AGR Petroleum Services Holdings AS Annual Report

Transcription

1 AGR Petroleum Services Holdings AS Annual Report 2013

2 Content Directors' Report Consolidated Income Statement 13 Consolidated Statement of Comprehensive Income 14 Consolidated Statement of Financial Position 15 Consolidated Statement of Changes in Equity 17 Consolidated Statement of Cash Flow 18 Notes 20 Income Statement 56 Balance Sheet as of Balance Sheet as of Cash Flow Statement 59 Notes 61 Auditor's Report 74

3 Directors' Report 2013 AGR Petroleum Services Holdings AS Comp. reg. no: Letter from the CEO strong growth in global drilling activity until 2020 and with shortage of resources already apparent in the industry, I believe there will be a demand for increased efficiency and more automated work processes in order to utilise available human capacity in the most optimum way in the future. This new business line should therefore be well positioned for strong future growth, as it enables the end user to plan their well projects in a smarter and more efficient way. - AGR has drilled over 500 wells... Åge Landro, CEO AGR 2013 was the first full year under the new organisational structure implemented mid 2012 with AGR s divisions operating autonomously and with dedicated management teams for each of the businesses. In 2013 we took even further steps in separating the business areas so that we would ensure an even more focused business model going forward. Early in the year we successfully completed the refinancing of the Group with separate financing for AGR Petroleum Services and AGR Enhanced Drilling. Following this, in August, a demerger of the company was completed. With the demerger completed, AGR is now a service company focusing on exploration, development and production services. In 2012 we developed a new strategic plan for the company and since then the business has focused on delivering on this plan. I believe the performance in 2013 shows that we now are working according to a plan that ensures best possible development of the business and that the financial results clearly demonstrate the potential in AGR as a focused welland reservoir management business. Software Solutions was established as a new business line for AGR in This was one of the key strategic targets for the year. The division was established mid-2013 and during the last six months of the year three new software systems were launched and successfully commercialised. With the new software products, AGR now offers a full suite of software solutions for well planning, cost tracking during operations, material and logistics management and efficient experience transfer. All software systems have been tailormade for drilling departments within oil companies based on extensive experience from AGR s Well Management groups from around the world. It is expected that there will be Another key focus for us has been to strengthen our presence within production drilling and establish a broader relationship with the larger oil companies. AGR has drilled over 500 wells during the last 13 years and the majority of these wells have been exploration and appraisal wells for small Exploration and Production (E&P) companies. Despite this unique track-record, only very few of the wells drilled have been production wells. We see a growing demand for our services and expertise throughout the value chain of oil and gas and established, based on this increased demand, a plan for growing our market presence within production drilling. This started to pay off in 2013, being the first year in the history of the company we delivered as many production wells as exploration wells. Health, Safety and the Environment (HSE) remains our number one priority and in a year with significant increase in the activity level and with improved financial performance it is a pleasure to see that we are able to continue to improve the performance year by year. During 2013 we did not have any incidents with serious personal injuries or damage to equipment and at end of the year the H-value is down to 3.2. Our industry leading well- and reservoir management services continued to deliver professional performance on some of the industry s greatest challenges last year, beating our own records for deep wells with high pressure and high temperature as well as several other state of the art projects. I was very pleased to see the market continue to accept our concept for outsourced well management services, with several NOC s and majors now endorsing it and with Statoil awarding a significant part of its work to AGR last year. The global demand for rig days is estimated to increase by 6 % annually over the next years, so we expect the demand for our services to continue to grow in We will continue to deliver on an ambitious business plan to continue strengthening AGR s market position globally and further improve our business performance and health, safety and environment (HSE) performance. ANNUAL REPORT

4 Company Overview AGR is a leading supplier of services and software to the global oil and gas industry. The Group s main operations are based in Oslo, with other offices around the world including, Stavanger, Trondheim, Bergen, Aberdeen, Guilford, Houston, Perth, Almaty, Moscow, Dubai, Abu Dhabi and Tel Aviv. The company provides expertise and services to several of the world s major oil and gas fields, with a customer base comprising several small and medium sized operators, as well as a number of the large international oil companies and NOCs. At the end of 2013, the Group had 634 professionals, whereof 306 permanent employees, 2 project employees, 313 contracted-in staff and 13 associates. The annual turnover was NOK million. Corporate Governance Good corporate governance is a key goal of the AGR Board in order to ensure that its investors and stakeholders can be confident that the actions taken are in the best long term interest of the Company. AGR aims to achieve the best possible profitability, while maintaining an efficient and viable utilisation of the company s resources and ensuring adherence to HSE&Q best practice standards. AGR believes that adhering to the Group s values will benefit the company s shareholders, employees and society in general. Corporate Governance Policy for AGR This Policy was adopted by the AGR Group Board of Directors on 5 November 2007 and has thereafter been regularly updated. It is predominantly based on the guidelines on Corporate Governance (Anbefaling for Eierstyring og Selskapsledelse) of 21 October 2010 and updated 20 October Through its compliance with the policy the company aims to maintain the shareholders trust in the company s Board and Management as well as the Group s reputation. The policy lays down principles of transparency in its communication with stakeholders, independence of the Board, equal treatment of shareholders, and control to ensure predictability and appropriate risk management. In pursuit of the Corporate Governance Policy, the company has in place a code on Board Proceedings, a Management Code and an Insider Trading Policy. The Board and Management of the Group are continuously assessing the company s risks and its approach to ethics. The Board of Directors has evaluated potential conflicts of interest among the members of the Board and Management and has concluded that to the knowledge of the Board there were no such incidents in The company has monthly financial reporting which is an important tool to enable suitable control of the company and to monitor progress towards the achievement of its financial goals. This reporting enables the company to be confident that it is in compliance with statutory and Stock Exchange reporting requirements. Operations Introduction After completing the restructuring of the company, AGR is today a focused on reservoir and well management business with a unique global track-record. AGR delivers a broad service offering within reservoir evaluations, well planning, well operations and integrated field management to the upstream oil and gas industry. Its core competencies include geology, geophysics, petrophysics, reservoir and petroleum engineering, well construction, drilling management, completion design and installation, field development planning, risk and economics evaluation. The business unit also delivers a broad training portfolio within these topics, as well as a suite of software solutions for efficient planning and execution of the well delivery process. The services are offered provincially by regional business centers established in Norway, United Kingdom, USA, Russia, United Arab Emirates and Australia. In 2013 AGR made good progress in implementing its business plan, resulting in a stronger market presence, both across the lifecycle of oil and gas, as well as by establishing relationships with a number of new clients worldwide. During the year the company has also introduced new products and services to the markets such as software solutions business and a new rig management offering. To position the company for future growth, one key priority has been to establish a strong and broad client portfolio. At the end of 2013 the company had 360 active contracts with clients around the world was yet another year with success in winning important contracts. A number of wells for multiple clients in various locations were secured during the year. The largest single contract secured in 2013 was a Total Well Management contract for executing, planning, operations and post well activity for drilling and well operations for Genel and Medoil for 10 wells over the next 24 months by using the Noble Paul Romano rig. The duration of the contract was two years or 10 wells, whichever is reached first. Planning of the first well started in 2013 and drilling operations are expected to commence in April When entering into 2014 AGR has secured significant work in all regions. The high activity level in 2013 generated NOK 177 Million EBITDA, up from NOK 129 million in Included in these numbers are also costs related to the demerger of the business and other non-recurring items, meaning that the underlying operational performance was stronger than reported. In 2013 the business spudded 21 wells and has in total spudded 513 wells the last thirteen years. ANNUAL REPORT

5 At the time of the demerger of AGR, the company also reduced its ownership in AGR Energy from 100% to 44%. Norway and Russia capacity for operators on the NCS. Jorunn Sætre was appointed head of the rig team in addition to Office Manager for the growing AGR Stavanger office. UK, West Africa and ME At the start of 2013 AGR commenced the close out and demobilisation phase of the successful four well deepwater project in the Falkland Islands which concluded operations with the Leiv Eiriksson in December Also early in the year the Aphrodite 2 well offshore Israel was successfully completed within AFE time and cost. Operations were closed out and equipment demobilised. However, the overall Well Management activity level was unusually low with only one well spudded. Sjur Talstad, EVP Norway and Russia AGR in Norway experienced a very high activity level across all areas during The Well Management division delivered Well Management Services on seven different rigs and delivered a total of 18 wells in a safe and efficient manner to multiple operators during the year. A production drilling campaign was executed on the Volve asset for Statoil under the Total Well Management contract in addition to production wells on Oseberg Sør and Vega. The three year Borgland Dolphin campaign continued during the year and the new Bredford Dolphin campaign started in September. Exploration drilling for Lundin, Faroe and RWE was delivered using a semi, a jack-up rig as well as a drill ship. Two wells for OMV in the northern part of the Barents Sea were also executed successfully. A proactive HSEQ attitude was secured through heavy involvement from the HSEQ Services department in addition to AGR s Operational HSE delivering Safety Coaches on several AGR operated rigs and other rigs in Norway and internationally. The Reservoir Management division experienced a very active year with exploration, field development and field operations studies for several operators and authorities. The organisation was strengthened during the year both in the Oslo and Stavanger offices. Several verification and M&A support analyses were performed for several operators. Interest for our multi-client studies within exploration remained high. The Moscow reservoir office was active within their reservoir study offering. In May a multi-well management contract was signed with Genel Energy to support Genel operated activity over a two year period initially in Malta and Morocco. Later in the year the Noble Paul Romano semi-submersible rig was contracted for the work. This work was scheduled to commence in September 2013 but because of extensive rig upgrades and shipyard delays, commencement of the operations phase is now expected in April Significant well planning, supply-base set up and third party services contracting activity took place in 2013 nonetheless. A contract was signed for a one-well programme offshore Guinea Bissau with Svenska Petroleum to be drilled in the second half of 2013 but again due to rig availability issues this well was also deferred to a 2014 start. After some time conducting a search for a suitable rig, AGR was able to broker a rig sharing arrangement between Ophir, one of our APAC clients and STARC for whom we had been contracted to deliver one deep water well. With the combined demand of one well in Equatorial Guinea for STARC and one in Ghana for Ophir the Stena Drillmax DP drillship was secured for the work. The well for STARC was drilled successfully and considerably under AFE time and cost. In addition to the Full Well Management contracts, well design engineering work was undertaken on a number of projects yet to be executed. A well in Tunisia for Cooper Energy was completed and tested in late 2012 and plans were made for a re-entry, sidetrack and further test in The Facilities division supported Lundin in their first field development project on Brynhild. AGR Consultancy secured a renewal of the Consultancy contract for drilling and well personnel with Statoil. Several extensions and new contracts were also entered into with new operators. A dedicated rig team was established to secure new rig Ian Burdis, EVP UK & West Africa ANNUAL REPORT

6 During the year the Reservoir group executed significant projects for Maersk, Talisman, Premier, National Grid Carbon, MOL and BP. Major contracts were signed with GNPC and BP-ADMA for large scale studies which, commencing in 2013, will ensure high utilisation of resources throughout 2014 and beyond. The strategic aim of recruiting geomechanics expertise was realised and this has proven key in linking integrated projects involving both Reservoir and Well Management resources which now forms a growing component of the business. The training division of the Reservoir group represented the highest growth area for the region in 2013 carrying out 193 courses in At the end of the year, 112 courses had already been pre-booked for Asia Pacific Bruce Roebuck, EVP Asia Pacific 2013 has seen AGR strengthen its position in the Asia Pacific market. As a result of initiating a strategic development programme in late 2012, the company has seen significant progress in several business areas, particularly subsea and software solutions. Leveraging on the synergies between Well Management, Reservoir Management, Software and Consultancy has resulted in the establishment of several Master Service Agreements with other Engineering groups that lack these competencies within their own local organisations. This is the case with Wood Group Kenny, Worley Parsons and RPS, all of whom regard AGR as their preferred partner when they require drilling and/or reservoir expertise. Americas 2013 started off with a new management team in place and was immediately challenged with the task of replacing the revenue from McMoran, who was cutting back on their activity, the historical number one revenue generating client for AGR Americas for many years. Emphasis on existing contracts with other top five clients was made top priority in order to maintain market share. Ongoing ventures that included Karoon Brazil and the placement of a new support structure for Karoon Peru will occupy AGR through 2015 once drilling commences in both areas of South America. As ADTI shut down all activity in the US, AGR was able to replace ADTI and is now the primary supplier for the West Africa Operations and other areas like Romania. Other new contracts, like a new contract with Chevron will be finalised in 2014 and AGR will place emphasis on the land shale play regions in West Texas and the North East. Eagle Ford activity has stabilised with no significant fluctuations in the overall US land rig activity in GoM will see increased activity in the deepwater sector with clients like the new FMI (Plains Resources and McMoran merger), Chevron and other companies like Marubeni O&G in 2014, but the overall rig count for the GM has remained relatively flat throughout Throughout 2013, AGR has been planning the abandonment of an offshore field in the region, including subsea wells. This project will be completed in 2014 and these types of activities will remain a key focus in 2014 and beyond as the company continues to build its subsea team based on the experience gained from this initial contract. AGR has developed a comprehensive software offering in recent years and with the appointment of a Business Development Manager in the region, has managed to secure its first software sale in Australia with land operator Drillsearch who have recognised the benefits of utilising P1 in the planning and execution of wells in South Australia. Well Management remains core to the company with several major contracts having been secured over the course of 2013 with operators such as Hunt Oil, Minza Petroleum, Otto Energy and CalEnergy. Regional opportunities have also been identified in Vietnam, Malaysia, Philippines, Myanmar and India. Patrick McKinley, EVP Americas Software Software has grown to be an important element of AGR s product offering. In June 2013 AGR Software Solutions was made a separate business unit and Petter Mathisen hired to head it up. The strategy was to raise awareness of AGR s various software tools which include P1, Cost Tracker ANNUAL REPORT

7 (CT ), M² and iq. The aim was to increase sales across all AGR regions and further develop the products to meet client needs. include rig procurement, drilling engineering & planning services, supply chain management and operations support for the drilling of Hagar Qim Well 1. AGR successfully completed the refinancing of the Group, where the two business areas Petroleum Services and Drilling Services were financed separately. As a part of this work, AGR Group ASA s Board of Directors contemplated a legal demerger of the Group's two divisions. Group CEO Sverre Skogen elected to stand down after eight years with AGR, but continued in the role as Chairman of AGR Energy. AGR Petroleum Services EVP Åge Landro succeeded Sverre as CEO as AGR Group ASA. Petter Mathisen, VP Software Solutions Towards the end of July 2013, AGR increased its ownership in WDO owning the iq software from 50% to 56% in order to establish primary control of the product and integrate it with the AGR Software portfolio. A marketing strategy was put into place to give all products a uniform set of logos and marketing material. With P1 being the only sold product by June 2013, a high focus throughout the year was given to the other products. Towards the end of the year all regions had managed to secure sales. AGR E&P During 2011, AGR established AGR Energy which developed through 2012 and AGR is the Operator of several licenses in Israel, holding 5% of each license. In addition, through AGR s 44% ownership in AGR Energy, AGR holds an interest in a deepwater oilfield in Ghana Key Events January: AGR was awarded a Well Management contract from the independent Norwegian E&P company, Noreco. The agreement includes Well Management Services for three years, with the option for Noreco to extend the contract period by an additional two years. AGR Petroleum Services Holdings AS successfully completed a secured bond issue in the amount of NOK 550 million in the Norwegian bond market, with maturity in February Net proceeds from the contemplated bond issue was used to refinance existing debt and for general corporate purposes. February: AGR signed a Service Order with Mediterranean Oil & Gas plc. for the provision of full Well Management Services to March: The Board of Directors of AGR Group ASA approved a demerger plan for the proposed demerger of AGR Group ASA, with the Drilling Services business separated into a new private limited liability company. May: AGR signed an 18million (NOK 180 million) contract with Genel Energy to deliver Well Management Services for Genel Energy's North/West Africa offshore drilling campaign. The contract involves provision of Full Well Management and associated services, including drilling engineering and planning services, supply chain management and operations support for Genel Energy's high impact 10 well drilling campaign. July: AGR was awarded a contract to provide Project Management Services to the large independent operator Hunt Oil for the drilling of one exploration well located in Permit WA-425-P offshore North Western Australia. The contract includes provision of Full Well Management with the semi-submersible rig Stena Clyde, including drilling engineering, planning, procurement, regulatory requirements and operational support. August: The demerger of AGR Group ASA was completed on 7 th August AGR signed a contract with Svenska to deliver Well Management services for Svenska's offshore Guinea Bissau drilling campaign. The contract involves provision of Full Well Management and associated services, including drilling engineering and planning services, supply chain management and operations support for the drilling campaign on Svenska's operated Blocks 2 and 5A licences. The program is for a minimum of one firm well with the option of two additional exploration wells dependent on results. AGR won a major contract to deliver a two-year frame agreement for the Norwegian Petroleum Directorate (NPD). AGR's Norway-based Reservoir Management team will ANNUAL REPORT

8 deliver services within geology and reservoir engineering, including reservoir modelling, petrophysics, reservoir simulation and increased oil recovery. Working Environment and Personnel October: A major Frame Agreement for drilling and well technology consultancy manpower was awarded by Statoil to AGR Consultancy in Norway. Starting in January 2014, the agreement primarily covers Statoil's operations in Norway, but the services may be performed globally. The five-year contract has extension options which could see it extend to 10 years in total. November: Statoil exercised the first two-year option under the Frame Agreement that was announced in January December: AGR was contracted to drill two exploration wells for RWE Dea in the North Sea's Titan area, using the semisubmersible rig Leiv Eiriksson. AGR will deliver Well Delivery Services comprising planning, execution and reporting for the project. Tove Magnussen, SVP HSEQ A core objective of AGR is to have a safe and healthy working environment and the business is managed in accordance with the OSHAS 18001:2004 standard. Performance is monitored continuously, and status reported to the Executive Management team and the Board of Directors on a regular basis. The functioning safety organisations and Working Environment Committees ensure employee involvement in HSE related issues. During 2013, the company had zero incidents resulting in absence and zero medical treatment incidents. Hence, the frequency of lost time injuries and accordingly the frequency of personnel injuries per million working hours (H-value/ H2-value) was zero. AGR Software portfolio Average illness related absence during 2013 was 1.2% corresponding to working days. This is more or less the same as in 2012 and is considered low. There are some variations between the regions, Norway 2.4%, UK 0.7%, APAC 0.6%, Moscow 1.2% and Americas 0.6%. AGR operated 10 rigs in 2013, including facilitation of the rig contract, project management and well operation, seven out of Norway, two out of the UK and one out of the Middle East. The frequency of personnel injuries per million working hours (H2/TRIF-value) was 3.2, based on approximately 1.5 million offshore working hours. This is a decrease from AGR initiates an annual, worldwide engagement survey, monitoring employee satisfaction, involvement and engagement within the business. The results of this survey are used for further improving of the performance. People retention and reducing turnover will remain focus area in ANNUAL REPORT

9 Gender Equality As of 31 December 2013 the Board of AGR Petroleum Services Holdings AS has 3 Board Members of which 0 were women. AGR aspires to be an attractive employer for people with different backgrounds, regardless of their ethnicity, gender, religion or age. In its policy, the company has implemented conditions to ensure equal opportunities in areas such as salary, promotion and recruitment. The competence principle is decisive in all appointment processes. In a department where one gender is heavily under-represented, gender is taken into account during the appointment process if other qualifications are otherwise equal. In connection with the yearly salary evaluation, attention is shown to possible inequality regarding average level of pay for men and women. The Group provides equal pay for equal work and rewards good results. Environmental Reporting All AGR activities that effect the environment are managed by means of well-established systems and processes in order to identify and eliminate or reduce any negative impact, and to ensure, as a minimum, compliance with legislation and regulations set out by the authorities. The environmental aspects of the activities are identified and managed. AGR aims to facilitate the continuous environmental improvement in our operations by adopting the principles of ISO 14001:2007, an international standard for environmental management, and an increasing part of the AGR business are being certified. Internal control activities are run to verify compliance. Environmental Performance Summary 2013: Energy consumption is at a normal level for AGR s type of business Waste management is performed to minimise waste amounts, and to facilitate for reuse and recycling of generated waste Chemicals are managed to reduce use and planned discharge of environmentally hazardous chemicals There were 6 accidental spills from AGR s operations during 2013, from 10 drilling rigs, all risk rated as low risk. This is a significant reduction compared to 2012 with higher activity. ANNUAL REPORT

10 2014 Operations AGR s Board of Directors emphasises that there is always an element of uncertainty related to the delivery of business performance and forward looking projections. The market outlook for 2014 and beyond is very strong. Market Outlook data used for forward planning of the business indicates a 6% annual growth in number of rig days until the end of 2016, while the core client base of AGR is expected to increase their activity with 78% by The high demand for the drilling of wells in combination with a shortage of resources creates a strong foundation for continued growth of AGR. The company is the number one provider of independent drilling management, and with our global footprint we are well positioned to capture a significant share of the future growth in drilling activity. - the core client base of AGR is expected to increase their activity... Our expectation is that there will be a high demand for our services and software solutions going forward, as drilling efficiency, cost efficiency and safety during drilling operations will be vital for oil companies to deliver on their exploration plans. Entering into 2014, the business has an order backlog at the same level as when entering into 2013, while the activity level entering into 2014 is high and significantly up from year end Risk Management and Internal Control the group and the environment in which it operates are continually evolving together with its exposure to risk. The internal control system is designed to manage rather than eliminate the risk of assets being unprotected and to guard against their unauthorised use and the failure to achieve business objective. Internal controls can only provide reasonable and not absolute assurance against material misstatement or loss. The directors confirm that there is an ongoing process for identifying, evaluating and managing the risk faced by the group and the operational effectiveness of the related controls, which has been in place for the year under review and up to the date of approval of the annual report and accounts. They also confirm that they have regularly reviewed the system of internal control utilising the review process set out below. Standard AGR has established a Finance Manual laying out the roles, responsibilities and timelines for the accounting procedures including guidelines on the minimum level of internal control that each of the subsidiary companies should exercise over specified processes. The internal control process has been formalised and implemented where all subsidiaries are carrying out a self-assessment of the internal control, and signing off on an internal control questionnaire. The internal control questionnaire is standardised and similar for all subsidiaries, and includes questions about financial control, IT systems, transfer pricing, inventory, accounts receivables, fixed assets, cash, accounts payable, revenue recognition, cost accruals and so on. The questionnaire is based on the group policy, and provides adequate documentation that the policy is implemented. All companies prepare annual operating plans and budgets, and business strategies are prepared at regional level and approved by the board. In addition AGR prepares financial forecast that are presented to the board at least two times per year. Detailed actual financial segment information is prepared monthly; performance compared to budget is monitored at company and group level. In addition, actual performance is compared to latest forecast and prior year on a monthly basis including analysis of any significant variances. Svein Sollund, CFO Internal control Effective controls ensure that the group is not exposed to avoidable risk, that proper accounting records have been maintained, that the financial information used within the business is reliable and that the consolidated accounts preparation and financial reporting processes comply with all relevant regulatory reporting requirements. The dynamics of Capital expenditure and investment decisions are treated as a part of the budget and forecast processes. Details about who has right to approve investments are described in an authorisation matrix. The cash position of the group is monitored on a daily basis and variances from expected levels are investigated thoroughly. An important factor in ensuring accurate financial reporting is good IT controls. There are several IT controls in place to access the accounting systems for the year as a whole and at the year-end these controls have been intensified. ANNUAL REPORT

11 Results, Cash Flow, Investments, Finance and Liquidity Turnover for AGR increased from NOK million in 2012 to NOK million in Operating profit for AGR was positive NOK 159 million compared to NOK 109 million in Net profit for the financial year 2013 was positive NOK 75 million compared to NOK 53 million in For more information about the background for the results, see Operations section. Accumulated cash flow from the operational activities in 2013 was negative NOK 173 million mainly due to increased working capital in the E&P business (AGR s Operator engagement) which held significant advance payments from its partners at year end Total investments for AGR was NOK 11 million (excluding acquisition of operations), and was mainly related to Software licences. Cash and cash equivalents for the Group on were NOK 125 million. AGR s total interest-bearing debt (excluding capitalized arrangement fee) at year end 2013 was NOK 695 million, of which 145 million represents shareholders loans from AGR Group ASA. Total interest bearing debt represented 55 % of AGR s total assets, compared to 39 % at year-end By year-end 2013, the short-term interest-bearing debt represented 0 % of the total interest-bearing debt. The Group s net interest-bearing debt at the end of 2013 was NOK 570 million including shareholders loans. At the end of the year, total assets amounted to NOK million, down from NOK million the previous year. The equity to total assets ratio at was 20 %, up from 11% at The debt to equity ratio per was 2.7. Financial Risk Financial risk factors AGR s activities are exposed to a variety of financial risks: market risk (including currency-, interest rate- and price risk), credit risk and liquidity risk. AGR s overall risk management program seeks to reduce potential adverse effects from financial risks on AGR s financial performance. AGR uses derivative financial instruments to hedge certain risk exposures. Risk management is carried out by a central treasury department (Group Treasury) under policies approved by the board of directors. AGR Treasury identifies, evaluates and hedges financial risks in co-operation with AGR s operating units. The board provides a financial risk management policy covering foreign exchange risk, interest rate risk, liquidity risk and credit risk. Market risk (i) Foreign exchange risk AGR operates internationally and is exposed to foreign exchange risk arising from various currency exposures, primarily with respect to the US dollar, Australian dollar and the UK pound. Foreign exchange risk arises from future commercial transactions, recognised assets and liabilities and net investments in foreign operations. AGR s Financial risk policy states that 12 month forecasted net currency exposure shall be maximum 60 million in NOK equivalents. Positions are reviewed quarterly. Hedging of the net currency exposure is conducted by applying currency derivatives. (ii) Price risk AGR has very limited exposure to equity securities price risk due to limited investments held by AGR classified on the consolidated balance sheet as fair value through profit or loss. AGR is indirectly exposed to oil price changes. (iii) Interest rate risk AGR s interest rate risk arises from long-term borrowings. Borrowings issued at variable rates expose AGR to cash flow interest rate risk. AGR s policy is that long-term borrowings shall be based on floating interest rates, however interest rate derivatives could be applied in order to avoid catastrophic losses due to interest rate changes. AGR manages its interest rate risk by applying derivatives such as interest rate collar swaps, in order to establish a cap on interest rates in case of significant increase in market interest rates. In addition, the group has formerly applied floating-to-fixed interest rate swaps. Such interest rate swaps have the economic effect of converting borrowings from floating rates to fixed rates. At 31 December 2013 AGR held no interest rate derivative contracts. Credit risk The risk that counterparties fail to fulfill their financial obligations is considered low as AGR s historical losses related to receivables have been low. The majority of the Group's debtors are publicly listed Norwegian and international oil companies. The Petroleum Services client base consists of small to large oil companies. Some of these customers have moderate credit risk potential. The AGR policy is to obtain financial guarantees from debtors where the credit risk and exposure is considered to be high. In addition, AGR has put in place credit insurance where a majority of AGR s receivables are insured in order to reduce credit risk. The overall credit risk is thus considered to be low. ANNUAL REPORT

12 Liquidity risk Delayed payments from several large customers at the same time could have a significant impact on AGR s liquidity. AGR s management and the individual business units have focused highly on working capital management, and continuously take action if clients do not settle their obligations towards AGR in due time. The Group s policy is to reduce the liquidity risk by having a long term loan facility committed from relationship banks and/or bondholders. The Group shall at any time have unused credits at least equal to next quarter s interest & amortisation requirements under AGR s loan facility. At 31 December 2013 the Group had undrawn committed credit lines amounting to NOK 85 million. Parent Company AGR Petroleum Services Holdings AS is the parent company and its main activity is to act as the owner of the shares in the Petroleum Services companies. The operating result in 2013 was negative NOK 31 million compared to negative NOK 13 million in The net result was NOK 93 million in 2013 compared to NOK 39 million in The increase was mainly due to net financial items which increased from NOK 52 million in 2012 to NOK 124 million in Accumulated cash flow from the company s operations was negative NOK 181 million mainly due to increased working capital in the E&P business which held significant advance payments from partners at year end Net proceeds from financing was NOK 50 million which relates to Group Contributions from subsidiaries. Total net cash flow was NOK 116 million. The total assets were NOK million compared to NOK million in the previous year. The equity to asset ratio was 23 %. The Board has considered the factors above in relation to continued operations and concluded that in accordance with the Accounting Act 3-3a, we confirm that the financial statements have been prepared under the assumption of a going concern. ANNUAL REPORT

13 Annual Result and Allocations The Board proposes the following allocations of the AGR s result for the financial year: In NOK Profit for the year Non-controlling interests share of profit for the year 206 Total profit allocated to retained earnings The parent company's distributable equity at was: Profit for the year Total profit allocated to retained earnings Oslo, 30 April 2014 ANNUAL REPORT

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15 Consolidated Income Statement GROUP In NOK Year ended 31 December Continuing operations Note Revenue 6,7, Other operating revenue 6,7, Total operating revenue Goods and consumables used 11, Payroll expenses 18, Depreciation, amortisation and impairments 8, Other operating expenses 23, 25, Total operating expenses Operating profit Financial income Financial expenses Share of loss of an associate 10, Net financial items (29 783) (27 768) Profit before income tax Income tax expense Profit for the year Non-controlling interests' share of profit (loss) for the year 206 (512) Profit attributable to equity holders Earnings per share (NOK) ANNUAL REPORT

16 Consolidated Statement of Comprehensive Income GROUP In NOK Statement of comprehensive income Twelve months ended 31 December Profit for the period Other comprehensive income Currency translation differences (7 425) Net other comprehensive income to be reclassified to profit or loss in (7 425) subsequent periods Other comprehensive income not to be reclassified to profit ro loss in subsequent periods: Re-measurement gains (losses) on defined benefit plans Income tax effect (1 771) - Net other comprehensive income not to be reclassified to profit or loss in subsequent periods Total comprehensive income for the period Profit attributable to: - owners of the company non-controlling interest 206 (512) ANNUAL REPORT

17 Consolidated Statement of Financial Position GROUP In NOK As at 31 December Note Assets Deferred tax assets Other intangibles Goodwill 4, Intangible assets Machinery and operating equipment Tangible fixed assets Investment in an assosiate Long term receivables Financial fixed assets Total non current assets Inventories Trade receivables Related party receivables Other receivables 14, Receivables Financial assets at fair value 16, Cash and cash equivalents 15, Total current assets Total assets ANNUAL REPORT

18 GROUP In NOK As at 31 December Note Equity and liabilities Share capital Other paid in capital Total paid-in equity Retained earnings Non-controlling interest in equity Total equity Pension liabilities Deferred tax Provisions Related party loans Debt to credit institutions Total non-current liabilities Debt to credit institutions Trade payables Related party payables Tax payable VAT payable and other taxes payable Other current liabilities Total current liabilities Total liabilities Total equity and liabilities Oslo, 30 April 2014 ANNUAL REPORT

19 Consolidated Statement of Changes in Equity GROUP In NOK 1000 Share capital Other paid in capital Total paid-in equity Translation effects Retained earnings Total Group Noncontrolling intrests Total equity Opening balance Acquisition of subsidiary Capital contribution, Non-controlling (512) (512) - (512) interest Total other equity movements (512) (512) Profit for the period (512) Other comprehensive income (7 425) - (7 425) - (7 425) Total recognised other comprehensive income (7 425) (512) Adjustment to equity for (7 425) Closing balance (3 966) Opening balance (3 966) Acquisition of subsidiary Capital contribution, Non-controlling interest Total other equity movements Profit for the period Other comprehensive income Total recognised income and expense for Adjustment to equity for Closing balance ANNUAL REPORT

20 Consolidated Statement of Cash Flow GROUP In NOK Note Operating activities Profit/(loss) before taxes Non-cash adjustments to reconcile profit before tax to net cash flows Depreciation,amortisation and impairment of tangible assets 8, Loss/(gain) on disposal of property, plant and equipment 8,9 - (822) Finance income 26 ( ) ( ) Finance costs Other operating income 6,7 - - Pension Working capital adjustments: Increase in trade and other receivables and prepayments (6 591) Increase in inventory (12) Decrease (increase) in trade and other payables ( ) ( ) Decrease(increase) in other provisions (35 900) ( ) Interest received Income tax paid (9 800) (35 080) Net cash flow from operational activities ( ) Investing activities Proceeds from sale of property, plant and equipment and intangible assets Purchase of property, plant and equipment and intangible assets 8,9 (10 531) (21 387) Purchase of financial instruments - - Proceeds from sale of financial instruments - - Acquisition of subsidiary, net of cash acquired 4,8 (2 700) (27 604) Net cash flows used in investing activities (13 231) ( ) Financing activities Proceeds from borrowings Repayment of borrowings 20 ( ) (49 785) Repayment of Group loans - ( ) Interest paid (74 473) (31 256) Dividends paid to non-controlling interests (1 600) - Net cash flow from/ (used) in financing activities ( ) Net increase in cash and cash equivalents ( ) Net foreign exchange differences Cash and cash equivalents at 1 January Cash and cash equivalents at 31 December ANNUAL REPORT

21

22 Notes Note 1 Accounting Principles Company information AGR Petroleum Services Holdings AS ( the Company ) and its subsidiaries (together the Group ), is a leading supplier of services and technology to the oil and gas offshore industry. The Group s main operations are based in Oslo, with other offices around the world including Straume (Bergen), Stavanger, Aberdeen, Houston, Perth, Almaty and Dubai. The company's parent is AGR Group ASA. The company has provided goods and services for several of the world s major oil and gas fields, with a customer base comprising several small and medium sized operators as well as a number of the large international oil companies. The company is a limited liability company incorporated and domiciled in Norway. The address of its registered office is Karenslyst allè 4, 0278, Oslo. The Group consolidated financial statements were authorised for issue by the board of directors on 30 April Summary of significant accounting policies The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated. The consolidated financial statements of AGR Petroleum Services Holdings AS have been prepared in accordance with International Financial Reporting Standards as adopted by EU (IFRS) and IFRIC Interpretations. The Group's financial statements have been prepared under the historical cost convention, with exception of certain items: Financial assets and financial liabilities (including derivative instruments), which are reflected at fair value through profit or loss. The financial year follows the calendar year. Income statement items are classified by nature. The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgment in the process of applying the group s accounting policies. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in Note 3 Critical Accounting Estimates and Judgements. Consolidation principles a) Subsidiaries Subsidiaries are all entities (including special purpose entities) over which the Group has the power to govern the financial and operating policies generally accompanying a shareholding of more than one half of the voting rights. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether the Group controls another entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases. The Group uses the acquisition method of accounting to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair values of the assets transferred, the liabilities incurred and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Acquisition-related costs are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. On an acquisition-by-acquisition basis, the Group recognises any non-controlling interest in the acquisition either at fair value or at the non-controlling interest s proportionate share of the acquired net assets. The excess of the consideration transferred, the amount of any non-controlling interest in the acquisition and the acquisition-date fair value of any previous equity interest in the acquisition over the fair value of the group s share of the identifiable net assets acquired is recorded as goodwill. If this is less than the fair value of the net assets of the subsidiary acquired in the case of a bargain purchase, the difference is recognised directly in the statement of comprehensive income. Inter-company transactions, balances and unrealised gains on transactions between Group companies are eliminated. Unrealised losses are also eliminated. Accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Group. (b) Transactions and non-controlling interests The Group treats transactions with non-controlling interests as transactions with equity owners of the Group. For purchases from non-controlling interests, the difference between any consideration paid and the relevant share acquired of the carrying value of net assets of the subsidiary is recorded in equity. Gains or losses on disposals to noncontrolling interests are also recorded in equity ANNUAL REPORT

23 When the Group ceases to have control or significant influence, any retained interest in the entity is remeasured to its fair value, with the change in carrying amount recognised in profit or loss. The fair value is the initial carrying amount for the purposes of subsequently accounting for the retained interest as an associate, joint venture or financial asset. In addition, any amounts previously recognised in other comprehensive income in respect of that entity are accounted for as if the Group had directly disposed of the related assets or liabilities. This may mean that amounts previously recognised in other comprehensive income are reclassified to profit or loss. (c) Associates Associates are all entities over which the Group has significant influence but not control, generally accompanying a shareholding of between 20 % and 50 % of the voting rights. Investments in associates are accounted for using the equity method of accounting and are initially recognised at cost. The Group s investment in associates includes goodwill identified on acquisition, net of any accumulated impairment loss. Segment reporting Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the steering committee that makes strategic decisions. The primary reporting segment is business segment and the secondary reporting segment is geographical segment. Since the Group s business is limited to providing goods and services to the oil and gas industry, the chief operating decision-maker has organized and manages the entity as one segment based upon the service provided. Consequently, the Group has one operating segment. Even if an entity has a single reportable segment, secondary geographical segment information is required. Geographical segment information is presented and is specified if the region's accumulated external revenues and assets exceed 10 % of total revenue/assets for the regions as a whole. Geographical segment information for revenues that fails to satisfy the requirement for specified reporting is presented as other revenues. Transactions between segments are made on arm's length terms. Segment revenues and costs constitute the Group's operating revenue and operating costs that can be directly classified as activities in the segments. Segment assets and liabilities are balance sheet items that can be directly related to the segment activity. Segment revenue and costs include transactions between the different segments (Group-internal transactions). Geographical segment information is presented and is specified if the region's accumulated external revenues and assets exceed 10 % of total revenue/assets for the regions as a whole. Secondary segment information that fails to satisfy the requirement for specified reporting is presented as other revenues. Transactions between segments are made on arm's length terms. Functional currency and presentation currency (a) Functional and presentation currency Items included in the financial statements of each of the Group s entities are measured using the currency of the primary economic environment in which the entity operates ( the functional currency ). The consolidated financial statements are presented in Norwegian Kroner ( NOK ), which is the company s functional and presentation currency. (b) Transactions and balances Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the income statement, except when deferred in equity as qualifying cash flow hedges and qualifying net investment hedges. Foreign exchange gains and losses that relate to borrowings and cash and cash equivalents are presented in the income statement within finance income or expense. All other foreign exchange gains and losses are presented in the income statement. Changes in the fair value of monetary securities denominated in foreign currency classified as available for sale are analysed between translation differences resulting from changes in the amortised cost of the security and other changes in the carrying amount of the security. Translation differences related to changes in amortised cost are recognised in profit or loss, and other changes in carrying amount are recognised in equity. Translation differences on non-monetary financial assets and liabilities such as equities held at fair value through profit or loss are recognised in profit or loss as part of the fair value gain or loss. Translation differences on non-monetary financial assets such as equities classified as available-for-sale are included in the available-for-sale reserve in equity. (c) Group companies The results and financial position of all the Group entities (none of which has the currency of a hyper-inflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows: (1) assets and liabilities for each balance sheet presented are translated at the closing rate at the date of that balance sheet; (2) income and expenses for each income statement are translated at average exchange rates (unless this average is not ANNUAL REPORT

24 a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the rate on the dates of the transactions); and (3) all resulting exchange differences are recognised as a separate component of equity. On consolidation, exchange differences arising from the translation of the net investment in foreign operations, and of borrowings and other currency instruments designated as hedges of such investments, are taken to shareholders equity. When a foreign operation is partially disposed of or sold, exchange differences that were recorded in equity are recognised in the income statement as part of the gain or loss on sale. Goodwill and fair value adjustments arising on the acquisition of a foreign entity are treated as assets and liabilities of the foreign entity and translated at the closing rate. Classification of assets and liabilities Assets are classified as current assets when: the asset is a part of the unit's service cycle and is expected to be realised or used during the course of the unit's normal production period; the asset is held for trading purposes and is expected to be realised within 12 months of balance sheet date; the asset is cash or cash equivalent. All other assets are classified as non-current. Liabilities are classified as current liabilities when: the liability is a part of the unit's service range, and is expected to be settled during the course of normal production period; the liability is kept for trading purposes; settlement has been agreed within 12 months after balance sheet date; the unit does not have an unconditional right to postpone settlement of the liability until at least 12 months after balance sheet date; All other liabilities are classified as non-current. Property, plant and equipment Property, plant and equipment, are valued at cost less accumulated depreciation and write-downs. When assets are sold or divested, cost and accumulated depreciation are reversed in the financial statements, and any loss or gain on the disposal is recognised in the income statement. The cost of property, plant and equipment comprises the purchase price, including duties/taxes and direct acquisition costs linked to making the asset fit for use. Expenses accrued after the asset has been taken into use, such as repairs and maintenance, are normally recognised in the income statement. In cases where increased earnings can be demonstrated as a result of repairs/maintenance, the expenditure on this will be recognised in the balance sheet as additions to property, plant and equipment. Depreciation on other assets is calculated using the straightline method to allocate their cost or revalued amounts to their residual values over their estimated useful lives, as follows: Machinery 5-10 years Vehicles 3-5 years Furniture, fittings and equipment 3-8 years. The assets residual values and useful lives are reviewed, and adjusted if appropriate, at each balance sheet date. Assets under construction are classified as property, plant and equipment. Assets under construction are not depreciated until the asset has been taken into use. The write-down requirement for fixed assets is assessed if there are indications of impairment. If the carrying amount of an asset is higher than the recoverable amount, a writedown is recognised in the income statement. The recoverable amount is the higher of fair value less expected costs to sell and value in use. Fair value less expected costs to sell is the amount which can be obtained if the asset is sold to an independent third party, less costs to sell. Recoverable amounts are determined separately for all assets, but if impossible recoverable amount is calculated together with the unit to which the asset belongs. Write-downs which have been recognised in the income statement in previous periods are reversed if there is information to suggest that the write-down no longer exists. However, no reversal is made if the carrying amount is higher than it would have been if normal depreciation had been used. Gains and losses on disposals are determined by comparing the proceeds with the carrying amount and are recognised within other operating revenue in the income statement. Intangible assets (a) Goodwill Goodwill represents the excess of the cost of an acquisition over the fair value of the group s share of the net identifiable assets of the acquired subsidiary at the date of acquisition. Goodwill on acquisitions of subsidiaries is included in intangible assets. Goodwill is tested annually for impairment and carried at cost less accumulated impairment ANNUAL REPORT

25 losses. Impairment losses on goodwill are not reversed. Gains and losses on the disposal of an entity include the carrying amount of goodwill relating to the entity sold. Goodwill is allocated to cash-generating units for the purpose of impairment testing. The allocation is made to those cashgenerating units or groups of cash-generating units that are expected to benefit from the business combination. (b) Trademarks and licences Separately acquired trademarks and licences are shown at historical cost. Trademarks and licences acquired in a business combination are recognised at fair value at the acquisition date. Trademarks and licences have a finite useful life and are carried at cost less accumulated amortisation. Amortisation is calculated using the straight-line method to allocate the cost of trademarks and licences over their estimated useful lives of 15 to 20 years. (c) Contractual customer relationships Contractual customer relationships acquired in a business combination are recognised at fair value at the acquisition date. The contractual customer relations have a finite useful life and are carried at cost less accumulated amortisation. Amortisation is calculated using the straight-line method over the expected life of the customer relationship (3-8 years). (d) Computer software Acquired computer software licenses are capitalised on the basis of the costs incurred to acquire and bring to use the specific software. These costs are amortised over their estimated useful lives (3-4 years). Costs associated with maintaining computer software are recognised as an expense as incurred. Costs that are directly associated with the production of identifiable and unique software products controlled by the Group, and that are probable to generate economic benefits exceeding costs beyond one year, are recognised as intangible assets. Direct costs include the software development employee costs and an appropriate portion of relevant overheads. Computer software development costs recognised as assets are amortised over their estimated useful lives (3-4years). (e) Research and development Expenses relating to research are recognised in the income statement when they are incurred. Expenses relating to development are recognised in the income statement when they are incurred unless the following criteria are met in full: ability to measure reliably the expenditure attributable to the intangible asset during its development; the technical feasibility of completing the intangible asset so that it will be available for use or sale, has been demonstrated; the intention and ability to complete the intangible asset and sell it or use it in the Group s operations has been demonstrated; the intangible asset will generate probable future economic benefits; and availability of sufficient technical, financial and other resources for completing the project are present. When all the above criteria are met, the costs relating to development start to be recognised in the balance sheet. Costs that have been charged as expenses in previous accounting periods are not recognised in the balance sheet. Recognised development costs are depreciated on a straightline basis over the estimated useful life of the asset (5-8 years). The recoverable amount of the development costs will be estimated when there is an indication of impairment or that the need for previous periods impairment losses no longer exists and should be reversed to the original cost. (f) Other intangible assets Acquired technology, licenses and customer relationships are capitalised and carried at cost less accumulated amortisation. Amortisation is calculated using the straight-line method over their estimated useful lives. Impairment of non-financial assets Assets that have an indefinite useful life, for example goodwill, are not subject to amortisation and are tested annually for impairment. Assets that are subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cashgenerating units). Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment at each reporting date. Non-current assets (or disposal groups) held for sale Non-current assets (or disposal groups) are classified as assets held for sale when their carrying amount is to be recovered principally through a sale transaction and a sale is considered highly probable. They are stated at the lower of carrying amount and fair value less costs to sell if their carrying amount is to be recovered principally through a sale transaction rather than through continuing use. Financial assets The Group classifies its financial assets in the following categories: at fair value through profit or loss, loans and ANNUAL REPORT

26 receivables, and available-for-sale. The classification depends on the purpose for which the financial assets were acquired. Management determines the classification of its financial assets at initial recognition. (a) Financial assets at fair value through profit or loss Financial assets at fair value through profit or loss are financial assets held for trading. A financial asset is classified in this category if acquired principally for the purpose of selling in the short-term. Derivatives are also categorised as held for trading unless they are designated as hedges. Assets in this category are classified as current assets. (b) Loans and receivables Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are included in current assets, except for maturities greater than 12 months after the balance sheet date. These are classified as non-current assets. The Group s loans and receivables comprise trade and other receivables and cash and cash equivalents in the balance sheet. (c) Available-for-sale financial assets Available-for-sale financial assets are non-derivatives that are either designated in this category or not classified in any of the other categories. They are included in non-current assets unless management intends to dispose of the investment within 12 months of the balance sheet date. Regular purchases and sales of financial assets are recognised on the trade-date the date on which the Group commits to purchase or sell the asset. Investments are initially recognised at fair value plus transaction costs for all financial assets not carried at fair value through profit or loss. Financial assets carried at fair value through profit or loss is initially recognised at fair value and transaction costs are expensed in the income statement. Financial assets are derecognised when the rights to receive cash flows from the investments have expired or have been transferred and the group has transferred substantially all risks and rewards of ownership. Available-for-sale financial assets and financial assets at fair value through profit or loss are subsequently carried at fair value. Loans and receivables are carried at amortised cost using the effective interest method. Gains or losses arising from changes in the fair value of the financial assets at fair value through profit or loss category are presented in the income statement. Impairment of financial assets The Group assesses at the end of each reporting period whether there is objective evidence that a financial asset or group of financial assets is impaired. A financial asset or a group of financial assets is impaired and impairment losses are incurred only if there is objective evidence of impairment as a result of one or more events that occurred after the initial recognition of the asset (a loss event ) and that loss event (or events) has an impact on the estimated future cash flows of the financial asset or group of financial assets that can be reliably estimated. The criteria that the Group uses to determine that there is objective evidence of an impairment loss include: significant financial difficulty of the issuer or obligor; a breach of contract, such as a default or delinquency in interest or principal payments; the Group, for economic or legal reasons relating to the borrower s financial difficulty, granting to the borrower a concession that the lender would not otherwise consider; it becomes probable that the borrower will enter bankruptcy or other financial reorganisation; the disappearance of an active market for that financial asset because of financial difficulties; or observable data indicating that there is a measurable decrease in the estimated future cash flows from a portfolio of financial assets since the initial recognition of those assets, although the decrease cannot yet be identified with the individual financial assets in the portfolio, including: (i) adverse changes in the payment status of borrowers in the portfolio; (ii) national or local economic conditions that correlate with defaults on the assets in the portfolio. The Group first assesses whether objective evidence of impairment exists. 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 credit losses that have not been incurred) discounted at the financial asset s original effective interest rate. The asset s carrying amount of the asset is reduced and the amount of the loss is recognised in the consolidated income statement. If a loan or held-to-maturity investment has a variable interest rate, the discount rate for measuring any impairment loss is the current effective interest rate determined under the contract. As a practical expedient, the group may measure impairment on the basis of an instrument s fair value using an observable market price. 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 (such as an improvement in the debtor s credit rating), the reversal of the previously recognised impairment loss is recognised in the consolidated income statement. ANNUAL REPORT

27 Derivative financial instruments and hedging activities Derivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently remeasured at their fair value. The method of recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument, and if so, the nature of the item being hedged. The Group does not use hedge accounting according to IAS 39, and all financial derivatives are thus posted at fair value where changes in values are accounted for in the income statement. Inventories Inventories are stated at the lower of cost and net realisable value. Cost is determined using the first-in, first-out (FIFO) method. Net realisable value is the estimated selling price in the ordinary course of business, less applicable variable selling expenses. Costs of inventories include the transfer from equity of any gains/losses on qualifying cash flow hedges purchases of raw materials. Obsolete inventories have been fully recognised as impairment losses. Trade receivables Trade receivables are amounts due from customers for merchandise sold or services performed in the ordinary course of business. If collection is expected in one year or less (or in the normal operating cycle of the business if longer), they are classified as current assets. If not, they are presented as noncurrent assets. Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment. Discounting occurs only if the receivable are significant. Cash and cash equivalents Cash and cash equivalents includes cash in hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less, and bank overdrafts. Bank overdrafts are shown within borrowings in current liabilities on the balance sheet. The cash and cash equivalent amount in the cash flow statement includes overdraft facilities. Share capital Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from the proceeds. Where any Group company purchases the company s equity share capital (treasury shares), the consideration paid, including any directly attributable incremental costs (net of income taxes) is deducted from equity attributable to the company s equity holders until the shares are cancelled or reissued. Where such shares are subsequently reissued, any consideration received, net of any directly attributable incremental transaction costs and the related income tax effects, is included in equity attributable to the company s equity holders. Trade payables Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Accounts payable are classified as current liabilities if payment is due within one year or less (or in the normal operating cycle of the business if longer). If not, they are presented as non-current liabilities. Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method. Discounting occurs only if the payable are significant Borrowings Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the income statement over the period of the borrowings using the effective interest method. Fees paid on the establishment of loan facilities are recognised as transaction costs of the loan to the extent that it is probable that some or all of the facility will be drawn down. In this case, the fee is deferred until the draw-down occurs. To the extent there is no evidence that it is probable that some or all of the facility will be drawn down, the fee is capitalised as a pre-payment for liquidity services and amortised over the period of the facility to which it relates. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the balance sheet date. Current and deferred income tax The tax expense for the period comprises current and deferred tax. Tax is recognised in the income statement, except to the extent that it relates to items recognised directly in equity. In this case, the tax is also recognised in equity, respectively. The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the balance sheet date in the countries where the company s subsidiaries and associates operate and generate taxable income. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. It establishes provisions where appropriate on the basis of amounts expected to be paid to the tax authorities. Deferred income tax is recognised, using the liability method, on temporary differences arising between the tax bases of ANNUAL REPORT

28 assets and liabilities and their carrying amounts in the consolidated financial statements. However, the deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit nor loss. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the balance sheet date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled. Deferred income tax assets are recognised only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilised. Deferred income tax is provided on temporary differences arising on investments in subsidiaries and associates, except where the timing of the reversal of the temporary difference is controlled by the group and it is probable that the temporary difference will not reverse in the foreseeable future. Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when the deferred income taxes assets and liabilities relate to income taxes levied by the same taxation authority on either the taxable entity or different taxable entities where there is an intention to settle the balances on a net basis. Employee benefits (a) Pension obligations Group companies operate various pension schemes. The schemes are generally funded through payments to insurance companies, determined by periodic actuarial calculations. The Group has both defined benefit and defined contribution plans. A defined contribution plan is a pension plan under which the Group pays fixed contributions into a separate entity. The Group has no legal or constructive obligations to pay further contributions if the fund does not hold sufficient assets to pay all employees the benefits relating to employee service in the current and prior periods. A defined benefit plan is a pension plan that is not a defined contribution plan. Typically, defined benefit plans define an amount of pension benefit that an employee will receive on retirement, usually dependent on one or more factors such as age, years of service and compensation. The liability recognised in the balance sheet in respect of defined benefit pension plans is the present value of the defined benefit obligation at the balance sheet date less the fair value of plan assets, together with adjustments for unrecognised actuarial gains or losses and past service costs. The defined benefit obligation is calculated annually by independent actuaries using the projected unit credit method. The present value of the defined benefit obligation is determined by discounting the estimated future cash outflows using interest rates of high-quality corporate bonds that are denominated in the currency in which the benefits will be paid and that have terms to maturity approximating to the terms of the related pension liability. Actuarial gains and losses arising from experience adjustments and changes in actuarial assumptions in excess of the greater of 10% of the value of plan assets or present value of the defined benefit obligation at the end of the previous reporting period, are charged or credited to income over the employees expected average remaining working lives. Past-service costs are recognised immediately in income, unless the changes to the pension plan are conditional on the employees remaining in service for a specified period of time (the vesting period). In this case, the past-service costs are amortised on a straight-line basis over the vesting period. For defined contribution plans, the Group pays contributions to publicly or privately administered pension insurance plans on a mandatory, contractual or voluntary basis. The Group has no further payment obligations once the contributions have been paid. The contributions are recognised as employee benefit expense when they are due. Prepaid contributions are recognised as an asset to the extent that a cash refund or a reduction in the future payments is available. (b) Termination benefits Termination benefits are payable when employment is terminated by the Group before the normal retirement date, or whenever an employee accepts voluntary redundancy in exchange for these benefits. The Group recognises termination benefits when it is demonstrably committed to either: terminating the employment of current employees according to a detailed formal plan without possibility of withdrawal; or providing termination benefits as a result of an offer made to encourage voluntary redundancy. Benefits falling due more than 12 months after the balance sheet date are discounted to their present value. (c) Bonus plans The Group recognises a provision where contractually obliged or where there is a past practice that has created a constructive obligation. Provisions Provisions are recognised when, and only when, the company has a present liability (legal or constructive) as a result of events that have taken place, it is probable that a financial outflow will take place as a result of this liability, and that the size of the amount can be estimated reliably. Provisions are reviewed on each balance sheet date and their level reflects the best estimate of the liability. When the effect of time is insignificant, the provisions will be equal to the size of the expense necessary to be free of the liability. When the effect of time is significant, the provisions will be the present value of future payments to cover the liability. Any increase in the provisions due to time is presented as interest costs. ANNUAL REPORT

29 Contingent liabilities Contingent liabilities are defined as: (i) possible obligations resulting from past events whose existence depends on future events; (ii) obligations that are not recognised because it is not probable that they will lead to an outflow of resources; and (iii) obligations that cannot be measured with sufficient reliability. Contingent liabilities are not recognised in the annual financial statements, apart from contingent liabilities which are acquired through the acquisition of an entity. Significant contingent liabilities are disclosed, with the exception of contingent liabilities where the probability of the liability occurring is remote. Contingent liabilities acquired upon the purchase of operations are recognised at fair value even if the liability is not probable. The assessment of probability and fair value is subject to constant review. Changes in the fair value are recognised in the income statement. A contingent asset is not recognised in the annual financial statement unless deemed virtually certain to give rise to an inflow, but are disclosed where it is deemed probable that a benefit will accrue to the Group. Revenue recognition Revenue comprises the fair value of the consideration received or receivable for the sale of goods and services in the ordinary course of the Group s activities. Revenue is shown net of value-added tax, returns, rebates and discounts and after eliminating sales within the Group. Revenue includes only the gross inflows of economic benefits received and receivable by the entity on its own account. Amounts collected on behalf of third parties such as sales taxes, goods and services taxes and value added taxes are not economic benefits which flow to the entity and do not result in increases in equity. Therefore, they are excluded from revenue. Similarly, when an agency relationship, the gross inflows of economic benefits include amounts collected on behalf of the principal and which do not result in increases in equity for the entity. The amounts collected on behalf of the principal are not revenue. Instead, revenue is the amount of commission. The Group recognises revenue when the amount of revenue can be reliably measured, it is probable that future economic benefits will flow to the entity and when specific criteria have been met for each of the Group s activities as described below. The amount of revenue is not considered to be reliably measurable until all contingencies relating to the sale have been resolved. The Group bases its estimates on historical results, taking into consideration the type of customer, the type of transaction and the specifics of each arrangement. The Group s operations mainly consist of services related to personnel and equipment hire. Consequently, the revenue recognition is based on daily/monthly rates and actual registered hours. Revenue is recognised when it is probable that transactions will generate future economic benefits that will flow to the company and the revenue amount can be reliably estimated. Revenues from the sale of goods are recognised in the income statement once delivery has taken place, the risk has been transferred and the company has established a receivable due by customer. Interest income is recognised on a time-proportion basis using the effective interest method. When a receivable is impaired, the Group reduces the carrying amount to its recoverable amount, being the estimated future cash flow discounted at the original effective interest rate of the instrument, and continues unwinding the discount as interest income. Interest income on impaired loans is recognised using the original effective interest rate. Leases Leases in which a significant portion of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Payments made under operating leases (net of any incentives received from the lessor) are charged to the income statement on a straight-line basis over the period of the lease. Earnings per share Earnings per share are calculated by the majority's share of the result for the period being divided by a time-weighted average of ordinary shares for the period. Events after date of balance sheet New information on the Group's positions at the balance sheet date is taken into account in the annual financial statements. Events after the balance sheet date that do not affect the Group's position at the balance sheet date but which will affect the Group's position in the future are disclosed if significant. Cash Flow Statement The cash flow statement presents the accumulated cash flow for operational, investment and financial activities. The statement outlines the effect each activity has on liquid assets. The cash flow statement has been prepared in line with the indirect model. Discontinued operations If a significant part of the Group s operations is divested or a decision has been made to divest it, this business is presented as Discontinued operations on a separate line of the income statement and the balance sheet. As a result, all the other figures presented are exclusive of the discontinued operations. The comparative figures in the income statement are restated and presented on a single line with the discontinued operations. Comparative figures in the balance sheet are not correspondingly restated. ANNUAL REPORT

30 Changes in accounting policy and disclosures IFRSs implemented The Group applied, for the first time, certain standards and amendments. Due to materiality, none of these required restatement of previous financial statements. These include IAS 19 Employee Benefits (Revised 2011), IFRS 13 Fair Value Measurement and amendments to IAS 1 Presentation of Financial Statements. Several other amendments apply for the first time in However, they do not impact the annual consolidated financial statements of the Group or the interim condensed consolidated financial statements of the Group. The nature and the impact of each new standards and amendments is described below: IFRS 13 Fair Value Measurement IFRS 13 establishes a single source of guidance under IFRS for all fair value measurements. IFRS 13 does not change when an entity is required to use fair value, but rather provides guidance on how to measure fair value under IFRS. IFRS 13 defines fair value as an exit price. As a result of the guidance in IFRS 13, the Group re-assessed its policies for measuring fair values, in particular, its valuation inputs such as non-performance risk for fair value measurement of liabilities. IFRS 13 also requires additional disclosures. Application of IFRS 13 has not materially impacted the fair value measurements of the Group. Additional disclosures where required, are provided in the individual notes relating to the assets and liabilities whose fair values were determined. IAS 1 Presentation of Items of Other Comprehensive Income Amendments to IAS 1 The amendments to IAS 1 introduce a grouping of items presented in OCI. Items that will be reclassified ( recycled ) to profit or loss at a future point in time (e.g., net loss or gain on AFS financial assets) have to be presented separately from items that will not be reclassified (e.g., revaluation of land and buildings). The amendments affect presentation only and have no impact on the Group s financial position or performance. IAS 1 Clarification of the requirement for comparative information (Amendment) These amendments clarify the difference between voluntary additional comparative information and the minimum required comparative information. An entity must include comparative information in the related notes to the financial statements when it voluntarily provides comparative information beyond the minimum required comparative period. The amendments clarify that the opening statement of financial position (as at 1 January 2012 in the case of the Group), presented as a result of retrospective restatement or reclassification of items in financial statements does not have to be accompanied by comparative information in the related notes. As a result, the Group has not included comparative information in respect of the opening statement of financial position as at 1 January The amendments affect presentation only and have no impact on the Group s financial position or performance. IAS 19 Employee Benefits (Revised 2011) The Group applied IAS 19 (Revised 2011) retrospectively in the current period in accordance with the transitional provisions set out in the revised standard. Due to materiality the opening statement of financial position of the earliest comparative period presented (1 January 2012) and the comparative figures have not been accordingly restated. IFRSs and IFRICs issued but not yet effective. IFRS 9 Financial Instruments IFRS 9 as issued reflects the first phase of the IASBs work on replacement of IAS 39 and applies to classification and measurement of financial assets and financial liabilities as defined in IAS 39. According to IFRS 9 financial assets with basic loan features shall be measured at amortised cost, unless one opts to measure these assets at fair value. All other financial assets shall be measured at fair value. The classification and measurement of financial liabilities under IFRS 9 is a continuation from IAS 39, with the exception of financial liabilities designated at fair value through profit or loss (fair value option), where change in fair value relating to own credit risk shall be separated and shall be presented in other comprehensive income. In subsequent phases, the IASB will address hedge accounting and impairment of financial assets. IFRS 9 is effective for annual periods beginning on or after 1 January 2015, but the standard is not yet approved by the EU. The Group expects to apply IFRS 9 as of 1 January IFRS 10 Consolidated Financial Statements IFRS 10 replaces the portion of IAS 27 Consolidated and Separate Financial Statements that addresses the accounting for consolidated financial statements. It also includes the issues raised in SIC-12 Consolidation Special Purpose Entities. IFRS 10 establishes a single control model that applies to all entities including special purpose entities. The changes introduced by IFRS 10 will require management to exercise significant judgement to determine which entities are controlled, and therefore, are required to be consolidated by a parent, compared with the requirements that were in IAS 27. ANNUAL REPORT

31 The Group is currently assessing the impact that this standard will have on the financial position and performance. This standard becomes effective for annual periods beginning on or after 1 January The Group expects to apply IFRS 10 as of 1 January IFRS 11 Joint Arrangements IFRS 11 replaces IAS 31 Interests in Joint Ventures and SIC-13 Jointly-controlled Entities Non-monetary Contributions by Venturers. IFRS 11 removes the option to account for jointly controlled entities (JCEs) using proportionate consolidation. Instead, JCEs that meet the definition of a joint venture must be accounted for using the equity method. The Group is does not expect that the impact that this standard will have any effect on the financial position and performance. This standard becomes effective for annual periods beginning on or after 1 January The Group expects to apply IFRS 11 as of 1 January IFRS 12 Disclosure of Involvement with Other Entities IAS 28 Investments in Associates and Joint Ventures (as revised in 2011) As a consequence of the new IFRS 11 and IFRS 12, IAS 28 has been renamed IAS 28 Investments in Associates and Joint Ventures, and describes the application of the equity method to investments in joint ventures in addition to associates. IAS 28 as revised in 2011 becomes effective for annual periods beginning on or after 1 January The Group expects to implement the revised IAS 28 as of 1 January 2014 and does not expect the amendment to have an impact on the Group. IAS 32 Financial Instruments - Presentation (amendment) The amendments to IAS 32 clarify the meaning of "currently has a legally enforceable right to set-off" and also clarify the application of the IAS 32 offsetting criteria to settlement systems (such as central clearing house systems) which apply gross settlement mechanisms that are not simultaneously. The amended IAS 32 is effective for annual periods beginning on or after 1 January The Group expects to implement the amended IAS 32 as of 1 January IFRS 12 includes all of the disclosures that were previously in IAS 27 related to consolidated financial statements, as well as all of the disclosures that were previously included in IAS 31 and IAS 28. These disclosures relate to an entity s interests in subsidiaries, joint arrangements, associates and structured entities. A number of new disclosures are also required. This standard becomes effective for annual periods beginning on or after 1 January The Group expects to apply IFRS 12 as of 1 January IFRS 10, IFRS 11 and IFRS 12 Amendments - Transition guidance The amendments clarify and provide further relief in transition guidance. These amendments becomes effective for annual periods beginning on or after 1 January 2013, but are not yet approved by the EU which will likely provide an effective date on or after 1 January The Group expects to apply these amendments when it implements IFRS 10, IFRS 11 and IFRS 12. IAS 27 Separate Financial Statements (as revised in 2011) As a consequence of the new IFRS 10 and IFRS 12, what remains of IAS 27 is limited to accounting for subsidiaries, jointly controlled entities, and associates in separate financial statements. This revision will not have an impact on the consolidated financial statements of the Group. IAS 27 as revised in 2011 becomes effective for annual periods beginning on or after 1 January The Group expects to implement the revised IAS 27 as of 1 January ANNUAL REPORT

32 Note 2 Financial Risk Management Financial risk factors The Group s activities are exposed to a variety of financial risks. Market risks including currency risk, interest rate risk, credit risk and liquidity risk. The Group s overall risk management program focuses on the unpredictability of financial markets and seeks to minimize potential adverse effects on the Group s financial performance. The Group uses debt and derivative financial instruments to hedge certain risk exposures. Risk management is carried out by a central treasury department (Group Treasury) under policies approved by the board of directors. Group treasury identifies, evaluates and hedges financial risks in co-operation with the group s operating units. The board provides risk management policies covering specific areas, such as foreign exchange risk, interest rate risk, liquidity risk and credit risk. (a) Market risk (i) Foreign exchange risk The Group operates internationally and is exposed to foreign exchange risk arising from various currency exposures, primarily with respect to the US and Australian Dollar and the British Pound. Foreign exchange risk arises from future commercial transactions, recognised assets and liabilities and net investments in foreign operations. The Group s financial risk policy is that 12 month forecasted net currency exposure shall be maximum 60 million in NOK equivalents. Positions are reviewed quarterly. Hedging is conducted by applying currency derivatives such as forward exchange rate contracts. The group held no FX derivatives at year end 2013, however new FX derivative contracts were entered into i January If the NOK currency in 2013 had weakened/strengthened by 10 % against the US Dollar (USD) with all other variables held constant, EBIT for the year would have been approximately NOK 4 million higher/lower, mainly as a result of foreign exchange gains/losses on translation of net USD revenues. If the NOK currency in 2013 had weakened/strengthened by 10 % against the Australian Dollar (AUD) with all other variables held constant, EBIT for the year would have been approximately NOK 2 million higher/lower, mainly as a result of foreign exchange gains/losses on translation of net AUD revenues. If the NOK currency had weakened/strengthened 10 % against the British Pound (GBP) with all other variables held constant, EBIT for the year would have been approximately NOK 2 million lower/higher, mainly as a result of foreign exchange gains/losses on translation of net GBP costs. (ii) Price risk The Group is indirectly exposed to changes in the oil price, however current group policy is to not hedge oil price changes. (iii) Cash flow and fair value interest rate risk As the Group has no significant interest-bearing assets, the Group s income and operating cash flows are substantially independent of changes in market interest rates. The Group s interest rate risk arises from long-term borrowings. Borrowings issued at variable rates expose the group to cash flow interest rate risk. Group policy is that long-term borrowings shall be based on floating interest rates, however interest rate derivatives could be applied in order to avoid significant losses due to interest rate changes. The Group manages its interest rate risk by applying derivatives such as interest rate collar swaps, in order to establish a cap on interest rates in case of significant increase in market interest rates. In addition, the group has formerly applied floatingto-fixed interest rate swaps. Such interest rate swaps have the economic effect of converting borrowings from floating rates to fixed rates. The Group held both interest rate collar swaps and interest rate swaps until Q2 2013, but had no interest rate derivatives at year end Based on the risk analysis where a 1 % interest rate increase/decrease is applied, the impact of net interest expenses would be negative NOK 5.5 million and positive NOK 5.5 million respectively. ANNUAL REPORT

33 (b) Credit risk Credit risk is managed on group basis. Credit risk arises from cash and cash equivalents, derivative financial instruments and deposits with banks, as well as credit exposure to customers, including receivables and committed transactions. The majority of the Group's debtors are publicly listed Norwegian and international oil companies. AGR s customers consist of large, medium and small oil companies. Some of these customers have moderate credit risk potential. The Group seeks to obtain financial guarantees from debtors where the credit risk and exposure is considered to be high. In addition, majority of the Group s receivables are credit insured in order to reduce credit risk. The Group s main bank at 31st December 2013 is DNB Bank ASA where the majority of group cash is deposited. In addition the Group has other local banking relations in countries where DNB does not provide local services. The table below shows the rating of the Group main cash management bank Counterparty Long-term Rating Overdraft facility limit * Balance** Overdraft facility limit Balance Moody`s S&P DNB Bank ASA A-1 A (2 780) * In addition the Group has a Revolving Credit Facility of TNOK available for bank guarantees, letter of credits and cash drawings ** Aggregated cash pool deposits including deposits made by the parent company AGR Group ASA of NOK 16.6 million. The deposits have been booked as a related party payable in AGR Petroleum Services Holdings consolidated balance sheet c) Liquidity risk The Group has a customer portfolio with large, medium and small cap customers. Delayed payments from some of the largest customers at the same time could have a significant impact on the Group's liquidity situation. Prudent liquidity risk management implies maintaining sufficient cash and the availability of funding through an adequate amount of committed credit facilities. Due to the dynamic nature of the underlying businesses, group treasury maintains flexibility in funding by maintaining availability under committed credit lines. At 31 December 2013 the Group had undrawn committed shortterm credit lines amounting to NOK 85 million plus cash deposits of NOK 125 million (including NOK 16.6 milllion deposited by AGR Group ASA in AGR Petroleum Services Holdings cash pool system). Management monitors rolling forecasts of the Group s liquidity reserve and cash and cash equivalents on the basis of shortterm and long-term cash flow forecasts. The table below analyses the group s financial liabilities and net-settled derivative financial liabilities into relevant maturity groupings based on the remaining period at the balance sheet to the contractual maturity date. Figures in NOK (TNOK) Less than 1 year Between 1 and 2 years Between 2 and 5 years Over 5 Years Borrowings (refer to note 20) Derivative financial instruments (interest rate swaps & collars) Trade and other payables (TNOK) Less than 1 year Between 1 and 2 years Between 2 and 5 years Over 5 Years Borrowings (refer to note 20) Derivative financial instruments (interest rate swaps & collars) Trade and other payables ANNUAL REPORT

34 Capital risk management The Group s objectives when managing capital are to safeguard the group s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Group s long term target capital structure is an equity ratio of at least 25 %. In order to maintain or adjust the capital structure, the group may adjust the amount of dividends paid to shareholders, return capital to shareholders, issue new shares or sell assets to reduce debt. There were no dividends in The gearing ratios, defined as net debt to total capital, at 31 December 2013 and 31 December 2012 were as follows: Total borrowings (excluding capitalised arrangement fees) Less: cash and cash equivalents* ( ) ( ) Net debt Total equity Total capital Gearing ratio 34 % 20 % * 2013 including NOK 16.6 milllion deposited by AGR Group ASA in AGR Petroleum Services Holdings cash pool system Fair value estimation The fair value of financial instruments traded in active markets (such as trading) is based on quoted market prices at the balance sheet date. The quoted market price used for financial assets held by the Group is the current bid price. The fair value of financial instruments that are not traded in an active market (for example, over-the-counter derivatives) is determined by using valuation techniques. The Group uses a variety of methods and makes assumptions that are based on market conditions existing at each balance sheet date. Quoted market prices or dealer quotes for similar instruments are used for long-term debt. Other techniques, such as estimated discounted cash flows, are used to determine fair value for the remaining financial instruments. The fair value of interest rate swaps is calculated as the present value of the estimated future cash flows. The fair value of forward foreign exchange contracts is determined using quoted forward exchange rates at the balance sheet date. The carrying value less impairment provision of trade receivables and payables are assumed to approximate their fair values. The fair value of financial liabilities for disclosure purposes is estimated by discounting the future contractual cash flows at the current market interest rate that is available to the Group for similar financial instruments. Note 3 Critical Accounting Estimates and Judgements The preparation of consolidated financial statements in accordance with IFRSs and applying the chosen accounting policies requires management to make judgements, estimates and assumptions that affect the reported amounts of revenues, expenses, assets, liabilities, and the disclosure of contingent liabilities. However, uncertainty about these assumptions and estimates could result in outcomes that require material adjustment to the carrying amount of the asset or liability affected in future periods. The estimates and associated assumptions are based on historical experience and various other factors that are believed to be reasonable under the circumstances. Actual results may differ from these estimates. The estimates and the underlying assumptions are reviewed on an ongoing basis. Revision to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods. The accounting policies applied by the Group in which judgements, estimates and assumptions may significantly differ from actual results are addressed below. Impairment of non-current assets The Group's accounts for the impairment of non-current assets in accordance with IAS 36 Impairment of Assets. Under IAS 36 The Group are required to assess the conditions that could cause an asset to become impairment at least annually, and to ANNUAL REPORT

35 perform a recoverability test for potentially impaired assets held by the entity. Impairment exists when the carrying value of an assets or cash generating unit exceeds its recoverable amount, which is the higher of its fair value less cost to sell and its value to use. Directly observable market prices rarely exist for the Group s assets, however, fair value may be estimated based on recent observed transactions on comparable assets, bids or other discussions of potential transaction involving the asset, or internal models used by the Group for transactions involving the same type of assets. The value in use calculation is based on a discounted cash flow model. The cash flows are derived from budget for the next five years and do not include restructuring activities that the Group is not yet committed to or significant future investments that will enhance the asset s performance of the cash generating unit being tested. Such estimate are subjects to a number of assumptions including the useful lives of assets, replacement costs and the timing and amounts of certain future cash flows, which may be dependent on future prices, future activity, currency rates, and a suitable discount rate in order to calculate present value. While the Group believe that the assumptions are appropriate, such amounts estimated could differ materially from what will actually occur in the future. Refer to Note 9 Fixed Assets for disclosure of fixed assets. Impairment of goodwill In accounting for the acquisition of business, the Group is required to determine the fair value of assets, liabilities, intangible assets and contingent liabilities at the time of acquisition. In case of business combination achieved in stages, the Group must also estimate the fair value of the existing ownership interest when it gains control. Any excess purchase price is included in goodwill. In the business the Group operates, fair values of individual assets and liabilities are normally not readily observable in active markets, which require the Group to estimate the fair value of acquired assets and liabilities through valuation techniques. Determining whether goodwill is impaired requires an estimation of the value in use of the cash-generating units to which goodwill has been allocated. The value in use calculation requires the management to estimate the future cash flows expected to arise from cash-generating units. See discussion above regarding impairment of non-current assets. According to impairment test performed for 2013 and 2012 the recoverable amounts exceed the carrying amount for the Group. The impairment test of goodwill is not sensitive to an increase of 1 % in the discount rate in 2013 or 2012, or a 2% decrease in margins in 2013 or 2012 compared to management s estimates. Fair value measurement of contingent consideration Contingent consideration, resulting from business combinations, is valued at fair value at the acquisition date as part of the business combination. When the contingent consideration meets the definitions of a derivate and, thus a financial liability, it is subsequently remeasured to fair value at each reporting date. The determination of the fair value is based on discounted cash flows. The key assumptions take into consideration the probability of meeting each performance target and the discount factor. Refer to Note 24 Provisions for provisions for business combinations. Capitalised development costs Certain development costs are capitalised when it is probable that a development project will generate future economic benefits and certain criteria, including commercial and technological feasibility, have been met. These costs are then amortised on a systematic basis over their expected useful lives. During the development stage, management must estimate the commercial and technological feasibility of these projects as well as their expected useful lives. Whenever there is an indicator that development costs capitalised for a specific project may be impaired, the recoverable amount of the asset is estimated. See discussion above regarding impairment of non-current assets. Refer to Note 8 Intangible Assets for disclosure of capitalised development cost. Trade receivables Calculation of provision for impairment of trade receivables is based on a number of estimates. Areas including significant financial difficulties of the debtor, probability that the debtor will enter bankruptcy or financial reorganization, and default or delinquency in payments (more than 30 days overdue) are all considered indicators that the trade receivable is impaired. However, assessing the fair value of the amounts recoverable is highly judgmental and incomplete or incorrect information could lead to significant changes in the recoverable amounts. Refer to Note 13 Aging Trade Debtors at Nominal Value for aging and provision for impairment of trade receivables. Pension liabilities The fair value of pension liabilities is calculated based on several actuarial and economic assumptions. An actuarial valuation ANNUAL REPORT

36 involves making various assumptions that may differ from actual developments in the future. These include the determination of the discount rate, future salary increases, mortality rates and future pension increases. Due to the complexity of the valuation, the underlying assumptions and its long-term nature, a defined benefit obligation is highly sensitive to changes in these assumptions. The discount rate and other assumptions are normally reviewed annually when the actuarial calculation is carried out, unless there are significant changes during the year. Refer to Note 18 Pensions and Pension Commitments for disclosure of actuarial assumptions for the Group. Income tax The Group calculates income tax expense based on reported income in the different legal entities. Deferred income tax expense is calculated based on the differences between the assets carrying value for financial reporting purposes and their respective tax basis that are considered temporary in nature. The total amount of income tax expense and allocation between current and deferred income tax requires management s interpretation of complex tax laws and regulations in the many tax jurisdictions where the Group operates. Valuation of deferred tax assets is dependent on management s assessment of future recoverability of the deferred benefit. Expected recoverability may result from expected taxable income in the near future, planned transactions or planned tax optimizing measures. Economic conditions may change and lead to a different conclusion regarding recoverability, and such change may affect the result for each reporting period. Tax authorities in different jurisdictions may challenge the Group s calculation of tax payable from prior periods. Such process may lead to changes to prior periods taxable income, resulting in changes to income tax expense in the period of change. During the period when tax authorities may challenge the taxable income, management is required to make estimates of the probability and size of possible tax adjustments. Such estimates may change as additional information becomes known. Refer to Note 19 Tax disclosure of tax. Note 4 Business Combinations Acquisitions in 2013: During 2013 AGR increased its interest in Well Design Online AS (WDO) to 56 % of the shares. Total purchase price was NOK 3.5 million. No goodwill or other intangible assets arised from this acquisition, which is considered to be immaterial for the Group. The company is included in the Software division. Acquisitions in 2012: On 9 May 2012, the Group acquired an 80 % shareholding in Steinsvik & Co AS. Headquartered in Stavanger, Steinsvik & Co supplies safety professionals, including safety coaches and internal control officers (ICO), to drilling rigs in the Norwegian market. The firm also provides HSE training for oil companies and performs safety inspections on rigs operating both on the Norwegian sector and internationally. The acquisition is part of AGR's strategy to strengthen their HSE product offering. AGR has worked closely with Steinsvik for many years and, with Steinsvik now part of the product offering, will enhance the Groups' well management operations and help deliver safe and efficient drilling operations for our clients. In NOK Purchase consideration: Steinsvik & Co Cash paid Guarantee amount (note 24) Total purchase consideration The assets and liabilities arising from the acquisition are as follows: Steinsvik & Co Fair value Acquiree's carrying amount Cash and cash equivalents Property, plant and equipment (note 9) Financial fixed assets Trade and other receivables ANNUAL REPORT

37 Trade and other payables (10 071) (10 071) Deferred tax liabilities (note 19) (62) (62) Fair value of net assets Non-controlling interest measured at fair value (1 094) Goodwill (note 8) Total purchase consideration Purchase consideration settled in cash Cash and cash equivalents in subsidiary acquired (1 861) Cash outflow on acquisition The purchase price allocation was preliminary as of 31 December The allocation of goodwill is completed in TNOK is allocated to intangible assets. The guarantee amount of NOK 1.5 million was placed on escrow for 18 months and paid out to the former shareholders in The goodwill arising from the acquisition is mainly connected to the value of the employees. The goodwill is not deductible for tax purposes. Note 5 Segment Information The Group delivers a broad service offering within reservoir evaluation, well planning, well operations and integrated field management to the upstream oil and gas industry. For management purposes, the Group is organised into business units based on regions and has from 2013 six reportable segments, as follows: Norway including Russia United Kingdom (UK) including Middle East (ME) and West Africa Asia Pacific Americas Software Holdings Segment information for 2012 has been amended according to new segment structure. No operating segments have been aggregated to form the above reportable operating segments. Management monitors the operating results of its business units separately for the purpose of making decisions about resource allocation and performance assessment. Segment performance is evaluated based on operating profit or loss and is measured consistently with operating profit or loss in the consolidated financial statements. However, Group financing and income taxes are managed on a Group basis. Holdings segment consist of corporate administration and AGR E&P which is AGR's Operator engagement in Israel. Transfer prices between operating segments are on an arm's length basis in a manner similar to transactions with third parties. ANNUAL REPORT

38 In NOK 1000 Key figures 2013 Assets ( ) Liabilities ( ) Investments Investments ex. acquisition Business areas Norway UK incl Asia Pasific Americas Software Holdings Elimin. Total incl. Russia ME and West Africa Profit and Loss Account 2012 External operating revenues Intercompany operating revenues (70 662) - Project expenses/ payroll expenses ( ) ( ) ( ) ( ) (2 884) (24 443) ( ) EBITDA (15 515) Depreciation and (3 181) (7 603) (670) (5 882) (338) (2 406) - (20 081) amortisation Operating profit (17 921) (loss) Net financial items (52 124) (18 445) (1 335) (6 853) (131) (27 768) Tax (4 620) (8 979) (767) (4 612) (818) (8 724) - (28 519) Key figures 2012 Assets ( ) Liabilities ( ) Investments Investments ex. acquisition EBITDA is short for Earnings Before Interest, Tax, Depreciation and Amortization, excluding stock write downs and is a non-gaap measure which management uses to measure operations. Segment assets consist primarily of property, plant and equipment, intangible assets, inventories, trade and other receivables, and cash and cash equivalents. Segment liabilities comprise operating liabilities. Unallocated liabilities comprise items such as taxation and borrowings including related hedging derivatives. Investments comprises additions to property, plant and equipment and intangible assets, including additions resulting from acquisitions through business combinations. ANNUAL REPORT

39 Note 6 Geographical Segment Information Geographical segment reporting represents external customer sales based on the loaction of the customer. In NOK Total operating revenues Norway Europe ex. Norway Australia America Asia Africa Total Major customers Sales to Statoil ASA and its subsidiaries amounted in total to NOK 209 million in FY The revenue is mainly listed under the segment Norway above, but the amount also includes sales to Statoil in Europe, America and Africa. Non-current assets Norway Europe ex. Norway Australia America Asia Africa - - Total Note 7 Operating Revenues In NOK Operating revenue comprises: Sale of goods Sale of services Total revenue Profit from sale of fixed assets 5 18 Other sales Total other operating revenue Total operating revenue ANNUAL REPORT

40 Note 8 Intangible Assets 2013 Goodwill Acquired patents development projects Self-developed patents development project In NOK Historical cost Additions Acquisition of subsidiary (Note 4) Disposals - - (5 915) (5 915) Exchange adjustment (13 217) (8 907) (246) (22 370) Historical cost Additions Acquisition of subsidiary (Note 4) (7 561) - - (7 561) Disposals - - (8 154) (8 154) Exchange adjustment Historical cost Accumulated amortisation Amortisation of the year Impairments for the year Disposals during the year - - (5 315) (5 315) Exchange adjustment - (8 487) (201) (8 688) Accumulated amortisation and impairment Amortisation of the year Impairments for the year Disposals during the year Exchange adjustment Accumulated amortisation and impairments Net book value Net book value Net book value Amortisation rates years 5 years Amortisation method Linear Linear Self developed assets are started amortised when they are fully developed. The table below specifies goodwill per acquisition for the Group: Goodwill DPT Triangle RES Peak Acquired Acquired Acquired (5 241) Acquired over the year Disposal during the year Exchange differences (28 463) Acquisition cost Amortisation for the year Amortisation Accumulated impairments Total ANNUAL REPORT

41 Impairments for the year Accumulated impairments Book value Book value Goodwill FJ Brown Tracs Steinsvik Total Acquired Acquired Acquired Acquired Acquired (12 205) - (12 205) Acquired (1 076) - (1 076) Acquired Acquired over the year - - (7 561) (7 561) Disposal during the year Exchange differences (26 749) Acquisition cost Amortisation for the year Amortisation Accumulated impairments Impairments for the year Accumulated impairments Book value Book value Goodwill is allocated to the group s cash-generating units (CGUs) identified according to the business segment. A summary of the goodwill allocation is presented below. Goodwill per segment Norway incl. Russia UK, ME and West Africa United States Goodwill as of Goodwill as of Goodwill as of Goodwill as of Goodwill as of Goodwill as of Goodwill as of The key assumptions used for the value-in-use calculations are based on the presumption that management have the flexibility to re-allocate resources between segments. As a result the same assumptions are used for all segments/cgus and are as follows: Petroleum Services EBITDA-margin % % Growth rate % Discount rate % 1 Budgeted EBITDA-margin. The margin varies in the budget period. 2 Weighted average growth rate used to extrapolate cash flows beyond the budget period. 3 After-tax discount rate applied to the cash flow projections. Total ANNUAL REPORT

42 Note 9 Fixed Assets In NOK Machinery and operating equipment Total Historical cost Additions Acquisition of subsidiary (Note 4) Disposals (4 388) (4 388) Conversion variances (1 362) (1 362) Historical cost Additions Acquisition of subsidiary (Note 4) - - Disposals (3 741) (3 741) Conversion variances Historical cost Accumulated deprecation and impairment Amortisation for the year Impairments for the year - - Disposals during the year (4 370) (4 370) Exchange adjustment (1 109) (1 109) Accumulated depreciation and impairment Amortisation of the year Impairments for the year - - Disposals during the year (3 184) (3 184) Exchange adjustment Accumulated amortisation and impairment Net book value Net book value Net book value Depreciation rates 3-8 years Depreciation method Linear Note 10 Group Entities Company Head Office Owner Equity interest/ voting share 2013 Equity interest/ voting share 2012 AGR Australia Pty Ltd Perth - Australia AGR Group Holdings Ltd 100 % 100 % AGR Canada Inc Houston-USA AGR Group Americas Inc 100 % 100 % AGR Central Asia AS Oslo - Norway AGR Petroleum Services AS 100 % 100 % AGR Consultancy Services AS Stavanger - Norway AGR Petroleum Services AS 100 % 100 % AGR Consultancy Solutions Ltd Aberdeen - UK AGR Group Holdings Ltd 100 % 100 % AGR F.J Brown Inc Houston-USA AGR Group Americas Inc 100 % 100 % AGR Facilities Solutions AS Oslo - Norway AGR Petroleum Services AS 85 % 80 % AGR Group Americas Inc Houston-USA AGR Petroleum Services Holdings AS 100 % 100 % AGR Group Holdings Ltd Aberdeen - UK AGR Petroleum Services Holdings AS 100 % 100 % ANNUAL REPORT

43 AGR Group Mexico Inc Houston-USA AGR Group Americas Inc 100 % 100 % AGR Group Mexico S de R.L de C.V Houston-USA AGR Group Mexico Inc 100 % 100 % AGR Petroleum (ME) Ltd Dubai - United Arab AGR Group Holdings Ltd 100 % 100 % Emirates AGR Petroleum Services AS Oslo - Norway AGR Petroleum Services Holdings AS 100 % 100 % AGR Petroleum Services Inc Houston-USA AGR Group Americas Inc 100 % 100 % AGR Reservoir Evaluation Services Aberdeen - UK AGR Petroleum Services AS 100 % 100 % Kazakstan Ltd AGR Solution Systems Ltd Aberdeen - UK AGR Group Holdings Ltd 100 % 100 % AGR Steinsvik AS Stavanger - Norway AGR Petroleum Services Holdings AS 80 % 80 % AGR Well Management Ltd Aberdeen - UK AGR Group Holdings Ltd 100 % 100 % Altinex Inc Houston-USA AGR Petroleum Services Holdings AS 100 % 100 % Teredo AS Oslo - Norway AGR Petroleum Services AS 100 % 100 % Tracs Consult LLC Moscow - Russia Tracs International Consultancy Ltd 100 % 100 % Tracs International Consultancy Ltd Aberdeen - UK AGR Group Holdings Ltd 100 % 100 % Tracs International Training Ltd Aberdeen - UK Tracs International Consultancy Ltd 100 % 100 % Well Design Online AS Oslo - Norway AGR Petroleum Services Holdings AS 56 % - Investment in an Associate In NOK 1000 The Group has a 44% interest in AGR Energy AS, which is involved in activities in Israel and elsewhere, acting as an Operator with minority stakes in the oilfields. AGR Energy AS was a fully owned subsidiary until August 2013 when 56 % of the shares in the company was sold. After the sale AGR Petroleum Services Holdings AS lost control and AGR Energy AS has been deconsolidated. From the transaction date AGR Energy AS has been accounted for by using the equity method. AGR Energy AS is a private entity that is not listed on any public exchange. The following table illustrates the summarised financial information of the Group's investement in AGR Energy AS: Share of the associate's statement of financial position: Current assets Non current assets Current liabilities (756) - Non-current liabilities - - Equity Share of the associate's revenue and profit: Revenue Loss (4 333) - Carrying amount of the investment Note 11 Inventory In NOK Stocks Work in progress - - Finished goods - - Total inventories All amounts are net of any write-downs for obsolescence. ANNUAL REPORT

44 Note 12 Trade Receivables In NOK Trade debtors at nominal value Revenues not invoiced Provisions for bad debt (51 919) ( ) Trade receivables Of the total TNOK in provision for bad debt, TNOK is reclassification from accounts payable to Provision for bad debt regarding amounts collected for third-parties. See Note 30 Contingencies. Note 13 Aging Trade Debtors at Nominal Value In NOK Receivables not overdue Receivables overdue up to 3 months Receivables overdue more than 3 months Provision (51 919) ( ) Trade debtors Individually impaired Collectively impaired Total Provision (2 777) - (2 777) Charge for the year ( ) - ( ) Provision ( ) - ( ) Charge for the year Provision (51 919) - (51 921) Note 14 Other Receivables In NOK Other taxes receivables Advanced payments to suppliers Advanced payments employees Other prepaid expenses Other current assets Other current receivables ANNUAL REPORT

45 Note 15 Cash and Cash Equivalents In NOK Cash Bank deposits Cash and cash equivalents Of which is restricted deposits* Unused overdraft facilities * Deducted employee tax due within 3 months Note 16 Financial Instruments by Category The accounting policies for financial instruments have been applied to the items below: In NOK Loans and receivables Assets at fair value through the profit and loss Total Assets as per balance sheet Derivative financial instruments Trade and other receivables* Other financial assets at fair value Cash and cash equivalents Total *including Group receivables towards AGR Group ASA Liabilities at fair value through the profit and loss Derivatives used for hedging Other financial liabilities Liabilities as per balance sheet Borrowings Derivative financial instruments Total Total Loans and receivables Assets at fair value through the profit and loss Total Assets as per balance sheet Derivative financial instruments Trade and other receivables* Other financial assets at fair value Cash and cash equivalents Total ANNUAL REPORT

46 *including Group receivables towards AGR Group ASA and AGR Drilling Services Liabilities at fair Derivatives used value through the for hedging profit and loss Other financial liabilities Liabilities as per balance sheet Borrowings - DNB/Nordea Derivative financial instruments (3 617) - - (3 617) Total (3 617) For all financial instruments included in the tables above fair value corresponds to book value. Note 17 Share Capital and Shareholder Information At 31 December 2013 and at 31 December 2012 the company had a share capital of NOK distributed in shares, each with a nominal value of NOK 2. The company has one share class, and all shares have equal voting and dividend rights. Total In NOK Shareholders at 31 December 2013 Equity interest Number of shares Nominal value Share capital AGR Group ASA 92.6% Petco Invest AS 3.1% Petco Invest II AS 4.3% Total 100% Note 18 Pensions and Pension Commitments The Group companies provide various retirement plans in accordance with the local regulations and practice in the countries in which they operate. Contribution plans Defined contribution plans require the companies to make agreed contributions to a separate fund when employees have rendered services entitling them to contributions. The companies have no legal or constructive obligations to pay further contributions. Some companies make a contribution to multi-employer pension plans included in a joint arrangement with others. All multi-employer plans are accounted for as defined contribution plans. The premium related to the contribution plans are expensed when occurred as operating expenses. In 2013 the total expense for defined contribution schemes was NOK 8.9 million and in 2012 NOK 7.3 million. Defined benefit plans Defined benefit plans are generally based on years of services and final salary levels, offering retirement benefits in addition to what is provides by state pension plans. The Group's defined benefit plan is invested with an insurance company which manages the plan assets. The special pension schemes financed through company operations covers 4 employees. In NOK Specification of the year s pension cost Costs according to defined benefit schemes: Current service cost Interest cost Expected return on plan assets (600) (725) Net actuarial losses (688) 23 Administrative expenses ANNUAL REPORT

47 Pension cost excl. social security tax (56) Employers' social security tax Pension cost incl.social security tax Balance sheet specification of net pension commitments Guaranteed schemes: Accumulated benefit obligation Estimated effect of future wage adjustment Gross pension commitments Pension funds as of (16 620) (14 425) Net pension commitments Social security tax Estimate devations not recognised in the proft and loss accounts Net pension commitment on the balance sheet The movement in the defined benefit obligation over the year is as follows: Beginning of year Net pension cost Estimated deviations recognised as Other Comprehensive Income (6 238) - Estimated payment to pension funds including administration costs (88) (1 710) Net pension commitment on the balance sheet Actuarial assumptions for the group Expected return on funds 4.00 % 3.60 % Discount rate 4.00 % 2.30 % Annual salary increase 3.75 % 3.50 % Annual adjustment of the national insurance base amounts 3.50 % 3.25 % Annual adjustment of current pension payments 0.60 % 0.20 % Turnover 2-5 % 2-5 % Expected average remaining servicetime 8 12 Demographic tariff K2013 K2005 Note 19 Tax Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when the deferred income taxes relate to the same fiscal authority. In NOK Current income tax expense Norway Current income tax expense abroad Adjustment of current income tax of prior years 459 (4 118) Changes in deferred tax Norway Change in deferred tax abroad (924) 889 Impact of change in the tax rate 4 - Income tax expense Reconciliation of tax payable Tax payable in profit and loss account adjusted for Group contribution Prepaid tax (5 029) Credit deduction, international (7 399) (15 463) Tax, international (4 604) Opening balance, tax from 2012 not paid in ANNUAL REPORT

48 Corrections previous years (6 133) (63) Tax payable/(receivable) in balance sheet (4 714) Reconciliation of nominal and effective tax rate Pre-tax result Applicable tax with tax rate 28 % Variance, actual and expected income tax expense Explanation of why actual tax cost deviates from expected tax cost Tax effect from non-deductible costs Tax effect from non-taxable income (5 815) (2 879) Tax losses for which no deferred income tax asset was recognised (988) Re-measurement of deferred tax - change in the tax rate (15) - International tax rate deviates from Norwegian tax rate Charge of deferred tax asset Adjustment of current income tax of prior years (4 118) Variance compared to applicable tax rate Change in book value of deferred tax Balance sheet value at (56 710) (68 498) Currency conversion (1 558) Charged to income in the period Corrections previous years (548) 83 Acquisition of Subsidiary Balance sheet value (27 916) (56 710) Deferred tax assets as of Deferred tax liability as of Balance sheet value (27 916) (56 710) Deferred income tax assets are recognised for tax loss carry-forwards to the extent that the realisation of the related tax benefit through future taxable profits is probable. The tax losses are connected to previous years tax losses. The Group has during the last 3-5 years delivered taxable profits, and based on future expected tax profit deferred tax asset is substantiated. Management believe that there is convincing evidence for future uses. Tax losses in Norway can be offset against future taxable profit, and there is no limit for usage. Deferred tax assets will be booked when there is convincing evidence for future taxable profit. Of the total loss carried forward, TNOK (2012 TNOK ) TNOK 403 (2012 TNOK ) relates to Norway. Deferred tax Below is a specification of temporary differences between accounting and tax values, as well as calculation of deferred tax / tax advantage at the end of the financial year. ANNUAL REPORT

49 Basis for deferred tax Receivables (2 158) 52 Other current balance sheet items (55 319) (65 065) Amount linked to current balance sheet items (57 477) (65 013) Fixed assets and intangible assets (4 775) Long term receivables (360) (2 070) Pensions (1 861) (8 132) Profit and loss account Loss carried forward (27 892) ( ) Amount linked to long-term balance sheet items (24 100) ( ) Total basis for deferred tax assets (81 577) ( ) Note 20 Debt to Credit Institutions Refinancing of AGR Petroleum Services In Q the Group was refinanced by placing a NOK 550 million 5 year bond in the market. The bond agreement was signed in February 2013 and was listed on Oslo Stock Exchange in June In addition, DNB provided a NOK 100 million Revolving Credit Facility which purpose is to finance working capital requirements and to issue financial guarantees. The parent company AGR Group ASA provided a shareholder loan to AGR Petroleum Services Holdings AS which is a PIK loan subordinated to the bond and the RCF, and pledged in favor of the lenders. In NOK Overview of long-term interest bearing debt Long-term interest bearing debt Capitalised arrangement fee deducted (25 358) - Total long-term external interest bearing debt Shareholder loan from AGR Group ASA Total long-term interest bearing debt The Group has a Revolving Credit Facility (the "RCF") of TNOK and an overdraft facility of TNOK At 31 December 2013 no cash drawings were made under the facilities, however bank guarantees of TNOK was drawn under the RCF. Accordingly the Group had total unused credit facilities of TNOK Interest bearing debt is recorded at amortised cost, and the table below specifies the actual repayment schedule. At year end 2013 all interest bearing debt was denominated in NOK. Guaranteed liabilities Long-term and Short-term interest bearing debt Total guaranteed liabilities Average interest rate NOK loans (including shareholder loans) 8.50 % 4.9 % Debt amortisation profile Thereafter Total Revolving and overdraft credit facilities Interest bearing debt (excluding capitalised arrangement fee) Total Financial Covenants The bond Agreement entered into with Norsk Tillitsmann (on behalf of the bondholders) and the Revolving Credit Facility Agreement entered into with DNB Bank ASA includes the following financial covenants as per 31 December 2013: ANNUAL REPORT

50 (a) Net Interest Bearing Debt (NIBD) to EBITDA ("Gearing ratio") The Borrower shall ensure that the Group maintains a maximum Gearing Ratio as follows: Relevant Period ending: Gearing Ratio: 31 March June September December March June September December March June 2015 (and each Relevant Period thereafter) 3.50 In addition, the Borrower shall ensure that the Group maintains an Interest Cover ratio (EBITDA to Net Interest Expense) above 2.0. According to the bond and the RCF agreements, there are other conditions related to dividends, disposals of assets, substantial change in the nature of business, mergers and further encumbrances. The Group's long-term debt is secured by pledge in certain assets. AGR Petroleum Services Holdings AS has issued a negative pledge which includes the majority of its subsidiaries. Subsidiaries that are defined as obligors under AGR's loan agreement are jointly and severally liable for the Group's debt. Note 21 Other Current Liabilities In NOK Holiday pay and wages due Advances from customers Incurred interest cost Other creditors Accrued costs Market value of financial instruments Other current liabilities Current liabilities Note 22 Earnings per Share Basic earnings per share is calculated by dividing the profit attributable to equity holders of the company by the weighted average number of ordinary shares in issue during the year. There are no dilution effects as the company has no convertible bond or stock option plan. In NOK Basis for calculation of earnings per share Net result allocated to shareholders from continuing operations Weighted average number of outstanding shares Earnings per share from continuing operations (NOK) ANNUAL REPORT

51 Note 23 Wages, Fees, Number of Employees etc. In NOK Wages Employers' social security contributions Pension costs Other remunerations Capitalised wages (305) (2 151) Total Average number of man-labour years Salaries and other remuneration to the CEO is paid by AGR Group ASA and recharged to AGR Petroleum Services Holdings AS. There are no fees paid to the Board members of AGR Petroleum Services Holdings AS. Pension costs are described in detail in Note 18 Pensions and Pension Commitments. Auditor's fee The Board has reviewed the level and distribution of fees paid to EY and considers them to be appropriate. Specification of auditor's fee excl. VAT Fees for audit of annual accounts Fees for other attestation services - Fees for tax-related services Fees for other services* Total * Fees for other services includes due diligence service and various technical assistance. Note 24 Provisions AGR Petroleum Services Holdings AS acquired 80% of the share capital of Steinsvik&Co AS in May 2012 for a cash consideration of TNOK The guarantee amount was TNOK and was released in November In NOK Balance Other provisions Guarantee amount Total provisions ANNUAL REPORT

52 Note 25 Leasing Costs The Group has entered into the following operating lease agreements for tangible assets not recognised in the balance sheet, but expensed as incurred: In NOK Land, buildings and permanent property Apartments Machinery and operating equipment Total The Group has entered into lease agreements for premises, among others in Oslo, Trondheim and Stavanger in Norway, Houston in USA, Aberdeen in UK, Perth in Australia, Moscow in Russia and Abu Dhabi in United Arab Emirates. The Group has not entered into non-cancellable operating leases. Note 26 Financial Income and Expences In NOK Interest income Currency gain Unrealised gain/(loss) of financial instruments calculated at fair value* Financial income Interest expense Currency loss Other financial expense Financial expense ( ) Share of loss of an associate (4 333) - Net financial items (29 783) (27 768) *The Group held no Foreign Exchange derivates at year end Gain on interest rate swap was NOK thousand in Note 27 Financial Market Risk The Group has financial instruments linked to ordinary activities such as trade debtors, trade creditors and similar. Shortterm and medium-term interest rate risk arises from floating interest rates on parts of the company's debt. The Group held both interest rate collar swaps and interest rate swaps until Q2 2013, but had no interest rate derivatives at year end The Group s credit risk exposure is considered to be low. The majority of the Group's debtors are publicly listed Norwegian and international oil companies. The Group seeks to obtain financial guarantees from debtors where the credit risk and exposure is considered to be high. In addition, majority of the Group s receivables are credit insured in order to reduce credit risk. A proportion of the Group's turnover is in foreign currencies, primarily USD and GBP. As a result of international operations, the Group is exposed to fluctuations in currency exchange rates. The Group held no FX derivatives at year end 2013, however new FX derivatives contracts were entered into in January The Group is not directly exposed to fluctuations in commodity prices. Below is an outline of the Group's turnover, trade debtors and -creditors converted into NOK at balance sheet date: ANNUAL REPORT

53 Currency Currency (1 000) In NOK In NOK Share % Currency in In NOK Share % Total operating revenue: AUD % % EUR % % GBP % % NOK % % USD % % Other* % % Total % % Trade receivables: AUD % % CAD % % EUR (628) (5 247) (1 %) (963) (7 068) (2 %) GBP (1 073) (10 787) (3 %) % NOK % % USD % % Other* % % Total % % Trade payables: AUD % % EUR % % GBP % % NOK % % USD % % Other* % % Total % % Note 28 Related Party Receivables and Payables In NOK Related party receivables AGR Drilling Services Canada Inc - 57 AGR Subsea Inc AGR Deepwater Technology Inc - - AGR Cannseal AS - 70 AGR Group ASA AGR Drilling Services Holdings AGR Subsea AS - - AGR Subsea Ltd AGR DS do Brasil Ltda - - AGR Drilling Services Pty Ltd PS Abu Dhabi (Branch AGR Group) Cashpool Group Total related party receivables ANNUAL REPORT

54 Related party payables, short term AGR Drilling Services Canada Inc - 71 AGR Subsea Inc AGR Group ASA AGR Drilling Services Holdings - - AGR Subsea AS - 13 AGR Subsea Ltd - 1 PS Abu Dhabi (Branch AGR Group) Cashpool Group Total related party payables Related party loans AGR Deepwater Technology Inc AGR Group ASA Total related party loans Note 29 Related Parties In NOK Other related parties Other income Altor Equity Partners AS (rental of premises) Total Key management personnel Purchase of goods / other operating costs PIR AS Total Key management personnel Trade payables PIR AS Total Note 30 Contingencies During 2013 the Group was in a legal dispute with Hyperdynamics. In accordance with IAS the Group does not provide further information on this dispute in order not to impair the outcome of the proceeding. An invoice and demand for settlement for approximately $5.8 million has been presented to the Group by Awilco Drilling plc ( Awilco), a drilling contractor, in respect of services it claims were performed during January 2012 on a contract between the parties., The services were allegedly performed for a customer of the Group, Antrim Energy Inc ( Antrim ). This liability has not yet been accepted pending the outcome of a dispute between the Group and Antrim. The directors, based on legal advice, understand that the Group has an agreement with Antrim, which, in their opinion, provides the Group with an enforceable indemnification against any costs arising in connection with the claim from Awilco, however Antrim are presently disputing this. A claim for approximately $47.3 million has been made against the Group by SCS Corporation in respect of cost over-runs incurred against the pre-estimate of costs for the Sabu-1 well which was completed in A defence and counterclaim for $22.2 million has been made by the Group against SCS Corporation in respect of amounts outstanding under the contract. The directors are of the opinion that the claim by SCS Corporation can be successfully resisted by the Group. ANNUAL REPORT

55 An invoice and demand for settlement for approximately $10.25 million has been made against the Group by Jasper Drilling Private Limited, a service provider, in respect of services it claims were provided under a contract between the parties for the ultimate benefit of a customer of the Group, SCS Corporation. This liability has not been accepted pending the outcome of the dispute between the Group and SCS Corporation, as well as management s concerns about the validity of various line items being claimed. Note 31 Financial Assets at Fair Value In NOK Specification of market-based shares: Acquisition cost shares in Get Energy Inc Conversion to market price at (8) Market value Short-term financial investments as at 31 December 2013 and 2012 are accounted for at fair value with unrealised gains and losses included in the income statement. Note 32 Goods and Consumables used Expenses classified as goods and consumables used are directly related to projects, such as project equipment, travelling expenses, loading etc. Note 33 Events after the Balance Sheet Date AGR evaluating strategic options Following the demerger of AGR Drilling Services (renamed to AGR Enhanced Drilling after the demerger), the Board of the listed parent compay AGR Group ASA has initiated a strategy review for AGR Petroleum Services. Alpha Corporate Finance has been appointed as advisor and will assist in an evaluation of all strategic avenues open to the company. Restructuring of AGR Petroleum Services Holdings AS In order to strengthen its focus on both the Exploration and Production ("E&P") and Petroleum Services businesses and create a more flexible structure for the benefit of all stakeholders in the Group, the Group decided to carry out a de-merger of AGR Petroleum Services Holdings AS ("AGPS") whereby all the assets of AGPS, save for the E&P Business, will be transferred to a new holding company with the same ownership structure as AGPS.The business operations of the AGR Group will be carried out as currently conducted, with AGR Holdings AS as the new holding company for the AGR Group companies involved in the Petroleum Services Business and AGPS as the holding company for AGR Group's interests in the E&P Business. Note 34 Share Investment Program Share investment program In 2011 AGR introduced co-investment program in AGR Petroleum Services. In May 2011 AGR Group ASA sold A-shares in its subsidiary PetCo Invest AS to key employees and board members in AGR Group ASA and AGR Petroleum Services Holdings for NOK 102 per share. PetCo Invest AS owns shares in AGR Petroleum Services Holdings AS, corresponding to 2.1%. AGR Group ASA is the owner of the remaining 97.9 %. In April 2012 Petco Invest AS increased its ownership in AGR Petroleum Services Holdings with shares and owns shares, corresponding to 3.1 % per December AGR Group ASA was the owner of the remaining 96.9 %. In May 2013 the co-investment program in AGR Petroleum Services was expanded further through the establishment of PetCo Invest II AS. AGR Group ASA owned at this time A-shares in PetCo Invest II AS. During 2013, A- shares were sold to key employees and the chairman of AGR Group ASA for NOK 102 per share. Petco Invest II AS owns shares in AGR Petroleum Services Holdings AS, corresponding to 4.3 % at the end of AGR Group ASA (92.6 %) and PetCo Invest AS (3.1 %) own the remaining % per December ANNUAL REPORT

56 AGR Group ASA's shareholding in Petco Invest AS and PetCo Invest II AS following the transaction was one controlling B- share respectively. Petco Invest AS and PetCo Invest II AS have been incorporated for the purpose of investing in AGR Petroleum Services Holdings AS. The price per share in PetCo Invest AS and PetCo Invest II AS was determined based on the estimated fair value of AGR Petroleum Services Holdings AS, using over-the-cycle EV/EBITDA trading multiples in accordance with EVCA guidelines. Accordingly, the transactions have not affected the profit and loss accounts of AGR. In order to increase the investments made by PetCo Invest AS and PetCo Invest II AS, AGR Group ASA has provided loans in the form of seller s credits with an annual interest rate of 8 %. AGR Group ASA has an option to increase its shareholding in PetCo Invest AS and PetCo Invest II AS by cash payment or set-off against any outstanding amount under the loan agreements. The co-investment programs within AGR Petroleum Services are governed by the provisions in a shareholders agreement. The shareholders agreement is entered into by and between the holding company, the investment company and the participants in the program. Among other things the shareholder agreement will provide for drag-along and tag-along provisions for the event that AGR Group ASA should sell its shares in the holding company. The participants cannot sell or transfer the shares in PetCo Invest AS and PetCo Invest II AS without the consent of AGR. If a participant in the program gives or is given notice of termination of employment before the second anniversary of the program, AGR has an option to buy the shares at fair value. ANNUAL REPORT

57

58 Income Statement AGR Petroleum Services Holdings AS In NOK Note Revenue 2,3 (230) - Other operational revenue 2, Total operating income (207) - Goods and consumables used Payroll expenses Depreciation, amortisation and impairments Other operating expenses 15, Total operating expenses Net operating income (30 674) (12 966) Financial income Financial expenses Net financial items Net profit before tax Income tax expense Profit for the year Attributable to Retained earnings Total appropriation ANNUAL REPORT

59 Balance Sheet as of AGR Petroleum Services Holdings AS In NOK As at 31 December Note Assets Concessions, patents and licences etc Deferred tax assets Intangible assets Machinery and operating equipment Tangible fixed assets Investment in subsidiaries Loan to group companies Investment in associated companies Investments in shares and units Financial fixed assets Total non current assets Trade receivables Group receivables Other receivables Receivables Cash pool Bank deposits, cash in hand Total Bank deposits, cash in hand, etc Total current assets Total assets ANNUAL REPORT

60 Balance Sheet as of AGR Petroleum Services Holdings AS In NOK Note Equity and liabilities Share capital 10, Other paid-in capital Total paid-in equity Retained earnings Other equity Total retained earnings Total equity Deferred tax Provisions Total provision for liabilities Debt to group companies Bond loan Total non-current liabilities Debt to credit institutions Trade payables Public duties payable 36 - Debt to group companies Other current liabilities Total current liabilities Total liabilities Total equity and liabilities Oslo, 30 April 2014 ANNUAL REPORT

61 Cash Flow Statement AGR Petroleum Services Holdings AS In NOK Cash flow from operating activities Profit/(loss) before taxes Adjustment for Group contribution ( ) (49 915) Depreciation of tangible assets Amortisation of intangible assets Loss on sale of subsidiary Change in trade receivables (21 620) - Change in trade payables ( ) Changes in other current assets and liabilities (working capital) Net cash flow from operating activities ( ) Cash flow from investments activities Purchase of property, plant & equipment (1 033) (200) Purchase of intangible fixed assets (158) (1 917) Investments in shares and units (2 700) (29 904) Net changes in long-term receivables/debt to group companies ( ) Net cash flow from investment activities ( ) Cash flow from financing activities Proceeds from borrowings Repayment of borrowings ( ) ( ) Net increase/decrease in cash and cash equivalents Arrangement fees bond (29 399) - Group contributions received Net cash flow from financing activities Net foreign exchange differences - - Net change in cash and equivalents ( ) Cash and equivalents at 1 January Cash and equivalents at 31 December ANNUAL REPORT

62 nurture it and look after it.

63 Notes Note 1 Accounting Principles AGR Petroleum Services Holdings AS ("the Company") and its subsidiaries are a leading supplier of services and technology to the oil and gas offshore industry. The Company offers administrative services to its subsidiaries in the Group. It also holds interests in certain oil and gas exploration and production licences in Israel, which is the E&P business of the company. The Company and its subsidiaries are part of the listed company AGR Group ASA. The Group's head office is located in Oslo and its registered office is Karenslyst allè 4, 0278 Oslo. The Group consolidated financial statements are available at The company will be demerged in 2014, whereby most assets will be transferred to a new Holding company. The E&P business will remain in the company. The financial statements have been prepared in accordance with the Norwegian Accounting Act and generally accepted accounting principles in Norway. The management has applied estimates and assumptions which have affected assets, liabilities, income and expenses, as well as the disclosures regarding potential obligations. The financial year follows the calendar year. Income statement items are classified by nature. Changes in accounting policies Changes in accounting principles and disclosures are recognised directly in equity. Basis of comparison is changed correspondingly. Subsidiaries Subsidiaries and investments in associates are valued at cost in the company accounts. The investment is valued as cost, less any impairment losses. An impairment loss is recognised if the impairment is not considered temporary, in accordance with generally accepted accounting principles. Impairment losses are reversed if the reason for the impairment loss disappears in a later period. Dividends, group contributions and other distributions from subsidiaries are recognised in the same year as they are recognised in the financial statement of the provider. If dividends/group contribution exceed withheld profits after the acquisition date, the excess amount represents repayment of invested capital, and the distribution will be deducted from the recorded value of the acquisition in the balance sheet for the parent company. Balance sheet classification Assets intended for permanent ownership or long-term use are classified as non-current assets. Assets which are a part of the company's service cycle and are expected to be realised or used during the course of the company's normal production period are classified as current assets. Receivables are classified as current if they are expected to be realised within 12 months of the balance sheet date. Liabilities which fall due more than a year after the balance sheet date are classified as non-current. All other liabilities are classified as current. Liabilities which are part of the service cycle, however, are always classified as current. Current assets are recognised at the lower of cost and fair value. Current liabilities are carried at nominal value at the time they are incurred. Non-current assets are valued at cost. Tangible fixed assets which deteriorate in value over time are depreciated applying a straight line method over their expected economic lifetime. Tangible fixed assets are impaired to actual value if the drop in value is not expected to be temporary. Property, plant and equipment Property, plant and equipment, are valued at cost less accumulated depreciation and write-downs. The cost of property, plant and equipment comprises the purchase price, including direct acquisition costs linked to bringing the asset to the proper location and making it fit for use. Depreciation is calculated applying the straight-line method over the asset's expected economic life. Major additions and improvements are capitalised and depreciated along with the asset. Additions include expenses that have a positive effect on the asset's remaining cash flows in comparison to what was originally assumed at the time of acquisition. Other expenses are classified as maintenance and expensed as they incur. Gains on disposals of fixed assets are classified as other operating income and losses are classified as other operating expenses. Write-down of fixed assets and intangible assets is assessed when there are indications of impairment. A calculation is then made of discounted future cash flows for assets that will remain in use by the company and estimated sales price less sales costs for assets for sale. If the calculation shows a lower value than the carrying amount, the asset is written down to fair value or to sales price less sales cost for assets which are for sale. ANNUAL REPORT

64 Revenue recognition The company's activity is mainly related to the supply of services to subsidiaries in the Group. Revenues from sales of services are recognised in the income statement according to the level of completion. The Company recognises revenue when it is probable that the transaction will generate future economic benefits that will accrue to the company and the value of such benefits can be estimated reliably. Revenue is shown net of value-added tax, returns, rebates and discounts. Matching principle Revenues are matched with expenses in accordance with the matching principle. Unrealised losses which are considered both likely to incur and quantifiable, as well as unconditional obligations and orders, are expensed in accordance with generally accepted accounting principles. Foreign exchange Monetary items in foreign currency are translated to NOK using the exchange rates at the balance sheet date. Foreign exchange gains/losses are presented as finance income/ expenses in the income statement. Provisions, contingent liabilities and conditional assets Contingent liabilities are recognised in the financial statements if there is more than a 50 % probability that the liability will be settled. Best estimate is applied when calculating the settlement value. Provisions for contingent liabilities arising from the movement of goods or which are expected to be settled within a year from the balance sheet date are classified as short-term liabilities. Other provisions are classified as provision for liabilities under long-term debt. Pensions The Company's pension obligations to its employees consist of making a specified contribution to each employee's pension fund (defined contribution plan). The pension cost consists of the period's contribution including employers' social security tax. The Company has no further payment commitment after the contributions have been paid. Extraordinary income and expenses Income is classified as extraordinary if it is unusual, irregular and material considered in relation to the company's business. Accounts receivables and other receivables Accounts receivable and other current receivables are recorded in the balance sheet at nominal value less confirmed losses and provisions for doubtful accounts. Provisions for doubtful accounts are based on specific assessments of individual accounts, as well as an assessment of the group of accounts as a whole. Cash and cash equivalents Cash and cash equivalents consist of cash and bank deposits. The Company is a participant in the Group`s cash pool system, and all of the bank accounts which are part of the system are presented as intercompany receivables/debt in the balance sheet. Use of estimates When there is uncertainty regarding the measurement of an item in the accounts, the best estimate is applied. Changes in estimates are accounted for in the period that the change is made. Estimates are subject to uncertainty and may deviate from the final outcome. Cash flow statement The cash flow statement presents the accumulated cash flow for operational, investment and financial activities. The statement outlines each activity's effect on cash and cash equivalents. The cash flow statement has been prepared using the indirect method. Income Tax The tax expense in the financial statements consists of tax payable and changes in deferred tax. Deferred tax/tax asset is calculated using the relevant tax rate (28% for 2012 and 27% for 2013) and on all temporary differences that exist between the tax bases of assets and liabilities and their carrying amounts in the financial statements, as well as any tax losses carried forward at year-end. Tax increasing and tax reducing temporary differences that are reversed, or can be reversed in the same period are recorded net. Deferred tax assets are recorded in the balance sheet when it is more likely than not that the tax assets will be utilized. Borrowings Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowing are subsequently stated at amortised cost, any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the income statement over the period og the borrowings using the effective interest method. Fee paid on the establishment of loan facilities are recognised as transaction costs of the loan to the extent that it is probable that some or all of the facility will be drawn down. In this care, the fee is deferred until the drawn down occurs. To the extent there is no evidence that it is probable that some or all of the facility will be drawn down, the fee is capitalised as a pre-payment for liquidity services and amortised over the period of the facility to which it relates. Borrowings are classified as current liabilities unless the Company has an unconditional right to defer settlement of the liability for at least 12 months after the balance sheet date. ANNUAL REPORT

65 Note 2 Geographical Segment Information In NOK Norway 23 - Israel (230) - Total (207) - The negative revenue is due to a credit issued in December related to revenue in prior periods. Note 3 Operating Revenues In NOK Sale of services (230) - Total revenue (230) - Other sales 23 - Total other operating revenue 23 - Total operating revenue (207) - Note 4 Fixed Assets In NOK Concessions, patents and licences etc. Machinery and operating equipment Total Historical cost Additions Disposals Historical cost Accumulated amortisation and impairment Depreciation of the year Impairments for the year Accumulated depreciation Book value Depreciation rates 3 years Depreciation method Manual Linear 2012 Concessions, patents and licences etc. Machinery and operating equipment Total Historical cost Additions Disposals Historical cost Accumulated deprecation Deprecation of the year ANNUAL REPORT

66 Impairments for the year Accumulated depreciations Book value Depreciation rates 3 years Depreciation method Manual Linear Note 5 Other Current Receivables In NOK Other tax receivables Other prepaid expenses Other current assets Other current assets Note 6 Investments in Shares and Units In NOK Historical cost Offshore Technology Center Historical cost Well Design Online (Subsidiary company at 31 December 2013) Total investments Note 7 Investment in Group Entities and an Associate Subsidiary companies 31 December 2013 In NOK Company Head Office Owner Equity interest/ voting share 2013 Equity interest/ voting share 2012 AGR Australia Pty Ltd Perth - Australia AGR Group Holdings Ltd 100 % 100 % AGR Canada Inc Houston-USA AGR Group Americas Inc 100 % 100 % AGR Central Asia AS Oslo - Norway AGR Petroleum Services AS 100 % 100 % AGR Consultancy Services AS Stavanger - Norway AGR Petroleum Services AS 100 % 100 % AGR Consultancy Solutions Ltd Aberdeen - UK AGR Group Holdings Ltd 100 % 100 % AGR Energy AS Oslo - Norway AGR Petroleum Services Holdings AS % AGR F.J Brown Inc Houston-USA AGR Group Americas Inc 100 % 100 % AGR Facilities Solutions AS Oslo - Norway AGR Petroleum Services AS 85 % 80 % AGR Group Americas Inc Houston-USA AGR Petroleum Services Holdings AS 100 % 100 % AGR Group Holdings Ltd Aberdeen - UK AGR Petroleum Services Holdings AS 100 % 100 % AGR Group Mexico Inc Houston-USA AGR Group Americas Inc 100 % 100 % AGR Group Mexico S de R.L de C.V Houston-USA AGR Group Mexico Inc 100 % 100 % AGR Peak Solution Systems Pty Ltd Perth - Australia AGR Group Holdings Ltd % AGR Petroleum (ME) Ltd Dubai - United Arab AGR Group Holdings Ltd 100 % 100 % Emirates AGR Petroleum Services AS Oslo - Norway AGR Petroleum Services Holdings AS 100 % 100 % AGR Petroleum Services Inc Houston-USA AGR Group Americas Inc 100 % 100 % AGR Reservoir Evaluation Services Kazakstan Ltd Aberdeen - UK AGR Petroleum Services AS 100 % 100 % ANNUAL REPORT

67 AGR Solution Systems Ltd Aberdeen - UK AGR Group Holdings Ltd 100 % 100 % AGR Steinsvik AS Stavanger - Norway AGR Petroleum Services Holdings AS 80 % 80 % Altinex Inc Houston-USA AGR Petroleum Services Holdings AS 100 % 100 % Teredo AS Oslo - Norway AGR Petroleum Services AS 100 % 100 % Tracs Consult LLC Moscow - Russia Tracs International Consultancy Ltd 100 % 100 % Tracs International Consultancy Ltd Aberdeen - UK AGR Group Holdings Ltd 100 % 100 % Tracs International Training Ltd Aberdeen - UK Tracs International Consultancy Ltd 100 % 100 % Well Design Online AS Oslo - Norway AGR Petroleum Services Holdings AS 56 % - Subsidiary companies owned by AGR Petroleum Services Holdings 2013 Head office Voting share Total share capital Equity (100 %) Net profit 2013 (100 %) Book value AGR Petroleum Services AS Oslo - Norway 100 % Well Design Online AS* Oslo - Norway 57 % (175) AGR Steinsvik AS Stavanger - Norway 80 % AGR Group (Holdings) Ltd Aberdeen - UK 100 % 10 (3 469) (21 463) AGR Group Americas Inc Houston - USA 100 % (2 256) Altinex Inc Houston - USA 100 % Investment in subsidiaries per * The acquisition of Well Design Online AS found place in Net profit represented above is 100% of net profit in October-December 2013 Subsidiary companies owned by AGR Petroleum Services Holdings 2012 Head office Voting share Total share capital Equity (100 %) Net profit 2012 (100 %) Book value AGR Petroleum Services AS Oslo - Norway 100 % AGR Energy AS Oslo - Norway 100 % 100 (916) (4 355) 120 AGR Steinsvik AS* Stavanger - Norway 80 % AGR Group (Holdings) Ltd Aberdeen - UK 100 % (19 951) AGR Group Americas Inc Houston - USA 100 % (3 052) (3 840) Altinex Inc Houston - USA 100 % Investment in subsidiaries per * The acquisition of AGR Steinsvik AS found place in Net profit represented above is 100% of net profit in June- December 2012 Investment in an Associate In NOK AGR Energy AS is involved in activities in Israel and elsewhere, acting as an Operator with minority stakes in the oilfields. AGR Energy AS was a fully owned subsidiary until August 2013 when 56 % of the shares in the company was sold. Head office Voting share Shares Total share capital Equity (100 %) Net profit 2013 (100 %) Book value AGR Energy AS Oslo 44 % (13 942) Investment in associated (13 942) companies per ANNUAL REPORT

68 Note 8 Group Receivables and Liabilities In NOK Current receivables: AGR Petroleum Services AS AGR Consultancy Services AS AGR Steinsvik AS AGR Energy AS AGR Group (Holdings) Ltd AGR F.J Brown Inc 4 4 AGR Australia Pty Ltd - 3 AGR CannSeal AS AGR Petroleum (ME) Ltd AGR Group ASA - Abu Dhabi 3 13 AGR Well Management Ltd AGR Drilling Services Holdings AS TRACS International Consultancy Ltd 3 27 AGR Consultancy Solutions Ltd AGR Marine Engineering AS AGR Cleanup AS AGR Well Services AS Ocean Riser Systems AS Total current receivables Long term receivables: AGR Group (Holdings) Ltd AGR Group Americas Inc AGR Petroleum (ME) Ltd Total long term receivables Long term receivables: Interest is calculated using 6 months LIBOR + a margin of 6.75% Current liabilities: AGR Group ASA AGR Subsea AS AGR Steinsvik AS AGR Petroleum Services AS AGR Group (Holdings) Ltd 12 - AGR Well Management Ltd AGR Group Americas Inc AGR Consultancy Services AS AGR Drilling Services Pty Ltd AGR F.J. Brown Inc AGR Australia Pty Ltd AGR Petroleum (ME) Ltd AGR Solutions Systems Ltd AGR Central Asia AS AGR Petroleum Services Inc AGR Subsea Ltd AGR Subsea Inc AGR Seabed Intervention Ltd AGR Set Ltd Teredo AS ANNUAL REPORT

69 AGR Energy AS AGR Facilities Solutions AS Tracs International Consultancy Ltd Total current liabilities Long term liabilities Shareholder loan from AGR Group ASA Total long term liabilities Shareholder loan: Interest is calculated using 6 months LIBOR + a margin of 7.00% Note 9 Bank Deposits, Cash in Hand In NOK Cash in hand 2 - Bank deposits Bank deposits, cash in hand Of which is restricted deposits The majority of the Group companies are participants in a cash pool system. The participants are jointly liable for the obligations set out in the cash pool agreement entered into with DNB Bank ASA. Note 10 Share Capital and Shareholder Information Share capital consists of shares, with a face value at NOK 2. Total face value NOK The company has only ordinary shares and all shares have equal voting rights. In NOK Shareholders at 31 December 2013 Equity interest Number of shares Nominal value Share capital AGR Group ASA 92.6% Petco Invest AS 3.1% Petco Invest II AS 4.3% Total 100% Shareholders at 31 December 2012 Equity interest Number of shares Nominal value Share capital AGR Group ASA 96.9% Petco Invest AS 3.1% Total 100% ANNUAL REPORT

70 Note 11 Equity 2013 Share capital Other paid-in capital Other equity In NOK Total equity Opening balance Net profit Changes in equity Ending balance Share capital Other paid-in capital Other equity Total equity Opening balance Net profit Changes in equity Ending balance Note 12 Tax In NOK Income tax expense: Tax payable Norway - - Changes in deferred tax Norway Income tax expense Reconciliation of tax payable Tax payable in profit & loss account - - Tax payable in balance sheet - - Reconciliation of nominal and effective tax rate Net profit before tax Applicable tax with tax rate 28% Variance, actual and expected income tax expense (856) Explanation of why actual tax cost deviates from expected tax cost Tax effect from non-deductible costs Tax effect from non-taxable income (dividends) (1 120) (896) Re-measurement of deferred tax - change in the tax rate (252) - Adjustment of current income tax of prior years - 7 Variance compared to applicable tax rate (856) Tax base calculation Profit before income tax Permanent differences* (3 083) Temporary differences (26 824) (2 426) Loss carried forward (76 446) (33 343) Tax base - - ANNUAL REPORT

71 * Consist of non deductible costs. Deferred tax Below is a specification of temporary differences between accounting and tax values, as well as calculation of deferred tax/tax advantage at the end of the financial year. Basis for deferred tax Change Receivables (331) - (331) Borrowing costs* Financial instruments - (3 618) Amount linked to current balance sheet items (1 653) Fixed assets and intangible assets 47 (99) % at dividends Correction shares from 2011 (NOK 24,226) - 24 (24) Loss carried forward - (76 446) Amount linked to long-term balance sheet items 167 (76 425) Total basis for deferred tax assets (78 078) Calculation deferred tax/deferred tax assets Change Deferred tax of (6 802) * Classified as current in 2012 and long-term in 2013 Note 13 Bond loan/debt to Credit Institutions Refinancing of AGR Petroleum Services In Q AGR refinanced its Petroleum Services division by placing a NOK 550 million 5 year bond in the market. The bond agreement was signed in February 2013 and was listed on Oslo Stock Exchange in June In addition, DNB provided a NOK 100 million Revolving Credit Facility which purpose is to finance working capital requirements and to issue financial guarantees. The parent company AGR Group ASA provided a shareholder loan to AGR Petroleum Services Holdings AS which is a PIK loan subordinated to the bond and the RCF, and pledged in favor of the lenders. In NOK Overview of long-term interest bearing debt Long-term interest bearing debt Capitalised arrangement fee deducted (25 358) - Total long-term external interest bearing debt Shareholder loan from AGR Group ASA Total long-term interest bearing debt The company has a Revolving Credit Facility (the "RCF") of TNOK and an overdraft facility of TNOK At 31 December 2013 no cash drawings were made under the facilities, however bank guarantees of TNOK were drawn under the RCF. Accordingly the company had total unused credit facilities of TNOK Interest bearing debt is recorded at amortised cost, and the table below specifies the actual repayment schedule. At year end 2013 all interest bearing debt was denominated in NOK. Guaranteed liabilities Long-term and Short-term interest bearing debt Total guaranteed liabilities Average interest rate NOK loans (including shareholder loans) 8.5 % 4.88% ANNUAL REPORT

72 Debt amortisation profile Thereafter Total Revolving and overdraft credit facilities Interest bearing debt (excluding capitalised arrangement fee) Total Joint liability intercompany debt: The majority of the Group companies are participants in a cash pool system. The participants are jointly liable for the obligations set out in the cash pool agreement entered into with DNB Bank ASA. Guarantees: The Company`s guaranteed liabilities in 2013 are listed below, all in face value. Guaranteed liabilities, face value Bank of Western Australia Oil and Gas Development* MOL Pakistan* MOL Pakistan Qatar Petroleum* Bunduq Company Ltd* - 58 MOL Pakistan MOL Pakistan* Lukoil* Kogas Akkas* M/S Gail India Ltd* - 95 Petroleum Development Oman* - 29 Lukoil Overseas Iraq Exploration BV 91 - Abu Dhabi National Oil Company Tatapetrodyne Ltd Guaranteed liabilities, face value Comment: The guarantee expires when all terms and conditions to the contract are completed. * Guaranteed liabilities expired in 2013 Note 14 Other Current Liabilities In NOK Wages due Incurred interest costs Other current liabilities Current liabilities ANNUAL REPORT

73 Note 15 Wages, Fees, Number of Employees etc. In NOK Wages Employers' social security contributions 20 - Pension costs 50 - Other renumerations Total Wages and other remuneration to managing director are paid by AGR Group ASA and recharged to AGR Petroleum Services Holdings AS. There are no fees paid to the Board members of AGR Petroleum Services Holdings AS in There was one employee in the company's branch in Israel at 31 December. Auditor's fee Fees for audit of annual accounts Fees for tax-related services Fees for other services Total Note 16 Financial Income and Expenses In NOK Group distribution Interest income Group companies Other financial income Unrealised gain of financial instruments Dividend from subsidiaries Total financial income Interest expenses Group companies (14 127) (6 352) Other financial expenses Group companies (10 013) - Other interest expenses (46 983) (35 393) Other financial expenses ( ) ( ) Total financial expenses ( ) ( ) Net financial items Note 17 Provisions In NOK Amount related to the acquisition of Steinsvik, retained for 18 months Total ANNUAL REPORT

74 Note 18 Share Investment Program Share investment program In 2011 AGR introduced co-investment program in AGR Petroleum Services. In May 2011 AGR Group ASA sold A-shares in its subsidiary PetCo Invest AS to key employees and board members in AGR Group ASA and AGR Petroleum Services Holdings for NOK 102 per share. PetCo Invest AS owns shares in AGR Petroleum Services Holdings AS, corresponding to 2.1 %. AGR Group ASA is the owner of the remaining 97.9%. In April 2012 Petco Invest AS increased its ownership in AGR Petroleum Services Holdings with shares and owns shares, corresponding to 3.1 % per December AGR Group ASA was the owner of the remaining 96.9 %. In May 2013 the co-investment program in AGR Petroleum Services was expanded further through the establishment of PetCo Invest II AS. AGR Group ASA owned at this time A-shares in PetCo Invest II AS. During 2013, A- shares were sold to key employees and the chairman of AGR Group ASA for NOK 102 per share. Petco Invest II AS owns shares in AGR Petroleum Services Holdings AS, corresponding to 4.3% at the end of AGR Group ASA (92.6 %) and PetCo Invest AS (3.1 %) own the remaining 95.7 % per December AGR Group ASA's shareholding in Petco Invest AS and PetCo Invest II AS following the transaction was one controlling B- share respectively. Petco Invest AS and PetCo Invest II AS have been incorporated for the purpose of investing in AGR Petroleum Services Holdings AS. The price per share in PetCo Invest AS and PetCo Invest II AS was determined based on the estimated fair value of AGR Petroleum Services Holdings AS, using over-the-cycle EV/EBITDA trading multiples in accordance with EVCA guidelines. Accordingly, the transactions have not affected the profit and loss accounts of AGR. In order to increase the investments made by PetCo Invest AS and PetCo Invest II AS, AGR Group ASA has provided loans in the form of seller s credits with an annual interest rate of 8 %. AGR Group ASA has an option to increase its shareholding in PetCo Invest AS and PetCo Invest II AS by cash payment or set-off against any outstanding amount under the loan agreements. The co-investment programs within AGR Petroleum Services are governed by the provisions in a shareholders agreement. The shareholders agreement is entered into by and between the holding company, the investment company and the participants in the program. Among other things the shareholder agreement will provide for drag-along and tag-along provisions for the event that AGR Group ASA should sell its shares in the holding company. The participants cannot sell or transfer the shares in PetCo Invest AS and PetCo Invest II AS without the consent of AGR. If a participant in the program gives or is given notice of termination of employment before the second anniversary of the program, AGR has an option to buy the shares at fair value. ANNUAL REPORT

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