PETRONEFT RESOURCES PLC ANNUAL REPORT 2013 Годовой Отчет 2013 P e t r o N e f t R e s o u r c e s p l c A n n u a l R e p o r t 2 0 1 3 REVIEW OF THE YEAR 01-19 01 Highlights 02 Producing Oil from a Solid Asset Base 04 Licence 61 08 Licence 67 10 Chairman’s Statement 12 Chief Executive Officer’s Report 16 Financial Review 18 Principal Risks and Uncertainties 19 Health, Safety and Environmental Report GOVERNANCE 20-26 20 Board of Directors 22 Directors’ Report 26 Independent Auditor’s Report FINANCIAL STATEMENTS 27-64 27 Consolidated Income Statement Consolidated Statement 27 of Comprehensive Income 28 Consolidated Balance Sheet 29 Consolidated Statement of Changes in Equity 30 Consolidated Cash Flow Statement 31 Company Balance Sheet 32 Company Statement of Changes in Equity 33 Company Cash Flow Statement 34 Notes to the Financial Statements 63 Notice of Annual General Meeting 64 Glossary IBC Group Information Forward Looking Statements This report contains forward-looking statements. These statements relate to the Group’s future prospects, developments and business strategies. Forward-looking statements are identified by their use of terms and phrases such as ‘believe’, ‘could’, ‘envisage’, ‘potential’, ‘estimate’, ‘expect’, ‘may’, ‘will’ or the negative of those, variations or comparable expressions, including references to assumptions. The forward-looking statements in this report are based on current expectations and are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by those statements. These forward- looking statements speak only as at the date of these financial statements. 01 PETRONEFT RESOURCES PLC IS AN INTERNATIONAL OIL AND GAS EXPLORATION AND PRODUCTION COMPANY, FOCUSED ON RUSSIA. THE COMPANY’S SHARES ARE LISTED ON THE LONDON AIM AND DUBLIN ESM MARKETS. HIGHLIGHTS OPERATIONAL HIGHLIGHTS 50% 50% Farmout of Licence 61 agreed with Oil India. 3 Three new wells drilled at Arbuzovskoye. 2,386 bopd Average production. 130 mmbbls Group 2P reserves prior to Licence 61 Farmout. Comprehensive Seismic and Well reinterpretation on Licence 61 shows additional potential at Tungolskoye, Sibkrayevskoye, Emtorskaya, and Traverskaya. See Chief Executive Officer’s Report on pages 12 to 15 FINANCIAL HIGHLIGHTS US$85m Total investment by Oil India will be up to US$85 million after completion of Licence 61 Farmout. US$38.7m Revenue US$38.7 million. US$5.1m Gross Profit US$5.1 million. US$6.5m Debt to Macquarie reduced by US$6.5 million. US$6.7m Fundraising of US$6.7 million completed in March 2014. For more information on finances, see the Financial Review on pages 16 and 17 PetroNeft Resources plc: Annual Report 2013GovernanceFinancial StatementsReview of the Year 02 PRODUCING OIL FROM A SOLID ASSET BASE OUR ASSETS The main assets of the Company are a 50%* operating interest in a 4,991 km2 oil and gas licence (Licence 61) in the Tomsk Oblast in Russia and a 50% operating interest in a 2,447 km2 oil and gas licence (Licence 67) also located in the Tomsk Oblast. Both licences are located in the prolific Western Siberian Oil and Gas Basin. *Following completion of the Licence 61 Farmout. TOMSK OBLAST Licence 61 Licence 67 RUSSIA Moscow Tomsk 1,000 km Scale 0 Key: PetroNeft Rosneft Gazprom Gazpromneft ONGC (Imperial Energy) Other Oil Pipeline Gas Pipeline All-weather Road Tomsk Scale 0 100 km HISTORY AND BUSINESS STRATEGY The Group has its origins in PetroNeft LLC, a Texas-based company, which was established in 2003 as an oil and gas investment and consultancy company focused principally on the Russian market. In May 2005, PetroNeft LLC acquired a Russian company, Stimul-T, which had acquired a 100% interest in Licence 61 following a competitive auction process in the November 2004 Tomsk Licence Auction. PetroNeft Resources plc was incorporated on 15 September 2005 and was admitted to the London AIM and Dublin ESM Markets in September 2006. The Group’s strategy is to develop an oil exploration, development and production business in Russia, using the combined skills, experience and resources of the Group’s Directors and employees. In the short-term this is to be achieved through a focus on growth of production and cash flows at Licence 61 and a rigorous appraisal and exploration programme on Licences 61 and 67, by seeking to bring the existing discoveries into production as rapidly as possible and by exploiting the additional opportunities already identified and summarised in the Ryder Scott Report. In addition to operations on Licences 61 and 67, the Company continues to evaluate new projects for acquisition. In April 2014 PetroNeft signed a Farmout deal with Oil India Limited to farmout a 50% non-operating interest in Licence 61. PetroNeft remains the operator of Licence 61. PetroNeft Resources plc: Annual Report 2013 03 Scale 0 12 km LICENCE 61 Licence 61 contains seven known oil fields: Lineynoye, Arbuzovskoye, Tungolskoye, Sibkrayevskoye, West Lineynoye, Kondrashevskoye and North Varyakhskoye and over 25 exploration prospects and leads. More information see page 4 LICENCE 67 Licence 67 contains the Cheremshanskoye and Ledovoye oil fields and numerous prospects and leads. More information see page 8 Scale 0 20 km PetroNeft Resources plc: Annual Report 2013GovernanceFinancial StatementsReview of the Year 04 LICENCE 61 As well as seven discovered oil fields in Licence 61 there are over 25 additional prospects and leads to be explored. 21 20 9 8 1 5 7 19 22 23 10 3 4 6 11 12 13 2 14 15 18 16 17 24 Scale 0 12 km Separator units at Lineynoye CPF. 7 Oil Fields 01 Lineynoye oil field 02 Tungolskoye oil field 03 West Lineynoye oil field 05 Kondrashevskoye oil field 07 Arbuzovskoye oil field 08 North Varyakhskoye 20 Sibkrayevskoye Tungolskoye West Lobe and North (2) West Korchegskaya (Lower Jurassic) 23 Prospects 02 04 Lineynoye Lower 06 08 Upper Varyakhskaya 09 Emtorskaya East 10 Emtorskaya Crown 11 Sigayevskaya 12 Sigayevskaya East 13 Kulikovskaya Group (2) 14 Kusinskiy Group (2) 15 Tuganskaya Group (3) 16 Kirillovskaya (4) 17 North Balkinskaya 18 Traverskaya 19 Tungolskoye East 4 Potential Prospects/Leads 21 Emtorskaya North 22 Sibkrayevskaya East 23 Sobachya 24 West Balkinskaya Oil field Prospect ready for drilling Prospect identified Potential prospects Pipeline Structure Map on Base Bazhenov Horizon PetroNeft Resources plc: Annual Report 2013 05 ABOUT OIL INDIA LIMITED Oil India Limited (BSE: 533106, NSE: OIL) is one of the largest national oil and gas companies in India as measured by total proved plus probable oil and natural gas reserves and production. It is engaged in the business of exploration for oil and gas, production of crude oil, natural gas and LPG and transportation of crude oil, natural gas and petroleum products. OIL has over 50 E&P blocks in India and an International presence spanning Egypt, Gabon, Libya, Mozambique, Nigeria, USA, Venezuela and Yemen. For further detail please refer to www.oil-india.com. LICENCE 61 FARMOUT Farmout of a 50% non-operating interest to Oil India Limited. In April 2014 PetroNeft signed a deal with Oil India Limited (‘OIL’ or ‘Oil India’) to farmout a 50% non-operating interest in Licence 61. In addition, through the shareholders agreement, both parties will have joint control of WorldAce with PetroNeft continuing as operator (the ‘Licence 61 Farmout’). The basic terms of this agreement are summarised as follows: • Total investment by OIL of up to US$85 million consisting of: – US$35 million upfront cash payment; – US$45 million of exploration and development expenditure on Licence 61; – US$5 million performance bonus, contingent upon average production from the Sibkrayevskoye Field reaching 7,500 bopd within the next five years. • PetroNeft to remain operator of Licence 61, but OIL will have the right to second certain technical experts into PetroNeft’s Tomsk team. Under the terms of the agreement, OIL will subscribe for shares in WorldAce, the holding company for Stimul-T, the entity which holds Licence 61 and all related assets and liabilities; following which, PetroNeft and Oil India Limited will both hold 50% of the voting shares of WorldAce. OIL also has the right to become the Operator of the Licence should there be a substantial change in the management team of PetroNeft within the first three years. On completion OIL will be able to book 50% of production and reserves from Licence 61. POST COMPLETION ACTIVITIES Up to five additional production wells will be drilled at Arbuzovskoye and delineation wells will be drilled at Tungolskoye (T-5) and Sibkrayevskoye (S-373), where significant upside potential and near-term developments are possible. The Tungolskoye No. 5 well will be the first horizontal well drilled on Licence 61. There are also plans in place to acquire additional 2D seismic across the large Sibkrayevskoye oil field and Emtorskaya prospect commencing later in 2014. In 2015 it is likely that the Tungolskoye oil field will be brought into production. It is expected that drilling will recommence in July 2014. ARBUZOVSKOYE OIL FIELD DEVELOPMENT Development has been revised based on drilling results. • Pilot production commenced in Jan 2012 with Well A-1 brought online at >300 bopd. • Six wells drilled and brought onstream winter 2012/13. All wells were completed with ESP’s and had Initial production of ≥100 bopd. • Water cut less than 2%. • Water injection started with conversion of A-112 well in April 2013 – now seeing start of production response in well 102. • Plans for up to five additional wells to be drilled on Pad 1 during 2014. • Future Well 9s strategically located to maximise information gathering for Pad 2 well locations. • Horizontal wells will be considered for the development of the southern portion of the field based on reservoir geometry and shape of the structure. Arbuzovskoye 109 • IP 100 bopd on ESP • Less than 2% water Arbuzovskoye 101 • IP 300 bopd on ESP • Less than 2% water 102 112 109 101 Pad 1 A-1 111 105 Arbuzovskoye 102 • IP 540 bopd on ESP • Less than 2% water Arbuzovskoye 112 • IP 140 bopd on ESP • Water injector Arbuzovskoye 111 • IP 150 bopd on ESP • Less than 2% water 9S Arbuzovskoye 105 • IP 160 bopd on ESP • Less than 2% water Pad 2 Base Bazhenov Seismic Horizon Contour Interval 10 m November 2012 Scale 0 3 km PetroNeft Resources plc: Annual Report 2013GovernanceFinancial StatementsReview of the Year Arbuzovskoye Oil Field • Tie-in to Lineynoye Facilities • Oil in J1-1 Sandstone only • Reserves estimated ± 7 million bbls 06 TUNGOLSKOYE APPRAISAL Significant appraisal work prior to development. 2012/2013 PROGRAMME: • TGK re-processing and re-evaluation of well and seismic data. • Significant portion of structure is updip from T-1 and T-4 wells which had over 10 m net pay. 2014 PROGRAMME: • Q1 mobilize rig for T-5 well. • Drill, core and test T-5 vertical segment. • Drill horizontal segment, complete and test. • Russian State Reserve (GKZ) approval. • Pilot Production Project (CDC) approval. RISK MITIGATION • Confirm structure and reservoir with T-5 well. • Confirm flow test in 300 m horizontal segment. • Potential for horizontal wells to greatly reduce the cost and time required for development. Lineynoye Oil Field Facilities • Central Process Facilities • Oil Storage • Export Pipeline Connection Tungolskoye Oil Field • Facilities same as Arbuzovskoye • 26 km Utility Line to Lineynoye • 26 km Pipeline (dia. 273 mm) • Oil in J1-1 and J1-2 Sandstones • Reserves estimated ± 20 million bbls T-2 e y o n y e n L o t e n i i i l e p P m k 6 2 e n i i l e p p t r o p x e m k 0 6 Scale 0 T-4 5 km T-5 T-1 TUNGOLSKOYE DEVELOPMENT Expected on-stream 2015. POTENTIAL 2015 PROGRAMME: • Construction of 26 km pipeline from Lineynoye Central Processing Facility – Q1. • Construction of Pad 1 and mobilisation of development drilling rig and supplies – Q1. • Commence drilling from Pad 1 – Q2. • First development using horizontal wells. TUNGOLSKOYE DEVELOPMENT • 7 horizontal wells (6 + T-5). • 8 vertical wells (convert to injectors). • 2 drilling pads. • 1,000 m horizontal segments. Well types net pay for Pad 1 >12.0 metres >12.0 metres 4H + 0V wells 1H + 1V wells 1H + 5V wells 6H + 6V wells >7.5 metres =Total Base Bazhenov Seismic Horizon – 2013 PetroNeft Resources plc: Annual Report 2013 SIBKRAYEVSKOYE OIL FIELD OVERVIEW Major discovery – expected on-stream 2016. 07 THREE WELLS WERE DRILLED ON THE FIELD TO DATE • Well 372 (2011) twinned well 370 was drilled by PetroNeft. • Well confirmed 12.3 m of ‘missed pay’. • Open hole inflow test 170 bopd, 37° API. • Over 50 km2 of closure above oil-down-to level in well 372. • RS 2P reserves 53 million bbls. • Additional seismic and well data will be required to fully assess the discovery and register reserves for development. PETRONEFT IS PLANNING: • Well 373 with rig currently on location and additional 2D Seismic acquisition for 2014/15. • Development decision in 2015. • Will be tied back to Lineynoye CPF. • Water injection for pressure maintenance. EMTORSKAYA HIGH Significant exploration upside. Structure Map on Base Bazhenov Horizon Contour Interval 10 m March 2012 Scale 0 6 km Emtorskaya 300 – Reinterpretation • J1 • J1 1 – 1.0 m oil 2 – 5.0 m potential oil Structure Map on Base Bazhenov Horizon Contour Interval 10 m November 2012 Scale 0 12 km Emtorskaya 304 – Proposed 1 • Crestal high -2,315 m J1 • 65 m high to Lineynoye Crest Emtorskaya 303 – Reinterpretation • J1 • J1 1 – 1.9 m oil 2 – 3.2 m potential oil Likely Field Extension to the North • Pad 1 & Pad 2 drilling results • Revised Structure Map • Lower oil-water-contact • Well 212 oil-down-to -2,434 m J1 • Well 211 owc -2,436 m J1 2 1 PetroNeft Resources plc: Annual Report 2013GovernanceFinancial StatementsReview of the Year 08 LICENCE 67 3D Seismic programme is the next step. Exploration drilling rig at Ledovoye. 15 2 Ledovoye Oil Field 6 7 5 9 8 10 1 Cheremshanskoye Oil Field 14 Drilled Structures 01 Cheremshanskoye oil field 02 Ledovoye oil field 03 Sklonovaya 04 North Pionerskaya 05 Bolotninskaya Identified Prospects and Leads 06 Levo-Ilyakskaya 07 Syglynigaiskaya 08 Grushevaya 09 Grushevaya Stratigraphic trap 10 Malostolbovaya 11 Nizhenolomovaya Terrasa Gp. 11 13 4 3 12 Scale 0 10 km 12 Baikalskaya 13 Malocheremshanskaya 14 East Chermshanskaya 15 East Ledovoye Drilled Structure with oil show or test Drilled Structure with no oil shows reported Undrilled Structure or Stratigraphic Trap Excluded area with producing oil fields In 2011/2012 two wells were drilled, one at the Cheremshanskaya prospect and a second at the Ledovoye oil field. These wells resulted in the discovery of a new oil field at Cheremshanskoye (December 2011) and the confirmation of the Upper Jurassic J1-3 oil pool at Ledovoye field with a potential new oil pool discovery in the lower Cretaceous (February 2012). Cheremshanskoye The Cheremshanskaya No. 3 well discovered three separate oil pools and established the Cheremshanskoye oil field. These intervals were the J14, the J1-3 and the J1-1 + Bazhenov and there were successful flow tests from each interval. The area of the field is very large encompassing almost 40 km2 and further delineation and pilot testing will be required to assess the true size of the field and ultimate development plan. There are large producing fields nearby with similar characteristics and the strong indications are that Cheremshanskoye will prove to be a substantial discovery upon further delineation. Ledovoye The Ledovaya No. 2a well was spudded in December 2011 in order to target oil in both the Lower Cretaceous and Upper Jurassic intervals with oil discovered in both zones. The well achieved stabilised natural oil flow of 52 bopd from the Upper Jurassic interval and the core and log data also indicate that the well has discovered a new oil pool in the secondary objective Lower Cretaceous interval containing 4.5m of potential oil pay. The Lower Cretaceous zone will eventually need to be flow tested behind casing for confirmation. We are pleased with the result given that the same interval is productive at the neighbouring Stolbovoye field which is located 24 km to the south of Ledovoye. 2014 3D Seismic In the first half of 2014 PITC Geophysical Company acquired 156 km2 of 3D seismic data across the Ledovoye and Cheremshanskoye oil fields. The data is currently being processed and interpreted and will be available in the second half of 2014. Once the interpretation is complete we will review with our partner Arawak and assess the next steps. PetroNeft Resources plc: Annual Report 2013 OUR RESERVES 2P RESERVES Licences 61 and 67 • 2P reserves are as estimated by Ryder Scott, Petroleum Consultants, each year and conform to the definitions approved by the Society of Petroleum Engineers (‘SPE’) Petroleum Resources Management System (‘PRMS’) rules. • Ryder Scott reserves for Licence 61 were updated as at 1 April 2013, as adjusted for production to the end of December 2013. • As a result of the Licence 61 Farmout 2P reserves will be reduced by 58.22 mmbbls to 72.23 mmbbls. 130m 130 million barrels of 2P reserves 09 131.70 14.02 1.93 49.83 131.07 14.02 1.95 53.03 130.45 14.02 1.95 53.03 13.29 4.96 32.10 6.54 4.98 23.68 6.35 4.98 23.67 Million barrels 140 120 100 80 60 40 20 Ledovoye North Varyakhskoye Sibkrayevskoye Arbuzovskoye Kondrashevskoye West Lineynoye Lineynoye Tungolskoye 27.89 9.34 18.55 33.54 15.61 17.92 96.93 14.02 13.24 8.12 23.32 70.00 8.11 23.30 23.82 22.74 60.62 28.82 16.32 15.49 14.77 15.48 15.57 7.13 19.74 6.71 19.74 0 2005 2006 2007 2008/09 2010 2011 2012 2013 3P RESERVES AND EXPLORATION RESOURCES (P4) Licences 61 and 67 • 3P reserves are as estimated by Ryder Scott, Petroleum Consultants, and conform to the definitions approved by the Society of Petroleum Engineers (‘SPE’) Petroleum Resources Management System (‘PRMS’) rules. • All Exploration Resources (P4) are based on structures with unequivocal four-way dip closure at the reservoir horizon as identified by 2D seismic data. • As a result of the Licence 61 Farmout 3P reserves and Exploration Resources will be reduced by 271.77 mmbbls to 368.92 mmbbls. Million barrels 700 600 500 400 300 200 100 324.21 350.00 183.62 640.69 156.17 100.41 384.11 531.3 156.17 63.06 312.07 0 2005 2006 2007 2008/09 2010-13 Cretaceous Middle/Lower Jurassic Upper Jurassic PetroNeft Resources plc: Annual Report 2013GovernanceFinancial StatementsReview of the Year 10 CHAIRMAN’S STATEMENT The Licence 61 Farmout materially strengthens PetroNeft both financially and strategically. We believe the transformation we will undergo as a result of the Licence 61 Farmout will be for the benefit of the shareholders in the Company as a whole. David Golder Non-Executive Chairman A Turn-around Year 2013 was a turn-around year for our Company. The overriding strategy of the Board was to solve both the short-term funding constraints and to secure the long-term investment requirements necessary to develop the full potential of Licence 61. In December 2013, we signed a Memorandum of Understanding with Oil India Limited (‘OIL’ or ‘Oil India’) which defined the terms for a farmout deal that would accomplish both our short-term and long-term goals. The final documentation for this deal was then finalised on 17 April 2014 and the deal is expected to close imminently. The total investment by OIL will be up to US$85 million. The Licence 61 Farmout is defined and further details are provided in the Chief Executive Officer’s report. The Licence 61 Farmout materially strengthens PetroNeft both financially and strategically. We believe the transformation we will undergo as a result of the Licence 61 Farmout will be for the benefit of the shareholders in the Company as a whole. The Company will be debt-free and the jointly controlled entity will have a fully funded US$45 million work programme. The Licence 61 Farmout gives us a strong industry partner seeking to build a strategic position in Russia as well as the financial resources to develop the significant potential of Licence 61. The Licence 61 Farmout and strategy of the Board were supported overwhelmingly by shareholders at two Extraordinary General Meetings of the Company held in Dublin on 9 May 2014. Operations The Pad 1 wells at Lineynoye have performed well during 2013 and early 2014. They have responded positively to the pressure maintenance programme we initiated in June 2011 as well as efforts from our Tomsk team to keep wells on line and to intervene where necessary to optimise production. The Arbuzovskoye field was brought into production through the pipeline to Lineynoye in May 2012. We have also had good success in maintaining production and slowing the production decline here by the timely workover of wells to replace pumps and re-perforate where possible despite the last production well being drilled in February 2013. The specific geological and operations expertise we gained from Lineynoye and Arbuzovskoye will serve the Company well in the future developments at Tungolskoye and Sibkrayevskoye. This programme builds on the innovative work that has been done both to move forward with the development at Arbuzovskoye as well as understanding the production issues at Lineynoye Pad 2 and how to avoid similar issues in the future. The first well drilled in the 2014 programme will be Tungolskoye No. 5 which will be the first horizontal well drilled by the Company. This is an exciting well with significant production potential and we look forward to the results, which we expect to be available in the third quarter of 2014. PetroNeft Resources plc: Annual Report 2013 Summary On 9 May 2014, the shareholders overwhelmingly supported the Board’s proposed strategy for the next phase of the Company’s development. This gave us a mandate to conclude the Licence 61 Farmout with Oil India and to progress the development of Licence 61, debt-free and with a fully funded US$45 million work programme. With the Lineynoye, Arbuzovskoye, Tungolskoye and Sibkrayevskoye oil fields we can generate significant cash in the coming years utilising the infrastructure already in place as well as through the addition of yet to be discovered reserves from our portfolio of exploration prospects. Oil India appreciates the potential of the asset and has a long-term view with respect to Licence 61 and business development in Russia. This should enable PetroNeft to expand its oil reserve base both through exploration and delineation in current licence areas and through business development opportunities in Tomsk and further afield in Russia. We look forward to working with Oil India in the future. PetroNeft is fortunate to have a highly experienced and dedicated team whose knowledge and experience have enabled us to meet the array of challenges facing the Group in recent years. I am confident that this team will enable PetroNeft to provide shareholders with better returns in the future. While 2013 was a challenging year operationally and in the overall financial markets, shareholders should not lose sight of our strong Proved and Probable reserve base. Many lessons have been learned and, along with the results of new technical studies, we have further improved our knowledge and understanding of our extensive licence acreage. We are producing from less than 15% of our reserve base and the substantial investment in infrastructure made in recent years leaves us well placed to deliver significant and profitable growth now that we have satisfactorily addressed the funding challenges that we have been facing for the last couple of years. Finally, I know that I speak for all the Directors, management and staff of the Group in giving sincere thanks to our shareholders, both old and new, for your continued support throughout the past year. David Golder Non-Executive Chairman Reserves Independent reserve auditor Ryder Scott has completed an assessment of PetroNeft’s petroleum reserves and resources on Licence 61 as at 1 April 2013. Total Proved and Probable (‘2P’) reserves were estimated at 117 million barrels, essentially unchanged from the previous assessment. Ryder Scott has not prepared a new report for the Licence this year as the only new well drilled since the last report was Lineynoye No. 9 and we still need to conduct a cased hole test on this well; however, we do not see a significant reserve adjustment associated with this well. If we adjust these reserves for production to the end of 2013 the Licence 61 2P reserves are estimated at 116.4 million barrels. While the Licence 61 Farmout results in a reduction of the 2P reserves net to PetroNeft, the Company has had good exploration success in the past and I am confident that we can bring the Company’s reserves back towards pre-farmout levels in the medium term with further appraisal and exploration wells on key fields and prospects, especially Sibkrayevskoye, Emtorskaya and Traverskaya. At Licence 67 we acquired 156 km2 of 3D seismic data this past winter to better define the three oil pools discovered at Cheremshanskoye and the two oil pools at Ledovoye. This data is currently being processed and interpreted with results expected later in 2014. Finance In March 2014 we secured additional funding of US$6.7 million including US$5.2 million new equity and US$1.5 million in additional debt under the Arawak loan as detailed in the Financial Review. The proceeds of the placing and debt were largely used to purchase and mobilise supplies and equipment to the field to enable a full programme of works in 2014 following the Licence 61 Farmout. This needed to be completed while winter roads were still available in March. The proceeds were also used to pay Macquarie Bank Limited (‘Macquarie’) US$2.5 million and for working capital purposes. Business Development The principal near-term objective of the Group is the development of the Northern oil fields on Licence 61, leveraging the infrastructure put in place in recent years, together with our new partner Oil India. However, we have not lost sight of Licence 67 and our longer-term objective of securing assets outside our current licences to provide growth for the future. Corporate Development In recent years we have transitioned from an exploration company to an exploration and production company. The management structure in Tomsk has been revised over the past couple of years with most new positions being filled by excellent candidates from within our own organisation. We are operating the new Arbuzovskoye oil field without having expanded our workforce. The Group headcount now stands at 163 employees. I would like to thank all of our employees for their extraordinary dedication and hard work in 2013. 11 Accommodation block at Lineynoye crew camp. Well heads at Lineynoye. I WOULD LIKE TO THANK ALL OF OUR EMPLOYEES FOR THEIR EXTRAORDINARY DEDICATION AND HARD WORK IN 2013. PetroNeft Resources plc: Annual Report 2013GovernanceFinancial StatementsReview of the Year 12 CHIEF EXECUTIVE OFFICER’S REPORT We are very pleased to have signed an agreement with Oil India for the Licence 61 Farmout, and to have Shareholders’ endorsement of the Licence 61 Farmout. The Company will now be debt-free with significant funding available to develop the significant potential in Licence 61 alongside a great new partner. Dennis Francis Chief Executive Officer General 2013 was a very active year in respect of the efforts to find a solution to the funding constraints on the Company. It was a quiet year from the point of view of drilling new wells due to those financial constraints imposed by the commencement of monthly repayments to Macquarie in March 2013. Production was relatively stable during the year and it enabled us to make significant repayments to Macquarie during this time. The work to find a solution to the Company’s funding requirements came to fruition with the announcement of the Licence 61 Farmout to Oil India Limited in April 2014. This significantly strengthens PetroNeft financially and will provide a much-needed source of funding for future developments. We produced 870,965 barrels of oil (2012: 806,761 barrels) in the year or an average of 2,386 bopd (2012: 2,204 bopd). At Licence 67 we have completed the acquisition of a 156 km2 3D seismic survey over two fields and this licence shows promise for the future. Licence 61 Highlights • Licence 61 Farmout to Oil India Limited. • Work-overs and water injection managed to maintain production above normal decline rates. • Obligation well at Lineynoye No. 9 drilled under deferred payment scheme. Licence 67 Highlights • 3D seismic survey over Cheremshanskoye and Ledovoye oil fields. • New Law on Mineral Extraction Tax (‘MET’) relief for Tight Oil likely applicable. Licence 61 (Tungolsky) Licence 61 Farmout to Oil India In order to continue the development and exploration of this large licence area, we needed to strengthen the Group’s financial position. In consultation with major shareholders and finance providers, we undertook two parallel paths to try and achieve this: re-financing our existing debt and farming out 50% of Licence 61. In regard to the farmout we contracted Evercore Partners, a London-based financial adviser and M&A specialist with proven experience in Russia and the FSU, to run a formal process to seek an industry partner to join in the development and exploration of the licence. We set up an extensive electronic data room and held detailed discussions with a number of potential partners. We also held discussions with a number of Russian and international banks with a view to re-financing the existing debt facilities. In total we contacted almost 60 companies regarding the Licence 61 Farmout and over 50 different financial institutions regarding re-financing of the Macquarie debt. Over 16 of these companies signed Confidentiality Agreements and had access to the data room and management presentations. The culmination of this process was the Licence 61 Farmout to Oil India Limited. The basic terms of this agreement are summarised as follows: PetroNeft Resources plc: Annual Report 2013 • Total investment by OIL of up to US$85 million consisting of: – US$35 million upfront cash payment; – US$45 million of exploration and development expenditure on Licence 61; – US$5 million performance bonus, contingent upon average production from the Sibkrayevskoye Field reaching 7,500 bopd within the next five years. • PetroNeft to remain operator of Licence 61, but OIL will have the right to second certain technical experts into PetroNeft’s Tomsk team. Under the terms of the agreement, OIL will subscribe for shares in WorldAce, the holding company for Stimul-T, the entity which holds Licence 61 and all related assets and liabilities; following which, PetroNeft and Oil India will both hold 50% of the voting shares of WorldAce. In addition, through the shareholders agreement, both parties will have joint control of WorldAce with PetroNeft continuing as operator (the ‘Licence 61 Farmout’). The Licence 61 Farmout will fully address PetroNeft’s capital structure and long-term investment requirements with all existing debt repaid in full and additional funds for working capital and significant investment directly in Licence 61. The Licence 61 Farmout gives PetroNeft a strong industry partner seeking to build a strategic position in Russia. It will also give us the financial resources to develop the significant potential of Licence 61 in the short term. The deal is subject to shareholder approval which was granted at EGMs in May 2014 and to the Russian Regulatory approval which is expected to be received imminently. An aggressive drilling and appraisal campaign has been agreed following the Licence 61 Farmout as follows: • Drill a delineation well at Tungolskoye (T-5). • Drill up to five additional production wells at Arbuzovskoye Pad 1. • Drill a delineation well at Sibkrayevskoye (S-373) where significant upside potential and near-term developments are possible. • Acquire high resolution 2D seismic data across Sibkrayevskoye, Emtorskaya, West Lineynoye and other leads and prospects in the northern part of Licence 61. Workover crew at work. Licence 61 – Lineynoye Development The wells at Pad 1 at Lineynoye have performed well during 2013 and early 2014 and have shown good response to the water injection and pressure maintenance programme. Our team in Tomsk, including our in-house workover crew, have worked well to keep wells online and to intervene where necessary to optimise well performance, replace pumps and in some cases carry out acid washes on both production and injection wells to improve or maintain production. As part of the full field development of the Lineynoye and West Lineynoye oil field, and in order to meet our government obligation to fully assess the potential of the field, we drilled the Lineynoye No. 9 delineation well on the western lobe of the Lineynoye field in 2013. This was done under an arrangement with our drilling contractor, LLC Tomskburneftegaz (‘TBNG’), wherein the cost of the drilling of the well will not be paid until after the Company completes its re-financing/farmout to the satisfaction of the Board. All other elements of the commercial agreement relating to this operation are consistent with prior turnkey drilling contracts between PetroNeft and TBNG. Personnel involved in emergency preparedness exercise. 13 Based on the log and core data in the L-9 well there is from 2 to 3 metres of oil pay in the J1-1 reservoir. The J1-1 results are consistent with our estimates for this portion of the field. We were pleased, however, to find that the J1-2 sandstone is thicker than expected (10+ metres), but it appears to be water bearing at this location. This reservoir could be oil saturated to the south where it is located higher on the structure. A cased hole test will be performed on the J1-1 interval later this year, but given the thin pay at this location the West Lineynoye development is not a high priority versus other developments such as Tungolskoye and Sibkrayevskoye where significant upside potential and near-term developments are possible. Both of these fields have in excess of 10 metres of net pay. Licence 61 – Arbuzovskoye Development Arbuzovskoye was brought into year-round production in 2012 following the construction of a 10 km pipeline and utility line from the Lineynoye Central Processing Facilities to Arbuzovskoye. The discovery well (Arbuzovskoye No. 1) commenced production through the pipeline in May 2012 at a rate of 350 bopd. Drilling of additional wells commenced in August 2012 and good results were achieved particularly from the 101 and 102 wells which achieved initial rates of 310 and 540 bopd respectively. The coring carried out at the 101 well indicated that the rock quality at Arbuzovskoye is better than that encountered at Lineynoye. This explains the good flow rates achieved despite the fact that no stimulation has yet been carried out at Arbuzovskoye. To date we have drilled a total of seven wells at Arbuzovskoye including the original discovery well. We had started to see some normal pressure decline in the field so we drilled a water source well in early 2013 and in April 2013 we converted one oil production well into a water injection well in order to arrest/ slow that decline as soon as possible. We also had good success in maintaining production and slowing the production decline by the timely workover of wells to replace pumps and re-perforate where possible. PetroNeft Resources plc: Annual Report 2013GovernanceFinancial StatementsReview of the Year 14 Tank farm at Lineynoye CPF. It is likely we will drill at least three more wells (up to five wells depending upon results) from Pad 1 at Arbuzovskoye including a long reach well to the south that will seek to test that area before committing to a full drilling pad in the south. Supplies for these wells were moved to site by winter roads in March 2014 and we expect to commence drilling again at Arbuzovskoye Pad 1 in the fourth quarter of 2014, once the Tungolskoye No. 5 well is completed. Tungolskoye At Tungolskoye oil field the study confirms that much of the reserves are located structurally higher than the previous wells drilled there which had good oil tests, this means that we should not encounter the same oil transition zone issues as encountered before at Pad 2 Lineynoye. Based on this new interpretation, we have selected a crestal location for a delineation well, Tungolskoye No. 5, which is planned to spud in July 2014. The Arbuzovskoye development was the first outlying field to be developed and tied back to the Lineynoye Central Processing Facility (‘CPF’). It will act as a design template for future developments such as Tungolskoye (Q1 2015) and Sibkrayevskoye (Q1 2016) which will also be tied back to the CPF. The CPF will act as a hub for processing oil produced from oil fields in the northern part of the licence. Based on this model future developments can be simple and cost-effective with minimal infrastructure costs because of the substantial infrastructure already in place. As future projects are incremental in nature the economics are robust even at lower flow rates. Licence 61 – Exploration and Delineation In 2012/2013 we carried out a comprehensive study to update the mapping in the northern and central parts of Licence 61. The study, carried out with Tomsk Geophysical Company (‘TGK’), involved the reprocessing of all seismic data from the base raw data and tied it to the well log data from all wells drilled in the area since the previous comprehensive remapping in 2007. Some of the well logs from wells drilled in the Soviet-era were also re-processed and re-analysed. This important study utilised more modern software and techniques than were used in the prior study in 2007 and has significantly improved our understanding of the northern and central parts of the Licence area. Our plans here are to drill an initial vertical hole which we will core, open hole test and log. This data will then be used in conjunction with the structural map and data from the Tungolskoye No. 1 well to plan and drill a 300 metre horizontal segment in the J1-1 and J1-2 reservoirs between the T-5 and T-1 wells. Assuming this well comes in close to prognosis, we could quickly proceed with the Tungolskoye development and construct a pipeline to the CPF in Q1 of 2015 and commence year-round production from Tungolskoye in mid-2015. Sibkrayevskoye The TGK study also indicated that the Sibkrayevskoye oil field is potentially larger than previously estimated. We have not yet asked Ryder Scott to take this into account as it is our intention to acquire further seismic here and to drill a delineation well, No. 373, before going forward to a full development. In that regard there is a rig in place at the new Sibkrayevskoye location together with the necessary supplies to drill the well. It is our intention, subject to final agreement of the location with Oil India to drill the well in Q1 of 2015. We also plan to acquire additional high resolution 2D seismic data over the Sibkrayevskoye field in the winter of 2014/2015. This data, in conjunction with the well results, will serve as the basis for a decision on bringing the field into production. Emtorskaya The 2011 drilling results indicated that the Lineynoye field extends further north than previously estimated, the Lineynoye and West Lineynoye fields are one connected structure and that the field wide oil water contact lies below the structural spill point between Lineynoye and the Emtorskaya high to the north. This provides further evidence that the field is much larger and potentially includes the Emtorskaya high structures to the north. The additional work carried out during 2012 included the re-interpretation of the two old Soviet-era wells at Emtorskaya. In both wells it has been interpreted that there is potential missed oil pay making this a very interesting prospect for future development. The crest of the Emtorskaya prospect is 65 metres higher than the crest of Pad 1 at Lineynoye. While we are acquiring more seismic data for the Sibkrayevskoye oil field in 2014/2015 we will also acquire some infill lines over the large Emtorskaya structure. The Emtorskaya structure encompasses an area over 100 km2 and is over twice as large as the combined Lineynoye and West Lineynoye structures. Traverskaya The TGK study also provided new information about the Traverskaya prospect, located at the eastern border of the licence, including identifying a promising potential stratigraphic trap on the flank of the structure based on seismic attributes at analogous fields in the Tomsk region. Reserves Update Independent reserve consultants Ryder Scott completed an assessment of PetroNeft’s petroleum reserves on Licence 61 as at 1 April 2013. The total Proved and Probable (‘2P’) reserves for the licence stood at 117 mmbbls. Ryder Scott has not prepared a new reserve update for the Licence area this year as the only new well drilled since the last report is PetroNeft Resources plc: Annual Report 2013 Lineynoye No. 9 and we still need to conduct a cased hole test on this well, however, we do not see significant reserve adjustments associated with this well. As a result of the April 2013 report on Licence 61, total 2P reserves net to PetroNeft are 131.1 mmbbls. Total P1 reserves are 21.7 mmbbls. If we adjust these reserves for production to the end of 2013 reserves are estimated at 130.4 mmbbls 2P and 21.0 mmbbls P1. As a result of the Licence 61 Farmout, PetroNeft’s net reserves will become 72.2 mmbbls 2P and 11.3 mmbbls P1. We have had good exploration success in the past and feel we can add much of these reserves back with additional appraisal at Sibkrayevskoye, Emtorskaya and Traverskaya in the medium term. Licence 67 (Ledovy) Licence 67 was registered in January 2010. The 2010 work programme focused on the overall re-evaluation of all the previous data on the licence area with modern technology. Well and seismic data was re-processed and the results of this evaluation were used to select the location of two exploration wells and to assess where to acquire additional seismic data. In 2011/2012 two wells were drilled, one at the Cheremshanskaya prospect and a second at the Ledovoye oil field. These wells resulted in the discovery of a new oil field at Cheremshanskoye (December 2011) with three separate oil pools and the confirmation of the Upper Jurassic J1-3 oil pool at Ledovoye oil field with a potential new oil pool discovery in the lower Cretaceous (February 2012). During 2012/2013 we have been reviewing the well results and it is clear that in both cases further work is required in order to assess these structures and potential development scenarios. In the winter of 2013/2014, we acquired 156 km2 of 3D seismic data over the Cheremshanskoye and Ledovoye oil fields. We are hopeful that the 3D seismic will help us to define the structure and distribution of the Lower Jurassic J-14 oil pool at Cheremshanskoye which is interpreted to be a river valley-fill in nature. This data is currently being processed and interpreted. Ryder Scott Estimated Reserves in Oil Fields (net to PetroNeft) 15 Oil Field Name Licence 61 Lineynoye Tungolskoye Kondrashevskoye Arbuzovskoye Sibkrayevskoye North Varyakhskoye Licence 67 Ledovoye Total net to PetroNeft Proved 1P mmbo 8.4 2.7 1.8 2.1 3.7 0.8 19.5 1.5 21.0 Proved & Probable Proved, Probable & Possible 2P mmbo 30.4 19.7 5.0 6.4 53.0 1.9 116.4 14.0 130.4 3P mmbo 39.1 24.7 6.2 8.0 67.3 2.4 147.7 17.4 165.1 • Licence 61 as at 31 December 2013 (Ryder Scott report as at 1 April 2013 adjusted for production to 31 December 2013). • All oil in discovered fields is in the Upper Jurassic section. • Reserves were determined in accordance with the Society of Petroleum Engineers (‘SPE’) Petroleum Resources Management System (‘PRMS’) rules. • Licence 67 will be co-developed with Arawak Energy and the reserves above reflect PetroNeft’s 50% share as per the most recent Ryder Scott report as at 1 January 2011. The gross cost of this will be approximately US$4.8 million. Once we have a chance to study the results of the interpretation, we will decide the next steps in the development of Licence 67. Depending upon the results and the development scenario we may qualify for Mineral Extraction Tax (‘MET’) relief for small fields. The Lower Jurassic J14 reservoir at Cheremshanskoye should also qualify for maximum tight oil reservoir (80% MET relief for ten years) and Tyumen Formation MET relief (20% for 15 years). The Bazhenov Formation is present throughout both Licence 67 and Licence 61. The Bazhenov Formation is the organic rich source rock that sourced 85% of the conventional oil fields in the West Siberian Basin. The Bazhenov has similarities to major US tight oil plays (Bakken and Eagle Ford) and is currently the subject of Joint Venture studies with major Russian and Foreign companies to determine if the US technology (horizontal wells with multiple fracs) is applicable in Russia. Recent legislation adopted in July 2013 provides for zero MET for 15 years for Bazhenov Formation production. In Licence 67 oil shows were described in Bazhenov core samples in two of the prior wells. Given the attractive fiscal incentives, we are carefully following efforts within the industry to commercialise the potential of this resource. Health, Safety and Environmental The Group is fully committed to high standards of Health, Safety and Environmental (‘HSE’) management. More details of our HSE activities are included in the HSE report on page 19. Conclusion We are very pleased to have signed an agreement with Oil India for the Licence 61 Farmout, and to have Shareholders’ endorsement of the Licence 61 Farmout. The Licence 61 Farmout to OIL was the culmination of an extensive process that took over a year and a half to finalise. As a result of the Licence 61 Farmout PetroNeft will be materially strengthened both financially and strategically. The Company will be debt-free with significant funding available to develop the significant potential in Licence 61 alongside a great new partner. I would like to personally thank the Shareholders for their patience over the last two years and their resounding endorsement of the Licence 61 Farmout to OIL. I would also like to thank the many employees of PetroNeft and its subsidiaries who have worked tirelessly over the last two years to maintain production levels under significant funding constraints and for their efforts in meeting the extensive due diligence requests during negotiation of the Licence 61 Farmout agreement with OIL. 2014 will be an exciting year and we especially look forward to the Tungolskoye No. 5 well which will be the first horizontal well drilled by the Company. Water tanks of firefighting facility at Lineynoye CPF. Dennis Francis Chief Executive Officer PetroNeft Resources plc: Annual Report 2013GovernanceFinancial StatementsReview of the Year 16 FINANCIAL REVIEW 2013 was a busy year from a finance point of view. Significant effort was focused on finding a solution to the long-term funding needs of the Group either through re-financing of the existing debt facilities or through a farmout of a 50% interest in Licence 61. Paul Dowling Chief Financial Officer 2013 was a busy year from a finance point of view. Significant effort was focused on finding a solution to the long-term funding needs of the Group either through re-financing of the existing debt facilities or through a farmout of a 50% interest in Licence 61. This was in the context of no new additional drilling being possible because of the commencement of principal repayments on the Macquarie loan in March 2013. While production held up well and good oil prices were achieved, with no new wells being drilled, a long-term solution was required in order to allow the recommencement of drilling and therefore production growth. Having spoken to over 60 potential counterparties the efforts started coming to fruition in late December 2013 with the signing of a memorandum of understanding with Oil India Limited to farmout a 50% non-operated interest in Licence 61. The deal was subject to final legal and financial due diligence and to final legal documentation which was completed in the first quarter of 2014 leading to the signing of a legally-binding agreement in April 2014. The deal is subject to shareholder approval which was granted at EGMs in May 2014 and to Russian Regulatory approval which is expected to be received imminently. The deal will close shortly after the receipt of the Russian Regulatory approval and the Macquarie and Arawak loans will be repaid in full from the proceeds. Net Loss The net loss for the year increased to US$9,158,726 from US$4,566,143 in 2012. The increase in the loss for the year before taxation can be attributed to a foreign exchange loss of US$6,189,735 (2012: gain of US$4,538,236) on US Dollar-denominated loans from PetroNeft to its wholly owned subsidiary, Stimul-T, whose functional currency is the Russian Rouble. This loss arises due to the weakening of the Russian Rouble against the US Dollar in the year. Gross margin improved slightly during the year as a result of increased production and better oil prices. As a result of an impairment of interest on intra-Group loans during the year, there was a reversal of a deferred tax liability which led to a net credit to the Consolidated Income Statement of US$2,337,159. Total administrative expenses fell by US$540,621 as compared with 2012. Revenue, Cost of Sales and Gross Margin Revenue from oil sales was US$38,687,123 for the year (2012: US$34,581,257). Cost of sales includes depreciation of US$5,133,256 (2012: US$4,219,955). We would expect the gross margin to improve in future periods as our facilities and field operations are fully staffed and can handle additional production from the Arbuzovskoye oil field under the current cost structure. We produced 870,965 barrels of oil (2012: 806,761 barrels) in the year and sold 879,826 barrels of oil (2012: 812,006 barrels) achieving an average oil price of US$43.97 per barrel (2012: US$42.86 per barrel). The increase in production and barrels sold is a result of more wells producing in 2013. All of our oil was sold on the domestic market in Russia. PetroNeft Resources plc: Annual Report 2013 Finance Costs Finance costs of US$3,437,088 (2012: US$4,216,548) relate to interest on loans, arrangement fees in relation to the loan facilities, interest paid for late payment to suppliers and unwinding of discount on the decommissioning provision. The primary reason for the decrease is the commencement of principal repayments on the Macquarie loan during the year. Finance Revenue Finance revenue of US$70,810 (2012: US$77,233) arises from interest earned on bank deposits and on shareholder loans to the Licence 67 joint venture. Taxation The current tax charge arises on interest earned from bank deposits. The deferred tax charge in prior years primarily arose on interest earned by PetroNeft on loans to its wholly owned subsidiary Stimul-T. As part of the Licence 61 Farmout, the unpaid interest owed by Stimul-T to PetroNeft was impaired on 31 December 2013. This gave rise to the reversal of the accrued deferred tax liability of US$6,469,864 in 2013. A deferred tax charge of US$2,400,000 arose in relation to temporary differences in Russia. Cost Management A number of initiatives were undertaken in 2012 to reduce and manage costs including reducing the number of employees in the Group from 188 to 170 by the end of 2012. This was achieved through a hiring embargo whereby department managers must first try to re-allocate duties of a departing employee to other employees and can only replace a departing employee having demonstrated that this is not possible. These policies were continued in 2013 and employee numbers were held at the same levels during the year. With very few exceptions, no pay rises have been awarded since January 2011. Capital Investment During 2013 the capital expenditure was lower than 2012 as the funding available was limited due to the commencement of repayments to Macquarie in March 2013. In early 2013 two oil production wells and one water source well were drilled at the Arbuzovskoye oil field. In November/December 2013 a delineation well was drilled at Lineynoye 9 location. The contractor, TBNG, agreed to delay payment for this work until the loan to Macquarie is repaid. The Group intends to drill up to five further production wells at Arbuzovskoye as well as two exploration/delineation wells at Tungolskoye and Sibkrayevskoye and commence a programme of seismic acquisition at Sibkrayevskoye later in 2014. Current and Future Funding of PetroNeft The total debt outstanding as at 31 December 2013 was US$30 million down from US$36.5 million at the start of the year. In March 2014 the Company raised US$6.7 million through an equity funding of US$5.2 million at 5 pence per share and additional debt of US$1.5 million in order to fund the purchase of certain drilling supplies and to make a US$2.5 million payment to Macquarie. The additional debt of US$1.5 million came from Arawak through an increase of the existing loan facility to US$16.5 million on similar terms. As discussed in Note 2 of the consolidated financial statements on page 34, the Licence 61 Farmout deal with Oil India will lead to the repayment of all debt owed to Macquarie and Arawak totalling almost US$25 million. As part of Licence 61 Farmout, Oil India will be providing exploration and development funding of US$45 million in the coming years through the jointly operated entity WorldAce. With this funding we expect to bring both the Tungolskoye and Sibkrayevskoye oil fields into production in 2015 and 2016 which will result in much increased cash generation from Licence 61 providing sufficient funding to develop the Licence further. Following the Licence 61 Farmout, PetroNeft will be debt-free and well capitalised to further develop its assets. Key Financial Metrics Revenue Cost of sales Gross profit Gross margin % Administrative expenses Overheads Share-based payment expense Other foreign exchange (gain)/loss Foreign exchange (loss)/gain on intra-Group loans Finance costs Loss for the year before taxation Income tax credit/(expense) Loss for the year attributable to equity holders of the Parent Capital expenditure in the year Net proceeds of equity share issues Bank and cash balance at year end (including restricted cash) 2013 US$ 2012 US$ 38,687,123 (33,551,965) 5,135,158 13.3% 34,581,257 (30,134,453) 4,446,804 12.9% (6,587,732) (418,775) 166,537 (6,313,028) (977,030) (90,533) (6,839,970) (7,380,591) (6,189,735) (3,437,088) (11,495,885) 2,337,159 (9,158,726) 5,263,823 – 2,171,778 4,538,236 (4,216,548) (2,777,569) (1,788,574) (4,566,143) 14,270,220 16,256,115 7,939,422 Total debt at year end (undiscounted) 30,000,000 36,500,000 17 Accounting Impact of Licence 61 Farmout When the Group signed the Memorandum of Understanding with Oil India in respect of the Licence 61 Farmout in December 2013, the related assets and liabilities (‘the Licence 61 group’) were classified as held for sale in the 31 December 2013 balance sheet. Note 12 to the consolidated financial statements sets out the assets and liabilities that were classified as held for sale. Once the deal has been completed, the accounting for the net investment in the Licence 61 group will change from being fully consolidated to being accounted for using the equity method from the closing date of the Oil India agreement. The effect of this is that the performance of the Licence 61 group will be reported as a single line within the Group Income Statement, being the 50% share of the net profit or loss of the Licence 61 group. On the Group Balance Sheet the net assets will be reported as a single line ‘equity-accounted investment in joint venture’ being the 50% share of the net assets. Financial Risk Management The Board sets the treasury policies and objectives of the Group, which include controls over the procedures used to manage financial risk. The Group’s activities expose the Group to a variety of financial risks including foreign currency, commodity price, credit, liquidity and interest rate risks. These financial risks are managed by the Group under policies approved by the Board. Details of the Group’s financial risk management policies are set out in detail in Note 25 to the Consolidated Financial Statements. Investor Relations During 2013, the CEO and CFO held regular meetings with analysts and institutional investors. The target for 2014 is to continue our programme of meetings and specifically to remind investors of the existing and potential future value of the asset portfolio. Significant Shareholders So far as the Directors are aware, the names of the persons other than the Directors who, directly or indirectly, are interested in 3% or more of the Issued Share Capital at 12 June 2014 are as follows: Name of shareholder Ordinary Shares Percentage 104,301,536 14.75% 42,855,060 34,201,130 6.06% 4.84% 23,975,066 23,014,273 61,010,600 3.39% 3.25% 8.63% Natlata Partners Macquarie Bank Limited Athos Limited Ceres Environmental Consultants Ali Sobraliev J&E Davy Paul Dowling Chief Financial Officer PetroNeft Resources plc: Annual Report 2013GovernanceFinancial StatementsReview of the Year 18 PRINCIPAL RISKS AND UNCERTAINTIES Country Risks Technical Risks Financial Risks Other Risks Integrated Business Risk Management System Audit Committee PetroNeft Board The principal risks and uncertainties affecting the Group and the actions taken by the Group to mitigate these risks and uncertainties are: COUNTRY RISKS Risk Issue Mitigation FINANCIAL RISKS Risk Issue Mitigation Availability of finance Strong reserve base and key infrastructure already in place makes attractive investment case. Oil price Robust project sanction economics – conservative base case assumptions. Russian tax system means economics are not too sensitive to changes in oil price. Board will consider use of appropriate hedging instruments. Industry cost inflation Rigorous contracting procedures with competitive tendering. Also the relationship of the US Dollar:Russian Rouble exchange rate to the oil price provides a natural balance between costs and income. Uninsured events Comprehensive insurance programme in place. OTHER RISKS Risk Issue Mitigation HSE incidents Export quota HSE standards set and monitored regularly across the Group. Equal access to export quotas available for all oil producers using Transneft. Conservative assumption in economics – domestic net back price now largely in alignment with export net back. Third party pipeline access 25-year transportation agreement in place for Licence 61, several options available for ultimate development of Licence 67. Available capacity and access confirmed. Transneft pipeline access East Siberia-Pacific Ocean (‘ESPO’) pipeline allows export of oil to Pacific market. Geopolitical Sanctions to date relating to the Ukraine situation are at a very high level concentrating on Government officials and very high net worth individuals. It is not currently expected that international sanctions will affect Group operations. Political – federal risks Fields/acquisitions below 500 million boe are not considered strategic to the Russian state. State is encouraging small operators. Political – local risks Tomsk Oblast administration is very supportive of development. Local management are well respected in region. Ownership of assets Licences were acquired at government auctions. Work programme for Licence 61 is complete. Work programme for Licence 67 is not onerous. 25-year licence term can be automatically extended based on approved production plan. Changes in tax structure Fiscal system is stable – recent and proposed changes largely benefit upstream oil and gas companies. Proactive lobbying effort made in area of tax legislation. TECHNICAL RISKS Risk Issue Mitigation Exploration risk Proven oil and gas basin with multiple plays. Good quality 2D seismic. Knowledgeable exploration team with proven track record in region. Drilling risk Relatively shallow wells with proven technology. Good rig availability. Experienced operations team. Can avoid drilling wells low on structure that risk poor results. Routine completion practices including fracture stimulation. Production/ Completion risk Reserves high-graded; extensive reservoir simulation and reservoir management will be undertaken. Performance of similar fields in region. Reserve risk SPE and Russian reserves updated and in substantive alignment. PetroNeft Resources plc: Annual Report 2013 HEALTH, SAFETY AND ENVIRONMENTAL REPORT 19 The Group is fully committed to high standards of Health, Safety and Environmental (‘HSE’) management and being socially responsible within the communities where we work. There are inherent risks in the oil and gas industry and these are managed through policies and practices, which stress the need for individual and collective responsibility within our staff structure and with contractors that operate for the Group. Alexey Balyasnikov, the General Director of Stimul-T, has primary responsibility for all aspects of HSE management. As well as reporting directly to Group CEO, Dennis Francis, he also attends all Board meetings to report to the full Board on HSE issues. Health and Safety Management The Group has a Labour Safety and Industrial Security Department headed up by Elena Morgunova. The role of the department is to minimise the risks to employees and contractors from the day-to-day operation of our business, to train all staff in safety awareness and to prepare contingency plans to minimise the potential impact of any unplanned incidents or events. For that purpose we: • Control compliance of all employee operations with labour safety requirements and ensure that employees of the Group and employees of contractors are adequately trained in the use of relevant equipment. • Have a medical facility and appropriate medical personnel at our central Lineynoye base to deal with any issues arising and provide necessary healthcare. • Monitor all contracts the Group enters into in order to ensure that contractors are informed of the labour safety policies of the Group. • Carry out regular site inspections to ensure full compliance. • Develop and deliver labour safety and industrial security training to Group employees. related to the potential emergency that would be caused by an oil spill from a pipeline into the environment. 29 people, including 17 from Stimul-T, and 12 vehicles took part in the exercise which was a success. There were some minor recommendations at the end of the exercise but the local and federal authorities were satisfied that the Company is well prepared for such an emergency. Environmental Initiatives In 2013 we handed back five leased land plots at Licence 61 to the local authorities. These included old well sites and areas where we were able to narrow the amount of land required for operations. As part of this process we were obliged to carry out recultivation works in these areas. This included the planting of over 50,000 cedar tree saplings. Lost-time Incident Unfortunately the Group suffered the first lost-time incident in its history in May 2013. A maintenance technician used the incorrect grindstone on a grinding machine which then broke apart causing a piece to hit him near the eye. While he was wearing the necessary protective goggles and helmet, he did suffer an injury and required hospitalisation but has since fully recovered. An internal investigation that was carried out into the incident ascertained that the employee was fully qualified to carry out the activities and was wearing the necessary protective gear. However, following this incident a new clearer labelling system for grindstones and other equipment was put in place in the workshop. Environmental Impact Management The Board recognises that the Group’s activities can have a significant impact on the environment. As part of its responsibilities under Russian law, an environmental assessment of Licence 61 was carried out before any drilling work commenced in 2007. This was to establish the state of the environment within Licence 61 in advance of any major works. A similar base-line assessment at Licence 67 was also completed before drilling works commenced. Since 2007 there has been a dedicated full-time Environmental Engineer, Elena Nepriyateleva, on staff in our Tomsk office. Her responsibilities include: • Monitoring of exploration and production International Environmental Protection Day In June 2013 we also took part in an initiative supported by the Ministry of Natural Resources and Ecology of the Russian Federation as part of their campaign to recognise International Environmental Protection Day on 5 June 2013. Participants in the campaign, called “Zero Negative Environmental Impact”, were aiming to demonstrate to the public an environmentally responsible approach in matters of negative impact on the environment and a considerate attitude to natural resources of Russia. As part of this initiative we planted over 100 kg of grass seed and almost 400 trees and saplings at the central crew camp at Lineynoye. Gas Utilisation The initial facilities design at Lineynoye emphasised the installation of gas piston power generators to utilise associated gas from the oil production to generate electricity for the camp, facilities and field needs, and thereby minimise the flaring of associated gas. This has been very successful and has led to our operations being amongst the top three in the region in terms of percentage of gas utilisation. We continue to work towards a goal of close to 100% gas utilisation and are currently studying an option to mix associated gas with water for use in our water flood operations thereby re-injecting the gas back to the formation it came from as well as a new type of gas turbine generator that can utilise a higher percentage of the low pressure gas that is currently being flared. Compliance and Inspections The Group reports on its HSE activities to various statutory authorities in Russia on a quarterly and annual basis and is also subject to regular inspections by various bodies. A number of routine inspections relating to compliance with the various health, safety and environmental obligations took place in 2013 and 2012 and no significant issues arose from these inspections. • Maintain an Emergency Response Plan activities. for the facilities of the Group. • Develop and get approved by state authorities: – Regulation for control of industrial safety compliance at hazardous facilities. – Regulation for accident investigation at hazardous industrial facilities of the Group. • Maintain a vaccination and insurance programme for tick-borne encephalitis, a disease common in the West Siberian environment. Emergency Preparedness In January 2013 we held a tactical training exercise at Lineynoye oil field jointly with the Tomsk Regional Centre for Emergency, Rescue and Ecological Operations and the Emergency Situations Department of the Russian Federation • Monitoring activities of sub-contractors. • Maintaining compliance with various environmental laws and regulations. In 2013 the main activities from an environmental perspective were: • Environmental and subsoil monitoring at Lineynoye and Arbuzovskoye oil fields. • Planning and approvals for 2013 and 2014 drilling programmes. • Environmental and subsoil monitoring in Licence 67. This included the use of an independent company to supervise the work of both our own staff and the staff of contractors working at our sites. PetroNeft Resources plc: Annual Report 2013GovernanceFinancial StatementsReview of the Year 20 BOARD OF DIRECTORS DAVID GOLDER Non-Executive Chairman (Age 66) Mr. Golder has been Non-Executive Chairman of the Company since 2005. He is also Chairman of the Remuneration Committee and a member of the Audit Committee. He has over 40 years experience in the petroleum industry and was formerly Senior Vice President of Marathon Oil Company (‘Marathon’), retiring in 2003. From June 1996 to 1999, Mr. Golder was seconded from Marathon to Sakhalin Energy Investment Company where he was Executive Vice President – Upstream. Located in Moscow, he managed all upstream activities which focused on the oil development and company infrastructure aspects of the Sakhalin II Project onshore and offshore Sakhalin Island. Mr. Golder is a member of the Society of Petroleum Engineers. He has a BSc degree in Petroleum & Natural Gas Engineering from Pennsylvania State University and has completed the Program for Management Development at Harvard University. DENNIS FRANCIS Chief Executive Officer and Executive Director (Age 65) Mr. Francis has been Chief Executive Officer and an Executive Director of the Company since its formation in 2005. He has over 40 years experience in the petroleum industry and was with Marathon for 30 years. From 1990, Mr. Francis was the USSR/FSU task force manager, responsible for developing new opportunities for Marathon in Russia. Marathon and its partners ultimately won the first Russian competitive tender, which was to develop the Sakhalin II Project offshore Sakhalin Island. Mr. Francis was instrumental in the formation of Sakhalin Energy Investment Company and was a director in that company. He is a member of the American Association of Petroleum Geologists and Society of Exploration Geophysicists. He has a BSc degree in geophysical engineering and an MSc degree in geology, both from the Colorado School of Mines. He has also completed the Program for Management Development at Harvard University. PAUL DOWLING Chief Financial Officer and Executive Director (Age 42) Mr. Dowling joined the Company in October 2007 and was appointed to the Board of Directors in April 2008. He has 20 years experience in the areas of accounting, auditing, taxation, financial reporting, AIM/IPO reporting, corporate restructuring, corporate finance and acquisitions/disposals. Most recently he was a Partner in the accounting firm, LHM Casey McGrath, located in Dublin. Mr. Dowling is a fellow of the Association of Chartered Certified Accountants (ACCA) and a member of the Irish Taxation Institute. He currently represents the ACCA with the Consultative Committee of Accountancy Bodies – Ireland. He is also a non-executive director of Moesia Oil & Gas plc, an unlisted company focused on oil and gas exploration and development in Central and Eastern Europe. DR. DAVID SANDERS General Legal Counsel, Executive Director and Company Secretary (Age 65) Dr. Sanders has been General Legal Counsel, Executive Director and Company Secretary of the Company since its formation in 2005. He is an attorney at law and has over 35 years experience in the petroleum industry, including 20 years of doing business in Russia and three years in the oil and gas litigation division of the law firm of Fulbright & Jaworski LLP. In 1988, Dr. Sanders joined Marathon where he analysed and reviewed joint venture agreements for worldwide production until his assignment in 1991 to the negotiating team for the Sakhalin II Project in Russia. Dr. Sanders has a degree in electronics from Pennsylvania Institute of Technology, a liberal arts degree from the University of Houston and a doctorate of jurisprudence from South Texas College of Law. He is a member of the State Bar of Texas and of the American Bar Association. PetroNeft Resources plc: Annual Report 2013 21 GERARD FAGAN Non-Executive Director (Age 65) Mr. Fagan was appointed as a Non-Executive Director in 2010. He is a member of the Audit Committee and a member of the Remuneration Committee. Mr. Fagan previously worked with Smurfit Kappa Group plc (‘Smurfit Kappa’) for 23 years before his retirement as Group Financial Controller in September 2009. During this time he had global responsibility for controlling financial operations of Smurfit Kappa, a company with turnover of €7 billion and operations in over 30 countries worldwide. Mr. Fagan has vast experience in mergers and acquisitions, corporate finance, accounting, taxation, insurance and corporate governance. He is both a Chartered Accountant and a Chartered Certified Accountant and has previously served on the audit committee of the Institute of Chartered Accountants in Ireland. Mr. Fagan is also a Non-Executive Director of Smurfit Kappa Group Foundation, Liffey Reinsurance Company Limited, The Baxendale Insurance Company Limited, Bramshott Management Limited and Bramshott Europe Fund plc, Stewarts Care Limited, Stewarts Foundation Limited and Ronanstown Community Training Workshop Limited. THOMAS HICKEY Non-Executive Director (Age 45) Mr. Hickey has been a Non-Executive Director of the Company since 2005. He is Chairman of the Audit Committee and a member of the Remuneration Committee. He is Chief Financial Officer of Petroceltic International plc an AIM listed oil and gas company focused on the Middle East, North Africa and the Mediterranean basin. Tom was previously an Executive Director and Chief Financial Officer of Tullow Oil plc, from 2000 to 2008. During this time, Tullow grew via a number of significant acquisitions including the US$570 million acquisition of Energy Africa in 2004 and the US$1.1 billion acquisition of Hardman Resources in 2006. Prior to joining Tullow, Tom was an Associate Director of ABN AMRO Corporate Finance (Ireland) Limited. Tom is a Fellow of the Institute of Chartered Accountants in Ireland. VAKHA SOBRALIEV Non-Executive Director (Age 59) Mr. Sobraliev has been a Non-Executive Director of the Company since 2005. He is a member of both the Audit and Remuneration Committees. He has over 35 years of experience operating and managing energy service companies and state operating units exploring for and exploiting oil resources in the Western Siberian oil basin. Mr. Sobraliev is currently the principle shareholder of LLC Tomskburneftegaz, an oil and gas well drilling and services company operating in Western Siberia. In May 2014 Mr. Sobraliev became an adviser to the CEO of JSC Rosgeologia, a state-owned Russian company, that provides a full range of exploration services, ranging from regional surveys to parametric drilling and subsoil monitoring to customers across Russia. From 1975 to 2000, Mr. Sobraliev worked for Tomskneft and Strezhevoy drilling boards in various drilling and economic capacities including Chief Engineer and Chief Accountant. He has degrees in mining engineering and economics from Tomsk Polytechnic Institute and the Tomsk State University respectively and an Executive MBA from the Academy of National Economy of Russia. Mr. Sobraliev is a resident of Tomsk, Russia. PetroNeft Resources plc: Annual Report 2013Review of the YearFinancial StatementsGovernance 22 DIRECTORS’ REPORT FOR THE YEAR ENDED 31 DECEMBER 2013 The Directors present herewith their Annual Report and the audited financial statements of PetroNeft Resources plc (the ‘Company’) and its subsidiaries (collectively, the ‘Group’) for the year ended 31 December 2013. Principal Activity The principal activities of the Group are that of oil and gas exploration, development and production. The Group was established to acquire and develop oil and gas exploration, development and production interests in Russia and other countries of the former Soviet Union. A detailed business review is included in the Chairman’s Statement, Chief Executive Officer’s Report and in the Financial Review. Results and Dividends The loss for the year before tax amounted to US$11,495,885 (2012: US$2,777,569). After a tax credit of US$2,337,159 (2012: charge of US$1,788,574) the loss for the year amounted to US$9,158,726 (2012: US$4,566,143). The Directors do not recommend payment of a dividend. Accordingly, an amount of US$9,158,726 has been debited to reserves. Review of the Development and Performance of the Business In compliance with the requirements of the Companies Acts, 1963 to 2013, a fair review of the performance and development of the Group’s business during the year, its position at the year-end and its future prospects is contained in the Chairman’s Statement on pages 10 and 11, the Chief Executive Officer’s Report on pages 12 to 15 and the Financial Review on pages 16 and 17. The key financial metrics used by management are set out in the Financial Review on page 17. Corporate Governance The Company is not subject to the UK Corporate Governance Code applicable to companies with full listings on the Dublin and London Stock Exchanges. The Company does, however, intend, in so far as is practicable and desirable, given the size and nature of the business and the constitution of the Board, to comply with the Corporate Governance Guidelines for AIM Companies (the ‘QCA Guidelines’) as published by the Quoted Companies Alliance (the ‘QCA’). The QCA Guidelines were devised, in consultation with a number of significant institutional small company investors, as an alternative corporate governance code applicable to AIM companies. An alternative code was proposed because the QCA considered the UK Corporate Governance Code to be inappropriate to many AIM companies. The QCA Guidelines state that ‘the purpose of good corporate governance is to ensure that the Company is managed in an efficient, effective and entrepreneurial manner for the benefit of all shareholders over the longer term.’ The guidelines set out a code of best practice for AIM companies. Those guidelines require, among other things, that: a) certain matters be specifically reserved for the Board’s decision; b) the Board should be supplied in a timely manner with information (including regular management financial information) in a form and of a quality appropriate to enable it to discharge its duties; c) the Board should, at least annually, conduct a review of the effectiveness of the Company’s system of internal controls and should report to shareholders that they have done so; d) the roles of Chairman and Chief Executive should not be exercised by the same individual or there should be a clear explanation of how other Board procedures provide protection against the risks of concentration of power within the Company; e) the Company should have at least two independent Non-Executive Directors on the Board and the Board should not be dominated by one person or group of people; f) all Directors should be submitted for re-election at regular intervals subject to continued satisfactory performance; g) the Board should establish audit, remuneration and nomination committees; and h) there should be a dialogue with shareholders based on a mutual understanding of objectives. PetroNeft satisfies all of these requirements with the exception of having a permanent nomination committee in place. Major corporate decisions of the Group are subject to Board approval. The Board is supplied in a timely manner with information in a form and of a quality appropriate to enable it to discharge its duties. These matters include approval of the Group’s general commercial strategy, financial statements, Board membership, significant acquisitions and disposals, major capital expenditures, overall corporate governance and risk management and treasury policies. The Company holds regular Board meetings throughout the year. In accordance with the QCA Guidelines, the Board has established Audit and Remuneration Committees, as described below, and utilises other committees as necessary in order to ensure effective governance. Audit Committee The members of the Audit Committee are Thomas Hickey (Chairman), David Golder, Gerard Fagan and Vakha Sobraliev. The Audit Committee’s responsibilities include, among other things, reviewing interim and year-end financial statements and preliminary announcement, accounting principles, policies and practices, internal controls and overseeing the relationship with the external auditor including reviewing the results of their audit. Remuneration Committee The members of the Remuneration Committee are David Golder (Chairman), Gerard Fagan, Thomas Hickey and Vakha Sobraliev. The Remuneration Committee’s responsibilities include, among other things, determining the policy and elements of remuneration for Executive Directors, provided however, that no Director shall be directly involved in any decisions as to their own remuneration. Nomination Committee Given the current size of the Group, a permanent Nominations Committee is not considered necessary. The Board reserves to itself the process by which a new Director is appointed. PetroNeft Resources plc: Annual Report 2013 23 The percentage of Non-Executive Directors on the Board is above the recommended 50%. The Group has adopted a model code for Directors’ dealings that is appropriate for an AIM company. The Group complies with Rule 21 of the AIM Rules relating to Directors’ dealings and will take all reasonable steps to ensure compliance by the Directors and the Group’s applicable employees and their relative associates. Shareholder Communication Shareholder communication is given high priority by the Group and there are regular meetings between senior executives, institutional shareholders, analysts and brokers. These meetings, which are governed by procedures designed to ensure that price sensitive information is not divulged, are designed to facilitate a two-way dialogue based upon the mutual understanding of objectives. The Annual General Meeting (‘AGM’) affords individual shareholders the opportunity to question the Chairman and the Board and their participation is welcomed. Shareholders are also welcome to telephone or email the Company at any time. The Chairmen of the Audit Committee and Remuneration Committee are available at the AGM to answer questions. In addition, major shareholders can meet with the Chairman of the Board or any Executive and Non-Executive Directors on request. The Board is kept appraised of the views of shareholders, and the market in general, through feedback from the meetings programme. Analysts’ reports on the Company are also circulated to the Board on a regular basis. The Group’s website, www.petroneft.com, is also a key communication tool with all shareholders. News releases are made available on the website immediately after release to the Stock Exchange. Investor presentations, reserve reports and other materials are also available on the website. Internal Control The Directors have overall responsibility for the Group’s system of internal control and have delegated responsibility for the implementation of this system to executive management. This system is reviewed annually and includes financial controls that enable the Board to meet its responsibilities for the integrity and accuracy of the Group’s accounting records. The Group’s system of internal financial control provides reasonable, though not absolute, assurance that assets are safeguarded, transactions authorised and recorded properly and that material errors or irregularities are either prevented or detected within a timely period. Directors The present Directors are listed on pages 20 and 21. In accordance with Article 83 of the Articles of Association, David Golder, Paul Dowling and Gerard Fagan retire by rotation and, being eligible, offer themselves for re-election. Directors, Company Secretary and their Interests The Directors and Company Secretary who held office at 31 December 2013 had no interest, other than those shown below, in the Ordinary Shares of the Company. All interests shown below are beneficial interests. David Golder Dennis Francis Paul Dowling David Sanders Vakha Sobraliev Gerard Fagan Thomas Hickey Ordinary Shares As at 12 June 2014 Ordinary Shares As at 31 December 2013 Ordinary Shares As at 1 January 2013 3,165,458 23,760,416 731,583 2,238,235 – 200,000 2,226,283 3,165,458 23,760,416 731,583 2,238,235 – 200,000 2,226,283 3,165,458 23,760,416 731,583 2,238,235 – 200,000 2,226,283 As at 31 December 2013, Mr. Thomas Hickey is entitled to receive 557,659 (2012: 213,957) shares in relation to Directors’ fees payable in shares instead of cash. In addition to the above, the Directors hold the following share options: Director David Golder Dennis Francis Paul Dowling David Sanders Vakha Sobraliev Gerard Fagan Thomas Hickey Options held as at 1 January 2013 865,000 2,345,000 1,541,250 1,246,250 765,000 260,000 553,000 Granted in year Exercised in year Lapsed in year Options held as at 31 December 2013 – – – – – – – – – – – – – – (440,000) (880,000) – – (440,000) – (198,000) 425,000 1,465,000 1,541,250 1,246,250 325,000 260,000 355,000 Exercise price £0.065 – £0.66 £0.065 – £0.66 £0.065 – £0.66 £0.065 – £0.66 £0.065 – £0.66 £0.065 – £0.66 £0.065 – £0.66 Details of the terms and conditions of the option scheme are included in Note 29 of the financial statements. PetroNeft Resources plc: Annual Report 2013Review of the YearFinancial StatementsGovernance 24 DIRECTORS’ REPORT FOR THE YEAR ENDED 31 DECEMBER 2013 (CONTINUED) Principal Risks and Uncertainties The Group has a risk management structure in place which is designed to identify, manage and mitigate business risks. Risk assessment and evaluation is an essential part of the Group’s internal control system. Details of the principal risks and uncertainties affecting the Group, as required to be disclosed in accordance with the Companies Acts, 1963 to 2013, are listed on page 18. Remuneration Committee Report The Group’s policy on senior executive remuneration is designed to attract and retain people of the highest calibre who can bring their experience and independent views to the policy, strategic decisions and governance of the Group. In setting remuneration levels, the Remuneration Committee takes into consideration the remuneration practices of other companies of similar size and scope. A key philosophy is that staff must be properly rewarded and motivated to perform in the best interests of the shareholders. Bonuses for Executive Directors are based on performance targets which include elements relating to shareholder return and individual performance. The share option scheme is designed to incentivise performance and loyalty of Directors and key employees. Options vest when certain operational and total shareholder return targets are met. Share option holdings of the Directors are disclosed on page 23. The Board has also agreed to allow Directors elect to have their Directors’ fees paid in shares. Under this scheme, the number of shares issued will be based on the closing price at each quarter end. Elections under this scheme must be for a minimum of one year. Certain Directors elected to receive a portion of their remuneration for 2008 to 2013 in shares instead of cash. Directors Remuneration Director Executive Directors Dennis Francis Paul Dowling David Sanders Non-Executive Directors David Golder Gerard Fagan Thomas Hickey Vakha Sobraliev 2013 2012 Basic* US$ Bonus† US$ Pension US$ Total US$ Basic* US$ Bonus US$ Pension US$ Total US$ 312,425 255,566 254,698 80,888 15,621 66,163 12,427 39,566 12,735 408,934 334,156 306,999 301,865 256,455 245,981 – 15,071 – 12,023 – 12,286 316,936 268,478 258,267 822,689 186,617 40,783 1,050,089 804,301 – 39,380 843,681 59,766 39,844 39,844 26,563 166,017 – – – – – – – – – – 59,766 39,844 39,844 26,563 57,213 38,997 38,997 25,998 166,017 161,205 – – – – – – – – – – 57,213 38,997 38,997 25,998 161,205 Total Directors remuneration 988,706 186,617 40,783 1,216,106 965,506 – 39,380 1,004,886 Your attention is drawn to the details of the share options received by the Directors as set out in the Directors’ Report on page 23. In accordance with IFRS 2, Share-based Payment, a further expense of US$157,218 (2012: US$290,846) has been recognised in the Consolidated Income Statement in respect of share options granted to Directors. * Certain amounts are to be paid in shares instead of cash. † The 2013 bonuses approved for the executive directors by the Remuneration Committee are payable following the completion of the Licence 61 Farmout. Directors’ Responsibilities Statement in Respect of the Financial Statements The Directors are responsible for preparing the Directors’ Report and the financial statements in accordance with Irish law and regulations. Irish company law requires the Directors to prepare financial statements giving a true and fair view of the state of affairs of the Company and of the Group and the profit or loss of the Group for each financial year. Under that law the Directors have elected to prepare the financial statements in accordance with IFRSs as adopted by the European Union. In preparing these financial statements, the Directors are required to: • Select suitable accounting policies and then apply them consistently; • Make judgements and estimates that are reasonable and prudent; • State that the financial statements comply with International Financial Reporting Standards as adopted by the European Union; and • Prepare the financial statements on the going concern basis unless it is inappropriate to presume that the Group and Company will continue in business. The Directors are responsible for keeping proper books of account that disclose with reasonable accuracy at any time the financial position of the Company and enable them to ensure that the financial statements comply with the Companies Acts, 1963 to 2013. They are also responsible for safeguarding the assets of the Group and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities. PetroNeft Resources plc: Annual Report 2013 25 Political Donations The Company did not make any political donations during the year. Books of Account The measures taken by the Directors to ensure compliance with the requirements of Section 202, Companies Act 1990, regarding proper books of account are the implementation of necessary policies and procedures for recording transactions, the employment of competent accounting personnel with appropriate expertise and the provision of adequate resources to the financial function. The books of account of the Company are maintained at 20 Holles Street, Dublin 2, Ireland. Important Events after the Balance Sheet Date On 17 March 2014 the Company announced a US$6.7 million fund raise consisting of US$5.2 million of new equity and an additional US$1.5 million loan from Arawak Energy. The purpose of this funding was to fund the purchase of supplies during the winter period in Russia in order that once the funding situation was fully solved the drilling programme could re-commence later in 2014. On 17 April 2014, the Company entered into a legally-binding agreement with Oil India Limited. Under the terms of the agreement, OIL will subscribe for shares in WorldAce, the holding company for Stimul-T, the entity which holds Licence 61 and all related assets and liabilities, and following, PetroNeft and Oil India Limited will both hold 50% of the voting shares, and through the shareholders agreement, both parties will have joint control of WorldAce with PetroNeft continuing as operator (‘The Licence 61 Farmout’). Under the terms of the Licence 61 Farmout, OIL will be making a total investment of up to US$85 million consisting of: • US$35 million upfront cash payment: – This will enable PetroNeft to repay in full its existing debts (the Macquarie Debt Facility and the Arawak Loan) and will provide cash for working capital purposes. • US$45 million of exploration and development expenditure on Licence 61. • US$5 million performance bonus, contingent upon average production from the Sibkrayevskoye Field reaching 7,500 bopd within the next five years. The Licence 61 Farmout is conditional on shareholder approval, which was granted on 9 May 2014 and on Russian Regulatory approval which is expected to be received imminently. Going Concern The Directors are required to make an assessment of the Group and Company’s ability to continue in operational existence as a going concern. Although the Directors remain confident about the outcome of the Russian Regulatory approval and the completion of the Licence 61 Farmout, as at the date of approval of these financial statements, the Russian Regulatory approval remains outstanding and the most recent waiver received from Macquarie will expire on 7 July 2014. These circumstances represent a material uncertainty that may cast significant doubt upon the Group and the Company’s ability to continue as a going concern. Nevertheless, the Directors believe it is appropriate to prepare the financial statements on a going concern basis based on the following assumptions: • That no material obstacles remain for the completion of the Licence 61 Farmout, other than as noted above; and • That the cashflows from the investment by Oil India Limited will be sufficient to enable the Group and the Company to repay its net outstanding debt to Macquarie and Arawak, to further develop its assets and to continue in operational existence for the foreseeable future. Further details are set out in Note 2 to the Consolidated Financial Statements. Auditors Ernst & Young, Chartered Accountants, have indicated their willingness to continue in office in accordance with the provisions of Section 160(2) of the Companies Act, 1963. Annual General Meeting Your attention is drawn to the Notice of the Annual General Meeting (‘AGM’) set out on page 63. The AGM will be on 29 August 2014 in the Herbert Park Hotel, Ballsbridge, Dublin 4, Ireland. Your Directors believe that the Resolutions to be proposed at the AGM are in the best interests of the Company and its shareholders as a whole and, therefore, recommend you to vote in favour of the Resolutions. Your Directors intend to vote in favour of the Resolutions in respect of their own beneficial holdings of 32,321,975 Ordinary Shares. Approved by the Board on 26 June 2014 Dennis Francis Director Paul Dowling Director PetroNeft Resources plc: Annual Report 2013Review of the YearFinancial StatementsGovernance 26 INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS OF PETRONEFT RESOURCES PLC We have audited the Group and Parent Company financial statements (the ‘financial statements’) of PetroNeft Resources plc for the year ended 31 December 2013 which comprise the Consolidated Income Statement, the Consolidated Statement of Comprehensive Income, the Consolidated and Parent Company Balance Sheets, the Consolidated and Parent Company Cash Flow Statements, the Consolidated and Parent Company Statements of Changes in Equity, and the related Notes 1 to 31. The financial reporting framework that has been applied in their preparation is Irish law and International Financial Reporting Standards (‘IFRSs’) as adopted by the European Union and, as regards the Parent Company financial statements, as applied in accordance with the provisions of the Companies Acts 1963 to 2013. This report is made solely to the Company’s members, as a body, in accordance with section 193 of the Companies Act, 1990. Our audit work has been undertaken so that we might state to the Company’s members those matters we are required to state to them in an auditor’s report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company and the Company’s members as a body, for our audit work, for this report, or for the opinions we have formed. Respective Responsibilities of Directors and Auditors As explained more fully in the Directors’ Responsibilities Statement, the Directors are responsible for the preparation of the financial statements giving a true and fair view. Our responsibility is to audit and express an opinion on the financial statements in accordance with Irish law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the Auditing Practices Board’s Ethical Standards for Auditors. Scope of the Audit of the Financial Statements An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting policies are appropriate to the Group and the Parent Company’s circumstances and have been consistently applied and adequately disclosed; the reasonableness of significant accounting estimates made by the Directors; and the overall presentation of the financial statements. In addition, we read all the financial and non-financial information in the Annual Report to identify material inconsistencies with the audited financial statements and to identify any information that is apparently materially incorrect based on, or materially inconsistent with, the knowledge acquired by us in the course of performing the audit. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report. Opinion on Financial Statements In our opinion: • The Group financial statements give a true and fair view, in accordance with IFRSs as adopted by the European Union, of the state of the Group’s affairs as at 31 December 2013 and of its loss for the year then ended; • The Parent Company balance sheet gives a true and fair view, in accordance with IFRSs as adopted by the European Union as applied in accordance with the provisions of the Companies Acts 1963 to 2013, of the state of the Parent Company’s affairs as at 31 December 2013; and • The financial statements have been properly prepared in accordance with the requirements of the Companies Acts 1963 to 2013. Emphasis of Matter – Going Concern In forming our opinion on the financial statements, which is not modified, we have considered the adequacy of the disclosures made in Note 2 to the financial statements concerning the Group and the Company’s ability to continue as a going concern. These conditions indicate the existence of a material uncertainty which may cast significant doubt about the Group and the Company’s ability to continue as a going concern. The financial statements do not include any adjustments to the carrying amount or classification of assets and liabilities that would result if the Group or the Company was unable to continue as a going concern. Matters on Which We Are Required to Report by the Companies Acts 1963 to 2013 • We have obtained all the information and explanations which we consider necessary for the purposes of our audit. • In our opinion proper books of account have been kept by the Parent Company. • The Parent Company balance sheet is in agreement with the books of account. • In our opinion the information given in the Directors’ Report is consistent with the financial statements. • The net assets of the Parent Company, as stated in the Parent Company balance sheet are more than half of the amount of its called-up share capital and, in our opinion, on that basis there did not exist at 31 December 2013 a financial situation which under Section 40 (1) of the Companies (Amendment) Act, 1983 would require the convening of an extraordinary general meeting of the Parent Company. Matters on Which We Are Required to Report by Exception We have nothing to report in respect of the provisions in the Companies Acts 1963 to 2013 which require us to report to you if, in our opinion, the disclosures of Directors’ remuneration and transactions specified by law are not made. Dermot Quinn For and on behalf of Ernst & Young Dublin 26 June 2014 PetroNeft Resources plc: Annual Report 2013 CONSOLIDATED INCOME STATEMENT FOR THE YEAR ENDED 31 DECEMBER 2013 Continuing operations Revenue Cost of sales Gross profit Administrative expenses Exchange (loss)/gain on intra-Group loans Operating (loss)/profit Loss on disposal of oil and gas properties Share of joint venture’s net loss Finance revenue Finance costs Loss for the year for continuing operations before taxation Income tax credit/(expense) Loss for the year attributable to equity holders of the Parent Loss per share attributable to ordinary equity holders of the Parent Basic and diluted – US Dollar cent CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME FOR THE YEAR ENDED 31 DECEMBER 2013 Loss for the year attributable to equity holders of the Parent Other comprehensive income to be reclassified to profit or loss in subsequent periods: Currency translation adjustments – subsidiaries Currency translation adjustments – joint venture Total comprehensive loss for the year attributable to equity holders of the Parent Approved by the Board on 26 June 2014 Dennis Francis Director Paul Dowling Director 27 Note 5 6 16 7 8 10 11 2013 US$ 2012 US$ 38,687,123 (33,551,965) 34,581,257 (30,134,453) 5,135,158 (6,839,970) (6,189,735) (7,894,547) – (235,060) 70,810 (3,437,088) (11,495,885) 2,337,159 4,446,804 (7,380,591) 4,538,236 1,604,449 (19,231) (223,472) 77,233 (4,216,548) (2,777,569) (1,788,574) (9,158,726) (4,566,143) (1.42) (1.03) 2013 US$ 2012 US$ (9,158,726) (4,566,143) (3,293,001) (252,238) 2,215,334 190,734 (12,703,965) (2,160,075) Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 28 CONSOLIDATED BALANCE SHEET AS AT 31 DECEMBER 2013 Assets Non-current Assets Oil and gas properties Property, plant and equipment Exploration and evaluation assets Equity-accounted investment in joint venture Current Assets Inventories Trade and other receivables Cash and cash equivalents Restricted cash Assets held for sale Total Assets Equity and Liabilities Capital and Reserves Called-up share capital Share premium account Share-based payment reserve Retained loss Currency translation reserve Other reserves Amounts recognised in other comprehensive income and accumulated in equity relating to assets held for sale Equity attributable to equity holders of the Parent Non-current Liabilities Provisions Interest-bearing loans and borrowings Deferred tax liability Current Liabilities Trade and other payables Interest-bearing loans and borrowings Liabilities directly associated with assets held for sale Total Liabilities Total Equity and Liabilities Approved by the Board on 26 June 2014 Dennis Francis Director Paul Dowling Director Note 13 14 15 16 18 19 20 20 2013 US$ 2012 US$ 467,060 – 3,331,844 – 105,097,756 1,696,626 28,294,677 3,819,142 3,798,904 138,908,201 30,523 790,864 116,831 2,054,947 1,711,417 1,320,032 3,939,422 4,000,000 2,993,165 10,970,871 12 125,766,570 – 128,759,735 10,970,871 132,558,639 149,879,072 24 8,561,499 8,561,499 136,762,387 136,762,387 6,266,045 (48,357,296) (5,224,443) 336,000 6,684,820 (57,516,022) (177,021) 336,000 12 (8,592,661) – 86,059,002 98,344,192 23 22 10 – – 106,674 1,843,790 14,559,722 4,871,227 106,674 21,274,739 21 22 1,806,732 30,000,000 8,909,830 21,350,311 31,806,732 30,260,141 12 14,586,231 – 46,392,963 30,260,141 46,499,637 51,534,880 132,558,639 149,879,072 PetroNeft Resources plc: Annual Report 2013 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEAR ENDED 31 DECEMBER 2013 Called up share capital US$ Share premium account US$ Share–based payment and other reserves US$ Currency translation reserve US$ Currency translation reserve relating to assets held for sale US$ At 1 January 2012 5,636,142 122,431,629 5,230,985 (7,630,511) Loss for the year Currency translation adjustments – subsidiaries Currency translation adjustments – joint venture Total comprehensive loss for the year New share capital subscribed Transaction costs on issue of share capital Conversion of debt for new shares issued Share-based payment expense Share-based payment expense – Macquarie warrants (Note 29) Arawak warrants (Note 22) – – – – – – – 2,762,969 – 14,447,506 – (954,360) 162,388 – 837,612 – – – – – – – – – – – – 977,030 197,230 196,800 – 2,215,334 190,734 2,406,068 – – – – – – At 31 December 2012 8,561,499 136,762,387 6,602,045 (5,224,443) At 1 January 2013 8,561,499 136,762,387 6,602,045 (5,224,443) Loss for the year Currency translation adjustments – subsidiaries Currency translation adjustments – joint venture Total comprehensive loss for the year Transfer in relation to assets held for sale Share-based payment expense – – – – – – – – – – – – – – – – – (3,293,001) (252,238) (3,545,239) 29 Retained loss US$ Total US$ (43,791,153) 81,877,092 (4,566,143) (4,566,143) – – 2,215,334 190,734 (4,566,143) – (2,160,075) 17,210,475 – – – – – (954,360) 1,000,000 977,030 197,230 196,800 (48,357,296) 98,344,192 (48,357,296) 98,344,192 (9,158,726) (9,158,726) – – (3,293,001) (252,238) (9,158,726) (12,703,965) – – – – – – – – – – – – – – – – – At 31 December 2013 8,561,499 136,762,387 7,020,820 (177,021) (8,592,661) (57,516,022) 86,059,002 – 418,775 8,592,661 – (8,592,661) – – – – 418,775 Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 30 CONSOLIDATED CASH FLOW STATEMENT FOR THE YEAR ENDED 31 DECEMBER 2013 Operating activities Loss before taxation Adjustment to reconcile loss before tax to net cash flows Non-cash Depreciation Loss on disposal of oil and gas properties Share of loss in joint venture Share-based payment expense Finance revenue Finance costs Working capital adjustments Decrease in trade and other receivables Decrease in inventories Increase/(decrease) in trade and other payables Income tax received/(paid) Net cash flows received from operating activities Investing activities Purchase of oil and gas properties Advance payments to contractors Purchase of property, plant and equipment Proceeds from disposal of property, plant and equipment Exploration and evaluation payments Decrease in restricted cash Interest received Net cash used in investing activities Financing activities Proceeds from issue of share capital Transaction costs of issue of shares Proceeds from loan facilities Transaction costs on loans and borrowings Repayment of loan facilities Interest paid Net cash (used in)/received from financing activities Net (decrease)/increase in cash and cash equivalents Translation adjustment Cash and cash equivalents held for sale Cash and cash equivalents at the beginning of the year Cash and cash equivalents at the end of the year Note 2013 US$ 2012 US$ (11,495,885) (2,777,569) 5,632,077 – 235,060 418,775 (70,810) 3,437,088 189,890 661,568 9,703,801 167,592 4,637,596 19,231 223,472 977,030 (77,233) 4,216,548 1,603,422 383,541 (1,837,731) (186,675) 8,879,156 7,181,632 (4,789,662) (76,594) (83,286) 12,268 (326,918) 1,945,053 32,819 (18,479,654) (119,159) (15,529) 3,549 (1,787,260) 1,000,000 52,714 (3,286,320) (19,345,339) – – – – (6,500,000) (2,709,529) 17,210,475 (954,360) 15,000,000 (350,811) (12,500,000) (3,340,504) (9,209,529) 15,064,800 (3,616,693) (14,607) (191,291) 3,939,422 2,901,093 8,324 – 1,030,005 116,831 3,939,422 29 7 8 12 20 PetroNeft Resources plc: Annual Report 2013 COMPANY BALANCE SHEET AS AT 31 DECEMBER 2013 Non-current Assets Property, plant and equipment Financial assets Current Assets Trade and other receivables Cash and cash equivalents Restricted cash Total Assets Equity and Liabilities Capital and Reserves Called-up share capital Share premium account Share-based payment reserve Retained loss Other reserves 31 Note 14 17 2013 US$ 2012 US$ 4,140 40,128,770 8,651 45,634,887 40,132,910 45,643,538 19 20 20 82,900,052 129,481,865 3,692,037 4,000,000 115,165 2,054,947 85,070,164 137,173,902 125,203,074 182,817,440 24 8,561,499 8,561,499 136,762,387 136,762,387 6,266,045 (10,603,541) 336,000 6,684,820 (58,969,330) 336,000 Equity attributable to equity holders of the Parent 93,375,376 141,322,390 Non-current Liabilities Interest-bearing loans and borrowings Deferred tax liability Current Liabilities Trade and other payables Interest bearing loans and borrowings Total Liabilities Total Equity and Liabilities Approved by the Board on 26 June 2014 Dennis Francis Director Paul Dowling Director 22 10 – 106,674 14,559,722 4,871,227 106,674 19,430,949 21 22 1,721,024 30,000,000 713,790 21,350,311 31,721,024 22,064,101 31,827,698 41,495,050 125,203,074 182,817,440 Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 32 COMPANY STATEMENT OF CHANGES IN EQUITY FOR THE YEAR ENDED 31 DECEMBER 2013 At 1 January 2012 Loss for the year Called up share capital US$ Share premium account US$ Share-based payment and other reserves US$ Retained loss US$ Total US$ 5,636,142 122,431,629 5,230,985 (10,238,869) 123,059,887 – – – (364,672) (364,672) Total comprehensive loss for the year New share capital subscribed Transaction costs on issue of share capital Conversion of debt for new shares issued Share-based payment expense Share-based payment expense – Macquarie warrants (Note 29) Arawak warrants (Note 22) – 2,762,969 – 162,388 – – – – 14,447,506 (954,360) 837,612 – – – – – – – 977,030 197,230 196,800 (364,672) – – – – – – (364,672) 17,210,475 (954,360) 1,000,000 977,030 197,230 196,800 At 31 December 2012 At 1 January 2013 Loss for the year Total comprehensive loss for the year Share-based payment expense At 31 December 2013 8,561,499 136,762,387 6,602,045 (10,603,541) 141,322,390 8,561,499 136,762,387 6,602,045 (10,603,541) 141,322,390 – – – – – – – (48,365,789) (48,365,789) – 418,775 (48,365,789) – (48,365,789) 418,775 8,561,499 136,762,387 7,020,820 (58,969,330) 93,375,376 PetroNeft Resources plc: Annual Report 2013 COMPANY CASH FLOW STATEMENT FOR THE YEAR ENDED 31 DECEMBER 2013 Operating Activities (Loss)/profit before taxation Adjustments to reconcile (loss)/profit before tax to net cash flows Non-cash Depreciation of property, plant and equipment Share-based payment expense Impairment of financial assets Impairment of trade and other receivables Finance revenue Finance costs Working capital adjustments Decrease/(increase) in trade and other receivables Increase/(decrease) in trade and other payables Income tax paid Net cash flows received from/(used in) operating activities Investing activities Purchase of property, plant and equipment Decrease in restricted cash Interest received Net cash received from investing activities Financing activities Proceeds from issue of share capital Transaction costs of issue of shares Proceeds from loan facilities Transaction costs on loans and borrowings Repayment of loan facilities Interest paid Net cash (used in)/received from financing activities Net (decrease)/increase in cash and cash equivalents Translation adjustment Cash and cash equivalents at the beginning of the year Cash and cash equivalents at the end of the year 33 Note 2013 US$ 2012 US$ (53,102,948) 1,423,902 17 18 4,511 158,072 5,766,820 46,287,424 (6,920,052) 3,299,496 3,958 380,514 – – (7,093,078) 3,890,820 7,170,652 1,008,047 (1,293) (11,883,865) (42,290) (17,790) 3,670,729 (13,337,829) – 1,945,053 15,002 (3,165) 1,000,000 16,226 1,960,055 1,013,061 – – – – (6,500,000) (2,709,529) 17,210,475 (954,360) 15,000,000 (350,811) (12,500,000) (3,340,504) (9,209,529) 15,064,800 (3,578,745) 1,873 3,692,037 2,740,032 1,180 950,825 20 115,165 3,692,037 Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 34 NOTES TO THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2013 1. General Information on the Company and the Group PetroNeft Resources plc (‘PetroNeft’, ‘the Company’, or together with its subsidiaries, ‘the Group’) is a company incorporated in Ireland. The Company is listed on the Alternative Investments Market (‘AIM’) of the London Stock Exchange and the Enterprise Securities Market (‘ESM’) of the Irish Stock Exchange. The address of the registered office and the business address in Ireland is 20 Holles Street, Dublin 2. The Company is domiciled in the Republic of Ireland. The principal activities of the Group are oil and gas exploration, development and production. 2. Going Concern On 17 April 2014, the Company entered into a legally-binding agreement with Oil India Limited (‘OIL’). Under the terms of the agreement, OIL will subscribe for shares in WorldAce, the holding company for Stimul-T, the entity which holds Licence 61 and all related assets and liabilities, and following, the Company and OIL will both hold 50% of the voting shares, and through the shareholders agreement, both parties will have joint control of WorldAce with the Company continuing as operator (‘The Licence 61 Farmout’). Under the terms of the Licence 61 Farmout, OIL will be making a total investment of up to US$85 million consisting of: • US$35 million upfront cash payment, – This will enable the Company to repay in full its existing debts (the Macquarie Debt Facility and the Arawak Loan) and will provide cash for working capital purposes. • US$45 million of exploration and development expenditure on Licence 61. • US$5 million performance bonus, contingent upon average production from the Sibkrayevskoye Field reaching 7,500 bopd within the next five years. The Licence 61 Farmout is conditional on shareholder approval, which was granted on 9 May 2014 and on OIL obtaining Russian Regulatory approval. There has been a short delay in the Russian Regulatory approval due to a routine administrative matter within the relevant Russian Federation governmental department but there are no other significant obstacles and approval is expected to be received imminently. In the unlikely event that the approval is not granted, the decision can be appealed in court. At 25 June 2014, the Company has total net outstanding debt amounting to US$24.9 million with US$8.4 million due to Macquarie Bank Limited (‘Macquarie’) and US$16.5 million due to Belgrave Naftogas B.V. (‘Arawak loan’). The scheduled repayment date of the Arawak loan is May 2015, however the Macquarie maturity date was 28 May 2014. In anticipation of the completion of the Licence 61 Farmout, Macquarie has granted an extension to the maturity date up to 7 July 2014 to facilitate the completion. Macquarie is supportive of the License 61 Farmout and is expected to work with the Directors, if due to the administrative matter noted above there is a further delay in the timing of the receipt of the Russian Regulatory approval, by extending the maturity date if necessary. It is expected that shortly after the receipt of the Russian Regulatory approval the Company will complete the Licence 61 Farmout which will result in the immediate repayment of all of its outstanding debt to Macquarie and Arawak. Following the completion of the Licence 61 Farmout the Company will be debt-free. Although the Directors remain confident about the outcome of the Russian Regulatory approval and the completion of the Licence 61 Farmout, as at the date of approval of these financial statements, the Russian Regulatory approval remains outstanding and the most recent waiver received from Macquarie will expire on 7 July 2014. These circumstances represent a material uncertainty that may cast significant doubt upon the Group and the Company’s ability to continue as a going concern. Nevertheless, the Directors believe it is appropriate to prepare the financial statements on a going concern basis based on the following assumptions: • That no material obstacles remain for the completion of the Licence 61 Farmout, other than as noted above; and • That the cashflows from the investment by Oil India Limited will be sufficient to enable the Group and the Company to repay its net outstanding debt to Macquarie and Arawak, to further develop its assets and to continue in operational existence for the foreseeable future. Accordingly, these financial statements do not include any adjustments to the carrying amount or classification of assets and liabilities that would result if the Group or Company was unable to continue as a going concern. 3. Accounting Policies 3.1 Basis of Preparation The financial statements have been prepared on a historical cost basis. The financial statements are presented in US Dollars (’US$’). The accounting policies set out below have been applied consistently by all the Group’s subsidiaries and the joint venture to all periods presented in these consolidated financial statements. Certain prior year disclosures have been amended to conform to current year presentation. Statement of Compliance The consolidated financial statements of PetroNeft Resources plc and its subsidiaries have been prepared in accordance with International Financial Reporting Standards (‘IFRS’) as adopted by the European Union (‘EU’). 3.2 Basis of Consolidation The consolidated financial statements comprise the financial statements of PetroNeft Resources plc and its subsidiaries as at 31 December each year. PetroNeft Resources plc: Annual Report 2013 35 3. Accounting Policies (continued) Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Group obtains control, and continue to be consolidated until the date that such control ceases. The financial statements of the subsidiaries are prepared for the same reporting period as the Parent Company. All intra-Group balances, income and expenses and unrealised gains and losses resulting from intra-Group transactions are eliminated in full. A change in the ownership interest of a subsidiary, without a loss of control, is accounted for as an equity transaction. If the Group loses control over a subsidiary, it: • Derecognises the assets (including goodwill) and liabilities of the subsidiary. • Derecognises the carrying amount of any non-controlling interest. • Derecognises the cumulative translation differences recognised in equity. • Recognises the fair value of the consideration received. • Recognises the fair value of any investment retained. • Recognises any surplus or deficit in profit or loss. • Reclassifies the parent’s share of components previously recognised in other comprehensive income to profit or loss or retained earnings, as appropriate. 3.3 Significant Accounting Judgements, Estimates and Assumptions The preparation of the Group’s consolidated financial statements in compliance with IFRS as adopted by the European Union (‘EU’) requires management to make judgements, estimates and assumptions that affect the reported amounts of assets, liabilities and disclosed contingent liabilities at the end of the reporting year and the amounts of revenues and expenses recognised during the reporting period. Estimates and judgements are continuously evaluated and are based on management’s experience and other factors, including expectations of the future events that are believed to be reasonable under the circumstances. However, uncertainty about these assumptions and estimates could result in outcomes that require an adjustment to the carrying amount of the asset or liability affected in future periods. (a) Judgements In the process of applying the Group’s accounting policies, management has made the following judgements, apart from those involving estimations, which have a significant effect on amounts recognised in the consolidated financial statements. Assets held for sale and discontinued operations On 27 December 2013, the Group signed a Memorandum of Understanding with OIL in respect of the Licence 61 Farmout. Consequently it was deemed that the held for sale criteria under IFRS 5 were met and that the related assets and liabilities (‘the disposal group’) be classified as held for sale in the 31 December 2013 balance sheet. The Directors considered the disposal group to meet the criteria to be classified as held for sale at that date for the following reasons: • The disposal group is available for immediate sale and can be sold in its current condition; • The actions to complete the sale were initiated and expected to be completed within one year from the date; and • The Group expects the procedural formalities for the sale to be completed in mid-2014. For more details on the assets held for sale, refer to Note 12. The Directors determined that the disposal group does not meet the criteria under IFRS 5 for discontinued operations for the following reasons: • The Group will have significant continuing involvement with Licence 61 and while the Group will lose outright control, it will maintain joint control and continue to be the operator of Licence 61; • There will be no strategic shift in how the Directors approach the Group – although the Group have brought in a new investor for financing and operational expertise, and while the Group’s economic interest in Licence 61 will be reduced, the Directors consider the nature of the Group’s continuing operations are substantively unchanged; and • Licence 61 was never considered a separate component of the entity or geographical area of business, and was previously assessed on a unified basis with licence 67 as one segment. Exploration and evaluation expenditure – Notes 12 and 15 Exploration and evaluation expenditure represents active exploration projects. These amounts will be written-off to the Consolidated Income Statement as exploration costs unless commercial reserves are established, or the determination process is not completed. The outcome of ongoing exploration, and therefore whether the carrying value of these assets will ultimately be recovered, is inherently uncertain. The Group has capitalised intangible exploration and evaluation assets in accordance with IFRS 6 Exploration for and Evaluation of Mineral Resources, which are evaluated for indicators of impairment. Any impairment review, where required, involves significant judgement related to matters such as recoverable reserves, production profiles, oil and gas prices, discount rate, development, operating and offtake costs and other matters. The carrying amount of exploration and evaluation assets at 31 December 2013 is US$27.2 million (2012: US$28.3 million). At the end of 2013 the carrying value of US$27.2 million was transferred to assets held for sale, see Note 12. (b) Estimates and Assumptions The key assumptions concerning the future and other key sources of estimation uncertainty at the balance sheet date that have a significant risk of causing a material adjustment to the carrying amount of assets and liabilities within the next financial year are discussed below: Assets Held for Sale The Group classifies non-current assets and disposal groups as held for sale if their carrying amounts will be recovered principally through a sale rather than through continuing use. Such non-current assets and disposal groups classified as held for sale are measured at the lower of their carrying amount and fair value less costs to sell. Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 36 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 3. Accounting Policies (continued) Reserves Base Certain oil and gas properties are depreciated on a unit-of-production (‘UOP’) basis at a rate calculated by reference to Proved and Probable reserves, determined in accordance with the Society of Petroleum Engineers Petroleum Resources Management System rules and incorporating the estimated future cost of developing and extracting those reserves. This results in a depreciation charge proportional to the depletion of the anticipated remaining production from the field. Commercial reserves are determined using estimates of oil in place, recovery factors and future oil prices. Future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities, and other capital costs. The current long-term Urals blend oil price assumption used in the estimation of commercial reserves is an export price of US$95 per barrel and a Russian domestic price of US$43 per barrel. Each item’s life, which is assessed annually, has regard to both its physical life limitations and to present assessments of economically recoverable reserves of the field at which the asset is located. These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The calculation of the UOP rate of depreciation could be impacted to the extent that actual production in the future is different from current forecast production based on Proved and Probable reserves. This would generally result from significant changes in any of the factors or assumptions used in estimating reserves. These factors could include: • Changes in Proved and Probable reserves; • The effect on Proved and Probable reserves of differences between actual commodity prices and commodity price assumptions; and • Unforeseen operational issues. Recoverability of Oil and Gas Properties – Notes 12 and 13 The Group assesses each asset or cash-generating unit (‘CGU’) every reporting period to determine whether any indication of impairment exists. Where an indicator of impairment exists, a formal estimate of the recoverable amount is made, which is considered to be the higher of the fair-value- less-costs-of-disposal and value-in-use. These assessments require the use of estimates and assumptions such as long-term oil prices (considering current and historical prices, price trends and related factors), discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, reserves (see 3(b) reserves base above) and operating performance (which includes production and sales volumes). These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or CGUs. Fair value is determined as the amount that would be obtained from the sale of the asset in an orderly transaction between market participants at the measurement date. Fair value for oil and gas properties is generally determined as the present value of estimated future cash flows arising from the continued use of the assets, which includes estimates such as the cost of future expansion plans and eventual disposal, using assumptions that an independent market participant may take into account. Cash flows are discounted to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Management has assessed its CGUs as being an individual field, which is the lowest level for which cash inflows are largely independent of those of other assets. At the end of 2013 the carrying value of US$96.0 million was transferred to assets held for sale, see Note 12. Impairment of Non-Financial Assets The Group assesses whether there are any indicators of impairment for all non-financial assets at each reporting date. When value-in-use or fair-value-less-costs-of-disposal calculations are undertaken, management must estimate the future expected cash flows from the asset or cash-generating unit and determine a suitable discount rate in order to calculate the present value of those cash flows. It is reasonably possible that the oil price assumption may change, which may then impact the estimated life of a field and may then require a material adjustment to the carrying value of the assets. The Group continuously monitors internal and external indicators of possible/potential impairment relating to its tangible and intangible assets. Impairment of Financial Assets – Note 17 Investments in subsidiaries in the Parent Company balance sheet are stated at cost and are reviewed for impairment if there are indications that the carrying value may not be recoverable in the parent company balance sheet. Decommissioning Costs – Notes 12 and 23 Decommissioning costs will be incurred by the Group at the end of the operating life of certain of the Group’s facilities and properties. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other sites. The expected timing and amount of expenditure can also change, for example, in response to changes in reserves or changes in laws and regulations or their interpretation. As a result, there could be significant adjustments to the provisions established which would affect future financial results. Refer to Note 23 for details of this provision and related assumptions. At the end of 2013 the carrying value of US$1.6 million was transferred to assets held for sale, see Note 12. PetroNeft Resources plc: Annual Report 2013 37 3. Accounting Policies (continued) 3.4 Summary of Significant Accounting Policies (a) Foreign currencies The consolidated financial statements are presented in US Dollars, which is the Group’s presentational currency. The US Dollar is also the Company’s functional currency. Each entity in the Group determines its own functional currency and items included in the financial statements of each entity are measured using that functional currency. The Company’s Russian subsidiaries’ functional currency is the Russian Rouble. Transactions in foreign currencies are initially recorded at the rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the rate of exchange ruling at the balance sheet date, including foreign exchange differences arising on intercompany loans from the Company to the Russian subsidiaries. All differences are taken to profit or loss. Non-monetary items are translated using the exchange rates ruling as at the date of the initial transaction. The assets and liabilities of foreign operations are translated into US Dollars at the rate of exchange ruling at the balance sheet date and their Income Statements are translated at the average exchange rates for the year. The exchange differences arising on the translation are taken directly to equity. The relevant average and closing exchange rates for 2013 and 2012 were: US$1 = Russian Rouble Euro British Pound 2013 2012 Closing 32.769 0.7263 0.6064 Average 31.819 0.7532 0.6395 Closing 30.440 0.7565 0.6185 Average 30.986 0.7781 0.6310 Interest in Joint Venture (b) The Group has an interest in a joint venture, which is a jointly controlled entity (‘JCE’), whereby the venturers have a contractual arrangement that establishes joint control over the economic activities of the entity. The agreement requires unanimous agreement for financial and operating decisions among the venturers. The JCE controls the assets of the joint venture, earns its own income and incurs its own liabilities and expenses. Interests in the JCE are accounted for using the equity method. Under the equity method, the investment in the joint venture is carried in the balance sheet at cost plus post acquisition changes in the Group’s share of net assets of the joint venture. Where there has been a change recognised directly in other comprehensive income or equity of the joint venture, the Group recognises its share of any changes and discloses this, when applicable, in the consolidated income statement or the statement of changes in equity, as appropriate. Unrealised gains and losses resulting from transactions between the Group and the joint venture are eliminated to the extent of the interest in the joint venture. The share of the joint venture’s net profit/(loss) is shown on the face of the consolidated income statement. This is the profit/(loss) attributable to the Group’s interest in the joint venture. The financial statements of the JCE are prepared for the same reporting period as the venturer. Where necessary, adjustments are made to bring the accounting policies in line with those of the Group. The Group, acting as the operator of the JCE, receives reimbursement of direct costs recharged to the joint venture, such recharges represent reimbursements of costs that the operator incurred as an agent for the joint venture and therefore have no effect on profit or loss. When the Group charges a management fee to cover other general costs incurred in carrying out the activities on behalf of the joint venture, it is not acting as an agent. Therefore, the general overhead expenses and the management fee are netted against each other. (c) Oil and Gas Exploration, Evaluation and Development Expenditure Oil and gas exploration, evaluation and development expenditure is accounted for using the successful efforts method of accounting. Pre-licence costs Pre-licence costs are expensed in the period in which they are incurred. Exploration and Evaluation Costs Payments to acquire the legal right to explore are capitalised at cost as intangible assets. If no future activity is planned, the carrying value of these costs is written-off. Costs directly associated with an exploration well are capitalised until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs and payments made to contractors. If hydrocarbons are not found, the exploration expenditure is written-off as a dry hole. If extractable oil is found and, subject to further appraisal activity, which may include the drilling of further wells, is likely to be developed commercially, the costs continue to be carried as an intangible asset. All such carried costs are subject to technical, commercial and management review as well as review for impairment at least once a year to confirm the continued intent to develop or otherwise extract value from the discovery. If this is no longer the case, the costs are written-off. When proved reserves are determined and development is sanctioned, the relevant expenditure is transferred to oil and gas properties after impairment is assessed and any resulting impairment loss is recognised. The net proceeds or costs of pilot production are allocated to exploration and evaluation costs. Development Costs Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalised within oil and gas properties and depreciated from the commencement of production on a unit-of-production basis other than certain non-production related equipment and facilities which are expected to have a shorter useful economic life and are depreciated on a straight-line basis. Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 38 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 3. Accounting Policies (continued) (d) Oil And Gas Properties and Other Property, Plant and Equipment Oil and gas properties and other property, plant and equipment are stated at cost, less accumulated depreciation. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation, and for qualifying assets, relevant borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. Depreciation Oil and gas properties are depreciated on the following basis: • Production related items including the wells, production facility and pipeline are depreciated on a unit-of-production basis over the Proved and Probable reserves of the field concerned. The unit-of-production rate for the amortisation of field development costs takes into account expenditures incurred to date, together with sanctioned future development expenditure to extract these reserves. The related depreciation is included within cost of sales. • Certain non-production related equipment and facilities which are expected to have a shorter useful economic life are depreciated on a straight-line basis over their estimated useful lives at annual rates ranging from 10% to 50%. The related depreciation is included within administrative expenses. Property, plant and equipment are generally depreciated on a straight-line basis over their estimated useful lives at the following annual rates: • Buildings and leasehold improvements – 3% to 7% or remaining term of the lease. • Plant and machinery – 10% to 35%. • Motor vehicles – 14% to 35%. Impairment of Property, Plant and Equipment and Intangible Assets (e) At each balance sheet date, the Group reviews the carrying amounts of its property, plant and equipment and intangible assets to determine whether there is any indication that those assets may be impaired. If such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of any impairment loss. The recoverable amount is determined as the higher of the fair-value-less-costs–of-disposal for the asset and the asset’s value-in-use. If the carrying amount of the asset exceeds its recoverable amount, the asset is impaired and an impairment loss is charged to the Consolidated Income Statement so as to reduce the carrying amount in the Consolidated Balance Sheet to its recoverable amount. Fair value is determined as the amount that would be obtained from the sale of the asset in an orderly transaction between market participants at the measurement date. Direct costs of selling the asset are deducted. Fair value for oil and gas assets is generally determined as the present value of the estimated future cash flows expected to arise from the continued use of the asset, including any expansion prospects, and its eventual disposal, using assumptions that a market participant could take into account. These cash flows are discounted by an appropriate discount rate to arrive at a net present value (‘NPV’) of the asset. Value-in-use is determined as the present value of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal. Value-in-use is determined by applying assumptions specific to the Group’s continued use and cannot take into account future development. These assumptions are different to those used in calculating fair value and consequently the value-in-use calculation is likely to give a different result to a fair value calculation. Where it is not possible to estimate the recoverable amount of an individual asset, the Group estimates the recoverable amount of the cash- generating unit to which the asset belongs. (f) Financial Assets – Investment in Subsidiaries Investments in subsidiaries are stated at cost and are reviewed for impairment if there are indications that the carrying value may not be recoverable. (g) Cash and Cash Equivalents Cash and cash equivalents on the balance sheet comprise cash at bank and on hand and short-term deposits with an original maturity of three months or less. (h) Financial Assets Financial assets within the scope of IAS 39 Financial Instruments: Recognition and Measurement (‘IAS 39’) are classified as loans and receivables. When financial assets are recognised initially, they are measured at fair value plus, in the case of investments not at fair value through profit or loss, directly attributable transaction costs. The Group determines the classification of its financial assets on initial recognition and, where allowed and appropriate, re-evaluates this designation at each financial year end. The Group does not have held-to-maturity investments or available-for-sale financial assets or financial assets at fair value through profit or loss. Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurements, loans and receivables are carried at amortised cost using the effective interest rate method (‘EIR’) less any allowance for impairment. Amortised cost is calculated by taking into account any discount or premium on acquisition and fees or costs that are an integral part of the EIR. The EIR amortisation is included in finance revenue in the Consolidated Income Statement. The losses arising from impairment are recognised in the Consolidated Income Statement in finance costs. PetroNeft Resources plc: Annual Report 2013 39 3. Accounting Policies (continued) The Group assesses at each year-end whether a financial asset or group of financial assets is impaired. If there is objective evidence that an impairment loss on assets carried at amortised cost has been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows (excluding future expected credit losses that have not been incurred) discounted at the financial asset’s original effective interest rate (i.e. the effective interest rate computed at initial recognition). The amount of the loss is recognised in the Consolidated Income Statement. The same policy applies in respect of the Company financial statements. If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised, the previously recognised impairment loss is reversed, to the extent that the carrying value of the asset does not exceed its amortised cost at the reversal date. Any subsequent reversal of an impairment loss is recognised in the Consolidated Income Statement. In relation to trade receivables, a provision for impairment is made when there is objective evidence (such as the probability of insolvency or significant financial difficulties of the debtor) that the Group will not be able to collect all of the amounts due under the original terms of the invoice. The carrying amount of the receivable is reduced through use of an allowance account. Impaired debts are written-off when they are assessed as uncollectible. (i) Financial Liabilities Financial liabilities within the scope of IAS 39 are classified as loans and borrowings. The Group determines the classification of its financial liabilities at initial recognition. All financial liabilities are recognised initially at fair value and in the case of loans and borrowings, net of directly attributable transaction costs. Financial assets and financial liabilities are offset and the net amount is reported in the consolidated balance sheet if there is a currently enforceable legal right to offset the recognised amounts and there is an intention to settle on a net basis, to realise the assets and settle the liabilities simultaneously. The Group’s financial liabilities include trade and other payables and loans and borrowings. Interest-bearing Loans and Borrowings After initial recognition, interest bearing loans and borrowings are subsequently measured at amortised cost using the effective interest rate method. Gains and losses are recognised in the Consolidated Income Statement when the liabilities are derecognised as well as through the EIR amortisation process. Amortised cost is calculated by taking into account any discount or premium on acquisition and fee or costs that are an integral part of the EIR. The EIR amortisation is included in finance cost in the Consolidated Income Statement. Derecognition A financial liability is derecognised when the obligation under the liability is discharged or cancelled or expires. When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability, and the difference in the respective carrying amounts is recognised in the Consolidated Income Statement. Compound Instruments IAS 32 Financial Instruments: Presentation requires the issuer of a financial instrument to classify the instrument, or its component parts, on initial recognition, as a financial liability, financial asset or equity instrument in accordance with the substance of the contractual arrangement. When the initial carrying value of a financial instrument is allocated to its liability and equity components, the equity component is assigned the residual amount after deducting from the fair value of the instrument as a whole the amount separately determined for the liability component. The fair value of the liability component is the present value of the contractually determined stream of future cash flows discounted at the rate of interest applied by the market to instruments of comparable credit status and providing substantially the same cash flows on the same terms, but without the equity component. Thereafter, it is measured at amortised cost until extinguished on conversion or redemption. The remainder of the proceeds on issue is allocated to the equity component and included in other reserves. The carrying amount of the equity component is not remeasured in subsequent years. (j) Fair Value Measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place either: • In the principal market for the asset or liability, or • In the absence of a principal market, in the most advantageous market for the asset or liability. The principal or the most advantageous market must be accessible by the Group. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 40 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 3. Accounting Policies (continued) For financial reporting purposes, fair value measurements are categorised into Level 1, 2 or 3 based on the degree to which inputs to the fair value measurements are observable and the significance of the inputs to the fair value measurement in its entirety, which are described as follows: Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2: valuation techniques for which the lowest level of inputs which have a significant effect on the recorded fair value are observable, either directly or indirectly. Level 3: valuation techniques for which the lowest level of inputs that have a significant effect on the recorded fair value are not based on observable market data. Inventories (k) Inventories are stated at the lower of cost and net realisable value. Cost of producing and processing crude oil is accounted on a weighted average basis. This cost includes all costs incurred in the normal course of business in bringing each product to its present location and condition. The cost of crude oil includes an appropriate proportion of depreciation and overheads based on normal capacity. Net realisable value of crude oil is based on estimated selling price in the ordinary course of business less any costs expected to be incurred to completion and disposal. (l) Provisions General Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event and it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Group expects some or all of a provision to be reimbursed, for example, under an insurance contract, the reimbursement is recognised as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the Consolidated Income Statement net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as a finance cost. A contingent liability is disclosed where the existence of an obligation will only be confirmed by future events or where the amount of the obligation cannot be measured with reasonable reliability. Contingent assets are not recognised, but are disclosed where an inflow of economic benefits is probable. Decommissioning Liability A decommissioning liability is recognised when the Group has a present legal or constructive obligation as a result of past events, and it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of obligation can be made. The amount recognised is the estimated cost of decommissioning, discounted to its present value. A corresponding amount equivalent to the provision at the time of recognition is recognised as part of the cost of the related oil and gas properties or in exploration and evaluation expenditure. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to oil and gas properties or exploration and evaluation expenditure. The unwinding of the discount on the decommissioning provision is included as a finance cost. (m) Taxes Current Income Tax Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted, by the reporting date, in the countries where the Group operates and generates taxable income. Deferred Income Tax Deferred income tax is provided using the liability method on temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred income tax liabilities are recognised for all taxable temporary differences, except: • In respect of taxable temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, where the timing of the reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred income tax assets are recognised for all deductible temporary differences, carry forward of unused tax credits and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry forward of unused tax credits and unused tax losses can be utilised except: • In respect of deductible temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, deferred income tax assets are recognised only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilised. The carrying amount of deferred income tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilised. Unrecognised deferred income tax assets are reassessed at each balance sheet date and are recognised to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered. Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realised or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. PetroNeft Resources plc: Annual Report 2013 41 3. Accounting Policies (continued) Deferred income tax relating to items recognised outside of profit and loss is recognised outside profit and loss. Deferred tax items are recognised in correlation to the underlying transaction either in other comprehensive income or directly in equity. Deferred income tax assets and deferred income tax liabilities are offset if a legally enforceable right exists to set off current tax assets against current income tax liabilities and the deferred income taxes relate to the same taxable entity and the same taxation authority. (n) Revenue Recognition Revenue from the sale of crude oil is recognised when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. This generally occurs when product is physically transferred into a pipe or other delivery mechanism. Revenue is stated after deducting sales taxes, excise duties and similar levies. (o) Borrowing Costs Borrowing costs directly attributable to the acquisition, construction or production of an asset that necessarily takes a substantial period of time to get ready for its intended use or sale are capitalised as part of the cost of the respective assets. All other borrowing costs are expensed in the period they occur. Borrowing costs consist of interest and other costs that an entity incurs in connection with the borrowing of funds. No finance costs met the criteria to be capitalised as borrowing costs in either or 2013 or 2012. (p) Share-based Payment Employees (including senior executives) and Directors of the Group may receive fees and remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments (‘equity-settled transactions’). In situations where equity instruments are issued and some or all of the goods or services received by the entity as consideration cannot be specifically identified, the unidentified goods or services received (or to be received) are measured as the difference between the fair value of the share-based payment transaction and the fair value of any identifiable goods or services received at the grant date. This is then capitalised or expensed as appropriate. Equity-settled Transactions The cost of equity-settled transactions is measured by reference to the fair value at the date on which they are granted. The fair value is determined by an external valuer using an appropriate pricing model, further details of which are given in Note 29. The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled. The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group’s best estimate of the number of equity instruments that will ultimately vest. The income statement charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period and is recognised in employee benefits expense. No expense is recognised for awards that do not ultimately vest, except for equity-settled transactions where vesting is conditional upon a market or non-vesting condition, which are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance and/or service conditions are satisfied. Where the terms of an equity-settled transaction are modified, the minimum expense recognised is the expense as if the terms had not been modified, if the original terms of the awards are met. An additional expense is recognised for any modification that increases the total fair value of the share-based payment transaction, or is otherwise beneficial to the employee as measured at the date of modification. Where an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. This includes any award where non-vesting conditions within the control of either the entity or the employee are not met. However, if a new award is substituted for the cancelled award, and designated as a replacement award on the date that it is granted, the cancelled and new awards are treated as if they were a modification of the original award, as described in the previous paragraph. Where appropriate, the dilutive effect of outstanding options is reflected as additional share dilution in the computation of diluted earnings per share. (q) Share Issue Expenses Costs of share issues are written-off against the premium arising on the issue of share capital. (r) Operating Leases The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement at inception date, or whether the fulfilment of the arrangement is dependent on the use of a specific asset or assets or the arrangement conveys a right to use the asset. Operating lease payments are recognised as an expense in the Consolidated Income Statement on a straight-line basis over the lease term. (s) Finance Revenue and Finance Cost For all financial instruments measured at amortised cost, interest income or expense is recorded using the effective interest rate, which is the rate that exactly discounts the estimated future cash payments or receipts through the expected life of the financial instrument or a shorter period, where appropriate, to the net carrying amount of the financial asset or liability. Interest income is included in finance revenue in the income statement. Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 42 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 3. Accounting Policies (continued) (t) Pension Costs Pension benefits are funded over the employees’ period of service by way of contributions to a defined contribution scheme. Contributions are charged to the Consolidated Income Statement in the year to which they relate. (u) Non-current Assets Held for Sale The Group classifies non-current assets and disposal groups as held for sale if their carrying amounts will be recovered principally through a sale rather than through continuing use. Such non-current assets and disposal groups classified as held for sale are measured at the lower of their carrying amount and fair value less costs to sell. The criteria for held for sale classification is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition. Actions required to complete the sale should indicate that it is unlikely that significant changes to the sale will be made or that the sale will be withdrawn. Management is committed that the sale is expected within one year from the date of the classification. Property, plant and equipment and intangible assets are not depreciated or amortised once classified as held for sale. Assets and liabilities classified as held for sale are presented separately as current items in the consolidated balance sheet. (v) Exceptional Items Exceptional items are disclosed separately in the financial statements where it is necessary to do so to provide further understanding of the financial performance of the Group or the Company. They are material items of income or expense that have been shown separately due to the significance of their nature or amount. 3.5 Changes in Accounting Policy and Disclosures IFRS and IFRIC Interpretations Adopted During the Financial Year The following amended standards and interpretations became effective for the current financial year but had no impact on the Group’s financial position or performance: • IAS 1 (Amendments) Presentation of Items of Other Comprehensive Income; • IAS 19 Employee Benefits (Revised 2011) (IAS 19R); • IFRS 7 (Amendments) Disclosures – Offsetting Financial Assets and Financial Liabilities; • IFRS 13 Fair Value Measurement; • IFRIC 20 Stripping Costs in the Production Phase of a Surface Mine; and • Annual Improvements to IFRS 2009-2011 Cycle. Standards Issued But Not Yet Effective The standards and interpretations that are issued but not yet effective up to the date of issuance of the Group’s financial statements are disclosed below. The Group intends to adopt these standards and interpretations, if applicable, when they become effective (subject to EU endorsement). • IFRS 10 Consolidated Financial Statements and IAS 27 Separate Financial Statements. • IFRS 11 Joint Arrangements and IAS 28 Investment in Associates and Joint Ventures. • IFRS 12 Disclosure of Interests in Other Entities. • IFRIC 21 Levies. • Defined benefit plans: Employee contributions (Amendments to IAS 19). • IAS 32 Offsetting Financial Assets and Financial Liabilities – Amendments to IAS 32. • Recoverable Amount Disclosures for Non-Financial Assets – Amendments to IAS 36 Impairment of Assets. • IAS 39 Novation of Derivatives and Continuation of Hedge Accounting – Amendments to IAS 39. • IFRS 14 Regulatory Deferral Accounts. • IFRS 15 Revenue from Contracts with Customers. • Annual Improvements to IFRS – 2010-2012. • Annual Improvements to IFRS – 2011-2013. The Group is in the process of assessing the impact of these standards. IFRS 9 Financial Instruments IFRS 9, as issued, reflects the IASB’s work on the replacement of IAS 39 and applies to the classification and measurement of financial assets and liabilities as defined in IAS 39 and the application of hedge accounting. The standard was initially effective for annual periods beginning on or after 1 January 2013 but Amendments to IFRS 9 Mandatory Effective Date of IFRS 9 and Transition Disclosures, issued in December 2011, moved the mandatory effective date to 1 January 2015. This date has now been removed to provide sufficient time for preparers of financial statements to make the transition to the new requirements and a new effective date will be announced upon completion of the IFRS 9 project. During 2013 the IASB issued an updated version of IFRS 9 Financial Instruments (Hedge Accounting and amendments to IFRS 9, IFRS 7 and IAS 39) (IFRS 9 (2013)), which includes new hedge accounting requirements and some related amendments to IFRS 7 Financial Instruments: Disclosures. The IASB still has to complete the impairment phase of the project. The Group will assess the impact of IFRS 9 when the final standard including all phases is issued, subject to EU endorsement. There are no other standards and interpretations in issue but not yet adopted that the Directors anticipate will have a material impact on the reported income or net assets of the Group. PetroNeft Resources plc: Annual Report 2013 43 4. Segment Information At present the Group has one reportable operating segment, which is oil exploration and production. As a result, there are no further disclosures required in respect of the Group’s reporting segment. The risk and returns of the Group’s operations are primarily determined by the nature of the activities that the Group engages in, rather than the geographical location of these operations. This is reflected by the Group’s organisational structure and the Group’s internal financial reporting systems. Management monitors and evaluates the operating results for the purpose of making decisions consistently with how it determines operating profit or loss in the consolidated financial statements. Geographical Segments All of the Group’s sales are in Russia. Substantially all of the Group’s capital expenditures are in Russia. Assets are allocated based on where the assets are located: Non-current assets Russia Ireland 5. Revenue Revenue from crude oil sales 2013 US$ 2012 US$ 3,794,764 138,899,550 8,651 4,140 3,798,904 138,908,201 2013 US$ 2012 US$ 38,687,123 34,581,257 38,687,123 34,581,257 All revenue arises from sales to third parties based in the Russian Federation. In 2013, revenue arises from sales of oil to Finko Group companies (65%) and VTEK (35%) (2012: 99.9% NTK Finko). Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 44 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 6. Operating (Loss)/Profit Operating (loss)/profit is stated after charging/(crediting): Included in cost of sales Cost of inventory recognised as an expense – including: Operating lease rentals – land and buildings Operating lease rentals – equipment Foreign exchange loss/(gain) on intra–Group loans Included in administrative expenses Other foreign exchange (gains)/losses Operating lease rentals – land and buildings Operating lease rentals – equipment Depreciation of property, plant and equipment Included in administrative expenses Capitalised during year Depreciation of oil and gas properties Included in cost of sales Included in administrative expenses Included in closing inventories Auditor’s remuneration – Group – audit of Group financial statements – other assurance services – tax advisory services Auditor’s remuneration – Company – audit of parent company financial statements – other assurance services – tax advisory services 7. Finance Revenue Bank interest receivable Interest from Joint Venture loans Unwinding of discount on deposit paid for pipeline usage 8. Finance Costs Interest on loans Unwinding of discount on decommissioning provision Other Note 2013 US$ 2012 US$ 33,551,965 63,180 1,285,471 6,189,735 30,134,453 78,808 1,106,540 (4,538,236) (166,537) 152,105 93,220 271,985 57,018 329,003 90,533 143,759 239,102 166,446 172,890 339,336 14 5,133,256 226,836 195,884 4,219,955 251,195 238,145 13 5,555,976 4,709,295 169,652 22,908 – 192,560 20,000 – – 20,000 2013 US$ 32,819 32,222 5,769 70,810 164,475 29,025 – 193,500 20,000 – – 20,000 2012 US$ 34,784 17,930 24,519 77,233 2013 US$ 2012 US$ 3,299,496 137,592 – 3,890,820 65,167 260,561 3,437,088 4,216,548 PetroNeft Resources plc: Annual Report 2013 9. Employees Number of employees The average numbers of employees (including Directors) during the year was: Directors Senior Management Professional Staff Oil field employees Construction crew employees Employment costs (including Directors) Wages and salaries Social insurance costs Share-based payment expense Contributions to defined contribution pension plan 45 2013 Number 2012 Number 7 5 48 83 28 171 2013 US$ 7 5 50 84 36 182 2012 US$ 5,143,318 945,546 418,775 55,129 5,122,829 972,412 977,030 57,188 6,562,768 7,129,459 Included in employment costs above is an amount of US$961,423 (2012: US$1,362,084) capitalised during the year. Directors’ emoluments Remuneration and other emoluments – Executive Directors Remuneration and other emoluments – Non-Executive Directors Remuneration and other emoluments payable in shares Pension contributions 2013 US$ 2012 US$ 1,009,306 126,173 39,844 40,783 804,301 122,208 38,997 39,380 1,216,106 1,004,886 Your attention is drawn to the details of the share options received by the Directors as set out in the Report of the Directors. In accordance with IFRS 2, Share-based Payment, a further expense of US$157,218 (2012: US$290,846) has been recognised in the Consolidated Income Statement in respect of share options granted to Directors. An amount of US$46,864 (2012: US$45,368) relating to Executive Directors salaries was re-charged to Russian BD Holdings B.V. 10. Income Tax Current income tax Current income tax charge Income tax on dividends (paid in Russia) Total current income tax Deferred tax Relating to origination and reversal of temporary differences Total deferred tax Income tax (credit)/expense reported in the Consolidated Income Statement 2013 US$ 480 – 480 2012 US$ 64,105 10,799 74,904 (2,337,639) (2,337,639) 1,713,670 1,713,670 (2,337,159) 1,788,574 Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 46 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 10. Income Tax (continued) Reconciliation of the Total Tax (Credit)/Expense The tax assessed for the year differs from that calculated by applying the standard rate corporation tax in the Republic of Ireland of 12.5%. The differences are explained below: Loss before income tax Accounting loss multiplied by Irish standard rate of tax of 12.5% Share-based payment expense Effect of higher tax rates on investment income Effect of impairment of Intra-Group Interest Non-deductible expenses Tax deductible timing differences Other Losses available at higher rates Taxable losses not utilised Utilisation of previously unrecognised tax losses Income tax on dividends (paid in Russia) 2013 US$ 2012 US$ (11,495,885) (2,777,569) (1,436,986) 52,347 865,007 (3,229,806) 971,268 1,489,594 29,362 – – (1,077,945) – (347,196) 122,129 884,394 – 664,930 (46,602) 27,934 (283,312) 755,498 – 10,799 Total tax (credit)/expense reported in the Consolidated Income Statement (2,337,159) 1,788,574 Deferred Tax Group Deferred income tax liability At 1 January Translation adjustment Expense for the year recognised in the income statement Reversal of deferred tax liability through the income statement as a result of impairment of accrued interest income on intra-Group loans Transferred to liabilities held for sale (Note 12) At 31 December 2013 US$ 2012 US$ 4,871,227 (26,914) 4,132,225 3,157,557 – 1,713,670 (6,469,864) (2,400,000) – – 106,674 4,871,227 Company The deferred income tax liability movement in 2013 for the Group disclosed above is similar to the movement for the Company, except that the deferred tax liability expense recognised in the income statement of US$1.7 million is offset by the release of the deferred tax liability of US$6.5 million resulting in a closing balance of US$0.1 million. Group and Company Deferred income tax liability Accrued interest income on intra-Group loans 106,674 4,871,227 106,674 4,871,227 Factors That May Affect Future Tax Charges Continued full year-round oil production in Russia is likely to result in taxable profits in Russia in future years, where the applicable tax rate is 20%. PetroNeft Resources plc: Annual Report 2013 47 11. Loss per Ordinary Share Basic loss per Ordinary Share amounts are calculated by dividing net loss for the year attributable to ordinary equity holders of the Parent by the weighted average number of Ordinary Shares outstanding during the year. Basic and diluted earnings per Ordinary Share are the same as the potential Ordinary Shares are anti-dilutive. Numerator Loss attributable to equity shareholders of the Parent for basic and diluted loss Denominator Weighted average number of Ordinary Shares for basic and diluted earnings per Ordinary Share Diluted weighted average number of shares Loss per share: Basic and diluted – US Dollar cent 2013 US$ 2012 US$ (9,158,726) (4,566,143) (9,158,726) (4,566,143) 644,920,275 444,974,000 644,920,275 444,974,000 (1.42) (1.03) The Company has instruments in issue that could potentially dilute basic earnings per Ordinary Share in the future, but are not included in the calculation for the reasons outlined below: • Employee Share Options – Refer to Note 29 for the total number of shares related to the outstanding options that could potentially dilute basic earnings per share in the future. These potential Ordinary Shares are anti-dilutive for the years ended 31 December 2013 and 2012. • Warrants – At 31 December 2013, 9,400,000 (2012: 14,100,000) Ordinary Shares are subject to warrants being exercised (refer to Note 29). These potential Ordinary Shares are anti-dilutive for the years ended 31 December 2013 and 2012. 12. Assets Held for Sale In 2013 the Company commenced a process with Evercore Partners of London to seek a farmout partner for Licence 61. This process led to the signing of a Memorandum of Understanding with Oil India Limited on 27 December 2013 in respect of the farmout of a 50% non-operated interest in Licence 61. Consequently it was deemed that the held for sale criteria under IFRS 5 were met and that the related assets and liabilities (‘the disposal group’) be classified as held for sale in the 31 December 2013 balance sheet. A legally-binding contract was entered into on 17 April 2014. Immediately before the classification as held for sale, the recoverable amount was estimated and no impairment loss was identified. As at 31 December 2013, there was no write-down as the carrying amount of the disposal group did not fall below its fair value less costs to sell. The major classes of assets and liabilities reclassified as held for sale as at 31 December 2013 are as follows: 2013 US$ 2012 US$ Assets held for sale Oil and gas properties Property, plant and equipment Exploration and evaluation assets Inventories Trade and other receivables Cash and cash equivalents Liabilities directly associated with assets held for sale Trade and other payables Deferred tax liability Provisions Amounts recognised in other comprehensive income and accumulated in equity relating to assets held for sale Currency translation reserve Note 13 14 15 96,023,796 935,000 27,235,454 1,215,210 165,819 191,291 125,766,570 10 23 10,633,142 2,400,000 1,553,089 14,586,231 8,592,661 8,592,661 – – – – – – – – – – – – – Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 48 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 13. Oil and Gas Properties Cost At 1 January 2012 Additions Disposals Translation adjustment At 1 January 2013 Additions Transferred to property, plant and equipment Transferred to exploration and evaluation assets Translation adjustment Transferred to assets held for sale At 31 December 2013 Depreciation At 1 January 2012 Charge for the year Translation adjustment At 1 January 2013 Charge for the year Transferred to property, plant and equipment Translation adjustment Transferred to assets held for sale At 31 December 2013 Net book values At 31 December 2013 At 31 December 2012 Wells US$ Equipment and facilities US$ Pipeline US$ Total US$ 63,611,460 8,281,792 (19,231) 3,485,238 75,359,259 4,038,164 – (864,783) (5,332,793) 25,557,989 1,227,254 – 1,383,657 28,168,900 1,017,713 (155,183) – (2,010,516) 13,315,422 2,333,384 – 754,214 16,403,020 55,611 – – (1,159,067) 102,484,871 11,842,430 (19,231) 5,623,109 119,931,179 5,111,488 (155,183) (864,783) (8,502,376) 73,199,847 (73,199,847) 27,020,914 (27,020,914) 15,299,564 (15,299,564) 115,520,325 (115,520,325) – – – – 8,711,882 3,706,710 261,360 12,679,952 4,352,641 – (654,101) 958,420 893,632 61,149 1,913,201 1,088,078 (78,673) (139,846) 116,593 108,953 14,724 240,270 115,257 – (20,250) 9,786,895 4,709,295 337,233 14,833,423 5,555,976 (78,673) (814,197) 16,378,492 (16,378,492) 2,782,760 (2,782,760) 335,277 (335,277) 19,496,529 (19,496,529) – – – – – – – – 62,679,307 26,255,699 16,162,750 105,097,756 The net book value of oil and gas properties at 31 December 2013, prior to the transfer to held for sale, includes US$5,724,639 in respect of assets under construction, which are not yet being depreciated. Expenditure of US$5,111,488 was incurred mainly in connection with the Arbuzovskoye oil field, primarily relating to production wells and oilfield infrastructure. The net book value at 31 December 2012 includes US$8,369,828 in respect of assets under construction, which are not yet being depreciated. PetroNeft Resources plc: Annual Report 2013 49 Buildings & leasehold improvements US$ 1,046,723 – – 55,961 1,102,684 – – – (77,679) 1,025,005 (1,025,005) Plant and machinery US$ Motor vehicles US$ Total US$ 1,748,682 15,529 (3,549) 94,062 1,854,724 14,551 108,427 (39,380) (129,353) 1,808,969 (335,997) 117,670 – – 6,325 123,995 68,335 46,756 – (12,148) 226,938 (226,938) 2,913,075 15,529 (3,549) 156,348 3,081,403 82,886 155,183 (39,380) (219,180) 3,060,912 (1,587,940) – 1,472,972 – 1,472,972 146,251 63,217 8,996 218,464 61,563 – – (17,311) 262,716 (262,716) – – 884,220 785,981 250,421 45,896 1,082,298 227,083 52,512 (27,112) (81,280) 1,253,501 (247,589) 1,005,912 467,060 772,426 54,905 25,698 3,412 84,015 40,357 26,161 – (7,898) 142,635 (142,635) – – 987,137 339,336 58,304 1,384,777 329,003 78,673 (27,112) (106,489) 1,658,852 (652,940) 1,005,912 467,060 39,980 1,696,626 Plant and machinery US$ 23,862 3,165 27,027 – 27,027 14,418 3,958 18,376 4,511 22,887 4,140 8,651 14. Property, Plant and Equipment Group Cost At 1 January 2012 Additions Disposals Translation adjustment At 1 January 2013 Additions Transferred from oil and gas properties Disposals Translation adjustment Transferred to assets held for sale At 31 December 2013 Depreciation At 1 January 2012 Charge for the year Translation adjustment At 1 January 2013 Charge for the year Transferred from oil and gas properties Disposals Translation adjustment Transferred to assets held for sale At 31 December 2013 Net book values At 31 December 2013 At 31 December 2012 Company Cost At 1 January 2012 Additions At 1 January 2013 Additions At 31 December 2013 Depreciation At 1 January 2012 Charge for the year At 1 January 2013 Charge for the year At 31 December 2013 Net book values At 31 December 2013 At 31 December 2012 Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 50 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 15. Exploration and Evaluation Assets Group Cost At 1 January 2012 Additions Translation adjustment At 1 January 2013 Additions Transferred from oil and gas properties Translation adjustment Transferred to assets held for sale At 31 December 2013 Net book values At 31 December 2013 At 31 December 2012 Exploration and evaluation expenditure US$ 24,552,717 2,412,261 1,329,699 28,294,677 69,449 864,783 (1,993,455) 27,235,454 (27,235,454) – – 28,294,677 Exploration and evaluation expenditure represents active exploration projects. These amounts will be written-off to the Consolidated Income Statement as exploration costs unless commercial reserves are established, or the determination process is not completed and there are no indications of impairment. The outcome of ongoing exploration, and therefore whether the carrying value of these assets will ultimately be recovered, is inherently uncertain. In accordance with IFRS 6, once commercial viability is demonstrated the capitalised exploration and evaluation costs are transferred to oil and gas properties or intangibles, as appropriate after being assessed for impairment. Additions in 2012 relate mainly to completion of exploration wells in the Sibkrayevskoye and North Varyakhskoye prospects and the Kondrashevskoye oilfield. 16. Equity-accounted Investment in Joint Venture PetroNeft Resources plc has a 50% interest in Russian BD Holdings B.V., a jointly controlled entity which holds 100% of LLC Lineynoye, an entity involved in oil and gas exploration and the registered holder of Licence 67. The interest in this joint venture is accounted for using the equity accounting method. Russian BD Holdings B.V. is incorporated in the Netherlands and carries out its activities in Russia. At 1 January 2012 Retained loss Translation adjustment At 1 January 2013 Retained loss Translation adjustment At 31 December 2013 Share of net assets US$ 3,851,880 (223,472) 190,734 3,819,142 (235,060) (252,238) 3,331,844 Summarised financial statement information prepared in accordance with IFRS of the equity-accounted joint venture entity is disclosed below: Sales and other operating revenues Operating expenses Exchange (loss)/gain Finance revenue Finance costs Loss before taxation Taxation Loss for the year 2013 US$ – (114,563) (65,784) 184 (45,134) 2012 US$ – (196,468) 8,890 1,719 (30,437) (225,297) (216,296) (9,763) (7,176) (235,060) (223,472) PetroNeft Resources plc: Annual Report 2013 16. Equity-accounted Investment in Joint Venture (continued) Current assets Non-current assets Total assets Current liabilities Non-current liabilities Total liabilities Capital Commitments – Joint Venture Details of capital commitments at the balance sheet date are as follows: Contracted for but not provided in the financial statements Including contracted with related parties Future minimum rentals payable under non-cancellable operating leases at the balance sheet date are as follows: Within one year After one year but not more than five years More than five years 51 2013 US$ 2012 US$ 164,066 4,774,180 61,672 4,647,923 4,938,246 4,709,595 (376,128) (1,230,274) (29,413) (861,040) (1,606,402) (890,453) 2013 US$ 2012 US$ 4,935,229 204,980 112,678 112,678 2013 US$ 4,261 15,801 51,251 71,313 2012 US$ 4,587 18,157 62,051 84,795 The above capital commitments in the joint venture are incurred jointly with Arawak Energy. The Group has a 50% share of these commitments. 17. Financial Assets Company Cost At 1 January 2012 Capital contribution in respect of share-based payment expense At 1 January 2013 Capital contribution in respect of share-based payment expense Impairment charge during year At 31 December 2013 Net book values At 31 December 2013 At 31 December 2012 Investment in joint venture US$ Investment in subsidiaries US$ Total US$ 4,858,816 – 4,858,816 – – 40,179,555 596,516 45,038,371 596,516 40,776,071 260,703 (5,766,820) 45,634,887 260,703 (5,766,820) 4,858,816 35,269,954 40,128,770 4,858,816 35,269,954 40,128,770 4,858,816 40,776,071 45,634,887 Impairment of Investment in Subsidiaries Investments in subsidiaries primarily relate to the historic equity investment in WorldAce Investments Limited by the Company. The Directors identified the announcement of the Licence 61 Farmout as an indicator of impairment. Subsequently, the Directors performed an impairment review on the carrying amount of the investment in WorldAce in accordance with IAS 36 Impairment of Assets. In performing their review the Directors established that the carrying value exceeded the recoverable amount of the investment based on its fair value less costs of disposal. As a result, the investment in WorldAce was impaired by US$5,766,820. Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 52 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 17. Financial Assets (continued) Details of the Company’s holding in direct and indirect subsidiaries at 31 December 2013 are as follows: Name of subsidiary Registered office Proportion of ownership interest Proportion of voting power held Principal activity WorldAce Investments Limited LLC Stimul-T Granite Construction Dolomite 3 Themistocles Street, Nicosia, Cyprus 147 Prospekt Lenina, Tomsk 634009, Russia 147 Prospekt Lenina, Tomsk 634009, Russia 147 Prospekt Lenina, Tomsk 634009, Russia 100% 100% 100% 100% 100% 100% 100% 100% Holding company Oil and Gas exploration Construction Oil and Gas exploration Details of the Group’s interest in joint ventures at 31 December 2013 are as follows: Name of entity Registered office Proportion of ownership interest Proportion of voting power held Russian BD Holdings B.V. Prins Bernhardplein 200, 1097 JB, 50% Amsterdam, the Netherlands LLC Lineynoye 147 Prospekt Lenina, Tomsk 634009, Russia 50% 50% 50% Principal activity Holding company Oil and Gas exploration Arawak Energy owns the other 50% of Russian BD Holdings B.V. 18. Inventories Group Oil stock Materials 19. Trade and Other Receivables Group Russian VAT Russian profit tax receivable Other receivables Receivable from jointly controlled entity (Note 28) Advances to and receivables from related parties (Note 28) Advances to contractors Prepayments Company Amounts owed by subsidiary undertakings (Note 28) Amounts owed to other related companies (Note 28) VAT receivable Prepayments 2013 US$ – 30,523 30,523 2012 US$ 1,572,957 138,460 1,711,417 2013 US$ – – 14,544 717,190 – – 59,130 2012 US$ 55,519 168,885 165,054 657,492 69,762 49,397 153,923 790,864 1,320,032 2013 US$ 2012 US$ 82,111,541 128,638,512 651,431 37,999 153,923 717,190 12,198 59,123 82,900,052 129,481,865 The Company recorded an impairment charge of US$46,287,424 during the year in relation to amounts owed by subsidiary undertakings. The impairment was measured as the difference between the carrying value of the receivable and the present value of the estimated cash flows. The Directors consider that the carrying amount of trade and other receivables approximates their fair value. Other receivables are non-interest-bearing and are normally settled on 60-day terms. Amounts owed by subsidiary undertakings are interest-bearing. Interest is charged at rates ranging from 0% to 10%. PetroNeft Resources plc: Annual Report 2013 20. Cash and Cash Equivalents and Restricted Cash Group Cash at bank and in hand Restricted cash Company Cash at bank and in hand Restricted cash 53 2013 US$ 2012 US$ 116,831 2,054,947 3,939,422 4,000,000 2,171,778 7,939,422 2013 US$ 2012 US$ 115,165 2,054,947 3,692,037 4,000,000 2,170,112 7,692,037 At 31 December 2013 restricted cash amounting to US$2,054,947 is being held in a Macquarie Debt Service Reserve Account (‘DSRA’). This account is part of the security package held by Macquarie and may be offset against the loan in the event of a default on the loan or by agreement between the parties. Bank deposits earn interest at floating rates based on daily deposit rates. Short-term deposits are made for varying periods of between one day and one month depending on the immediate cash requirements of the Group, and earn interest at the respective short-term deposit rates. 21. Trade and Other Payables Group Trade payables Trade payables to jointly controlled entity (Note 28) Trade payables to related parties (Note 28) Corporation tax Oil taxes, VAT and employee taxes Other payables Payments received in advance Accruals Company Trade payables Corporation tax Other taxes and social welfare costs Accruals The Directors consider that the carrying amount of trade and other payables approximates their fair value. Trade and other payables are non-interest-bearing and are normally settled on 60-day terms. Trade payables and accruals principally comprise amounts outstanding for trade purchases and ongoing costs. 2013 US$ 2012 US$ 813,476 – – 63,292 87,004 22,745 – 820,215 945,955 18,241 1,947,539 64,105 3,221,291 169,540 1,531,204 1,011,955 1,806,732 8,909,830 2013 US$ 812,026 63,292 53,510 792,196 1,721,024 2012 US$ 157,972 64,105 21,832 469,881 713,790 Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 54 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 22. Loans and Borrowings Group and Company Interest bearing Current liabilities Macquarie Bank Limited – US$75,000,000 loan facility Belgrave Naftogas B.V. – US$15,000,000 loan Total current liabilities Non-current liabilities Arawak Energy Russia B.V. – US$15,000,000 loan Total non-current liabilities Total loans and borrowings Contractual undiscounted liability Effective interest rate % Contractual maturity date 2013 US$ 2012 US$ 9.81% 7.38% 30-Jun-14 30-May-15 15,000,000 15,000,000 21,350,311 – 7.16% 30-May-15 30,000,000 21,350,311 – – 14,559,722 14,559,722 30,000,000 35,910,033 30,000,000 36,500,000 Macquarie Loan Facility On 28 May 2010 the Group agreed a loan facility agreement for up to US$30 million with Macquarie to re-finance an existing facility of US$5 million. In April 2011, PetroNeft signed a revised borrowing base loan facility agreement with Macquarie for up to US$75 million. The initial borrowing base was set at US$30 million. During 2012, pursuant to a borrowing base review, the Group repaid an amount of US$7.5 million on its outstanding loan balance and in addition an amount of US$1 million was converted into equity by way of issuing new shares. Also it was agreed that the Group would commence monthly repayments of US$650,000 on 31 March 2013. As a result of these repayments, the outstanding loan amount was reduced to US$15 million as at 31 December 2013. In April 2014, Macquarie agreed to extend the maturity date of their loan to 30 June 2014 in order to allow the completion of the transaction with Oil India Limited. A further extension to 7 July 2014 was granted as a result of a short delay in the Russian Regulatory approval which is expected to be received shortly. Certain oil and gas properties (wells, central processing facility, pipeline) together with shares in WorldAce Investments Ltd, shares in Stimul-T, certain bank accounts and inventories are pledged as a security for the Macquarie loan facility agreement. All of this security will be released once the loan is repaid. During the year the Group was in breach of certain financial and non-financial covenants and conditions subject to the loan agreement, relating primarily to receipt of certain amount of cash by sale of oil and certain financial ratios. Arawak Energy Loan Facility On 30 May 2012, the Group signed a three-year loan agreement with Arawak Energy Russia B.V. for US$15 million. The loan carries an interest rate of LIBOR plus 6%. In addition, 4,000,000 warrants were granted to Arawak as part of the loan agreement. Total transaction costs incurred in 2012 amounted to US$0.35 million and are applied against the proceeds. The effective interest rate will be applied to the liability to accrete the transaction costs over the period of the loan. Interest is payable monthly and the principal is repayable in one instalment on 30 May 2015. The loan is secured on PetroNeft’s 50% interest in Russian BD Holdings B.V. In July 2013, pursuant to an internal re-organisation, Arawak Energy Russia B.V. assigned the loan to its sister company Belgrave Naftogas B.V. The loan will be repaid in full from the proceeds of the Oil India transaction. The loan arrangement constitutes a compound financial instrument under IAS 32 Financial Instruments: Presentation comprising loans and borrowing and an equity component (warrants). These warrants granted to Arawak should be accounted for separately. Using the split accounting method, a value of US$0.2 million was allocated to the equity component which has been credited to reserves in 2012. 23. Provisions Decommissioning costs At 1 January Arising during the year Utilised during the year Adjustment arising from change in discount rate Unwinding of discount Translation adjustment Transferred to liabilities held for sale (Note 12) At 31 December 2013 US$ 2012 US$ 1,843,790 59,502 (112,988) (228,517) 137,592 (146,290) 1,147,988 538,901 – – 65,167 91,734 1,553,089 1,843,790 (1,553,089) – – 1,843,790 PetroNeft Resources plc: Annual Report 2013 55 23. Provisions (continued) The decommissioning provision represents the present value of decommissioning costs relating to the Group’s Russian oil interests, which are expected to be incurred near 2030. These provisions have been created based on the Group’s internal estimates. Assumptions, based on the current economic environment, have been made which management believe are a reasonable basis upon which to estimate the future liability. A discount rate of 7.89% (2012: 7.07%) is used for the assessment of the provision. The charge relating to the unwinding of the discount on the provision is reflected in finance costs in the Consolidated Income Statement. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required, which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend upon future oil prices, which are inherently uncertain. 24. Share Capital – Group and Company Authorised 800,000,000 Ordinary Shares of €0.01 each Allotted, called up and fully paid equity At 1 January 2012 Issued in the year At 1 January 2013 Issued in the year At 31 December 2013 2013 2012 8,000,000 8,000,000 8,000,000 8,000,000 Number of Ordinary Shares 416,356,432 228,563,843 644,920,275 – Called up share capital US$ 5,636,142 2,925,357 8,561,499 – 644,920,275 8,561,499 The Company issued 216,052,348 new shares for consideration of US$17.2 million in November 2012. The net proceeds of this share issue of US$16.3 million were used to finance expenditure on oil and gas properties, exploration and evaluation costs, debt repayment and corporate overhead. In addition, the Company issued 12,511,495 new shares in exchange for a reduction of US$1 million in its outstanding loan facility with Macquarie in November 2012. Warrants The following table illustrates the number and weighted average exercise prices (‘WAEP’) of, and movements in, warrants during the year. Outstanding as at 1 January Granted during the year Expired during the year Outstanding at 31 December Exercisable at 31 December 2013 Number 2013 WAEP 2012 Number 14,100,000 – (4,700,000) 9,400,000 9,400,000 £0.084 – £0.082 £0.085 £0.085 6,700,000 7,400,000 – 14,100,000 14,100,000 2012 WAEP £0.34 £0.085 – £0.084 £0.084 Prior to 2012, under various loan agreements Macquarie was granted 6.7 million warrants at various strike prices and with various expiry dates. In August 2012, the Group re-negotiated certain conditions in the US$75 million loan facility with Macquarie, mainly around covenants and its repayment schedule. As part of the re-negotiations, Macquarie were awarded 3.4 million new warrants, and all warrants granted in prior years (6.7 million warrants) were re-priced. 4.7 million warrants granted to Macquarie expired on 28 February 2013. Four million warrants were granted to Arawak during 2012 as part of the new loan agreement. The warrants granted to Arawak constitute a component of a compound financial instrument under IAS 32 Financial Instruments: Presentation containing both a liability and an equity component, and as such has been accounted for under IAS 32. 25. Financial Risk Management Objectives and Policies The Group and Company’s principal financial instruments comprise cash and cash equivalents. The main purpose of these financial instruments is to provide finance for the Group and Company’s operations. The Group has various other financial assets and liabilities such as receivables and trade payables, which arise directly from its operations. The Group also enters into derivative transactions, primarily forward currency contracts. The purpose is to manage the currency risks arising from the Group and Company’s operations and its sources of finance. The Group and Company entered into forward currency contracts during the year, however there are no contracts outstanding as at 31 December 2013 and 2012. It is the Group and Company’s policy that no trading in derivatives be undertaken. Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 56 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 25. Financial Risk Management Objectives and Policies (continued) The main risks arising from the Group and Company’s financial instruments are commodity price risk, foreign currency risk, credit risk, liquidity risk, interest rate risk and capital risk. The Board reviews and agrees policies for managing each of these risks which are summarised below. Commodity Price Risk The Group is exposed to the risk of fluctuations in prevailing market commodity prices on the oil it produces. To date the Group has sold all of its oil on the domestic market in Russia. There are no banks providing hedging or derivative type contracts for oil sold on the domestic market so it is not possible to mitigate risks in this way. The high taxes on oil produced in Russia are based on prevailing international oil prices and therefore operate as a natural hedge to a fall in oil prices. At 31 December 2013 and 2012, the Group and the Company had no outstanding commodity contracts. Foreign Currency Risk The Group and the Company undertake certain transactions denominated in foreign currencies. Hence, exposures to exchange rate fluctuations arise. Exchange rate exposures are managed within approved policy parameters utilising forward exchange contracts where appropriate. At 31 December 2013 and 2012, the Group and the Company had no outstanding forward exchange contracts. Foreign Currency Sensitivity Analysis The Group’s and the Company’s principal currency exposures arise in the currencies of Russian Rouble, Euro, UK Sterling and US Dollar. The Group has an exposure to US Dollars because the functional currency of its Russian subsidiaries is Russian Roubles. A change in the US Dollar:Russian Rouble exchange rate will therefore result in a foreign exchange gain or loss on the US Dollar denominated balances in these subsidiaries. The Company has an exposure to US Dollars because payments to some suppliers are effected in Euro and in UK Sterling, and the Company has bank accounts in Russian Rouble, Euro, UK Sterling and US Dollar. In accordance with IFRS 7, the impact of foreign currencies is determined based on the balances of financial assets and liabilities at 31 December 2013. The sensitivity analysis includes only outstanding foreign currency denominated monetary items and largely results from payables and receivables, and adjusts their translation at the year-end for a 5% change in foreign currency rates. A positive number below indicates a reduction in loss and increase in other equity where the US Dollar strengthens 5% against the relevant currency. For a 5% weakening of the US Dollar against the relevant currency, there would be an equal and opposite impact on the loss and other equity, and the balances following would be negative. If the US Dollar had gained/lost 5% against all currencies significant to the Group and Company at 31 December, the impact on loss and equity for the Group and the Company is shown below. Group Impact on loss [lower/(higher)] Impact on net equity [lower/(higher)] Company Impact on loss and net equity [lower/(higher)] 2013 US$ 2,368 12,019 2013 US$ 2,368 2012 US$ 2,207 14,570 2012 US$ 2,207 Credit Risk Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Group. The Group and Company’s financial assets comprise receivables and cash and cash equivalents. The credit risk on cash and cash equivalents is limited because the counterparties are banks with high credit ratings assigned by international credit-rating agencies. The Group and Company’s exposure to credit risk arise from default of its counterparty, with a maximum exposure equal to the carrying amount of cash and cash equivalents in its consolidated balance sheet. As the Group or the Company does not have any significant receivables outstanding from third parties, this risk is limited. The Group and the Company do not have any significant credit risk exposure to any single counterparty or any group of counterparties having similar characteristics. The Group and the Company define counterparties as having similar characteristics if they are connected entities. Liquidity Risk Management Liquidity risk is the risk that the Group and the Company will not have sufficient funds to meet liabilities. Ultimate responsibility for liquidity risk management rests with the Board of Directors, who manage liquidity risk and short, medium and long-term funding and liquidity management requirements by continuously monitoring forecast and actual cash flows and matching the maturity profiles of financial assets and liabilities. Cash forecasts are regularly produced to identify the liquidity requirements of the Group and the Company. To date, the Group and the Company have relied on shareholder funding, loan facilities and normal trade credit to finance its operations. As at 31 December 2013, the Group and the Company have outstanding loan facilities with Macquarie Bank Limited and with Arawak Energy Russia B.V. (see Note 22). The Macquarie loan facility was repayable in May 2014, however, Macquarie granted an extension to 7 July 2014 to allow the Licence 61 Farmout to complete. The Arawak loan facility is repayable in May 2015, however the loan will be repaid early from the proceeds of the Oil India transaction. The rest of the Group and the Company’s financial liabilities as at 31 December 2013 and 2012 are all payable on demand. The Group and the Company expect to meet its other obligations from operating cash flows. During the year the Group was in breach of certain financial and non- financial covenants and conditions subsequent to the Macquarie loan agreement, relating primarily to receipt of certain amount of cash by sale of oil and certain financial ratios. PetroNeft Resources plc: Annual Report 2013 57 25. Financial Risk Management Objectives and Policies (continued) The expected maturity of the Group and Company’s financial assets (excluding prepayments) as at 31 December 2013 and 2012 was less than one month. The Group and the Company further mitigate liquidity risk by maintaining an insurance programme to minimise exposure to insurable losses. The Group and the Company had no derivative financial instruments as at 31 December 2013 and 2012. The tables below show the projected contractual undiscounted total cash outflows (principal and interest) arising from the Group’s trade and other payables and gross debt. These projections are based on the interest and foreign exchange rates applying at the end of the relevant years: Year ended 31 December 2013 Interest-bearing loans and borrowings – current – non-current Trade and other payables Year ended 31 December 2012 Interest-bearing loans and borrowings – current – non-current Trade and other payables Within 1 year US$ Between 1 and 2 years US$ Between 2 to 5 years US$ After 5 years US$ Total US$ 31,009,233 – 1,806,732 32,815,965 – – – – – – – – 8,238,113 945,958 8,909,830 15,516,850 945,958 – – 15,391,342 – 18,093,901 16,462,808 15,391,342 – – – – – – – – 31,009,233 – 1,806,732 32,815,965 23,754,963 17,283,258 8,909,830 49,948,051 Interest Rate Risk The Group and Company’s exposure to the risk of changes in market interest rates relates primarily to the Group and Company’s borrowings which are tied to the LIBOR interest rate and their holdings of cash and short-term deposits which are on variable rates ranging from 0.3% to 0.75%. The Macquarie loan facility had a minimum LIBOR rate of 2%, the Arawak loan has no minimum rate attached. The effect of a rise of 1% in the LIBOR interest rate (e.g. from 0.3% to 1.3%) payable on borrowings would be to increase Group loss before tax by US$152,083 and Company loss before tax by US$152,083. It is the Group and Company’s policy, as part of its disciplined management of the budgetary process, to place surplus funds on short-term deposit in order to maximise interest earned. Capital Risk Management The Group and the Company manage capital to ensure that entities in the Group will be able to continue as a going concern while maximising the return to stakeholders through the optimisation of the debt and equity balance. The Group and the Company manage their capital structure and make adjustments to it in light of changes in economic conditions. To maintain or adjust its capital structure, the Group and the Company may issue new shares or raise debt. No changes were made in the objectives, policies or processes during the years ended 31 December 2013 and 2012. The capital structure of the Group and the Company consists of equity attributable to equity holders of the Parent, comprising issued capital, reserves and retained losses as disclosed in the Consolidated Statement of Changes in Equity. Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 58 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 25. Financial Risk Management Objectives and Policies (continued) Group External borrowings Less cash and cash equivalents Less restricted cash Net debt Equity Net debt ratio Company External borrowings Less cash and cash equivalents Less restricted cash Net debt Equity Net debt ratio 2013 US$ 2012 US$ 30,000,000 (116,831) (2,054,947) 35,910,033 (3,939,422) (4,000,000) 27,828,222 27,970,611 86,059,002 98,344,192 32% 2013 US$ 28% 2012 US$ 30,000,000 (115,165) (2,054,947) 35,910,033 (3,692,037) (4,000,000) 27,829,888 93,375,376 28,217,996 141,322,390 30% 20% Fair Values The carrying amount of the Group and Company’s financial assets and financial liabilities is a reasonable approximation of the fair value. The fair value of the financial liabilities is included at the amount at which the instrument could be exchanged in a current transaction between willing parties other than in a forced or liquidation sale. The fair value of fixed and variable rate borrowings is evaluated using a discounted cash flow valuation technique using based on market interest rates which are a Level 2 observable input. Hedging At the year ended 31 December 2013 and 2012, the Group had no outstanding contracts designated as hedges. Offsetting of Financial Assets and Liabilities No financial assets and liabilities were offset in the balance sheet as at 31 December 2013 and 2012. Amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain conditions arise, and collateral received or pledged, are shown in the table below to show the total net exposure of the Group and the Company. Financial assets and liabilities recognised at 31 December 2013 Restricted cash Interest-bearing loans and borrowings – current Total Financial assets and liabilities recognised at 31 December 2012 Restricted cash Interest-bearing loans and borrowings – current Total Net amount presented in balance sheet US$ Effect of remaining rights of set-off – fair value of collateral US$ Net exposure US$ 2,054,947 (30,000,000) (27,945,053) (2,054,947) 2,054,947 – (27,945,053) – (27,945,053) Net amount presented in balance sheet US$ Effect of remaining rights of set-off – fair value of collateral US$ Net exposure US$ 4,000,000 (21,350,311) (17,350,311) (4,000,000) 4,000,000 – (17,350,311) – (17,350,311) Restricted cash is being held in a Macquarie Debt Service Reserve Account (‘DSRA’). This account is part of the security package held by Macquarie and may be offset against the loan in the event of a default on the loan or by agreement between the parties. 26. Loss of Parent Undertaking The Company is availing of the exemption set out in section 148(8) of the Companies Act 1963 and section 7(1) (A) of the Companies (Amendment) Act 1986 from presenting its individual Income Statement to the Annual General Meeting and from filing it with the Registrar of Companies. The amount of the loss dealt with in the Parent undertaking for the year was US$48,365,789 (2012: US$364,672). PetroNeft Resources plc: Annual Report 2013 59 27. Capital Commitments 27.1 Details of capital commitments at the balance sheet date are as follows: Committed for but not provided in the financial statements Including committed with related parties 2013 US$ 1,196,759 1,196,759 2012 US$ 726,359 621,027 27.2 Future minimum rentals payable under non-cancellable operating leases at the balance sheet date are as follows: Land and buildings Within one year After one year but not more than five years More than five years 2013 US$ 2012 US$ 72,485 208,656 547,268 86,221 266,527 701,710 828,409 1,054,458 28. Related Party Disclosures Transactions between PetroNeft Resources plc and its subsidiaries, Stimul-T, Granite, Dolomite and WorldAce have been eliminated on consolidation. Details of transactions between the Group and other related parties are disclosed below. Vakha Sobraliev, a Director of PetroNeft, is the principal of LLC Tomskburneftegaz (‘TBNG’) which has drilled production and exploration wells for the Group. Various contracts for drilling have been awarded to TBNG in recent years. All drilling contracts with TBNG are ‘turnkey’ contracts whereby TBNG assumes substantially all liabilities in relation to the health and safety, environmental and other risks associated with drilling operation. As part of this relationship PetroNeft Group companies also occasionally sell sundry goods and services to TBNG. Other companies related to TBNG also provide some services to the Group such as transportation, power management and repairs. The following is a summary of the transactions: Year ended Maximum value of new contracts awarded during the year Paid during the year for drilling and related services Paid during the year for other services Amount due to TBNG and related companies at year-end Received during the year for sundry goods and services Amount due from TBNG and related companies at year-end 2013 TBNG US$ – 1,527,850 – 1,962,797 49,445 6,839 Other companies US$ – – 128,416 138 – 3,283 2012 TBNG US$ 441,264 9,834,779 – 1,922,796 15,501 66,228 Other companies US$ – – 491,339 24,743 – 3,534 The Group has an indirect 50% interest in Lineynoye which in turn is 100% owned by the jointly controlled entity Russian BD Holdings B.V. Lineynoye also entered into some transactions with TBNG and related companies as follows: Year ended Maximum value of new contracts awarded during the year Paid during the year for drilling and related services Amount due to TBNG and related companies at year-end Amount due from TBNG and related companies at year-end 2013 TBNG US$ Other companies US$ 2012 TBNG US$ Other companies US$ – – – 7,968 – – – – – 1,375,582 – 8,578 – – – – The Group provided various goods and services to the jointly controlled entity Russian BD Holdings B.V. and its wholly-owned subsidiary Lineynoye during 2013 amounting to US$193,841 (2012: US$332,424). An amount of US$731,503 (2012: US$657,492) is outstanding from these entities at 31 December 2013 while an amount of US$86,972 (2012: US$18,241) is payable. Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 60 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 28. Related Party Disclosures (continued) The following transactions occurred between Lineynoye, Russian BD Holdings B.V. and the Company: At 1 January 2012 Advanced during the year Transactions during the year Interest accrued in the year Repaid during the year Translation adjustment At 1 January 2013 Advanced during the year Transactions during the year Interest accrued in the year Repaid during the year Translation adjustment At 31 December 2013 Lineynoye US$ 230,650 – – – (235,734) 5,084 – – – – – – – Russian BD Holdings B.V. US$ 58,326 631,500 118,025 17,930 (174,350) – 651,431 15,000 111,904 32,222 (96,529) 3,162 717,190 Remuneration of Key Management Key management comprise the Directors of the Company, the Vice President of Business Development and Operations, the General Director and the Executive Director of the Russian subsidiary LLC Stimul-T, along with both the Chief Geologist and Chief Engineer of LLC Stimul-T. Their remuneration during the year was as follows: Remuneration of Key Management Compensation of key management Contributions to defined contribution pension plan Share-based payment expense 2013 US$ 2012 US$ 1,799,937 40,784 258,258 1,559,195 39,382 484,718 2,098,979 2,083,295 The total amount of unpaid fees and expenses due to Directors as at 31 December 2013 was US$400,036 (2012: US$152,101). PetroNeft Resources plc: Annual Report 2013 61 28. Related Party Disclosures (continued) Transactions with Subsidiaries The Company had the following transactions with its subsidiaries during the years ended 31 December 2013 and 2012: Loans At 1 January 2012 Advanced during the year Technical and management services provided Interest accrued in the year Translation adjustment Repaid during the year At 1 January 2013 Technical and management services provided Interest accrued in the year Impairment of loans receivable and interest in the year Repaid during the year Translation adjustment Balance 31 December 2013 Capital contributions Share-based payment 2012 Share-based payment 2013 LLC Stimul-T US$ Granite Construction US$ WorldAce Investments US$ 92,673,293 2,200,000 200,744 6,943,637 996,533 (1,090,000) 101,924,207 198,750 6,767,453 (46,287,424) (5,230,000) (1,481,277) 1,447,983 – – 133,184 – – 1,581,167 – 105,375 – (650,000) – 15,902,416 9,220,360 – – 10,362 – 25,133,138 41,627 – – – 8,525 55,891,709 1,036,542 25,183,290 571,864 221,744 24,832 38,959 – – 29. Share-based Payment Share Options The expense recognised for employee services during the year is US$418,775 (2012: US$977,030). The Group share-based payment plan is described below. There was no cancellation or modification to the plan during 2013 and 2012. Under the Group share option plan, employees of the Group can receive conditional awards of share options depending on their performance, seniority and length of service. The options typically vest in tranches and are subject to the achievement of vesting conditions related to drilling, production and shareholder return. The maximum term for options is seven years. There are no cash settlement alternatives. Movement in the Year The fair value of the options is estimated at the grant date using an option pricing model considering the terms and conditions upon which the instruments were granted. The following table illustrates the number and weighted average exercise prices (‘WAEP’) of, and movements in, share options during the year. Outstanding as at 1 January Granted during the year Forfeited during the year Expired during the year Outstanding at 31 December Exercisable at 31 December 2013 Number 22,429,750 – (795,000) (3,938,000) 17,696,750 3,293,000 2013 WAEP €0.295/£0.2915 – £0.2628 €0.295 £0.2928 £0.3476 2012 Number 15,496,000 7,203,750 (270,000) – 22,429,750 7,231,000 2012 WAEP €0.295/£0.44 £0.065 £0.66 – €0.295/£0.2915 €0.295/£0.3476 The range of exercise prices for options outstanding at the year-end is £0.065 to £0.66 (2012: £0.065 to £0.66). The weighted average remaining contractual life for the share options outstanding as at 31 December 2013 was 3.99 years (2012: 4.2 years). No options were granted in 2013. The weighted average fair value of options granted during 2012 was £0.0318. The weighted average share price of forfeited options in 2013 was £0.2628 (2012: £0.66). The weighted average share price of expired options in 2013 was €0.295. No options expired in 2012. Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 62 NOTES TO THE FINANCIAL STATEMENTS (CONTINUED) FOR THE YEAR ENDED 31 DECEMBER 2013 29. Share-based Payment (continued) As no options were issued in 2013, no valuation was carried out in 2013. The following table lists the inputs to the model used for options granted during the year ended 31 December 2012: Grant date Vesting conditions Dividend yield Expected volatility Risk-free interest rate Expected life of option Expected early exercise % Share price at date of grant Exercise price at date of grant Model used 2012 November Share price growth-based 0% 70% n/a 7 n/a £0.051 £0.065 Bespoke partial differential equation model The expected life of the options is based on the expectation of management and is not necessarily indicative of exercise patterns that may occur. The expected volatility estimate used in the valuation has been calculated based on the historical volatilities of the Company’s share price over various historical periods, weighing the historical volatility over period commensurate with the expected term of the options. The fair value is measured at the grant date. Warrants Where applicable, the fair value of the warrants is estimated at the grant date using an option pricing model considering the terms and conditions upon which the instruments were granted. The table included in Note 24 illustrates the number and weighted average exercise prices (‘WAEP’) of, and movements in, warrants during the year. In August 2012, Macquarie were awarded 3,400,000 new warrants, and all warrants granted in prior years (6,700,000 warrants) were re-priced. On the basis that Macquarie committed significant technical, engineering and legal resources to negotiating and agreeing the loan facility and subsequent draw downs, all warrants granted to Macquarie in prior years were in lieu of arrangement fees. The costs of the warrants fall within the scope of IFRS 2 Share-based Payment. This share-based payment expense constitutes a transaction cost under IAS 39 Financial Instruments: Recognition and Measurement and is included in the initial carrying amount of the loan facility and amortised over the duration of the loan. The new 3,400,000 warrants granted to Macquarie in August 2012 were granted as a facilitation fee and were accounted for as a transaction fee in accordance with IFRS 2. The charge associated with these new warrants of US$0.1 million was applied against the loan. The original costs of the re-priced warrants were largely expensed at the time of re-pricing. The incremental costs of US$0.1 million between the fair value of original award re-calculated at the re-pricing date in August 2012 and the fair value of the re-priced warrants were applied against the loan. The range of exercise prices for warrants outstanding at the year-end is £0.085 to £0.086 (2012: £0.082 to £0.086). The weighted average remaining contractual life for the warrants outstanding as at 31 December 2013 was 1.31 years (2012: 1.59 years). No warrants were granted in 2013. The weighted average fair value of warrants granted in 2012 was £0.03. The following table lists the inputs to the models used for valuing warrants which have been accounted for under IFRS 2: Dividend yield Expected volatility Risk-free interest rate Expected life of warrant Share price at date of grant Exercise price Model used 2012 0% 70% 0.809% 2.53 £0.0575 £0.0845 Binomial The expected life of the warrants is based on the expectation of management and is not necessarily indicative of exercise patterns that may occur. The expected volatility estimate used in the valuation has been calculated based on the historical volatilities of the Company’s share price over various historical periods, weighing the historical volatility over period commensurate with the expected term of the options. The fair value is measured at the grant date. 30. Important Events after the Balance Sheet Date On 17 March 2014, the Company announced a US$6.7 million fund raise consisting of US$5.2 million of new equity and an additional US$1.5 million loan from Arawak Energy. The purpose of this funding was to fund the purchase of supplies during the winter period in Russia in order that once the funding situation was fully solved the drilling programme could re-commence. On 17 April 2014, the Company entered into a legally-binding agreement with Oil India Limited for the Licence 61 Farmout, more details of which are included in Note 2. 31. Approval of Financial Statements The financial statements were approved, and authorised for issue, by the Board of Directors on 26 June 2014. PetroNeft Resources plc: Annual Report 2013 NOTICE OF ANNUAL GENERAL MEETING 63 Notice is hereby given that the Annual General Meeting of PetroNeft Resources plc will be held at the Herbert Park Hotel, Ballsbridge, Dublin 4 at 11.00 am on Friday 29 August 2014, for the purposes of considering and, if thought fit, passing, the following Resolutions, of which Resolutions numbered 1, 2, 3, 4, 5 and 6 will be proposed as Ordinary Resolutions and Resolutions numbered 7 will be proposed as a Special Resolution. ORDINARY BUSINESS 1. To receive, consider and adopt the accounts for the year ended 31 December 2013 together with the Directors’ and Auditors’ Reports thereon. 2. To re-elect Mr. Golder as a Director, who retires by rotation in accordance with Article 83 of the Articles of Association of the Company. 3. To re-elect Mr. Dowling as a Director, who retires by rotation in accordance with Article 83 of the Articles of Association of the Company. 4. To re-elect Mr. Fagan as a Director, who retires by rotation in accordance with Article 83 of the Articles of Association of the Company. 5. To re-appoint Ernst & Young, Chartered Accountants, as Auditors and to authorise the Directors to fix the remuneration of the Auditors. SPECIAL BUSINESS 6. That the authorised share capital of the Company be and is hereby increased from €8,000,000 divided into 800,000,000 Ordinary Shares of €0.01 each to €10,000,000 by the creation of 200,000,000 new Ordinary Shares of €0.01 ranking equally in all respects with the other existing issued and unissued Ordinary Shares of €0.01 each. 7. That, in substitution for all existing authorities of the Directors pursuant to Section 20 of the Companies (Amendment) Act, 1983, the Directors be and are hereby generally and unconditionally authorised pursuant to Section 20 of the Companies (Amendment) Act, 1983 to exercise all the powers of the Company to allot relevant securities (within the meaning of the said Section 20) up to a maximum amount equal to the aggregate nominal value of the authorised but unissued share capital of the Company as at the date of passing of this Resolution. The authority hereby conferred shall expire (unless previously renewed, varied or revoked by the Company in general meeting) on the earlier of the date of the next Annual General Meeting of the Company held after the date of passing of this Resolution, and the close of business on 29 November 2015, save that the Company may before such expiry make an offer or agreement which would or might require relevant securities to be allotted after such expiry and the Directors may allot relevant securities in pursuance of such offer or agreement notwithstanding that the authority hereby conferred has expired. 8. That the Directors be and are hereby empowered pursuant to Sections 23 and 24 (1) of the Companies (Amendment) Act, 1983 to allot equity securities (within the meaning of the said Section 23) for cash pursuant to the authority conferred by Resolution numbered 7 above as if the said Section 23 does not apply to any such allotment provided that this power shall be limited to the allotment of equity securities: a) in connection with the exercise of any options or warrants to subscribe granted by the Company; b) (including, without limitation, any shares purchased by the Company pursuant to the provisions of the Companies Act 1990 and held as treasury shares) in connection with any offer of securities, open for a period fixed by the Directors, by way of rights, open offer or otherwise in favour of shareholders holding Ordinary Shares and/or any persons having a right to subscribe for, or convert securities into, Ordinary Shares in the capital of the Company (including, without limitation, any person entitled to options under any of the Company’s share option schemes or any other person entitled to participate in any of the Company’s profit sharing schemes for the time being) and subject to such exclusions or other arrangements as the Directors may deem necessary or expedient in relation to legal or practical problems under the laws or the requirements of any recognised body or stock exchange in any territory; and c) up to an aggregate nominal value equal to the nominal value of 10% of the issued share capital of the Company from time to time; each of (a), (b) and (c) above being separate powers, which powers shall expire on the earlier of the date of the next Annual General Meeting of the Company held after the date of passing of this Resolution and the close of business on 29 November 2015, save that the Company may before such expiry make an offer or agreement which would or might require equity securities to be allotted after such expiry and the Directors may allot equity securities in pursuance of such offer or agreement as if the power conferred hereby had not expired. 26 June 2014 BY ORDER OF THE BOARD David Sanders Company Secretary Registered Office: 20 Holles Street Dublin 2 Review of the YearGovernanceFinancial StatementsPetroNeft Resources plc: Annual Report 2013 64 GLOSSARY 1P 2P 3P AGM AIM AMI Arawak bbl Belgrave Naftogas bfpd boe bopd Company CPF CSR Custody Transfer Point ESM Exploration resources Group HSE IAS IFRIC IFRS km km2/sq km KPI Licence 61 Licence 61 Farmout Licence 67 Lineynoye Macquarie m mmbbls mmbo Oil pay P1 P2 P3 Pervomayka PetroNeft Russian BD Holdings B.V. SPE Spud Stimul-T TSR VAT WAEP WorldAce Proved reserves according to SPE standards. Proved and probable reserves according to SPE standards. Proved, probable and possible reserves according to SPE standards. Annual General Meeting. Alternative Investment Market of the London Stock Exchange. Area of Mutual Interest. Arawak Energy Russia B.V. Barrel. Belgrave Naftogas B.V., a member of the Arawak group of companies. Barrels of fluid per day. Barrel of oil equivalent. Barrels of oil per day. PetroNeft Resources plc. Central Processing Facility. Corporate and Social Responsibility. Facility/location at which custody of oil transfers to another operator. Enterprise Securities Market of the Irish Stock Exchange. An undrilled prospect in an area of known hydrocarbons with unequivocal four-way dip closure at the reservoir horizon. The Company and its subsidiary undertakings. Health, Safety and Environment. International Accounting Standard. IFRS Interpretations Committee. International Financial Reporting Standard. Kilometres. Square kilometres. Key Performance Indicator. The Group’s Exploration and Production Licence in the Tomsk Oblast, Russia. It contains seven known oil fields, Lineynoye, Tungolskoye, West Lineynoye, Arbuzovskoye, Kondrashevskoye, Sibkrayevskoye and North Varyakhskoye and 27 Prospects and Leads that are currently being explored. An agreement whereby Oil India Limited will subscribe for shares in WorldAce, the holding company for Stimul-T, the entity which holds Licence 61 and all related assets and liabilities, and following, PetroNeft and Oil India Limited will both hold 50% of the voting shares, and through the shareholders agreement, both parties will have joint control of WorldAce with PetroNeft continuing as operator. The Group’s Exploration and Production Licence in the Tomsk Oblast, Russia. It contains two oil fields, Ledovoye and Cheremshanskoye and several potential prospects. Limited Liability Company Lineynoye, a wholly owned subsidiary of Russian BD Holdings B.V., registered in the Russian Federation. Macquarie Bank Limited. Metres. Million barrels. Million barrels of oil. A formation containing producible hydrocarbons. Proved reserves according to SPE standards. Probable reserves according to SPE standards. Possible reserves according to SPE standards. Limited Liability Company Pervomayka, a wholly owned subsidiary of PetroNeft, registered in the Russian Federation. PetroNeft Resources plc. Russian BD Holdings B.V., a company owned 50% by PetroNeft and registered in the Netherlands. Society of Petroleum Engineers. To commence drilling a well. Limited Liability Company Stimul-T, a wholly owned subsidiary of PetroNeft, based in the Russian Federation. Total Shareholder Return. Value Added Tax. Weighted Average Exercise Price. WorldAce Investments Limited, a wholly owned subsidiary of PetroNeft, registered in Cyprus. PetroNeft Resources plc: Annual Report 2013 GROUP INFORMATION Directors1 David Golder (U.S. citizen) (Non-Executive Chairman) Dennis Francis (U.S. citizen) (Chief Executive Officer) Paul Dowling (Chief Financial Officer) David Sanders (U.S. citizen) (General Legal Counsel) Gerard Fagan (Non-Executive Director) Thomas Hickey (Non-Executive Director) Vakha Sobraliev (Russian citizen) (Non-Executive Director) Registered Office and Business Address 20 Holles Street Dublin 2 Ireland Secretary David Sanders Auditor Nominated and ESM Adviser Joint Brokers Ernst & Young Chartered Accountants Harcourt Centre Harcourt Street Dublin 2 Ireland Davy 49 Dawson Street Dublin 2 Ireland Davy 49 Dawson Street Dublin 2 Ireland 1 Irish citizens unless otherwise stated. Canaccord Genuity 88 Wood Street London EC2V 7QR United Kingdom Principal Bankers Macquarie Bank Limited AIB Bank 1 Lower Baggot Street Dublin 2 Ireland 4 Romanov Pereulok 125009 Moscow Russia Ropemaker Place 28 Ropemaker Street London EC2Y 9HD United Kingdom KBC Bank Ireland Sandwith Street Dublin 2 Ireland Eversheds One Earlsfort Centre Earlsfort Terrace Dublin 2 Ireland White & Case 5 Old Broad Street London EC2N 1DW United Kingdom 408101 Computershare Heron House Corrig Road Sandyford Industrial Estate Dublin 18 Ireland Solicitors Registered Number Registrar P e t r o N e f t R e s o u r c e s p l c A n n u a l R e p o r t 2 0 1 3 PetroNeft Resources plc Dublin Office 20 Holles Street Dublin 2 Ireland Houston Office Suite 518, 10333 Harwin Drive Houston, TX 77036 USA www.petroneft.com