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 2 PetroNeft Resources plc Annual Report 2012 Годовой Отчет 2012 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 Financial Highlights 2,204 bopd Average production. 131 mmbbls Group 2P reserves. US$34.6m Revenue US$34.6 million. Gross Profit US$4.4 million. US$14.27m Capital Expenditure of US$14.27 million. Second Licence 61 oil field brought into production at Arbuzovskoye. US$15.0m New US$15 million loan facility with Arawak Energy – May 2012. Six new production wells and a water injection well drilled at Arbuzovskoye. US$17.2m Share placing of US$17.2 million – October 2012. Comprehensive Seismic and Well reinterpretation on Licence 61 shows additional potential at Tungolskoye, Sibkrayevskoye, Emtorskaya, and Traverskaya. US$8.5m Debt to Macquarie Bank decreased by US$8.5 million – November 2012. US$28.0m Net debt at US$28.0 million. Oil storage facility at Lineynoye. Overview 02 Producing Oil from a Solid Asset Base 04 Licence 61 06 Licence 67 07 Our Reserves Review of the Year 08 Chairman’s Statement 10 Chief Executive Officer’s Report 14 Health, Safety and Environmental Report 15 Financial Review 17 Principal Risks and Uncertainties Governance 18 Board of Directors 20 Directors’ Report 24 Independent Auditor’s Report Financial Statements 25 Consolidated Income Statement 25 Consolidated Statement of Comprehensive Income 26 Consolidated Balance Sheet 27 Consolidated Statement of Changes in Equity 28 Consolidated Cash Flow Statement 29 Company Balance Sheet 30 Company Statement of Changes in Equity 31 Company Cash Flow Statement 32 Notes to the Financial Statements 59 Notice of Annual General Meeting 60 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. 02 Producing Oil from a Solid Asset Base History 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. Strategy 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. The objective is to acquire new Core Exploration and Production Areas that satisfy the Group’s strict technical and legal evaluation criteria. While the main focus for new acquisitions will be the West Siberian Basin, the Company will also consider projects in other areas within the Russian Federation. Our Assets The main assets of the Company are a 100% 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. Russia Moscow Tomsk Scale 0 1,000 km Licence 61 Licence 61 contains seven known oil fields: Lineynoye, Arbuzovskoye, Sibkrayevskoye, Tungolskoye, West Lineynoye, Kondrashevskoye and North Varyakhskaya and over 25 exploration prospects and leads. “The near-term objective is to bring the existing discovered fields into production utilising the substantial infrastructure already in place.” Page More information see page 04 PetroNeft Resources plc: Annual Report 2012 03 Tomsk Oblast Licence 67 50% Licence 61 100% Key: PetroNeft Rosneft Gazprom Gazpromneft ONGC (Imperial Energy) Other Oil Pipeline Gas Pipeline All-weather Road Scale Tomsk Scale 0 100 km Licence 67 Licence 67 contains the Cheremshanskoye and Ledovoye oil fields and numerous prospects and leads. Scale 0 12 km Page More information see page 06 Scale 0 20 km PetroNeft Resources plc: Annual Report 2012 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 Oil field Prospect ready for drilling Prospect identified Potential prospects Pipeline 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 Structure Map on Base Bazhenov Horizon Arbuzovskoye Field Development Second oil field brought to year-round production. Arbuzovskoye Pad Facilities are a template for future field development and tie-back to Lineynoye CPF. Lineynoye Central Processing Facility • Capacity – 14,800 bfpd • Storage Capacity – 37,740 bbls • Gas Power Generation – 3.350 MW • Diesel Backup Power Generation – 1.0 MW • Export Pipeline Capacity – 20,000 bopd – Length 60 km – Diameter 273 mm • Lineynoye Camp – up to 60 people Scale 0 2 km L-3 L-8 L-9 Arbuzovskoye Pad 1 Facilities A-1 • Well Test Separator Module • Water Injection Manifold Module • Transformer Station • ESP Control Modules • Pipeline to Lineynoye – Length 10 km – Diameter 273 mm • Camp – up to 16 people Pipeline Utility line Emtorskaya High L-5 L-7 212 211 Lineynoye Oil Field L-1 L-4 L-6 K-2 K-2s K-1 NV-1 Arbuzovskoye Oil Field A-1 A-2 Structure Map on Base Bazhenov Horizon PetroNeft Resources plc: Annual Report 2012 05 Sibkrayevskoye oil field development planning Largest ever discovery by PetroNeft. Major discovery expected on-stream by 2015 utilising Arbuzovskoye tie-back template. Sibkrayevskoye S-371 Proposed S-373 S-372 S-370 History • 50 km2 structure in the Northeast of the licence • Three wells were drilled on the field to date • S-370 (1972) reinterpreted in 2008 identified potential missed pay in the Upper Jurassic J1 interval • S-371 drilled off structure • S-372 (2011) twinned well S-370 was drilled by PetroNeft – logs confirm >10m of net pay and inflow of 170 bopd achieved in open hole flow test PetroNeft is planning: • Well S-373 with rig currently stocked and on location • Additional 2D Seismic acquisition for 2013/14 • Development decision in 2014 • Drill Pad 1 and install pipeline and utility line to CPF in 2015 • Pilot Production Licence anticipated for 2015 – leading to full field development upon success • Will be tied back to Lineynoye CPF • Water injection for pressure maintenance Scale 0 E-300 6 km Proposed E-304 Emtorskaya High E-303 N. Varyakhskoye L-5 L-7 212 NV-1 Lineynoye L-1 Arbuzovskoye L-6 L-4 L-2 A-1 K-2 K-2s Kondrashevskoye K-1 Structure Map on Base Bazhenov Horizon Emtorskaya Prospect Large prospect de-risked by Lineynoye drilling. • As a result of Lineynoye Pad 1 and Pad 2 drilling the oil-water-contact was determined to be below the previously interpreted spill point and that Lineynoye and Emtorskaya are one continuous oil field at the J1-1 interval. Emtorskaya is both larger in area and higher structurally than Lineynoye • Emtorskaya wells 300 and 303 were reinterpreted and oil was confirmed in the J1-1 interval and potentially in the J1-2 interval • The reserves associated with this play could be large, > 40 million bbls for just the J1-1; however, the J1-1 is usually only around 2 metres in thickness and it is difficult to develop on its own. Further delineation will be required to confirm those areas where a thicker J1-2 sandstone is present below the J1-1 interval • Emtorskaya well 304 located on the crest of the high is proposed. This well is about 65 m higher than the Lineynoye field at the J1-1 level Scale 0 2 km E-300 Emtorskaya High E-304 E-303 L-3 L-8 L-9 L-7 L-5 212 211 Lineynoye Oil Field L-4 L-6 L-1 L-2 NV-1 Arbuzovskoye Oil Field A-1 Structure Map on Base Bazhenov Horizon PetroNeft Resources plc: Annual Report 2012 06 Licence 67 Successful two well programme completed in 2012. 2011/2012 Work Programme 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). It is important to note that both wells were drilled parallel to existing wells in order to optimise the coring and testing of potential by-passed pay zones identified in the vintage wells drilled in 1962 and 1973 respectively. 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. What next? The next step at Licence 67 is likely to be the acquisition of additional 2D seismic. A plan to acquire 750 km of new 2D seismic to be acquired, funds permitting, in early 2014. Exploration drilling rig at Ledovoye. 15 2 6 7 5 9 8 10 1 14 11 13 4 3 12 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. 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 Scale 0 20 km PetroNeft Resources plc: Annual Report 2012 Our Reserves Year-round production commenced in 2010. Since acquiring Licence 61 in 2005, Group proved and probable reserves have grown by 372% to 131 mmbbls. 07 2P Reserve Growth 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. 131m 131 million barrels of 2P reserves Million barrels 140 120 100 80 60 40 20 27.89 9.34 18.55 33.34 15.61 17.93 Ledovoye North Varyakhskoye Sibkrayevskoye Arbuzovskoye Kondrashevskoye West Lineynoye Lineynoye Tungolskoye 96.93 14.02 13.24 8.12 23.32 70.00 8.11 23.30 23.82 22.74 60.62 28.82 16.32 131.70 131.07 14.02 1.93 49.83 14.02 1.95 53.03 13.29 4.96 32.10 6.54 4.98 30.81 19.74 15.48 14.77 15.48 15.57 0 2005 2006 2007 2008/09 2010 2011 2012 3P Reserves and Exploration Resources (P4) Growth 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. Million barrels 700 600 500 400 300 200 100 0 640.69 156.17 100.41 384.11 531.3 156.17 63.06 312.07 324.21 350.00 183.62 2005 2006 2007 2008/09 2010-12 Cretaceous Middle/Lower Jurassic Upper Jurassic PetroNeft Resources plc: Annual Report 2012 08 Chairman’s Statement 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 once the necessary funding is available. David Golder Non-Executive Chairman A Challenging Year 2012 was a difficult year for the Group. Exploration discoveries and operational successes like the pressure maintenance programme at Pad 1 in the Lineynoye oil field and the development of our second producing field at Arbuzovskoye were unable to fully compensate for the poor results from the previous year’s drilling on Pad 2 at Lineynoye. As a result production and cash flows were lower than expected causing issues with our Macquarie debt facility that impeded our ability to fund drilling and workover programmes at the pace required to offset the production shortfall. Operations The Pad 1 wells which were drilled in 2010 have responded well to the pressure maintenance programme that we initiated in June 2011 and production here is stable with minimal decline. In the first quarter of 2012 we constructed a ten kilometre pipeline and utility line to connect the Arbuzovskoye oil field to the central processing facilities at Lineynoye. The Arbuzovskoye No. 1 exploration well was brought into production through the pipeline in May 2012 and production drilling commenced in August 2012 with good results achieved in the wells drilled to date. The Chief Executive Officer’s report details much of the innovative work that has been done to move forward with the development at Arbuzovskoye and understand the problem at Pad 2 so that it could be remedied and avoided in the future. It has been determined that there was a deterioration in rock quality and oil saturation as we got lower structurally in the Pad 2 area, which cannot be effectively remediated. In our other discovered fields we should be able to avoid this issue as most of our reserves are located higher structurally than the existing wells that have been tested successfully. Reserves In early 2012 the Company successfully completed the last exploration well on Licence 67 from the 2011 programme at the Ledovoye oil field where two oil pools were encountered. At Licence 61 we carried out a project to reinterpret the seismic data in the central to northern end of the licence area 1 1. Arbuzovskoye Production drilling rig at Arbuzovskoye. 2. Lineynoye Processing Facility Daily meeting of technical personnel at Lineynoye Central Processing Facility. PetroNeft Resources plc: Annual Report 2012 09 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 2012 was a challenging year operationally and in the overall market, shareholders should not lose sight of the 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 once the necessary funding is available. 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 through the past year. David Golder Non-Executive Chairman using the most up to date well information and more modern software since the last remapping in 2007. It shows that the southern end of Arbuzovskoye appears to be slightly smaller than previously interpreted and that both Tungolskoye and Sibkrayevskoye appear to be larger than previously interpreted. 2 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 stand at 117 million barrels, essentially unchanged from the previous assessment. This, combined with the portfolio of undrilled but seismically-defined structures in the north and south of Licence 61, confirms the Group’s strong reserve base. Ryder Scott did not update the reserves in Licence 67 as further work is required to establish the full potential of this Licence. Studies are now underway to better define the three new oil pools discovered at Cheremshanskoye and two oil pools at Ledovoye. Finance In May 2012, PetroNeft signed a three-year loan agreement with Arawak Energy Russia B.V. (‘Arawak’) for US$15 million. The loan is secured on PetroNeft’s 50% interest in Licence 67 and will be repayable in one lump sum at the end of the three-year loan period in May 2015. The interest payable under the loan is LIBOR plus 6%, a competitive rate given present market conditions. Under the terms of the loan PetroNeft also granted Arawak 4,000,000 warrants over shares at a strike price of US$0.1345 per share. In October 2012 we secured additional equity funding from shareholders of US$17.2 million including some substantial new shareholders. We also agreed to amend the Company’s existing borrowing base loan facility with Macquarie Bank Limited. The amendments to the facility included the repayment of US$7.5 million from the proceeds of the equity funding, the repayment of a further US$9.1 million in 14 monthly instalments (US$650,000 per month) beginning on 31 March 2013 and the conversion of US$1 million of debt into equity in the Company at the placing price of 5 pence per share. The monthly repayments have now commenced and are being made from our own resources. The commencement of monthly repayments to Macquarie does limit the Group’s operational and financial flexibility. Therefore we have been seeking to strengthen the Group’s position by either bringing in a partner to help fully develop and explore Licence 61 or arranging a debt facility more suited to our needs over the coming years. Discussions on both fronts are continuing at pace and I hope that we can close on one or other of these options in the coming months. The financial review and Note 2 to the consolidated financial statements discuss the funding situation of the Group in more detail. Business Development The principal near-term objective of the Group remains the development of the northern oil fields on Licence 61 leveraging the infrastructure put in place in recent years. However, we have not lost sight of our longer-term objective of securing assets outside of Licence 61 to provide growth for the future. The acquisition of Licence 67 (Ledovy) in January 2010 was a first step in this growth. Licence 67 was acquired under the August 2008 Area of Mutual Interest (‘AMI’) with Arawak where they have exercised their right to acquire 50% of the Licence. Licence 67 has now provided collateral in the new US$15 million debt financing with Arawak. Also, PetroNeft entered into a new three-year AMI with Arawak in May 2012. Under the agreement the two companies will continue to jointly pursue new opportunities in Western Siberia, building on the success of the previous AMI agreement. 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 170 employees. I would like to thank all of our employees for their dedication and their hard work in 2012. Summary With the Arbuzovskoye, Sibkrayevskoye and Tungolskoye oil fields the Group 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. This is an attractive proposition for a new partner or financier with a long-term view and 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. PetroNeft Resources plc: Annual Report 2012 10 Chief Executive Officer’s Report We are now focused on developing Arbuzovskoye and seeking to build on our existing production profile and positive cash flows as well as obtaining funding through either a farmout or debt refinancing in order to allow us to fully realise the Groups potential. Licence 61 has a large amount of discovered reserves that have not yet been brought into production and already has the infrastructure in place to handle this production. Dennis Francis Chief Executive Officer General 2012 was a tough year for the Group. While we had good success in bringing the Arbuzovskoye oil field into production, the poor results from Pad 2 at Lineynoye led to financial pressures that meant we could not progress at the speed we would have wished. Arbuzovskoye is the second field we have brought into year-round production which included the construction of tie-in infrastructure and drilling of new production wells. We are happy with the results at Arbuzovskoye to date and at the way the Lineynoye Pad 1 wells are performing as a result of good well management and water flood performance. We produced 806,761 barrels of oil (2011: 748,079 barrels) in the year or an average of 2,204 bopd (2011: 2,050 bopd). At Licence 67 we completed the two well exploration programme early in 2012 and this licence shows promise for the future. Licence 61 Highlights • Construction of a 10 km pipeline and utilities line from Lineynoye to Arbuzovskoye. • Drilling of new production wells at Arbuzovskoye. • Extensive seismic re-interpretation project for central and northern area of licence. Licence 67 Highlights • In February 2012 oil was confirmed in the primary Upper Jurassic objective at Ledovoye oil field along with a potential new oil pool in the secondary Lower Cretaceous interval. Licence 61 (Tungolsky) Licence 61 – Lineynoye Development The wells at Pad 1 at Lineynoye have performed well during 2012 and early 2013 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 manage pump settings, replace pumps and in some cases carry out acid washes on both production and injection wells to improve or maintain production. We have seen little decline here over the last 12 months. 1 1. Oil Storage Almost 40,000 barrels of oil storage in place at Lineynoye Central Processing Facility. 2. Oil Measurement Well test separator conducts daily testing of oil wells and is part of the standard kit at each production drilling pad. PetroNeft Resources plc: Annual Report 2012 11 2 Unfortunately the results from the Pad 2 wells have been very disappointing. The initial response from the fracture stimulation carried out in late 2011 was positive and the field peaked at 3,000 bopd in December 2011; however, production from Pad 2 wells decreased rapidly and the water cut was very high at over 80% in many cases compared to less than 15% at the Pad 1 wells after more than two years of production. As the Pad 2 wells did not perform nearly as well as those on Pad 1, we commenced a number of studies on the Pad 2 wells, including a field wide pressure transient test of individual wells in order to understand the difference in results. The pressure transient tests did not indicate that the issue was caused by an unusual pressure decline in the field. All of the Pad 2 wells were lower on the structure than the Pad 1 wells, the reservoir section was closer to the oil-water-contact and the oil saturation in the wells was lower. This resulted in higher water cuts in the wells than expected, in part due to the lower oil saturations, and the combination of relative permeability and fractional flow effects in the reservoir. Core analysis that had been carried out on exploration/delineation wells had indicated that the lower oil saturations that we encountered at Pad 2 wells should not have been an issue and that oil should still have dominated the flow. This clearly hasn’t been the case and it is likely because of the poorer rock properties in Pad 2 as compared to Pad 1. These problems can be avoided in the future by drilling higher on the structures and avoiding potential oil and water zones. More extensive testing and coring of the production wells will also be carried out in the future. The 2011 drilling results confirmed that the Lineynoye and West Lineynoye structures are one oil field. In order to fully assess the potential and determine the timing of future development we plan to drill an L-9 well in the western end of the Lineynoye field in 2013, funds permitting. Licence 61 – Arbuzovskoye Development In early 2012 we constructed a 10 km pipeline and utility line from the Lineynoye Central Processing Facilities to Arbuzovskoye and mobilised the drilling rig and supplies to drill up to ten new production wells. The discovery well (Arbuzovskoye No. 1) commenced production through the pipeline in May 2012 at a rate of 350 bopd. Drilling of new 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 also drilled a water source well in early 2013. In April 2013 we converted one oil production well into a water injection well as we had started to see some normal pressure decline in the field and wanted to arrest/slow that decline as soon as possible. It will take a number of months to see the benefit of the water injection at which stage we will be in a better position to select the next well locations. It is likely we will drill at least three more wells 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. The Arbuzovskoye development was the first outlying field to be developed and tied back to the Lineynoye Central Processing Facilities. It will act as a design template for future developments such as Sibkrayevskoye and Tungolskoye which will be tied back to the Central Processing Facility which will act as a hub for processing oil produced from oil fields in the northern end of the licence. Pipeline and utility lines were installed at a cost of about US$230,000 per kilometre and the construction of the pad and the associated accommodation and facilities cost about US$1 million. Based on this model future developments can be simple and cost effective with minimal infrastructure costs because of the substantial infrastructure already in place. Licence 61 – Exploration and Delineation In 2012 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, reprocessed 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 reprocessed and reanalysed. The study utilised more modern software and techniques than were used in 2007 and has significantly improved our understanding of the area. Arbuzovskoye The results of this study have led to the narrowing of the estimated structure in the southern end of the Arbuzovskoye oil field which will lead to fewer wells being required here and has impacted on the total reserve estimate of the Arbuzovskoye oil field. Tungolskoye At Tungolskoye oil field the structure appears larger than previously estimated and confirms that much of the reserves are located structurally higher than the previous wells drilled there which means that we should not encounter the same problems as encountered at Pad 2 Lineynoye. Based on this new information we have selected a location for a delineation well, Tungolskoye No. 5, which we would like to drill in 2014. Assuming this well comes in close to prognosis we could quickly proceed with the Tungolskoye development. Sibkrayevskoye The study also indicates that the Sibkrayevskoye oil field is larger than previously estimated, however, we did not ask Ryder Scott to take this into account in their new reserve update 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 373 location together with the necessary supplies to drill the well. It is our intention, funding permitting, to drill this well later in 2013. 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 so we should be able to avoid the issues encountered at Pad 2. We have selected a location for a new exploration well here which may be drilled in 2014 or 2015. While we are acquiring more seismic data for the Sibkrayevskoye oil field we will also acquire some infill lines over the large PetroNeft Resources plc: Annual Report 2012 12 Chief Executive Officer’s Report (continued) 1. Pumping Oil Pump house for pumping oil through 60 km pipeline to Kiev-Eganskoye. The capacity of 20,000 bopd could be increased simply by adding additional pumps. 2. Power Generation Control Station We generate our own power with gas fired generators using the associated gas produced with our oil. 1 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 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 now stand at 117.1 mmbbls a reduction of 0.5%. The net reduction arises from production of just over 1 mmbbls since the last report, a reduction at Arbuzovskoye because of net pays in some wells drilled in 2012 being slightly thinner than expected and the narrowing of the potential structure to the southern end of Arbuzovskoye. The previous year’s assessment by Ryder Scott had already taken into account the results of Pad 2 at Lineynoye. There were increases at Tungolskoye because of the potential structure becoming larger as a result of the new mapping and at Sibkrayevskoye as last years’ report had cut-off reserves at the end of the licence period in 2030. Because we have an automatic right to extend the licence, we are entitled to count reserves for the economic life of the field. As a result of the new report on Licence 61, total Proved and Probable (2P) reserves net to PetroNeft have fallen by 0.5% from 131.7 mmbbls to 131.1 mmbbls. Total Proved reserves (P1) have increased by 8.5% from 20.0 mmbbls to 21.7 mmbbls. 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 reprocessed and the results of this evaluation were used to select the location of two exploration wells and will be used to assess where to acquire the 750 km of new seismic data required to be completed under the licence terms. 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). Both wells were drilled parallel to existing wells in order to optimise the coring and testing of potential by-passed pay zones identified in the vintage wells drilled in 1962 and 1973 respectively. During 2012 we have been reviewing both results and it is clear that in both cases further work is required in order to assess these structures. The most likely next step is the acquisition of some more seismic data particularly at Cheremshanskoye and we are in discussions with our partner, Arawak, to agree the best way forward. Arawak Area of Mutual Interest (‘AMI’) On 30 May 2012, PetroNeft entered into a new three-year AMI with Arawak Energy a subsidiary of Vitol, one of the world’s largest independent energy trading companies. Under the agreement the two companies will continue to jointly pursue new opportunities in Western Siberia, building on the success of the previous AMI agreement that ran for three years to August 2011. Under the previous AMI, Arawak opted to take a 50% interest in Licence 67 which was acquired by PetroNeft in January 2010. Potential Farmout of Licence 61 In order to continue the development and exploration of this large licence we need to strengthen the Group’s financial position. In consultation with major shareholders and finance providers we have concluded that a farmout of up to 50% of Licence 61 while remaining as operator could represent the best way to achieve this goal. In that regard we have 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 have set up an extensive electronic data room and are in detailed discussions with a number of potential partners and hope these discussions will come to fruition in the coming months. We are also in discussions with a number of Russian and international banks with a view to re-financing the existing debt facilities but, assuming we can get the right offer, the farmout is the preference of the Board of Directors. 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 14. PetroNeft Resources plc: Annual Report 2012 13 reserves that have not yet been brought into production and already has the infrastructure in place to handle this production. This is a key attraction for potential partners as well as the significant exploration upside. 2 We have learned valuable lessons this past year and have taken a more deliberate approach with additional coring, testing and high grading of the production wells prior to fracture stimulation. We have an excellent and determined workforce and a good asset base. We are confident that we can find the right solution for the Company and its shareholders to realise the inherent value of our reserves. Dennis Francis Chief Executive Officer Personnel The Group made one important senior management appointment in early 2012. In March, Dmitry Shelkovnikov, who has worked with us since 2006, was appointed to the Group as Chief Engineer having previously been Chief Drilling engineer and Chief of Production for LLC Stimul-T. Dmitry has over ten years’ experience in the development of oil and gas fields in the Tomsk region. He has advanced degrees from Tomsk Polytechnic University in the drilling of oil and gas wells and the design, construction and operation of oil and gas infrastructure. Conclusion While we are pleased we brought a second oil field into production in 2012, regrettably this success has been overshadowed by the production results from Pad 2 and the consequent financial constraints that have since slowed the Group’s development. However, we have overcome technical challenges, continued to build our knowledge of our licences and through applying advanced techniques and data analysis better understand our oil field structures and as such, have better positioned ourselves to return the Group to growth from the many opportunities that lie in our licenses. We are now focused on developing Arbuzovskoye and seeking to build on our existing production profile and positive cash flows as well as obtaining funding through either a farmout or debt refinancing in order to allow us to fully realise the Groups potential. Licence 61 has a large amount of discovered Ryder Scott Estimated Reserves in Oil Fields (net to PetroNeft) Oil Field Name Licence 61 Lineynoye Tungolskoye Kondrashevskoye Arbuzovskoye Sibkrayevskoye North Varyakhskoye Licence 67 Ledovoye Total net to PetroNeft Proved 1P mmbo 8.9 2.7 1.8 2.3 3.7 0.8 20.2 1.5 21.7 Proved & Probable Proved, Probable & Possible 2P mmbo 30.9 19.7 5.0 6.5 53.0 1.9 3P mmbo 39.6 24.7 6.2 8.2 67.3 2.4 117.0 148.4 14.0 131.0 17.4 165.8 • Licence 61 as at 1 April 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. PetroNeft Resources plc: Annual Report 2012 14 Health, Safety and Environmental Report 1. Safety Sign Safety warning sign at Lineynoye. 2. Environmentally Responsible Part of the continual efforts to restore and replant at our various sites. 1 2 Licence 61 in advance of any major works. A similar 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 activities. • Monitoring activities of sub-contractors. • Maintaining compliance with various environmental laws and regulations. In 2012 the main activities from an environmental perspective were: • Environmental and subsoil monitoring at Lineynoye and Arbuzovskoye oil fields. • Planning and approvals for 2012 production drilling. • Planning and approvals for construction of 10 km pipeline and utility line from Lineynoye to Arbuzovskoye. • 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. 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. 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 2012 and 2011 and no significant issues arose from these inspections. 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. There were no lost time incidents in the year relating to employees of PetroNeft and no lost time incidents relating to the employees of contractors. 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 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. • Maintain an Emergency Response Plan 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. 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 PetroNeft Resources plc: Annual Report 2012 Financial Review The Group has been seeking a farm-in partner for Licence 61 that will help provide the financial resources to fully develop its portfolio of reserves and prospects. The Group is also in discussions with a number of Russian and European banks with a view to refinancing existing debt facilities. Paul Dowling Chief Financial Officer 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 gain/(loss) on intra-Group loans Impairment of oil and gas properties Finance costs 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) Total debt at year end (undiscounted) 2012 US$ 2011 US$ 34,581,257 29,031,693 (30,134,453) (25,598,616) 3,433,077 12% 4,446,804 13% (6,313,028) (977,030) (90,533) (5,848,021) (1,108,446) 159,244 (7,380,591) (6,797,223) (5,114,345) 4,538,236 (5,000,000) – (2,501,070) (4,216,548) (4,566,143) (17,913,356) 52,136,170 14,270,220 – 16,256,115 7,939,422 6,030,005 36,500,000 35,000,000 15 2012 was a difficult year from a finance point of view. Production was lower than expected which had a knock on effect to the near-term cash generation capability of the Group. During the year we renegotiated the debt facility with Macquarie Bank Limited to arrange a firm amortisation schedule. Monthly repayments started in March 2013 and while we are making these payments from our own resources there is little room for capital expenditure now that these payments have commenced. We had a significant work programme in 2012 with over US$14 million of capital investment in production and exploration wells as well as the construction of a tie-in connection between Lineynoye and Arbuzovskoye. Net Loss The net loss for the year decreased to US$4,566,143 from US$17,913,356 in 2011. The decrease in the net loss can be attributed to an improvement in gross margin as a result of increased production and oil price, an impairment of oil and gas properties of US$5,000,000 in 2011 and a foreign exchange gain of US$4,538,236 (2011: loss of US$5,114,345) on US Dollar denominated loans from PetroNeft to its wholly owned subsidiary, Stimul-T whose functional currency is the Russian Rouble. This gain arises due to the strengthening of the Russian Rouble against the US Dollar in the last year. Administrative expenses were largely consistent with 2011. Revenue, Cost of Sales and Gross Margin Revenue from oil sales was US$34,581,257 for the year (2011: US$29,031,693). Cost of sales includes depreciation of US$4,219,955 (2011: US$3,968,704). 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 806,761 barrels of oil (2011: 748,079 barrels) in the year and sold 812,006 barrels of oil (2011: 719,422 barrels) achieving an average oil price of US$42.86 per barrel (2011: US$40.35 per barrel). The increase in production and barrels sold is a result of more wells producing in 2012. All of our oil was sold on the domestic market in Russia. Finance Costs Finance costs of US$4,216,548 (2011: US$2,501,070) 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 increase is the addition of the new loan from Arawak during the year along with a higher average outstanding balance on the Macquarie loan. Finance Revenue Finance revenue of US$77,233 (2011: US$59,854) primarily arises from interest earned on bank deposits. Taxation The current tax charge arises on interest earned from bank deposits. The deferred tax charge arises on interest earned by PetroNeft on loans to its wholly owned subsidiary Stimul-T. PetroNeft Resources plc: Annual Report 2012 16 Financial Review (continued) of alternatives to refinance or repay its debt facilities and strengthen its financial position well in advance of that date. In that regard the Group has been seeking a farm-in partner for Licence 61 that will provide the necessary funding to clear all existing debt and the financial resources to fully develop its portfolio of reserves and prospects. The Group is also in discussions with a number of Russian and European banks with a view to refinancing existing debt facilities. These circumstances represent a material uncertainty that may cast significant doubt upon the Group’s ability to continue as a going concern which is described in more detail in Note 2 to the Consolidated Financial Statements. 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 2012, the CEO and CFO held regular meetings with analysts and institutional investors. The target for 2013 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 14 June 2013 are as follows: Name of Shareholder Ordinary Shares Percentage Henderson Global Investors Macquarie Bank Limited Athos Limited Ali Sobraliev Arawak Energy Russia B.V. J&E Davy 59,034,710 9.15% 42,855,060 28,201,130 23,014,273 20,457,136 19,948,034 6.65% 4.37% 3.57% 3.17% 3.09% Paul Dowling Chief Financial Officer Cost Management A number of initiatives during the year were undertaken to reduce and manage costs. While the average number of employees in the Group for the year was 188 this had reduced to 170 by year end. This has been achieved through a hiring embargo whereby department managers must first try to reallocate duties of a departing employee to other employees and can only replace a departing employee having demonstrated that this is not possible. Also, when the Arbuzovskoye oil field was brought into operation we reallocated existing employees from Lineynoye to operate the Arbuzovskoye oil field. With very few exceptions no pay rises have been awarded since January 2011. Also during 2012 we renegotiated the contract with our supplier of electric submersible pumps (‘ESP’). The cost of renting, maintaining and repairing ESPs is the largest operating cost in the field after wages and salaries. We agreed a contract to essentially fix the cost of rental, maintenance and repair of ESPs. This ensures that these costs are predictable based on the number of wells in operation. Capital Investment During 2012 the capital expenditure was lower than 2011 as the Group concentrated on bringing the Arbuzovskoye field into year round production including: • Stocking Arbuzovskoye for drilling up to 10 wells. • Construction of a ten kilometre pipeline and utility line from Lineynoye to Arbuzovskoye. • Drilling four new wells at Arbuzovskoye. • Mobilising two exploration rigs and stocking for same at Licence 61. In early 2013 and additional two oil production wells and one water source well were drilled at the Arbuzovskoye oil field and, funding permitting, the Group intends to drill at least three further production wells at Arbuzovskoye as well as two exploration/ delineation wells at Sibkrayevskoye and West Lineynoye and commence a programme of seismic acquisition at Sibkrayevskoye later in 2013. Current and Future Funding of PetroNeft In October 2012 a revised borrowing base was agreed with Macquarie Bank Limited whereby US$7.5 million was repaid from the proceeds of an equity issue completed in November 2012 and US$1 million was converted to shares of PetroNeft at 5 pence per share. It was also agreed to commence monthly repayments of US$650,000 on 31 March 2013. These repayments have now commenced and the Company is meeting them from its own resources. In addition, the revised borrowing base is subject to certain financial covenants and lender approvals for the application of certain funds typical of a facility of this nature. The Macquarie loan matures in May 2014 at which time a final payment of US$8.4 million, net of US$4 million in restricted cash held by Macquarie, will be required. The Group is evaluating a number PetroNeft Resources plc: Annual Report 2012 Principal Risks and Uncertainties 17 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: Risk Category Risk Issue Mitigation Risk Category Risk Issue Mitigation Country Risks Political – federal risks Fields/acquisitions below 500 million boe are not considered strategic to the Russian state. Financial Risks Availability of finance Strong reserve base and key infrastructure already in place makes attractive investment case. State is encouraging small operators. 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. Rigorous contracting procedures with competitive tendering. Also the relationship of the Dollar/Rouble exchange rate to the oil price provides a natural balance between costs and income. Industry cost inflation Uninsured events Comprehensive insurance programme in place. Other Risks HSE incidents HSE standards set and monitored regularly across the Group. Export quota 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. Transneft pipeline access Available capacity and access confirmed. East Siberia-Pacific Ocean (‘ESPO’) pipeline allows export of oil to Pacific market. Political – local risks Tomsk Oblast administration is very supportive of development. Ownership of assets Local management are well respected in region. 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 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 oper ations team. Can avoid drilling wells low on structure that risk poor results. Production/ Completion risk Routine completion practices including fracture stimulation. 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 2012 18 Board of Directors 1 2 3 4 5 1. David Golder (Non-Executive Chairman) (Age 65) 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. 2. Dennis Francis (Chief Executive Officer and Executive Director) (Age 64) 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. 3. Paul Dowling (Chief Financial Officer and Executive Director) (Age 41) 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. 4. Dr. David Sanders (General Legal Counsel, Executive Director and Company Secretary) (Age 64) 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. 5. Gerard Fagan (Non-Executive Director) (age 64) 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 PetroNeft Resources plc: Annual Report 2012 19 6 7 7. Vakha Sobraliev (Non-Executive Director) (Age 58) 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 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 a shareholder and General Director of Tomskburneftegaz LLC, an oil and gas well drilling and services company operating in Western Siberia. 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. Mr. Sobraliev is a resident of Tomsk, Russia. 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. 6. Thomas Hickey (Non-Executive Director) (Age 44) 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 focussed on the Middle East, North Africa and the Mediterranean basin. He was Chief Financial Officer and a Director of Tullow Oil plc from 2000 to 2008. During this time Tullow grew via a number of significant acquisitions and exploration success. Prior to joining Tullow Oil plc, he was an Associate Director of ABN AMRO Corporate Finance (Ireland) Limited. In this role, he advised public and private companies in a wide range of industry sectors in the areas of fund raising, stock exchange requirements, mergers and acquisitions, flotation and related transactions. Mr. Hickey is a Commerce graduate of University College Dublin and a Fellow of the Institute of Chartered Accountants in Ireland. He is also a non-executive director of Ikon Science Limited, a UK geological software company. PetroNeft Resources plc: Annual Report 2012 20 Directors’ Report For the year ended 31 December 2012 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 2012. 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$2,777,569 (2011: US$16,422,036). After a tax charge of US$1,788,574 (2011: US$1,491,320) the loss for the year amounted to US$4,566,143 (2011: US$17,913,356). The Directors do not recommend payment of a dividend. Accordingly, an amount of US$4,566,143 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 2012, 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 8 and 9, the Chief Executive Officer’s Report on pages 10 to 13 and the Financial Review on pages 15 and 16. The key financial metrics used by management are set out in the Financial Review on page 15. 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 Exchange. 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, David Golder, Gerard Fagan and Vakha Sobraliev. It is chaired by Thomas Hickey. 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, Gerard Fagan, Thomas Hickey and Vakha Sobraliev. It is chaired by David Golder. 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 2012 21 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 18 and 19. In accordance with Article 83 of the Articles of Association, Dennis Francis and David Sanders 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 2012 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 14 June 2013 Ordinary Shares As at 31 December 2012 Ordinary Shares As at 1 January 2012 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 22,760,416 331,583 2,238,235 – 200,000 1,826,283 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 2012 735,000 1,870,000 1,135,000 840,000 655,000 150,000 443,000 Granted in Year Exercised in Year 31 December 2012 Exercise price Options held as at 130,000 475,000 406,250 406,250 110,000 110,000 110,000 – – – – – – – 865,000 2,345,000 1,541,250 1,246,250 765,000 260,000 553,000 £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. 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 2012, are listed on page 17. PetroNeft Resources plc: Annual Report 2012 22 Directors’ Report For the year ended 31 December 2012 (continued) 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 21. 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 2012 in shares instead of cash. Director Executive Directors Dennis Francis Paul Dowling David Sanders Non-Executive Directors David Golder Gerard Fagan Thomas Hickey* Vakha Sobraliev Total Directors remuneration 2012 2011 Basic remuneration* US$ Bonuses US$ Pension US$ Share-based payment US$ Total remuneration US$ Basic remuneration* US$ Bonuses US$ Pension US$ Share-based payment US$ Total remuneration US$ 301,865 256,455 245,981 – 15,071 – 12,023 – 12,286 72,293 61,339 61,339 389,229 329,817 319,606 330,306 269,613 269,867 – 16,007 – 11,685 – 12,985 79,876 67,233 67,773 426,189 348,531 350,625 804,301 – 39,380 194,971 1,038,652 869,786 – 40,677 214,882 1,125,345 57,213 38,997 38,997 25,998 161,205 – – – – – – – – – – 26,289 26,605 21,908 21,073 83,502 65,602 60,905 47,071 62,608 41,739 41,739 27,826 95,875 257,080 173,912 – – – – – – – – – 28,711 27,245 23,922 22,765 91,319 68,984 65,661 50,591 – 102,643 276,555 965,506 – 39,380 290,846 1,295,732 1,043,698 – 40,677 317,525 1,401,900 * Certain amounts were payable in shares instead of cash. 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 2012. 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 2012 23 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. Going Concern The Directors are required to make an assessment of the Group’s ability to continue in operational existence as a going concern. After making appropriate enquiries including the considerations referred to in this Annual Report, the Directors are confident that the Group and Company will have adequate resources to continue in operational existence for the foreseeable future. However, the Directors have concluded that there are material uncertainties facing the business. Further details are set out in the Financial Review and in Note 2 to the Consolidated Financial Statements. Important Events after the Balance Sheet Date There were no important events after the balance sheet date. 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 59. The AGM will be on 11 September 2013 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 21 June 2013 Dennis Francis Director Paul Dowling Director PetroNeft Resources plc: Annual Report 2012 24 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 2012 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 2012. 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. 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 2012 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 2012, of the state of the Parent Company’s affairs as at 31 December 2012; and • the financial statements have been properly prepared in accordance with the requirements of the Companies Acts 1963 to 2012. 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 2012 • 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 2012 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 2012 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 21 June 2013 PetroNeft Resources plc: Annual Report 2012 Consolidated Income Statement For the year ended 31 December 2012 Continuing operations Revenue Cost of sales Gross profit Administrative expenses Impairment of oil and gas properties Exchange gain/(loss) on intra-Group loans Operating profit/(loss) Profit on disposal of subsidiary undertaking 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 expense Loss for the year attributable to equity holders of the Parent Loss per share attributable to equity holders of the Parent Basic and diluted – US Dollar cent 25 Note 2012 US$ 2011 US$ 5 29,031,693 34,581,257 (30,134,453) (25,598,616) 13 6 12 13 16 7 8 10 4,446,804 (7,380,591) – 4,538,236 3,433,077 (6,797,223) (5,000,000) (5,114,345) 1,604,449 (13,478,491) 223,222 (391,188) (334,363) 59,854 (2,501,070) – (19,231) (223,472) 77,233 (4,216,548) (2,777,569) (16,422,036) (1,491,320) (1,788,574) (4,566,143) (17,913,356) 11 (1.03) (4.30) Consolidated Statement of Comprehensive Income For the year ended 31 December 2012 Loss for the year attributable to equity holders of the Parent Currency translation adjustments Total comprehensive loss for the year attributable to equity holders of the Parent Approved by the Board on 21 June 2013 2012 US$ 2011 US$ (4,566,143) (17,913,356) (1,802,179) 2,406,068 (2,160,075) (19,715,535) Dennis Francis Director Paul Dowling Director PetroNeft Resources plc: Annual Report 2012 26 Consolidated Balance Sheet As at 31 December 2012 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 Total Assets Equity and Liabilities Capital and Reserves Called up share capital Share premium account Share-based payments reserve Retained loss Currency translation reserve Other reserves Note 2012 US$ 2011 US$ 13 105,097,756 92,697,976 14 1,925,938 24,552,717 15 3,851,880 16 1,696,626 28,294,677 3,819,142 138,908,201 123,028,511 18 19 20 20 24 1,711,417 1,320,032 3,939,422 4,000,000 1,856,813 2,810,459 1,030,005 5,000,000 10,970,871 10,697,277 149,879,072 133,725,788 8,561,499 6,266,045 5,636,142 136,762,387 122,431,629 4,894,985 (48,357,296) (43,791,153) (7,630,511) 336,000 (5,224,443) 336,000 Equity attributable to equity holders of the Parent 98,344,192 81,877,092 Non-current Liabilities Provisions 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 21 June 2013 Dennis Francis Director Paul Dowling Director 23 22 10 1,843,790 14,559,722 4,871,227 1,147,988 – 3,157,557 21,274,739 4,305,545 21 22 8,909,830 21,350,311 12,938,593 34,604,558 30,260,141 47,543,151 51,534,880 51,848,696 149,879,072 133,725,788 PetroNeft Resources plc: Annual Report 2012 Consolidated Statement of Changes in Equity For the year ended 31 December 2012 27 At 1 January 2011 5,624,840 122,082,388 3,977,064 (5,828,332) (25,877,797) 99,978,163 Share capital US$ Share premium US$ Share-based payment and other reserves US$ Currency translation reserve US$ Retained loss US$ Total US$ Loss for the year Currency translation adjustments Total comprehensive loss for the year Share options exercised in year Share-based payment expense Share-based payment expense – Macquarie warrants (Note 29) At 31 December 2011 At 1 January 2012 Loss for the year Currency translation adjustments – – – 11,302 – – – – – (1,802,179) – (17,913,356) (17,913,356) (1,802,179) – – 349,241 – – – 1,108,446 (1,802,179) (17,913,356) (19,715,535) 360,543 1,108,446 – – – – – – 145,475 – – 145,475 5,636,142 122,431,629 5,230,985 (7,630,511) (43,791,153) 81,877,092 5,636,142 122,431,629 5,230,985 (7,630,511) (43,791,153) 81,877,092 – – – – – – – 2,406,068 (4,566,143) – (4,566,143) 2,406,068 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) At 31 December 2012 – 2,762,969 – 162,388 – – 14,447,506 (954,360) 837,612 – – – – – – – – – 977,030 197,230 196,800 2,406,068 – – – – (4,566,143) – – – – (2,160,075) 17,210,475 (954,360) 1,000,000 977,030 – – – – 197,230 196,800 8,561,499 136,762,387 6,602,045 (5,224,443) (48,357,296) 98,344,192 PetroNeft Resources plc: Annual Report 2012 28 Consolidated Cash Flow Statement For the year ended 31 December 2012 Operating activities Loss before taxation Adjustments to reconcile loss before tax to net cash flows Non-cash Depreciation Impairment of oil and gas properties Loss on disposal of oil and gas properties Profit on disposal of subsidiary undertaking Share of loss in joint venture Share-based payment expense Finance revenue Finance costs Working capital adjustments Decrease in trade and other receivables Decrease/(increase) in inventories (Decrease)/increase in trade and other payables Income tax 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 Investment in joint venture undertaking Decrease/(increase) 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 exercise of options Proceeds from loan facilities Transaction costs on loans and borrowings Repayment of loan facilities Interest paid Net cash received from financing activities Net increase/(decrease) 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 Note 2012 US$ 2011 US$ (2,777,569) (16,422,036) 7 8 4,637,596 – 19,231 – 223,472 977,030 (77,233) 4,216,548 4,293,949 5,000,000 391,188 (223,222) 334,363 1,108,446 (59,854) 2,501,070 1,603,422 383,541 (1,837,731) (186,675) 3,372,948 (646,118) 6,285,719 (68,029) 7,181,632 5,868,424 (18,479,654) (32,967,288) (199,568) (570,396) – (6,629,469) (3,850,000) (2,500,000) 55,861 (119,159) (15,529) 3,549 (1,787,260) – 1,000,000 52,714 (19,345,339) (46,660,860) 17,210,475 (954,360) – 15,000,000 (350,811) – – 360,543 37,000,000 (472,696) (12,500,000) (16,212,000) (1,729,447) (3,340,504) 15,064,800 18,946,400 2,901,093 (21,846,036) 94,160 22,781,881 8,324 1,030,005 20 3,939,422 1,030,005 PetroNeft Resources plc: Annual Report 2012 Company Balance Sheet As at 31 December 2012 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 29 Note 2012 US$ 2011 US$ 14 17 8,651 45,634,887 9,444 45,038,371 45,643,538 45,047,815 19 129,481,865 110,522,328 950,825 20 5,000,000 20 3,692,037 4,000,000 137,173,902 116,473,153 182,817,440 161,520,968 24 8,561,499 5,636,142 136,762,387 122,431,629 4,894,985 (10,603,541) (10,238,869) 336,000 6,266,045 336,000 Equity attributable to equity holders of the Parent 141,322,390 123,059,887 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 21 June 2013 Dennis Francis Director Paul Dowling Director 22 10 14,559,722 4,871,227 – 3,157,557 19,430,949 3,157,557 21 22 713,790 21,350,311 698,966 34,604,558 22,064,101 35,303,524 41,495,050 38,461,081 182,817,440 161,520,968 PetroNeft Resources plc: Annual Report 2012 30 Company Statement of Changes in Equity For the year ended 31 December 2012 At 1 January 2011 Loss for the year Total comprehensive loss for the year Share options exercised in year Share-based payment expense Share-based payment expense – Macquarie warrants (Note 29) At 31 December 2011 At 1 January 2012 Loss for the year 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) At 31 December 2012 Share capital US$ Share premium US$ Share-based payment and other reserves US$ Retained loss US$ Total US$ 5,624,840 122,082,388 3,977,064 (8,854,833) 122,829,459 – – 11,302 – – – (1,384,036) (1,384,036) – 349,241 – – – 1,108,446 (1,384,036) – – (1,384,036) 360,543 1,108,446 – – 145,475 – 145,475 5,636,142 122,431,629 5,230,985 (10,238,869) 123,059,887 5,636,142 122,431,629 5,230,985 (10,238,869) 123,059,887 – – – (364,672) (364,672) – 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 8,561,499 136,762,387 6,602,045 (10,603,541) 141,322,390 PetroNeft Resources plc: Annual Report 2012 Company Cash Flow Statement For the year ended 31 December 2012 Operating activities Profit before taxation Adjustments to reconcile profit before tax to net cash flows Non-cash Depreciation of property, plant and equipment Share-based payment expense Finance revenue Finance costs Working capital adjustments Increase in trade and other receivables (Decrease)/increase in trade and other payables Income tax paid Net cash flows used in operating activities Investing activities Purchase of property, plant and equipment Investment in financial assets Decrease/(increase) in restricted cash Interest received Net cash received from/(used in) investing activities Financing activities Proceeds from issue of share capital Transaction costs of issue of shares Proceeds from exercise of share options Proceeds from loan facilities Transaction costs on loans and borrowings Repayment of loan facilities Interest paid Net cash received from financing activities Net increase/(decrease) 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 31 Note 2012 US$ 2011 US$ 1,423,902 107,284 3,958 380,514 (7,093,078) 3,890,820 3,654 418,997 (6,271,781) 2,438,971 (11,883,865) (29,267,707) 56,657 (68,029) (42,290) (17,790) (13,337,829) (32,581,954) 17 (3,165) – 1,000,000 16,226 (3,962) (3,980,000) (2,500,000) 48,553 1,013,061 (6,435,409) 17,210,475 (954,360) – 15,000,000 (350,811) – – 360,543 37,000,000 (472,696) (12,500,000) (16,212,000) (1,729,447) (3,340,504) 15,064,800 18,946,400 2,740,032 (20,070,963) 20,540 21,001,248 1,180 950,825 20 3,692,037 950,825 PetroNeft Resources plc: Annual Report 2012 32 Notes to the Financial Statements For the year ended 31 December 2012 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 In October 2012 a revised borrowing base was agreed with Macquarie Bank Limited (‘Macquarie’) whereby US$7.5 million was repaid from the proceeds of an equity issue completed in November 2012 and US$1 million was converted into shares of PetroNeft at 5 pence per share. It was also agreed to commence monthly repayments of US$650,000 on 31 March 2013. The revised borrowing base is subject to certain financial covenants and lender approvals for the application of funds typical of a facility of this nature and are subject to periodic review. The Company has received waivers from Macquarie in respect of breaches at year-end and for any subsequent breaches to the latest review date. The Macquarie loan matures in May 2014 at which time a final payment of US$8.4 million (in addition to the US$4 million restricted cash held by Macquarie) will be required. In May 2012 PetroNeft entered into a new loan facility for US$15 million with our partner Arawak Energy Russia B.V. (‘Arawak’). This loan carries an interest rate of LIBOR plus 6%. 4,000,000 warrants were granted to Arawak as part of this loan facility. The Arawak loan facility is a three year loan repayable in one lump sum in May 2015. Refer to Note 22 for further details. The Group has analysed its cash flow requirements through to 31 December 2014 in detail. The monthly repayments from operating cash flows of US$650,000 to Macquarie commenced in March 2013, however, based on our current cash flow forecasts the Group will need to obtain additional funding in order to repay in full the final amount of US$8.4 million due in May 2014. The cash flow includes estimates for a number of key variables including timing of cash flows of development expenditure, oil price, production rates, and management of working capital. The Directors believe that the Group’s cash flow forecasts represent the Group’s best estimate of the results over the forecast period as at the date of approval of the financial statements. As part of the Directors’ overall consideration of the appropriateness of going concern, the cash flow is stress tested to assess the potential adverse effect arising from reasonable changes in circumstance. It is recognised that the cash flow impact of these changes could result in further funding being required. In addition, under the revised borrowing base the Group has to remain in compliance with certain financial covenants and lender approvals. The Company has entered into discussions with a number of parties and is currently pursuing two independent funding strategies. In consultation with major shareholders and finance providers we have concluded that a farmout of up to 50% of Licence 61, while remaining as operator, represents the best way to provide the necessary finance to strengthen the Group’s financial position and allow it to realise the full potential of its substantial asset base. In that regard we have contracted Evercore Partners to run a formal process to seek an industry partner to join in the development and exploration of the licence. We have set up an extensive electronic data room and are in discussions with a number of potential partners. Secondly, we are also in discussions with certain Russian and international banks with a view to re-financing the existing debt facilities, however, the farmout option remains the preference of the Board of Directors. The aim of these discussions is to deliver a long term solution to the Group’s finances to enable it to fully exploit its portfolio of reserves and prospects. While, as at the date of approval of these financial statements, no commitment has been received in respect of either a farmout or re-financing, and there can be no certainty that additional funding will ultimately be received, the Directors remain confident about the outcome of these discussions and the resilience of the Group despite the pressures outlined above. 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, after making enquiries, and considering the uncertainties described above, the Directors are confident that the Group and the Company will have adequate resources to continue in operational existence for the foreseeable future. For these reasons, the Directors continue to adopt the going concern basis in preparing the annual report and accounts. 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 2012 33 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; and • 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. Going Concern In preparing the consolidated financial statements, the Directors are required to make an assessment of the Group’s ability to continue in operational existence as a going concern. The consolidated balance sheet shows an excess of current liabilities over current assets at the balance sheet date. After making appropriate enquiries, the Directors are confident that the Group and Company will have adequate resources to continue in operational existence for the foreseeable future. However, the Directors have concluded that there are material uncertainties facing the business. Further details are set out in the Finance Review and in Note 2 to the Consolidated Financial Statements. Exploration and Evaluation Expenditure – Note 15, US$28.3 million 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 intangible exploration and evaluation assets at 31 December 2012 is US$28.3 million (2011: US$24.6 million). 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: Reserves Base Certain oil and gas properties are depreciated on a unit-of-production 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. 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 and a Russian domestic price of US$43. Certain oil and gas properties are depreciated using the unit-of-production (‘UOP’) basis at a rate calculated by reference to Proved and Probable reserves. This results in a depreciation charge proportional to the depletion of the anticipated remaining production from the field. 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. PetroNeft Resources plc: Annual Report 2012 34 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 3. Accounting Policies (continued) 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 – Note 13, US$105.1 million 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-to-sell 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 arm’s length transaction between knowledgeable and willing parties. 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. 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-to-sell 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, US$45.6 million 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. Share-based Payment Transactions – Note 29 The Group measures the cost of equity-settled transactions by reference to the fair value of the equity instruments at the date on which they are granted. Estimating fair value requires determining the most appropriate valuation model for a grant of equity instruments, which is dependent on the terms and conditions of the grant. This also requires determining the most appropriate inputs to the valuation model; including the expected life of the option, volatility and dividend yield, and making assumptions about them. The model and assumptions used are discussed in Note 29. Decommissioning Costs – Note 23, US$1.8 million 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. 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. PetroNeft Resources plc: Annual Report 2012 35 3. Accounting Policies (continued) 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 2012 and 2011 were: US$1 = Russian Rouble Euro British Pound 2012 2011 Closing Average Closing Average 30.440 0.7565 0.6185 30.986 0.7781 0.6310 32.077 0.7722 0.6470 29.330 0.7188 0.6235 b) Interest in Joint Venture 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. Goodwill relating to the joint venture is included in the carrying amount of the investment and is neither amortised nor individually tested for impairment. The profit or loss reflects the Group’s share of the results of operations 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. PetroNeft Resources plc: Annual Report 2012 36 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 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%. e) Impairment of Property, Plant and Equipment and Intangible Assets 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–to-sell 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 arm’s length transaction between knowledgeable and willing parties. 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. PetroNeft Resources plc: Annual Report 2012 37 3. Accounting Policies (continued) 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. 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. 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. 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 effective interest rate method (‘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) Inventories 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. PetroNeft Resources plc: Annual Report 2012 38 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 3. Accounting Policies (continued) k) 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. l) 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. 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. m) 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. PetroNeft Resources plc: Annual Report 2012 39 3. Accounting Policies (continued) n) 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 2012 or 2011. o) 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. p) Share Issue Expenses Costs of share issues are written-off against the premium arising on the issue of share capital. q) 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. r) 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. s) 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. PetroNeft Resources plc: Annual Report 2012 40 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 3. Accounting Policies (continued) 3.5 Changes in Accounting Policy and Disclosures The Group has adopted the following new and amended IFRS and IFRIC interpretations in respect of the 2012 financial year-end: IAS 12 Income Taxes (Amendment) IFRS 7 Financial Instruments – Disclosures (Amendment) Effective date 1 January 2012 1 July 2011 There were no changes necessary arising from the above amendments to the Group during the year. IFRS and IFRIC Interpretations Effective in Respect of the 2013 Financial Year-end The Group has not applied the following standards and interpretations that have been issued but are not yet effective: • IAS 1 Presentation of Items of Other Comprehensive Income – Amendments to IAS 1 effective 1 July 2012. • IAS 19 Employee Benefits (Revised) effective 1 January 2013. • IAS 28 Investments in Associates and Joint Ventures (as revised in 2011) effective 1 January 2013. • IFRS 7 Disclosures — Offsetting Financial Assets and Financial Liabilities — Amendments to IFRS 7 effective 1 January 2013. • IFRS 13 Fair Value Measurement effective 1 January 2013. Improvements to IFRSs (May 2012) – These improvements will not have an impact on the Group, but include: • IFRS 1 First-time Adoption of International Financial Reporting Standards. • IAS 1 Presentation of Financial Statements. • IAS 16 Property Plant and Equipment. • IAS 32 Financial Instruments, Presentation. • IAS 34 Interim Financial Reporting. These improvements are effective for annual periods beginning on or after 1 January 2013. The standards and interpretations addressed above will be applied for the purposes of the Group Consolidated Financial Statements with effect from the dates listed. Their application is not currently envisaged to have a material impact on the Group’s Consolidated Financial Statements. IFRS and IFRIC Interpretations Effective Subsequent to the 2013 Financial Year-end • IAS 32 Offsetting Financial Assets and Financial Liabilities — Amendments to IAS 32 effective 1 January 2014. • IFRS 10 Consolidated Financial Statements, IAS 27 Separate Financial Statements effective 1 January 2014. • IFRS 11 Joint Arrangements effective 1 January 2014. • IFRS 12 Disclosure of Interests in Other Entities effective 1 January 2014. • IFRS 9 Financial Instruments effective 1 January 2015. The Group is in the process of assessing the impact of these standards but does not currently envisage their application to have a material impact on the Group’s Consolidated Financial Statements. 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. PetroNeft Resources plc: Annual Report 2012 4. Segment Information (continued) Non-current Assets Assets are allocated based on where the assets are located: Russia Ireland 5. Revenue Revenue from crude oil sales 41 2012 US$ 2011 US$ 138,899,550 123,019,068 9,443 8,651 138,908,201 123,028,511 2012 US$ 2011 US$ 34,581,257 29,031,693 34,581,257 29,031,693 All revenue arises from sales to third parties based in the Russian Federation. More than 99% of revenue or US$34,564,079 (2011: US$28,891,704) arises from sales of crude oil to NTK Finko. 6. Operating Profit/(loss) Operating profit/(loss) is stated after charging/(crediting): Included in cost of sales Cost of inventory recognised as an expense Impairment of oil and gas properties Foreign exchange (gain)/loss on intra-Group loans Included in administrative expenses Other foreign exchange loss/(gain) Operating lease rentals – land and buildings Operating lease rentals – equipment Depreciation of property, plant and equipment Included in administrative expenses Included in cost of sales Capitalised during period Depreciation of oil and gas properties Included in cost of sales Included in administrative expenses Capitalised in closing inventories Auditor’s remuneration – Group – audit of Group financial statements – other assurance services – tax advisory services Auditor’s remuneration – Company – audit of Company financial statements – other assurance services – tax advisory services Note 13 2012 US$ 2011 US$ 30,134,453 – (4,538,236) 25,598,616 5,000,000 5,114,345 90,533 230,454 1,345,642 (159,244) 238,055 951,296 166,446 – 172,890 145,328 62,136 174,677 14 339,336 382,141 4,219,955 251,195 238,145 3,906,568 179,917 302,748 13 4,709,295 4,389,233 164,475 29,025 – 216,676 8,043 8,403 193,500 233,122 20,000 – – 20,000 20,000 – – 20,000 PetroNeft Resources plc: Annual Report 2012 42 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 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 finance costs 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 At the end of 2012 the total number of employees was 170 (2011: 188). Employment costs (including Directors) Wages and salaries Social insurance costs Share-based payment expense Pension contributions (defined contributions) 2012 US$ 34,784 17,930 24,519 77,233 2011 US$ 47,583 8,278 3,993 59,854 2012 US$ 2011 US$ 3,890,820 65,167 260,561 2,438,971 62,099 – 4,216,548 2,501,070 2012 Number 2011 Number 7 5 50 84 36 7 5 51 75 36 182 174 2012 US$ 2011 US$ 5,122,829 972,412 977,030 57,188 5,119,742 995,261 1,108,446 59,719 7,129,459 7,283,168 Included in employment costs above is an amount of US$1,362,084 (2011: US$1,884,599) capitalised during the year. Directors’ emoluments Remuneration and other emoluments – Executive Directors Remuneration and other emoluments – Non-Executive Directors Remuneration and other emoluments payable in shares Pension contributions Share-based payment expense 2012 US$ 2011 US$ 804,301 122,208 38,997 39,380 290,846 869,786 145,007 28,905 40,677 317,525 1,295,732 1,401,900 An amount of US$45,368 (2011: US$92,222) relating to Executive Directors salaries was re-charged to Russian BD Holdings B.V. PetroNeft Resources plc: Annual Report 2012 43 2012 US$ 2011 US$ 64,105 10,799 – 7,756 – (37,518) 74,904 (29,762) 1,713,670 1,521,082 1,713,670 1,521,082 1,788,574 1,491,320 10. Income Tax Current income tax Current income tax charge Income tax on dividends (paid in Russia) Adjustment in respect of prior periods Total current income tax Deferred tax Relating to origination and reversal of temporary differences Total deferred tax Income tax expense reported in the Consolidated Income Statement The tax expense comprises: The income tax charge relates to interest income received by the Company. Reconciliation of the Total Tax Charge 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 Non-deductible expenses Tax deductible timing differences Other Losses available at higher rates Taxable losses not utilised Income tax on dividends (paid in Russia) Adjustment in respect of prior periods Total tax expense reported in the Consolidated Income Statement Deferred Tax Deferred tax at 31 December relates to the following: Group and Company Deferred income tax liability Accrued interest income 2012 US$ 2011 US$ (2,777,569) (16,422,036) (347,196) 122,129 884,394 664,930 (46,602) 27,934 (283,312) 755,498 10,799 – (2,052,755) 138,556 781,785 720,592 (81,116) (12,631) (1,220,644) 3,255,051 – (37,518) 1,788,574 1,491,320 2012 US$ 2011 US$ 4,871,227 3,157,557 4,871,227 3,157,557 The Group has tax losses which arose in Russia that are available for offset against future taxable profits of the companies in which the losses arose. Deferred tax assets of US$8.4 million (2011: US$7.2 million), which expire in six to ten years, have not been recognised in respect of these losses as they may not be used to offset taxable profits elsewhere in the Group and they have arisen in subsidiaries that have been loss-making over recent years. Factors That May Affect Future Tax Charges Continued full year-round oil production in Russia is likely to result in taxable profits in Russia in future years, where the applicable tax rate is 20%. 11. Loss per Ordinary Share Basic loss per Ordinary Share amounts are calculated by dividing net loss for the year attributable to ordinary equity holders of the Parent by the weighted average number of Ordinary Shares outstanding during the year. Basic and diluted earnings per Ordinary Share are the same as the potential Ordinary Shares are anti-dilutive. PetroNeft Resources plc: Annual Report 2012 44 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 11. Loss per Ordinary Share (continued) Numerator Loss attributable to equity shareholders of the Parent for basic and diluted loss Denominator Weighted average number of Ordinary Shares for basic and diluted earnings per Ordinary Share Diluted weighted average number of shares Loss per share: Basic and diluted – US dollar cent 2012 US$ 2011 US$ (4,566,143) (17,913,356) (4,566,143) (17,913,356) 444,974,000 416,224,994 444,974,000 416,224,994 (1.03) (4.30) 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 2012 and 2011. • Warrants – At 31 December 2012, 14,100,000 (2011: 6,700,000) 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 2012 and 2011. 12. Profit on Disposal of Subsidiary Undertaking In January 2010, the Group acquired and registered Licence 67. Under the August 2008 Area of Mutual Interest agreement, Arawak Energy exercised their option to participate as a 50% partner in the development of Licence 67, which will be operated by PetroNeft. PetroNeft Resources Plc entered into an agreement with Arawak to jointly own and control a holding company (Russian BD Holdings B.V.) which holds all of the shares of LLC Lineynoye, an entity involved in oil and gas exploration and the registered holder of Licence 67. The legal agreements and documentation relating to the jointly controlled entity were completed in September 2011 when the assets were transferred to the jointly controlled entity. On 9 September 2011, Russian BD Holdings B.V., which was previously a 100% subsidiary of PetroNeft, became a jointly controlled entity, resulting in a profit on disposal on consolidation of US$223,222. 13. Oil and Gas Properties Cost At 1 January 2011 Transfer from exploration and evaluation assets Additions Disposals Translation adjustment At 1 January 2012 Additions Disposals Translation adjustment At 31 December 2012 Depreciation At 1 January 2011 Charge for the year Impairment Depreciation on disposals Translation adjustment At 1 January 2012 Charge for the year Translation adjustment At 31 December 2012 Net book values At 31 December 2012 At 31 December 2011 Wells US$ Equipment and facilities US$ Pipeline US$ Total US$ 35,213,042 2,803,399 30,033,170 (19,843) (4,418,308) 13,553,500 111,368 13,846,905 (127,661) (1,826,123) 14,174,036 – 51,406 (249,045) (660,975) 62,940,578 2,914,767 43,931,481 (396,549) (6,905,406) 63,611,460 8,281,792 (19,231) 3,485,238 25,557,989 1,227,254 – 1,383,657 13,315,422 102,484,871 11,842,430 (19,231) 5,623,109 2,333,384 – 754,214 75,359,259 28,168,900 16,403,020 119,931,179 550,067 3,476,558 5,000,000 (500) (314,243) 8,711,882 3,706,710 261,360 216,050 816,099 – (4,126) (69,603) 958,420 893,632 61,149 30,660 96,576 – (735) (9,908) 116,593 108,953 14,724 796,777 4,389,233 5,000,000 (5,361) (393,754) 9,786,895 4,709,295 337,233 12,679,952 1,913,201 240,270 14,833,423 62,679,307 26,255,699 16,162,750 105,097,756 54,899,578 24,599,569 13,198,829 92,697,976 PetroNeft Resources plc: Annual Report 2012 45 13. Oil and Gas Properties (continued) The net book value at 31 December 2012 includes US$8,369,828 (2011: US$24,395,926) in respect of assets under construction, which are not yet being depreciated. Expenditure of US$11,842,430 was incurred mainly in connection with the Arbuzovskoye oil field, primarily relating to production wells and oil field infrastructure. In November 2011 the Board sanctioned the development of the Arbuzovskoye oil field. Exploration and evaluation costs of US$2,914,767 in relation to the Arbuzovskoye oil field were transferred to oil and gas properties. Loss on Disposal of Oil and Gas Properties During 2011, the Group disposed of pipeline and facilities relating to the decommissioning of the Lineynoye No. 1 well and the conversion of the Lineynoye No.6 well to a water injection well resulting in a loss on disposal of US$391,188. Impairment Loss No impairment was recognised in 2012. In 2011, an impairment of US$5 million was recognised in respect of the Lineynoye oil field. The trigger for the 2011 impairment test was primarily the effect of lower than expected production from Pads 2 and 3 at the Lineynoye oil field during the year. An impairment test in 2012 was triggered by a reduction in reserves at the Arbuzovskoye oil field as a result of thinner than expected net pays in some new wells drilled there in the year and a narrowing of the southern end of the structure based on a new seismic interpretation carried out. In addition, the reduction in the market capitalisation of the Company below the carrying value of the net assets of the Group was also an indicator of potential impairment of the carrying value of oil and gas properties and exploration and evaluation expenditure as a whole. In assessing whether impairment is required, the carrying value of an asset or cash-generating unit (‘CGU’) is compared with its recoverable amount. The recoverable amount is the higher of the asset’s/CGU’s fair value less costs to sell and value in use. Given the nature of the Group’s activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers are taking place. Consequently, the recoverable amount used in assessing the impairment charges described below is value in use. The Group generally estimates value in use using a discounted cash flow model. Key Assumptions Used in Value-in-use Calculations for the Lineynoye and Arbuzovskoye Oil Fields The calculations of value-in-use for the Lineynoye and Arbuzovskoye oil field CGU are most sensitive to the following assumptions: • Production volumes. • Discount rates. • Crude oil prices. Estimated production volumes are based on detailed data for the fields and take into account development plans for the fields agreed by management as part of the long-term planning process and estimated by Ryder Scott Petroleum Consultants in their report on the Group’s reserves. It is estimated that, if all production were to be reduced by 15% for the whole of the next 20 years, this would not be sufficient to reduce the excess of recoverable amount over the carrying amounts of the CGU to zero. Consequently, management believes no reasonably possible change in the production assumption would cause the carrying amount of the CGU to exceed the recoverable amount. The Group generally estimates value in use for the oil exploration and production CGU and total oil and gas properties using a discounted cash flow model. The future cash flows are discounted to their present value using a pre-tax discount rate of 17% that reflects current market assessments of the time value of money and the risks specific to the asset. This discount rate is derived from the Group’s post-tax weighted average cost of capital (‘WACC’), with appropriate adjustments made to reflect the risks specific to the asset/CGU and to determine the pre-tax rate. The WACC takes into account both debt and equity. The cost of equity is derived from the expected return on investment by the Group’s investors. The cost of debt is based on its interest bearing borrowings the Group is obliged to service. Segment specific risk is incorporated by applying individual beta factors. The beta factors are evaluated annually based on publicly available market data. Management also believes that currently there is no reasonably possible change in discount rate which would cause the carrying amount of the oil and gas properties to exceed their recoverable amount. The long-term forecast Urals blend oil price used of US$95 per barrel is based on management’s estimates and available market data. It is estimated that if the long-term price of Urals blend crude oil fell by 15% for the whole of the next 20 years, this would not be sufficient to reduce the excess of recoverable amount over the carrying amounts of the oil and gas properties to zero. Consequently, management believes no reasonably possible change in the oil price assumption would cause the carrying amount of oil and gas properties to exceed their recoverable amount. PetroNeft Resources plc: Annual Report 2012 46 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 14. Property, Plant and Equipment Group Cost At 1 January 2011 Additions Translation adjustment At 1 January 2012 Additions Disposals Translation adjustment At 31 December 2012 Depreciation At 1 January 2011 Charge for the year Translation adjustment At 1 January 2012 Charge for the year Translation adjustment At 31 December 2012 Net book values At 31 December 2012 At 31 December 2011 Company Cost At 1 January 2011 Additions At 1 January 2012 Additions At 31 December 2012 Depreciation At 1 January 2011 Charge for the year At 1 January 2012 Charge for the year At 31 December 2012 Net book values At 31 December 2012 At 31 December 2011 Buildings & leasehold improvements US$ 1,099,715 – (52,992) 1,046,723 – – 55,961 Plant and machinery US$ 1,119,864 745,073 (116,255) 1,748,682 15,529 (3,549) 94,062 Motor vehicles US$ Total US$ 123,597 – (5,927) 117,670 – – 6,325 2,343,176 745,073 (175,174) 2,913,075 15,529 (3,549) 156,348 1,102,684 1,854,724 123,995 3,081,403 89,472 66,787 (10,008) 146,251 63,217 8,996 547,893 288,205 (50,117) 785,981 250,421 45,896 31,595 27,149 (3,839) 54,905 25,698 3,412 668,960 382,141 (63,964) 987,137 339,336 58,304 218,464 1,082,298 84,015 1,384,777 884,220 772,426 39,980 1,696,626 900,472 962,701 62,765 1,925,938 Plant and machinery US$ 19,900 3,962 23,862 3,165 27,027 10,764 3,654 14,418 3,958 18,376 8,651 9,444 PetroNeft Resources plc: Annual Report 2012 15. Exploration and Evaluation Assets Group Cost At 1 January 2011 Additions Reclassification to oil and gas properties Translation adjustment At 1 January 2012 Additions Translation adjustment At 31 December 2012 Net book values At 31 December 2012 At 31 December 2011 47 Exploration and evaluation expenditure US$ 21,391,491 7,459,616 (2,914,767) (1,383,623) 24,552,717 2,412,261 1,329,699 28,294,677 28,294,677 24,552,717 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 Sibkrayevskaya and North Varyakhskaya prospects and the Kondrashevskoye oil field. 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 2011 Subsidiary undertaking becoming joint venture Investment Retained loss Translation adjustment At 1 January 2012 Retained loss Translation adjustment At 31 December 2012 Share of net assets US$ – 445,748 3,850,000 (334,363) (109,505) 3,851,880 (223,472) 190,734 3,819,142 Summarised financial statement information prepared in accordance with IFRS of the equity-accounted joint venture entity is disclosed below: Summarised Financial Statements of Equity-accounted Joint Venture (50% Share) Sales and other operating revenues Operating expenses Exchange loss Finance revenue Finance costs Loss before taxation Taxation Loss for the period 2012 US$ – (196,468) 8,890 1,719 (30,437) 2011 US$ – (176,278) (149,640) 1,408 (9,496) (216,296) (334,006) (7,176) (357) (223,472) (334,363) PetroNeft Resources plc: Annual Report 2012 48 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 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 2012 US$ 2011 US$ 61,672 4,647,923 532,830 3,906,526 4,709,595 4,439,356 (29,413) (861,040) (6,136) (581,340) (890,453) (587,476) 2012 US$ 2011 US$ 112,678 1,146,596 112,678 1,078,820 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 2012 US$ 4,587 18,157 62,051 84,795 2011 US$ 3,376 17,413 59,793 80,582 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 2011 Capital contribution in respect of share-based payment expense Subsidiary undertaking becoming a joint venture Additions At 1 January 2012 Capital contribution in respect of share-based payment expense At 31 December 2012 Net book values At 31 December 2012 At 31 December 2011 Investment in joint venture US$ Investment in subsidiaries US$ Total US$ – – 1,008,816 3,850,000 40,368,922 689,449 (1,008,816) 130,000 40,368,922 689,449 – 3,980,000 4,858,816 – 40,179,555 596,516 45,038,371 596,516 4,858,816 40,776,071 45,634,887 4,858,816 40,776,071 45,634,887 4,858,816 40,179,555 45,038,371 PetroNeft Resources plc: Annual Report 2012 49 17. Financial Assets (continued) Details of the Company’s holding in direct and indirect subsidiaries at 31 December 2012 are as follows: Name of subsidiary Registered office Proportion of ownership interest Proportion of voting power held Principal activity WorldAce Investments Limited 3 Themistocles Street, Nicosia, Cyprus LLC Stimul-T LLC Pervomayka* Granite Construction Dolomite 147 Prospekt Lenina, Tomsk 634009, Russia Pobedy, Kolpashevo, Tomsk 634460, Russia 147 Prospekt Lenina, Tomsk 634009, Russia 147 Prospekt Lenina, Tomsk 634009, Russia 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Holding company Oil and Gas exploration Property holding Construction Oil and Gas exploration * LLC Pervomayka was dissolved on 13 January 2013. Details of the Group’s interest in joint ventures at 31 December 2012 are as follows: Name of entity Registered office Proportion of ownership interest Proportion of voting power held Principal activity Russian BD Holdings B.V. LLC Lineynoye Prins Bernhardplein 200, 1097 JB, Amsterdam, the Netherlands 147 Prospekt Lenina, Tomsk 634009, Russia 50% 50% 50% 50% 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 by other related companies (Note 28) VAT receivable Prepayments 2012 US$ 2011 US$ 1,572,957 138,460 1,619,333 237,480 1,711,417 1,856,813 2012 US$ 55,519 168,885 165,054 657,492 69,762 49,397 153,923 2011 US$ 1,802,450 – 77,860 520,921 47,397 152,171 209,660 1,320,032 2,810,459 2012 US$ 2011 US$ 128,638,512 110,023,692 288,976 – 209,660 651,431 37,999 153,923 129,481,865 110,522,328 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 2012 50 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 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 2012 US$ 2011 US$ 3,939,422 4,000,000 1,030,005 5,000,000 7,939,422 6,030,005 2012 US$ 2011 US$ 3,692,037 4,000,000 950,825 5,000,000 7,692,037 5,950,825 At 31 December 2012 restricted cash amounting to US$4 million is being held in a Macquarie Debt Service Reserve Account (‘DSRA’). This account is part of the security package held by Macquarie and may be offset against the loan in the event of a default on the loan or by agreement between the parties. Bank deposits earn interest at floating rates based on daily deposit rates. Short-term deposits are made for varying periods of between one day and one month depending on the immediate cash requirements of the Group, and earn interest at the respective short-term deposit rates. 21. Trade and Other Payables Trade payables Trade payables to jointly controlled entity (Note 28) Trade payables to related parties (Note 28) Corporation tax Oil taxes, VAT and employee taxes Other payables Payment received in advance Accruals Company Trade payables Corporation tax Other taxes and social welfare costs Accruals 2012 US$ 2011 US$ 945,955 18,241 1,947,539 64,105 3,221,291 169,540 1,531,204 1,011,955 5,543,318 – 4,548,673 7,827 1,957,835 160,237 – 720,703 8,909,830 12,938,593 2012 US$ 157,972 64,105 21,832 469,881 2011 US$ 210,688 7,827 66,396 414,055 713,790 698,966 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. PetroNeft Resources plc: Annual Report 2012 51 22. Loans and Borrowings Group and Company Interest-bearing Current liabilities Macquarie Bank – US$75,000,000 loan facility Arawak – US$5,000,000 loan Total current liabilities Non-current liabilities Arawak – US$15,000,000 loan Total non-current liabilities Total loans and borrowings Contractual undiscounted liability Effective interest rate % Maturity 2012 US$ 2011 US$ 9.79% 31 May 2014 21,350,311 9.11% 31 May 2012 – 29,628,011 4,976,547 21,350,311 34,604,558 7.16% 30 May 2015 14,559,722 14,559,722 – – 35,910,033 34,604,558 36,500,000 35,000,000 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. Total transaction costs incurred in 2011 amounted to US$0.6 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. 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. It was also agreed that monthly repayments of US$650,000 will commence on 31 March 2013. 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. The actual loan facility is still available subject to certain conditions and the coupon payable on the loan outstanding is unchanged. As part of the re-negotiations, 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 2012 were granted as a facilitation fee and have been accounted as a transaction fee in accordance with IFRS 2. The charge associated with these new warrants of US$0.1 million has been 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 and the fair value of the re-priced warrants were applied against the loan. 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. 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. These conditions were waived by Macquarie such that the Group was not in breach as at the year-end. However as the waiver did not extend to more than 12 months after the year-end, all of the Macquarie debt is classified as repayable within one year. Because of these breaches, the Group is currently not in a position to draw down any further amount under its loan facility agreement. Arawak Energy Russia B.V. Loan Facility The US$5 million loan from Arawak Energy Russia B.V. was a general purpose short-term bridge loan in advance of a larger three year-term loan which was completed in May 2012. It was repayable on 31 May 2012 out of the proceeds of the three-year loan. Total transaction costs, incurred in 2011 amounted to US$33,535 and are applied against the proceeds. The initial short-term bridge loan was unsecured On 30 May 2012, the Group signed a new three-year loan agreement with Arawak 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. 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$0.2 million was allocated to the equity component which has been credited to reserves. PetroNeft Resources plc: Annual Report 2012 52 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 23. Provisions Decommissioning Costs – Non-current At 1 January Arising during the period Unwinding of discount Translation adjustment At 31 December 2012 US$ 1,147,988 538,901 65,167 91,734 2011 US$ 743,670 419,075 62,099 (76,856) 1,843,790 1,147,988 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 7.07% (2011: 8.0%) 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 2011 Share options exercised in the year At 1 January 2012 Issued in the year At 31 December 2012 2012 € 2011 € 8,000,000 8,000,000 8,000,000 8,000,000 Number of Ordinary Shares Called up share capital US$ 415,532,432 824,000 416,356,432 228,563,843 5,624,840 11,302 5,636,142 2,925,357 644,920,275 8,561,499 The Company issued 216,052,348 new shares for consideration of US$17.2 million during the year. The net proceeds of this share issue of US$16.3 million are being used to finance expenditure on oil and gas properties, exploration and evaluation costs 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. 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 Outstanding at 31 December Exercisable at 31 December 2012 Number 6,700,000 7,400,000 14,100,000 14,100,000 2012 WAEP £0.34 £0.085 £0.084 £0.084 2011 Number 6,200,000 500,000 6,700,000 6,700,000 2011 WAEP £0.33 £0.42 £0.34 £0.34 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 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. PetroNeft Resources plc: Annual Report 2012 53 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 2012 and 2011. It is the Group and Company’s policy that no trading in derivatives be undertaken. 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 2012 and 2011, 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 2012 and 2011, 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 2012. 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)] 2012 US$ 2,207 14,570 2012 US$ 2011 US$ 1,003 4,962 2011 US$ 2,207 1,003 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. PetroNeft Resources plc: Annual Report 2012 54 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 25. Financial Risk Management Objectives and Policies (continued) 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 2012, the Group and the Company have outstanding loan facilities with Macquarie Bank and with Arawak Energy Russia B.V. (see Note 22). See also Note 2 for additional details on going concern. The Macquarie loan facility is repayable in May 2014. The Arawak Energy Russia B.V. loan facility is repayable in May 2015. The rest of Group’s and Company’s financial liabilities as at 31 December 2012 and 2011 are all payable on demand. The Group and the Company expect to meet its other obligations from operating cash flows and debt financing. During the year the Group was in breach of certain financial and non-financial covenants and conditions subsequent to Macquarie loan agreement, relating primarily to receipt of certain amount of cash by sale of oil and certain financial ratios. The expected maturity of the Group and Company’s financial assets (excluding prepayments) as at 31 December 2012 and 2011 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 2012 and 2011. 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 2012 Interest bearing loans and borrowings – current – non-current Trade and other payables Year ended 31 December 2011 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$ 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 15,311,069 – 12,938,593 8,238,113 – – 15,516,850 – – 28,249,662 8,238,113 15,516,850 – – – – – – – – 23,754,963 17,283,258 8,909,830 49,948,051 39,066,032 – 12,938,593 52,004,625 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 has 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. The effect of a 10% reduction in deposit interest rates (e.g. from 10% to 9%) obtainable on cash and short-term deposits would be to increase Group loss before tax by US$5,271 (2011: US$5,586) and Company loss before tax by US$709,308 (2011: US$625,428). Capital Risk Management The Group and the Company manage capital to ensure that entities in the Group will be able to continue as a going concern while maximising the return to stakeholders through the optimisation of the debt and equity balance. The Group and the Company manage their capital structure and make adjustments to it in light of changes in economic conditions. To maintain or adjust its capital structure, the Group and the Company may issue new shares or raise debt. No changes were made in the objectives, policies or processes during the years ended 31 December 2012 and 2011. The capital structure of the Group and the Company consists of equity attributable to equity holders of the Parent, comprising issued capital, reserves and retained losses as disclosed in the Consolidated Statement of Changes in Equity. PetroNeft Resources plc: Annual Report 2012 25. Financial Risk Management Objectives and Policies (continued) Group External borrowings Less cash and cash equivalents Less: restricted cash Net debt Equity Net debt ratio Company External borrowings Less cash and cash equivalents Less: restricted cash Net debt Equity Net debt ratio 55 2012 US$ 2011 US$ 35,910,033 (3,939,422) (4,000,000) 34,604,558 (1,030,005) (5,000,000) 27,970,611 28,574,553 98,344,192 81,877,092 28% 2012 US$ 35% 2011 US$ 35,910,033 (3,692,037) (4,000,000) 34,604,558 (950,825) (5,000,000) 28,217,996 28,653,733 141,322,390 123,059,887 20% 23% Fair Values The carrying amount of the Group and Company’s financial assets and financial liabilities is a reasonable approximation of the fair value. Hedging At the year ended 31 December 2012 and 2011, the Group had no outstanding contracts designated as hedges. 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$364,672 (2011: US$1,384,036). 27. Capital Commitments 27.1 Details of capital commitments at the balance sheet date are as follows: Contracted for but not provided in the financial statements Including contracted with related parties* 2012 US$ 2011 US$ 726,359 20,060,525 621,027 17,026,563 * The contracts with related parties relate to contracts for drilling wells at the Arbuzovskoye oil field. This contract is to drill up to 15 oil wells and one water source well, however, the Group may reduce the number of wells to be drilled with minimal penalty which would result in the value of the contract reducing proportionately. 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 2012 US$ 2011 US$ 86,221 266,527 701,710 226,608 279,869 716,286 1,054,458 1,222,763 28. Related Party Disclosures Transactions between PetroNeft Resources plc and its subsidiaries, Stimul-T, Granite, Pervomayka, Dolomite, World Ace Investments 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. PetroNeft Resources plc: Annual Report 2012 56 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 28. Related Party Disclosures (continued) The following is a summary of the transactions: Year ended 31 December 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 31 December Received during the year for sundry goods and services Amount due from TBNG and related companies at 31 December 2012 2011 TBNG US$ Other companies US$ TBNG US$ Other companies US$ 441,264 9,834,779 – 1,922,796 15,501 66,228 – 18,500,000 20,156,252 – – 491,339 4,363,262 24,743 73,883 – 44,805 3,534 – – 1,292,074 185,412 – 2,592 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 31 December 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 31 December 2012 2011 TBNG US$ Other companies US$ TBNG US$ Other companies US$ – 1,375,582 – – – – 5,200,000 3,461,009 549,178 – – – The Group provided various goods and services to the jointly controlled entity Russian BD Holdings B.V. and its wholly-owned subsidiary LLC Lineynoye during 2012 amounting to US$332,424 (2011: US$2,165,377). An amount of US$657,492 (2011: US$520,921) is outstanding from these entities at 31 December 2012 while an amount of US$18,241 (2011: US$Nil) is payable. The following transactions occurred between Lineynoye, Russian BD Holdings B.V. and the Company: At 1 January 2011 Advanced during year Transactions during year Interest accrued in year Repaid during year Translation adjustment At 1 January 2012 Advanced during year Transactions during year Interest accrued in year Repaid during year Translation adjustment At 31 December 2012 Lineynoye US$ 2,145,688 3,350,000 – 112,035 (5,288,118) (88,955) 230,650 – – – (235,734) 5,084 Russian BD Holdings B.V. US$ – – 521,639 – (463,313) – 58,326 631,500 118,025 17,930 (174,350) – – 651,431 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 Stimul-T, along with both the Chief Geologist and Chief Engineer of 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 2012 US$ 2011 US$ 1,559,195 39,382 484,718 1,730,623 40,677 512,727 2,083,295 2,284,027 PetroNeft Resources plc: Annual Report 2012 57 28. Related Party Disclosures (continued) Transactions with Subsidiaries The Company had the following transactions with its subsidiaries during the years ended 31 December 2012 and 2011: Loans At 1 January 2011 Advanced during year Technical and management services provided Interest accrued in year Translation adjustment Repaid during year At 1 January 2012 Advanced during year Technical and management services provided Interest accrued in year Translation adjustment Repaid during year At 31 December 2012 Capital contributions Share-based payment 2011 Cash contributions 2011 Share-based payment 2012 Cash contributions 2012 Stimul-T US$ Granite Construction US$ WorldAce Investments US$ 63,242,415 25,450,000 206,242 5,907,541 (1,250,000) (882,905) 92,673,293 2,200,000 200,744 6,943,637 996,533 (1,090,000) 818,776 500,000 – 129,207 – – 8,606,499 7,304,909 – – – (8,992) 1,447,983 – – 133,184 – – 15,902,416 9,220,360 – – 10,362 – 101,924,207 1,581,167 25,133,138 654,031 35,418 – 130,000 571,864 24,832 – – – – – – 29. Share-based Payment Share Options The expense recognised for employee services during the year is US$977,030 (2011: US$1,108,446). The Group share-based payment plan is described below. There was no cancellation or modification to the plan during 2012 and 2011. 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 Exercised during the year Outstanding at 31 December Exercisable at 31 December 2012 Number 2012 WAEP 2011 Number 2011 WAEP 15,496,000 7,203,750 (270,000) – 22,429,750 €0.295/£0.44 £0.065 £0.66 – €0.295/£0.44 7,231,000 €0.295/£0.3476 €0.295/£0.44 16,860,000 – – (540,000) £0.4671 (824,000) €0.295/£0.3375 €0.295/£0.44 7,231,000 €0.295/£0.3476 15,496,000 The range of exercise prices for options outstanding at the year-end is £0.065 to £0.66 (2011: £0.19 to £0.66). The weighted average remaining contractual life for the share options outstanding as at 31 December 2012 was 4.2 years (2011: 4.0 years). The weighted average fair value of options granted during 2012 was £0.0318. No options were granted in 2011. No options were exercised in 2012. The weighted average share price of exercised options at the date of exercise in 2011 was £0.65. The weighted average share price of forfeited options in 2012 was £0.66 (2011: £0.4671). PetroNeft Resources plc: Annual Report 2012 58 Notes to the Financial Statements For the year ended 31 December 2012 (continued) 29. Share-based Payment (continued) 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. The range of exercise prices for warrants outstanding at the year-end is £0.082 to £0.086 (2011: £0.30 to £0.50). The weighted average remaining contractual life for the warrants outstanding as at 31 December 2012 was 1.59 years (2011: 0.91 years). The weighted average fair value of warrants granted during the year was £0.03 (2011: £0.18). 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 2011 0% 70% 0.809% 2.53 £0.0575 £0.0845 Binomial 0% 80% 1.7% 4 £0.33 £0.418 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 There were no important events after the balance sheet date. 31. Approval of Financial Statements The financial statements were approved, and authorised for issue, by the Board of Directors on 21 June 2013. PetroNeft Resources plc: Annual Report 2012 Notice of Annual General Meeting 59 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 Wednesday 11 September 2013, for the purposes of considering and, if thought fit, passing, the following Resolutions, of which Resolutions numbered 1, 2, 3, 4 and 5 will be proposed as Ordinary Resolutions and Resolutions numbered 6 will be proposed as a Special Resolution. ORDINARY BUSINESS 1. To receive, consider and adopt the accounts for the year ended 31 December 2012 together with the Directors’ and Auditors’ Reports thereon. 2. To re-elect Mr. Francis as a Director, who retires by rotation in accordance with Article 83 of the Articles of Association of the Company. 3. To re-elect Dr. Sanders as a Director, who retires by rotation in accordance with Article 83 of the Articles of Association of the Company. 4. To re-appoint Ernst & Young, Chartered Accountants, as Auditors and to authorise the Directors to fix the remuneration of the Auditors. SPECIAL BUSINESS 5. 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 11 December 2014, 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. 6. 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 5 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 11 December 2014, 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. Dated this 21st day of June 2013 BY ORDER OF THE BOARD David Sanders Company Secretary Registered Office: 20 Holles Street Dublin 2 PetroNeft Resources plc: Annual Report 2012 60 Glossary 1P 2P 3P AGM AIM AMI Arawak bbl bfpd boe bopd Company CPF CSR Custody Transfer Point ESM ESPO pipeline Exploration resources Hydraulic fracturing, fracture stimulation Group HSE IAS IFRIC IFRS km km2/sq km KPI Licence 61 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 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. 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. East Siberia-Pacific Ocean pipeline which is expected to be completed in 2012. An undrilled prospect in an area of known hydrocarbons with unequivocal four-way dip closure at the reservoir horizon. The process of cracking open the rock formation around a well bore to increase productivity. 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. 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. PetroNeft Resources plc: Annual Report 2012 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 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 2 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