field basis. A summary of the remaining Additional Gas reserves on a life of license and life of field basis are presented below: Songo Songo Additional Gas reserves to October 2026 (Bcf) Independent reserves evaluation Proved producing Proved developed non-producing Proved undeveloped Total proved (1P) Probable Total proved and probable (2P) Gross (1) 2016 Net (2) 343.6 209.6 3.8 – 347.4 57.9 405.3 2.2 – 211.8 47.4 259.2 Gross 245.9 – 121.9 367.8 49.1 416.9 2015 Net 158.5 – 70.5 229.0 40.9 269.9 (1) Gross equals the gross reserves that are available for the Company after estimating the effect of the TPDC back in (see below). (2) Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the PSA. Songo Songo Additional Gas reserves to end of field life (Bcf) Independent reserves evaluation Proved producing Proved developed non-producing Proved undeveloped Total proved (1P) Probable Total proved and probable (2P) Gross (1) 595.0 47.0 – 642.0 117.5 759.5 2016 Net (2) 365.9 26.5 – 392.4 84.9 477.3 Gross 598.9 – 46.5 645.4 116.5 761.9 2015 Net 375.9 – 28.3 404.2 76.7 480.9 (1) Gross equals the gross reserves that are available for the Company after estimating the effect of the TPDC back in (see below). (2) Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the PSA. 4 Gas Reserves For the reserves certification as at December 31, 2016, the McDaniel Report has assumed that TPDC will exercise its right to ‘back in’ to any additional new field development plans for Songo Songo and consequently will receive a 20% increase in the profit share for the future production emanating from the Songo Songo North well, 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 their working interest share. For the purpose of calculating the Gross Additional Gas reserves, McDaniel has assumed in its 2P case that 111 Bcf (2015: 122 Bcf) or an average of 14.5 Bcf per annum will be required to meet the demands of the Protected Gas users from January 1, 2017 to July 31, 2024. During 2016 the Protected Gas users consumed 13.7 Bcf. Additional Gas price 1P US$/mcf 4.33 4.21 4.21 4.29 4.41 4.50 4.60 4.65 4.67 4.77 Year 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Gross Additional Gas volumes 1P MMcfd 46.93 60.57 78.47 87.84 90.86 99.97 107.36 121.77 145.08 145.08 Additional Gas price 2P US$/mcf 4.38 4.19 4.29 4.35 4.44 4.55 4.70 4.76 4.78 4.88 Gross Additional Gas volumes 2P MMcfd 50.30 84.05 89.81 103.23 113.49 121.88 123.40 141.29 164.60 164.60 Present value of reserves The estimated values of the Songo Songo reserves on a life of license basis are as follows: US$ millions Proved producing Proved developed non producing Proved undeveloped Total proved (1P) Probable Total proved and probable (2P) 5% 404.6 2.2 – 406.8 63.7 470.5 10% 312.1 1.0 – 313.1 49.9 363.0 2016 15% 247.3 0.3 – 247.6 40.3 287.9 5% 294.6 – 114.7 409.3 65.9 475.2 10% 229.2 – 79.4 308.6 48.8 357.4 2015 15% 184.6 – 55.5 240.1 37.7 277.8 There has been a 1.5% increase in the 2P present value at a 10% discount basis from US$357.4 million to US$363.0 million on a life of licence basis. The increase is due to a higher than anticipated growth in sales of Additional Gas to the NNGIP in the latter part of the licence period, the deferral of the onshore workover program and refrigeration capital expenditure from 2017 to 2018. O R C A E X P L O R A T I O N G R O U P I N C . ORCA EXPLORATION GROUP INC. | 2016 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 . 2016 MANAGEMENT’S DISCUSSION & ANALYSIS 6 THIS MD&A OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS SHOULD BE IN CONJUNCTION WITH THE AUDITED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES FOR THE YEAR ENDED DECEMBER 31, 2016. THIS MD&A IS BASED ON THE INFORMATION AVAILABLE ON APRIL 12, 2017. FORWARD LOOKING STATEMENTS This management’s discussion and analysis (“MD&A”) contains forward-looking statements or information (collectively, “for- ward-looking statements”) within the meaning of applicable securities legislation. More particularly, this MD&A contains, without limitation, forward-looking statements pertaining to the following: the Company’s expectations regarding supply and demand of natural gas; anticipated power sector revenues; potential impact of Tanzanian Production Development Corporation (“TPDC”) future back-in rights on the economic terms of the Production Sharing Agreement (“PSA”); ability to meet all conditions under the International Finance Corporation (“IFC”) financing agreement signed on October 29, 2015; the Company’s estimated spending for the planned Development Program for 2017 and 2018, which includes construction of the production platform for well SS-12, tie-in of well SS-12 to the production facilities and implementation of a refrigeration unit to enable production into the National Natural Gas Infrastructure Project (“NNGIP”) which includes two gas processing facilities and pipelines supplying gas from the Mtwara Region of Tanzania and Songo Songo Island to Dar es Salaam; the potential impact of the Petroleum Act, 2015 (“Act”) and the Finance Act, 2016 on the Company’s business in Tanzania; the Company’s belief that the parties to the unsigned Amended and Restated Gas Agreement (“ARGA”) will continue to conduct themselves in accordance with the ARGA until the new Gas Sales Agreement (“NGSA”) is signed; the Company’s expectation that, despite the Re-Rating Agreement of the gas processing plant owned by Songas Limited (“Songas”) having expired, the Songas gas processing plant will not be de-rated or production through the plant restricted; the risk that Songas and the Company will not agree on appropriate terms and sign the NGSA in a timely manner; the Company’s expectation that it can expand and maintain the deliverability of gas volumes in excess of the existing Songas infrastructure; the forward-looking statements under “Contractual Obligations and Committed Capital Investment”; the Company’s expectation that it will not have a shortfall during the term of the Protected Gas delivery obligation to July 2024; and the Company’s expectations in respect of its appeal on the decision of the Tax Revenue Appeals Tribunal and other statements under “Contingencies – Taxation”. 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 the Company’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 the Company’s control, and many factors could cause the Company’s actual results to differ materially from those expressed or implied in any forward-looking statements made by the Company, including, but not limited to: failure to receive payments from the Tanzanian Electrical Supply Company (“TANESCO”); risk that the planned financing solutions to resolve the TANESCO arrears are not implemented by the Tanzanian government; risk that planned financing provided by the World Bank will not be completed or funds will not be allocated to resolving TANESCO arrears; risk that TPDC, the Ministry of Energy and Minerals (“MEM”) and the Company are unable to agree on commercial terms for future incremental gas sales and consequently the Company cannot expand the Songo Songo development beyond the existing Songas infrastructure and supply gas to the NNGIP; risk that additional gas volumes available to the NNGIP from third parties will replace all or a portion of the volumes currently nominated by TANESCO under the Portfolio Gas Sales Agreement (“PGSA”) until additional gas-fired power generation is brought on-stream to consume all of the Company’s available gas production; risk that the Development Program is not completed as planned and the actual cost to complete the Development Program exceeds the Company’s estimates; risk that the remaining well workovers under the Development ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis7 Program are unsuccessful or determined to be unfeasible; risk that the contingencies related to the development work for the full field development plan for Songo Songo are not satisfied; potential negative effect on the Company’s rights under the PSA and other agreements relating to its business in Tanzania as a result of the recently approved Act, as well as the risk that such legislation will create additional costs and time connected with the Company’s business in Tanzania; risk that, without extending or replacing the Re-Rating Agreement, the gas being processed through the Songas gas processing plant may be reduced back to its original capacity, resulting in a material reduction in the Company’s sales volumes of Additional Gas; risk that the Company will not fully recover Songas’ share of capital expenditures associated with the workovers of wells SS-5 and SS-9; risk that the Company will not be successful in appealing claims made by the Tanzanian Revenue Authority (“TRA”) and may be required to pay additional taxes and penalties; the impact of general economic conditions in the areas in which the Company operates; civil unrest; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations, impact of new local content 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 satisfy debt obligations and conditions; failure to successfully negotiate agreements; and risk that the Company will not be able to fulfil its contractual obligations. In addition, there are risks and uncertainties associated with oil and gas operations, therefore the Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by these forward-looking statements will transpire or occur, or if any of them do so, what benefits the Company 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 the Company in light of its experience and perception of historical trends, current conditions and expected future developments, as well as other factors the Company believes are appropriate in the circumstances, including, but not limited to, the TPDC, the MEM and the Company are able to agree on commercial terms for future incremental gas sales and the Company can expand Songo Songo development beyond the existing Songas infrastructure and supply gas to the NNGIP; the Development Program will be completed within the timing anticipated; the actual costs to complete the Development Program are in line with estimates; that there will continue to be no restrictions on the movement of cash from Mauritius or Tanzania; 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 the Company to increase production at a consistent rate; infrastructure capacity; commodity prices will not further deteriorate significantly; the ability of the Company to obtain equipment and services 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’s appeal of various tax assessments will be successful; that the enactment of the Act in Tanzania will not impair the Company’s rights under the PSA to develop and market natural gas in Tanzania; 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 the Company 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. management's discussion & analysis 8 NON-GAAP MEASURES THE COMPANY EVALUATES ITS PERFORMANCE USING A NUMBER OF NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES) MEASURES. THESE NON-GAAP MEASURES ARE NOT STANDARDISED AND THEREFORE MAY NOT BE COMPARABLE TO SIMILAR MEASUREMENTS OF OTHER ENTITIES. • CASH FLOW FROM OPERATIONS REPRESENTS NET CASH FLOW FROM OPERATING ACTIVITIES LESS INTEREST PAID AND BEFORE CHANGES IN NON-CASH WORKING CAPITAL. THIS IS A NEW KEY PERFORMANCE MEASURE THAT MANAGEMENT BELIEVES REPRESENTS THE COMPANY'S ABILITY TO GENERATE SUFFICIENT CASH FLOW TO FUND CAPITAL EXPENDITURES AND REPAY DEBT. • 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. • CASH FLOW FROM OPERATIONS PER SHARE IS CALCULATED ON THE BASIS OF THE CASH FLOW FROM OPERATIONS DIVIDED BY THE WEIGHTED AVERAGE NUMBER OF SHARES. • NET CASH FLOW FROM OPERATING ACTIVITIES PER SHARE IS CALCULATED AS NET CASH FLOW FROM OPERATING ACTIVITES 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. NATURE OF OPERATIONS The Company’s principal operating asset is its interest in the PSA with 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 Block offshore Tanzania. The PSA defines the gas produced from the Songo Songo field as “Protected Gas” and “Additional Gas”. The Protected Gas is owned by TPDC and is sold under a 20-year gas agreement (until July 31, 2024) to Songas. Songas is the owner of the infrastructure that enables the gas to be treated and delivered to Dar es Salaam, which includes a gas processing plant on Songo Songo Island. Songas utilizes the Protected Gas as feedstock for its gas turbine electricity generators at Ubungo and for onward sale to customers. The Company receives no revenue for the Protected Gas delivered to Songas and operates the original wells 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 Block in excess of the Protected Gas requirements (“Additional Gas”) until the PSA expires in October 2026. TANESCO is a parastatal organization which is wholly-owned by the Government of Tanzania, with oversight by the MEM. TANESCO is responsible for the generation, transmission and distribution of electricity throughout Tanzania. Natural gas has become an integral component of TANESCO’s power generation fuel mix as a more reliable source of supply over seasonal hydro power and a more cost effective alternative to liquid fuels. The Company currently supplies gas directly to TANESCO by way of the PGSA and indirectly through the supply of Protected Gas and Additional Gas to Songas which in turn generates and sells power to TANESCO. TANESCO is the Company’s largest customer and the gas supplied by the Company to Songas and TANESCO today fires approximately 35% of the electrical power generated in Tanzania and 55% of the gas utilized for power generation in the country. In addition to gas supplied to Songas and TANESCO for the generation of power, the Company has developed and supplies an industrial gas market in the Dar es Salaam area consisting of some 38 industrial customers. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis9 Consolidation The companies which are 100% owned 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 (“PAET”) Orca Exploration UK Services Limited Incorporated British Virgin Islands British Virgin Islands British Virgin Islands Mauritius Jersey United Kingdom PRINCIPAL TERMS OF THE TANZANIAN PSA AND RELATED AGREEMENTS The principal terms of the Songo Songo PSA and related agreements are as follows: Obligations and restrictions (a) The Company has the right to conduct petroleum operations, market and sell all Additional Gas produced and share the net revenue with TPDC for a term of 25 years, expiring in October 2026. (b) The PSA covers the two licenses in which the Songo Songo field is located (“Discovery Blocks”). The Proven Section is essentially the area covered by the Songo Songo field within the Discovery Blocks. (c) No sale of Additional Gas may be made from the Discovery Blocks, if in the Company’s reasonable judgment such sales would jeopardize the supply of Protected Gas. Any Additional Gas contracts entered into are subject to interruption. Songas has the right to request that the Company and TPDC obtain security reasonably acceptable to Songas prior to making any sales of Additional Gas from the Discovery Block to secure the Company’s and TPDC’s obligations in respect of Insufficiency (see (d) below). (d) “Insufficiency” occurs if there is insufficient gas from the Discovery Blocks to supply the Protected Gas requirements or if the gas 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, 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. management's discussion & analysis10 Access and development of infrastructure (f) The Company is able to utilize 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 utilized by any third party who wishes to process or transport gas. Songas is not required to incur capital costs with respect to additional processing and transportation facilities unless the construction and operation of the facilities are, in the reasonable opinion of Songas, financially viable. If Songas is unable to finance such facilities, Songas shall permit the seller of the gas to construct the facilities at its expense, provided that, the facilities are designed, engineered and constructed in accordance with good pipeline and oilfield practices. Revenue sharing terms and taxation (g) 75% of the gross field revenue, less processing and pipeline tariffs and direct sales taxes in any year (“field net revenue”) can be used to recover past costs incurred. Costs recovered out of field net revenue 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 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 ratable 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. For the purpose of the reserves certification as at December 31, 2016, it was assumed that TPDC will ‘back-in’ for 20% for all future new drilling activities as determined by the current submitted Additional Gas 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 January 1, 2010. The Company’s long-term gas price to the Power sector as set out in the unsigned ARGA and the 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. As at the date of this report, the ARGA remains an initialed agreement only and the parties are not in agreement with all the terms in the ARGA, however the parties are conducting themselves in terms of pricing as though the ARGA is in force. The Company and Songas are currently reviewing the terms of a new sales agreement. In 2011 the Company signed a re-rating agreement with TANESCO, TPDC and Songas (the “Re-Rating Agreement”) which evidenced an increase to the gas processing capacity of the Songas facilities 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 paid additional compensation of US$0.30/mcf for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd by issuing credit notes to TANESCO. This was in addition to the tariff of US$0.59/mcf payable to Songas as set by the energy regulator, EWURA. In May 2016 the Company notified TANESCO and Songas that the additional compensation for sales over 70 MMcfd would no longer be paid effective June 2016. The additional compensation was always intended to be temporary in nature until the expansion of the Songas infrastructure, at which time Songas would apply to EWURA to obtain approval of a new tariff for the processing of volumes over 70 MMcfd. The PGSA provides for passing on to TANESCO any tariff to be charged to the Company and in the event that a new tariff is approved. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 11 The parties are seeking to resolve the status of the re-rating agreement. The processing capacity at the Songas facilities remain unaltered and are fully utilized by the company. Without a new agreement, there are no assurances that Songas will continue to allow the gas plant to operate above 70 MMcfd. 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’s or Songas’ insurance policies. 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. (i) Profits on sales from the Proven Section (“Profit Gas”) are shared between TPDC and the Company, the proportion of which is dependent on the average daily volumes of Additional Gas sold or cumulative production. The Company receives a higher share of the field net revenue after cost recovery, based on the higher of the cumulative 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 percentage share of Profit Gas. The Company is liable for 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. (j) “Additional Profits Tax” (or “APT”) is payable when 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 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. (k) 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 improvements, contract maintenance, maintenance of books and records, preparation of reports, maintenance of permits, waste handling, liaison with the Government of Tanzania and taking all necessary safety, 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. (l) In the event of loss arising from Songas’ failure to perform, and the loss is not fully compensated by Songas 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 willful misconduct of the Company, its subsidiaries or employees, and (ii) Songas has insufficient funds to cure the loss and operate the project. management's discussion & analysis 12 Results for the year ended December 31, 2016 SUMMARY During the year ended December 31, 2016 the Company successfully completed the drilling of well SS-12. This completed all work-over and drilling activities planned under the Offshore Development Program which commenced in the third quarter of 2015. Based on our evaluation of the drilling and testing results, the Company estimates that total field production capabilities will increase to 180 MMcfd once the SS-12 production platform is completed and the well is tied into the NNGIP infrastructure. Total capital expenditures for the year were US$16.9 million (2015: US$38.4 million). For the year ended December 31, 2016 there was a decrease of 3% from the prior year in 2P reserve volumes primarily related to gas produced during the year. Despite the overall decline in sales volume the change in sales mix with increased forecast industrial sales has resulted in the net present value of cash flows from 2P reserves at a 10% discount rate decreasing by 1% compared to the prior year. Despite a 6% decline in the volume of Additional Gas sold there was a 20% increase in revenue for 2016. The increase being a consequence of the revenue sharing mechanism of the PSA, whereby the Company is entitled to a higher percentage of total sales due to the recovery of capital costs associated with the Offshore Development Program. The increase in revenue is a primary factor in the 185% increase in net cash flow from operating activities to US$20.0 million (2015: US$7.0 million) and a 41% increase in cash flow from operations to US$30.5 million (2015: US$26.5 million). The Company recorded net income of US$2.2 million (2015: US$1.5 million) for the year despite recording an additional US$12.4 million provision against the TANESCO long term receivable. The Company finished 2016 in a stable financial position with US$72.0 million in working capital (2015: US$32.5 million) and US$58.4 million in long-term debt (2015: US$18.6 million) with the change resulting from drawing down the balance of the International Finance Corporation financing facility. OPERATING VOLUMES The total volume of Protected Gas and Additional Gas delivered and sold for the year was 29,961 MMcf (2015: 31,485 MMcf) or 82.0 MMcfd (2015: 86.28 MMcfd), net of approximately 0.5 MMcfd (2015: 0.5 MMcfd) consumed locally for fuel gas. The Additional Gas sales volumes for the year were 16,291 MMcf (2015: 17,311 MMcf) or average daily volumes of 44.5 MMcfd (2015: 47.4 MMcfd). This represents a decrease in average daily volumes of 6% year on year. Additional Gas sales volumes for Q4 2016 were 4,121 MMcf (Q4 2015: 4,572 MMcf) or average daily volumes of 44.8 MMcfd (Q4 2015: 49.7 MMcfd), a decrease of 10% over the prior year quarter. The decrease in Additional Gas volumes year over year is primarily a result of reduced nominations of natural gas volumes by TANESCO arising from the cessation of a power generation contract with an independent power producer who was using the Company’s Additional Gas; incremental natural gas supply to TANESCO from other gas suppliers; and suspension of power generation by Songas in the early part of Q1 2016 due to issues of non-payment by TANESCO. The decline in natural gas supplied to the power sector was partially offset by the increase in gas supplied to the industrial customers. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis13 The Company’s gross sales volumes were split between the Industrial and Power sectors as detailed in the table below: Gross sales volume (MMcf) Industrial sector Power sector Total volumes Gross daily sales volume (MMcfd) Industrial sector Power sector Total daily sales volume THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31 2016 2015 2016 2015 1,226 2,895 4,121 13.3 31.5 44.8 1,089 3,483 4,572 11.8 37.9 49.7 4,587 11,704 16,291 12.5 32.0 44.5 4,166 13,145 17,311 11.4 36.0 47.4 Industrial sector Industrial sales volume for the year increased by 10% to 4,587 MMcf (12.5 MMcfd) from 4,166 MMcf (11.4 MMcfd) in 2015. Fourth quarter Industrial sales volume increased by 13% to 1,226 MMcf (13.3 MMcfd) from 1,089 MMcf (11.8 MMcfd) in the prior year quarter. The increased volumes are primarily the result of fewer days of unscheduled maintenance work by cement, textile and edible oil companies and consumption by new customers connected during the first half of 2016. Power sector Power sector sales volumes for the year decreased by 11% to 11,704 MMcf (32.0 MMcfd), compared to 13,145 MMcf (36.0 MMcfd) in 2015. Power sector sales volumes decreased by 17% to 2,895 MMcf (31.5 MMcfd), compared to 3,483 MMcf (37.9 MMcfd) in Q4 2015. The decrease in volumes over the year is primarily a result of reduced nominations of natural gas volumes by TANESCO arising from the cessation of a power generation contract with an independent power producer who was using the Company’s Additional Gas; incremental natural gas supply to TANESCO from other gas suppliers; and suspension of power generation by Songas during parts of the year due to issues of non-payment with TANESCO. management's discussion & analysis 14 SONGO SONGO DELIVERABILITY As at December 31, 2016 the Company had a field productive capacity of approximately 155 MMcfd, with the ability to expand production capacity to 180 MMcfd with the tie-in of well SS-12. The SS-12 well was successfully completed in the first quarter of 2016 but is currently suspended awaiting tie-in. Production volumes are currently limited to 102 MMcfd, as only the Songas infrastructure is available to the Company. The Company now has significant redundant productive capacity. The well SS-3 is currently suspended and well SS-4 has been shut-in; it is the Company’s intention to undertake workovers on both the wells in the future. The SS-12 well has been identified for connection to the NNGIP infrastructure subject to the negotiation with TPDC for additional gas sales. Volumes sold to TPDC under this agreement would initially result in concomitant reduction in volumes through the existing Songas infrastructure. This would provide the Company the opportunity to increase sales volumes to industrial customers as production capacity would no longer be constrained by the Songas infrastructure. COMMODITY PRICES The commodity prices achieved in the different sectors during the year is detailed in the table below: US$/mcf Average sales price Industrial sector Power sector Weighted average price THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31 2016 2015 2016 2015 7.52 3.57 4.75 7.62 3.56 4.51 7.70 3.56 4.73 7.58 3.54 4.49 Industrial sector The average gas price achieved during the year was US$7.70/mcf up 2% from (2015: US$7.58/mcf). The overall increase in the average gas price is a consequence of a contractual step change in the gas price to the cement company that came into effect on January 1, 2016 against a similar mix of sales year over year. The average industrial price in the fourth quarter was US$7.52/mcf down 1% from Q4 2015 (US$7.62/mcf). The decline in the average industrial price is the result of re-setting the floor price for a number of industrial customers at the end of the third quarter. Power sector The average sales price to the Power sector was US$3.56/mcf for the year (2015: US$ 3.54 /mcf), an increase of 1%. The average sales price to the Power sector in the fourth quarter was US$3.57/mcf, compared with US$3.56/mcf in Q4 2015. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis15 OPERATING REVENUE Under the terms of the PSA, the Company is responsible for invoicing, collecting and allocating the revenue from Additional Gas sales. The Company is able to recover all costs incurred on the exploration, development and operations of the project up to a maximum of 75% of the Net Revenue (“Cost Gas”) prior to the distribution of Profit Gas. Any costs not recovered in any period are carried forward for recovery out of future revenues. Once the Cost Gas has been recovered, TPDC is able to recover any pre-approved marketing costs. The Additional Gas sales volumes for 2016 were below 50 MMcfd and, as a consequence, the Company was entitled to a 40% share of Profit Gas revenue for the year compared to 55% for sales volumes above 50 MMcfd. See “Principal Terms of the Tanzanian PSA and Related Agreements.” The Company was allocated a total of 85% of the Songo Songo field net revenue in 2016 (2015: 74%). The increase in allocation of the net revenue is a consequence of the Offshore Development Program which enabled the Company to be entitled to the maximum Cost Gas allocation due to the increase in the cost pool. The Offshore Development Program commenced in the third quarter of 2015 and was completed in the first quarter of 2016. US$’000 Gross field revenue Tariff for processing plant and pipeline infrastructure Field net revenue Analysed as to: Company Cost Gas Company Profit Gas Company operating revenue TPDC share of revenue Field net revenue THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31 2016 2015 2016 2015 17,920 21,288 75,377 79,885 (2,433) 15,487 (3,229) 18,059 (10,057) 65,320 (12,282) 67,603 11,615 1,549 13,164 2,323 15,487 13,544 1,806 15,350 2,709 18,059 48,990 6,532 55,522 9,798 65,320 38,689 11,565 50,254 17,349 67,603 The Company’s reported revenue for the quarter and the year amounted to US$16.5 million and US$64.7 million respectively, after adjusting the Company’s operating revenues of US$13.2 million and US$55.5 million by: i) Adding US$3.7 million for income tax for the quarter and US$10.4 million for 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. To account for this, revenue is adjusted to include the current income tax charge grossed up at 30%; and ii) Subtracting US$0.3 million and US$1.2 million for deferred Additional Profits Tax charged in the quarter and for the year. This tax is considered a royalty and is presented as a reduction in revenue. management's discussion & analysis 16 Revenue presented on the Consolidated Statements of Comprehensive Income may be reconciled to the operating revenue as follows: US$’000 Industrial sector Power sector Gross field revenue Processing and transportation tariff Field net revenue TPDC share of revenue Company operating revenue Additional Profits Tax charge Current income tax adjustment Revenue THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31 2016 2015 2016 2015 9,506 8,414 17,920 (2,433) 15,487 (2,323) 13,164 (301) 3,670 8,794 12,494 21,288 (3,229) 18,059 (2,709) 15,350 (335) 857 16,533 15,872 35,626 39,751 75,377 33,164 46,721 79,885 (10,057) (12,282) 65,320 (9,798) 55,522 (1,226) 10,363 64,659 67,603 (17,349) 50,254 (2,355) 6,189 54,088 Prior to 2016 the Company had reached an understanding with TANESCO that it would continue to supply gas if TANESCO remained reasonably current with payments for gas deliveries. As a result of TANESCO’s inability to fully pay all amounts invoiced by the Company for the past few years, management of the Company has modified its approach to revenue recognition as it relates to TANESCO only. Commencing on October 1, 2016 the Company will record 80% of the amounts invoiced to TANESCO for revenue recognition purposes. The 80% amount was determined by comparison of TANESCO’s historical payment history to the amounts invoiced by the Company over the past three years. Management believes this approach provides the best estimate of TANESCO’s ability to pay and remain reasonably current and as well reflects the economic reality of the situation. This results in a reduction in revenue recognized from the effective date. For cash received in excess of the revenue recorded from TANESCO in any given period, the additional amounts received will be recorded as deferred revenue. In periods when cash received is less than revenue recorded, the deferred revenue will be reduced accordingly. If the deferred revenue amount is reduced to nil, the difference will be recorded as accounts receivable. The percentage used to recognize TANESCO revenue will be reviewed on at least a semi-annual basis, more frequently if circumstances require and if there is a significant difference between the amount of revenue recorded and amounts received, the percentage used to record revenue as well as any existing receivable or deferred revenue balance will be revised accordingly. As a result of recording revenue based on the expected collectability from the effective date, there is the following impact on the 2016 results: 1) US$1.6 million decrease in revenue, 2) US$1.3 million decrease in long-term receivables and allowance for doubtful accounts, 3) US$0.6 million decrease in current accounts receivable, 4) US$0.3 million decrease in net income and current liabilities. Company operating revenue decreased by 14% in the fourth quarter of 2016 compared with Q4 2015. The decrease is primarily due to the adjustment in revenue associated with the modified approach used for TANESCO revenue recognition. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis17 Company operating revenue for the year increased 10% to US$55.5 million compared to US$50.3 million in the prior year. The 10% increase is due to the impact of the capital expenditures associated with the Offshore Development Program which commenced in the third quarter of 2015. This entitled the Company to 75% of the field net revenue as Cost Gas for the year compared to 57% in 2015, the increase in Cost Gas resulting in a corresponding reduction in Profit Gas and a corresponding decrease in the Profit Gas attributable to TPDC by 42% over the year. The fall in the level of Profit Gas for the year resulted in a 47% fall in the Additional Profits Tax charge for the year to US$1.2 million from US$2.4 million. The increase in operating revenue and decrease in Additional Profits Tax contributing to the increase in the current income tax adjustment from US$6.2 million to US$10.4 million. PROCESSING AND TRANSPORTATION TARIFF The processing and transportation tariff charge for the quarter and for the year were US$2.4 million (Q4 2015: US$3.2 million) and US$10.1 million (2015: US$12.3 million), respectively. The reduction in the tariff for the year is a consequence of the cessation of the additional compensation and lower sales volumes during the periods. PRODUCTION AND DISTRIBUTION EXPENSES Well maintenance costs are allocated between Protected Gas and Additional Gas in proportion to their respective sales during the period. The total cost of maintenance for the quarter was US$0.2 million (Q4 2015: US$0.1 million) and for the year, US$0.6 million (2015: US$0.4 million). Amounts allocated for Additional Gas for the quarter and for the year were US$0.1 million (Q4 2015: US$0.1 million) and US$0.4 million (2015: US$0.2 million), respectively. The increase in the year is the consequence of increased activity following the completion of the Offshore Development Program at the end of the first quarter. Other field and operating costs include an apportionment of the annual PSA licence costs, regulatory fees, insurance, some costs associated with the evaluation of the reserves, and the cost of personnel which are not recoverable from Songas. Distribution costs represent the direct cost of maintaining the ring main distribution pipeline and pressure reduction stations (security, insurance and personnel). Ring main distribution costs were US$0.7 million (Q4 2015: US$0.5 million) for the quarter and US$2.7 million (2015: US$1.9 million) for the year. The production and distribution costs are detailed in the table below: US$’000 Share of well maintenance Other field and operating costs Ring main distribution costs Production and distribution expenses THREE MONTHS ENDED DECEMBER 31 2016 2015 112 265 377 651 1,028 47 251 298 512 810 YEAR ENDED DECEMBER 31 2016 351 979 1,330 2,703 4,033 2015 233 1,594 1,827 1,924 3,751 management's discussion & analysis 18 OPERATING NETBACKS The netback per mcf before general and administrative costs, overhead, tax and APT is detailed in the table below: US$/mcf Gas price – Industrial Gas price – Power (1) Weighted average price for gas Tariff TPDC share of revenue Net selling price Well maintenance and other operating costs Ring main distribution costs Operating netbacks THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31 2016 7.52 3.56 4.75 (0.59) (0.56) 3.60 (0.09) (0.16) 3.35 2015 7.62 3.56 4.51 (0.71) (0.59) 3.21 (0.07) (0.11) 3.03 2016 7.70 3.56 4.73 (0.62) (0.60) 3.51 (0.08) (0.17) 3.26 2015 7.58 3.54 4.49 (0.71) (1.00) 2.78 (0.13) (0.08) 2.57 (1) The weighted average sales price is stated before the decrease in TANESCO revenue due to the modified approach used for revenue recognition purposes and represents the weighted average price of the volumes invoiced and delivered. The operating netback increased by 11% from US$3.03/mcf in Q4 2015 to US$3.35/mcf in Q4 2016 as a result of the 5% increase in the weighted average price of gas from US$4.51/mcf in Q4 2015 to US$4.75/mcf in Q4 2016 and the decrease in compensation to Songas for volumes over 70 MMcfd. The operating netback for the year increased 27% to US$3.26/mcf from US$2.57/mcf in 2015. The increase in the weighted average price for the year of 5% was a consequence of the increase in the volume of industrial sales during the year and the 40% decrease in TPDC’s share of revenue per mcf, as a consequence of lower total profit gas resulting from the completion of the Offshore Development Program during the first quarter of the year. GENERAL AND ADMINISTRATIVE EXPENSES General and administrative expenses are detailed in the table below: US$’000 Employee and related costs Stock based compensation (recovery) Office costs Marketing and business development costs Reporting, regulatory and corporate General and administrative expenses THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31 2016 2,514 556 1,317 42 459 4,888 2015 2,796 (87) 916 6 1,067 4,698 2016 8,050 2,591 3,618 322 1,756 2015 7,001 (244) 3,366 214 3,271 16,337 13,608 General and administrative expenses include the costs of running the natural gas distribution business in Tanzania which is recoverable as Cost Gas and is relatively fixed in nature. Excluding stock based compensation and other expenses, general and administrative expenses averaged US$1.5 million (Q4 2015: US$1.6 million) per month during the quarter and US$1.2 million (2015: US$1.1 million) per month over the year. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis19 STOCK BASED COMPENSATION The breakdown of the costs incurred in relation to stock based compensation is detailed in the table below: US$’000 Stock appreciation rights (“SARs”) Restricted stock units (“RSUs”) Stock-based compensation (recovery) THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31 2016 2015 2016 2015 439 117 556 463 (550) (87) 1,467 1,124 2,591 (266) 22 (244) As at December 31, 2016 a total of 2,430,000 SARs were outstanding compared to 3,100,000 as at December 31, 2015. A total of 580,000 SARs with exercise prices ranging from CDN$2.30 to CDN$3.10 were exercised during the year resulting in a total cash payout of US$0.5 million, with a further 90,000 SARs with an exercise price of CDN$2.30 being forfeited. No new SARs were granted in the year. As at December 31, 2016 a total of 239,361 RSUs were outstanding compared to zero at December 31, 2015. During the year a total of 386,420 RSUs were issued. The RSUs vested in full on the date of grant have an exercise price of CDN$0.001 and have a five year term. A total of 147,059 RSUs were exercised during the year resulting in a total cash payout of US$0.4 million. As SARs and RSUs are settled in cash, they are re-valued at each reporting date using the Black-Scholes option pricing model with the resulting liability being recognized in trade and other payables. In the valuation of stock appreciation rights and restricted stock units at the reporting date, the following assumptions have been made: a risk free rate of interest of 0.5%; stock volatility of 33.5% to 50.7%; 0% dividend yield; 5% forfeiture; and a closing price of CDN$3.86 per Class B share. As at December 31, 2016 a total accrued liability of US$3.2 million (2015: US$1.6 million) has been recognized in relation to SARS and RSUs. The Company recognized an expense of US$0.6 million (Q4 2015: credit US$0.1 million) for the quarter and for the year ended December 31, 2016 an expense of US$2.6 million (2015: credit US$0.2 million). The increased expense in 2016 is due to the combination of a 40% increase in the share price to CDN$3.86 (2015: CDN$2.75) together with issuing 386,420 fully vested Restrictive Stock Units (“RSUs”) during the first half of the year. management's discussion & analysis20 NET FINANCE EXPENSE The movement in net finance expense is detailed in the table below: US$’000 Finance income Interest expense Net foreign exchange loss Financing fee Provision for doubtful accounts Indirect tax Finance expense Net finance expense THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31 2016 193 (1,567) (18) – 2015 20 (117) (370) 250 2016 383 (5,668) (24) – 2015 43 (117) (2,677) (16) (414) (10,731) (12,853) (11,178) (1,388) (3,387) (3,194) – (10,968) (10,948) (1,392) (19,937) (19,554) – (13,988) (13,945) Total amount of interest paid in 2016 was US$5.7 million (2015: US$0.1). The foreign exchange loss reflects the impact of movements in the value of the Tanzanian shilling against the US dollar during the period on outstanding customer/supplier balances and bank accounts in Tanzanian shillings. During 2016 the Company billed TANESCO US$4.2 million (2015: US$2.4 million) of interest for late payments. The interest income is not recorded in the financial statements because it does not meet the revenue recognition criteria with respect to assurance of collectability. In the fourth quarter of 2016 the Company billed TANESCO two additional contractual invoices totaling US$7.8 million for take or pay gas and excess gas taken over the declared maximum daily quantity. These have not been included in the financial statements as they do not meet the revenue recognition criteria with respect to assurance of collectability. The Company is pursuing collection and amounts will be recognized in earnings when collected. The provision for doubtful accounts includes US$12.4 million (2015: US$9.9 million) for overdue TANESCO receivables, US$0.4 million (2015: US$0.1 million) relates to Industrial customers and US$ nil (2015: US$1.3 million) relates to Songas receivables. The US$1.4 million is in relation to indirect tax associated with trade receivables not recognized in the financial statements due to IFRS revenue recognition criteria with respect to assurance of collectability. TANESCO At December 31, 2016 TANESCO owed the Company US$80.1 million, excluding interest, (of which arrears were US$74.4 million) compared to US$69.8 million (including arrears of US$61.9 million) as at December 31, 2015. Current TANESCO receivables as at December 31, 2016 amounted to US$5.7 million (2015 US$7.8 million). Since the year-end, TANESCO has paid the Company US$12.9 million, and as at the date of this report the total TANESCO receivable is US$74.8 million (of which US$74.4 million has been provided for). The amounts owed do not include interest billed to TANESCO or debtors not meeting the revenue recognition criteria with respect to assurance of collectability. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis21 TAXATION Income Tax Under the terms of the PSA with TPDC and the Government of Tanzania, the Company is liable for income tax in Tanzania at the corporate tax rate of 30%. However, the PSA provides a mechanism by which income tax payable is recovered from TPDC by reducing TPDC’s share of Profit Gas and increasing the allocation to the Company. This is reflected in the accounts by increasing the Company’s share of revenue by an amount equivalent to income taxes payable. As at December 31, 2016 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 recognized a deferred tax liability of US$12.9 million (2015: US$9.3 million). During the year there was a deferred tax charge of US$3.7 million compared to US$1.7 million in 2015. The deferred tax has no impact on cash flow until it becomes a current income tax, at which point the tax is paid 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”), an Additional Profits Tax is payable. The timing and the effective rate of APT depends on the realized value of Profit Gas which in turns depends of the level of expenditure. The Company provides for APT by forecasting annually the total APT payable as a proportion of the forecast Profit Gas over the term of the PSA. The forecast takes into account the timing of future development capital spending. The Company provides for APT by forecasting the total APT payable as a proportion of the forecast Profit Gas over the term of the PSA. The effective APT rate of 19.4% (Q4 2015: 18.6%) has been applied to Profit Gas of US$1.5 million (Q4 2015: US$1.8 million) for the quarter, and an average effective rate of 18.8% (2015: 20.2%) has been applied to Profit Gas of US$6.5 million (2015: US$11.6 million) for the year ended December 31, 2016. Accordingly, US$0.3 million (Q4 2015: US$0.3 million) and US$1.2 million (2015: US$2.4 million) have been netted off against revenue for the quarter, and for the year ended December 31, 2016, respectively. US$’000 Additional Profits Tax THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31 2016 301 2015 335 2016 1,226 2015 2,355 DEPLETION AND DEPRECIATION 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 December 31, 2016 the proven reserves estimated to have been produced over the term of the PSA licence were 341 Bcf (2015: 368 Bcf). A depletion expense of US$2.4 million for the quarter (Q4 2015: US$2.6 million) and US$9.2 million for the year (2015: US$11.9 million) has been recorded in the account at an average depletion rate to US$0.56/mcf (2015: US$0.69/mcf). The decrease in the depletion rate is the consequence of the successful completion of the Offshore Program at a lower level of expenditure than planned which in turn reduced expected future development costs from what had been originally forecast at the end of 2015. 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 management's discussion & analysis22 CARRYING AMOUNT OF ASSETS Capitalized costs are periodically assessed to determine whether it is likely that such costs will be recovered in the future. To the extent that these capitalized costs are unlikely to be recovered in the future, they are impaired and recorded in earnings. CASH FLOW FROM OPERATIONS Cash flow from operations was US$6.2 million for Q4 2016 (Q4 2015: US$8.4 million) and US$31.9 million for the year (2015: US$26.5 million) and is detailed in the table below: THREE MONTHS ENDED DECEMBER 31 YEAR ENDED DECEMBER 31 2016 6,211 1,567 567 8,345 7 (1,566) 6,786 30 6,816 2015 8,391 117 (3,058) 5,450 (19,539) 18,482 4,393 (136) 2016 31,855 5,668 2015 26,454 117 (17,555) (19,553) 19,968 7,018 (27,609) (29,950) 34,132 26,491 607 18,324 (4,608) 746 4,257 27,098 (3,862) US$’000 Cash flow from operations (1) Interest paid Change in non-cash working capital (2) Net cash flows from operating activities Net cash used in investing activities Net cash from (used in) financing activities Increase in cash Effect of change in foreign exchange on cash Net increase in cash (1) See non-GAAP measures (2) See Consolidated Statement of Cash Flows CAPITAL EXPENDITURES During 2016 the Company incurred US$16.9 million (2015: US$38.4 million) in capital expenditures relating primarily to the drilling of well SS-12, improvement of Songo Songo infrastructure and purchase of other equipment. The 2016 capital expenditures are net of recharges of US$1.0 million to Songas for its share of costs on wells SS-5 and SS-9 (2015: US$11.2 million). US$’000 Geological and geophysical and well drilling Pipelines and infrastructure Other equipment THREE MONTHS ENDED DECEMBER 31 2016 2015 23,099 1,382 59 32 99 – 131 2016 16,255 565 104 YEAR ENDED DECEMBER 31 2015 35,796 2,359 256 38,411 24,540 16,924 ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 23 WORKING CAPITAL Working capital as at December 31, 2016 was US$72.0 million (December 31 2015: US$32.5 million) and is detailed in the table below: US$’000 Cash Trade and other receivables TANESCO Songas Industrial customers Songas gas plant operations Songas well workover program Other receivables Provision for doubtful accounts Tax recoverable Prepayments Trade and other payables TPDC share of Profit Gas (1) Songas Other trade payables Deferred income Accrued liabilities Tax payable Working capital (2) 2016 80,895 27,638 AS AT DECEMBER 31 2015 53,797 25,391 5,749 2,218 7,463 6,601 14,458 1,516 (10,367) 28,319 1,893 3,245 – 6,250 5,402 651 114,586 39,707 7,831 2,178 6,894 5,631 11,209 1,604 (9,956) 28,208 1,071 11,234 667 8,351 4,519 1,118 84,825 49,531 2,890 71,989 2,773 32,521 Notes (1) Payable to TPDC for their share of profit gas reflects the total accrued liability based on gas delivered to TANESCO which has not been paid for. Settlement of this liability is dependent on receipt of payment from TANESCO. (2) Working capital as at December 31, 2016 includes a TANESCO receivable (excluding interest) of US$5.7 million (2015: US$7.8 million). Management has recorded a provision for doubtful accounts against the long-term receivables totaling US$74.4 million (2015: US$61.9 million). The total of long and short-term TANESCO receivables as at December 31, 2016, including interest and unrecorded revenue as a result of issued invoices not meeting revenue recognition criteria, was US$100.8 million. The financial statements do not recognize the interest receivable from TANESCO as it does not meet revenue recognition criteria. The Company is actively pursuing the collection of all the receivables including the interest that has been charged to TANESCO. Working capital as at December 31, 2016 increased by 121% over December 31, 2015 and by 6% during the quarter. The increase is primarily a result of having drawn down the balance of the loan from the IFC and the paying down of creditors associated with the 2015/2016 Offshore Development Program. Other significant points are: • There are no restrictions on the movement of cash from Mauritius or Tanzania, and currently the majority of cash is outside of Tanzania. As at the date of this report, approximately 90% of the Company’s cash is held outside of Tanzania. • Of the US$7.4 million relating to other trade debtors US$7.4 million had been received as at the date of this report. The balance of US$28.3 million payable to TPDC represents the remaining balance of its accrued share of revenue as at December 31, 2016. As a consequence of the contractual arrangements within the PSA, the settlement of the majority of the liability is dependent upon the receipt of the TANESCO arrears. management's discussion & analysis 24 LONG TERM LOAN On October 29, 2015 the Company entered into an agreement with the IFC, a member of the World Bank Group, to provide financing of up to US$60 million for the Company’s operating subsidiary, PAET. The Company has drawn the US$60 million Loan facility in full, with an initial drawdown of US$20 million on December 14, 2015 followed by an additional draw down of US$40 million on February 9, 2016. The term of the Loan is 10-years, with no required repayment of principal for the first seven years, followed by a three-year amortization period. The Loan is to be paid out through six semi-annual payments of US$5 million and one final payment of US$30 million. The Company may voluntarily prepay all or part of the Loan but must simultaneously pay any accrued base interest costs related to the principal amount being prepaid. If any portion of the Loan is prepaid prior to the fourth anniversary of the first drawdown, the Company would be required to pay the accrued base interest as if the prepaid portion of the Loan had remained outstanding for the full four years. The Loan is an unsecured subordinated obligation of PAET and is guaranteed by the Company to a maximum of US$30 million. The guarantee may only be called upon by IFC at maturity in 2025. Subject to receipt of the IFC approval and required regulatory approvals, the Company may issue shares in fulfillment of all or part of the guarantee obligation in 2025. Base interest on the Loan is payable quarterly at 10% per annum on a ‘pay-if-you-can-basis’ using a formula to calculate the net cash available for such payments as at any given interest payment date. The Company must provide notice to the IFC of the amount of any interest which is not to be paid on any interest payment date the unpaid interest is added to the principal outstanding and may be paid out before or at the time of principal repayment. In addition, an annual variable participatory interest equating to 7% of the cash flow of PAET net of capital expenditures is payable in respect of any given year, commencing with 2016. The participatory interest survives the repayment and/or maturity of the Loan until October 15, 2026. No provision was made for the year ended December 31, 2016 as the 2016 net cash flow from operating activities less the 2016 net cash used in investing activities is a negative amount. Dividends and distributions from PAET to the Company are restricted at any time that any amounts of unpaid interest, principal or participating interest are outstanding. SHAREHOLDERS’ EQUITY AND OUTSTANDING SHARE DATA There were 34,856,432 shares outstanding as at December 31, 2016 as detailed in the table below: Number of shares (‘000) Shares outstanding Class A shares Class B shares Class A and Class B shares outstanding Weighted average Class A and Class B shares Convertible securities Options Weighted average diluted Class A and Class B shares AS AT DECEMBER 31 2016 2015 1,751 33,106 34,857 1,751 33,106 34,857 34,857 34,887 – – 34,857 34,887 As at the date of this report, there were a total of 1,750,517 Class A common voting shares (“Class A shares”) and 33,105,915 Class B subordinated voting shares (“Class B shares”) outstanding. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis25 RELATED PARTY TRANSACTIONS One of the non-executive Directors is counsel with a law firm that provides legal advice to the Company and its subsidiaries. For the year ended December 31, 2016 US$0.2 million (2015: US$0.6 million) was incurred from this firm for services provided. The former Chief Financial Officer provided services to the Company through a consulting agreement with a personal services company until his resignation on November 2, 2015. For the period from January 1, 2015 to November 2, 2015, US$0.4 million was incurred from this firm for services provided. As at December 31, 2016 the Company has a total of US$0.1 million (2015: US$0.4 million) recorded in trade and other payables in relation to the related parties. CONTRACTUAL OBLIGATIONS AND COMMITTED CAPITAL INVESTMENT 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, 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 (161.2 Bcf as at December 31, 2016). 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. Re-Rating Agreement In 2011 the Company signed a re-rating agreement with TANESCO, TPDC and Songas (the “Re-Rating Agreement”) which evidenced an increase to the gas processing capacity of the Songas facilities 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 paid additional compensation of US$0.30/mcf for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd by issuing credit notes to TANESCO. This was in addition to the tariff of US$0.59/mcf payable to Songas as set by the energy regulator, EWURA. In May 2016 the Company notified TANESCO and Songas that the additional compensation for sales over 70 MMcfd would no longer be paid effective June 2016. The additional compensation was always intended to be temporary in nature until the expansion of the Songas infrastructure, at which time Songas would apply to EWURA to obtain approval of a new tariff for the processing of volumes over 70 MMcfd. The PGSA provides for passing on to TANESCO any tariff to be charged to the Company and in the event that a new tariff is approved. The parties are seeking to resolve the status of the re-rating agreement. The processing capacity at the Songas facilities remain unaltered and are fully utilized by the company. Without a new agreement, there are no assurances that Songas will continue to allow the gas plant to operate above 70 MMcfd. Portfolio Gas Supply Agreement On June 17, 2011, a long term PGSA was signed (to June 2023) between TANESCO (as the buyer), the Company and TPDC (collectively as the seller). Under the PGSA, the seller is obligated, subject to infrastructure capacity, to sell a maximum of approximately 36 MMcfd for use in any of TANESCO’s current power plants, except those operated by Songas at Ubungo. Under the agreement, the basic wellhead price of approximately US$2.93/mcf increased to US$2.98/mcf on July 1, 2015. 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 November 1, 2015 and expires on October 31, 2019 at an annual rent of US$0.4 million. The agreement in Winchester expires on September 25, 2022 and is at an annual rental of US$0.1 million per annum. The costs of these leases are recognized in the general and administrative expenses. management's discussion & analysis26 Capital Commitments Italy The Company has an agreement to farm in on the 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 fifteen per cent (15%) of the back costs in relation to the well up to a maximum of US$0.5 million. Changes in Italian environmental legislation in late 2015 has resulted in the development of this permit being postponed indefinitely. As at the date of this report, the Company has no further capital commitments in Italy. Tanzania There are no contractual commitments for exploration or development drilling or other field development either in the PSA or otherwise agreed which would give rise to significant capital expenditure at Songo Songo. Any significant additional capital expenditure in Tanzania is discretionary. Given the completion of the Offshore component of Phase I of the Development Programme in February 2016, which has restored field deliverability and provides sufficient natural gas production to fill the Songas plant and pipeline to capacity for the greater portion of the remaining life of the production licence, the Company does not expect to commit to further significant capital expenditures until: (i) agreeing commercial terms with TPDC for the supply of gas to the NNGIP regarding the sale of incremental gas volumes from Songo Songo; and/or (ii) TANESCO arrears have been substantially reduced, guaranteed or other arrangements for payment made which are satisfactory to the Company; and/or (iii) the establishment of payment guarantees with the World Bank or other multi-lateral lending agencies to secure future receipts under any new sales contracts with Government entities. When conditions are deemed appropriate and there is justification to further improve the reliability/capacity of field deliverability, the Company would contemplate undertaking the remaining part or all of the Phase I Development Programme. The additional costs are estimated to be approximately US$30 million. There is no assurance that financing will be available and on acceptable commercial terms to complete Phase I. At the date of this report, the Company has no significant outstanding contractual commitments, and has no outstanding orders for long lead items related to any capital programmes. CONTINGENCIES Petroleum Act, 2016 During the third quarter of 2015, the Petroleum Act, 2015, (the “Act”) was passed into law. The Act repeals earlier legislation, provides a regulatory framework over upstream, mid-stream and downstream gas activity, and consolidates and puts in place a comprehensive legal framework for regulating the oil and gas industry in the country. The Act also provides for the creation of an upstream regulator, the Petroleum Upstream Regulatory Authority ("PURA"). The mid and downstream oil and gas activities are proposed to be regulated by the current authority, the Energy and Water Utilities Regulatory Authority (EWURA). The Act also confers upon on TPDC, the status of the National Oil Company, mandated with the task of managing the country’s commercial interest in petroleum operations as well as mid and downstream natural gas activities. The Act vests TPDC with exclusive rights in the entire petroleum upstream value chain and the natural gas mid and downstream value chain. However, the exclusive rights of TPDC do not extend to mid and downstream petroleum supply operations. The Act does provide grandfathering provisions upholding the rights of the Company under their PSA as it was signed prior to passing of the Act. However, it is still unclear how the provisions of the Act will be interpreted and implemented regarding upstream and downstream activities and the Company is uncertain regarding the potential impact on its business in Tanzania. On October 7, 2016, the Government of Tanzania issued the Petroleum (Natural Gas Pricing) Regulation made under Sections 165 and 258 (I) of the Act. Under the Act, Article 260 (3) preserves the Company’s pre-existing right with TPDC to market and sell Additional Gas together or independently on terms and conditions (including prices) negotiated with third party Natural Gas customers. The impact of the Natural Gas Pricing Regulation, if any, cannot be determined at this time. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis27 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 working 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. Cost recovery 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. In 2014 TPDC and the Company agreed to remove approximately US$1.0 million from the Cost Pool. In 2015 and 2016 there were no further developments. Under the dispute mechanism outlined in the PSA, TPDC are to appoint an independent specialist to assist the parties in reaching agreement on costs that are still subject to dispute. At the time of writing this report no such specialist has been appointed. If the matter is not resolved to the Company’s satisfaction, the Company intends to proceed to arbitration via the International Centre for Settlement of Investment Disputes (“ICSID”) pursuant to the terms of the PSA. Tax dispute Disputed amount US$, million Period Reason for dispute Principal Interest Total Taxation Area PAYE 2008-10 WHT 2005-10 Income Tax 2008-15 Pay-As-You-Earn (“PAYE”) on grossed-up amounts in staff salaries which are contractually stated as net. WHT on services performed outside of Tanzania by non-resident persons. Deductibility of capital expenditures and expenses (2009 and 2012), additional income tax (2008, 2010, 2011 and 2012), tax on repatriated income (2012), foreign exchange rate application (2013 and 2015) and underestimation of tax due (2014). VAT 2008-10 Output VAT on imported services and SSI Operatorship services. 0.3 – 0.3(1) 1.1 16.8 2.7 20.9 0.7 10.1 2.9 13.7 1.8(2) 26.9(3) 5.6(4) 34.6 (1) (2) In 2015 PAET appealed the Tax Revenue Appeals Board (“TRAB”) ruling that PAET is liable to pay PAYE on grossed-up amounts in staff salaries. TRAB waived interest assessed thereon. PAET is awaiting ruling of the Tax Revenue Appeals Tribunal (“TRAT”); (a) 2005-2009 (US$1.7 million): In 2016 the TRA filed an application for review of the Court of Appeal decision in favour of PAET and later filed another application for leave to amend its earlier application. At the Court of Appeal hearing subsequent to year-end, TRA withdrew their second application for review. The Court has set April 27, 2017 for hearing of the first application; (b) 2010 (US$0.1 million): TRAB is awaiting a ruling from the review by the Court of Appeal on the 2005-2009 case, which would influence TRAB decision on this matter accordingly; (3) (a) 2009 (US$1.8 million): In 2015 TRAB ruled against PAET with respect to the deductibility of capital expenditures and other expenses. PAET appealed to TRAT and is awaiting a hearing date to be scheduled ; (b) 2008 and 2011 (US$2.1 million): In 2015 PAET filed objections against TRA assessments with respect to the deductibility of capital expenditures and other expenses as well as underestimation of interest and is awaiting a response. Subsequent to year-end, TRA rejected PAET’s objections for 2011 and undertook to issue a final assessment for the year. PAET intends to appeal the assessment. The 2008 assessment was issued late and is time-barred; (c) 2010 (US$2.6 million): PAET filed an appeal with TRAB against TRA assessment with respect to the deductibility of capital expenditures and other expenses as well as underestimation of interest and penalty amounts. PAET is awaiting a hearing date to be scheduled; (d) 2013 (US$ 0.2 million): During the year PAET filed objections to TRA assessment with respect to foreign exchange rate application and is awaiting a response; management's discussion & analysis 28 (e) 2012 (US$16.3 million): During the year TRA issued two assessments with respect to understated revenue, deductibility of capital expenditures and expenses, and tax on repatriated income. PAET filed an appeal with TRAB against the TRA decision to deny PAET a waiver required for its objection to be admitted and is awaiting a hearing date to be scheduled; (f) 2014 (US$3.5 million): During the year TRA issued an-assessment with respect to underestimation of tax due based on the provisional quarterly payments made by PAET, delayed filings of returns and late payments. PAET filed objections to the assessments and is awaiting a response; (g) 2015 (US$0.4 million): During the year TRA issued a self-assessment. PAET filed an objection to the assessment with respect to foreign exchange rate application and is awaiting a response; (4) During the year TRA responded to PAET’s objection filed in 2014 and issued an assessment in respect of output VAT on imported services and SSI Operatorship services. PAET filed an appeal with TRAB against TRA assessment and is awaiting a hearing date to be scheduled. (5) On March 29, 2017, management received a tax audit findings report from TRA for the years 2012-14. The report requests the Company to elaborate on the corporation tax, repatriated income, VAT and withholding tax. Management is preparing its response and expects to submit it to TRA before the deadline of April 19, 2017. Management, with the advice from its legal advisors, has reviewed the Company’s position on the above objections and appeals and has concluded that no provision is required with regard to the above matters. NEW ACCOUNTING POLICIES At the date of these financial statements the standards and interpretations listed below were issued but not yet effective. The adoption of these standards may result in future changes to existing accounting policies and disclosures. The Company is currently evaluating the impact that these standards will have on results of operations and financial position. In May 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers," which replaces IAS 18 "Revenue," IAS 11 "Construction Contracts," and related interpretations. The standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted. The Company has commenced the process of identifying and reviewing sales contracts with customers to determine the extent of the impact, if any, that this standard will have on the consolidated financial statements. In July 2014, the IASB finalized the remaining elements of IFRS 9 – Financial Instruments, which includes new requirements for the classification and measurement of financial assets, amends the impairment model and outlines a new general hedge accounting standard. The mandatory effective date of IFRS 9 is for annual periods on or after January 1, 2018 and must be applied retrospectively with some exemptions. Early adoption is permitted. The Company is evaluating the impact of this standard on the consolidated financial statements and does not anticipate material changes to the valuation of its financial assets. In January 2016, the IASB issued IFRS 16 Leases, which replaces IAS 17 Leases. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted if the entity is also applying IFRS 15 Revenue from Contracts with Customers. The Company is currently identifying contracts that will be identified as leases and evaluating the impact of the standard on the consolidated financial statements. There are no other standards and interpretations in issue but not yet adopted that are expected to have a material effect on the reported earnings or net assets of the Company. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 29 SUMMARY QUARTERLY RESULTS OUTSTANDING The following is a summary of the results for the Company for the last eight quarters: Figures in US$’000 except where otherwise stated Financial Revenue Net income (loss) Earnings (loss) per share – basic and diluted (US$) 2016 2015 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 16,533 17,744 14,572 15,810 15,872 15,943 12,553 9,720 1,048 5,302 1,452 (5,638) (6,468) 6,112 3,566 (1,677) 0.03 0.15 0.04 (0.16) (0.19) 0.18 0.10 (0.05) Cash flow from operations (1) 6,211 10,024 6,772 8,848 8,391 9,462 4,889 3,712 Cash flow from operations per share – basic and diluted (US$) Net cash flow from (used in) operating activities Net cash flows (utilized) per share – basic and diluted (US$) Operating netback (US$/mcf) Working capital Long-term loan Shareholders’ equity Capital expenditures Geological and geophysical and well drilling Pipeline and infrastructure Other equipment Operating Additional Gas sold – industrial (MMcf) – industrial (MMcfd) Additional Gas sold – power (MMcf) – power (MMcfd) Average price per mcf – industrial (US$) Average price per mcf – power (US$) (1) See non-GAAP measures 0.18 0.29 0.19 0.25 0.24 0.27 0.14 0.11 8,345 6,540 6,237 (1,154) 5,450 (2,963) (2,844) 7,375 0.24 3.35 0.19 3.31 0.18 3.32 (0.03) 3.08 0.16 3.03 (0.09) (0.08) 2.65 2.68 0.21 1.86 71,989 67,635 58,395 56,340 32,521 39,660 38,067 34,870 58,399 58,398 58,368 58,350 18,599 – – – 80,023 79,153 73,887 72,482 78,154 84,476 78,480 74,944 32 99 – 26 (71) – 2,558 13,639 23,099 7,578 4,135 181 102 356 1,382 2 59 547 150 275 47 984 155 – 1,226 1,238 1,151 13.3 13.5 12.6 972 10.7 1,089 11.8 2,895 3,047 2,521 3,241 3,483 31.5 33.1 27.7 35.6 37.9 1,137 11.9 3,127 34.5 1,015 11.1 925 10.3 3,041 3,494 33.4 38.8 7.52 7.60 7.64 8.15 7.62 7.67 7.45 7.54 3.57 3.57 3.55 3.55 3.56 3.62 3.47 3.49 management's discussion & analysis 30 PRIOR EIGHT QUARTERS The Company’s revenue for the last six quarters has been reasonably consistent. The increase in revenue from Q2 2015 has been the consequence of the Offshore Development Program which commenced in Q3 2015 and was completed at the end of Q1 2016. The capital costs associated with the program entitle the Company to a higher proportion of field net revenue. The fall in revenue from Q3 2016 to Q4 2016 is the consequence of the Company only recognizing 80% of the TANESCO invoiced amounts for revenue recognition purposes in Q4 2016. Changes in net income over the last two years were negatively impacted by the impairment provisions relating to TANESCO. In Q4 2015, Q1 2016, Q2 2016 and Q3 2016 doubtful debt provisions of US$9.8 million, US$8.0 million, US$3.5 million and US$0.9 million respectively were provided against increased TANESCO arrears. Other significant factors affecting the results were: • • • • • • In Q1 2016 the Company took a charge of US$2.8 million for stock based compensation as a consequence of the share price closing at CDN$4.14 compared to CDN$2.75 at the end of Q4 2015 together with the issuance of new Restrictive Stock Units. In Q2 2016 the Company had a decrease in the stock based compensation charge of US$0.7 million as the share price closed at CN$3.40 at the end of the quarter. In Q3 2016 the Company recorded a credit of US$0.1 million for stock based compensation compared to a credit of US$1.1 million in Q3 2015. In Q4 2016 the Company recorded a stock based compensation charge of US$0.6 million, as a consequence of an increase in the closing share price to CDN$3.82 from CDN$3.41 at the end of Q3 2016, In Q4 2016 the Company recognized 80% of the TANESCO invoiced amount for revenue recognition purposes in accordance with the new estimation procedure which resulted in a net income reduction of US$1.3 million (see "Operating Revenue"). The Company recorded an interest expense of US$1.6 million in the last three quarters of 2016 and US$1.0 million in Q1 2016. Differences in cash flow from operations for the last six quarters were primarily a result of changes in revenue during the periods. The decrease in cash flow from operations in Q4 2016 is a consequence of expensing indirect taxes associated with sales invoices that have not been recorded in the financial statements because they do not meet the revenue recognition criteria with respect to assurance of collectability. The increase in cash flow from operations to US$10.0 million in Q3 2016 from US$6.7 million in Q2 2016 is primarily the result of the US$3.3 million increase in revenue over the quarter. In Q2 and Q1 of 2015, cash flow from operations decreased reflecting the drop in revenue during these periods due to declining well production and lower Cost Pool levels reducing the Company’s share of revenues. Changes in net cash flow from operating activities between quarters were primarily a result of the timing of receipt of payments from TANESCO. The decrease in working capital from Q3 2015 to Q4 2015 was a consequence of the increase in creditors associated with the workover and drilling program together with the additional bad debt provision against TANESCO, both of which were offset by the initial draw down of US$18.6 million from the IFC (net of expenses). The second draw down from the IFC of US$40 million in Q1 2016 has offset the decrease in working capital associated with the completion of the workover and drilling program from Q4 2015 to Q1 2016. The progressive increase in working capital from Q1 2016 is mainly the result of US$20.0 million in net cash flow from operating activities being offset by US$3.0 million of capital expenditure over the same period. Capital expenditure for the last four quarters Q4 2016 to Q1 2016 has amounted to US$16.9 million compared to US$38.4 million from Q4 2015 to Q3 2014. The 2015 workover and drilling program commenced in Q3 2015 with some preliminary expenditure in Q2 2015 and was completed at the end of the second quarter 2016 with the demobilization of the rig. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis31 The level of Industrial sales volumes increased in the four quarters ending Q4 2016 to an average of 1,146 MMcf (2015: 1,042 MMcf). Industrial sales volume for the four quarters ending Q4 2016 increased by 10% to 4,587 MMcf (12.5 MMcfd) compared to 4,166 MMcf (11.4 MMcfd) in 2015. The increased volumes are primarily the result of fewer days of unscheduled maintenance work by cement, textile and edible oil companies and consumption by new customers connected during the first half of 2016. The level of Power sales volumes decreased by 11% in the in the four quarters ending Q4 2016 to an average of 2,926 MMcf (2015: 3,286 MMcf). Power sector sales volumes for the four quarters ending Q4 2016 decreased by 11% to 11,704 MMcf (32.0 MMcfd) compared to 13,145 MMcf (36.0 MMcfd) in 2015. The decline is mainly the consequence of the decision by TANESCO not to renew a contract with an emergency power plant, unscheduled maintenance at the Songo Ubungo Power generation facility and the increased competition from gas suppliers within Tanzania. SELECTED FINANCIAL INFORMATION Selected annual financial information derived from the audited consolidated financial statements for the years ended December 31, 2016, 2015 and 2014 is set out below: Figures in US$’000 except per share amount Revenue Net cash flows from operating activities Cash flow from operations (1) Net income (loss) Total assets Earnings (loss) in US$ per share: Basic and diluted (1) See Non-GAAP measures 2016 64,659 19,968 31,855 2,164 226,532 2015 54,088 7,018 26,454 1,533 189,683 2014 56,607 29,757 32,412 (38,301) 198,492 0.06 0.04 (1.10) Revenue increased by 20% to US$64.7 million in 2016 from US$54.1 million in 2015. The increase is primarily a consequence of the Company being entitled to 85% of the net revenue in 2016 compared to 74% in 2015 following the increased costs pools after the completion of the Offshore Development Program in 2016. The increase in revenue occurred even though sales volumes were 10% lower in 2016 than 2015 and the weighted average price decreased 5% from US$4.49/mcf to US$4.73/mcf. As a result, TPDC share of revenue decreased from US$17.3 million in 2015 to US$9.8 million in 2016. The increased share of revenue contributed to the 20% increase in the cash flow from operations to US$31.9 million (2015: US$26.5 million) and the 185% increase in net cash flow from operating activities to US$20 million (2015: US$7.0 million). management's discussion & analysis32 BUSINESS RISKS Financing The ability of the Company to meet its financing obligations or to arrange financing in the future will depend in part upon the prevailing capital market conditions as well as the business performance of the Company. There can be no assurance that the Company would be successful in its efforts to meet its current commitments or 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 evaluates the collectability of its receivables on the basis of payment history, frequency and predictability, as well as Management’s assessment of the customer’s willingness and ability to pay. The Company has been impacted by TANESCO’s inability to pay for current deliveries and pay down arrears. Prior to 2016 the Company had reached an understanding with TANESCO that it would continue to supply gas if TANESCO remained reasonably current with payments for gas deliveries. As a result of TANESCO’s inability to fully pay all amounts invoiced by the Company for the past few years, management of the Company has modified its approach to revenue recognition as it relates to TANESCO only. Commencing on October 1, 2016 the Company will record 80% of the amounts invoiced to TANESCO for revenue recognition purposes. The 80% amount was determined by comparison of TANESCO’s historical payment history to the amounts invoiced by the Company over the past three years. Management believes this approach provides the best estimate of TANESCO’s ability to pay and remain reasonably current and as well reflects the economic reality of the situation. This results in a reduction in revenue recognized from the effective date. The percentage used to recognize TANESCO revenue will be reviewed on at least a semi-annual basis, more frequently if circumstances require and if there is a significant difference between the amount of revenue recorded and amounts received, the percentage used to record revenue as well as any existing receivable or deferred revenue balance will be revised accordingly. At December 31, 2016 TANESCO owed the Company US80.1 million, excluding interest, (of which arrears were US$74.4 million) compared to US$69.8 million (including arrears of US$61.9 million) as at December 31, 2015. Current TANESCO receivables as at December 31, 2016 amounted to US$5.7 million (2015 US$7.8 million). Since the year-end, TANESCO has paid the Company US$12.9 million in 2017, and as at the date of this report the total TANESCO receivable is US$74.8 million (of which US$74.4 million has been provided for). The amounts owed do not include interest billed to TANESCO or debtors not meeting the revenue recognition criteria with respect to assurance of collectability. As at December 31, 2016 Songas owed the Company US$23.3 million (2015: US$19.0 million), whilst the Company owed Songas US$2.3 million (2015: US$2.6 million); there is no contractual right to offset these amounts. Amounts due to Songas primarily relate to pipeline tariff charges of US$ 1.9 million (2015: US$1.1 million), whereas the amounts due to the Company are mainly for capital expenditures of US$14.4 million (2015: US$11.2 million), sales of gas of US$2.2 million (2015: US$2.2 million) and for the operation of the gas plant of US$6.6 million (2015: US$5.6 million). The operation of the gas plant is conducted at cost and the charges are billed to Songas on a flow through basis. As at December 31, 2016 the net amount owed by Songas to the Company was US$21.0 million (2015: US$16.4 million). Although significant progress has been made in settling outstanding balances, a doubtful debt provision of US$9.8 million (2015: US$9.8 million) is necessary recognizing the pending settlement of the remaining overdue operatorship charges and the Songas share of the well workover costs. Any significant amounts not agreed will be pursued through the mechanisms provided in the agreements with Songas. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis33 The “Tax Recoverable” figure carried on the balance sheet arises from the revenue sharing mechanism within the PSA which entitles the Company to recover from TPDC, by way of a deduction from TPDC’s Profit Gas share, an amount “the adjustment factor” equal to the actual income taxes payable by the Company. Recovery, by offset against TPDC’s share of revenue is dependent on payment of income taxes relating to prior period adjustment factors as they are assessed. 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 formations or production facilities and other property, equipment and the environment, as well as interrupt operations. 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 na- tionalization, renegotiation or nullification of existing contracts and production sharing agreements, taxation policies, foreign exchange restrictions, changing political conditions, international monetary fluctuations, currency controls and foreign governmental regulations that favour or require the awarding of drilling and construction contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. In addition, if a dispute arises with foreign operations, the Company may be subject to the exclusive jurisdiction 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, production 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. This policy was confirmed with the passing of the Petroleum Act, 2015 in the third quarter of 2015. The Act does provide grandfathering provisions upholding the rights of the Company under their PSA as it was signed prior to passing of the Act. However, it is still unclear how the provisions of the Act will be interpreted and implemented regarding upstream and downstream activities. 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. management's discussion & analysis34 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. Primarily operations are regulated by 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 has 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. Corruption remains an issue in Tanzania, the country ranking 116 out of 176 on the 2016 Transparency International Corruption Index. At the end of 2014 there was a significant corruption scandal in Tanzania’s energy sector involving a number of senior government officials, including senior officials from MEM. Having assessed the Company’s exposure to corruption in Tanzania, it was concluded that the risk of the Company and/ or its subsidiaries violating applicable laws prohibiting corrupt activities are mitigated or unlikely given the Company’s controls relating to such risks and their effective operation. There can be no assurance, however that corruption may indirectly affect or otherwise impair the Company’s ability to operate in Tanzania and effectively pursue its business plan in that country. The TRA 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 development and the ultimate monetization of the Company’s reserves through additional gas sales. The Government of Tanzania has completed the US$1.2 billion NNGIP that comprises two gas processing plants, one being at Songo Songo, and a pipeline to transport gas from Southern Tanzania to Dar es Salaam. The Company is currently negotiating terms for the sale of incremental gas volumes however there is no assurance that the Company’s gas will be processed and transported to markets on economic terms. Access to Songas processing and transportation Although the Company operates the Songo Songo gas processing plant, Songas is the owner of plant and pipeline system which transports natural gas from Songo Songo to Dar es Salaam. The Company’s ability to deliver gas to its customers in Dar es Salaam is dependent upon it having access to the Songas infrastructure. Although there are agreements with Songas to allow the Company to process and transport gas, there is no assurance that these rights could not be challenged or curtailed by Songas. The inability to access Songas plant and processing facilities would materially impair the Company’s ability to realize revenue from natural gas sales. As a result of the Ubungo power plant re-rating that occurred in 2011 pursuant to the Re-Rating Agreement, the capacity of the Songas gas processing plant was increased to a maximum of 110 MMcfd (restricted to 102 MMcfd because of pipeline and pressure requirements). The Re-Rating Agreement expired in 2013 and no new agreement is currently in place. Without the Re-Rating Agreement Songas, the owner of the gas processing plant, may require the plant to be operated at 70 MMcfd (the capacity originally agreed to), which would result in a material reduction in the Company’s sales volumes of Additional Gas. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis35 The Petroleum Act, 2015 In the third quarter of 2015 the Tanzania Parliament passed the Petroleum Act, 2015. The Act repeals earlier legislation, provides a regulatory framework over mid-stream and downstream gas activity and as well consolidates and puts in place a single, effective and comprehensive legal framework for regulating the oil and gas industry in the country. The Act also provides for the creation of an upstream regulator, the PURA. The mid and downstream petroleum as well as gas activities are proposed to be regulated by the current authority, EWURA. The Act also confers upon on TPDC, the status of the National Oil Company, mandated with the task of managing the country’s commercial interest in the petroleum operations as well as mid and downstream natural gas activities. The Act vests TPDC with exclusive rights in the entire petroleum upstream value chain and the natural gas mid and downstream value chain. However, the exclusive rights of the National Oil Company does not extended to mid and downstream petroleum supply operations. The Act does provide grandfathering provisions upholding the rights of the Company under the PSA as it was signed prior to passing of the Act. However, it is still unclear how the provisions of the Act will be interpreted and implemented regarding upstream and downstream activities and related impact on the Company. On October 7, 2016, the Government of Tanzania issued the Petroleum (Natural Gas Pricing) Regulation made under Sections 165 and 258 (I) of the Act. Article 260 (3) preserves the Company’s pre-existing right with TPDC to market and sell Additional Gas together or independently on terms and conditions (including prices) negotiated with third party Natural Gas customers. The impact of the Natural Gas Pricing Regulation, if any, cannot be determined at this time. Amended and Restated Gas Agreement The ARGA provides clarification of the Protected Gas volumes and removes all terms dealing with the security of the Protected Gas and contract terms dealing with the consequences of any insufficiency are dealt with in 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. As at the date of this report, the ARGA remains an initialed agreement only, however the parties thereto, in certain respects, are conducting themselves as though the ARGA is in effect. Management does not foresee at this time a material risk with the conduct of the Company’s business with an unsigned ARGA. 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. The Company has the right to earn an interest in a permit in Italy; however, changes in Italian environmental legislation in late 2015 have resulted in the development of the license being postponed indefinitely. 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 organizations 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. management's discussion & analysis36 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. The developed natural gas market in Tanzania is in its infancy and there is currently limited access to infrastructure with which to serve potential new markets beyond that being constructed by the Company, Songas and TPDC which includes the NNGIP. 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 process gas and to deliver sales gas volumes, including acquiring capacity on pipelines which deliver natural gas to commercial markets. The Company is also subject to market fluctuations in the prices of oil and natural gas, uncertainties related to the delivery and proximity of its reserves to pipelines and processing facilities and extensive government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and gas and many other aspects of the oil and gas business. 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. With the enactment of the Petroleum Act, 2015 TPDC was given significant rights over upstream and downstream operations in the country and is the sole aggregator of natural gas in the country. The Act recognizes the rights of the Company pursuant to the PSA; however, some clauses conflict with the Company’s rights to directly market Additional Gas, and there is a risk that this prior right will not continue to be recognized and that the Company’s ability to maximize revenue on Additional Gas sales may be impaired by the requirement 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 activities, 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. 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. There is no assurance that the Company will have sufficient deliverability through the existing wells to provide additional natural gas sales volumes, and that there may be significant capital expenditures associated with any remedial work, workovers, or new drilling required to achieve deliverability. In addition, any difficulties relating to the operation or performance of the field would have a material adverse effect on the Company. Until the Company is connected to the NNGIP, it has no redundant capacity in the production facilities or pipeline. A loss or material reduction in production capabilities will have a material adverse effect on the total production and funds flow from operating activities of the Company. The Company has an interest in the Elsa licence in Italy however changes in Italian environmental legislation in late 2015 have resulted in the development of the Elsa Italian licence being postponed indefinitely. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis37 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. Compliance 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 may have an obligation to restore producing fields to a condition acceptable to the authorities at the end of their commercial lives. The PSA does not contain abandonment obligations for the Company. In addition, the Company expects the Songo Songo field to produce well beyond the term of the current license. The Company’s petroleum and natural gas operations are subject to extensive governmental legislation and regulation and increased public awareness concerning environmental protection. While management believes that the Company is currently in compliance with environmental laws and regulations 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. In accordance with the terms of the PSA, no provision has been recognized 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 interpre- tations thereof or the nature of its operations may require the Company to make significant additional capital expenditures to ensure compliance in the future. Volatility of Oil and Gas Prices and Markets 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 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. There has been a significant increase in exploration activity in Tanzania, which has yielded world class 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. management's discussion & analysis38 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 Consultants Ltd. These evaluations include a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, crude oil price differentials to benchmarks, future prices of oil and natural gas, operating costs, transportation costs, cost recovery provisions and royalties, TPDC “back-in” methodology and other government levies that may be imposed over the producing life of the reserves. These assumptions were based on price forecasts in use at the date of the relevant evaluations were prepared and many of these assumptions are subject to change and are beyond the control of 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. 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 individual 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 99.6% 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 (20.7% fully diluted) and controls 59.2% of the total votes of the Company. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis39 CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS The following are the critical judgements, apart from those involving estimations (see below), that management has made in the process of applying the Company’s accounting policies and that have the most significant effect on the accounts recognized in these consolidated financial statements. Critical judgements in applying accounting policies: A. Exploration and evaluation assets and property, plant and equipment The Company assesses its property, plant and equipment for impairment when events or circumstances indicate that the carrying amount of its assets may not be recoverable. If any indication of impairment exists, the Company performs an impairment test on the CGU, which is the lowest level at which there are identifiable cash flows. The carrying amount of the CGU is compared to its recoverable amount which is defined as the greater of its fair value less cost to sell and value in use and is subject to management estimates. These estimates include quantities of reserves and future production, future commodity pricing, development costs, operating costs, and discount rates. Any changes in these estimates may have an impact on the recoverable amount of the CGU. Property, plant and equipment is measured at cost less accumulated depreciation, depletion and amortization. The Company’s oil and natural gas properties are depleted using the unit-of-production method over proved plus probable reserves. The unit-of-production method takes into account estimates of capital expenditures incurred to date along with future development capital required to develop both proved plus probable reserves. B. Collectability of receivables The Company evaluates the collectability of its receivables on the basis of payment history, frequency and predictability, as well as Management’s assessment of the customer’s willingness and ability to pay. Management performs impairment tests each period on the Company’s current and long-term receivables. As a result of TANESCO’s inability to fully pay all amounts invoiced by the Company for the past few years, management of the Company has modified its approach to revenue recognition as it relates to TANESCO only. Commencing on October 1, 2016 the Company will record 80% of the amounts invoiced to TANESCO for revenue recognition purposes. The 80% amount was determined by comparison of TANESCO’s historical payment history to the amounts invoiced by the Company over the past three years. This results in a reduction in revenue recognized from the effective date. The percentage used to recognize TANESCO revenue will be reviewed on at least a semi-annual basis, more frequently if circumstances require and if there is a significant difference between the amount of revenue recorded and amounts received, the percentage used to record revenue as well as any existing receivable or deferred revenue balance will be revised accordingly. C. Taxes The Company operates in a jurisdiction with complex tax laws and regulations, which are evolving over time. The Company has taken certain tax positions in its tax filings and these filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax impact may differ significantly from that estimated and recorded by management. Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in profit or loss in the period in which the change occurs. management's discussion & analysis 40 Key sources of estimation of uncertainty D. 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 evaluated by 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, 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 December 31, 2016 it was assumed that TPDC will elect to ‘back-in’ for 20% for all future new drilling activities after well SS-12 and this is reflected in the Company’s net reserve position. As at the time of writing this report TPDC have made no such election. Reserves are integral to the amount of depletion recognized and impairment test. E. 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. F. 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. G. 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 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. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTORCA EXPLORATION GROUP INC.Management’s Discussion & Analysis 2016 FINANCIAL STATEMENTS & NOTES ORCA EXPLORATION GROUP INC.42 Management’s Report to Shareholders The accompanying consolidated financial statements of Orca Exploration Group Inc. are the responsibility of Management. 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 authorized, assets are safeguarded and financial records are properly maintained to provide reliable information for the preparation of financial statements. An independent firm of Chartered Professional Accountants, as appointed by the Shareholders, audited the consolidated financial statements in accordance with the Canadian Generally Accepted Auditing Standards to enable them to express an opinion on the 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 the 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 April 12, 2017 Blaine E. Karst Chief Financial Officer April 12, 2017 ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORT Independent Auditors’ Report 43 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, 2016 and December 31, 2015, the consolidated statements of comprehensive income, changes in shareholders’ 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 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, 2016 and December 31, 2015 and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards. Chartered Professional Accountants April 12, 2017 Calgary, Canada financial statements44 Consolidated Statements of Comprehensive Income ORCA EXPLORATION GROUP INC. US$’000 Revenue Production and distribution Net production revenue Operating expenses General and administrative Depletion Operating income Finance income Finance expense Income before tax Income tax – current Income tax – deferred Net income Foreign currency translation (loss) gain from foreign operations Comprehensive income Net income per share (US$) Basic and diluted See accompanying notes to the consolidated financial statements. Note 6, 7 9 9 10 10 YEARS ENDED DECEMBER 31 2016 2015 64,659 (4,033) 60,626 (16,337) (9,191) 35,098 383 (19,937) 15,544 (9,719) (3,661) 2,164 (295) 1,869 54,088 (3,751) 50,337 (13,608) (11,855) 24,874 43 (13,988) 10,929 (7,691) (1,705) 1,533 144 1,677 17 0.06 0.04 ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTConsolidated Statements of Financial Position 45 ORCA EXPLORATION GROUP INC. US$’000 Assets Current assets Cash and cash equivalents Trade and other receivables Tax recoverable Prepayments Non-current assets Long-term trade receivable Property, plant and equipment Total Assets Equity and liabilities Current liabilities Trade and other payables Tax payable Non-current liabilities Deferred income taxes Long-term loan Additional Profits Tax Total Liabilities Equity Capital stock Contributed surplus Accumulated other comprehensive loss Accumulated loss Total equity and liabilities AS AT DECEMBER 31 Note 2016 2015 12 10 12 13 14 10 15 11 80,895 27,638 5,402 651 53,797 25,391 4,519 1,118 114,586 84,825 525 584 111,421 104,274 111,946 104,858 226,532 189,683 39,707 2,890 42,597 12,973 58,399 32,540 103,912 146,509 49,531 2,773 52,304 9,312 18,599 31,314 59,225 111,529 16 85,488 85,488 6,347 (381) (11,431) 80,023 6,347 (86) (13,595) 78,154 226,532 189,683 See accompanying notes to the consolidated financial statements. Nature of Operations (Note 1); Contractual obligations and committed capital investment (Note 19); Contingencies (Note 20). The consolidated financial statements were approved by the Board of Directors on April 12, 2017. Director Director financial statements 46 Consolidated Statements of Cash Flows ORCA EXPLORATION GROUP INC US$’000 Operating activities Net Income Adjustment for: Depletion and depreciation Provision for doubtful accounts Stock-based compensation (recovery) Deferred income taxes Additional Profits Tax Unrealized gain on foreign exchange Interest expense Change in non-cash working capital Net cash flow from operating activities Investing activities Property, plant and equipment expenditures Change in working capital related to investing activities Net cash used in investing activities Financing activities Interest paid Increase in long-term loan Normal course issuer bid repurchases Net cash flow from financing activities Increase (decrease) in cash Cash and cash equivalents at the beginning of the year Effect of change in foreign exchange on cash for the year Cash and cash equivalents at the end of the year See accompanying notes to the consolidated financial statements. YEARS ENDED DECEMBER 31 Note 2016 2015 2,164 1,533 13 9 16 10 11 9 13 9 15 16 9,777 14,245 1,604 3,661 1,226 (822) 5,668 (17,555) 19,968 (16,924) (10,685) (27,609) (5,668) 39,800 – 34,132 26,491 53,797 607 80,895 12,555 9,908 (244) 1,705 2,355 (1,358) 117 (10,553) 7,018 (38,411) 8,461 (29,950) (117) 18,599 (158) 18,324 (4,608) 57,659 746 53,797 ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORT Consolidated Statements of Changes in Shareholders’ Equity 47 ORCA EXPLORATION GROUP INC. US$’000 Note Capital stock Contributed surplus Cumulative translation adjustment Accumulated loss Total 16 Balance as at January 1, 2016 85,488 6,347 (86) (13,595) 78,154 Foreign currency translation adjustment on foreign operations Net income – – – – Balance as at December 31, 2016 85,488 6,347 (295) – (381) – 2,164 (295) 2,164 (11,431) 80,023 US$’000 Note Balance as at January 1, 2015 Normal course issuer bid exercise Foreign currency translation adjustment on foreign operations Net income Capital stock Contributed surplus Cumulative translation adjustment Accumulated loss Total 16 85,637 (149) – – 6,356 (9) – – (230) – 144 – (86) (15,128) 76,635 – – 1,533 (158) 144 1,533 (13,595) 78,154 Balance as at December 31, 2015 85,488 6,347 See accompanying notes to the consolidated financial statements. financial statements48 General Information Orca Exploration Group Inc. was incorporated on April 28, 2004 under the laws of the British Virgin Islands with registered offices located at PO Box 146, Road Town, Tortola, British Virgin Islands, VG110 The Company produces and sells natural gas to the power and industrial sectors in Tanzania. The consolidated financial statements of the Company as at and for the year ended December 31, 2016 comprise accounts of the Company and all its wholly owned subsidiaries (collectively, the “Company” or “Orca Exploration”) and were authorized for issue in accordance with a resolution of the directors on April 12, 2017. 1 NATURE OF OPERATIONS 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 (“GoT”) in the United Republic of Tanzania. This PSA covers the production and marketing of certain gas from the Songo Songo Block offshore Tanzania. The PSA defines gas in the Songo Songo field as “Protected Gas” and “Additional Gas”. The “Protected Gas” is owned by TPDC and is sold under a 20-year gas agreement until July 2024 (“Gas Agreement”) 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. Songas utilizes the Protected Gas as feedstock for its gas turbine electricity generators for onward sale to customers. 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 Block in excess of the Protected Gas requirements (“Additional Gas”). The Tanzania Electric Supply Company Limited (“TANESCO”) is a parastatal organization which is wholly-owned by the GoT, with oversight by the Ministry of Energy and Minerals (“MEM”). TANESCO is responsible for the generation, transmission and distribution of electricity throughout Tanzania. The Company currently supplies gas directly to TANESCO by way of a Portfolio Gas Supply Agreement (“PGSA”) and indirectly through the supply of Protected Gas and Additional Gas to Songas which in turn generates and sells power to TANESCO. The state utility is the Company’s largest customer. In addition to gas supplied to Songas and TANESCO for the generation of power, the Company has developed and supplies an industrial gas market in the Dar es Salaam area. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements49 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 (“US$”). 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”). Basis of consolidation 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. Orca Exploration Italy Inc. Orca Exploration Italy Onshore Inc. PAE PanAfrican Energy Corporation PanAfrican Energy Tanzania Limited Orca Exploration UK Services Limited British Virgin Islands British Virgin Islands British Virgin Islands Mauritius Jersey United Kingdom Parent Company 100% 100% 100% 100% 100% US dollar Euro Euro US dollar US dollar British Pound Transactions eliminated upon consolidation Inter-company balances and transactions, and any unrealized gains or losses arising from inter-company transactions, are eliminated in preparing the consolidated financial statements. 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 earnings. ii) Foreign currency translation Foreign currency differences are recognized in comprehensive income and accumulated in the translation reserve. The assets and liabilities of these companies are translated into the functional currency at the period-end exchange rate. The income and expenses of the companies are translated into the functional currency at the average exchange rate for the period. Translation gains and losses are included in other comprehensive income. notes50 3 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements. Exploration and evaluation assets, property plant and equipment i) Exploration and evaluation assets Exploration and evaluation costs are capitalized as intangible assets. Intangible assets include lease and license acquisition costs, geological and geophysical costs and other direct costs of exploration and evaluation which management considers to be unevaluated until reserves are appraised to be commercially viable and techno- logically 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, depreciation and accumulated impairment losses. Cost includes purchase price and construction costs for qualifying assets. Depletion of these assets commences when the assets are ready for their intended use. Only costs that are directly related to the discovery and development of specific oil and gas reserves are capitalized. The cost associated with tangible natural gas assets are amortized on a field by field unit of production method based on commercial proven reserves. The calculation of the unit of production amortization takes into account the estimated future development cost associated with proven reserves. 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 identifiable 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 CGU 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 recognized for the CGU in prior years. A reversal of an impairment loss is recognized in earnings. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 51 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 gain no loss’ 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. Costs incurred by the Company in connection with the operatorship of the Songas plant are recorded as receivables, which are re-charged to Songas. Subsequent payments received from Songas are credited to receivables. 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. 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 recognized 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 earnings 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, and the estimate of the level of forfeiture. . iii) Stock appreciation rights and restricted stock units Stock appreciation rights (“SARs”) and restricted stock units (“RSUs”) are issued to certain key managers, officers, directors and employees. The fair value of SARs and RSUs is expensed in the statement of comprehensive income in accordance with the service period. The fair value of the SARs and RSUs is revalued every reporting date with the change in the value recognized in earnings. 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 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. 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 TPDC, to sell or otherwise dispose of Additional Gas. The Company recognizes revenue related to Additional Gas sales from the sale of gas to all customers, including both TANESCO and Songas, when title passes to the customer at fiscal gas meters which are installed at the respective customer’s plant gate in Dar es Salaam. Under the terms of the PSA, the Company pays both its share and TPDC’s share of operating, administrative and capital costs. The Company recovers all reasonably incurred operating, administrative and capital costs including the parastatal’s share of these costs from future revenues over several years (“Cost Gas”). TPDC’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. notes52 The Company has a gas sales contract under which the customer is required to take, or pay for, a minimum quantity of gas. In the event that the customer has paid for gas that was not delivered, the additional income received by the Company is carried on the balance sheet as “deferred income”. If the customer consumes volumes in excess of the minimum, it will be charged at the current rate, but may receive a credit for volumes paid but not delivered. At the end of each reporting period the Company reassesses the volumes for which the customer may receive credit, any remaining balance is credited to income. 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. Under the PSA the Company’s share of Profit Gas is further increased by the amount necessary to fully pay and discharge any liability for taxes on income. Revenue represents the Company’s share of Profit Gas and Cost Gas during the period. Prior to 2016 the Company had reached an understanding with TANESCO that it would continue to supply gas if TANESCO remained reasonably current with payments for gas deliveries. As a result of TANESCO’s inability to fully pay all amounts invoiced by the Company for the past few years, management of the Company has modified its approach to revenue recognition as it relates to TANESCO only. Commencing on October 1, 2016 the Company will record 80% of the amounts invoiced to TANESCO for revenue recognition purposes. The 80% amount was determined by comparison of TANESCO’s historical payment history to the amounts invoiced by the Company over the past three years. Management believes this approach provides the best estimate of TANESCO’s ability to pay and remain reasonably current and as well reflects the economic reality of the situation. This results in a reduction in revenue recognized from the effective date (see Notes 4 and 7). For cash received in excess of the revenue recorded from TANESCO in any given period, the additional amounts received will be recorded as deferred revenue. In periods when cash received is less than revenue recorded, the deferred revenue will be reduced accordingly. If the deferred revenue amount is reduced to nil, the difference will be recorded as accounts receivable. The percentage used to recognize TANESCO revenue will be reviewed on at least a semi-annual basis, more frequently if circumstances require and if there is a significant difference between the amount of revenue recorded and amounts received, the percentage used to record revenue as well as any existing receivable or deferred revenue balance will be revised accordingly. 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 program. The PSA states that APT shall be calculated for each year and shall vary with the real rate of return earned by the Company on the net cash flow from the Contract Area (as defined). The calculation of APT includes a working capital adjustment reflecting the effect of the timing of actual receipt of amounts owing from TANESCO on net cash flow available to APT. Income taxes The Company is liable for Tanzanian income tax on the income for the year; this comprises current and deferred tax. Where current income tax is payable, this is shown as a current tax liability. 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 realization or settlement of carrying amounts of assets and liabilities using tax rates substantively enacted at the balance sheet date. A deferred tax asset is recognized only to the extent that it is probable that future taxable profits will be available, against which the asset can be utilized. Deferred tax assets are reduced to the extent that it is no longer probable that the related tax benefits will be realized. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements53 Depreciation Depreciation for non-natural gas properties is charged to earnings 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 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 the statement of comprehensive income (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 statement of comprehensive 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 repurchasing 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 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 long-term loan are classified as other financial liabilities and are initially measured at fair value less directly attributable transaction costs and are subsequently recorded at amortized cost using the effective interest method. The fair value of trade and other payables approximates the carrying amounts due to the short-term nature of these instruments. The fair value of the long-term loan approximates its carrying value as there has been no significant change in interest rates since the Company finalized the loan. The loan interest rate is fixed at 10%. notes54 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. There are no restrictions on the movement of funds out of Tanzania. 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 earnings. 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 earnings. New accounting standards and interpretations At the date of these financial statements the standards and interpretations listed below were issued but not yet effective. The adoption of these standards may result in future changes to existing accounting policies and disclosures. The Company is currently evaluating the impact that these standards will have on results of operations and financial position. In May 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers," which replaces IAS 18 "Revenue," IAS 11 "Construction Contracts," and related interpretations. The standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted. The Company has commenced the process of identifying and reviewing sales contracts with customers to determine the extent of the impact, if any, that this standard will have on the consolidated financial statements. In July 2014, the IASB finalized the remaining elements of IFRS 9 – Financial Instruments, which includes new requirements for the classification and measurement of financial assets, amends the impairment model and outlines a new general hedge accounting standard. The mandatory effective date of IFRS 9 is for annual periods on or after January 1, 2018 and must be applied retrospectively with some exemptions. Early adoption is permitted. The Company is evaluating the impact of this standard on the consolidated financial statements and does not anticipate material changes to the valuation of its financial assets. In January 2016, the IASB issued IFRS 16 Leases, which replaces IAS 17 Leases. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted if the entity is also applying IFRS 15 Revenue from Contracts with Customers. The Company is currently identifying contracts that will be identified as leases and evaluating the impact of the standard on the consolidated financial statements. There are no other standards and interpretations in issue but not yet adopted that are expected to have a material effect on the reported earnings or net assets of the Company. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements55 4 USE OF ESTIMATES AND JUDGEMENTS The following are the critical judgements, apart from those involving estimations (see below), that management has made in the process of applying the Company’s accounting policies and that have the most significant effect on the accounts recognized in these consolidated financial statements. Critical judgements in applying accounting policies: A. Exploration and evaluation assets and property, plant and equipment The Company assesses its property, plant and equipment for impairment when events or circumstances indicate that the carrying amount of its assets may not be recoverable. If any indication of impairment exists, the Company performs an impairment test on the CGU, which is the lowest level at which there are identifiable cash flows. The carrying amount of the CGU is compared to its recoverable amount which is defined as the greater of its fair value less cost to sell and value in use and is subject to management estimates. These estimates include quantities of reserves and future production, future commodity pricing, development costs, operating costs, and discount rates. Any changes in these estimates may have an impact on the recoverable amount of the CGU. Property, plant and equipment is measured at cost less accumulated depreciation, depletion and amortization. The Company’s oil and natural gas properties are depleted using the unit-of-production method over proved reserves. The unit-of-production method takes into account estimates of capital expenditures incurred to date along with future development capital required to develop the proved reserves. B. Collectability of receivables The Company evaluates the collectability of its receivables on the basis of payment history, frequency and predictability, as well as Management’s assessment of the customer’s willingness and ability to pay. Management performs impairment tests each period on the Company’s current and long-term receivables. Prior to 2016 the Company had reached an understanding with TANESCO that it would continue to supply gas if TANESCO remained reasonably current with payments for gas deliveries. As a result of TANESCO’s inability to fully pay all amounts invoiced by the Company for the past few years, management of the Company has modified its approach to revenue recognition as it relates to TANESCO only. Commencing on October 1, 2016 the Company will record 80% of the amounts invoiced to TANESCO for revenue recognition purposes. The 80% amount was determined by comparison of TANESCO’s historical payment history to the amounts invoiced by the Company over the past three years. Management believes this approach provides the best estimate of TANESCO’s ability to pay and remain reasonably current and as well reflects the economic reality of the situation. This results in a reduction in revenue recognized from the effective date (see Notes 7 and 12). C. Taxes The Company operates in a jurisdiction with complex tax laws and regulations, which are evolving over time. The Company has taken certain tax positions in its tax filings and these filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax impact may differ significantly from that estimated and recorded by management. Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in profit or loss in the period in which the change occurs. notes56 Key sources of estimation of uncertainty D. 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 evaluated by 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, 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 December 31, 2016 it was assumed that TPDC will elect to ‘back-in’ for 20% for all future new drilling activities after well SS-12 and this is reflected in the Company’s net reserve position. As at the date of the consolidated financial statements, TPDC has made no such election. Reserves are integral to the amount of depletion and impairment test. E. 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. F. 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 field revenue less processing and pipeline tariffs (“field 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. G. 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 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. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements57 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. A. Foreign exchange risk Foreign exchange risk arises when transactions and recognized 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, British pounds sterling, Euros and Canadian dollars. The majority of the expenditure associated with the operation of the gas distribution system is denominated in Tanzanian shillings. Whilst conversion of Tanzanian shillings into US dollars is unrestricted, the foreign exchange market for Tanzanian shillings is limited and not highly liquid, reducing the Company’s ability to convert large amounts of Tanzanian shillings into US dollars at any given time. To mitigate the risk of Tanzanian shilling devaluation, the Company regularly converts Tanzanian shilling receipts into US dollars to the extent practicable. Capital stock, equity financing and any associated stock based compensation are denominated in Canadian dollars. The operational revenue and the majority of capital expenditures are denominated in US dollars. There are no forward exchange rate contracts in place. A 10% increase in the US dollar against the relevant foreign currency would result in an overall decrease in working capital (defined as current assets less current liabilities) of US$0.7 million to US$71.3 million and an increase in the income before tax to US$16.2 million. The sensitivity includes only outstanding foreign currency denominated monetary items and adjusts their translation at period end for a 10% change in the foreign currency rates. A 10% sensitivity rate is used when reporting foreign currency risk internally to key management personnel and represents management’s assessment of the reasonable possible change in foreign exchange rates. The following balances are denominated in foreign currency (stated in US dollars at period end exchange rates): Balances as at December 31, 2016 US$’000 Cash Trade and other receivables Trade and other payables Canadian dollars Tanzanian shillings Euros Other 0.1 – (3.3) (3.2) 7.6 8.1 (4.4) 11.3 1.1 0.7 (0.1) 1.7 0.4 0.8 (1.0) 0.2 Total 9.2 9.6 (8.8) 10.0 B. Commodity price risk The Company negotiated industrial gas sales contracts with gas prices which, subject to certain floors and ceilings, are determined as 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. C. Interest rate risk Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company has minimal exposure to interest rates as the long-term loan has a fixed interest rate and interest received on cash balances is not significant. notes58 D. 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 at December 31, 2016 and 2015, other than the provisions against the long-term TANESCO receivable, the provision for gas plant operations charges and capital expenditure receivables from Songas and the provision of US$ 0.4 million for two industrial customers, the Company does not have an allowance for doubtful accounts against any other receivables nor was it required to write-off any receivables (see Note 12). All 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 of gas. The contracts with Songas and TANESCO accounted for 53% of the Company’s gross field revenue during 2016 and US$3.8 million of the short and long-term receivables prior to provision at year-end. TANESCO continues to have difficulties paying invoices in full. As a result, management has placed a provision for doubtful accounts against arrears due from TANESCO in the amount of US$74.4 million as at December 31, 2016 (2015: US$61.9 million). Based on a review of the TANESCO payment history in October 2016, Management revised its estimate for collectability of revenue for sales to TANESCO (see Notes 7 and 12). Sales to the Industrial sector are subject to an internal credit review to minimize the risk of non-payment. The Company manages the credit exposure related to cash and cash equivalents by selecting counterparties 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. The Company’s cash resources are placed with reputable financial institutions with no history of default. E. 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$39.7 million of financial liabilities with regards to trade and other payables of which US$38.8 million is due within one to three months, nil is due within three to six months, and US$0.9 million is due within six to twelve months (see Note 14). As at year-end the Company had a current tax liability of US$2.9 million. At the end of the year a significant proportion of the current liabilities relate to TPDC. The amounts due to TPDC represent its share of Profit Gas; in accordance with the terms of the PSA TPDC is entitled to the payment of its share of Profit Gas, on a quarterly basis in relation to the cash receipts during the quarter. Given the difficulties in collecting from TANESCO, the Company has been settling and intends to continue to settle these amounts on a pro rata basis in accordance with amounts received from TANESCO. F. 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 optimization of capital structure as many sources of traditional capital are unavailable. G. Country risk Prior to 2014 an allegation had been made by TPDC that the Company had over-recovered approximately US$21 million in Cost Gas revenue. In response to a Notice of Dispute delivered by the Company in March 2014, TPDC retracted the allegation and no further action has been taken by Parliament or the Government against the Company related to the allegations. Accordingly, the Company continues to rely upon its rights under the existing PSA and has initiated notices of dispute to resolve any remaining issues. The Company has put in place an advisory committee of experienced individuals with significant experience working with the Tanzanian government to mitigate the risks of doing business in Tanzania. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements59 6 SEGMENT INFORMATION The Company has one reportable industry segment which is international exploration, development and production of petroleum and natural gas. The Company currently has producing and exploration assets in Tanzania and had exploration and appraisal interests in Italy. US$’000 External revenue Segment income (loss) Non-cash charge (1) Depletion & depreciation Capital additions Total assets Total liabilities 2016 2015 Italy Tanzania Total Italy Tanzania Total – (100) – – – 1,477 102 64,659 2,264 64,659 2,164 (14,245) (14,245) 9,777 16,924 9,777 16,924 – (167) – – – 54,088 54,088 1,700 (9,908) 12,555 38,411 1,533 (9,908) 12,555 38,411 225,055 226,532 1,621 188,062 189,683 146,407 146,509 131 111,398 111,529 (1) Non-cash charge represent amounts provided for doubtful accounts receivable from TANESCO and indirect taxes expensed directly to the statement of comprehensive income. notes 60 7 REVENUE US$’000 Industrial sector Power sector Gross field revenue Processing and transportation tariff Field net revenue TPDC share of revenue Company operating revenue Additional Profits Tax charge Current income tax adjustment Revenue YEARS ENDED DECEMBER 31 2016 2015 35,626 39,751 75,377 (10,057) 65,320 (9,798) 55,522 (1,226) 10,363 64,659 33,164 46,721 79,885 (12,282) 67,603 (17,349) 50,254 (2,355) 6,189 54,088 The Company’s reported revenues for the year amounted to US$64.7 million after adjusting the Company’s operating revenue of US$55.5 million by: i) Adding US$10.4 million for income tax for the current year. The Company is liable for income tax in Tanzania, but the income tax is recoverable out of TPDC’s Profit Gas when the tax is payable. To account for this, revenue is adjusted to include the current income tax charge grossed up at 30%; and, ii) Subtracting US$1.2 million for deferred Additional Profits Tax charged in the year. This tax is considered a royalty and is presented as a reduction in revenue. Prior to 2016 the Company had reached an understanding with TANESCO that it would continue to supply gas if TANESCO remained reasonably current with payments for gas deliveries. As a result of TANESCO’s inability to fully pay all amounts invoiced by the Company for the past few years, management of the Company has modified its approach to revenue recognition as it relates to TANESCO only. Commencing on October 1, 2016 the Company will record 80% of the amounts invoiced to TANESCO for revenue recognition purposes. The 80% amount was determined by comparison of TANESCO’s historical payment history to the amounts invoiced by the Company over the past three years. Management believes this approach provides the best estimate of TANESCO’s ability to pay and remain reasonably current and as well reflects the economic reality of the situation. This results in a reduction in revenue recognized from the effective date For cash received in excess of the revenue recorded from TANESCO in any given period, the additional amounts received will be recorded as deferred revenue. In periods when cash received is less than revenue recorded, the deferred revenue will be reduced accordingly. If the deferred revenue amount is reduced to nil, the difference will be recorded as accounts receivable. The percentage used to recognize TANESCO revenue will be reviewed on at least a semi-annual basis, more frequently if circumstances require and if there is a significant difference between the amount of revenue recorded and amounts received, the percentage used to record revenue as well as any existing receivable or deferred revenue balance will be revised accordingly. As a result of recording revenue based on the expected collectability from the effective date, there is the following impact on the 2016 results: 1) US$1.6 million decrease in revenue, 2) US$1.3 million decrease in long-term receivables, allowance for doubtful accounts, 3) US$0.6 million decrease in current accounts receivable, 4) US$0.3 million decrease in net income and current liabilities. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements8 PERSONNEL EXPENSES Personnel costs are as follows: US$’000 Wages and salaries Social security costs Other statutory costs Stock based compensation 61 YEARS ENDED DECEMBER 31 2016 2015 10,589 629 284 11,502 2,591 14,093 9,037 876 207 10,120 (244) 9,876 Stock based compensation is recorded under general and administrative expenses in the statement of comprehensive income. The balance of personnel expenses for 2016 of US$11.5 million (2015: US$10.1 million) is recorded in distribution and production expenses and general administrative expenses at US$2.6 million (2015: US$1.9 million) and US$8.9 million (2015: US$8.0 million) respectively. Personnel expenses include Company employees who operate the plant on behalf of Songas, these expenses are recharged to Songas. 9 NET FINANCE EXPENSE US$’000 Finance income Interest expense Net foreign exchange loss Financing fee Indirect tax Provision for doubtful accounts Finance expense Net finance expense YEARS ENDED DECEMBER 31 2016 383 (5,668) (24) – (1,392) (12,853) (19,937) (19,554) 2015 43 (117) (2,677) (16) – (11,178) (13,988) (13,945) The total amount of interest paid in 2016 was US$5.7 million (2015: US$0.1 million). During 2016 the Company invoiced TANESCO US$4.2 million of interest for late payments (2015: US$2.4 million). The interest income is not recorded in the financial statements because it does not meet the revenue recognition criteria with respect to assurance of collectability. The Company is pursuing collection and amounts will be recognized in earnings when collected. The US$1.4 million is in relation to indirect taxation associated with trade receivables not recognized in the financial statements due to IFRS revenue recognition criteria with respect to assurance of collectability. The provision for doubtful accounts includes US$12.4 million for overdue TANESCO receivables (2015: US$9.9 million), US$ nil relates to Songas receivables (2015: US$1.3 million) and US$0.4 million relates to Industrial customers (2015: US$0.1 million). notes62 10 INCOME TAXES The tax charge is as follows: US$’000 Current tax Deferred tax expense YEARS ENDED DECEMBER 31 2016 9,719 3,661 13,380 2015 7,691 1,705 9,396 Tax of US$1.2 million was paid during the year in relation to the settlement of the prior year’s tax liability (2015: US$3.0 million). In addition, provisional tax payments totaling US$8.3 million were made in respect of the current year (2015: US$6.9 million). These are presented as a reduction in tax payable on the statement of financial position. Tax rate reconciliation US$’000 Income before tax 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 Foreign exchange loss Stock-based compensation (recovery) TANESCO interest not recognized as interest income (Note 9) Unrecognized tax asset Other permanent differences YEARS ENDED DECEMBER 31 2016 15,544 4,663 1,343 48 777 1,062 5,445 42 13,380 2015 10,929 3,279 1,552 199 (73) 714 2,930 795 9,396 As at December 31, 2016, the provision for doubtful debt from TANESCO has resulted in a US$23.1 million unrecognized deferred tax asset (2015: US$17.6 million). If this amount was ultimately not recovered, the Company would also be entitled to a US$13.9 million recovery of Value Added Tax. A deferred tax asset of US$2.2 million in respect of Longastrino Italy exploration and evaluation costs has not been recognized because it is not probable that there will be future profits against which this can be utilized (2015: US$2.2 million). ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 63 The deferred income tax liability includes the following temporary differences: US$’000 AS AT DECEMBER 31 2016 2015 Differences between tax base and carrying value of property, plant and equipment (21,563) (18,185) Tax recoverable from TPDC Provision for doubtful debt Deferred Additional Profits Tax Unrealized exchange losses/other provisions (4,142) 3,110 9,787 (165) (12,973) (3,442) 2,987 9,394 (66) (9,312) Tax recoverable The Company has a tax recoverable balance of US$5.4 million (2015: US$4.5 million). This arises from the revenue sharing mechanism within the PSA, which entitles the Company to recover from TPDC, by way of a deduction from TPDC’s Profit Gas share an amount equal to the actual income taxes payable by the Company. The recovery, by deduction from TPDC’s share of revenue, is dependent upon payment of income taxes relating to prior period adjustment factors as they are assessed. US$’000 Tax recoverable 11 ADDITIONAL PROFITS TAX AS AT DECEMBER 31 2016 5,402 2015 4,519 Under the terms of the PSA, in the event that all costs have been recovered with an annual cash 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 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 18.8% (2015: 20.2%) has been applied to Profit Gas of US$6.5 million (2015: US$11.6 million). Accordingly, US$1.2 million has been netted off revenue for the year ended December 31, 2016 (2015: US$2.4 million). notes64 12 TRADE AND OTHER RECEIVABLES Current receivables US$’000 Trade receivables TANESCO Songas Industrial customers Other receivables Songas gas plant operations Songas well workover programme Other Less provision for doubtful accounts Trade receivables aged analysis US$’000 TANESCO Songas Industrial customers US$’000 TANESCO Songas Industrial customers AS AT DECEMBER 31 2016 2015 5,749 2,218 7,463 7,831 2,178 6,894 15,430 16,903 6,601 14,458 1,516 (10,367) 12,208 27,638 5,631 11,209 1,604 (9,956) 8,488 25,391 AS AT DECEMBER 31, 2016 >90 – – 780 780 Total 5,749 2,218 7,463 15,430 AS AT DECEMBER 31, 2015 >90 – – 821 821 Total 7,831 2,178 6,894 16,903 Current >30 <60 >60 <90 2,570 1,190 2,769 6,529 2,559 1,028 3,679 7,266 620 – 235 855 Current >30 <60 >60 <90 3,972 1,082 3,317 8,371 3,859 1,096 1,859 6,814 – – 897 897 ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements65 TANESCO At December 31, 2016 TANESCO owed the Company US$80.1 million excluding interest (including arrears of US$74.4 million) compared to US$69.8 million (including arrears of US$61.9 million) as at December 31, 2015. Current TANESCO receivables as at December 31, 2016 amounted to US$5.7 million (2015 US$7.8 million). Since the year-end, TANESCO has paid the Company US$12.9 million, and as at the date of this report the total TANESCO receivable is US$74.8 million (of which US$74.4 million has been provided for). The amounts owed do not include interest billed to TANESCO or debtors not meeting the revenue recognition criteria with respect to assurance of collectability (see Note 7). To September 30, 2016 the Company classified US$12.4 million as a long-term receivable and placed a full provision against this amount. The total provision was US$74.4 million (2015: US$ 61.9 million) at December 31, 2016. Long-term receivables US$’000 TANESCO receivable Provision for doubtful accounts Net TANESCO receivable VAT bond Lease deposit Long-term receivables AS AT DECEMBER 31 2016 2015 74,361 61,922 (74,361) (61,922) – 318 207 525 – 332 252 584 Songas As at December 31, 2016 Songas owed the Company US$23.3 million (2015: US$19.0 million), whilst the Company owed Songas US$2.3 million (2015: US$2.6 million); there is no contractual right to offset these amounts. Amounts due to Songas primarily relate to pipeline tariff charges of US$ 1.9 million (2015: US$1.1 million), whereas the amounts due to the Company are mainly for capital expenditures of US$14.4 million (2015: US$11.2 million), sales of gas of US$2.2 million (2015: US$2.2 million) and for the operation of the gas plant of US$6.6 million (2015: US$5.6 million). The operation of the gas plant is conducted at cost and the charges are billed to Songas on a flow through basis. As at December 31, 2016 the net amount owed by Songas to the Company was US$21.0 million (2015: US$16.4 million). Although significant progress has been made in settling outstanding balances, a doubtful debt provision of US$9.8 million (2015: US$9.8 million) is necessary recognizing the possible settlement of the remaining overdue operatorship charges and the Songas share of the well workover costs. Any significant amounts not agreed will likely be pursued through the mechanisms provided in the agreements with Songas. All amounts due to and from Songas have been summarized in the table below: Pipeline tariff – payable Gas sales – receivable Gas plant operation receivable Workover program Other payable Net balances January 1, 2016 Year to date transactions Gross balance December 31, 2016 Post year-end payments and receipts Outstanding as at the date of this report (1,071) 2,178 5,631 11,209 (1,546) 16,401 (822) 40 970 3,249 1,168 4,605 (1,893) 2,218 6,601 14,458 (378) 21,006 1,893 (2,218) (1,465) – – – – 5,136 14,458 (378) (1,736) 19,270 notes66 13 PROPERTY, PLANT AND EQUIPMENT US$’000 Costs Oil & natural gas interests Leasehold improvements Computer equipment Vehicles Fixtures & fittings Total As at January 1, 2016 Additions As at December 31, 2016 178,808 16,816 195,624 Accumulated depletion and depreciation As at January 1, 2016 Depletion and depreciation As at December 31, 2016 Net book values 75,389 9,191 84,580 As at December 31, 2016 111,044 699 – 699 345 281 626 73 1,341 25 1,366 1,168 136 1,304 62 297 83 380 168 81 249 131 1,125 182,270 – 16,924 1,125 199,194 926 88 1,014 77,996 9,777 87,773 111 111,421 US$’000 Costs Oil & natural gas interests Leasehold improvements Computer equipment Vehicles Fixtures & fittings Total As at January 1, 2015 Additions As at December 31, 2015 140,653 38,155 178,808 Accumulated depletion and depreciation As at January 1, 2015 Depletion and depreciation As at December 31, 2015 63,534 11,855 75,389 Net book values 699 – 699 170 175 345 1,233 108 1,341 955 213 1,168 149 148 297 120 48 168 1,125 143,859 – 38,411 1,125 182,270 662 264 926 65,441 12,555 77,996 As at December 31, 2015 103,419 354 173 129 199 104,274 In determining the depletion charge, it is estimated that future development costs of US$84.0 million (2015: US$103.8 million) will be required to bring the total proved reserves to production. The decrease in estimated future development costs is a result of the successful completion of the SS-12 development well during the year. This reduced the amount of capital expenditure required in the future to ensure the Company can produce the required gas volumes to meet its contractual obligations for the remaining life of the licence. During the year the Company recorded depreciation of US$0.6 million (2015: US$0.7 million) in general and administrative expenses. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements14 TRADE AND OTHER PAYABLES US$’000 Songas Other trade payables Trade payables TPDC share of Profit Gas Deferred income Accrued liabilities 15 LONG-TERM LOAN 67 AS AT DECEMBER 31 2016 1,893 3,245 5,138 28,319 – 6,250 39,707 2015 1,071 11,234 12,305 28,208 667 8,351 49,531 On October 29, 2015, the Company’s subsidiary, PanAfrican Energy Tanzania Limited (“PAET”), entered into a loan agreement (“Loan”) with the International Finance Corporation (“IFC”), a member of the World Bank Group, for US$60 million. The term of the Loan is ten years, with no repayment of principal for the first seven years, followed by a three-year amortization period. The Company may voluntarily prepay all or part of the Loan but must simultaneously pay any accrued base interest costs related to the principal amount being prepaid. If any portion of the Loan is prepaid prior to the fourth anniversary of the first drawdown, the Company would be required to pay the accrued base interest as if the prepaid portion of the Loan had remained outstanding for the full four years. The Loan is an unsecured subordinated obligation of PAET and is guaranteed by the Company to a maximum of US$30 million. The guarantee may only be called upon by IFC at maturity in 2025 and, subject to IFC approval and receipt of all required regulatory approvals, the Company may issue shares in fulfillment of all or part of the guarantee obligation in 2025. Base interest on the Loan is payable quarterly at 10% per annum on a ‘pay-if-you-can-basis’ using a formula to calculate the net cash available for such payments as at any given interest payment date. To date, all interest incurred has been paid. In addition, an annual variable participatory interest equating to 7% of the net cash flow from operating activities of PAET net of net cash flow used in investing activities in respect of any given year. Such participatory interest will continue until October 15, 2026 regardless whether the Loan is repaid prior to its contractual maturity date. No provision was made for the year ended December 31, 2016 as the current cash flow from operating activities less cash flow used in investing activities for 2016 is a negative amount. Dividends and distributions from PAET to the Company are restricted at any time that any amounts of unpaid interest, principal or participating interest are outstanding. US$’000 Total IFC facility Loan drawdown Financing costs AS AT DECEMBER 31 2016 2015 60,000 60,000 (1,601) 58,399 60,000 20,000 (1,401) 18,599 notes68 16 CAPITAL STOCK 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. Changes in the capital stock of the Company were as follows: 2016 2015 Authorised (000) Issued (000) Amount (US$’000) Authorised (000) Issued (000) Amount (US$’000) 50,000 1,751 983 50,000 1,751 983 Number of shares Class A As at January 1 and December 31 Class B As at January 1 100,000 33,106 84,505 100,000 33,164 84,654 Normal course issuer bid repurchases – – – – (58) (149) As at December 31 100,000 33,106 84,505 100,000 33,106 84,505 First preference As at December 31 100,000 – – 100,000 – – Total Class A, Class B and first preference 250,000 34,857 85,488 250,000 34,857 85,488 All issued capital stock is fully paid. Stock Options Number of options Outstanding as at January 1 Forfeited Outstanding as at December 31 2016 2015 Options Exercise Price Options (000) CDN$ – – – – – – (000) 400 (400) – Exercise Price CDN$ 3.18 3.18 – ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements69 Stock Appreciation Rights (“SARs”) 2016 2015 SARs (000) Exercise Price (CDN$) SARs (000) Exercise Price (CDN$) Outstanding as at January 1 3,100 2.12 to 3.25 2,910 2.12 to 4.20 Exercised Exercised Exercised Forfeited Expired Granted (260) 2.12 to 2.30 (265) 2.32 to 2.70 (55) 3.02 to 3.25 (90) – – 2.30 – – – – – – – – (300) 4.20 490 3.02 to 3.25 Outstanding as at December 31 2,430 2.12 to 3.25 3,100 2.12 to 3.25 The number outstanding, the weighted average remaining life and weighted average exercise prices of SARs at December 31, 2016 were as follows: Exercise price (CDN$) 2.12 to 2.30 2.32 to 2.70 3.02 to 3.25 2.12 to 3.25 Number outstanding (000) Weighted average remaining contractual life (years) Number exercisable (000) Weighted average exercise price (CDN$) 1,730 265 435 2,430 1.94 0.83 3.77 2.15 752 265 85 1,102 2.27 2.48 3.05 2.43 Restricted Stock Units (“RSUs”) Outstanding as at January 1 Granted Exercised Outstanding as at December 31 2016 2015 RSUs (000) – 386 (147) 239 Grant/ exercise price (CDN$) – – 3.90 – RSUs (000) 645 – (645) – Grant/ exercise price (CDN$) – – – – (i) A total of 386,420 RSUs were granted during the year. The RSUs vested on the date of grant and have an exercise price of CDN$.001 and have a five-year term. As SARs and RSUs are settled in cash, they are re-valued at each reporting date using the Black-Scholes option pricing model with the resulting liability being recognized in trade and other payables. In the valuation of stock appreciation rights and restricted stock units at the reporting date, the following assumptions have been made: a risk free rate of interest of 0.5%, stock volatility of 33.5 to 50.7%; 0% dividend yield; 5% forfeiture; a closing stock price of CDN$3.86 per share. US$’000 SARs RSUs AS AT DECEMBER 31 2016 2,495 682 3,177 2015 1,572 – 1,572 As at December 31, 2016, a total accrued liability of US$3.2 million (2015: US$1.6 million) has been recognized in relation to SARs and RSUs which is included in other payables. The Company recognized an expense for the year of US$2.6 million (2015: credit US$0.2 million) in general and administrative expenses. notes70 17 EARNINGS PER SHARE (‘000) Outstanding shares Weighted average number of Class A and Class B shares Weighted average diluted number of Class A and Class B shares AS AT DECEMBER 31 2016 2015 34,857 34,857 34,887 34,887 The calculation of basic earnings per share is based on a net income for the year of US$2.2 million (2015: US$1.5 million) and a weighted average number of Class A and Class B shares outstanding during the period of 34,856,432 (2015: 34,887,100). 18 RELATED PARTY TRANSACTIONS One of the non-executive Directors is council to a law firm that provides legal advice to the Company and its subsidiaries. For the year ended December 31, 2016 US$0.2 million (2015: US$0.6 million) was incurred from this firm for services provided. The former Chief Financial Officer provided services to the Company through a consulting agreement with a personal services company until his resignation on November 2, 2015. For the period from January 1, 2015 to November 2, 2015, US$0.4 million was incurred from this firm for services provided. As at December 31, 2016 the Company has a total of US$0.1 million (2015: US$0.4 million) recorded in trade and other payables in relation to the related parties. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements71 19 CONTRACTUAL OBLIGATIONS & COMMITTED CAPITAL INVESTMENTS Protected Gas Under the terms of the 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, 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 (161.2 Bcf as at December 31, 2016). 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. Terms of the Gas Agreement were modified by the Amended and Restated Gas Agreement (“ARGA”) which was initialed by all parties but remains unsigned. The unsigned ARGA provides clarification of the Protected Gas volumes and removes all terms dealing with the security of the Protected Gas and contract terms dealing with the consequences of any insufficiency are dealt with in 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. Although the ARGA remains unsigned, the parties have continued to conduct themselves as though the ARGA is in full force and effect. Re-Rating Agreement In 2011 the Company signed a re-rating agreement with TANESCO, TPDC and Songas (the “Re-Rating Agreement”) which evidenced an increase to the gas processing capacity of the Songas facilities 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 paid additional compensation of US$0.30/ mcf for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd by issuing credit notes to TANESCO. This was in addition to the tariff of US$0.59/mcf payable to Songas as set by the energy regulator, EWURA. In May 2016 the Company notified TANESCO and Songas that the additional compensation would no longer be paid effective June 2016. This additional compensation was always intended to be temporary in nature until such time as Songas applied to EWURA to obtain approval of a new tariff for the processing of volumes over 70 MMcfd. The PGSA provides for passing on to TANESCO any tariff to be charged to the Company. The parties are seeking to resolve the status of the re-rating agreement. The processing capacity at the Songas facilities remain unaltered and are fully utilized by the company. Without a new agreement, there are no assurances that Songas will continue to allow the gas plant to operate above 70 MMcfd. 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$15.0 million, but only to the extent that this was not already covered by indemnities from TANESCO’s or Songas’ insurance policies. notes 72 Portfolio Gas Supply Agreement ("PGSA") On June 17, 2011, a long term PGSA was signed (to June 2023) between TANESCO (as the buyer) and the Company and TPDC (collectively as the seller). 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 basic wellhead price of approximately US$2.93/mcf increased to US$2.98/mcf on July 1, 2015. 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 November 1, 2015 and expires on October 31, 2019 at an annual rent of US$0.4 million. The agreement in Winchester expires on September 25, 2022 and is at an annual rental of US$0.1 million per annum. The costs of these leases are recognized in the general and administrative expenses. Capital Commitments Italy The Company has an agreement to farm in on the 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 fifteen per cent (15%) of the back costs in relation to the well up to a maximum of US$0.5 million. Changes in Italian environmental legislation in late 2015 has resulted in the development of this permit being postponed indefinitely. As at the date of this report, the Company has no further capital commitments in Italy. Tanzania There are no contractual commitments for exploration or development drilling or other field development either in the PSA or otherwise agreed which would give rise to significant capital expenditure at Songo Songo. Any significant additional capital expenditure in Tanzania is discretionary. Given the completion of the Offshore component of Phase I of the Development Programme in February 2016, which has restored field deliverability and provides sufficient natural gas production to fill the Songas plant and pipeline to capacity for the greater portion of the remaining life of the production licence, the Company does not expect to commit to further significant capital expenditures until: (i) agreeing commercial terms with TPDC for the supply of gas to the NNGIP regarding the sale of incremental gas volumes from Songo Songo; and/or (ii) TANESCO arrears have been substantially reduced, guaranteed or other arrangements for payment made which are satisfactory to the Company; and/or (iii) the establishment of payment guarantees with the World Bank or other multi-lateral lending agencies to secure future receipts under any new sales contracts with Government entities. When conditions are deemed appropriate and there is justification to further improve the reliability/capacity of field deliverability, the Company would contemplate undertaking the remaining part or all of the Phase I Development Programme. The additional costs are estimated to be approximately US$30 million. There is no assurance that financing will be available and on acceptable commercial terms to complete Phase I. At the date of this report, the Company has no significant outstanding contractual commitments, and has no outstanding orders for long lead items related to any capital programmes. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements73 20 CONTINGENCIES Downstream unbundling The Petroleum Act, 2015 (the “Act”) was passed into Law by Presidential decree on August 4, 2015. In relation to the unbundling of the downstream business, the Act vests TPDC with exclusive rights in the distribution of gas, however, the Act has a provision which recognizes the Company’s PSA within the legislation. The Act does provide grandfathering provisions upholding the rights of the Company under their PSA as it was signed prior to passing of the Act. However, it is still unclear how the provisions of the Act will be interpreted and implemented regarding upstream and downstream activities and the Company is uncertain regarding the potential impact on its business in Tanzania. On October 7, 2016, the Government of Tanzania issued the Petroleum (Natural Gas Pricing) Regulation made under Sections 165 and 258 (I) of the Petroleum Act 2015. Article 260 (3) of the Act preserves the Company’s pre-existing right with TPDC to market and sell Additional Gas together or independently on terms and conditions (including prices) negotiated with third party Natural Gas customers. The impact of the Natural Gas Pricing Regulation, if any, cannot be determined at this time. 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 working 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. For the purpose of the reserves certification as at December 31, 2016, it was assumed that TPDC will elect to ‘back-in’ for 20% for all future new drilling activities within the prescribed period as determined by the current development plan and this is reflected in the Company’s net reserve position. Cost recovery 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. In 2014 TPDC and the Company agreed to remove US$1.0 million from the Cost Pool. In 2015 and 2016 there were no further developments. Under the dispute mechanism outlined in the PSA, TPDC are to appoint an independent specialist to assist the parties in reaching agreement on costs that are still subject to dispute, as at the time of writing this report no such specialist has been appointed. If the matter is not resolved to the Company’s satisfaction, the Company intends to proceed to arbitration via the International Centre for Settlement of Investment Disputes (“ICSID”) pursuant to the terms of the PSA. Taxation Area PAYE Tax dispute Period Reason for dispute 2008-10 Pay-As-You-Earn (“PAYE”) on grossed-up amounts in staff salaries which are contractually stated as net. WHT 2005-10 WHT on services performed outside of Tanzania by non-resident persons. Disputed amounts US$ million Principal Interest Total 0.3 1.1 – 0.3 (1) 0.7 1.8 (2) Income Tax 2008-15 Deductibility of capital expenditures and expenses 16.8 10.1 26.9 (3) (2009 and 2012), additional income tax (2008, 2010, 2011 and 2012), tax on repatriated income (2012), foreign exchange rate application (2013 and 2015) and underestimation of tax due (2014). VAT 2008-10 Output VAT on imported services 2.7 2.9 5.6 (4) and SSI Operatorship services. 20.9 13.7 34.6 notes74 (1) In 2015 PAET appealed the Tax Revenue Appeals Board (“TRAB”) ruling that PAET is liable to pay PAYE on grossed-up amounts in staff salaries. TRAB waived interest assessed thereon. PAET is awaiting ruling of the Tax Revenue Appeals Tribunal (“TRAT”); (2) (a) 2005-2009 (US$1.7 million): In 2016 TRA filed an application for review of the Court of Appeal decision in favour of PAET and later filed another application for leave to amend its earlier application. At the Court of Appeal hearing subsequent to year-end, TRA withdrew their second application for review. The Court has set April 27, 2017 for hearing of the first application; (b) 2010 (US$0.1 million): TRAB is awaiting a ruling from the review by the Court of Appeal on the 2005-2009 case, which would influence TRAB decision on this matter accordingly; (3) (a) 2009 (US$1.8 million): In 2015 TRAB ruled against PAET with respect to the deductibility of capital expenditures and other expenses. PAET appealed to TRAT and is awaiting a hearing date to be scheduled; (b) 2008 and 2011 (US$2.1 million): In 2015 PAET filed objections against TRA assessments with respect to the deductibility of capital expenditures and other expenses as well as underestimation of interest and is awaiting a response. Subsequent to year-end, TRA rejected PAET’s objections for 2011 and undertook to issue a final assessment for the year. PAET intends to appeal the assessment. The 2008 assessment was issued late and is time-barred; (c) 2010 (US$2.6 million): PAET filed an appeal with TRAB against TRA assessment with respect to the deductibility of capital expenditures and other expenses as well as underestimation of interest and penalty amounts. PAET is awaiting a hearing date to be scheduled; (d) 2013 (US$0.2 million): During the year PAET filed objections to TRA assessment with respect to foreign exchange rate application and is awaiting a response; (e) 2012 (US$16.3 million): During the year TRA issued two assessments with respect to understated revenue, deductibility of capital expenditures and expenses, and tax on repatriated income. PAET filed an appeal with TRAB against the TRA decision to deny PAET a waiver required for its objection to be admitted and is awaiting a hearing date to be scheduled; (f) 2014 (US$3.5 million): During the year TRA issued an assessment with respect to underestimation of tax due based on the provisional quarterly payments made by PAET, delayed filings of returns and late payments. PAET filed objections to the assessments and is awaiting a response; (g) 2015 (US$0.4 million): During the year TRA issued a self-assessment. PAET filed an objection to the assessment with respect to foreign exchange rate application and is awaiting a response; (4) During the year TRA responded to PAET’s objection filed in 2014 and issued an assessment in respect of output VAT on imported services and SSI Operatorship services. PAET filed an appeal with TRAB against TRA assessment and is awaiting a hearing date to be scheduled. (5) On March 29, 2017, management received a tax audit findings report from TRA for the years 2012-14. The report requests the Company to elaborate on the corporation tax, repatriated income, VAT and withholding tax. Management is preparing its response and expects to submit it to TRA before the deadline of April 19, 2017. Management, with the advice from its legal counsels, has reviewed the Company’s position on the above objections and appeals and has concluded that no provision is required with regard to the above matters. 21 DIRECTORS AND OFFICERS COMPENSATION US$’000 Directors Directors Officers Officers Year Base Bonus 2016 2015 2016 2015 1,277 1,100 900 1,469 – 500 280 345 Stock based compensation expense 1,744 1,676 348 43 Total 3,021 3,276 1,528 1,857 The table above provides information on compensation relating to the Company’s officers and directors. Three officers and four non-executive directors comprised the key management personnel during the year ended December 31, 2016 (2015: five officers and three non-executive directors). One of the officers is also a director and as such their remuneration has been included under directors’ emoluments in the table above. ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements Corporate Information Board of Directors W. David Lyons Chairman and Chief Executive Officer David W. Ross Non-Executive Director 75 c o r p o r a t e i n f o r m a t i o n William H. Smith Non-Executive Director Calgary, Alberta Canada E. Alan Knowles Non-Executive Director Calgary, Alberta Canada Glenn D. Gradeen Non-Executive Director Calgary, Alberta Canada Calgary, Alberta Canada Queensway Gibraltar Officers W. David Lyons Chairman and Chief Executive Officer Queensway Gibraltar Operating Office PanAfrican Energy Tanzania Limited Oyster Plaza Building, 5th Floor Haile Selassie Road P.O. Box 80139, Dar es Salaam Tanzania Tel: + 255 22 2138737 Fax: + 255 22 2138938 International Subsidiaries Blaine Karst Chief Financial Officer Calgary, Alberta Canada David K. Roberts Vice President of Operations Kansas City, Missouri United States of America Registered Office Investor Relations Orca Exploration Group Inc. P.O. Box 146 Road Town Tortola British Virgin Islands, VG110 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, 5th 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 Orca Exploration Italy Inc. Orca Exploration Italy Onshore Inc. P.O. Box 3152, Road Town Tortola British Virgin Islands Engineering Consultants Auditors Website McDaniel & Associates Consultants Ltd. Calgary, Canada KPMG LLP Calgary, Canada orcaexploration.com Lawyers Transfer Agent Burnet, Duckworth & Palmer LLP Calgary, Canada CST Trust Company Calgary, Alberta, Canada www.orcaexploration.com ORCA EXPLORATION GROUP INC.

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