Annual Report • Dec 31, 2010
Annual Report
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Afren plc Annual Report and Accounts 2010
| 01 Overview |
IFc 01 02 04 06 08 10 |
Our Business at a Glance A Full Cycle Business Our Highlights The Opportunity Our Strategy Delivering Against our Strategy Key Performance Indicators (KPIs) |
|---|---|---|
| 12 Business Review |
12 20 26 42 44 56 57 60 62 64 |
Chairman and Chief Executive's Statement Case Studies Review of Operations 26 Production 32 Appraisal and Development 34 Exploration – Sub Saharan Africa 38 Exploration – Afren East Africa Exploration Risk Management Corporate Social Responsibility Share Price Information Financial Review Board of Directors Technical and Operational Leadership Team Corporate Functions Leadership Team |
| 65 Governance |
65 66 69 75 83 84 |
Index to the Report Directors' Report Corporate Governance Statement Directors' Remuneration Report Statement of Directors' Responsibilities Independent Auditors' Report |
| 85 Financial Statements |
85 85 86 87 88 90 |
Group Income Statement Group Statement of Comprehensive Income Balance Sheets Cash Flow Statements Statements of Changes in Equity Notes to the Consolidated Financial Statements |
121 Licences Oil and Gas Reserves Glossary of Terms Advisers and Company Secretary The progress arrow...
Throughout this report we outline Afren's business, the strategic goals and our performance against them in 2010. We look at the opportunity set; our strategy; how we delivered our strategy; risk management and CSR; and ultimately our financial performance and delivery of value to shareholders. For quick reference we have included an arrow graphic that clearly indicates the content of each page as you progress through the report:
Against a backdrop of increasing global demand for hydrocarbons, and with competition for upstream assets ever intensifying, a core and proven ability of Afren is to identify and access opportunities that offer substantial reserves potential on economically attractive terms and at a low unit cost.
Our vision to be the leading African independent upstream exploration and production company is underpinned by a clear and consistent strategy, one that is designed to provide a framework for sustainable long-term growth across the full cycle E&P value chain.
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We have defined four key objectives against which we measure the delivery of our strategy, namely production growth; organic reserves growth; materially accretive acquisitions and strong cost control and financial discipline.
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Afren's vision is backed by an unshakeable commitment to responsible business practices. We recognise the potential impact of our business on the environments and societies in which we operate, and our role in helping tackle some of our host communities' biggest challenges. In addition we are constantly identifying and analysing potential risks that could inhibit the Company's ability to deliver against our objectives, whilst also regularly reviewing our response and mitigating measures should things go wrong.
5. The outcome Afren's objective is to deliver top quartile returns to shareholders. We measure our performance against a range of peer group benchmarked metrics and equity market indices.
Afren is an upstream oil and gas company with 29 assets in 11 African countries that is active across the full cycle exploration and production value chain.
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• Production, Development, Appraisal, Exploration
• Production, Appraisal, Exploration
• Exploration
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• Exploration
• Appraisal, Exploration
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Afren is a leading pan-African independent exploration and production company – listed on London's Main Market and a constituent of the FTSE 250.
Our portfolio now extends to 29 assets in 11 countries, from Nigeria, Ghana, Côte d'Ivoire, Nigeria and São Tomé & Príncipe JDZ, Congo Brazzaville and South Africa, through to new East African opportunities in Ethiopia, Kenya, Madagascar, the Seychelles and Tanzania.
Our activities span the full-cycle E&P value chain of exploration, appraisal, development through to production, in a continent that is the fastest-growing supplier of natural resources to the world's leading markets.
Maintaining a strong local representation on our Board and management teams, as well as close relationships with indigenous companies and suppliers are top Afren priorities – as are ambitious Corporate Social Responsibility and ethical policies that ensure significant resources re-enter local economies.
Together, these unique factors have contributed to Afren's strong positioning in the London-listed E&P universe.
The 2010 results reflect the transitional stage of our underlying portfolio. During the period we have positioned the business for a considerable phase of growth throughout 2011 and beyond. We have significantly expanded our asset base, and put in place a capital structure with the financial flexibility to deliver our forward work programme and allow us to capitalise on further inorganic growth opportunities.
(1) See note 7 to the financial statements.
Production operations are underway at the Ebok field, we are expecting 35,000 bopd by the end of Q2 2010.
For more information see page 20
For more information see www.afren.com/ebok
The acquisition of OML 26 by First Hydrocarbon Nigeria (FHN) with Afren acting as FHN's technical partner, delivers a significant onshore portfolio with multiple production, development, appraisal and exploration growth opportunities.
For more information see page 24
Afren has established a core presence in East Africa through the acquisition of 13 high impact exploration assets in Ethiopia, Kenya, Madagascar, Seychelles and Tanzania. An active exploration drilling campaign across our portfolio is underway that will look to move a significant proportion of our 3,478 mmboe prospective resource base into the proved reserves category over 2011 and 2012.
For more information see page 22
In January 2011, Afren became the first UK listed independent E&P company to successfully raise capital from the bond market. This, together with expected cashflow from operations and existing cash resources, strongly enhances Afren's ability to capitalise on organic and inorganic growth opportunities.
For more information see page 57
Seeking out under-developed or overlooked opportunities in areas with proved working hydrocarbon systems in place and the potential for large scale upside.
Against a backdrop of increasing global demand for hydrocarbons, and with competition for upstream assets ever intensifying, a core and proven ability of Afren's is to seek out and access opportunities that offer substantial reserves potential on economically attractive terms at a low unit cost. We have been able to achieve this by playing to our strengths, focusing our efforts on opportunities where we are strategically advantaged, have a deep understanding of the subsurface, can leverage our track record and forge strong partnerships with key stakeholders.
For example, the African opportunity set is attractive to us on many levels. Most fundamentally the resources are there, in abundance. The continent continues to be a global leader in terms of growth in proven oil reserves, with an increase of 216% in Africa generally and 242% in West Africa specifically over the last two decades. Importantly the potential exists for this trend to continue long into the future, with numerous under-explored basins offering large scale upside over the medium to long term.
It is not just the sheer scale of opportunity that makes Africa such a compelling value proposition. The host governments of the countries in which we operate recognise the importance of attracting international investment and providing a stable fiscal and regulatory framework that allows local and international stakeholders to work together today, and plan for tomorrow.
Africa is a crucial source of oil supply to some of the world's most commodity hungry economies. The US currently sources 16% of its total crude oil imports from West Africa, a figure that is forecast to increase to as much as 30% over the next five years. Nigeria alone accounted for 11% of total US crude oil imports in 2010, and is one of only four countries that supplies in excess of one million barrels of oil per day into that market.
Afren is strategically well positioned in Nigeria's upstream sector and has been an early mover in forging strong indigenous partnerships, accessing and monetising some of the many discovered but undeveloped fields that reside in the incumbent major IOC's portfolios. These fields typically fall below the materiality and commercial thresholds at which the majors would actively progress development, yet to a more agile, independent operator such as Afren and our indigenous partners they represent opportunities of scale. There are also signs that the majors are actively considering strategic options for some of their legacy producing assets, typically in the onshore parts of the Niger Delta. These are all encouraging signs that point towards increasing liquidity in the asset market and a much greater role for independent E&Ps such as Afren.
Africa still has much to offer in terms of exploration potential, and although some basins have been extensively drilled there are many that until now have attracted only limited interest from the international industry, but hold tremendous potential. We have carefully constructed an exploration portfolio that provides us with exposure across some of the continent's highest profile exploration fairways. From the under explored Upper Cretaceous systems of the West African Transform Margin to the barely drilled rift basins of East Africa, we have today a high grade prospect inventory encompassing a diverse spread of hydrocarbon play types and structural settings. With net un-risked prospective resources in excess of 3,478 mmboe, a major growth opportunity for Afren is in shifting a significant portion of this prospective resource base into proved reserves by undertaking a sustainable internally funded exploration drilling campaign.
| 1999 | 2009 | growth (%) |
|---|---|---|
| 69.5 | 73.3 | 5.4 |
| 97.8 | 198.9 | 103.4 |
| 107.8 | 136.9 | 27.0 |
| 685.8 | 754.2 | 10.0 |
| 39.9 | 42.0 | 5.6 |
| 39.6 | 58.6 | 48.2 |
| 45.2 | 69.0 | 52.9 |
Source: BP Statistical Review of World Energy 2010.
Source: US Energy Information Administration
* Source: NSAI; Gaffney Cline; McDaniel; Management estimates for Kenya Block 1, Tanga Block and Block 2B.
Our vision to be the leading African independent upstream exploration and production company is underpinned by a clear and consistent strategy – one that is designed to provide a framework for sustainable long-term growth across the full cycle E&P value chain.
A closer look at our strategic priorities sets them in the context of Afren's growth to date. From the outset one of our key priorities was to establish a reliable platform of cash generative reserves and production that would lead us ultimately to a sustainable position of internally generated cashflows funding activities across the full cycle exploration and production value chain.
At the same time we recognised early signs of a trend in Africa towards greater indigenous ownership of assets and participation in the oil sector, and that opportunities would increasingly present themselves for an aligned partner that could provide the necessary technical solutions and access to capital in support of this.
The vast number of discovered but undeveloped assets that exist in Africa, particularly in the shallow water areas of offshore Nigeria, is an opportunity set that lends itself ideally to the early achievement of these objectives. Through forging strong partnerships with indigenous companies, such as Amni International and Oriental Energy Resources, we have accessed and successfully monetised important reserves and production, firmly establishing the region as our growth engine. This track record has also enabled us to progressively target larger scale opportunities that are starting to arise
out of the major IOC's portfolios, in partnership with indigenous companies such as First Hydrocarbon Nigeria.
Having sufficiently matured the business through the appraisal, development and production of key assets, the next step was to introduce an exploration portfolio to the business that would offer a balanced exposure to organic upside, leveraging our underlying cashflow to internally fund a carefully selected exploration campaign across some of Africa's highest profile hydrocarbon plays.
2010 was the year in which we realised our full cycle ambitions. With a proven acquisition led strategy at the core of the business, strict financial discipline and a balanced portfolio of assets that offer near, medium and long-term growth opportunities, our future is bright.
In 2010, our producing assets in Nigeria (Okoro) and Côte d'Ivoire (CI-11 and Lion Gas Plant) provided net effective working interest oil, natural gas and natural gas liquid production of 14,333 boepd (vs 22,100 boepd in 2009). This is primarily as a result of strengthening oil prices accelerating cost recovery at the Okoro field, with Afren's production share switching to 50% from the previous 95% at mid year.
Start up of the Ebok field represents the beginning of a new phase in production growth for Afren. Output from the field will progressively increase to 35,000 bopd, with ongoing development work through the remainder of 2011 and throughout 2012 expected to take production to full capacity of 50,000 bopd.
OML 26 offers a major re-development opportunity that is expected to further augment our future production. Afren and its partner First Hydrocarbon Nigeria (FHN) have defined a multi phase work programme that will see gross production at the field ultimately increase to 50,000 bopd.
02 Organic reserves growth
In 2010, we completed the Okwok-9 appraisal well, successfully establishing the field as a commercially viable development project and meeting all pre-drill objectives. The well encountered 35 ft of oil pay and flowed 31° API crude oil. NSAI has since estimated gross recoverable reserves at the field to be 51.8 mmbbls. We are in a strong position to further de-risk additional upside across the broader Ebok/Okwok/OML 115 area. We plan to drill another appraisal well at the Okwok field in 2011, and have two further wells planned targeting the Ebok North Fault Block, and the Ufon prospect on OML 115.
With net prospective resources estimated in excess of 3,478 mmboe, we have an exploration opportunity set that offers multiple drilling targets in some of Africa's most prospective basins. A key opportunity for Afren is to migrate a significant portion of this prospective resource into the proved reserves category. We aim to achieve this through undertaking an internally funded exploration campaign throughout 2011 and 2012 incorporating, amongst others, key wells in Ghana, Nigeria, Kenya, Ethiopia, Madagascar, Tanzania and the Seychelles.
03 Operational efficiency and financial discipline
Profit after tax for 2010 was US\$46 million, representing the Company's first full year reported profit after tax. On a normalised basis, excluding the effect of unrealised hedging movements and share based charges, we recorded a profit after tax of US\$64 million. We ended the period with a significant cash position of US\$140 million and continued to pay down existing debt facilities.
In March 2010, we secured an up to US\$450 million RBL facility to fund future development activities across the broader Ebok/Okwok/OML 115, area and in January 2011 we became the first UK listed independent E&P to go to the bond market and raise capital. A portion of the US\$500 million bond has been used by the Company to repay certain shorter term facilities, the remainder of which combined with existing resources and positive cashflow from operations means we have the capital structure and financial flexibility to deliver our work programme and capitalise on future organic and inorganic growth opportunities.
04 Pursue materially accretive acquisitions
Accessing low cost reserves One of the most important factors behind Afren's growth has been our acquisition strategy, and in particular our ability to deploy capital efficiently and access low cost reserves. In January 2010, we expanded our footprint offshore south east Nigeria around the Ebok and Okwok fields with the acquisition of an interest in OML 115, where we will explore for the same reservoirs that have proved oil bearing at Ebok and Okwok. In October 2010, together with FHN, we announced the acquisition of a significant onshore Nigerian portfolio at OML 26, offering existing production and large scale development, appraisal and exploration upside. Through our established partnership model we are well positioned to further capitalise on future growth opportunities in Nigeria.
Afren East Africa Exploration 2010 saw us expand our footprint into East Africa through the all share acquisition of Black Marlin Energy. The transaction delivered a platform of 12 assets across Ethiopia, Kenya, Madagascar and Seychelles, located in some of the region's most prospective rift and coastal basins. Post period end we were able to further consolidate this position with the acquisition of the Tanga Block, offshore Tanzania.
Afren has a balanced portfolio of 29 assets across 11 African countries covering the entire E&P value chain.
For more information see page 34
Afren has 7 KPIs which we use to measure our performance and progress.
Net effective working interest production boepd
2010 production was primarily influenced by cost recovery being achieved at the Okoro field mid year, at which point Afren's production share switched to 50% from 95%, and also reflects natural depletion at assets in production during the period.
The Company expects new projects to drive significant production growth in 2011 and beyond.
An in-depth geological understanding combined with close monitoring and planning of production performance helps us guard against unplanned interruptions.
Realised oil price US\$/bbl
Year on year increase Oil prices strengthened considerably throughout 2010.
Oil prices have continued to rise during the first quarter of 2011, although volatility remains a concern.
Our strategy to manage exposure to oil price volatility is to hedge between 20-30% of our production curve by using financial instruments which allow us to protect against downside risk.
Reserves replacement ratio
Reserves increases have again been significant, driven by the successful appraisal of Okwok. The ratio is calculated using the last three year's reserves additions over that period's production.
The significant exploration and appraisal programme for 2011 has the potential for a further high reserve replacement ratio, despite high production expected.
* Includes Okwok contingent resources which are subject to final development approvals.
Operating cash flow US\$ million
The reduced operating cash flow realised in 2010 is a factor of lower net production, although oil prices partially countered this effect.
Higher production volumes and strong oil prices are expected to lead to increased cash flows in 2011.
Strong financial management, tight controls over expenditure with detailed monitoring and monthly reporting of cash flow allows us to develop courses of action to ensure positive cash generation from our
Overview
We fell short of our target of improving performance to below the industry average for Africa, primarily due to a security breach at the Okoro field in November 2010.
We have undertaken a full review of our performance security requirements and implemented actions to upgrade security at our operations. We will focus on strengthening our supervision and oversight of contractor activities.
With strong leadership and clear policy and procedures in place, we promote health and safety awareness and accountability at all levels of the organisation.
18.1 US\$/boe
Operating costs increased during the period as a result of reduced production rates adding pressure to cost per unit. Higher costs were also associated with exporting Okoro crude oil via the Ima terminal, although this arrangement was offset by the resulting increase of US\$3/bbl to realised sales price relative to Brent at the point of sale. efficiency can be achieved at our producing assets. 2009 2010
With production forecast to increase considerably we expect operating costs per unit to decrease significantly in 2011.
We undertake a comprehensive budgeting process and continually monitor costs against budget to identify potential over-runs. Additionally, our operations team constantly seeks to identify areas in which greater
Normalised profit after tax increased due to the higher realised oil price, a 40% reduction to DD&A charges and substantially reduced financing costs.
With production start up at the Ebok field, Afren's outlook is expected to be positive over the forseeable future with a flat oil price outlook.
The Board of Directors is responsible for the effective implementation of Afren's strategy and business plan. It is the successful execution of strategy and achievement of our key objectives that will ensure
Net reserves and contingent resources.
Egbert Imomoh Chairman
Osman Shahenshah Chief Executive
In 2010 we made significant progress on the Ebok development, progressed our Nigerian growth strategy and made a strategic exploration-led entry into East Africa. Looking forward, we have a balanced portfolio combining production and development assets that we can leverage to internally fund high impact exploration and appraisal activities, underpinned by a capital structure that will support a strong acquisition opportunity set.
Full year profit after tax of US\$45.9 million. Strong realised oil prices during the period benefited revenues which, together with reduced depreciation, depletion and amortisation (DD&A) and finance charges, substantially offset lower net volumes, having reached payback on Okoro. Afren's financial profile will be further strengthened in 2011, with ramp up of production at the Ebok field.
2010 production reflects both the earlier than anticipated achievement of cost recovery at the Okoro field, due to strengthening oil prices during the period, and natural reservoir depletion. Net production is expected to average 40,000 boepd during 2011, through production ramp up at the Ebok field and the impact of two infill wells at the Okoro field, where we are moving towards the 3P recovery case. OML 26 has the potential to add significantly to volumes as First Hydrocarbon Nigeria ("FHN") moves towards completion and seeks to progress with the re-development of the Ogini and Isoko fields.
Total net working interest 2P reserves and contingent resources at 31 December 2010 have been independently estimated by NSAI at 135.7 mmboe, representing an increase of 23 mmboe (20%) year-on-year. This increase is due predominantly to the successful Okwok-9 appraisal well, confirming commercial gross recoverable volumes of 51.8 mmbbls at the field.
The acquisition of OML 26 by FHN, with Afren acting as FHN's technical partner, represents a key milestone for our long term Nigerian growth strategy. Transitioning of operational handover to FHN and Afren is almost complete and customary approvals are anticipated shortly. We are well positioned to implement a phased re-development plan to ramp up production at the Ogini and Isoko fields to 50,000 boepd, and rapidly monetise the significant E&A upside potential that also exists on the block.
During the period from January 2010 to March 2011 the Company acquired 16 assets and entered six new countries. We will continue to seek under-developed or overlooked opportunities where Afren is competitively and strategically advantaged, and can leverage its track record and expertise to access and monetise reserves and resources at a low unit cost.
In Ghana, we farmed down a 35% interest and operatorship in the Keta Block to ENI in return for a full carry through the drilling of one exploration well, contribution to back costs and future seismic acquisition. Post farm down, Afren will retain a 35% interest in the block. Other partners on the Block are GNPC (10%) and Mitsui E&P Ghana Limted (20%). The farm down is subject to customary government and partner approvals.
Following a period of significant expansion to our exploration portfolio, we now have an established presence in three core exploration fairways – the West African Transform Margin where we are focused on large scale potential in the Upper Cretaceous; the Niger Delta where we are particularly focused on low risk, amplitude supported upside around the core Ebok/Okwok/OML 115 area; and the East African rift systems and coastal basins where we have identified major prospectivity across Permo-Triassic to Tertiary aged sequences and have multiple potentially play-opening drilling targets. In 2011, Afren will participate in up to 10 exploration and appraisal wells targeting a total net mean prospective resource base in excess of 630 mmbbls (1,150 mmbbls gross).
Afren became the first UK listed independent E&P company to access the bond market in 2011, raising a total of US\$500 million and in the process diversifyied its sources of capital. With forward E&A capex internally funded, and significant additional working capital available, the Company's ability to capitalise on M&A growth opportunities has been greatly enhanced.
Afren has achieved significant portfolio growth, and shown innovation in accessing new sources of capital. We expect 2011 to be another defining year in the history of Afren, characterised by strong production growth and an internally funded E&A drilling campaign, whilst continuing to capitalise on a strong acquisitions pipeline.
In 2010, the Company expanded its portfolio to 29 assets across 11 African countries, offering an attractive mix of near, medium and long-term growth opportunities spanning the full cycle E&P value chain.
Six years ago the Afren Board set out its vision of becoming the leading pan-African independent upstream oil and gas company, and put in place a carefully formulated strategy to provide a sustainable long-term growth model. Key objectives were also set, against which we measure our progress. These cover the delivery of reserves growth, production growth and materially accretive acquisitions to our shareholders whilst maintaining strict financial discipline at all times.
2010 was a year of continued delivery against each of these objectives and we have carried this momentum into 2011. The Company has expanded its portfolio to 29 assets across 11 African countries, offering an attractive mix of both near, medium and long-term growth opportunities spanning the full cycle E&P value chain. Our production outlook is one of considerable growth as we ramp up output at the Ebok field. We also have a busy development pipeline as we further progress work at the Okwok field and implement plans to realise the full potential of our newly acquired onshore Nigerian portfolio at OML 26, where we are partnered with FHN. We have expanded our exploration portfolio, which now encompasses high grade acreage positions in some of Africa's most exciting exploration fairways, and have multiple wells planned over the coming 24 months with each having the potential to be a major play-opener for us. All of this has been underpinned by prudent financial management and preservation of an appropriate capital structure that will allow for us to continue on our strong growth trajectory.
We believe that Afren's vision is only achievable through an unshakeable commitment to responsible business practices. Acting responsibly lies at the very heart of our corporate strategy. Our commitment to Corporate Social Responsibility (CSR) goes much deeper than simply satisfying legislation. It means embedding values and ethical behaviour throughout our organisation, and setting an example through the conduct of our Board of Directors. It also means adopting the highest standards, and encouraging and supporting employees to follow them.
We recognise the potential impact of our business on the environments and the societies in which we operate. We also know we have a deep responsibility to a wide range of stakeholders, from local communities and investors, to employees and business partners, as well as regulators and governments. This not only drives us to maintain the most rigorous health and safety procedures, but also to protect communities and environments by aiming to carry out our work with minimum impact. This commitment reaches to the core of the communities in which we operate. We continue to lend our support locally, establishing programmes that tackle some of the countries' biggest challenges in areas such as education, health and employment. More information on these and key initiatives can be found in the dedicated Corporate Social Responsibility section on page 44.
Right: Afren employee overseeing installation of the MOPU at Ebok.
In 2010, Afren's Total Shareholder Return (TSR) during the period was 74% representing an upper quartile performance versus our Main Market listed independent peer group.
Right: The Central Fault Block well head platform at Ebok, has 12 well slots and is tied back to the MOPU, where crude oil is stabilised before being stored in the FSO.
Vital to Afren's success are the people who enable us to deliver on our promises. We continued to grow our team with 53 new arrivals joining us during the year. Our total workforce now stands at 320, of which 225 are full-time employees. We remain committed to developing local talent in each of our operating areas and have 98% permanent Nigerian nationals working in our Lagos office and at the Okoro and Ebok fields. In Côte d'Ivoire we have 99% permanent Ivorian nationals working in our Abidjan office, as well as at Block CI-11 and the Lion Gas Plant.
The monitoring and management of risks to the business are integral to our organisational framework. So that we can continue to operate safely and effectively, we are constantly identifying and analysing potential risks that could adversely affect our ability to deliver against our objectives – whilst also, crucially, mapping out our response should things go wrong.
We have a reporting system in place that provides for the direct and timely reporting of risks to the Board of Directors. It is a solutions-based approach which focuses on specifying precisely what actions are required to help us continually improve risk mitigation and ensure we are equipped to deal with a constantly changing external operating and business environment. More information on risk management can be found on pages 42 and 43 of this report.
Commodity markets strengthened considerably over the course of 2010, with Brent Crude starting the year at US\$77.2/bbl and exiting the year at US\$94.3/bbl – an increase of 22%. In early 2011, geopolitical tensions in the Middle East and North Africa have raised concerns over risks to near term oil supply that have in turn contributed to oil prices breaking through US\$100/bbl for the first time since mid 2008. We actively seek to manage our exposure to oil price volatility, but large movements in either direction may still result in increased volatility with respect to the Company's earnings. The US Dollar showed early signs of strengthening in 2010, but weakened over the second half to give an average rate of US\$/£1.6.
In terms of the cost environment, we witnessed deflation during 2009 as reduced cashflows and tighter credit markets forced the industry to prioritise investments and rationalise capital expenditure. During this time we were able to lock-in a significant portion of costs relating to the Ebok field development. During 2010, inflation started to return as oil prices rebounded, liquidity returned to the credit markets and service companies sought to rebuild margins.
Initial indications for the industry in 2011 are encouraging, as the global economy trends towards continued recovery and consensus opinion indicates a strong oil price outlook. We do, however, recognise that the future will always hold a degree of risk and uncertainty. In this respect we plan for a number of possible external scenarios, and ensure that the necessary operational and financial flexibility is built into the business to enable us to deliver maximum returns.
In 2010 Afren's Total Shareholder Return (TSR) was 74%, representing an upper quartile performance versus our Main Market listed independent peer group, and we were the 25th best performer in the FTSE 250 index. We outperformed the FTSE All Share and FTSE 250 indices by 63% and 49% respectively during the period. From IPO to the end of 2010 we have delivered a TSR of 738%.
2010 is the first full year in which we have reported a statutory profit after tax.
2010 is the first full year in which we have reported a statutory profit after tax. Reported profit after tax of US\$46 million (US\$64 million on a normalised basis) was driven by turnover of US\$319 million (2009: US\$336 million) of which US\$287 million was related to the Okoro field. Gross profit for the year was up by 22% on 2009 at US\$129 million, due largely to a 41% reduction in the DD&A charge which reflects our lower effective working interest production as a result of achieving cost recovery earlier than expected at the Okoro field. Finance costs were also greatly reduced in the year at US\$11 million (2009: US\$37 million), reflecting lower overall debt in the period and capitalisation of US\$14 million of charges relating mostly to the Ebok RBL facility (2009: US\$2million). Tax for the year was US\$33 million (2009: US\$17 million), reflecting the increased profitability of the business in 2010.
We maintained a conservative balance sheet in 2010, ending the year with a net debt position of US\$128 million, compared with a net cash position of US\$54 million at the end of 2009. Cash from operations during the period was US\$209 million. In March 2010, we secured an up to US\$450 million RBL facility to fund ongoing development of the Ebok/Okwok/OML 115 area. US\$250 million was available to us at year end, of which US\$107 million had been drawn at 31 December 2010.
Left: Onshore operations at the Ogini field. The Ogini field was acquired by First Hydrocarbon Nigeria (FHN) with Afren acting as FHN's technical partner.
Left: OML 26 production infrastructure.
Right: The Virini Prem FSO, for the Ebok development, was converted from an existing tanker, and has a storage capacity of 1.2 million barrels.
Total oil and gas capital expenditure during the period amounted to US\$437 million, of which US\$329 million related to the Ebok project, US\$34 million to the Okoro infill programme and US\$74 million to appraisal and exploration activities. We anticipate capital expenditure in 2011 to total approximately US\$410 million. Post period end we completed a bond issue in January 2011, initially raising US\$450 million in senior secured notes with a subsequent tap issue in February raising a further US\$50 million. The notes replace certain of Afren's preexisting debt facilities, reflecting the growing maturity of the Company's capital structure. Independent upstream E&P companies (including Afren) are currently reliant on a relatively limited number of lending banks that support projects in Sub-Saharan Africa. The bond issue reduces this reliance and also any potential vulnerability in times of tight credit. Furthermore, the issue represents an opening to new additional sources of longterm capital, thereby enhancing our ability to capitalise on a strong acquisitions pipeline.
During the year we registered solid production performance across our core underlying platform of producing assets. Average full year gross 2010 production at the Okoro field, located offshore south-east Nigeria, was in line with expectations at 16,055 bopd for the year. We recently completed the drilling of two infill wells to increase sweep efficiency in the Lower Sand reservoir, and as a result expect full year 2011 gross production at the field to average 17,690 bopd.
In November 2010, a security breach occurred on the Transocean High Island Vll jack up drilling unit and the AT 101 support vessel positioned at the field. Seven hostages were taken and held captive for 10 days. We
were pleased when the successful release of all hostages was secured and have since undertaken a full review of the incident and security requirements at all Afren operations. The findings have now been incorporated into our risk management processes.
Full year 2010 production at Block CI-11 was approximately 5,088 boepd. A wireline workover programme to remove wellbore wax build-up and obtain down hole pressure data was also completed. Natural Gas Liquid (NGL) output at the Lion Gas Plant (Afren 100%) during full year 2010 was 721 boepd, again as projected.
Afren and its partners are continuing to monitor events closely in Côte d'Ivoire both in light of the political situation and the EU sanctions regime. Afren is in discussions with relevant authorities as to whether the EU sanctions regime may have an impact.
In February 2011, we successfully installed the Ebok production processing and storage facilities and commissioned development Phase 1 that is targeting the Central Fault Block area of the field. This feat was achieved in just over two years from drilling our first operated appraisal well at the field and is the culmination of over 300,000 man hours of intensive work by Afren, our partner Oriental Energy Resources and our contractors. The project is Afren's second greenfield development and further demonstrates our technical and operational capabilities whilst also illustrating the potential of Nigeria's large discovered, but to date undeveloped, "fallow field" opportunities.
The Ebok field has been developed using a Mobile Offshore Production Unit (MOPU), a Floating Storage Offloading vessel (FSO) and two unmanned 12-slot wellhead
Net effective working interest production for the period was 14,333 boepd, with significant growth expected in 2011.
Right: Armada Perkassa FPSO on the Okoro field.
platforms positioned over the Central and West Fault Block areas. The MOPU's initial production capacity is 50,000 bopd with 1.2 mmbbls storage capacity at the FSO. As part of a phased development approach, the facilities have been configured to allow for future on-site expansion and upgrade. This will allow us to accommodate production from any future additional development phases at the field or in the broader area including the Okwok field and OML 115.
Development Phase 2, targeting the West Fault Block area, will see four horizontal production wells and up to two water injection wells sequentially drilled and commissioned, taking gross field output up to a rate of 35,000 bopd. Further development work beyond Phases 1 and 2 will take place over the second half of the year and throughout 2012, and is expected to add incremental volumes taking field production to full capacity.
We successfully completed the Okwok-9 appraisal well in August 2010, encountering a 35ft oil column in an excellent quality D2 reservoir and flowing 31° API crude oil. The well confirmed the commerciality of the accumulation, for which NSAI has since independently estimated gross recoverable reserves of 51.8 mmbbls. Next steps at the field include acquiring additional 3D seismic to assist with development planning, and the drilling of a further appraisal well to scale the project and define production facilities requirements.
Our ongoing monetisation strategy of the broader Ebok/Okwok/OML 115 area will see us continue to test the upside potential we have identified through further drilling in 2011. We expect to spud key wells on the Ebok North Fault Block and also on OML 115, targeting the estimated 60 mmbbls Ufon prospect. Both wells are seeking to prove extensions of the same 'D Series' reservoirs that we have already proved as oil bearing at both the Ebok and Okwok fields.
In October we announced that our indigenous partner, First Hydrocarbon Nigeria (FHN), had reached a definitive agreement with the Nigerian subsidiaries of Shell, Total and ENI to acquire a 45% interest in OML 26 onshore Nigeria. Afren holds a 45% shareholding in FHN, and also provides necessary technical, operational and management resources. The block offers substantial resource potential and is an onshore portfolio in itself. With an independently estimated 184 mmbbls of recoverable oil identified at the currently producing Ogini and Isoko fields, we have defined a three-phase work programme to increase gross production to 50,000 bopd from current levels of around 5,000 bopd. At the same time we are devising a strategy to develop the estimated 144 mmboe of discovered but undeveloped resources and prove up the 615 mmboe of exploration upside potential that exists on the block. This ground-breaking transaction represents the crystallisation of Afren's long-term Nigerian growth strategy. It is also further evidence that a secondary asset acquisition and divestiture market is opening up in the country, as pressure mounts on the incumbent asset holders to optimise development of Nigeria's national hydrocarbon resources and develop local capacity. The transaction is also a strong endorsement of the progressive role that independent E&Ps such as Afren can play in achieving this. We believe that through our existing partnerships, and now also working with FHN, we are strategically well-positioned to play a significant role in the future growth of Nigeria's indigenous independent sector.
Having achieved our early strategic priority of establishing a reliable platform of cash generative reserves and production, the Afren Board deemed 2010 an appropriate time for the Company to take further steps towards realising its pan-African ambitions and grow its exposure across the full cycle E&P value
Looking ahead, we will continue to de-risk and develop the existing production, development and appraisal opportunities within our portfolio, whilst leveraging our West African production base to pursue multiple high impact exploration targets in East and West Africa.
chain. Having matured our West African production and development asset base, the Company today has a robust financial profile that it is able to leverage in support of a selective high-grade exploration campaign, offering a balanced exposure to potentially large-scale high value opportunities.
We completed the all-share acquisition of Black Marlin Energy, an East Africa focused exploration company that was listed on the Toronto Venture Exchange, in October 2010. The transaction has delivered a high-impact exploration portfolio comprising 12 assets across Ethiopia, Kenya, Madagascar and Seychelles. Post period end we acquired interests in the Tanga Block offshore north east Tanzania and Block 2B offshore South Africa, subject to customary approvals, further augmenting our exploration inventory and expanding our pan-African footprint. The newly acquired assets are highly complementary to our existing acreage positions, and all exhibit strong evidence of working hydrocarbon systems. Elsewhere, in Ghana we are pleased to welcome ENI as partner and operator at the Keta Block, having reached an agreement to farm down a portion of our interest in return for a carry through the drilling of a planned exploration well later this year. This farm down is pending customary approvals from the Ghanian government and our partner Mitsui. The involvement of such a successful, regionally active partner is a positive endorsement of the block's potential. We now have a strong presence in some of Africa's most prospective hydrocarbon basins and plays, ranging from the Upper Cretaceous fairway along the West African Transform Margin in Côte d'Ivoire and Ghana, to the prolific oil-producing Tertiary systems of the Niger Delta and now the high potential East African rift and coastal areas.
In December 2010, we announced that Constantine Ogunbiyi was to step down as Executive Director of Afren with effect from 4 January 2011 following his appointment as Chief Executive of First Hydrocarbon Nigeria. We are grateful for Mr Ogunbiyi's significant contribution to Afren over the past six years, and wish him every success in his new role.
Looking to the year ahead we are wellpositioned for ongoing success against our strategic objectives. We will continue to de-risk and develop the existing production, development and appraisal opportunities within our portfolio, whilst leveraging our West African production base to pursue multiple high impact exploration targets in East and West Africa. We believe we have a strategically advantaged position in key markets which, combined with our proven ability to access low cost resources and the financial profile to capitalise on new growth opportunities, means the future is bright for Afren.
Egbert Imomoh Chairman and Founder
Osman Shahenshah Chief Executive and Founder
In February 2011, we successfully installed the production and storage facilities and commenced production operations at the Ebok field. The phased development approach adopted by Afren and our partner Oriental Energy Resources, combined with the decision to utilise a Mobile Offshore Production Unit (MOPU) and Floating Storage Offloading vessel (FSO), has allowed us to fast track development of the field where our initial three well appraisal drilling campaign more than quadrupled gross reserves to 106.2 mmbbls. This innovative development concept has also generated cost savings of an estimated US\$51 million in up-front costs and day rate charges compared to other options that were considered.
Development Phase 1 is targeting the Central area of the field, and Phase 2 the West Fault Block. Un-manned 12-slot wellhead platforms have also been installed at each location and tied back to the MOPU, where crude oil is stabilised before being stored in the FSO for sale directly to the international market.
In December 2010, three out of five Phase 1 production wells were tested at a constrained aggregate rate of 12,500 bopd. Development drilling for Phase 2 will see a further four production wells and up to two water injection wells sequentially drilled, completed and commissioned. Gross output from Phases 1 and 2 alone is expected to reach 35,000 bopd. Post Phase 2 we intend to continue with ongoing development of the field, targeting proven oil bearing reservoirs that will not have been accessed by the first two phases and fully utilising the remaining available production capacity at the MOPU.
Our success at Ebok has created follow-on opportunities for us to extend our partnership with Oriental Energy Resources, and we were quick to secure positions in the nearby Okwok field and surrounding OML 115 acreage. In October we successfully completed the Okwok-9 appraisal well having encountered 35ft oil pay in the same D series reservoirs that are now in production at Ebok, and confirming the field as a commercially viable development project. Plans for 2011 include the acquisition of 3D seismic and additional appraisal drilling to help define and scale development requirements. We will also be drilling exploration wells to test the upside potential at the Ebok North Fault Block and the Ufon prospect on OML 115 as part of our ongoing strategy to progressively unlock the substantial upside that this core area has to offer.
Progressive de-risking of a substantial resource base (mmbbls)
Okwok Contingent Ebok 2P Okwok Upside OML 115 Upside Ebok Upside
Only 21% of total area resource potential is reflected in the 2P reserves category.
Above: Constructing the MOPU at the Gulf Cooper Shipyard, Galverston USA. The MOPU has been converted from an existing jack-up rig. With a processing module capable of producing 50,000 bopd.
Total gross Ebok resource potential certified by NSAI.
Source: NSAI
west Fault Block wellhead Platform Floating Storage Offloading vessel
Offtake Tanker
Mobile Offshore Production Unit
Central Fault Block wellhead Platform
Afren plc 21 Annual Report and Accounts 2010
From inception, Afren has sought to establish itself as a pan-African E&P company that is active across the full cycle value chain from exploration, appraisal, development through to production. Now, with an established platform of cash generative production in West Africa that we can leverage, it is an appropriate time for us to extend our footprint to other less well explored parts of the continent that offer large scale growth potential through the exploration drill-bit as part of a balanced portfolio.
The acquisition of Black Marlin Energy Holdings Ltd gives us an established multi-country platform in East Africa and provides a complementary extension to our portfolio where we now have exploration assets spanning the Upper Cretaceous plays along the West African Transform margin, the prolific oil producing Tertiary systems of the Niger Delta and now the highly prospective East African Permo-Triassic to Tertiary rift systems and coastal basin plays. The package comprises 12 assets across Kenya, Madagascar, Seychelles and Ethiopia, all of which encouragingly have evidence of working hydrocarbon systems being present. In March 2011 we announced the acquisition of a 74% interest in the Tanga Block, located offshore and onshore north east Tanzania. The block lies south of and is contiguous with Afren's 100% owned and operated blocks L17/L18 in Kenya, and contains a southerly extension of the same coastal high and basin trough plays. The acquisition represents a complementary extension to our existing East African platform, and is an opportunity for Afren to leverage its regional expertise and knowledge.
To put the opportunity into context, there have been less than 500 wells drilled in East Africa compared to over 14,600 wells in West Africa and 19,000 in North Africa. However, the comparatively few wells drilled to date have yielded some significant oil and gas accumulations, most notably in Madagascar, Mozambique, Tanzania and Uganda. Further encouragement is also provided by looking at areas that share the same geological origin as the region, and were connected as part of the mega-continent Gondwanaland some 200 million years ago before the continents drifted apart to their current locations. Yemen, Southern Sudan, the Bombay and Cambay Highs of India – all are productive regions today and provide important clues to unlocking the vast potential of the region.
The acquisitions have added over 2,258 mmboe of net unrisked prospective resources to Afren. We have an active work programme defined that will see us drill multiple high impact exploration wells across all five countries through 2011 and 2012, each of which has not only the potential to be a significant discovery in itself, but also play-opening possibilities that could validate resource potential far in excess of that identified today.
Afren plc 23 Annual Report and Accounts 2010
In 2009, we established First Hydrocarbon Nigeria (FHN), a majority Nigerian owned, indigenous oil and gas company that fulfils the Nigerian governments criteria for local operators. Afren has a 45% shareholding in FHN and also provides technical, operational and commercial resources to FHN.
In October 2010, we announced the acquisition by FHN of a 45% interest in OML 26 (subject to customary government approvals) from the Nigerian operating subsidiaries of Shell, Total and ENI. Transitioning of operational control is expected in April, with our focus now firmly on execution of a three phase re-development plan designed to ultimately increase production to gross rates of 50,000 bopd from the currently producing Ogini and Isoko fields, and also to devise a monetisation strategy for the undeveloped Ovo, Ozoro and Aboh discoveries in addition to testing the significant exploration potential that exists on the block.
We continue to place great emphasis on working with Nigerian partners, contractors and financial institutions, fully capitalising on local expertise and resources in the oil and gas sector whilst also developing local capacity – an objective driven and supported by the Nigerian government. Our partnership with FHN and consummation of this transaction places Afren in a uniquely advantaged position to participate in the future growth of the Nigerian independent E&P sector. With FHN now established as an indigenous upstream champion, we will continue to seek out opportunities to further expand our partnership through the acquisition of other substantial oil and gas assets in Nigeria including those that are currently held by joint ventures between the Nigerian government and major international oil companies, assets that could be divested in connection with indigenous licensing rounds and assets of other Nigerian companies if appropriate.
Below: An Afren employee inspects the pipeline inlet header at the Ogini flow station, OML 26.
Afren produces oil, natural gas and natural gas liquids from its upstream and midstream operations in Nigeria (Okoro and Ebok) and Côte d'Ivoire (CI-11 and Lion Gas Plant). We have undertaken infill drilling at Okoro to deliver incremental production volumes in 2011, commenced production operations at the Ebok field where we will continue to grow production and announced the acquisition of an onshore portfolio at OML 26 in Nigeria with our indigenous partner FHN.
| Asset | Gross Production | Reserves* | Turnover |
|---|---|---|---|
| Ebok | – | 106.2 mmboe | – |
| Okoro EXPLORATIO |
16,055 bopd | 19.5 mmboe | US\$286.5 million |
| CI-11 N |
5,088 boepd | 4.9 mmboe | US\$22.8 million |
| Lion Gas Plant | 721 boepd A PPRA SI |
– | US\$9.7 million |
| AL |
* Gross remaining 2P reserves at 31 December 2010. DEVELOPMENT
FLOW
Storage capacity at the Ebok FSO.
man hours to date developing the Ebok field.
| Working interest | 100%/50%* |
|---|---|
| JV partner | Oriental |
| Gross 2P certified | 106.2 mmbbls** |
| reserves (31/12/10) | |
| Gross prospective | 117.7 mmbbls** |
| resources | |
| Work programme | Production |
| operations, | |
| Development and | |
| Exploration drilling |
* 100% pre cost recovery effective working interest; 50% post cost recovery effective working interest.
** Source: NSAI.
In February 2011, we successfully installed the production processing and storage facilities and commenced production operations at the Ebok field, located offshore south east Nigeria. We have adopted a phased approach
to the field development. Phase 1 is targeting the Central Area of the field, and Phase 2 the West Fault Block area of the field. Together, these initial phases will access around only 60% of the 2P reserves base established to date, with a rolling development programme planned for the outstanding 2P reserves, in addition to testing the significant upside potential that exists on as yet un-drilled parts of the field.
In December, we successfully tested three out of five horizontal production wells that were drilled throughout 2010 as part of Phase 1. A combined aggregate rate of 12,500 bopd 24° API oil was achieved with excellent reservoir properties of 30% to 35% porosity and multi-Darcy permeability also established. The results provide a strong indication that, together with the remaining production wells, our expectation of Phase 1 production plateau at 15,000 bopd should be exceeded. Phase 2 development drilling consists initially of four horizontal production wells and up to two water injection wells. The wells are being sequentially drilled, completed and bought onstream over the course of the second quarter and are expected on aggregate to boost field output by 20,000 bopd, taking total field production to in excess of 35,000 bopd. Ongoing development beyond Phase 2 is expected to add further incremental volumes.
Right: The Ebok field FSO.
The selected development solution for the field incorporated two un-manned wellhead platforms, one positioned in the Central Area and one at the West Fault Block, tied back to a Mobile Offshore Production Unit (MOPU) where crude oil is processed, from where it is then piped to a Floating Storage Offloading vessel (FSO) spread-moored nearby, where it is stored prior to sale directly into the international market.
The MOPU is a former jack-up drilling rig that has been converted to a production facility by removing the drilling package and replacing it with a processing unit. The facility has the initial capacity to handle oil production of 50,000 bopd, and has been designed to allow for onsite expansion and upgrade to accommodate production from future additional development phases. The advantages of utilising a converted jack-up were many; the installation of the unit did not require a derrick barge, and it could be installed whilst drilling operations were in progress, allowing for simultaneous installation and drilling with minimal interruptions to work.
The FSO provides a storage volume in excess of 1.2 mmbbls, which allows for the sale of million-barrel cargoes that in turn provide us with maximum flexibility to optimise shipping and crude marketing economics. Similarly, the vessel was converted from a pre-existing tanker, greatly reducing lead times to delivery compared to if a new build vessel was commissioned. Furthermore, opting for the MOPU and FSO development configuration has provided an estimated total cost saving of US\$51 million in upfront costs and day rate charges compared to alternative FPSO development solutions that were considered.
The Ebok Deep exploration well was drilled in Q2 2010 and intersected two sandstone intervals of 370 ft combined gross thickness in the targeted Biafra and Isonga formations, with oil shows providing positive indications of oil migration pointing to good potential for oil trapped up-dip from the well location. The well was temporarily abandoned and is available to use for further drilling in the area in the future. Importantly the well established a working hydrocarbon system and excellent quality sands at the deeper levels, the results of which have been incorporated into the subsurface model and will assist in future exploration of the significant potential that exists at Ebok, Okwok and OML 115.
Our development strategy is to systematically bring each proven area onstream, and through ongoing drilling continue to increase the reserves base and production from the field. We plan for the MOPU and FSO to become a central facility for not just the immediately surrounding Ebok structure but also for the broader Ebok/Okwok/OML 115 area, allowing for the economical and rapid tie-back of production from potential future developments on the acreage.
The year ahead will see ongoing development beyond Phase 2 aimed at the proved undeveloped reservoirs in the Central Fault Block and Southern Lobe of the West Fault Block. We are also planning further exploration and appraisal drilling at Ebok North, an untested fault block in the northern area of the field, where we believe the same reservoirs that have been proved to be oil bearing elsewhere at the field are also present.
Above: Creating a Nigerian production hub: MOPU on site at Ebok.
Top right: Afren employees on a jack-up drilling unit on the Okoro field.
Bottom left: The Armarda Perkassa FPSO, during a resupply by a support vessel.
Nigeria Okoro Setu PRODUCTION CASH PRODUCTION
| Working interest | 95%/50%* |
|---|---|
| Owner and Local | Amni |
| partner | |
| Gross 2P certified | 19.5 mmbbls** |
| reserves (31/12/10) | |
| Gross production | 16,055 bopd |
| Work programme | Production |
| operations/ | |
| Infill drilling |
FLOW
* 95% pre cost recovery effective working interest; 50% post cost recovery effective working interest, cost recovery achieved mid 2010.
** Source: NSAI.
By the end of 2010, the Okoro field had produced 13.9 mmbbls of oil. Production averaged 16,055 bopd throughout the year. There was a planned shutdown in the fourth quarter in order to undertake routine maintenance work which resulted in a modest impact on gross output at the field during that period of 252,045 bbls. Field performance remained ahead of pre start-up expectations and is due to: FLOW DEVELOPMENT EXPLORATION PRODUCTION
By constantly monitoring the production performance of each well and reservoir conditions, and maintaining a dynamic reservoir simulation model, we have been able to identify particular zones in the Lower Sand where sweep efficiency could be further improved upon and additional incremental oil volumes accessed. In order to achieve this we commenced an infill drilling campaign in November 2010 utilising the GSF High Island Vll jack up drilling unit.
Left: Afren employee on the Armada Perkassa FPSO.
Two infill wells are currently being drilled updip from the existing Okoro-4 and Okoro-5 production wells.
Taking all of this and production during the period into account, NSAI has estimated gross remaining 2P reserves at the Okoro field to be 19.5 mmbbls as at 31 December 2010.
The off-take and export of the crude oil produced at Okoro continues to run smoothly and without interruption. Having implemented a change in our export process in November 2009, whereby we are now using a shuttle tanker to transport the processed Okoro crude to the Amni operated Ima terminal, we have continued to benefit from the increased flexibility and storage capacity of over 1 mmbbls which translated into improved shipping and sales economics.
To date, production uptime has been maintained at 95.3%. During November a security breach occurred on the GSF High Island Vll drilling rig, as it prepared to spud the infill wells, and also at a support vessel. Seven hostages were taken for a period of ten days, after which they were released unharmed. Following the incident a full review of security measures and procedures was
undertaken at the field, the results of which have been incorporated into our broader risk management process. Production at the field was uninterrupted by the incident.
Having successfully drilled two infill wells, work in 2011 is firmly focused on ensuring optimal oil recovery from the existing nine wells, whilst also continuing to identify and work up other in or near field opportunities that could potentially add further oil volumes.
95.3%
Process uptime at the Okoro field.
US\$79.7/bbl
Average realised oil price in 2011.
| Working interest | 47.96% |
|---|---|
| Operator | Afren |
| Gross production | 5,088 boepd |
| Gross 2P certified reserves | 4.9 mmboe* |
| (31/12/10) | |
| Work programme | Production |
* Source: NSAI.
Full year 2010 production at Block CI-11 was approximately 5,088 boepd, comprising an oil rate of 1,086 bopd and natural gas rate of 23.2 mmcfd. A wireline workover programme to remove wellbore wax build up and obtain down hole pressure data was also completed. A detailed reservoir simulation model has also been constructed and history matched, with model iterations and updates using the newly acquired data undertaken and ongoing in order to enable evaluation of the impact of potential new infill wells and/or pressure maintenance on field productivity.
The outcome of this work is that a number of potential new reservoirs have been defined in addition to infill drilling opportunities in existing reservoirs. We are also focused on ways to best address low recovery factors in some field reservoirs via sidetracks of current wells. Furthermore, we are also looking at pressure maintenance via water injection as a means of enhancing the productivity of current production wells. CASH FLOW DEVELOPMENT EXPLORATION PRODUCTION
Production operations have continued in 2011. We continue to evaluate measures to optimise production from existing wells and define potential infill drilling targets that could incrementally add to reserves and production. Implementation of these plans is contingent on resolution of the political situation and the EU sanctions regime that has been imposed.
Right: Afren employees onboard the Gulftide production platform.
| PRODUCTION CASH FLOW |
|
|---|---|
| Working interest | 100% |
|---|---|
| Operator | Afren |
| Gross production | 721 boepd |
| Work programme | NGL extraction* |
* Butane extracted from gas stream at a rate of 12bbls/mcf; gasoline extracted from gas stream at a rate of 9bbls/mcf.
Afren is the sole owner of the Lion Gas Plant, which processes gas from the CI-11 and adjacent CI-26 and CI-40 blocks operated by Canadian Natural Resources. The plant has an inlet capacity of 75 mmcfd and strips gasoline and butane from the rich gas stream it receives. The butane is sold into the local market (meeting approximately 35% of the domestic butane demand) and gasoline is spiked into the CI-11 crude stream and sold on the international market. The plant benefits from tax-exempt status and the average NGL production at the LGP in 2010 was 721 boepd. We are also exploring ways to extract propane at the plant, which we would sell locally to industrial customers. The execution of any plans are subject to resolution of the political situation and the impact of sanctions imposed by the EU.
Right: The Lion Gas Plant has an inlet capacity of 75 mmcfd.
PPRA SI AL
| Working interest | 70%/56%* |
|---|---|
| JV partner | Oriental FLOW |
| Gross contingent resources 51.8 mmbbls** | PRODUCTION CASH |
| PRODUCTION Gross prospective resources 26.3 mmbbls** |
|
| Work programme | 3D seismic and |
| appraisal drilling |
* 70% pre cost recovery effective working interest
56% post cost recovery effective working interest (subject to gross volumes lifted).
** Source: NSAI.
Having achieved a 100% appraisal drilling success rate and more than quadrupling reserves at the Ebok field, we were quick to recognise the potential of the surrounding area and secure interests in the Okwok oil field and surrounding OML 115 acreage. We have been able to deploy the subsurface knowledge gained from work on the Ebok field to identify Okwok as a high-potential opportunity. There are many similarities between the two fields. The same reservoirs are present in both fields, as is the relationship of seismic amplitude to reservoir and hydrocarbon distribution.
Consequently, we believe there are larger in-place oil volumes than have been previously and independently quoted. Additionally, we have also identified significant potential in the deeper formations at Okwok. DEVELOPMENT
The Okwok-9 appraisal well was spudded during August 2010, and reached a total measured depth of 8,083 ft. The well was completed over a 35 ft interval of good quality D2 reservoir with average porosity of 30%, and flowed 31° API crude oil. The well was flowed for 48 hours and shut in for a 54 hour build-up. The final build-up pressure was equal to the initial reservoir pressure, very encouragingly indicating no depletion. The 48 hour flow test was designed to establish a connected reservoir volume, and also to quantify reservoir permeability and heterogeneity. DEVELOPMENT EXPLORATION PRODUCTION
Analysis of the log and test data acquired from the Okwok-9 well, and together with the seismic data, indicates that the primary objective of establishing the minimum economic field size in order to commercially develop the Okwok field, estimated by management at 25 million barrels, was fulfilled. Furthermore, information obtained from the well is consistent with, and supports, our subsurface model for the field. The results suggest that well productivity under a development completion scenario from a horizontal well would be consistent with production rates typically expected in the area of between 2,000 bopd to 4,000 bopd per well.
Work is now focused on defining the next steps in the ongoing evaluation of the field, and in particular working up conceptual development solutions that may include standalone options and also development as a satellite to the nearby Ebok field.
Having established the field as a commercial development project, with NSAI ascribing 51.8 mmbbls of gross recoverable resources to the field, we are now focusing efforts on defining the precise requirements and optimal development concepts that could be utilised. These include development as a satellite tie back to the central Ebok MOPU and FSO, or alternatively installation of a separate dedicated production processing facility with shared usage of the Ebok FSO. In order to assist with this process we plan to drill an additional appraisal well at the field in 2011 and acquire new 3D seismic over the area.
Below: We have been able to deploy the knowledge gained from work on the nearby Ebok field to identify Okwok as a high potential opportunity.
| Working interest | 65%* |
|---|---|
| Operator | Afren FLOW |
| Gross contingent and | PRODUCTION CASH 124.5 mmboe** |
| PRODUCTION prospective resources |
|
| Work programme | Electromagnetic |
| survey and 3D | |
| seismic |
* With rights over an additional 15%.
** Source: NSAI.
CI-01 has a proven petroleum system in multiple reservoirs within the Cretaceous. Oil and gas has been found and tested in the Ibex and Kudu fields, while only gas has been found in the Eland field. Most of the oil and gas encountered is in reservoirs that are younger than the Albian structural closures originally targeted in the past. There are 3D seismic surveys covering Ibex, Kudu and Eland, and a 2D seismic grid covers the rest of the block. The block borders the maritime boundary with Ghana, and lies adjacent to the major Jubilee and Tweneboa oil and gas discoveries that have been made in recent years. We have applied the latest understanding of the Cretaceous depositional systems to the existing well and seismic dataset to redefine the distribution of oil and gas in Kudu and Ibex, as well as other accumulations on the block. Consequently, we believe that the discoveries made to date on the block have the potential to be significantly larger than originally mapped.
We have completed a detailed subsurface evaluation and defined multiple prospects and leads in order to establish the optimal location for a well to test the new Cretaceous interpretation. Contingent on resolution of the political situation and EU sanctions regime we aim to acquire more 3D seismic over the block and may consider other techniques such as electromagnetic surveying that could aid our understanding of these complex depositional systems.
Below: Routine site inspection at the Lion Gas Plant.
We have assembled a balanced portfolio of exploration assets that provide a mix of exploration options across multipleplay types and basins. We are active in some of Sub Saharan Africa's most high profile exploration hot spots; from the Upper Cretaceous plays along the West African Transform Margin, the prolific Tertiary systems of the Niger Delta to the East African rift and coastal basins – each area has proved working hydrocarbon systems in place and has the potential to yield large scale discoveries that could add materially to our proved reserves base.
Gross estimated resources at the Ufon prospect on OML 115.
* 100% pre cost recovery effective working interest; 40% post cost recovery effective working interest
** Source: NSAI.
In January 2010, we announced the signing of a joint venture agreement with Oriental Energy Resources to jointly explore, appraise and develop OML 115. The block surrounds the Ebok and Okwok development area, which we also operate with Oriental, and is close to the giant Zafiro Complex in Equatorial Guinea. It offers us an attractive opportunity to further capitalise on our extensive knowledge of the area gained to date, and explore the same reservoirs that have already been proved as oil bearing and productive at Ebok and Okwok.
The southern portion of the Okwok structure (Okwok South) extends into OML 115 and additional prospectivity has already been defined within the deeper Que Iboe, Biafra and Isonga formations. With production processing, storage and export infrastructure in place at the Ebok field we have a readily available export route for any potential future development in the area, and at the same time will be able to benefit from cost synergies, lowering the economic threshold for new barrels in the area. APPRA SI AL PRODUCTION CASH FLOW CASH DEVELOPMENT DEVELOPMENT EXPLORATION PRODUCTION
We will drill an exploration well on the south western part of OML 115 during 2011, targeting the estimated 60 mmbbls Ufon prospect.
EXPLORATION
| Working interest | 91%/70%* |
|---|---|
| Local Partner | Optimum |
| Gross prospective resources | PRODUCTION 520.6 mmbbls** |
| Work programme | Farm down/ |
| Exploration | |
| drilling |
* 91% pre cost recovery effective working interest; 70% post cost recovery effective working interest
** Source: NSAI.
OPL 310 is located in the Upper Cretacous fairway that runs along the West African Transform margin and lies next to the Chevronoperated Aje field, which has recently been declared commercial. The block extends from the shallow water continental shelf to deep water, representing an exploration opportunity in an under explored basin with a proven working hydrocarbon system – in line with our strategy. It is also in close proximity to the recently completed West African Gas Pipeline (WAGP), allowing gas discoveries to be readily developed. We have good seismic coverage of the block in the form of a 307 km2 3D survey and 483 km of 2D data.
Encouragingly, OPL 310 contains several identified prospects. These lie in the same Cenonian, Turonian and Albian sandstone intervals that have yielded significant discoveries along the West African Transform Margin in Ghana and Côte d'Ivoire. The trapping configurations are four-way dip closed structures over basement highs. These have the same characteristics as the Seme, Atacora and Alibori discoveries in neighbouring Benin. APPRA SI AL PRODUCTION CASH FLOW DEVELOPMENT DEVELOPMENT EXPLORATION PRODUCTION
So far work has focused on defining the potential of the area covered by 3D seismic data. The key to our understanding of this is the seismic velocity model used to interpret the depth domain. We have reprocessed the existing seismic data to Prestack Depth Migration (PSDM) format also carried out an Electro-Magnetic (EM) seabed survey over a number of leads identified during the first phase of interpretation work. The EM survey has reduced the exploration risk associated with the opportunities we have already defined. This process was successful in the adjacent block over the Aje field and has been used in many other areas in Nigeria.
Having undertaken a significant amount of data acquisition and interpretation work, we are in the process of seeking an industry partner to participate in future exploration drilling on the block. It is possible that we will seek to acquire additional seismic data in 2011 ahead of drilling one exploration well.
| Working interest | 4.4% |
|---|---|
| Operator | Total |
| Gross contingent | 392.6 mmbbls* |
| and prospective resources | |
| Work programme | Exploration and |
| appraisal drilling |
* Source: NSAI.
EXPLORATION
In July 2010, Total announced it had agreed to acquire Chevron's 45.9% interest in Block 1. Total now operates the block that extends over an area of approximately 700 km² in water depths ranging from 1,600 m to 1,800 m. One discovery has been made on the block with the sole exploration well that has been drilled to date. In 2006, the Obo-1 exploration well encountered 150 ft of net pay and importantly proved a working hydrocarbon system in the JDZ. The proximity of Total's operated licences and production facilities in Nigeria creates strong synergies and will enable cost reductions in any potential future development of the licence's resources. PPRA SI AL PRODUCTION CASH DEVELOPMENT DEVELOPMENT EXPLORATION PRODUCTION
The new operator is seeking to reprocess existing seismic data and has proposed the drilling of one appraisal well on the Obo discovery and one exploration well in 2011.
| Working interest | 41%* | 42%* |
|---|---|---|
| Operator | AGER | AGER |
| Work programme | Seismic reprocessing | PRODUCTION Seismic reprocessing |
* AGER effective working interest; AGER is owned 50% by Afren, 50% by Global Energy Company (GEC).
Having acquired the original seismic tapes and reprocessed the data, we continue to evaluate the potential of the blocks. We are working on the identification of areas for future seismic acquisition that could ultimately lead to future exploration drilling.
Gross prospective resources at the Keta Block as estimated by NSAI.
Continued
| Working interest | 35% |
|---|---|
| Operator | ENI |
| Gross prospective resources | PRODUCTION 1,412 mmbbls* |
| Work programme | Exploration |
| drilling |
* Source: NSAI.
The Keta Block is in the Volta River Basin in Eastern Ghana, next to the maritime boundary with Benin. The block has both Tertiary and Cretaceous prospectivity, with the principal exploration focus being the Cretaceous Albian to Campanian sections. The block offers multiple prospects and leads, with a variety of trapping and depositional settings. A number of these show potential for significant stratigraphic trapping and giant field potential
EXPLORATION
subsurface studies to further evolve our understanding of the broader prospectivity that the block has to offer. Through this process we identified several large scale prospects in the same Turonian intervals that have proved to be prolific hydrocarbon reservoirs in the eastern offshore zones. As a result of this, NSAI has more than doubled its independent view of gross unrisked prospective resources on the block to 1,412 mmbbls. PPRA SI AL PRODUCTION CASH FLOW CASH DEVELOPMENT DEVELOPMENT EXPLORATION PRODUCTION
In March 2011, oil major ENI agreed to farm in to a 35% participating interest in the block. The farm down is subject to customary government and partner approvals. Following such approvals, Afren will retain a 35% participating interest and transfer operatorship to ENI. In consideration for the assignment of the farm out interest, ENI has agreed to carry Afren's share of costs associated with drilling one exploration well during the current exploration period. Afren will also receive non drilling back costs and a carry through a 3D seismic acquisition programme that forms part of the obligation for the next licence phase. ENI is an experienced deep water operator, has an established presence in Ghana where it is already actively engaged in exploration activities and has a drilling unit available that could spud an exploration well on the Keta Block as early as the third quarter of this year. Not only is ENI's participation a strong endorsement of the prospectivity, further demonstrated by NSAI's independent assessment, but we now have in place an ideal partnership to unlock the substantial potential that exists on the block.
The current exploration period carries the drilling commitment of one exploration well, which the partners intend to drill in 2011.
Left: Afren employee on board the Armada Perkassa. By the end of 2010 the Okoro field had produced 13.9 mmbbls of oil.
| Working interest | 14% |
|---|---|
| Operator | Maurel et Prom |
| Gross prospective resources | PRODUCTION 251.6 mmbbls* |
| Work programme | Ongoing studies |
* Source: NSAI.
The La Noumbi permit is located onshore Congo Brazzaville, to the north and on trend with the large producing M'Boundi oil field. The partners have entered the next exploration phase on the block.
The partners are defining a forward work programme having recently entered the next exploration phase on the block.
| Working interest | 25%* |
|---|---|
| Operator EXPLORATIO CASH FLOW |
Thombo |
| Gross prospective N |
350.0 mmbbls* |
| resources | PRODUCTION |
| Work programme DEVELOPMENT |
Seismic acquisition and exploration drilling |
* Subject to customary approvals; working interest increases to 50% and operatorship transferred to Afren upon completion
of seismic acquisition programme. ** Source: Management estimate.
Block 2B is located in the Orange River Basin, offshore shallow water area, lying between the Ibhubesi gas field and the Namaqualand coast. The block covers an area of approximately 5,000 km2 with water depths ranging from shore line to 250 metres. The main reservoir objectives are the fluvial and lacustrine sands of the AJ Graben of Lower Cretaceous age, which occur in three sequences. The A-J1 exploration well, drilled in 1989, successfully encountered oil in these sequences and tested good quality 36° API oil. Reprocessing of 2D seismic data has since defined several other Lower Cretaceous rift graben prospects, genetically analogous to the prolific Lake Albert play in Uganda. Further prospectivity has also been identified within a fractured basement play (analogous to Yemen), which could form a secondary exploration play on the acreage.
The partners near term work programme involves the acquisition of 350 km2 of new 3D seismic data, with reprocessing of existing 2D seismic and ongoing seismic inversion and regional biostratigraphy studies ahead of expected exploration drilling in 2012.
Left: Okoro field: By constantly monitoring the production performance of each well and reservoir conditions, we have been able to identity particular zones in the Lower Sand where sweep efficiency could be further improved and additional incremental oil volumes accessed through infill drilling.
Afren plc 37 Annual Report and Accounts 2010
The high-impact East Africa exploration portfolio is complementary to Afren's pan-African ambitions and will enable Afren to leverage its cash generative West African production base.
Our portfolio of 13 East African assets cover an extensive surface area of 135,880 km2 on a gross basis, and are all located in basins with strong evidence of working hydrocarbon systems being present. Afren East Africa Exploration is focused on Cretaceous, Jurassic and Tertiary rift basins which are geological settings that have yielded significant discoveries in Uganda, Sudan, Tanzania, Madagascar, Ghana, Nigeria, Angola, Sierra Leone and Brazil. A number of prospects have already been defined to date across the acreage, where the potential also exists to establish new hydrocarbon plays and additional prospectivity.
EXPLORATION
Out East African acreage position is equivalent to approximately 700 North Sea blocks on a gross basis.
| 50% |
|---|
| EAX* |
| PRODUCTION 751.0 mmboe** |
| Seismic acquisition and exploration drilling |
* EAX is a wholly owned subsidiary of Afren Plc.
** Source: Management estimate.
Block 1 is located on the Western margin of the Mandera-Lugh basin in north eastern Kenya bordering both Somalia and Ethiopia, where it is connected to the Ogaden basin. Afren operates the block with a 50% working interest.
The Upper Triassic and Jurassic formations that have been identified are considered to be the primary zones of oil prospectivity. An oil seep close to the well Tarbaj-1 in the South West corner of the block confirms the presence of hydrocarbons. Analogous data with the Ogaden basin also suggests there may be other potential source rocks and reservoirs. The Bur Mayo and the Kalicha-Seir formations in the Mandera-Lugh basin appear comparable to the Lower and Upper Hamanlei (Jurassic) formations in the Ogaden basin. If analogous, these formations should have high total organic content ("TOC") source rocks and good quality reservoirs. APPRA SI AL DEVELOPMENT
The partners have defined an active work programme that involves the acquisition of up to 1,200 km of 2D seismic data in addition to airborne gravity and magnetic data in 2011. Several major structures have already been mapped on the block that currently has 850 km of 2D seismic coverage, ahead of planned exploration drilling in 2012. PRODUCTION CASH DEVELOPMENT PRODUCTION
Above: Afren employees at the Okoro field, where we recently completed the drilling of two infill wells.
| Working interest | 20% |
|---|---|
| Operator | Tullow Oil |
| Gross prospective resources | PRODUCTION 250.0 mmboe* |
| Work programme | Seismic acquisition |
* Source: Gaffney Cliene.
Block 10A is located in the Anza Basin onshore northern Kenya, which is part of Central African Mesozoic rift system that also includes the Muglad Graben in Southern Sudan, and the Lamu Graben in Kenya. The block covers a total of 14,747 km2 . Three exploration wells were drilled by Amoco in Block 10A (Sirius-1, Bellatrix-1 and Chalbi-3) throughout 1988 and 1989 in the southern part of the block. The presence of oil and gas shows and the high maturity level of organic rocks in wells Bellatrix-1 and Sirius-1 is evidence of a working hydrocarbon system on the block. The latter well notably established the presence of an Upper Cretaceous lacustrine source rock that may have generated low-sulphur/paraffinic oil.
The Tullow Oil operated joint venture will acquire 750 km of 2D seismic over the block during the first quarter of 2011 to supplement the existing 2D coverage of 2,631 km. This work will satisfy seismic obligations for the current exploration period, which also carries a one well commitment (drilling expected in 2012).
| Working interest | 100% |
|---|---|
| Operator | EAX* |
| Gross prospective resources | PRODUCTION 93.8 mmboe** |
| Work programme | Seismic |
| acquisition |
* EAX is a wholly owned subsidiary of Afren Plc.
** Source: McDaniels..
The Block L17/L18 area is located in the Lamu Coastal Basin, offshore south east Kenya. The individual Blocks L17 and L18 cover an area of approximately 1,275 and 3,630 km2 respectively and are situated in water depths varying from a few meters along the shoreline up to around 500 metres.
There are several potential source rocks for the Cretaceous plays in the southern areas of the basin including the Permo-Triassic Karoo interval and sections within the Lower to Middle Jurassic. There are oil seeps in the Lamu Basin and Pemba Island linked to a Jurassic source which implies that the structures in Block L17/L18 are most likely oil bearing. The main reservoir targets are in the Upper Cretaceous although there may be additional potential in clastic reservoirs within the Tertiary. The hydrocarbons are expected to have been generated in the deep Pemba trough south of Block L18. PPRA SI AL PRODUCTION CASH FLOW CASH FLOW DEVELOPMENT DEVELOPMENT EXPLORATION PRODUCTION
EXPLORATION
A programme of 400 km short offset shallow marine 2D seismic data was acquired in the Shimoni area of Block L18 and in the Mombasa area of Block L17 during 2010. The new data are of a high quality and are presently being interpreted. A number of prospects and leads have been identified elsewhere on the block that represent attractive exploration targets, the main focus being targets in the Upper Cretaceous with additional potential also in clastic Tertiary sequences. We expect to acquire additional 2D seismic over some parts of the blocks in 2011 and drill one exploration well commencing late 2011/early 2012.
EXPLORATION
Above: Monitoring production systems on board the Armarda Perkassa.
| Working interest | 40% |
|---|---|
| Operator | Candax |
| Gross prospective resources | PRODUCTION 191.4 mmboe* |
| Work programme | Exploration |
| drilling |
* Source: McDaniels.
Block 1101 is located on the eastern flank of the Ambilobe basin onshore northern Madagascar. The block encompasses an area of approximately 14,900 km2 . Some 220 km of 2D seismic has been acquired over the southern area of the block to date. The main exploration targets are sands of the Isalo formation. There are proven heavy oil accumulations in the Isalo formation in Central Madagascar such as Bemolanga and Tsimiroro, indicating good reservoir conditions.
An environmental impact assessment (EIA) has been submitted to the Malagasy authorities in preparation for exploration drilling on Block 1101 during 2011. As part of the work commitments associated with the current exploration phase, the partners have carried out interpretation work on the existing 200 km seismic data set acquired in 2008, field mapping, geochemical surveys and analysis.
| Working interest | 30% |
|---|---|
| Operator | Africa Oil |
| Gross prospective resources | PRODUCTION 964.0 mmboe* |
| Work programme | Seismic acquisition |
EXPLORATION
* Source: Gaffney Cliene.
Blocks 2, 6, 7 and 8 are located in the Ogaden Basin, onshore south west Ethiopia. Blocks 2 and 6 are part of the same production sharing contract which encompasses a combined area of 24,420 km2 . Blocks 7 and 8 are part of a separate PSC covering an overall area of 23,162 km2 .
Exploration in the Ethiopia area began in the 1970s with Tenneco discovering the Calub and Hilal gas fields approximately 200 kilometers to the east of Block 6. Exploration continued throughout the 1980s. Three wells have been drilled within the blocks: El Kuran-1, El Kuran-2 and Bodle-1. Both of the El Kuran wells encountered hydrocarbons and oil was recovered from the Jurassic, Hamanlei formation. The main potential reservoirs in the basin are clastic sediments of the Carboniferous age Calub formation and the Triassic age Adigrat formation. In addition some permeable Jurassic carbonate rocks in the Hamanlei formation can be considered potential reservoirs. PPRA SI AL PRODUCTION CASH FLOW CASH FLOW DEVELOPMENT EXPLORATION PRODUCTION
EXPLORATION
Seismic acquisition was completed across the onshore Blocks 2,6,7 and 8 in 2010. During the current exploration period, the partners have obtained 15,000 km of airborne gravity and magnetic data, 551 km of 2D seismic data and are required to drill one exploration well. Work is ongoing to further interpret the prospectivity of the block ahead of expected drilling in 2012. DEVELOPMENT
| 75% |
|---|
| EAX* |
| PRODUCTION 463.6 mmboe** |
| Seismic acquisition |
EXPLORATION
* EAX is a wholly owned subsidiary of Afren Plc.
** Source: McDaniels.
Areas A, B and C are located in the Seychelles micro-continent covering a combined area of approximately 14,964 km2 . Areas A and B are located in mainly shallow water in the northern half of the Seychelles plateau while Area C is in shallow water to the south. The main exploration targets are the Permo-Triassic Karoo interval which comprises non-marine sands inter-bedded with shales. The Karoo formation contains both the source rock and the reservoir. Other potential reservoirs in Jurassic clastic sediments may also exist. During the period 1980 to 1981 three exploration wells were drilled, all of which encountered oil shows and confirmed the presence of a working hydrocarbon system.
The partners fulfilled early work obligations with the acquisition of 3,637 km long offset seismic in 2007, and in 2009 a further 1,271 km of 2D seismic was acquired. This new data revealed the presence of several large scale structures in all three licence areas, in addition to new basins that could also contain significant Jurassic sedimentary sections. The partners intend to acquire new seismic data in 2011 over Blocks A, B and C, ahead of planned exploration drilling in 2012. A one year licence extension has been granted to assist in the completion of this work programme.
| Tanga Block A PPRA SI AL DEVELOPMENT |
EXPLORATIO N |
|---|---|
| Working interest | 74% |
| Operator CASH FLOW FLOW |
Afren EXPLORATIO |
| PRODUCTION CASH PRODUCTION Gross prospective resources 1,387.0 mmbbls* |
PRODUCTION N |
| Work programme | Seismic |
| DEVELOPMENT | acquisition and |
| exploration | |
| drilling |
* Source: Management estimate.
The Tanga Block lies mainly offshore north east Tanzania in coastal to shallow marine waters, directly south of and adjoining Kenyan Blocks L17 and L18 in which Afren holds a 74% interest. The block is covered by 200 km of legacy 2D seismic data, and 1,200 km of good quality new 2D seismic data. The Tanga Block is well located in that it lies across a deep basin with a very thick sedimentary section that has the potential of hosting several source rock intervals and multiple reservoir/seal pairings. Petroleum plays recognised to date are Lower Cretaceous sands deposited in deltaic to shallow marine environments, Upper Cretaceous submarine fans, Eocene shelf sands and Miocene fluvial and deltaic sands. There are structures, chiefly fault blocks, particularly along the western side of the basin, which are interpreted to form viable traps. Some of these lie in shallow water and could present relatively inexpensive drilling targets. The Tanga Block is also a possible source of charge into the southern parts of the adjacent Kenya Blocks L17/L18. Oil seeps and shows encountered in previous wells drilled on the nearby Pemba Island attest to the oil potential of the block and surrounding area.
The partners plan to acquire 900 km of 2D seismic over the offshore parts of the block and possibly geochemical work and non-seismic surveying over the onshore areas of the block, after which the partners intend to proceed with the drilling of an exploration well in 2011.
The Group's overall strategy to risk management is to employ suitably skilled personnel, implement appropriate policies and procedures and maintain a balanced portfolio of assets. We have an established Risk Management System, that adheres to best practice as set out in international standard ISO 310000 and the UK government's Orange book.
4
The risks we face have evolved over the course of the year as the business has grown and external factors have impacted the environment in which we operate.
Responsibility for reviewing the system of Risk Management rests with the Audit Committee of the Board which has reviewed and approved the corporate risk matrix and the measures that are being taken to mitigate the most significant risks.
The principal risks faced by Afren during 2010 related to operational risks involving the delivery of the Ebok project and Okoro and CI-11 production targets, political risks related to the situation in Nigeria and Côte d'Ivoire and strategic risks associated with the growth of the organisation and the economic climate.
| Key risk | Detail | Assessment | how do we manage it? | |
|---|---|---|---|---|
| 01 | Field delivery risk | • Operating in environments with operational risk which can cause delays, cost overruns, and ultimately lower than expected reserves. |
• Afren Nigeria review the project delivery programme against plan and take actions and develop new courses of action based on findings on a monthly basis. • The finance function monitor costs against budgets to identify potential overruns. • Our engineers analyse results from appraisal and development wells and determine the appropriate course of action in terms of drilling programme and facility design. |
|
| 02 | Exploration risk | • Exploration activities can be capital intensive and may involve a high degree of risk. |
• Budgets are produced by an experienced drilling team and regular peer reviews to capture best practice are performed. • Risk is managed using a portfolio approach, including the use of techniques such as farm downs. • Exploration programme is approved by the Board. |
|
| 03 | Côte d'ivoire and Nigeria country risk |
• Political instability in this developing economy could result in the loss of the business. |
• Ongoing monitoring and close liaison on the ground to monitor the situation from an Afren safety and security basis. • Contingency plans in place. |
|
| 04 | Environmental / safety incidents |
• Major pollution arising from operations and/or significant loss of life due to systems or equipment failure. |
• We adopt best practice in the industry with on-site, country level and corporate level policies and procedures. • Recognised potential implications of recent Gulf of Mexico events • Contingency plans in place. |
|
| 05 | Management of growth / governance |
• Management of transition from an AIM listed to a Main Market listed company. • Ensuring the design and operation of controls is appropriate for its scale. and size. |
• The board keeps internal controls and processes under constant review and takes steps to implement appropriate changes in the organisation. • The recruitment of an experienced Group Finance Director who has taken other businesses through the growth curve. • We have remuneration and training plans in place to attract and retain key people. |
|
| 06 | Security incidents | • Operating in regions where kidnapping, piracy and community unrest are commonplace. |
• Following the recent incident in Nigeria our procedures to deal with this type of incident have been reviewed and the security arrangements at both Ebok and Okoro facilities have been upgraded. • We would anticipate that this type of incident would continue to be a risk and as a consequence our procedures are robust and under constant review. |
|
| 07 | host community action |
• Direct action by host communities that results in disruptions to operations. |
• Pro-active community engagement. • Effective community development and employment programmes |
|
| 08 | Unfulfilled PSC work obligations |
• Loss of production interest or exploration licence due to incomplete fulfilment of PSC obligations. |
• The operations, finance and legal functions jointly monitor compliance with licence obligations. • Maintenance of good open working relationships with local governments in the countries of operation. |
|
| 09 | Oil prices | • Oil prices have fluctuated significantly over the past three years and given the current environment are expected to continue to fluctuate in the short term. |
• The policy of the group is to protect its minimum cash flow requirements in the context of a sustained downturn in oil prices. • The group strategy to manage oil price risk is to hedge between 20-30% of the production curve by using financial instruments which allow the group to protect the downside risk. |
|
| 10 | Loss of key employees |
• Loss of knowledge and skills to the group in particular in countries of operation. |
• Succession planning is considered on a group wide basis, taking into account the development of the executive and senior management. • Remuneration policies are designed to incentivise, motivate and retain key employees. |
|
| 11 | Taxation and other legislation changes |
• Operating in developing countries has additional risk of significant changes in taxation legislation on oil field profits or other legislation changes. |
• Our financial and legal teams monitor current legislation and proposed changes and incorporate these into our working practices. • Maintenance of good open working relationships with local authorities in the countries of operation. |
|
| 12 | Treasury management |
• The availability of financing to maintain the ongoing operations of the business is key. |
• In 2011, the group issued a bond for \$500 million, expects strong operating cashflow in 2011, has secured financing for Ebok field development and will continue to monitor its cash requirements carefully against the production curve and cash requirements. |
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Below: Afren are focused on sustainable education: Primary school students in Eastern Obolo.
Corporate Social Responsibility (CSR) continues to be a critical focus area. We are committed to ensuring that Afren is recognised as a responsible organisation with high standards of CSR performance.
Maintaining these standards will ensure that the business grows successfully for the benefit of all stakeholders, whose concerns and aspirations we must also understand if we are to develop long-standing, successful relationships. We are already applying this approach to existing projects in Nigeria and Côte d'Ivoire and will do so for all new activities.
We continue to evaluate our CSR policies and procedures against international best practice guided by both the UN Global Compact and Equator Principles. Based on this framework, our CSR report covers five key areas:
We place value on our relationship with the environment and strive constantly to interact respectfully with it by being mindful of its fragility.
We insist on high standards of performance to ensure our workforce remains safe and healthy.
We appreciate the opportunities to be gained from cooperation with local communities, striving to make connections and foster relationships with all of our stakeholders.
We reward performance and offer a progressive working environment and development opportunities for our employees. We will not tolerate discrimination of any sort.
We conduct ourselves with integrity to ensure that every aspect of our business is operating to highest standards of business ethics.
Our strategy for 2011 is to consolidate existing systems for managing EHSS, community and security issues. Having experienced major changes during 2010, we need to embed the lessons learned within our EHSS practices. 2011 has already seen start up of the Ebok field development, OML26 assets are being transferred to First Hydrocarbon Nigeria and activity will pick up in East Africa. At the end of 2010 we also conducted a second round of independent audits through the British Safety Council whose recommendations will form the basis of our 2011 action plans. Focus areas will include improving our monitoring and reporting of environmental emissions, closer working relations with our primary contractors, more effective execution of community development programmes, and addressing the lessons from the Okoro security incident of November 2010.
We have defined how we manage EHSS, ethical and HR issues through a set of corporate policies, management systems and supporting procedures and guidelines – available at www.afren.com
4
Responsible environmental management is a crucial component of our CSR approach and we endeavour to operate to the highest international standards, regardless of location. Our policy requires, as a minimum, that we comply with local legislation and that we identify all risks to the environment and implement processes to mitigate potential impacts.
In 2010, we began to set operational targets for spills and excursions above permitted discharge limits and can confirm that we had no reports of either events for any of our operations.
Shahid Ullah Chief Operating Officer
During 2010 we reviewed our environmental management practices. In particular we conducted a GAP analysis between our current processes and Equator Principles requirements – the benchmark used by financial institutions for determining and managing social and environmental risk in project financing. We are consequently now providing further guidance in greenhouse gas monitoring and reporting, biodiversity, waste management, and standards for conducting environmental and social impact assessments.
Implementing our environmental procedures will require further training for both Afren and contractor personnel. We are committed to having competent personnel at all levels of the organisation and believe this is the only sure means of achieving the high standards of environmental performance necessary.
The true measure of our success will be through the monitoring and reporting of key environmental performance indicators. We have begun to capture this information and will use this in the following years to drive performance improvements.
Specific environmental KPIs include:
To understand the risks to our operational environments it is first essential to understand the nature of the environment itself. We do this through the Environmental Impact
Assessment (EIA) process which records the environment around any proposed new development and then identifies how it might be impacted by our facilities and any hypothetical emissions. Significant impacts can then be mitigated by siting or designing the facilities appropriately. The EIA also identifies those aspects requiring ongoing monitoring throughout the life of the development.
Afren routinely carries out advance EIAs to ensure that we address potential environmental impacts. For the Ebok project we conducted baseline environmental surveys prior to starting activities and we will use this information to confirm the extent of any impacts during operations.
We also examined the Ebok project to identify those operations with the potential to cause impacts and evaluated their significance. For the most significant potential impacts we will establish an environmental monitoring programme – such as one already in place to monitor the drilling operations (see more below).
There is a rigorous review and approval process in Nigeria for environmental impact assessments and this includes a scoping workshop and public consultation. Final approval of the Ebok development EIA was received on 16 February 2010.
Towards the end of 2010 Afren began to work up the development options for Block CI-01 offshore Côte d'Ivoire. An EIA was therefore prepared and submitted to the Department of Environment for its review and approval, which was received on 26 January 2010.
Afren has environmental monitoring programmes in place for the Okoro production operation and Ebok drilling activity. This monitoring is carried out monthly by an independent environmental consultant with the results compiled in an annual report. Monthly reports are submitted to Department of Petroleum Resources and Federal Ministry of Environment.
Environmental due diligence is a key component of our acquisition process, particularly where operations are already well-established. Understanding potential impacts and, more importantly, knowing about any that may already have occurred are essential for planning and managing environmental issues.
For the First Hydrocarbon Nigeria (FHN) acquisition of the onshore OML 26 asset we conducted an exhaustive, multistage environmental due diligence survey. This began with an initial desktop study and aerial survey before moving on to visual inspection in and around the facilities, followed by detailed testing of soils and water (including groundwater).
From this we were able to build up a picture of contaminated sites requiring restoration prior to FHN taking over responsibility for the assets.
The acquisition of Black Marlin assets represents our first move into East Africa, where the environment is significantly different in some areas from those in which we operate in Africa's west. During the acquisition process significant emphasis was placed on the evaluation of Black Marlin's EHSS management system. Following deal completion, an EHSS implementation audit was conducted in October on the seismic operation in Ethiopia involving Blocks 7 and 8.
A number of recommendations were made following the audit on how to improve environmental performance on the seismic crews and around the base camp. These recommendations will also be followed through to the seismic programme planned for the adjacent Kenyan Blocks 1 and 2.
Oil spill is a key risk for any company operating in the E&P sector. At Afren we fully recognise this and have contingency plans in place. Although the majority of oil spills have historically occurred from shipping operations, the BP Macondo well blowout in the Gulf of Mexico highlighted that the upstream business is not immune. Following this incident we took immediate steps to review both our drilling practices and spill preparedness.
In line with best practice, Afren operates a tiered response to potential spills:
Tier 1 response is for small operational spills using equipment at site to contain or disperse any spill. For Tier 2 spills, Afren has contracts in place for the provision of additional resources. These include an aerial dispersant spraying capability contracted through the Oil Spill Response Limited industry consortium, of which Afren is an associate member. In the event of a major Tier 3 incident, Afren would call on the further support of OSRL personnel and resources based in Southampton.
We recognise, however, that our response to an oil spill cannot rely solely on having equipment available. To be effective we also require well-trained personnel who understand how spills behave and the options available to combat them. We have therefore conducted intensive training for our Incident Management Teams in both Lagos and Abidjan. This was delivered by OSRL to participants not only from Afren, but also our partners, key contractors and the local government agencies with responsibility for spill response. We believe that by holding joint training we will achieve a more effective and integrated response.
We naturally place equal emphasis on avoiding spills in the first place and were successful in 2010 in achieving zero operational oil spills.
With people our most valuable resource, we must ensure that they remain healthy and safe in the workplace. This extends beyond Afren employees to the wider workforce – including key contractors and representatives from our host communities who may be actively participating in our operations.
Above: Safety inspection at the Lion Gas Plant.
The primary focus of our health and safety programme is the identification, assessment and mitigation of risks. We believe that by assessing risks at all levels of operations we can eliminate events that may lead to injury or other losses. Our management system consequently incorporates a suite of risk assessment techniques ranging from hands-on job safety analysis, to design risk assessments such as HAZIDs and HAZOPs. We also require that our contractors adopt the same principles, rigorously checking to ensure this is the case – both before contracts are signed and again once work starts. By developing close relationships with our key contractors we have aligned health and safety programmes so that we share lessons learned and participate jointly in activities such as training and audits. This is a critical area that will be increasingly important in 2011 as Ebok comes on stream and operatorship of OML 26 is transferred to FHN.
Operational safety cases
Afren's EHSS management system requires safety cases to be prepared for all new facilities. We have an established safety case for the Okoro project that was prepared and is maintained by the contractor BAB. For the Ebok project we have been working closely with Mercator, our operations and maintenance contractor, to prepare a similar document covering the MOPU, West Fault Block platform and FSO. The Ebok safety case pulls together the safety studies that were carried out to ensure safe processes, and the safety management system that will be used to operate and maintain the facilities. The document has been reviewed and approved by the Nigerian Department of Petroleum Resources.
In 2010, our safety performance fell short of our target of achieving a Total Recordable Incident Rate (TRIR) below the OGP average for Africa. When analysed, the data showed clearly that Ebok project construction activities were the major contributor to the increase in recordable incidents. Whilst the majority of these were straightforward medical cases – such as minor eye treatments as a result of wind-blown rust particles during refurbishment of the MOPU – we believe that all incidents are avoidable. As a direct consequence we will be strengthening health and safety supervision on all future construction projects.
As we are committed to continuous improvement we have teamed-up with the British Safety Council to introduce a structured and independent approach to reviewing performance using its 5 Star Audit system.
The BSC 5 Star Audit is an objective, quantifiable measure of health and safety performance based on rating performance in five key areas:
The system is broken into 58 elements across these five main areas, a scoring protocol for each element reflecting the risks. Points are awarded for each risk depending upon the level of compliance.
The star rating system is based on percentage compliance across all elements and provides a means for benchmarking against industry best practice and for setting improvement targets year on year. We aim to achieve 5 Stars for our operations in Côte d'Ivoire and Nigeria, representing 92% compliance with best practice as indicated by the 5 Star table:
During 2009 the first of these audits was conducted for our Nigeria and Côte d'Ivoire operations. The audits were repeated during 2010 and the results demonstrate significant improvements in the development and implementation of our safety management system. Both Côte d'Ivoire and Nigeria showed significant improvements in performance achieving a 3 Star standard.
Compliance with best practice as indicated by the 5 Star table.
On the morning of 8th November Afren suffered an attack by militants on the Okoro field. During the incident the militants boarded the Okoro wellhead platform and gained access to the High Island VII drilling rig operated by Transocean and the AT101 support vessel. In the course of the attack a number of our contractors personnel were injured and seven were taken hostage. The hostages were kept by the militants for 10 days before being released unharmed.
As a consequence of this incident we have carried out an extensive independent review of our security management system and the arrangements that we have in place to protect our people and assets. We have upgraded the security arrangements at both Okoro and Ebok and will continue to place significant emphasis on managing this aspect of our business.
We are actively considering participation in the Voluntary Principles on Security and Human Rights initiative as a means of underpinning our commitment to uphold lawful means of securing our operations.
In 2010, Afren focused on projects in education, health and employment. We chose these sectors because we believe in a holistic approach to improving quality of life for our stakeholders. This is why Afren not only embarks on social initiatives that directly affect the host communities of our assets, but also supports projects with a national or international dimension for social development. Above all we want to ensure that success for Afren is also success for Africa.
"Moving forward, we will focus further on social initiatives as a means to ensure sustainability."
Above: SOS youth facility at the Isolo village – Lagos, Nigeria.
NGO: Non Government Organisation CLO: Community Liason Officer
Afren strives to ensure that our social initiatives not only secure a social licence to operate, but encourage real and sustainable change that is community driven. Our innovative approach complies with regional legislation, international standards and the local situation, and ensures full consultation with stakeholders.
We endeavour to demonstrate sustainable development in action through local content, human capital development, economic empowerment, and capacity building programs. We also aim to contribute meaningfully to improve the living standards of our host communities. Moving forward, we will focus further on social initiatives as a means to ensure sustainability.
In response to the challenges faced by many international students securing work experience, African students studying at institutions in the United States and Great Britain in 2010 were given the opportunity to work alongside industry professionals at Afren.
Students were identified from nine elite petroleum engineering departments and selected on academic achievement, community involvement and work experience. Ten offers were then made for positions at Afren Resources USA working in reservoir engineering, geosciences, drilling and facilities. Interns also attended field trips to local ship yards, service companies and petroleum industry events. In addition, students were recruited for positions in other parts of the Group totalling over 20 altogether.
This programme emanated from Afren's conscious decision to invest in the future of the indigenous oil and gas industry by seeking out students who could one day be its leaders, demonstrating a drive for success alongside a deep commitment to the future
Below: Primary school students in Eastern Obolo.
Students sponsored to date from the Eastern Obolo secondary school.
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Afren pursues its goal of a sustainable, transparent and ethical social development programme by ensuring all projects meet with standardised expectations and goals which are established at Board level. These goals are cascaded down to projects and progress on implementation is reported back to Board level. This method ensures accountability internally, as well as, most importantly, to our stakeholders.
During the year Afren placed substantial focus on education, acknowledging that, as a young company with an emphasis on growth and the future, it is education's natural partner. Investing in the future of countries where we operate by encouraging education at all levels was a major focus and will gain even greater prominence in coming years.
of their home country.
Key projects during the year included:
Nigeria
• Classroom and dormitories refurbishment at Bingerville orphanage.
4
It was important that these training and information opportunities be made available to all levels of the community; not just business people, current Oil and Gas professionals and job seekers, but also students, and the larger community as a whole. Local trainers were selected and provided with the background and training materials to then, in turn, provide information to their community as a whole. It was important that this initiative was for Ghanaians delivered by Ghanaians. It was hoped that being from the community would better equip the trainers to communicate and teach the community. In 2010, 70 final year students from Kwame Nkrumah University of Science and Technology (KNUST) in Kumasi attended Oil and Gas Fundamentals classes. The same class was administered to 35 local business people in the Takoradi region, and 25 local key opinion leaders from the head of departments of the Takoradi and Sekondi region. The last Oil and Gas Fundamentals course of the year was administered in December 2010 to 40 job seekers of the Takoradi region. In addition to providing this training, 15 additional trainers were identified and trained in hopes of expanding the program in the future. All training sessions were received with enthusiasm and appreciation.
Afren recognises the profound effect poor health can have on the economic and social wellbeing of a community, family and individual. Our focus is always to promote sustainable development and indigenous capacity building. By supporting health initiatives, Afren is better able to help host communities and countries to help themselves.
We also recognise the wealth of knowledge of many aid organisations in the health and healthcare sector. 2010 therefore saw Afren partnering with non-governmental and international organisations to improve health in Nigeria.
Looking to the future, Afren will be expanding these initiatives and practices to include other host countries. We will also be incorporating capacity building into our initiative, again to ensure that indigenous stakeholders maintain a real involvement in their own health development.
Key projects during the year included:
• Free cataract surgery for 104 people in Akwa Ibom state conducted by the Tulsi Chanrai Foundation.
• The first year of a multi-year partnership with Faith Regen/Global One to address the United Nations Millennium Development Goal 5 – improved maternal health – in Nigeria.
Afren firmly believes that indigenous populations should have a strong presence in their own industry. That is why we not only provide opportunities for employment, but also facilitate indigenous capacity building through training and economic development opportunities. In coming years, Afren will continue to increase our focus in these areas. We believe that training, education and opportunity represent the invaluable gift of self sufficiency.
Key projects during the year included:
Featured left: Patients at the Calabar Hospital.
A report released by the Nigerian Federal Ministry of Health's national programme for prevention of blindness indicated that the blindness prevalence in Nigeria is 4.2%.
Nigeria's partnership with the Tulsi Chanrai Foundation has been actively working towards addressing blindness in Nigeria – a major factor in inhibiting a person's ability to work and care for their family.
Afren funded TCF to conduct 923 free eye screenings at three screening camps across Akwa Ibom in Uyo, Eastern Obolo and Mbo. These resulted in 104 patients being selected to undergo Afren sponsored eye operations to correct conditions that were causing blindness. The support also included transportation to and from the base hospitals, full ophthalmic and medical examination prior to and following surgery by qualified surgeons using the latest techniques.
The Afren Nigeria Community Affairs team that visited the Calabar Hospital for patients' 30 day review were overwhelmed by their gratitude and the positive impact that the operations have made to their lives.
free eye screenings at three screening camps across Akwa Ibom in Uyo, Eastern Obolo and Mbo.
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It is critical that Afren fosters the best environment in which our employees can develop and grow, both personally and professionally. We aim to be an attractive employer to an increasingly international workforce and to find ways to engage and retain our employees – our most valuable resource.
Top: Interns from our host countries gain work experience at Afren`s Houston office.
Above: Staff at our offices in Lagos and Abidjan.
8 new graduates employed through our graduate development programme.
Afren's people strategy is geared towards providing measurable value for the business by ensuring that we have a workforce able to deliver against challenging objectives to the highest industry standards. Our key objective remains recruiting and developing a team of highly talented and skilled individuals in all areas of the business with particular focus on developing national staff in operational locations. We are particularly proud of the fact that 98% of our permanent employees in Nigeria and 99% of our permanent employees in Côte d'Ivoire are local nationals.
Effective and sensitive change management also forms part of the Human Resources strategy – as seen in 2010 during the acquisition of Black Marlin Energy and the set up of a new presence in Kenya.
We also seek to improve the working environment by ensuring fairness and consistency of remuneration practices, as well as policies and procedures. During 2010 we completed a major remuneration policy review which included benchmarking and the introduction of a new job grading system, bonus scheme and updated equity plan rules for roll out in 2011.
Our overall aim is to achieve a peoplecentred culture which enhances the conditions necessary for technical and business excellence.
During 2010 we saw significant growth with over 53 new employees joining the company – an increase of over 30%. Our staff turnover was very low at 2.2% which indicates a high level of satisfaction with the working environment and conditions.
We have a very active and structured intern programme to enable talented graduates to gain valuable experience and mentoring in Houston, London and Lagos. In 2010, we accommodated over 20 interns across the Group and employed 8 new graduates in our graduate development programme.
In 2010 we also invested over US\$400k in training and development programmes, as well as carrying out a major skills audit and training initiative for all technical employees in Côte d'Ivoire. We also introduced an online modular course 'Fundamentals of the Oil and Gas Business' as part of a structured induction programme.
US\$400k
invested in training and development programmes.
99%
of our permanent employees in Nigeria and Côte d'Ivoire are local nationals.
Having rolled out our Code of Business Conduct during 2009, our drive in 2010 was to embed its principles in all our business activities to ensure that we are free from accusations of unfair or illegal practices.
Right: The Code of Business Conduct features in our Employee Handbook which all new staff are required to read, as well as confirming that they understand it and will
abide by its requirements.
The Code of Business Conduct features in our Employee Handbook which all new staff are required to read, as well as confirming that they understand it and will abide by its requirements. The handbook was one of the first documents delivered to personnel joining us from Black Marlin.
The whistle blowing policy and procedure that we introduced in 2009 to alert us to potential malpractices remains in place. In addition the company has established an independent external reporting service available for use when circumstances necessitate a different approach to reporting. The service has been set up by Afren, working in partnerhsip with Safecall, who provide a professional, independent and confidential means of reporting concerns.
With offices in both the UK and USA we are conscious that we not only need to comply with the requirements of the US Foreign Corrupt Practices Act and the UK Bribery Act, but that we also need to demonstrate our compliance. We have therefore developed compliance procedures which will be cascaded through the organisation during the course of 2011, once the UK authorities have finalised their guidance.
We will continue to remain vigilant in this important area of corporate governance.
Afren's ultimate objective is to deliver sustainable long term growth in shareholder returns. In 2010, Afren rose 44 places to 61st position in the FTSE 250 index following inclusion in March 2010 and achieved outperformance versus our established industry peer group average and relevant market indices.
Petroceltic, ROC Oil Company, Serica Energy, Soco International, Sterling Energy, Tullow Oil, Vaalco and Stratic Energy 2. Average of the constituents of Ernst & Young's Oil & Gas Eye Index
Afren ranking in the FTSE 250 by Market Cap
As of 31 March 2010 105 As of 31 December 2010 61 Source: Bloomberg
Share price performance
31 December 2009 to 31 December 2010
Above: Darra Comyn – Group Finance Director.
In January 2011 Afren became the first UK exploration and production Company to go to the bond market and raise a substantial amount of capital. This bond issue brings a significant change in the capital structure of Afren, the proceeds of the bond allowing the Company to repay its shorter term facilities. Taken with the positive cashflow from existing operations and the reserve base lending facility for the development of the Ebok field there are considerable financial resources at the Company's disposal.
Revenue for 2010 was US\$319.4 million, a reduction of 5% from 2009. The decrease in revenue arises from the reduced economic interest on the Okoro field offset largely by the effect of higher oil prices. Economic interest production for the year fell to 14,333 boepd from 22,064 boepd in 2009. The fall in economic interest production also arises mainly as a result of reaching payback on the Okoro field which, as expected, saw our interest reduced from 95% to 50% in mid 2010.
The Company realised in 2010 an average oil price of US\$79.7/bbl and an average gas price of US\$5.7/mcf (2009: US\$59.3/bbl and US\$5.1/mcf). The average price for Brent in the period was US\$79.5/bbl.
Gross profit for the year was US\$129.0 million, an increase of 22% on the prior year (2009: US\$105.8 million). The DD&A charge for oil and gas assets in 2010 was US\$90.5 million, a reduction of 41% on the prior year (2009: US\$152.2 million). The reduction was largely due to our lower working interest production. The reduction in crude oil stock at the year end resulted in a charge for stock adjustment of US\$9.5 million, compared with a credit of US\$12.8 million in 2009.
Profit after tax on continuing activities for the year ended 31 December 2010 was US\$45.9 million (2009: loss US\$16.8 million). Normalised profit after tax, which excludes the effect of unrealised hedge movements and share related charges, was US\$63.8 million, see note 7 to the financial statements for a full reconciliation of this figure (2009: US\$50.7 million). This is the first full year profit after tax in the history of Afren and an important milestone for the Company.
Impairment charge on oil and gas assets was US\$1.6 million (2009: credit US\$0.9 million) reflecting residual costs on the La Noumbi licence in Congo arising from the unsucessful Tie-Tie well drilled in 2009. The low level of impairment
reflects the ongoing success of the Group's exploration and appraisal programme.
Finance costs for 2010 were US\$11.3 million (2009: US\$37.0 million). The costs in 2010 were reduced because the Group capitalised US\$13.6 million of charges as part of the Ebok project financing (2009: US\$1.8 million). Overall charges were also reduced because of the lower overall debt in the period, reflecting the paying down of the debt raised for the development of the Okoro field and the acquisition of the assets in Côte d'Ivoire.
During the year professional fees of US\$3.9 million were expensed in connection with the acquisition of Black Marlin Energy Holdings Limited. Following changes to IFRS3, which took effect during the year, professional fees incurred in respect of acquisitions can no longer be capitalised.
During the year we recognised a loss from derivative financial instruments of US\$8.9 million (2009: US\$33.6 million) relating to crude oil hedging contracts. This reflects a small realised loss of US\$2.4 million (2009: US\$11.4 million gain) as the oil price realised averaged just above the hedged price during the year. There was a further mark to market loss of US\$6.5 million (2009: loss of US\$45 million) on the unrealised positions due to further strengthening in the oil price from around US\$80 per barrel at the start of the year to over US\$90 per barrel at year end.
The income tax charge for the year is US\$32.9 million (2009: US\$17.3 million). The increase reflects the increased profitability of the Company in 2010. Of this, US\$0.9 million has been paid locally in Nigeria in respect of production on Okoro. The balance of current tax will be paid in 2011 with the deferred tax liability spread over the life of the field.
In addition, the Company pays other taxes in the form of royalties, withholding taxes, and non recoverable VAT locally in Africa. In 2010 these amounted to US\$83.2 million (2009: US\$72.5 million) – as a percentage of revenue this represents 26%.
Net cash generated from operating activities in 2010 was US\$209.3 million (2009: US\$278.3 million), and this cash has been used primarily to fund the Company's exploration and appraisal activities.
In March 2010, the Group secured a reserve based lending facility of up to US\$450 million to fund ongoing development of the Ebok, Okwok and OML 115 area. To date we have commitments on this facility of US\$250 million of which US\$107 million had been drawn at 31 December 2010.
In November we refinanced the Okoro facility with a new reserve based lending facility of up to US\$80 million to fund the drilling of two infill wells on the field and repay the original facility used to develop the Okoro field.
Gross debt as at 31 December 2010 was US\$284.7 million (2009: US\$281.1 million), largely comprising US\$107 million and US\$71 million in respect of Ebok and Côte d'Ivoire respectively.
Loan repayments in the year were US\$111.0 million reflecting repayment in full of the Okoro facility and the facilities used to finance the Côte d'Ivoire acquisition and periodic payments due under other facilities. Cash at bank at 31 December 2010 was US\$140.2 million, resulting in net debt of US\$127.5 million (2009: net cash US\$54.2 million).
The Company's investment in appraisal and exploration activities has continued during 2010, with expenditure of US\$74.3 million (2009: US\$67.3 million). The main areas of expenditure were on Okwok (US\$34.8 million), electromagnetic survey and seismic reprocessing on OPL310 (US\$13.5 million), the acquisition of OML115 (US\$11.2 million) and expenditure, largely seismic, on the newly acquired Black Marlin exploration assets (US\$4.0 million).
Development expenditure was US\$362.8 million, comprising US\$329.0 million on the Ebok field and US\$33.8 million on the Okoro infill programme.
There has been minimal write off of unsuccessful exploration costs (2010: US\$1.6 million, 2009: credit US\$0.9 million).
In October 2010, the Company completed its acquisition of the share capital of Black Marlin Energy Holdings Limited (Black Marlin). Total consideration for the acquisition was US\$140.3 million excluding costs and 76,776,096 ordinary shares in the capital of the Company were issued, allotted and credited as fully paid to the shareholders of Black Marlin as consideration. Subsequent to the acquisition, the Black Marlin Dubai office has been reduced in size and will close in the first half of 2011, with a cost of US\$0.9 million including redundancy costs. In accordance with IFRS 3 Revised, professional fees incurred in respect of the acquisition (US\$3.9 million) are not capitalised.
All staff are eligible to participate in the company bonus scheme and the Company paid an average cash bonus to employees relating to 2010 of 28% of gross salary. During the year 4,425,000 new options were issued to personnel recruited or upon a significant promotion. The average strike price of the options was 107p (2009: 33,315,000 at an average strike price of 65p) representing in each case the market level at the time of issue. The options vest over three years if a target share price of 40% above the strike price has been achieved. In addition, an award of 4,895,609 shares was made under Afren's Performance Share Plan (PSP) to all eligible staff excluding directors (2009: 15,552,824, of which 3,865,953 were awarded to the directors). The number of shares awarded varied dependent on seniority and the amount that vest after three years depends on total shareholder return when compared with our peers.
The Company has operating and capital commitments as at 31 December 2010 of US\$482.6 million (2009: US\$258.9 million), largely in respect of the ongoing development of Ebok, and the infill well programme on Okoro and operations on the Okoro field.
In 2011 the Group will recognise a liability as a finance lease in respect of the arrangements with Mercator Offshore Nigeria (Pte) Limited for the production facilities on the Ebok field. This will result in the recognition of a finance lease liability of approximately US\$163.0 million to be settled in monthly payments of US\$2.4 million. These amounts are included in the capital commitments figure stated above.
In January 2011, the Company completed a Bond issue, initially raising US\$450 million with a subsequent tap issue on 16 February raising an additional US\$50 million. The coupon on the bonds is 11.5% and they are listed on the Luxembourg Stock Exchange.
The bonds are secured with a first-ranking security interest over substantially all of the Company's assets related to the Okoro field, and a second-ranking security interest over substantially all of the Company's assets related to the Ebok field.
The Company used part of the funds to repay borrowings amounting to US\$169 million (net of issue costs) and accrued interest of US\$2.4 million of its existing facilities from the Okoro reserve based lending facility, the facilities used to acquire the Côte d'Ivoire assets and other outstanding facilities. The remaining funds raised by the bonds will be used to fund further development of the Group's assets and for acquisitions/other corporate purposes.
In the context of volatile oil prices and with the imminent first oil at Ebok, the Company reviewed its hedging arrangements. The Company previously had taken hedging positions associated with its operations in Okoro and Côte d'Ivoire. These arrangements were synthetic puts which allowed the Company to protect itself from the downside movements in prices while also benefiting from most of the upside. In early 2011 the Company purchased a number of put options. These options allow the Company to sell approximately 3 million barrels in the period to 31 December 2012 at a price of US\$80/bbl. The average cost of the hedge is US\$4/bbl giving effective protection to the Company at a price of US\$76/bbl. The new instruments have been classified as cash flow hedges. Each period the portion of the gains and losses on the hedging instrument that is determined to be an effective hedge will be taken to equity and the ineffective portion, as well as any change in time value, will be recognised in the income statement.
Existing hedges covering 248,000 barrels at a price of US\$60/bbl and 339,000 barrels at a price of US\$81/bbl will expire during 2011. These instruments are not designated as cashflow hedges and gains or losses are taken directly to the income statement in the period.
The policy of the Company is to protect its minimum cashflow requirement in the context of a sustained downturn in oil prices. As such the maximum amount of our working interest we would seek to protect with these arrangements is between 20-30% of estimated production for a rolling period of 24 months forward.
In 2011 the Company will carry out an extensive programme of exploration and development across its assets. With substantial increased cashflow from operations combined with its debt facilities and cash resources, the Company is well positioned to fund its next stage of growth and deliver value to shareholders.
Mr Imomoh, a founder of Afren, was previously Managing Director and Executive Chairman of Afren Energy Resources Limited. He successfully led the growth of Afren's Nigerian asset base, established a number of successful indigenous partnerships and achieved the First Oil milestone at the Okoro Setu project.
Prior to establishing Afren's Nigerian subsidiary, Mr Imomoh served as Deputy Managing Director of Shell Petroleum Development Company (Nigeria), one of Shell Group's largest operating companies. He is also a member of the Society of Petroleum Engineers and has served on its board as Regional Director for Africa.
Dr Shahenshah is a founder of Afren and has over 20 years' experience in oil and gas finance. His international career began with Credit Suisse First Boston and has included senior positions in the oil and gas finance groups of the International Finance Corporation (the private sector arm of the World Bank), and the investment banking divisions of Dresdner Kleinwort Wasserstein and Mediocredito Centrale.
Dr Shahenshah has been actively involved in the African oil and gas sector for more than 15 years, working with companies including Shell, Chevron, Total, Eni S.p.A and the Nigerian National Petroleum Corporation. He holds a PhD from the University of Pennsylvania, a Master's Degree from Columbia University and a Bachelor's Degree from Brown University.
Mr Ullah has held senior management positions at Western Atlas and Baker Hughes, where he was responsible for managing petroleum interests and assets. In particular, he brings extensive technical and commercial knowledge of the African petroleum industry to Afren. Mr Ullah holds a degree in Petroleum Engineering from the University of Texas and received executive development training at Oxford University and the London Business School. He is a member of the Engineering Advisory Board at the University of Texas.
Mr Comyn was previously the Group Finance Director for ITE Group plc and Expomedia Group Plc (both international groups focused on emerging markets); and in the oil industry with Chevron Oil UK and Dragon Oil where he was Group Financial Controller and Company Secretary.
Mr Comyn is a Chartered Accountant with a degree in Economics from Trinity College, University of Dublin.
Mr Bingham is a Non-executive Director of Afren. With over 40 years' experience in international financial markets, Mr Bingham began his career at Barclays Bank group. He subsequently held a succession of Directorships, first in London at branch level, then in Barclays merchant banking division and BZW – now known as Barclays Capital – where he set up the credit risk management team, all before becoming Head of Banking at BZW and serving as a member of the central Barclays Group Credit Committee.
John St. John was appointed to the Board of Afren in November 2006. He was formerly Global Head of Equity Capital Markets at Dresdner Kleinwort, Commerzbank and Lehman Brothers and European Head of Equity Capital Markets at Citigroup, formerly Salomon Brothers. He was also until recently the Chairman of Equity Capital Markets at Nomura International plc. John is a founding Partner of STJ Advisers. He has acted as an adviser on over \$100 billion of equity and equity-linked issuance in all major markets worldwide.
Ennio Sganzerla, a senior oil industry practitioner with a wealth of African upstream experience, has been an adviser to the Afren Board since November 2006. He was previously Senior Vice President (E&P) at ENI, having joined the group in 1971. From 1997, he was responsible for ENI's largest business unit encompassing the North Sea, America, Australasia and Russia, with production in excess of 500,000 boepd. Over the course of his wide-ranging career at ENI, he was instrumental in establishing and building ENI's presence in Congo, and played an active role in increasing ENI's position in Nigeria and Gabon as Regional VP for Africa.
Mr Sganzerla was also active in leading the group's M&A activities, including the acquisition of Lasmo plc and British Borneo.
A qualified Chartered Accountant, Mr Hayward has held a number of senior Equity Capital market positions in London. As Head of Oil and Gas Equity Capital Markets at Canaccord Adams he led a range of Initial Public Offerings (IPOs), including Afren's IPO, before moving on to his post as Managing Director and Head of Corporate Broking at Jefferies International Limited, where he was responsible for all international equity and equity linked transactions together with corporate broking and Nomad responsibilities.
With over 25 years in the industry, Mr Wright has extensive international geosciences experience and has served in both development and exploration geology roles. He has held senior positions with Randall & Dewey, Baker Hughes, Qatar Petroleum, Conoco (UK) and Anadrill Schlumberger. Mr Wright received a BSc (Hons) from the City of London Polytechnic and is a Certified Petroleum Geologist (CPG) with the AAPG, a fellow with the Geological Society, the SPE and PESGB.
Mr Virani joined the Company in 2005 following a career in the City of London in Corporate Finance and Mergers & Acquisitions. Mr Virani has played a key role in the Company's financing, in diversifying the shareholder base and to the overall growth of the Company's portfolio of assets.
Mr Virani is an East African national and a member of the JSE Africa Board Advisory Committee. He is a Fellow of the Securities Institute, and has a Master of Finance & Investment (with Distinction) and a Master of Philosophy in Emerging Market Finance.
Mr Ravi Sharma Director of Production and Development
Mr Adebayo Ayorinde Managing Director, Afren Nigeria
Mr Jack McFarland Director of Operations
Mr Ron Parenti Corporate Drilling Manager
Mr Patrick Ogunjimi Deputy Director of Operations
Mr Julien Forquet Production Manager, Côte d'ivoire
Mr Shahin El-Sharif Engineering and Planning Manager
Mr Ricardo Ramirez Corporate Geosciences Manager
Mr George Zeito Reservoir Engineering Manager
Mr Constantin Paul vihristencu Corporate Geoscience Technology Manager
Mr Kelechi Ojukwu OML 26 Asset Manager
Mr Taiwo Olushina Ebok Asset Manager
Mr Okon Akpan Okoro Asset Manager
Mr Yann Cherruau Country Manager, Côte d'ivoire
Dr Niall J McCormack Exploration Director
Mr Barrington Rogers COO, Afren East African Exploration
Mr Sharma leads Afren's production and development function. He has over 20 years' international experience in reservoir engineering, management and sub-surface development and has held senior positions at BHP Billiton, Occidental, BP and Baker Hughes. Mr Sharma holds an MSc in Mechanical Engineering from the University of Alberta, Canada.
Mr Ayorinde is Managing Director of Afren's Nigerian office. He has over 20 years' experience in the oil and gas industry including production and maintenance operations, oil and gas project economics, facilities engineering, drilling and completions engineering and general management. Prior to joining Afren he held senior positions with Allied Energy Resources, Moni Pulo and Ashland Oil. Mr Ayorinde holds a BSc (Hons) in Chemical Engineering from Obafemi Awolowo University in Nigeria and is a member of SPE.
Mr McFarland is Director of Operations and a registered petroleum engineer with over 30 years' experience in the oil and gas industry. He has extensive experience in reservoir, operations and production engineering coupled with a successful track record in oil and gas asset evaluations and acquisitions. Prior to joining Afren he was a Director at Valiant International Petroleum and held senior management positions at Panther Resource Corporation and Ocean Côte d'Ivoire amongst others.
Mr Parenti is Corporate Drilling Manager and has a wealth of international drilling management experience, most recently with Addax Petroleum where he worked extensively in Nigeria, Cameroon, Gabon and Kurdistan. He has over 25 years' experience in the oil and gas industry and holds a BSc in Petroleum Engineering; a BSc in Finance; an MBA in Management and an MSc in Environmental Science.
Mr Ogunjimi is Deputy Director of Operations and has over 20 years' experience in the oil and gas industry. He has extensive experience in exploration, field development, planning and implementation, production operations management, oil and gas asset valuation and project finance activities. Prior to joining Afren he worked in various senior technical and commercial roles with Western Atlas, Baker Hughes and Randall & Dewey. Mr Ogunjimi holds a BSc (Hons) in Chemical Engineering from University of Lagos and an MEng in Petroleum Engineering from Herriot-Watt University.
Mr Folquet is Production Manager for Afren's operations in Côte d'Ivoire. He has 20 years' experience in process and production operations including working with the SIR refinery, Ocean Energy and Devon CI. He has also worked internationally in Egypt. Mr Folquet has an engineering degree with honours from Ecole Nationale Superieure des Ingenieurs d'Abidjan (ENSIA) and a post graduate qualification in Petroleum Engineering from Ecole Nationale Superieure du Petrole et des Moteurs (ENSPM) in France.
Mr El-Sharif is Engineering and Planning Manager and has over 13 years' technical experience in all phases of the production life cycle. Prior to joining Afren he worked for Occidental in engineering planning management and most recently with BHP Billiton as a Subsurface Supervisor. He holds a BSc in Geological Engineering from the University of Arizona and an MBA from Pepperdine University, Malibu.
Mr Ramirez is Corporate Geosciences Manager for Afren's producing and development assets. He has nearly 30 years' experience in the upstream geosciences having worked for Exxon Corporation; PDVSA in Venezuela, Englehart Energy and Addax Petroleum. Mr. Ramirez holds a BSc in Geology from Duke University and an MSc in Coastal Marine Geology from the University of South Carolina.
Mr Zeito has over thirty years of industry experience, which include 10 years as a senior engineer assigned to reservoir studies and 17 years in engineering management roles. Mr Zeito has worked on a wide range of petroleum engineering projects including simulator development, conventional gas and water floods, miscible gas injection, steam injection, fractured reservoir modeling, and the characterization of complex fluid systems. Mr Zeito holds a BA degree in Computer Science from the University of Texas at Dallas and is a member of SPE.
Mr Vihristencu has 30 years international experience in upstream geosciences having worked in Eastern Europe, Siberia, Kazakhstan, China, India, West and North Africa, Madagascar and Argentina. He has extensive experience in petrophysics, geology, geophysics, reservoir modeling, data acquisition and processing technologies as well as geosciences software and databases applications. Prior to joining Afren in 2008, he worked in various senior technical roles with Petrom, Western Atlas International, Baker Hughes, Randall & Dewey and Jefferies International.
Mr Vihristencu received a MSc degree in Engineering Geology and Geophysics from Bucharest University. He is a member of AAPG and SEG.
Mr Ojukwu is an Asset Manager who will be project managing the transition of operations and technical handover of OML26 to FHN and Afren. Mr Ojukwu has over 20 years' experience, joining Afren from Shell where he worked in a similar capacity on a number of projects. Mr Ojukwu holds an MEng in Petroleum Engineering from Heriot Watt University and a BEng in Mechanical Engineering from the University of Nigeria, Nsukka.
Mr Olushina is Asset Manager for the Ebok Asset and has over 20 years' experience in the oil industry. His experience covers project and design management; operations, drilling and completions management. Mr Olushina previously worked for ExxonMobil both in Nigeria and the USA. Mr Olushina is a member of the Society of Petroleum Engineers.
Mr Akpan is Asset Manager for the Okoro field and has over 18 years' experience in the oil industry. Prior to joining Afren he was Project and Team Leader for Shell Nigeria. His experience spans process and production operations, facilities engineering, project management, pipeline engineering and supply chain management. Mr Akpan holds an MEng in Industrial Engineering and Management Science from the University of Nigeria and a BSc (Hons) in Chemical Engineering from the University of Ife, Nigeria.
Mr Cherruau is Country Manager for Afren Côte d'Ivoire and has around 10 years' legal, commercial and strategic planning experience in the oil and gas industry with Total, Baker Hughes, African Arabian and FMC Technologies. He has worked internationally in Singapore and Tunisia. Mr Cherruau has a Masters degree in International Business Law and Management from Essec in France and an MBA from INSEAD.
Dr McCormack is Exploration Director and is responsible for Afren's exploration strategy and work programme. Dr McCormack has over 15 years' experience and has held various senior positions within the Hess Corporation, most recently managing Exploration, Exploitation and Appraisal for Africa. Earlier in his career he worked for The Institute of Geological and Nuclear Sciences in New Zealand and for BP in a number of international assignments. He holds a PhD and BA in Geology from Trinity College, Dublin where he has also been appointed a research associate. Dr McCormack also lectures both nationally and internationally.
Mr Rogers has been appointed COO of Afren's East Africa Exploration business. Mr Rogers has over 35 years' experience in the oil and gas industry. He has previously held senior positions with BP, Enterprise Oil and a number of smaller independent companies in the Middle East and Turkey before joining Black Marlin Energy as Director of Exploration in 2007. He holds a BSc in Geology and Geography from the University of London.
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Mr Bajomo had a 25 year career with the Shell Group working in Exploration & Production, Economics & Planning, Gas Development and Gas Consultancy in Nigeria, Namibia, London and the Netherlands between 1980 and 2005. He was the Managing Director of Shell Exploration and Production Namibia and Namibia Country Chairman between 1999 and 2003. From 2005 to September 2010, Mr Bajomo was with the BG Group as Vice President, Nigerian Assets. Mr Bajomo holds a BSc in Chemical Engineering from the University of Ife, Nigeria and an MSc in Engineering Production and Management from the University of Birmingham, UK.
Mrs Barker joined Afren in 2008 as Head of Human Resources, a role which encompasses Group-wide responsibility for all HR activities. She is MBA qualified and has over 25 years' human resources experience in the oil and gas industry with Chevron, Gulf, LASMO and African Arabian; this included a three year assignment as Head of HR for a new country entry in Venezuela.
Mr Bassina is a lawyer with over 29 years' experience. He has held several roles in the oil and gas industry including Deputy to the Vice President of the United Meridian Corporation and Ocean Energy. He currently heads Government and Business Relations at Afren Côte d'Ivoire.
Mr Capra has nearly 30 years' experience in EHSS matters including 20 years international experience in oil and gas. His recent assignments includes acting as Senior Safety Advisor for Occidental; HSEQ Managing Coordinator for ENI's drilling and production operations in Alaska and the Gulf of Mexico and HSSE & Social Responsibility Corporate Manager for Addax Petroleum in Geneva where he had responsibility for HSSE and Community Relations activities worldwide including Africa and the Middle East. Mr Capra has an MS in Industrial Safety from Central Missouri State University and a BS in Health Science from Brigham Young University.
Before joining Afren, Mr Cherlet has held management positions at Western Geophysical, Western Atlas, Baker Hughes, Randall & Dewey and Jefferies International. Mr Cherlet has a strong academic background, having received an MS from Stanford University and an MS from Ghent University in Belgium.
Mr Imam has 15 years' experience in the oil industry. He has worked in a variety of roles including production engineering, facilities and gas engineering and government relations. Since joining Afren, he has made a significant contribution to the Company's business development initiatives in Nigeria. Mr Imam's career began with Texaco in Nigeria as an offshore production engineer. He moved through to developing projects, handling associated gas production, and then on to deep-water project development. He holds a MEng in Chemical and Biochemical Engineering from University College, London.
Prior to joining Afren, Ms Johri worked in Cadwalader, Wickersham & Taft LLP's African practice. She has extensive experience advising on acquisitions and disposals, joint ventures, infrastructure projects and private equity investment. Ms Johri has led the Afren team in all significant corporate acquisitions since joining in 2006. She holds an LLM from the Cornell Law School, New York, an LLB (Hons) from Delhi University, India and a Bachelor's degree from Delhi University. She has also been called to the New York Bar.
Mrs Kodja is a financial accountant with over 13 years' experience in the oil and gas industry. Prior to joining Afren, she was the Accountant at United Meridian International Corporation, Deputy Finance Manager at Ocean Energy and Finance Manager at Devon Côte d'Ivoire. Mrs Kodja holds an MBA from University of District of Columbia (Washington DC).
Mr Olleveant has over 18 years' health and safety experience in the oil industry of which over 10 were spent in an international role with LASMO. He has extensive experience of managing EHSS issues associated with major oil and gas projects as well as wider risk management experience. In previous roles he has been responsible for developing and implementing management systems and providing corporate assurance that effective controls are in place. Mr Olleveant holds an MSc degree in Engineering Geology from Durham University and a BSc in Environmental Science from Lancaster University.
Mr Sasegbon has over 15 years' advisory experience. His background includes advising on oil and gas in both Nigeria and the Gulf of Guinea, where he has advised a number of indigenous and international operators on farm-ins, production sharing contracts, joint venture agreements, FPSO and other operational contracts. Previously, Mr Sasegbon has worked as a Barrister in the UK, as well as for Jardines Insurance Brokers and the Nigerian National Petroleum Company (NNPC).
Mr West leads the finance function for Afren Nigeria. He brings over 23 years' experience and an in-depth knowledge of commerce, finance and accounting to the role from his time in several industries – including distribution, consulting, banking, manufacturing, and oil and gas. Previously, Mr West was Group CFO for the Sahara Group: Nigeria's largest private oil and gas company. He has worked with many organisations including British Petroleum, Price Waterhouse (now PWC) and Mellon Bank. He is a member of The Institute of Chartered Accountants in England and Wales, and also in Nigeria.
Mr Whitlock is a qualified accountant with 20 years' experience in the oil industry. He spent 13 years with Enterprise Oil in a variety of roles across the finance department, including several years as Financial Planning Manager and International and Corporate Accounting Manager. Prior to joining Afren he was Planning Manager at Nexen (UK) Ltd. Mr Whitlock has a BSc in Mathematics from Durham University.
| 65 Governance |
65 66 69 75 83 84 |
Index to the Report Directors' Report Corporate Governance Statement Directors' Remuneration Report Statement of Directors' Responsibilities Independent Auditors' Report |
|---|---|---|
| 85 Financial Statements |
85 85 86 87 88 90 |
Group Income Statement Group Statement of Comprehensive Income Balance Sheets Cash Flow Statements Statements of Changes in Equity Notes to the Consolidated Financial Statements |
Oil and Gas Reserves Glossary of Terms
Advisers and Company Secretary
Shareholder Information
The Directors submit their Annual Report on the affairs of the Group together with the financial statements and audit report of Afren plc for the year ended 31 December 2010.
The principal activities of the Group are oil and gas exploration, development and production in Africa. The subsidiary and associated undertakings principally affecting the profits or net assets of the Group in the year are listed in notes 14 and 15 to the consolidated financial statements.
The Company is required by the Companies Act to set out in this report a fair review of the business of the Group during the financial year ended 31 December 2010 and of the position of the Group at the end of the year and a description of the principal risks and uncertainties facing the Group ('business review'). The information that fulfils the requirements can be found within the Chairman and Chief Executive's Statement, the Review of Operations and the Financial Review, which are incorporated into this report by reference. These sections also include details of expected future developments in the business of the Group and details of Key Performance Indicators that management use. The Corporate Governance Statement on pages 69 to 74 forms part of this Directors' Report.
Information about the use of financial instruments by the company and its subsidiaries is given in note 21 to the financial statements.
Details of significant events since the balance sheet date are contained in note 34 to the financial statements.
The Group's business activities, together with the factors likely to affect its future development, performance and position are set out in the Review of Operations. The financial position of the Group at the year end, its cash flows, liquidity position and borrowing facilities are described in the Financial Review. In addition note 21 to the financial statements includes the Group's objectives, policies and processes for managing its capital, its financial risk management objectives and details of its financial instruments and hedging activities; and note 3 describes its exposures to credit risk and liquidity risk.
Following the successful bond issue in January 2011, the company has considerable financial resources. As a consequence, the Directors believe that the company is well placed to manage its business risks successfully despite the uncertain economic conditions that remain.
The Directors have a reasonable expectation that the Company and Group have adequate resources to continue in operational existence for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in preparing the annual financial statements.
The Group's profit for the year was US\$45.9 million (2009: US\$16.8 million loss). The Directors have not recommended the payment of a dividend (2009: US\$nil).
The Directors who served during the year and subsequently, together with their and their families' beneficial interests in shares in the Company, were as follows:
| Committees | Ordinary shares of £0.01 each | ||||||
|---|---|---|---|---|---|---|---|
| Name | Audit and Risk |
Nomination | Remuneration | At 25 March 2011 |
At 31 December 2010* |
At 31 December 2009** |
|
| Egbert Imomoh Chairman | •† | 3,672,246 | 3,672,246 | 3,672,246 | |||
| Osman Shahenshah Chief Executive | 4,181,515 | 4,181,515 | 4,181,515 | ||||
| Constantine Ogunbiyi(i) Director | 1,295,676 | 1,295,676 | 1,295,676 | ||||
| Shahid Ullah Chief Operating Officer | 3,268,961 | 3,268,961 | 3,081,461 | ||||
| Darra Comyn(ii) Group Finance Director | – | – | – | ||||
| Peter Bingham Non-Executive Director | •† | • | – | – | – | ||
| Toby Hayward Senior Non-Executive Director | • | • | 205,000 | 205,000 | 205,000 | ||
| Ennio Sganzerla Non-Executive Director | • | • | • | 24,000 | 24,000 | 24,000 | |
| John St. John Non-Executive Director | • | •† | 50,922 | 50,922 | 50,922 |
* Or resignation, if earlier (i) Stepped down 04 January 2011
** Or on appointment, if later (ii) Appointed 24 March 2010 † Chairman of Committee
Details of the Directors' share options are provided in the Directors' Remuneration Report.
The Company's policy, which is also applied by the Group, is to settle terms of payment with suppliers when agreeing the terms of each transaction, ensure that suppliers are made aware of the terms of the payment and abide by the terms of the payment. Trade creditors of the Group at 31 December 2010 were equivalent to 30 days' purchases (2009: 34 days), based on the actual year end balance.
During the year the Group made charitable donations of US\$581,665, the majority of which related to African-focused charities and institutions (2009: US\$133,863).
No political donations were made in either 2010 or 2009.
Details of the authorised and issued share capital, together with details of the movements in the Company's issued share capital during the year are shown in note 27. The Company has one class of ordinary shares which carry no right to fixed income. Each share carries the right to one vote at general meetings of the Company. The ordinary shares reflect 100% of the total issued nominal value of all share capital.
There are no specific restrictions on the size of a holding nor on the transfer of shares, which are both governed by the general provisions of the Articles of Association and prevailing legislation. The Directors are not aware of any agreements between holders of the Company's shares that may result in restrictions on the transfer of securities or on voting rights.
Details of employee share schemes are set out in note 30.
No person has any special rights of control over the Company's share capital and all issued shares are fully paid. Details of significant shareholdings are set out below.
With regard to the appointment and replacement of Directors, the Company is governed by its Articles of Association, the Combined Code, the Companies Acts and related legislation. The Articles themselves may be amended by special resolution of the shareholders. The powers of Directors are described in the Main Board Terms of Reference, copies of which are available on request, and the Corporate Governance Statement on page 69-74.
The Company currently has authority to make market purchases (within the meaning of section 693(4) of the Companies Act 2006) of ordinary shares of the Company up to a maximum number of ordinary shares of 89,040,503. This authority shall expire on 6th June 2011.
In respect of the Company's assets in Ghana, Block 10A in Kenya, the Seychelles and Ethiopia our partners may have a right of first refusal to acquire the Company's interest if a competitor directly or indirectly took control of the Company. In relation to the Ebok asset, our partner Oriental would have a similar right of first refusal to acquire our interest upon a direct or indirect change of control. In addition, under the terms on which the Senior Secured Notes of US\$500 million, upon a change of control each holder of the notes has the right to require Afren to repurchase all or any part of its holding.
There are a number of agreements that take effect, alter or terminate upon a change of control of the company such as commercial contracts, bank loan agreements, property lease arrangements and employees' share plans. None of these is considered to be significant in terms of their likely impact on the business of the Group as a whole. Furthermore, the Directors are not aware of any agreements between the company and its directors or employees that provide for compensation for loss of office or employment that occurs because of a takeover bid.
As of 29 March 2011 (being the latest practicable date prior to publication of the Annual Report), interests notified to the Company in accordance with Chapter 5 of the Disclosure and Transparency Rules comprised:
| % | |
|---|---|
| AXA SA | 9.98 |
| Vidacos Nominees | 8.18 |
| JPMorgan Asset Management Holdings Inc | 5.00 |
| BlackRock Inc | 4.98 |
| HSBC Client Holdings UK Limited | 4.93 |
| GLG Partners LP | 4.88 |
| Investec Asset Management Limited | 4.50 |
Percentages are based on the issued share capital at the date of notification.
At the end of the year, the Directors had authority, under the shareholders' resolutions of 29 April 2010, to purchase through the market 89,040,503 of the Company's ordinary shares at prices ranging between one penny and be the higher of (i) the amount equal to 105% of the average of the closing middle market quotations for an ordinary share (as derived from the London Stock Exchange Daily Official List) for the five business days immediately preceding the day on which the ordinary share is purchased and (ii) the amount stipulated by article 5(1) of the Buy-back and Stabilisation Regulations 2003 (in each case exclusive of expenses); per share. This authority expires on 6 June 2011.
Each of the persons who is a Director at the date of approval of this Annual Report confirms that:
This confirmation is given and should be interpreted in accordance with the provisions of section 418 of the Companies Act 2006.
Deloitte LLP have expressed their willingness to continue in office as auditors and a resolution to reappointment them will be proposed at the forthcoming Annual General Meeting.
At the Annual General Meeting of the Company, resolutions will be proposed to receive these accounts and the Directors' and auditors' reports and to re-elect the Directors who are retiring at the Annual General Meeting, in accordance with the Company's Articles of Association. Resolutions to reappoint Deloitte LLP as the Company's auditors, to authorise the Directors to fix Deloitte LLP's remuneration as auditors, to authorise the amendment and implementation of revised rules of the Company's employee share incentive plans, to authorise the establishment and operation of an employee benefit trust for the benefit of employees, to operate in conjunction with the Company's employee share incentive plans, to grant the Directors authority to allot ordinary shares, to buy back the Company's ordinary shares and to allow a general meeting to be held on not less than 14 days' notice will also be proposed.
For a more detailed explanation of these and other amendments, please refer to the Notes on Resolutions set out in the Notice of Annual General Meeting. A copy of the draft trust Deed for establishing the employee benefit trust and the proposed rules of the Company's employee share incentive plans, that reflect these amendments will be available for inspection during normal business hours (Saturdays, Sundays and public holidays excepted) at the registered office of the Company (Kinnaird House, 1 Pall Mall East, London SW1Y 5AU) and the offices of White & Case, 5 Old Broad Street, London EC2N 1DW up until the close of the meeting.
On behalf of the Board
Osman shahenshah Chief Executive 29 March 2011
The Directors support high standards of corporate governance. As a UK listed company, Afren plc is required to state whether it has complied with the provisions in Section 1 of the 2008 Combined Code on Corporate Governance (Combined Code) throughout the year and, where the provisions have not been complied with, to provide an explanation. Afren is also required to explain how it has applied the principles in Section 1 of the Combined Code.
This statement explains how the Directors applied the principles of the Combined Code during the year ended 31 December 2010. The Directors consider that the Company complied in full with the provisions set out in Section 1 of the Combined Code for the whole of the year ended 31 December 2010.
The Board considers the independence of each of the Non-Executive Directors upon appointment, annually and at any other time where the circumstances of a Director changes to warrant reconsideration. Following a review of Board composition the Company has reassessed the independence of all the Non-Executive Directors and regards all of the current Non-Executive Directors to be independent within the meaning of 'independent' as defined in the Combined Code.
When the Company listed on the AIM market, the Non-Executive Directors were eligible for share option awards. Since admission to the Official List of the United Kingdom Listing Authority no share options have been granted to any Non-Executive Director and the Share Option Scheme Rules were amended in November 2009 to prohibit the award of share options to Non-Executive Directors. Peter Bingham and John St John are the only independent Non-Executive Directors who have unexercised options. We take the view that this does not impact the independence of the Non-Executive Directors. For more information see the Directors' Remuneration Report.
The Board has a policy that it uses to determine the independence of its Directors. The policy provides that the test of independence is whether the Director is "independent of management and any business or other relationship that could materially interfere with the exercise of objective and unfettered or independent judgment by the director or the director's ability to act in the best interests of the shareholders". Where a director is considered by the board to be independent, but is affected by circumstances that may give rise to a perception that the director is not independent the board has undertaken to explain the reasons why it has reached its conclusion. The Board considers relationships with management, major shareholders, associated companies and other parties with whom the Group transacts business against predetermined materiality thresholds, all of which are set out in the policy. Tested against that policy, the Board considers that each of the Directors have retained independence of character and judgment and have not formed associations with management or others that might compromise their ability to exercise independent judgment or act in the best interests of the company.
Some of the Directors hold or previously held positions in companies with which we have commercial relationships. Those positions and companies are set out below in this report. The Board has assessed all of the relationships between the company and companies in which the Directors hold or held positions and has concluded that in all cases, the relationships do not interfere with the Director's exercise of objective, unfettered or independent judgment or their ability to act in the best interests of our business.
In the case of Mr. John St John, the Board has considered the fact that he is a shareholder in St. John Advisors Ltd and a partner in STJ Advisors LLP, companies with which Afren has had commercial dealings. St John Advisors Ltd and STJ Advisers LLP operate in the financial advisory sector and it is Mr. St John's breadth of current expertise, experience, knowledge and connections gained while providing capital markets advice to companies seeking access to the markets that brings significant value to the Board. Prior to this and before the appointment of Mr. St John the Board assessed the relationships between Afren and St John Advisors Ltd and STJ Advisers LLP and remains satisfied that Mr. St John is able to apply objective, unfettered and independent judgment and act in the best interests of the company notwithstanding his role with St John Advisors Ltd and STJ Advisers LLP. In addition, commercial dealings with St John Advisors and STJ Advisers have been and to the extent they continue in the future will be approved by the independent Non-Executive Directors. Mr. St. John and the Executive Directors absent themselves fully from these deliberations.
Transactions during the year that amounted to related party transactions under the International reporting Standards (IFRS) are outlined in note 35 to the financial statements. The Company does not consider the level of fees paid to St. John Advisors Ltd and STJ Advisers LLP to be material to either business. All the transactions with Directors including Mr. St John qualify under the exemption for smaller related party transactions in respect of the Related Party Rules of the UKLA Listing Authority.
continued
The Board currently has eight members. Nine directors served on the Board in the 2010 financial year. Of these, four, excluding the Chairman, are Non-Executive Directors, who the board consider to be independent. The Board considers that there is an appropriate balance between Executive and Non-Executive Directors, with a view to governing the business effectively and promoting shareholder interests. The Board considers that the Executive and Non-Executive Directors have a range of skills, knowledge and experience necessary to enable them to govern the business effectively. The Non-Executive Directors contribute international operational experience; understanding of the sectors in which we operate; knowledge of international capital markets and an understanding of the health, safety, environmental, political and community challenges we face. The Directors are listed below.
| Board member | Position | Year appointed | Year of vacation of office | Executive Director | Non-Executive Director |
|---|---|---|---|---|---|
| Egbert Imomoh | Non-Executive Chairman | 2005 | X | ||
| Osman Shahenshah | Chief Executive | 2004 | X | ||
| Toby Hayward1 | Non-Executive Director | 2009 | X | ||
| Peter Bingham | Non-Executive Director | 2005 | X | ||
| John St. John | Non-Executive Director | 2007 | X | ||
| Ennio Sganzerla2 | Non-Executive Director | 2009 | X | ||
| Shahid Ullah | Chief Operating Officer | 2008 | X | ||
| Darra Comyn | Group Finance Director | 2010 | X | ||
| Constantine Ogunbiyi | Executive Director | 2008 | 2011 | X | |
1 Managing Director at Jeffries International, Afren's AIM Nomad. Mr Hayward left Jeffries International in June 2008.
2 Member of Afren's International Advisory Board providing Non-Executive support to the Company until June 2009.
The Board is committed to ensuring the majority of Directors are independent and is actively seeking to recruit an additional independent Non-Executive Director with the relevant industry and geographical experience. The Board hopes to be able to make an announcement in this regard, subject to securing the right candidate.
The Board is responsible for providing leadership, setting the Group's strategic objectives and key policies, ensuring that appropriate resources are in place to enable the Group to meet its objectives, reviewing the Group's performance and overseeing the Group's internal control systems and is responsible to shareholders for the proper management of the Group. At the end of the period of this report, the Board comprised of a Non-Executive Chairman, three Executive Directors and four Non-Executive Directors. Darra Comyn joined the Board on 24 March 2010 as Executive Director responsible for leading and directing Afren's group-wide finance function and on 4 January 2011 Constantine Ogunbiyi stepped down as a Director of Afren plc to take up the position of CEO of First Hydrocarbon Nigeria. Afren benefits from an experienced Board with extensive African experience and relationships and a broad range of commercial, financial and other relevant experience. Brief biographies are set out on pages 60 to 61.
The Nomination Committee periodically reviews the composition of the Board including the balance between Executive and Non-Executive Directors and considers succession planning for both Executive and Non-Executive Directors and the Group's senior management. It is also responsible for the process for new Board appointments and makes recommendations to the Board on the appointment of new Directors and is responsible for ensuring that appointments are made on merit and against objective criteria.
In making appointments to the Board, the Nomination Committee considers the skills, experience and knowledge of the existing Directors and assesses which of the potential candidates would most benefit the Board. It considers the potential candidate's knowledge and experience of Africa, the oil and gas industry in Africa, capital markets and the regulatory environment, and that, in the case of Non-Executive Director appointments they have sufficient time to devote to the role. The Chairman ensures that any new Directors are provided with a full induction on joining the Board. Non-Executive Directors are appointed for an initial term of three years, which may be extended by mutual agreement subject to satisfactory performance. The letters of appointment of each Non-Executive Director are available for inspection at the registered office of the Company.
The Board meets on at least four occasions during the course of the year to review trading performance and budgets, funding, to set and monitor strategy, examine acquisition opportunities and report to shareholders. The Chief Executive holds informal meetings with the Chairman and Non-Executive Directors to discuss issues affecting the Group, such as target objectives, strategy, key performance indicators and remuneration matters.
The Board has a formal schedule of matters specifically reserved to it for decisions and responsibility for developing and implementing the Group's strategic and financial objectives is delegated to the senior management of the Group. The roles of Chairman and Chief Executive are separate and the responsibilities of Chairman and Chief Executive are independently defined. It is the Chairman's responsibility to ensure that the principles and processes of the Board are maintained, including the provision of accurate, timely and clear information in relation to the Group and its business.
The Chairman is also responsible for encouraging debate and constructive criticism, speaking and acting for the Board and representing the Board to shareholders, and presenting shareholders' views to the Board. The Board considers that none of Mr Imomoh's other commitments interfere with the discharge of his responsibilities to the Company. The Board is satisfied that he makes sufficient time available to serve the Group effectively. The Group does not have a Deputy Chairman, but has identified Mr Bingham to act as Chairman should the need arise at short notice.
The Combined Code recommends that the Board should appoint one of its independent Non-Executive Directors to be the senior independent Director. The senior independent Director should be available to shareholders if they have concerns that contact through the normal channels of Chairman, Chief Executive or Chief Operating Officer has failed to resolve or where such contact is inappropriate. Mr Toby Hayward is the Board's existing senior independent Director.
The Board has appointed an Audit and Risk Committee, a Remuneration Committee and a Nomination Committee, each of which have defined terms of reference which are summarised below. Terms of Reference of the respective committees are available on the Company website. Each Committee and each Director has the authority to seek independent professional advice where necessary to discharge their respective duties in each case at Afren's expense. In addition, each Director and Committee has access to the advice of the Company Secretaries, Ms Shirin Johri and Mr Elekwachi Ukwu.
The Directors collectively have responsibility for the conduct of the Group's business and are expected, wherever possible, to attend all Board meetings, relevant Committee meetings and the Annual General Meeting (AGM). A table detailing the Directors' attendance at each of the Company's scheduled Board and Committee meetings during 2010 is set out below.
The number of Board and Committee meetings held during 2010, together with details of each Director's attendance, is set out below:
| Number of Board meetings held whilst a Board member |
Number of Board meetings attended |
Audit and Risk Committee |
Remuneration Committee |
Nomination Committee |
|
|---|---|---|---|---|---|
| Number of meetings* | 4 | 4 | 3 | 2 | 1 |
| Egbert Imomoh | 4 | 4 | 1 | ||
| Osman Shahenshah | 4 | 4 | |||
| Toby Hayward | 4 | 4 | 3 | 1 | |
| Peter Bingham | 4 | 4 | 3 | 2 | |
| John St. John | 4 | 4 | 3 | 2 | |
| Ennio Sganzerla | 4 | 4 | 3 | 2 | 1 |
| Shahid Ullah | 4 | 4 | |||
| Darra Comyn | 4 | 4 | |||
| Constantine Ogunbiyi | 4 | 4 | |||
* In addition to the four scheduled meetings, the Board also met on a quorate basis on ten occasions to deal with specific matters.
The performance of the Board is a fundamental component of the Group's success. The Board regularly reviews its own performance and historically this review has been conducted internally. The results of the most recent assessment were taken into account in the decision to recommend the search for prospective candidates for appointment as an additional Non-Executive Director. The Board is satisfied that each Director continues to contribute effectively and to demonstrate commitment to his role. The Chairman reviews the performance of each Non-Executive Director and, with the input of the Non-Executive Directors, the performance of each Executive Director in respect of their boardroom as opposed to executive roles (which are evaluated as part of the Group's regular Performance Development Review process). The Chief Executive's total performance is reviewed by the Chairman. During the year, the Chairman met with the Non-Executive Directors, without the Executive Directors present, to discuss Board issues. The Chairman's own evaluation was conducted by the Non-Executive directors led by the senior independent Director, taking into account the views of the Executive Directors. The senior independent Director discussed and agreed the conclusions with the Chairman.
At the request of the Chairman, for the year ended 31 December 2010, Afren has retained Armstrong Bonham Carter LLP to conduct an external review of the Afren plc Board performance. The review will cover the performance of the Board as a whole, of the individual Directors and of the various committees of the Board. The review is scheduled to take place in May 2011 and the results will be presented to the Board in June at which time recommendations will be made and agreed by the Board.
The Audit and Risk Committee comprises Mr Peter Bingham (Chairman), Mr John St. John, Mr Ennio Sganzerla and Mr Toby Hayward. The Board has determined that Mr Toby Hayward who is a chartered accountant and Mr John St. John who has extensive experience in financial markets have recent and relevant financial experience through their previous and current roles. In addition, the other members of the Committee have a range of financial, commercial and other relevant experience.
The Chairman of the Company, the Chief Executive, Group Finance Director and other senior executives attend meetings of the Committee by invitation. Deloitte LLP (Deloitte) is also invited to attend meetings of the Audit and Risk Committee. The Committee also meets privately with representatives from Deloitte at least once per annum (and as and when required) to discuss any matters which the auditors may wish to raise without Executive Directors being present. During the year the Committee met on three occasions at each of which there was full attendance.
The Committee's remit includes reviewing the internal control framework, the internal audit process, the financial reporting practices, the external audit process and recommending to the Board whether to reappoint the external auditor. It ensures the Board regularly assesses business risks and the risk management and mitigation strategies. In doing so, the Committee places reliance on reports from executive management, external audit and internal audit reviews. In monitoring the financial reporting practices the Audit and Risk Committee reviewed the accounting policies, areas of judgement, the going concern assumption and compliance with accounting standards, the Disclosure and Transparency rules and the Combined Code. During the year the Committee reviewed, prior to publication, the half year and annual financial statements and other major statemetns affecting the Group concerning price sensitive information.
The Audit and Risk Committee has approved a policy on considering whether to employ the external auditors to supply services other than audit services, and closely monitors the level of audit and non-audit services the external auditors provide to the Group. Non-audit services are normally limited to assignments that are closely related to the annual audit or where the work is of such a nature that a detailed understanding of the Group is necessary. The external auditors are specifically excluded from providing internal audit services, litigation support, remuneration advice and legal advice services. Every other piece of non-audit work is assessed separately and is awarded depending on which professional services firm is considered best suited to perform the work. In addition any non-audit work with a total fee greater than 25% of the annual audit fee must be approved by the Chairman of the Audit and Risk Committee prior to the appointment being made. The Board is satisfied that this policy is conducive to the maintenance of auditor independence and objectivity. During the year a significant amount of non-audit related work was performed by the external auditors in relation to the acquisition of Black Marlin, work that would ordinarily be performed by external auditors for companies involved in such projects. The Audit and Risk Committee is satisfied that the carrying out of this work would not impair the independence of the external auditors. A breakdown of the fees paid to the external auditors in respect of audit and non-audit work is included in note 7 to the financial statements.
The Audit and Risk Committee has recommended to the Board that the current auditors, Deloitte LLP be reappointed as external auditor. In making the recommendation it has taken into consideration the independence matters noted above and the past service of the auditors, who were first appointed in 2005 after a full tender process. The Committee has also considered the likelihood of a withdrawal of the auditor from the market and noted that there are no contractual obligations to restrict the choice of external auditor.
The Nomination Committee currently comprises Mr Egbert Imomoh (Chairman), Mr Ennio Sganzerla and Mr Toby Hayward. The Nomination Committee meets at least once a year and more frequently if required and is responsible for reviewing and recommending to the Board suitable candidates for appointment as Directors of the Company. It regularly reviews the structure, size and composition (including the skills, knowledge and experience) required on the Board. There is a formal, rigorous and transparent procedure, which is based on merit and against objective criteria, for the appointment of new directors to the Board. Darra Comyn was identified as a potential candidate by internal sources and subsequently recommended to the Board by the Nomination Committee on the basis of his significant international experience as a finance practitioner, gained over 24 years in various senior positions including roles with international companies with emerging markets focus. The whole Board subsequently discussed the recommendation before his appointment was confirmed.
The Remuneration Committee currently comprises Mr John St. John (Chairman), Mr Ennio Sganzerla and Mr Peter Bingham. The Remuneration Committee is responsible for:
The remuneration of the Non-Executive Directors is determined by the Chairman and the other Executive Directors outside the framework of the Remuneration Committee.
The Director's Remuneration report can be found on pages 75 to 82.
The Board has applied principle C.2 of the Combined Code by establishing a continuous process for identifying, evaluating and managing the significant risks the Group faces. The Board regularly reviews the process, which has been in place from the start of the year to the date of approval of this report and which is in accordance with revised guidance on internal control published in October 2005 (the Turnbull Guidance).
The Board is responsible for the Group's system of internal control and for reviewing its effectiveness on an ongoing basis. Such a system is designed to manage rather than eliminate the risk of failure to achieve business objectives, and can only provide reasonable and not absolute assurance against material misstatement or loss. In compliance with provision C.2.1 of the Combined Code, the Board regularly reviews the effectiveness of the Group's system of internal control. The Board's monitoring covers all controls, including financial, operational and compliance controls and risk management. It is based principally on reviewing reports from management to consider whether significant risks are identified, evaluated, managed and controlled and whether any significant weaknesses are promptly remedied and indicate a need for more extensive monitoring. As well as the ongoing regular reviews of the Group's system of internal control, the Board has also performed a specific assessment for the purpose of this annual report. This assessment considers all significant aspects of internal control arising during the period covered by the report, including relevant internal audit work undertaken. The Audit Committee assists the Board in discharging its review responsibilities.
Internal audit and compliance monitoring work is carried out by the Group's Director of Business Process, supported by independent specialist consultants as required. The reporting line is to the Group Finance Director, however reports of work undertaken are also provided to the Chairman of the Audit Committee and any requests from the Audit Committee of specific review areas are included in the work programme and the Chairman of the Audit Committee has direct access to the Group's Director of Business Process. The Board and the Audit Committee has considered the need for a formal internal audit department but considers the current structure to be most suitable at this point in time. This will be reviewed on an annual basis.
The Board has put in place a management structure with defined lines of responsibility and clear delegation of authority. Key elements of the overall control environment are the various committees, including the Executive Committee, which meets at least bi-monthly and is responsible for all strategic and operational activities on a day to day basis.
The Group has developed a formal structured business planning process which operates on an annual cycle. The Board approves the consolidated annual budget, and performance against budget is monitored and reported to the Board.
The Group's risk assessment process is described on pages 42 to 43. Significant risks, their potential impact on the Group's financial position, and actions taken to manage those risks were reviewed regularly during the year by the Audit and Risk Committee and senior executives of the Company.
The UK Bribery Act 2010 (Act) received royal assent on 8 April 2010. The UK Ministry of Justice is working on additional guidance aimed at making the new legislation practical and comprehensive for businesses. When the guidance is published it will be followed by a three month notice period before implementation of the Act. The Company is currently awaiting the issue of the anticipated guidance prior to finalising our policies and procedures in this area.
During the course of its review of the system of internal control, the Board has not identified nor been advised of any failings or weaknesses which it has determined to be significant. As described in the Corporate and Social Responsibility Report on page 49, security arrangements were reviewed at our operations in Nigeria following the incident in November 2010.
The Board remains satisfied with the arrangements by which staff may, in confidence and if they wish via an external reporting line, raise concerns about possible improprieties in relation to financial reporting or other matters.
The Board represents the shareholders and is accountable to them for creating and delivering value through the effective governance of the business. The Board remains fully committed to maintaining regular communication with its shareholders. The Board has developed a strategy for engaging and communicating with shareholders, key aspects of which are outlined below.
There is regular dialogue with major institutional shareholders and meetings are offered regularly following significant announcements. Press releases have been issued throughout the year and the Company maintains a website (www.afren.com) on which all press releases are posted and which also contains major corporate presentations and the reports and accounts. Additionally, this Annual Report, which is sent to all registered shareholders, contains extensive information about the Group's activities. Enquiries from individual shareholders on matters relating to their shareholdings and the business of the Group are welcomed. Shareholders are also encouraged to attend the Annual General Meeting (AGM) to discuss the progress of the Group and are encouraged to make their views known to us and to raise directly any matters of concern. The CEO, CFO and Investor Relations Team maintain a dialogue with institutional shareholders on strategy, performance, plans and objectives through a programme of regular meetings. The Company reports formally to shareholders twice a year, when its half-year and full-year results are announced. The CEO and CFO give presentations on the full-year results to institutional investors, analysts and the media.
The Group's Investor Relations department, with offices in London, acts as a focal point for contact with investors throughout the year. The Chairman meets regularly with institutional investors to hear their views and discuss issues of mutual importance and communicates the views of investors to the Board as a whole. The Senior Independent Director is also available to shareholders on their request. All Non-Executive Directors, are available to meet with major shareholders if requested. The Company's website provides access to current financial and business information about the Group.
The Company amended its Articles of Association in June 2008 to deal with, amongst other things, the provisions on conflicts of interest in the Companies Act 2006 which came into force in October 2008. Following this the Company has put in place procedures for the disclosure and review of any conflicts, or potential conflicts, of interest which the Directors may have and for the authorisation of such conflict matters by the Board. In deciding whether to authorise a conflict or potential conflict the Directors must have regard to their general duties under the Companies Act 2006. The procedure operates to ensure the disclosure of conflicts, and for the consideration and if appropriate, the authorisation of them by non-conflicted Directors. The authorisation of a conflict matter, and the terms of authorisation, may be reviewed at any time by the Board. The Nomination Committee supports the Board in this process, both by reviewing requests from Directors for authorisations of situations of actual or potential conflict and making recommendations to the Board and by reviewing any situations of actual or potential conflict that have been previously authorised by the Board, and making recommendations regarding whether the authorisation remains appropriate.
The Company maintains Directors' and Officers' liability insurance cover, the level of which is reviewed annually.
continued
The Board is committed to transparency in determining Board Membership. All new Directors are required by the Company's Articles of Association to be elected by shareholders at the first Annual General Meeting (AGM) after their appointment. Subsequently, Directors are subject to re-election by shareholders every three years. The Directors seeking re-election at the 2010 AGM are Osman Shahenshah and Shahid Ullah. In accordance with the UK Corporate Governance Code, annual re-election of all Directors will commence at the AGM in 2012.
Ms Shirin Johri is the Group Company Secretary. Ms Johri has been called to the New York Bar. The Group Company Secretary is responsible for developing and maintaining the information systems and processes that enable the Board to fulfil its role. The Group Company Secretary is also responsible to the Board for ensuring that Board procedures are complied with and advising the Board on governance matters. Ms Shirin Johri is supported by Mr Elekwachi Ukwu who is the Joint Company Secretary. Mr. Ukwu is a solicitor. All Directors have access to the Company Secretaries. The Board has the power to appoint and remove the Company Secretaries.
At Afren, we uphold the highest ethical standards for the conduct of our business activities. We operate with integrity and honesty throughout the organisation and with all our external stakeholders, namely: governments, business partners, shareholders, contractors and local communities. In March 2009 the Board approved a Code of Business Conduct to formalise Afren's commitment to high ethical standards and to reinforce prompt and consistent action in the maintenance of these standards. Our Code of Business Conduct sets out the standards of business ethics that we expect all employees to adhere to. We are committed to ensuring that our business is conducted ethically, honestly and to high standards. The Code applies to Directors and all employees, regardless of their position or location. Consultants, contractors and business partners are also expected to act in accordance with the Code. The Code of Business Conduct can be found on our website at www.afren.com. In addition to Afren's existing policies and procedures an independent, external reporting line has been introduced which allows employees in any country to report any concerns regarding fraud or other unethical practices in confidence. The service is provided by Safecall who report to a senior management team who are responsible for determining the best course of action to be taken.
The Company has a share dealing code (Code) which covers dealings by Directors, Persons Discharging Managerial Responsibilities (PDMR) and relevant employees. This Code complies with the provisions set out in the Model Code contained in Annex 1 to Listing Rule 9 of the UK Listing Authority Listing Rules. The Code restricts dealings in shares and other relevant securities by PDMRs and employees during designated prohibited periods and at any time that they are in possession of unpublished price-sensitive information.
We are committed to maintaining the highest standards of disclosure ensuring that all investors and potential investors have the same access to relevant information in an accessible and timely manner to assist them in making informed decisions. Copies of announcements to the market, investor presentations, the Annual Report and other relevant information are published on our website.
This report has been prepared in accordance with Schedule 8 to the Accounting Regulations under the Companies Act 2006. The report also meets the relevant requirements of the Listing Rules of the Financial Services Authority and describes how the Board has applied the principles relating to the Directors' remuneration in the Combined Code. As required by the Act, a resolution to approve the report will be proposed at the Annual General Meeting of the Company at which the financial statements will be put to shareholders for approval.
The Act requires the auditors to report to the Company's members on certain parts of the Directors' remuneration report and to state whether in their opinion those parts of the report have been properly prepared in accordance with the Accounting Regulations. The Report has therefore been divided into separate sections for audited and unaudited information.
The members of the Remuneration Committee are Mr John St. John (Chairman), Mr Peter Bingham and Mr Ennio Sganzerla. All are Non-Executive Directors.
The Remuneration Committee's responsibilities are set out in its terms of reference which are available in the Corporate Governance section of the Company's website. These include:
No Director plays a part in any discussion about his or her own remuneration.
Executive Directors are entitled to accept appointments outside the Company providing that the Chairman's permission is sought and fees in excess of £10,000 from all such appointments are accounted for to the Company, except where specific approval is gained from the Board.
The Committee met two times during the year for which each member was present. Although not a member of the Committee, Dr. Osman Shahenshah was invited to attend both of the Committee meetings during the year but he was not involved in discussions relating to his own remuneration.
Afren is a relatively young company with a phenomenal growth record. It moved from an AIM listing to a full FTSE listing in late 2009 and achieved membership of the FTSE 250 during 2010. The Company has an ambitious strategy of growth, shareholder return and profitability. The Committee believes that in order to encourage and support this exceptional performance it needs to reward Directors appropriately for their significant contribution to the business with upper quartile salary positioning and a powerful equity incentive programme linked to shareholder value to enhance the overall value of the business.
Over the last few years there have been a number of statements from shareholder bodies and institutional investors clarifying their expectations for directors' remuneration. This culminated in a revised UK Corporate Governance Code. As a result of this the Committee, supported by independent external professional remuneration advisors MM & K Limited (MM&K), undertook an overall review of the Company's remuneration policies and practices during 2010. MM&K is not retained to provide advice to any other part of the Company. A subsidiary of MM&K, Higher Talent Limited, which specialises in the recruitment of HR and Reward professionals, was appointed and received a fee in connection with the recruitment by the Company of HR staff.
The review was instigated following the AGM in 2010 to affirm the Committee's commitment to improve the clarity and structure of the Company's remuneration policies. The results of the review including a revised Remuneration Policy have been discussed and agreed with major shareholders and will be placed before shareholders in General Meeting in 2011. The main parts of the policy review will be rolled out during 2011.
Afren's remuneration philosophy is to ensure that its remuneration policy is fully aligned with its long term business strategy, its business objectives, its risk appetite and its values whilst recognising the interests of all relevant stakeholders. The revised policy clearly links equity, bonus and salary awards to individual and Company performance.
continued
| Strategy | Policy | Package |
|---|---|---|
| To provide a remuneration package that: | • Base salaries set at upper quartile levels. | Short Term: |
| • Helps to attract, retain and motivate | • Reward exceptional performance with upper | Base salary |
| • Is aligned to shareholders' interests | quartile bonus and equity rewards. | Annual performance bonus |
| • Is competitive in the oil and gas industry | • Balance remuneration between short and long | |
| • Encourages exceptional performance | term reward. | Long Term: |
| • Is fair and transparent | Share Option Scheme | |
| • Can be applied consistently across the Group. | Performance Share Plan | |
| Benefits: | ||
| Pension Scheme | ||
| Life cover | ||
| Family PHI and Dental cover | ||
| Critical Illness and Income Protection insurance |
In assessing the Directors' performance, the Remuneration Committee takes into account the general performance of the Company and the prevailing economic environment. The five main elements of the remuneration package for Executive Directors are as follows:
The Company's policy is that a substantial proportion of the remuneration of the Executive Directors and senior management team should be performance related to support the long term growth of the Company and ensure the Executive Directors focus strongly on long term value creation. Base salary progression, annual performance bonus and the long term incentive plan are all based on either individual or Company performance or both.
The underlying remuneration policy applicable to all employees is to position base salaries at or around the upper quartile for comparable positions in similar companies within the oil and gas industry. The Company uses the Deloitte Executive Survey and Deloitte Beyond the Board Survey as well as the Mercer UK Oil and Gas Exploration and Production survey in order to benchmark appropriate remuneration levels. This practice has been established for a number of years and the Committee continues to believe that this is the correct strategy for Afren at the present time. Directors' salaries, detailed below for 2010, are below median and will be increased to levels more in line with competitive requirements for 2011.
| Afren 2010 Salary | FTSE 250 Median | FTSE 250 U/Q | |||
|---|---|---|---|---|---|
| Chief Executive | £462,500 | £600,000 | £700,000 | ||
| Finance Director | £290,000 | £360,000 | £404.000 | ||
| Chief Operating Officer | £357,600* | £321,000 | £408,500 | ||
| Other Director | £260,000 | £301,500 | £332,900 | ||
| * Paid in US\$ Source: Deloitte Executive Survey 2010 |
The Bonus Scheme has been revised to incorporate both individual and company objectives. Bonus targets are based on individual performance as measured by the Company's Performance Management Programme which is completed annually in December, as well as the achievement of challenging corporate targets to ensure a clear link between performance and reward for all employees.
The maximum potential bonus for Directors is 100% of base salary at the time of award of which 80% relates to corporate performance and 20% relates to personal performance targets.
For 2010, no formal key performance indicators were put in place to measure corporate performance and as such the Committee considered the overall performance of the Company including growth, shareholder value, profitability and risk management. In summary 2010 proved to be a pivotal year for the Company with a number of extraordinary achievements on the part of the Executive Team and the business:
Annual Report and Accounts 2010
As a result of this performance, the Remuneration Committee assessed that in 2010 the achievement of Company objectives justified an award of the maximum bonus of 100% of base salary for the Chief Executive, the Chief Operating Officer and the Group Finance Director.
For 2011 the maximum performance bonus award will be 100% of base salary for the Chief Executive, Chief Operating Officer and Group Finance Director if both personal and corporate performance targets are met.
For 2011, corporate performance will be measured in accordance with a number of key performance indicators:
In consultation with the Remuneration Committee, the personal performance targets for Board Directors, other than the Chief Executive, are set by the Chief Executive and the personal targets for the Chief Executive are set by the Chairman.
The basis upon which the bonus is calculated is the same for all employees, including Board Directors, although the weighting towards Company performance is higher at the senior levels and towards personal performance at more junior levels.
The Executive Directors receive certain benefits in kind, principally private medical insurance, club membership and critical illness cover.
UK-based Executive Directors are members of the Company pension scheme. The scheme is a defined contribution scheme and the Company contributes 10% of salary subject to the participant contributing at least 5% of their salary. The US-based Executive Director receives a Company contribution equal to 10% of their salary and bonus subject to the participant contributing at least 5% of their salary and bonus and subject to statutory limits on contributions.
The Remuneration Committee believes that the ability of employees to acquire a meaningful equity stake in the Company is an essential element of Afren's overall remuneration policy.
To that end in 2005 the Company adopted a share option scheme and in 2008 a performance share plan (PSP) in connection with which options and performance share awards have been granted to a wide range of employees. Afren intends to continue to operate both of these schemes, although it is proposed that the share option scheme will be gradually phased out as a general reward scheme and will in future be used mainly as a recruitment tool for senior staff.
The share option scheme was adopted before the company's shares were admitted to the Official List of the London Stock Exchange plc.
The share option scheme provides for the grant of unapproved options (ie options which are not approved by HMRC and so do not confer tax advantages on the option holders) to employees, including Directors, selected by the grantor. It is proposed that the share option scheme should be amended to bring the rules up to date and, to the extent permitted within the relevant legislation, to improve tax efficiency by allowing for the grant of HMRC approved options. Details of the proposed amendments are included in the Notice of Annual General Meeting. Copies of the amended rules of the scheme will be available for inspection by shareholders as set out in the AGM notice.
Awards will not exceed 200% of base salary except in exceptional circumstances to recruit a top executive. Only the Group Finance Director received a grant of options under the share option scheme in 2010 on his appointment as a Director. No other awards were granted to Directors during the year. Details of share options granted to Directors are included on page 81.
continued
The Performance Share Plan (PSP) was introduced in 2008 before the Company's shares were admitted to the Official List of the London Stock Exchange plc. Under the PSP, eligible employees, including Directors, who have been selected to participate, receive an award of shares in the Company. Share awards may be made annually and the maximum value of an award for any Director may not exceed 200% of base annual salary, except that the Remuneration Committee may decide to increase this limit to 300% in exceptional circumstances.
Ordinarily, an award, normally in the form of a conditional share award or a nominal share option, may vest three years after the award date subject to the Company's Total Shareholder Return (TSR) performance relative to the TSR of a selected peer group of companies. An award may vest in full only if Afren's position in the peer group is at or above the 75th percentile. 30% of an award vests for median performance and nothing vests if Afren's TSR is below the median. There is pro rata vesting for performance between the median and upper quartile.
During 2010, the Remuneration Committee reviewed the performance measure linked to PSP awards and the composition of the peer group in relation to which the Company's performance is measured. The Remuneration Committee also considered introducing a new form of share-based long term incentive for Board Directors and key senior executives.
Following its review, the Remuneration Committee has decided to retain the PSP, including the relative TSR performance measure to which the vesting of awards is linked. The revised peer group in relation to which the Company's TSR will be measured in respect of awards granted in 2010 and subsequently comprises the following companies (the preceding peer group is also shown below for the purposes of comparison):
| Borders & Southern Petroleum | Hardy Oil & Gas | Salamander Energy |
|---|---|---|
| Bowleven | Heritage Oil Plc | Serica Energy |
| Cairn Energy | Ithaca Energy | SOCO International |
| Desire Petroleum | JKX Oil & Gas | Sterling Energy |
| EnQuest | Melrose Resources | Tullow Oil |
| Falkland Oil and Gas | Petroceltic International | Valiant Petroleum |
| Gulf Keystone Petroleum | Premier Oil | |
| Gulfsands Petroleum | Rockhopper Exploration |
| Preceding peer group: | ||
|---|---|---|
| Addax | Mart Resources | Sterling Energy |
| Bowleven | Petroceltic International | Stratic Energy |
| Gulf Keystone Petroleum | Roc Oil Company | Tullow Oil |
| Gulfsands Petroleum | Serica Energy | Vaalco Energy |
| Hardy Oil & Gas | SOCO International |
Factors the Remuneration Committee took into account when selecting the revised peer group included:
• The industry within which the Company operates, specifically taking into account both the international nature of the Company's business;
• The UK listing environment the Company is now part of; and
• The market capitalisation, turnover and number of countries in which the Company operates.
In the view of the Remuneration Committee, it is important for the Company's performance to be recognised and for Directors to be rewarded for providing, when measured against the Company's peers, above median returns to shareholders. For the present, the Remuneration Committee believes that the current PSP, which measures Afren's TSR performance against the revised peer group, remains consistent with those aims. The Remuneration Committee will take into account the company's financial performance as well as relative TSR performance in determining the extent such PSP awards should vest.
It is, however, proposed that the PSP should be amended to bring the rules up to date and, to the extent permitted within the relevant legislation, to improve tax efficiency. Details of the proposed amendments are included in the Notice of Annual General Meeting. Copies of the amended PSP rules will be available for inspection by shareholders as set out in the AGM notice.
No PSP share awards were granted to Directors in 2010. Details of PSP share awards granted to Directors to date are included on page 82.
The Company is proposing to establish an employee benefit trust (EBT). This is a discretionary trust settled by the Company for the purposes of providing benefits to employees (including former employees) of the Company. It is common practice for companies to establish an EBT in connection with employees' share schemes. Using funds provided or procured by the Company, the EBT acquires and holds shares pending release to participants in connection with one or more schemes. The Company proposes to establish the EBT to facilitate the operation of its employee share schemes by acquiring ordinary shares either by subscription or purchase in the market. The EBT may not at any time hold more than 5% of the issued ordinary share capital of the Company from time to time.
A resolution to adopt the EBT will be included in the Notice of Annual General Meeting. A copy of the deed for establishing the EBT will be available for inspection by shareholders as set out in the AGM notice.
It is the Company's policy that Executive Directors should have contracts of an indefinite term providing for a maximum of one year's notice. The Directors have no entitlement to any bonus or other additional payment on severance of their contract. Each Director would be considered on an individual basis and any payment would be entirely at the Company's discretion. The details of the Directors' contracts are summarised below:
| Name of Director | Date of contract | Notice period | |
|---|---|---|---|
| Egbert Imomoh | Non-executive Director and Chairman | 1 January 2009 | 3 months |
| Osman Shahenshah | Chief Executive Officer | 27 February 2009 | 12 months |
| Constantine Ogunbiyi | Executive Director | 12 June 2008 | 12 months |
| Shahid Ullah | Chief Operating Officer | 16 April 2008 | 6 months |
| Darra Comyn | Group Finance Director | 29 October 2009 | 6 months |
All Non-Executive Directors have specific terms of engagement and their remuneration is determined by the Board based on independent surveys of fees paid to non-executive directors of similar companies. The notice period for all Non-Executive Directors is three months. The Chairman, in recognition of his role as both Chairman of a main listed company and ambassador for the Company, is paid a basic fee of £140,000 p.a. The basic fee paid to each other Non-Executive Director is £47,000 p.a. except the senior Non-Executive Director who receives £50,000 p.a. The Non-Executive Directors do not participate in the share option scheme, although the awards from 2008 and earlier remain in place, and are not eligible to join the Company's pension scheme.
Afren vs Peer Group Average vs E&Y 350 oil and gas index
The graph shows the relative performance of Afren plc against the Peer Group Average and the Ernst & Young Oil & Gas Index since Afren's IPO. The selected indices give the most appropriate benchmark for other similar-sized oil and gas companies and the Peer Group is used by the Company for the performance criterion for the 2008 & 2009 Performance Share Plan awards.
The Peer Group comprises BowLeven, Gulfsands Petroleum, Gulf Keystone Petroleum, Hardy Oil & Gas, Mart Resources, Petroceltic International, ROC Oil Company, Serica Energy, SOCO International, Sterling Energy, Tullow Oil, Vaalco and Stratic Energy.
continued
| diREcTORs' EmOlumEnTs | ||
|---|---|---|
| Name of Director | Fees/basic salary US\$'000 |
Benefits in kind US\$'000 |
Pension contributions US\$'000 |
Annual bonus US\$'000 |
Total 2010 us\$'000 |
Total 2009 US\$'000 |
|---|---|---|---|---|---|---|
| Executive | ||||||
| Osman Shahenshah | 717 | 15 | 72 | 717 | 1,521 | 1,127 |
| Constantine Ogunbiyi | 403 | 6 | 27 | 349 | 785 | 663 |
| Shahid Ullah | 564 | 19 | 25 | 563 | 1,168 | 1,058 |
| Darra Comyn* | 414 | 5 | 41 | 449 | 909 | – |
| Egbert Imomoh | – | – | – | – | – | 27 |
| 2,098 | 45 | 162 | 2,078 | 4,383 | 2,875 | |
| non-executive | ||||||
| Egbert Imomoh** | 299 | 18 | – | – | 317 | 181 |
| Peter Bingham | 73 | – | – | – | 73 | 62 |
| John St. John | 73 | – | – | – | 73 | 62 |
| Toby Hayward | 78 | – | – | – | 78 | 33 |
| Ennio Sganzerla | 73 | – | – | – | 73 | 33 |
| Guy Pas | – | – | – | – | – | 29 |
| 596 | 18 | – | – | 614 | 400 | |
| 2,694 | 63 | 162 | 2,078 | 4,997 | 3,275 |
* Darra Comyn was appointed to the Board on 24 March 2010. His bonus was based on 100% of his salary at the date of award (December 2010).
** Egbert Imomoh's fee includes fees and other allowances received for work carried out with related entities and an allowance for the costs incurred working from home, totalling US\$81,000 for the period.
Three of the Executive Directors were members of the Company's defined contribution scheme during 2010 (2009: two).
Aggregate emoluments disclosed above do not include any amounts for the value of options to acquire ordinary shares in the Company granted to or held by the Directors. Details of the options held and granted during the year under the 2005 Share Option Scheme are as follows:
| Name of Director |
As at 1 January 2010 |
Granted | Exercised | Lapsed | Date granted |
As at 31 December 2010 |
Share price at grant date |
Exercise price |
Exercisable from |
Exercisable to |
|---|---|---|---|---|---|---|---|---|---|---|
| E Imomoh | 400,000 | – | – | – | 28.06.05 | 400,000 | 36p | 20p | 28.06.05-01.03.07 | 27.06.15 |
| 500,000 | – | – | – | 28.06.05 | 500,000 | 36p | 50p | 28.06.05-01.03.06 | 27.06.15 | |
| 500,000 | – | – | – | 28.06.05 | 500,000 | 36p | 100p | 28.06.05-01.03.07 | 27.06.15 | |
| 600,000 | – | – | – | 30.05.06 | 600,000 | 63p | 63p | 30.05.07-30.05.09 | 29.05.16 | |
| 250,000 | – | – | – | 28.03.07 | 250,000 | 53.5p | 80p | 28.03.07-28.03.10 | 27.03.17 | |
| 250,000 | – | – | – | 28.03.07 | 250,000 | 53.5p | 120p | 28.03.07-28.03.10 | 27.03.17 | |
| 250,000 | – | – | – | 28.03.07 | 250,000 | 53.5p | 180p | 28.03.07-28.03.10 | 27.03.17 | |
| 750,000 | – | – | – | 23.01.09 | 750,000 | 20.25p | 23.25p | 23.01.10-23.01.12 | 23.01.19 | |
| C Ogunbiyi* | 100,000 | – | – | – | 28.06.05 | 100,000 | 36p | 20p | 28.06.05-01.03.07 | 27.06.15 |
| 150,000 | – | – | – | 28.06.05 | 150,000 | 36p | 50p | 28.06.05-01.03.06 | 27.06.15 | |
| 250,000 | – | – | – | 28.06.05 | 250,000 | 36p | 100p | 28.06.05-01.03.07 | 27.06.15 | |
| 200,000 | – | – | – | 30.05.06 | 200,000 | 63p | 63p | 30.05.07-30.05.09 | 29.05.16 | |
| 300,000 | – | – | – | 26.06.07 | 300,000 | 67.5p | 70p | 26.06.08-26.06.10 | 25.06.17 | |
| 250,000 | – | – | – | 25.04.08 | 250,000 | 144.5p | 150p | 25.04.09-25.04.11 | 25.04.18 | |
| 750,000 | – | – | – | 25.04.08 | 750,000 | 144.5p | 190p | 25.04.09-25.04.11 | 25.04.18 | |
| 1,250,000 | – | – | – | 23.01.09 | 1,250,000 | 20.25p | 23.25p | 23.01.10-23.01.12 | 23.01.19 | |
| 2,750,000 | – | – | – | 30.12.09 | 2,750,000 | 84.75p | 84.75p | 30.12.10-30.12.12 | 30.12.19 | |
| O Shahenshah | 1,150,000 | – | – | – | 28.06.05 | 1,150,000 | 36p | 20p | 28.06.05-01.03.07 | 27.06.15 |
| 850,000 | – | – | – | 28.06.05 | 850,000 | 36p | 50p | 28.06.05-01.03.06 | 27.06.15 | |
| 550,000 | – | – | – | 28.06.05 | 550,000 | 36p | 100p | 28.06.05-01.03.07 | 27.06.15 | |
| 600,000 | – | – | – | 30.05.06 | 600,000 | 63p | 63p | 30.05.07-30.05.09 | 29.05.16 | |
| 416,666 | – | – | – | 28.03.07 | 416,666 | 53.5p | 80p | 28.03.07-28.03.10 | 27.03.17 | |
| 416,667 | – | – | – | 28.03.07 | 416,667 | 53.5p | 120p | 28.03.07-28.03.10 | 27.03.17 | |
| 416,667 | – | – | – | 28.03.07 | 416,667 | 53.5p | 180p | 28.03.07-28.03.10 | 27.03.17 | |
| 3,000,000 | – | – | – | 23.01.09 | 3,000,000 | 20.25p | 23.3p | 23.01.10-23.01.12 | 23.01.19 | |
| 5,800,000 | – | – | – | 30.12.09 | 5,800,000 | 84.75p | 84.8p | 30.12.10-30.12.12 | 30.12.19 | |
| S Ullah | 1,500,000 | – | – | – | 23.01.09 | 1,500,000 | 20.25p | 23.25p | 23.01.10-23.01.12 | 23.01.19 |
| 1,500,000 | – | – | – | 30.12.09 | 1,500,000 | 84.75p | 84.75p | 30.12.10-30.12.12 | 30.12.19 | |
| D Comyn | 650,000 | – | – | – | 30.12.09 | 650,000 | 84.75p | 84.75p | 30.12.10-30.12.12 | 30.12.19 |
| – | 1,200,000 | – | – | 29.03.10 | 1,200,000 | 103p | 103.00p | 29.03.11-29.03.13 | 28.03.20 | |
| P Bingham | 125,000 | – | – | – | 28.06.05 | 125,000 | 36p | 50p | 28.06.05-01.03.06 | 27.06.15 |
| 130,000 | – | – | – | 28.06.05 | 130,000 | 36p | 100p | 28.06.05-01.03.07 | 27.06.15 | |
| 145,000 | – | – | – | 21.06.07 | 145,000 | 69p | 70p | 21.06.07-21.06.08 | 20.06.17 | |
| J St. John | 400,000 | – | – | – | 21.06.07 | 400,000 | 69p | 70p | 21.06.07-21.06.09 | 20.06.17 |
| Total | 27,150,000 | 1,200,000 | – | – | 28,350,000 |
* Seconded to FHN and stepped down as Director of Afren plc on 4 January 2011.
There have been no variations to the terms and conditions or performance criteria for the share options during the financial year.
In relation to the grant of share options, John St. John and Peter Bingham were appointed Non-Executive Directors and awarded share options whilst the Company was AIM listed on the basis that their experience and support to the executive team in relation to technical and financial expertise would, and will continue, to add significant value to the business. Whilst they retain options granted whilst the Company was AIM listed, the rules have been amended such that no additional share options will be granted to Non-Executive Directors. No further options have been granted to any Non-Executive Director following admission to the Official List of the United Kingdom Listing Authority and the Share Option Scheme Rules were amended in November 2009 to prohibit the grant of share options to Non-Executive Directors.
Governance
continued
The options granted on 28 June 2005, 28 March 2007, 25 April 2008 and those granted to Peter Bingham on 21 June 2007 have no performance criteria attached to them. Those granted to John St. John on 21 June 2007 only vest if a closing share price for the Company of over £1.00 has been achieved for a three-month period. The options granted on 30 May 2006 will only vest if the share price has increased by 40% over the market price at date of grant for a period of ten days. The options granted on 23 January 2009 and 30 December 2009 will only vest if the share price has increased by 40% over the market price at date of grant for a period of three months.
On 1 June 2008 and 19 June 2009, awards were granted to Afren Directors and employees under the Afren Performance Share Plan. Awards were granted to each eligible member of the scheme that will vest in full only if Afren achieves top quartile performance against its peers of oil and gas upstream companies over a three-year period, based on Total Shareholder Return (TSR). No part of an award will vest if Afren does not at least perform at the median level. At the median level, 30% of the awards will vest and there is a straight-line calculation between the median level and the top quartile. Awards to date under this scheme were as follows:
| Date of grant | Date of vesting | Market price at date of grant |
Maximum number of shares |
|
|---|---|---|---|---|
| O Shahenshah | 01.06.2008 | 01.06.2011 | £1.66 | 361,446 |
| 19.06.2009 | 19.06.2012 | £0.43 | 1,526,012 | |
| C Ogunbiyi | 01.06.2008 | 01.06.2011 | £1.66 | 240,964 |
| 19.06.2009 | 19.06.2012 | £0.43 | 1,017,341 | |
| S Ullah | 19.06.2009 | 19.06.2012 | £0.43 | 1,322,600 |
| E Imomoh | 01.06.2008 | 01.06.2011 | £1.66 | 271,084 |
The closing market price of the ordinary shares at 31 December 2010 was 147.6p and the range during the year was 79p to 147.6p.
On joining in April 2008, Shahid Ullah was granted 2,025,000 shares to be issued at nominal consideration subject to certain time constraints. Of these, 1,462,500 were issued during 2009 with 187,500 outstanding as at 31 December 2009. These final shares were all issued in January 2010.
This report was approved by the Board of Directors on 29 March 2011 and signed on its behalf by:
Chairman, Remuneration Committee 29 March 2011
The Directors are responsible for preparing the Annual Report and the financial statements in accordance with applicable law and regulations.
Company law requires the Directors to prepare such financial statements for each financial year. Under that law the Directors are required to prepare Group financial statements in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union and Article 4 of the IAS Regulation and have also chosen to prepare the Parent Company financial statements under IFRS as adopted by the European Union. Under company law the Directors must not approve the accounts unless they are satisfied that they give a true and fair view of the state of affairs of the company and of the profit and loss of the Company for that period. In preparing these financial statements, the Directors are required to:
The Directors are responsible for keeping proper accounting records that are sufficient to show and explain the Company's transactions and disclose with reasonable accuracy at any time the financial position of the Company and enable them to ensure that the financial statements comply with the Companies Act 2006. They are also responsible for safeguarding the assets of the Company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.
The Directors are responsible for the maintenance and integrity of the corporate and financial information included on the Company's website. Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.
I confirm to the best of my knowledge:
By order of the Board
Osman shahenshah Chief Executive Officer 29 March 2011
to the members of Afren plc
We have audited the financial statements of Afren plc for the year ended 31 December 2010 which comprise the Group Income Statement, the Group Statement of Comprehensive Income, the Group and Parent Company Balance Sheets, the Group and Parent Company Cash Flow Statements, the Group and Parent Company Statements of Changes in Equity and the related notes 1 to 35. The financial reporting framework that has been applied in their preparation is applicable law and International Financial Reporting Standards (IFRS) as adopted by the European Union.
This report is made solely to the Company's members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work has been undertaken so that we might state to the Company's members those matters we are required to state to them in an auditors' report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the Company's members as a body, for our audit work, for this report, or for the opinions we have formed.
As explained more fully in the Directors' Responsibilities Statement, the Directors are responsible for the preparation of the financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit the financial statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the Auditing Practices Board's (APB's) Ethical Standards for Auditors.
An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting policies are appropriate to the Group's and the Parent Company's circumstances and have been consistently applied and adequately disclosed; the reasonableness of significant accounting estimates made by the Directors; and the overall presentation of the financial statements. In addition, we read all the financial and non-financial information in the annual report to identify material inconsistencies with the audited financial statements. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report.
In our opinion:
In our opinion:
We have nothing to report in respect of the following:
Under the Companies Act 2006 we are required to report to you if, in our opinion:
Under the Listing Rules we are required to review:
Bevan whitehead (Senior Statutory Auditor) for and on behalf of Deloitte LLP Chartered Accountants and Statutory Auditors London, UK 29 March 2011
For the year ended 31 December 2010
| Notes | 2010 us\$000's |
2009 US\$000's |
|
|---|---|---|---|
| Revenue | 5 | 319,447 | 335,818 |
| Cost of sales | (190,451) | (230,036) | |
| Gross profit | 128,996 | 105,782 | |
| Administrative expenses | (29,500) | (27,215) | |
| Other operating (expenses)/income | |||
| – derivative financial instruments | 21 | (8,894) | (33,635) |
| – impairment (charge)/reversal of oil and gas assets | 6 | (1,614) | 859 |
| Operating profit | 7 | 88,988 | 45,791 |
| Investment revenue | 9 | 298 | 626 |
| Finance costs | 10 | (11,320) | (36,950) |
| Other gains and (losses) | |||
| – foreign currency gains/(losses) | 305 | (2,770) | |
| – fair value of financial liabilities and financial assets | 21 | (8,100) | (5,034) |
| – impairment reversal on available for sale investments | – | 97 | |
| Share of gain/(loss) of associates | 15 | 8,625 | (1,277) |
| Profit from continuing operations before tax | 78,796 | 483 | |
| Income tax expense | 28 | (32,923) | (17,261) |
| Profit/(loss) from continuing operations after tax | 45,873 | (16,778) | |
| Discontinued operations | |||
| Loss for the period from discontinued operations | 23 | (614) | – |
| Profit/(loss) for the period | 45,259 | (16,778) |
| Profit/(loss) per share from continuing operations | |||
|---|---|---|---|
| Basic | 11 | 5.1c | (2.6c) |
| Diluted | 11 | 4.9c | (2.6c) |
| Profit/(loss) per share from continuing and discontinued operations | |||
| Basic | 11 | 5.0c | (2.6c) |
| Diluted | 11 | 4.8c | (2.6c) |
For the year ended 31 December 2010
| 2010 us\$000's |
2009 US\$000's |
|
|---|---|---|
| Profit/(loss) after tax | 45,259 | (16,778) |
| Total comprehensive profit/(loss) attributable to equity holders of Afren plc | 45,259 | (16,778) |
| Group | Company | |||||
|---|---|---|---|---|---|---|
| Notes | 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
||
| assets | ||||||
| Non-current assets | ||||||
| Intangible oil and gas assets | 12 | 443,761 | 184,161 | – | – | |
| Property, plant and equipment | ||||||
| – Oil and gas assets | 13 | 759,167 | 486,672 | – | – | |
| – Other | 13 | 6,919 | 6,996 | 2,387 | 2,711 | |
| Prepayments | 18 | 1,983 | 3,383 | – | – | |
| Investments in subsidiaries | 14 | – | – | 202,238 | 54,128 | |
| Derivative financial instruments | 21 | – | 2,153 | – | – | |
| Investments in associates | 15 | 11,227 | 604 | – | 604 | |
| 1,223,057 | 683,969 | 204,625 | 57,443 | |||
| Current assets | ||||||
| Inventories | 16 | 39,055 | 34,564 | – | – | |
| Trade and other receivables | 18 | 41,343 | 55,614 | 723,642 | 485,415 | |
| Derivative financial instruments | 21 | – | 4,523 | – | – | |
| Cash and cash equivalents | 19 | 140,221 | 321,312 | 5,258 | 203,117 | |
| 220,619 | 416,013 | 728,900 | 688,532 | |||
| Assets held for sale | 23 | 2,812 | – | – | – | |
| Total assets | 1,446,488 | 1,099,982 | 933,525 | 745,975 | ||
| liabilities | ||||||
| Current liabilities | ||||||
| Trade and other payables | 20 | (216,037) | (134,739) | (75,804) | (61,226) | |
| Borrowings | 21 | (89,254) | (117,634) | – | – | |
| Derivative financial instruments | 21 | (4,927) | (5,240) | – | – | |
| (310,218) | (257,613) | (75,804) | (61,226) | |||
| Net current (liabilities)/assets | (86,787) | 158,400 | 653,096 | 627,306 | ||
| non-current liabilities | ||||||
| Provision for decommissioning | 22 | (35,119) | (21,836) | – | – | |
| Deferred tax liabilities | 25 | (63,470) | (12,460) | – | – | |
| Borrowings | 21 | (178,467) | (149,446) | – | – | |
| Derivative financial instruments | 21 | (499) | (379) | – | – | |
| (277,555) | (184,121) | – | – | |||
| Total liabilities | (587,773) | (441,734) | (75,804) | (61,226) | ||
| Net assets | 858,715 | 658,248 | 857,721 | 684,749 | ||
| Equity | ||||||
| Share capital | 27 | 17,007 | 15,702 | 17,007 | 15,702 | |
| Share premium | 27 | 896,812 | 755,169 | 896,812 | 755,169 | |
| Other reserves | 32 | 22,764 | 17,272 | 25,198 | 19,706 | |
| Accumulated losses | 33 | (77,868) | (129,895) | (81,296) | (105,828) | |
| Total equity | 858,715 | 658,248 | 857,721 | 684,749 |
The financial statements of Afren plc, registered number 05304498 were approved by the Board of Directors and authorised for issue on 29 March 2011. They were signed on its behalf by:
darra comyn Group Finance Director 29 March 2011
| Group | Company | ||||
|---|---|---|---|---|---|
| Notes | 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
|
| Operating profit/(loss) for the year | 88,988 | 45,791 | (22,952) | (28,407) | |
| Depreciation, depletion and amortisation | 93,979 | 154,783 | 1,355 | 862 | |
| Derivative financial instruments | 6,482 | 48,458 | – | – | |
| Impairment of oil and gas assets | 1,614 | (859) | – | – | |
| Share-based payments charge | 8,333 | 9,292 | 6,945 | 6,767 | |
| Operating cash flows before movements in working capital | 199,396 | 257,465 | (14,652) | (20,778) | |
| Cash used by operating activities held for sale | (28) | – | – | – | |
| Decrease/(increase) in trade and other operating receivables | 16,046 | 533 | (10,358) | (1,416) | |
| (Decrease)/increase in trade and other operating payables | (11,793) | 31,761 | 3,968 | 16,744 | |
| Decrease/(increase) in inventory – crude oil | 5,895 | (11,588) | – | – | |
| Currency translation adjustments | (199) | 117 | (10) | 76 | |
| Net cash generated/(used) in operating activities | 209,317 | 278,288 | (21,052) | (5,374) | |
| Purchases of property, plant and equipment: | |||||
| – oil and gas assets | (295,443) | (97,810) | – | (1,274) | |
| – other | (3,209) | (3,770) | (1,031) | – | |
| Exploration and evaluation expenditure | (59,739) | (90,365) | – | – | |
| Advances to Group undertakings | – | – | (171,222) | (133,312) | |
| Investment in subsidiaries | – | – | (7,799) | (4,060) | |
| Increase in inventories – spare parts | (10,386) | (9,700) | – | – | |
| Purchase of investments | (1,998) | (1,815) | – | (1,815) | |
| Investment revenue | 298 | 599 | 209 | 521 | |
| Completion payment on 2008 acquired subsidiaries | – | (6,198) | – | – | |
| Acquisition of subsidiaries in 2010, net of cash acquired | 31 | 2,289 | – | – | – |
| Net cash used in investing activities | (368,188) | (209,059) | (179,843) | (139,940) | |
| Issue of ordinary share capital | 5,191 | 326,969 | 5,191 | 326,969 | |
| Costs of share issues | (2,381) | (14,236) | (2,381) | (14,236) | |
| Net proceeds from borrowings | 100,217 | – | – | – | |
| Repayment of borrowings | (110,970) | (148,447) | – | – | |
| Interest and financing fees paid | (14,493) | (26,870) | – | (49) | |
| Net cash (used) in/from financing activities | (22,436) | 137,416 | 2,810 | 312,684 | |
| Net (decrease)/increase in cash and cash equivalents | (181,307) | 206,645 | (198,085) | 167,370 | |
| Cash and cash equivalents at beginning of year | 321,312 | 117,719 | 203,117 | 39,106 | |
| Effect of foreign exchange rate changes | 216 | (3,052) | 226 | (3,359) | |
| Cash and cash equivalents at end of year | 19 | 140,221 | 321,312 | 5,258 | 203,117 |
For the year ended 31 December 2010
| Share | |||||
|---|---|---|---|---|---|
| Share | premium | Other | Accumulated | Total | |
| capital | account | reserves | losses | equity | |
| US\$000's | US\$000's | US\$000's | US\$000's | US\$000's | |
| group | |||||
| At 1 January 2009 | 8,806 | 446,958 | 18,173 | (122,991) | 350,946 |
| Issue of share capital | 6,896 | 322,447 | – | – | 329,343 |
| Deductible costs of share issues | – | (14,236) | – | – | (14,236) |
| Share-based payments for services | – | – | 9,197 | – | 9,197 |
| Other share-based payments | – | – | 95 | – | 95 |
| Reserves transfer relating to loan notes | – | – | (2,312) | 2,312 | – |
| Reserves transfer on exercise of options, awards and LTIP | – | – | (4,792) | 4,792 | – |
| Reserves transfer on exercise of warrants | – | – | (2,770) | 2,770 | – |
| Other movements | – | – | (319) | – | (319) |
| Net loss for the year | – | – | – | (16,778) | (16,778) |
| Balance at 31 December 2009 | 15,702 | 755,169 | 17,272 | (129,895) | 658,248 |
| Issue of share capital | 1,305 | 144,024 | – | – | 145,329 |
| Deductible costs of share issues | – | (2,381) | – | – | (2,381) |
| Share-based payments for services | – | – | 9,359 | – | 9,359 |
| Other share-based payments | – | – | 313 | – | 313 |
| Reserves transfer relating to loan notes | – | – | (2,474) | 2,474 | – |
| Reserves transfer on exercise of options, awards and LTIP | – | – | (2,206) | 2,206 | – |
| Exercise of warrants designated as financial liabilities | – | – | – | 2,088 | 2,088 |
| Shares to be issued | – | – | 500 | – | 500 |
| Net profit for the year | – | – | – | 45,259 | 45,259 |
| Balance at 31 December 2010 | 17,007 | 896,812 | 22,764 | (77,868) | 858,715 |
| Share | |||||
|---|---|---|---|---|---|
| Share | premium | Other | Accumulated | Total | |
| capital | account | reserves | losses | equity | |
| US\$000's | US\$000's | US\$000's | US\$000's | US\$000's | |
| company | |||||
| At 1 January 2009 | 8,806 | 446,958 | 20,607 | (87,233) | 389,138 |
| Issue of share capital | 6,896 | 322,447 | – | – | 329,343 |
| Deductible costs of share issues | – | (14,236) | – | – | (14,236) |
| Share-based payments for services | – | – | 9,197 | – | 9,197 |
| Other share-based payments | – | – | 95 | – | 95 |
| Reserves transfer relating to loan notes | – | – | (2,312) | 2,312 | – |
| Reserves transfer on exercise of options, awards, warrants and LTIP | – | – | (7,562) | 7,562 | – |
| Other movements | – | – | (319) | – | (319) |
| Net loss for the year | – | – | – | (28,469) | (28,469) |
| Balance at 31 December 2009 | 15,702 | 755,169 | 19,706 | (105,828) | 684,749 |
| Issue of share capital | 1,305 | 144,024 | – | – | 145,329 |
| Deductible costs of share issues | – | (2,381) | – | – | (2,381) |
| Share-based payments for services | – | – | 9,359 | – | 9,359 |
| Other share-based payments | – | – | 313 | – | 313 |
| Reserves transfer relating to loan notes | – | – | (2,474) | 2,474 | – |
| Reserves transfer on exercise of options, awards, warrants and LTIP | – | – | (2,206) | 2,206 | – |
| Exercise of warrants designated as financial liabilities | – | – | – | 2,088 | 2,088 |
| Shares to be issued | – | – | 500 | – | 500 |
| Net profit for the year | – | – | – | 17,764 | 17,764 |
| Balance at 31 December 2010 | 17,007 | 896,812 | 25,198 | (81,296) | 857,721 |
For the year ended 31 December 2010
Afren plc (the Company or the Group) is a company incorporated in the United Kingdom under the Companies Act. The address of the registered office is given on the inside back cover. The nature of the Group's operations and its principal activities are set out in note 4 and in the Chairman and Chief Executive's Statement and Review of Operations on pages 14 and 26 These financial statements are presented in US dollars because that is the currency of the primary economic environment in which the Group operates. Foreign operations are included in accordance with the policies set out in note 2.
In the current financial year, the Group has adopted International Financial Reporting Standard 3 ''Business combinations'' (revised 2008) and International Accounting Standard 27 ''Consolidated and Separate Financial Statements'' (revised 2008).
The most significant changes to the Group's previous accounting policies for business combinations are as follows:
At the date of authorisation of these financial statements, the following Standards, amendments and Interpretations which have not been applied in these financial statements were in issue but are not yet effective (and in some cases had not yet been adopted by the EU):
| IFRS 9 | Financial Instruments |
|---|---|
| IAS 24 (amended) | Related Party Disclosures |
| IAS 32 (amended) | Classification of Rights Issues |
| IFRIC 14 (amended) | Prepayment of a Minimum Funding Requirement |
| IFRIC 19 | Extinguishing Financial Liabilities with Equity Instruments |
| Improvements to IFRSs (May 2010) |
The adoption of IFRS 9 will impact both the measurement and disclosure of financial instruments. No decision will be made by the Group on early adoption until all phases of the standard are complete. The Directors anticipate that the adoption of the other Standards and Interpretations in future periods will have no material impact on the financial position of the Group.
The financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS). The financial statements have also been prepared in accordance with IFRS adopted by the European Union and therefore the Group financial statements comply with Article 4 of the EU IAS Regulation.
The financial statements have been prepared on the historical cost basis, except for the revaluation of certain financial instruments and oil inventory which is subject to certain commodity swap arrangements that have been measured at fair value.
The financial statements have been prepared in accordance with the going concern basis of accounting. The use of this basis of accounting takes into consideration the Group's current and forecast financing position, additional details of which are provided in the Going Concern section of the Directors' Report.
The consolidated financial statements incorporate the financial statements of the Company and entities controlled by the Company (its subsidiaries) made up to the 31 December each year. Control is achieved where the Company has the power to govern the financial and operational policies of an entity so as to gain benefit from its activities. Entities over which the Company exercises joint control are accounted for using proportional consolidation, under which the Group records its share of revenue, expenditure, assets and liabilities.
The results of subsidiaries acquired or disposed of during the year are included in the consolidated income statement from the effective date of acquisition or up to the effective date of disposal, as appropriate. Where necessary, adjustments are made to the financial statements of the subsidiaries to bring the accounting policies used into line with those used by the Group. All intra-group transactions, balances, income and expenses are eliminated on consolidation.
As a consolidated Group income statement is published, a separate profit and loss account for the Parent Company has not been published in accordance with section 408 of the Companies Act 2006.
Acquisitions of subsidiaries and businesses are accounted for using the acquisition method. The consideration for each acquisition is measured at the aggregate of the fair values (at the date of exchange) of assets given, liabilities incurred or assumed, and equity instruments issued by the Group in exchange for control of the acquiree. Acquisition-related costs are recognised in profit or loss as incurred.
Where applicable, the consideration for the acquisition includes any asset or liability resulting from a contingent consideration arrangement, measured at its acquisition-date fair value. Subsequent changes in such fair values are adjusted against the cost of acquisition where they qualify as measurement period adjustments (see below). All other subsequent changes in the fair value of contingent consideration classified as an asset or liability are accounted for in accordance with relevant IFRSs. Changes in the fair value of contingent consideration classified as equity are not recognised.
Where a business combination is achieved in stages, the Group's previously-held interests in the acquired entity are remeasured to fair value at the acquisition date (i.e. the date the Group attains control) and the resulting gain or loss, if any, is recognised in profit or loss. Amounts arising from interests in the acquiree prior to the acquisition date that have previously been recognised in other comprehensive income are reclassified to profit or loss, where such treatment would be appropriate if that interest were disposed of.
The acquiree's identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3(2008) are recognised at their fair value at the acquisition date, except that:
If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the Group reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted during the measurement period (see below), or additional assets or liabilities are recognised, to reflect new information obtained about facts and circumstances that existed as of the acquisition date that, if known, would have affected the amounts recognised as of that date.
The measurement period is the period from the date of acquisition to the date the Group obtains complete information about facts and circumstances that existed as of the acquisition date, and is subject to a maximum of one year.
Goodwill arising in a business combination is recognised as an asset at the date that control is acquired. Goodwill is measured as the excess of the sum of the consideration transferred, the amount of any non-controlling interest in the acquiree and the fair value of the acquirer's previously held equity interest (if any) in the entity over the net of the acquisition-date amounts of the identifiable assets acquired and the liabilities assumed. Management generally assigns fair values to intangible exploration and evaluation assets to equal the excess of the purchase price consideration over and above the other assets and liabilities acquired, when this represents the most reliable indication of fair value. As a consequence, no goodwill arises.
Property, plant and equipment are stated at cost less depreciation and any provision for impairment.
Depreciation is provided at rates calculated to write off the cost of the tangible fixed assets, less anticipated disposal proceeds, on a straight-line basis over their estimated useful economic life as follows:
| Leasehold improvements | over life of lease |
|---|---|
| Fixtures and equipment | over three years |
| Computer hardware and software | over three years |
| Gas plant | over six and a quarter years |
The Group follows the successful efforts method of accounting for intangible exploration and evaluation (E&E) costs. All licence acquisition, exploration and evaluation costs are initially capitalised as intangible fixed assets in cost centres by field or exploration area, as appropriate, pending determination of commerciality of the relevant property. Directly attributable administration costs are capitalised insofar as they relate to specific exploration activities. Pre-licence costs and general exploration costs not specific to any particular licence or prospect are expensed as incurred.
If prospects are deemed to be impaired ('unsuccessful') on completion of the evaluation, the associated costs are charged to the income statement. If the field is determined to be commercially viable, the attributable costs are transferred to property, plant and equipment in single field cost centres. These costs are then depreciated on a unit of production basis.
All field development costs are capitalised as property, plant and equipment. Property, plant and equipment related to production activities are amortised in accordance with the Group's depletion and amortisation accounting policy.
For the year ended 31 December 2010 continued
Revenue represents the sales value, net of VAT and royalties paid in kind or where the financial obligation does not fall directly to Afren, of the Group's share of oil liftings in the year together with gas and tariff income and interest income. Oil and gas revenue is recognised when goods are delivered and title has passed. Interest income is accrued on a time basis by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount.
Commercial reserves are proven and probable oil and gas reserves, which are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as a proven and probable reserves and a 50% statistical probability that it will be less.
All expenditure carried within each field is amortised from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a field-by-field basis. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future field development costs. Changes in the estimates of commercial reserves or future field development costs are dealt with prospectively.
Where there has been a change in economic conditions that indicates a possible impairment in a discovery field, the recoverability of the net book value relating to that field is assessed by comparison with the estimated discounted future cash flows based on management's expectations of future oil and gas prices and future costs.
Any impairment identified is charged to the income statement as additional depletion and amortisation. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit to the income statement, net of any depreciation that would have been charged since the impairment.
Provision for decommissioning is recognised in full when the related facilities are installed. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related property, plant and equipment. The amount recognised is the estimated cost of decommissioning, discounted to its net present value, and is reassessed each year in accordance with local conditions and requirements.
Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to property, plant and equipment.
The unwinding of the discount on the decommissioning is included as a finance cost.
Non-current assets are assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Such triggering events are defined in IFRS 6 in respect of E&E assets and include the point at which determination is made as to whether commercial reserves exist.
Where there has been an indication of a possible impairment, management assesses the recoverability of the carrying value of the asset by comparison with the estimated discounted future net cash flows based on management's expectation of future production, oil prices and costs. Any identified impairment is charged to the income statement.
Investment in subsidiaries held by the Company as fixed assets are stated at cost less any provision for impairment.
The individual financial statements of each Group company are presented in the currency of the primary economic environment in which it operates (its functional currency). For the purpose of consolidated financial statements, the results and financial position of each Group company are expressed in US dollars which is the functional currency of the Company and the presentational currency for the consolidated financial statements of the Group.
In preparing the financial statements of the individual companies, transactions in currencies other than the entity's functional currency (foreign currencies) are recorded at the rate of exchange prevailing on the dates of the transactions. At each balance sheet date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing at that date. Non-monetary items carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated. Exchange differences arising are included in the profit and loss for the period.
For the purposes of presenting consolidated financial statements, the assets and liabilities of each Group company are translated into US dollars at exchange rates prevailing on the balance sheet date. Income and expense items are translated at the average exchange rates for the period. Exchange differences (if any) arising are recognised in other comprehensive income and accumulated in equity. Such translation differences are recognised as income or as expense in the period in which the operation is disposed of. At present the Group has no subsidiaries with functional currencies other than US dollars.
Annual Report and Accounts 2010
Rentals under operating leases are charged to the income statement on a straight-line basis over the period of the relevant lease.
The tax expense represents the sum of tax currently payable and deferred tax.
The tax currently payable is based on taxable profit for the year. The Group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised.
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.
Deferred tax is calculated at the rates of tax expected to apply in the period when the liability is settled or the asset realised.
The Group makes equity-settled share-based payments to certain employees, Directors and other third parties. Equity-settled share-based schemes are measured at fair value (excluding the effect of non market-based vesting conditions) at the date of grant, measured by use of an appropriate valuation model. The expected life used in the model has been adjusted, based on management's best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations.
The fair value determined at the grant date of the equity-settled share-based payments is expensed on a straight-line basis over the period to exercise, based on the Group's estimate of shares that will eventually vest.
The Company is liable for Employer's National Insurance on the difference between the market value at date of exercise and exercise price. This expense is accrued by reference to the share price of the Company at the balance sheet date.
Payments to a defined contribution pension scheme are charged as an expense as they fall due.
Inventories (spare parts) are stated at the lower of cost and net realisable value. Costs comprise direct materials and, where applicable, direct labour costs and those overheads that have been incurred in bringing the inventories to their present location and condition. The cash flows associated with the purchase of spare parts are classified in investment activities with the oil and gas assets. Net realisable value represents the estimated selling price less costs to be incurred in marketing, selling and distribution.
Inventories (oil and butane inventories) are stated at the lower of cost and net realisable value other than certain oil inventory in Côte d'Ivoire, which is settled via a reduction in the amount recoverable in respect of realised gas sales from the Lion Gas Plant. The inventory subject to this swap is recorded at its fair value.
Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.
Financial costs of debt are allocated to periods over the term of the related debt at a constant rate on the carrying amount. Arrangement fees and issue costs are deducted from the debt proceeds on initial recognition of the liability and are amortised and charged to the income statement as finance costs over the term of the debt.
All other borrowing costs are recognised in profit or loss in the period in which they are incurred.
Financial assets and financial liabilities are recognised on the Group's balance sheet when the Group becomes party to the contractual provisions of the instrument.
The Group has entered into swaps and call options to economically protect against exposures to variability in the price of a proportion of Okoro and Côte d'Ivoire crude oil production for 2008 to 2012. Derivative financial instruments are stated at fair value. The gains and losses arising out of changes in fair value of these derivative financial instruments together with settlements in the period are accounted for in other operating income/(expense) in the income statement in the period in which they are incurred.
For the year ended 31 December 2010 continued
Available for sale investments are initially measured at cost, including transaction costs. Gains and losses arising from changes in fair value of available for sale investments are recognised directly in equity, until the security is disposed of or is determined to be impaired, at which time the cumulative gain or loss previously recognised in equity is included in the profit or loss for the period.
Trade receivables are measured at initial recognition at their fair value. Appropriate allowances for estimated irrecoverable amounts are recognised in the income statement when there is objective evidence that the asset is impaired.
Cash and cash equivalents comprise cash on hand, demand deposits and other short-term highly liquid investments that are readily convertible to a known amount of cash and are subject to an insignificant risk of change in value.
Trade payables are stated at amortised cost.
Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities. Equity instruments issued by the Company are recorded at the proceeds received net of direct issue costs.
An associate is an entity over which the Group is in a position to exercise significant influence, but not control or joint control, through participation in the financial and operating policy decisions of the investee. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies.
The results and assets and liabilities of associates are incorporated using the equity method of accounting except when classified as held for sale. Investments in associates are carried in the balance sheet at cost as adjusted by post acquisition changes in the Group's share of the net assets of the associate, less any impairment in the value of individual investments. Losses of an associate in excess of the Group's interest in that associate (which includes any long-term interests that, in substance, form part of the Group's net investment in the associate) are recognised only to the extent that the Group has incurred legal or constructive obligations to make or has made payments on behalf of the associate.
Any excess of the cost of acquisition over the Group's share of the fair values of the identifiable net assets of the associate at the date of acquisition is recognised as goodwill. The goodwill is included within the carrying amount of the investment and is assessed for impairment as part of that investment. Any excess of the Group's share of the fair values of the identifiable net assets of the associate at the date of acquisition above the cost of acquisition (i.e. discount on acquisition) is credited in profit or loss in the period of acquisition.
Where a Group company transacts with an associate of the Group, profits and losses are eliminated to the extent of the Group's interest in the relevant associate. Losses may provide evidence of an impairment of the asset transferred, in which case appropriate provision is made for impairment.
Convertible bonds and loan notes are regarded as compound instruments, consisting of a liability component and an equity component. At the date of issue, the fair value of the liability component is estimated using the prevailing market interest rate for similar non-convertible debt. The difference between the proceeds of issue of the convertible bonds or loan notes and the fair value assigned to the liability component, representing the embedded option to convert the liability into equity of the Group, is included in equity. Issue costs are apportioned between the liability and equity components of the convertible loan notes based on their relative carrying amounts at the date of issue. The portion relating to the equity component is charged directly against equity.
The interest expense on the liability component is calculated by applying the prevailing market interest rate for similar non-convertible debt to the liability component of the instrument. The difference between this amount and the interest paid is added to the carrying amount of the convertible loan note.
Non-current assets and disposal groups are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the non-current asset(or disposal group) is available for immediate sale in its present condition and the sale is expected to be completed within one year of the classification.
Non-current assets (and disposal groups) classified as held for sale are measured at the lower of their carrying amount and fair value less costs to sell.
In the application of the Group's accounting policies, which are described in note 2, the Directors are required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates. The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions 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 following are the critical judgements, key assumptions and other key sources of estimation uncertainty at the balance sheet date that may have a significant effect on the amounts recognised in the financial statements.
Management is required to assess the oil and gas assets for indicators of impairment. Note 13 discloses the carrying value of tangible oil and gas assets. As part of this assessment, management has carried out an impairment test (ceiling test) on the tangible oil and gas assets (Okoro Setu, Ebok and Côte d'Ivoire assets). This test compares the carrying value of the assets at the balance sheet date with the expected discounted cash flows from each project. For the discounted cash flows to be calculated, management has used a production profile based on its best estimate of proven and probable reserves of the assets and a range of assumptions, including an internal oil price profile benchmarked to mean analysts' consensus and a 10% discount rate which, taking into account other assumptions used in the calculation, management considers to be reflective of the risks.
Management is required to assess impairment in respect of intangible exploration and evaluation assets. Note 12 discloses the carrying value of such assets. The triggering events are defined in IFRS 6. In making the assessment, management is required to make judgements on the status of each project and the future plans towards finding commercial reserves. The nature of exploration and evaluation activity is such that only a proportion of projects are ultimately successful and some assets are likely to become impaired in future periods.
Management is required to make assumptions in respect of the inputs used to calculate the fair values of share-based payment arrangements. Details of these can be found in note 30.
The assets and liabilities acquired following the completion of Black Marlin Energy Holdings Limited acquisition by the Company have been recorded at fair value at the completion date, as outlined further in note 31. The estimates of such fair values required significant judgement to be applied, particularly in respect of intangible exploration and evaluation assets. Management generally assigns fair values to intangible exploration and evaluation assets to equal the excess of the purchase price consideration over and above the other assets and liabilities acquired, when this represents the most reliable indication of fair value. As a consequence, no goodwill arises. The amounts are provisional, and may be revised within 12 months of the acquisition.
The Group has decommissioning obligations in Nigeria and Côte d'Ivoire. The extent to which a provision is required depends on the legal requirements at the date of decommissioning, the costs and timing of work and the discount rate to be applied. The decommissioning provision will be updated each year to reflect Management's best estimates.
The application of tax legislation in jurisdictions in which the Group operates can be uncertain and subject to interpretation. As disclosed in note 28, the Group has significant tax liabilities which may be subject to revision as the Group's tax filings are agreed with the relevant authorities in future periods.
In respect of financial risk management, at the balance sheet date, the Group's principal financial assets are cash and cash equivalents, trade and other receivables and any derivative asset. The Group manages liquidity risk by ensuring that sufficient funds are available to meet its commitments as they fall due. The Group uses projected cash flows to monitor funding requirements for the Group's activities. Additional details in respect of the Group's financing facilities are in note 21.
The Group's exposure to the risk of changes in market interest rates is mitigated by regular reviews of available fixed and variable rate debts and taking the most favourable for the Group's needs. The interest on borrowings from BNP Paribas, Sojitz and FCMB is based on LIBOR plus a margin and therefore the interest charged is affected by movement in LIBOR.
Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Group. The Group reviews the credit risk of the entities that it sells its products to or that it enters into contractual arrangements with and will obtain guarantees and commercial letters of credit as may be considered necessary where risks are significant to the Group. The Group's business is diversified in terms of both region and the number of counterparties and, other than transactions with major oil companies with high credit rating and government organisations in Côte d'Ivoire, the Group does not have significant exposure to any single counterparty or group of counterparties with similar characteristics. The credit risk on cash is limited because the majority is deposited with banks with good credit ratings assigned by international credit rating agencies or with governmental guarantee. The Group's total maximum exposure to credit risk as at 31 December 2010 was US\$171.3 million (2009: US\$ 369.6 million) made up of cash and bank balances and trade and other receivables (excluding prepayments).
For the year ended 31 December 2010 continued
For management purposes, the Group currently operates in four geographical markets: Nigeria, Côte d'Ivoire, Other West Africa and Eastern Africa. Unallocated operating expenses, assets and liabilities relate to the general management, financing and administration of the Group.
| 2010 | Nigeria US\$000's |
Côte d'Ivoire US\$000's |
Other West Africa US\$000's |
Eastern Africa US\$000's |
Unallocated US\$000's |
Consolidated US\$000's |
|---|---|---|---|---|---|---|
| Sales revenue by origin | 286,546 | 32,568 | – | 131 | 202 | 319,447 |
| Operating profit/(loss) before derivative financial instruments |
128,053 | (2,583) | (2,051) | (248) | (25,289) | 97,882 |
| Derivative financial instruments losses | (3,270) | (5,624) | – | – | – | (8,894) |
| Segment result | 124,783 | (8,207) | (2,051) | (248) | (25,289) | 88,988 |
| Investment revenue | 298 | |||||
| Finance costs | (11,320) | |||||
| Other gains and losses – fair value of financial assets & liabilities |
(8,100) | |||||
| Other gains and losses – foreign currency gains | 305 | |||||
| Share of profit of associates | 8,625 | |||||
| Profit from continuing operations before tax | 78,796 | |||||
| Income tax expense | (32,923) | |||||
| Profit from continuing operations after tax | 45,873 | |||||
| Loss from discontinued operations | (614) | |||||
| Profit for the period | 45,259 | |||||
| Segment assets – non-current | 805,105 | 153,270 | 68,459 | 192,548 | 3,675 | 1,223,057 |
| Segment assets – current | 172,251 | 15,818 | 6,107 | 2,046 | 24,397 | 220,619 |
| Assets held for sale | – | – | – | 2,812 | – | 2,812 |
| Segment liabilities | (352,857) | (110,545) | (5,090) | (47,967) | (71,314) | (587,773) |
| Capital additions – oil and gas assets | 362,879 | 119 | – | – | – | 362,998 |
| Capital additions – exploration and evaluation | 59,462 | 1,723 | 7,559 | 192,470 | – | 261,214 |
| Capital additions – other | 488 | 453 | – | 270 | 2,188 | 3,399 |
| Capital disposal – other | (815) | – | – | – | – | (815) |
| Depletion, depreciation and amortisation | (76,708) | (15,668) | – | (3) | (1,600) | (93,979) |
| Exploration costs write back/(write-off) | 370 | – | (1,984) | – | – | (1,614) |
| 2009 | Nigeria US\$000's |
Côte d'Ivoire US\$000's |
Other West Africa US\$000's |
Unallocated US\$000's |
Consolidated US\$000's |
|
| Sales revenue by origin | 292,111 | 43,707 | – | – | 335,818 | |
| Operating gain/(loss) before derivative financial instruments | 93,157 | 7,554 | 3,576 | (24,861) | 79,426 | |
| Derivative financial instruments gains | (15,346) | (18,289) | – | – | (33,635) | |
| Segment result | 77,811 | (10,735) | 3,576 | (24,861) | 45,791 | |
| Investment revenue | 626 | |||||
| Finance costs | (36,950) | |||||
| Other gains and losses – impairment reversal on available for sale investment |
97 | |||||
| Other gains and losses – fair value of financial assets and liabilities | (5,034) | |||||
| Other gains and losses – foreign currency losses | (2,770) | |||||
| Share of loss of an associate | (1,277) | |||||
| Profit before tax | 483 | |||||
| Income tax expense | (17,261) | |||||
| Profit after tax | (16,778) |
| 2009 | Nigeria US\$000's |
Côte d'Ivoire US\$000's |
Other West Africa US\$000's |
Unallocated US\$000's |
Consolidated US\$000's |
|---|---|---|---|---|---|
| Segment assets – non-current | 448,785 | 168,796 | 62,884 | 3,504 | 683,969 |
| Segment assets – current | 158,764 | 27,940 | 21,373 | 207,936 | 416,013 |
| Segment liabilities | (233,027) | (139,795) | (8,824) | (60,088) | (441,734) |
| Capital additions – oil and gas assets | 76,502 | 6,406 | – | – | 82,908 |
| Capital additions – exploration and evaluation | 59,135 | 1,447 | 6,683 | – | 67,265 |
| Capital additions – other | 2,352 | 123 | – | 1,333 | 3,808 |
| Depletion, depreciation and amortisation | (135,595) | (18,226) | – | (962) | (154,783) |
| Impairment reversal/(charge) on oil and gas assets | (2,705) | – | 3,564 | – | 859 |
| Impairment reversal of available for sale investments | – | – | – | 97 | 97 |
Included in revenues for Nigeria for the year ended 31 December 2010 are US\$286.5 million (2009: US\$292.1 million) which arose from the Group's largest customer.
Non-current assets held in the UK at 31 December 2010 totalled US\$2.4 million (2009: US\$3.3 million). Non-current assets held in Other West Africa at 31 December 2010 included US\$20.3 million (2009: US\$16.0 million) relating to Keta Block, Ghana, US\$30.1 million (2009: US\$29.2 million) relating to La Noumbi permit in Congo (Brazzaville) and US\$18.1 million (2009: US\$17.6 million) relating to JDZ Block One in São Tomé & Príncipe. Non-current assets held in East Africa at 31 December 2010 included US\$62.1 million (2009: US\$nil) related to Block L17/L18, Block 1 and Block 10A in Kenya, US\$58.4 million (2009: US\$nil relating to the Ethiopian Blocks 2&6 and 7&8). US\$35.6 million (2009: US\$nil) related to the Madsgascar Block 1101 and US\$36.2 million (2009: US\$nil) relating to Seychelles Block A,B,C.
| 2010 us\$000's |
2009 US\$000's |
|
|---|---|---|
| Oil revenue | 298,484 | 311,842 |
| Gas revenue | 20,631 | 23,976 |
| Other revenue | 332 | – |
| 319,447 | 335,818 | |
Investment revenue is shown in note 9.
| 2010 us\$000's |
2009 US\$000's |
|
|---|---|---|
| Intangible oil and gas assets (written off )/written back | (1,614) | 859 |
| (1,614) | 859 |
Impairment of oil and gas assets is largely attributable to a US\$1.8 million charge (2009: US\$2.1 million) in respect of the Tie Tie NE well in the La Noumbi permit, offset by a net write-back of US\$0.2 million on previously written-off costs on other licences. In 2009, US\$7.8 million was written-back relating to insurance proceeds receivable in respect of the Cuda well drilled in 2008. The write-back in 2009 was offset by a US\$2.5 million write-off relating to the Ogedeh licence, US\$2.1 million write-off relating to Gabon licences and US\$2.1 million write-off relating to the Tie Tie NE well in the La Noumbi permit referred to above.
For the year ended 31 December 2010 continued
| The operating profit/(loss) for the year is stated after charging: | 2010 us\$000's |
2009 US\$000's |
|---|---|---|
| Staff costs (note 8) | 38,239 | 29,414 |
| Depletion, depreciation and amortisation | 93,979 | 154,783 |
| Property lease rentals | 2,191 | 1,745 |
| FPSO lease rentals | 25,643 | 29,170 |
| Boats, helicopters and other lease rentals | 16,759 | 10,690 |
| An analysis of auditors' remuneration is as follows: | ||
| Fees payable to the Company's auditors for the audit of the Company's annual accounts | 312 | 259 |
| Fees payable to the Company's auditors and their associates for other services to the Group: | ||
| – The audit of the Company's subsidiaries pursuant to legislation | 256 | 156 |
| Total audit fees | 568 | 415 |
| – Tax services | 173 | 117 |
| – Corporate finance services | 1,174 | 2,129 |
| – Other services | 129 | 159 |
| Total non-audit fees | 1,476 | 2,405 |
Corporate finance services primarily represent services provided in respect of the acquisition of Black Marlin (2009: move to the main market of the London Stock Exchange and concurrent equity raising), work that would ordinarily be performed by external auditors for companies involved in such projects and is in-line with the Company's policy on non-audit services. A proportion of these costs, being that relating to the issue of shares following Black Marlin acquisition, has been charged to the share premium account. Other services primarily represent amounts in respect of the review of the Group's and Nigerian subsidiaries' interim results.
A proportion of the Group's staff costs shown above are recharged to the Group's joint venture partners and a proportion is capitalised into the cost of intangible and tangible oil and gas assets under the Group's accounting policy for exploration, evaluation and oil and gas assets. The amount ultimately charged to the income statement was US\$11.6 million (2009: US\$13.1 million).
| Reconciliation of normalised profit/(loss) after tax to profit/(loss) after tax | 2010 us\$000's |
2009 US\$000's |
|---|---|---|
| Profit/(loss) after tax from continuing activities | 45,873 | (16,778) |
| Unrealised losses on derivative financial instruments* | 6,482 | 45,080 |
| Cost of move to the main market of the London Stock Exchange | – | 4,073 |
| Cost of acquisition of Black Marlin | 3,913 | – |
| Share-based payment charge | 8,333 | 9,292 |
| Foreign exchange (gains)/losses | (305) | 2,770 |
| Fair value financial liabilities | 8,100 | 5,034 |
| Share of (gain)/loss of associates | (8,625) | 1,180 |
| 63,771 | 50,651 |
* Excludes realised losses on derivative financial instruments of US\$2.4 million (2009: US\$11.4 million gain).
Normalised profit after tax is a non-IFRS measure of financial performance of the Company, which in management's view more accurately reflects the Company's underlying financial performance. This may not be comparable to similarly titled measures reported by other companies.
8. sTaff cOsTs
| The average monthly number of employees (including Executive Directors) employed was as follows: | 2010 | 2009 |
|---|---|---|
| Administration | 31 | 41 |
| Professional | 188 | 131 |
| 219 | 172 | |
| Their aggregate remuneration comprised: | 2010 us\$000's |
2009 US\$000's |
| Wages and salaries | 22,529 | 16,980 |
| Share based payments | 9,295 | 9,080 |
| Social security costs | 5,169 | 2,611 |
| Pension costs | 1,246 | 743 |
| 38,239 | 29,414 |
Details of Directors' remuneration are provided in the part of the Directors' Remuneration Report described as having been audited.
| us\$000's US\$000's |
||
|---|---|---|
| Interest on bank deposits 298 |
626 |
| 2010 us\$000's |
2009 US\$000's |
|
|---|---|---|
| Bank interest payable | 10,521 | 21,270 |
| Borrowing costs amortisation and facility fees | 9,042 | 11,941 |
| Interest on loan notes | 1,138 | 1,822 |
| Unwinding of discount on loan notes | 2,787 | 2,625 |
| Unwinding of discount on decommissioning | 1,468 | 1,050 |
| 24,956 | 38,708 | |
| Less: capitalised amounts | (13,636) | (1,758) |
| 11,320 | 36,950 |
The Ebok field offshore Nigeria transferred to development in the fourth quarter of 2009 and since then a proportion of the borrowing costs have been capitalised using a weighted average rate of approximately 4.6% (2009: 6.1%). Further, the Okoro infill wells drilling commenced in the fourth quarter 2010 and therefore borrowing costs incurred during the period relating to the Okoro project were capitalised using a weighted average rate of approximately 3.2% (2009: nil).
| Year ended 31 December | ||
|---|---|---|
| 2010 | 2009 | |
| From continuing and discontinued operations | ||
| Basic | 5.0c | (2.6)c |
| Diluted | 4.8c | (2.6)c |
| From continuing operations | ||
| Basic | 5.1c | (2.6)c |
| Diluted | 4.9c | (2.6)c |
| The profit/(loss) and weighted average number of ordinary shares used in the calculation of the profit/(loss) per share are as follows: | ||
| Profit/(loss) for the period used in the calculation of basic profit/(loss) per share from continuing and discontinued operations (US\$000's) |
45,259 | (16,778) |
| Effect of dilutive potential ordinary shares (US\$000's) | – | – |
| Profit/(loss) used in the calculation of diluted profit/(loss) per share from continuing and discontinued activities (US\$000's) |
45,259 | (16,778) |
| Loss for the period from discontinued operations (US\$000's) | 614 | – |
| Profit/(loss) used in the calculation of basic and diluted profit/(loss) per share from continuing activities (US\$000's) | 45,873 | (16,778) |
| The weighted average number of ordinary shares for the purposes of diluted profit/(loss) per share reconciles to the weighted average number of ordinary shares used in the calculation of basic profit/(loss) per share as follows: |
||
| Weighted average number of ordinary shares used in the calculation of basic profit/(loss) per share | 908,821,987 | 637,328,455 |
| Effect of dilutive potential ordinary shares: | ||
| Share based schemes awards | 33,609,396 | – |
| Warrants | 898,464 | – |
| Weighted average number of ordinary shares used in the calculation of diluted profit/(loss) per share | 943,329,847 | 637,328,455 |
9.9 million potential ordinary shares are anti-dilutive and are therefore excluded from the weighted average number of ordinary shares for the purposes of diluted earnings per share in 2010. In 2009 all potential ordinary shares were anti-dilutive because of the loss in that year.
Financial Statements
For the year ended 31 December 2010 continued
Costs of oil and gas exploration – pending determination
| Group US\$000's |
|
|---|---|
| At 1 January 2009 | 213,933 |
| Additions | 67,265 |
| Transfer to tangible oil and gas assets | (90,316) |
| Amounts written off* | (6,721) |
| At 1 January 2010 | 184,161 |
| Additions | 74,274 |
| Acquisition of subsidiaries (see note 31) | 186,940 |
| Amounts written off | (1,614) |
| At 31 December 2010 | 443,761 |
* Excluding the US\$7.8 million net write back of prior year impairment charges on Keta Block
During the year the Company acquired Black Marlin's East African business as described in note 31. The allocated fair value of the oil and gas exploration assets acquired was US\$186.9 million. The Group's carrying value at 31 December 2010 also includes US\$104.2 million (2009: US\$102.5 million) in respect of CI-01 field in Côte d'lvoire, US\$30.1 million (2009: US\$29.2 million) relating to the La Noumbi permit in Congo (Brazzaville), US\$18.1 million (2009: US\$17.6 million) in respect of JDZ Block One of the Nigeria – São Tomé & Príncipe Joint Development Zone (JDZ Block One), US\$27.8 million (2009: US\$14.3 million) in respect of OPL 310 field in Nigeria , US\$20.3 million (2009: US\$16.0 million) in respect of Keta Block in Ghana and US\$36.4 million (2009: US\$nil) in respect of Okwok field in Nigeria.
| 13. PROPERTy, PlanT and EquiPmEnT | Production US\$000's |
Development US\$000's |
Gas plant US\$000's |
Total US\$000's |
|---|---|---|---|---|
| gROuP | ||||
| Oil and gas assets | ||||
| Cost At 1 January 2009 |
466,492 | 6,044 | 27,877 | 500,413 |
| Additions | 14,510 | 68,319 | 79 | 82,908 |
| Transfers from intangible oil and gas assets | – | 90,316 | – | 90,316 |
| At 1 January 2010 | 481,002 | 164,679 | 27,956 | 673,637 |
| Additions | 33,935 | 329,063 | – | 362,998 |
| At 31 December 2010 | 514,937 | 493,742 | 27,956 | 1,036,635 |
| Accumulated Depreciation | ||||
| At 1 January 2009 | 27,614 | 6,044 | 1,111 | 34,769 |
| Charge for the year | 147,753 | – | 4,443 | 152,196 |
| At 1 January 2010 | 175,367 | 6,044 | 5,554 | 186,965 |
| Charge for the year | 86,060 | – | 4,443 | 90,503 |
| At 31 December 2010 | 261,427 | 6,044 | 9,997 | 277,468 |
| Carrying amount |
| at 31 december 2010 | 253,510 | 487,698 | 17,959 | 759,167 |
|---|---|---|---|---|
| At 31 December 2009 | 305,635 | 158,635 | 22,402 | 486,672 |
| Leasehold | Fixtures and | hardware | |||
|---|---|---|---|---|---|
| improvements US\$000's |
equipment US\$000's |
and software US\$000's |
Total US\$000's |
||
| gROuP | |||||
| Other property, plant and equipment | |||||
| Cost | |||||
| At 1 January 2009 | 3,008 | 2,809 | 2,727 | 8,544 | |
| Additions | 1,678 | 1,046 | 1,084 | 3,808 | |
| Disposal | – | (60) | – | (60) | |
| At 1 January 2010 | 4,686 | 3,795 | 3,811 | 12,292 | |
| Additions | 238 | 858 | 2,109 | 3,205 | |
| Additions – acquisition of subsidiary | 94 | 100 | – | 194 | |
| Disposal | (448) | (221) | (146) | (815) | |
| At 31 December 2010 | 4,570 | 4,532 | 5,774 | 14,876 | |
| Accumulated depreciation | |||||
| At 1 January 2009 | 1,124 | 841 | 766 | 2,731 | |
| Charge for the year | 837 | 722 | 1,028 | 2,587 | |
| Disposal | – | (22) | – | (22) | |
| At 1 January 2010 | 1,961 | 1,541 | 1,794 | 5,296 | |
| Charge for the year | 938 | 1,000 | 1,538 | 3,476 | |
| Disposal | (448) | (221) | (146) | (815) | |
| At 31 December 2010 | 2,451 | 2,320 | 3,186 | 7,957 | |
| At 31 December 2009 | 2,725 | 2,254 | 2,017 | 6,996 |
|---|---|---|---|---|
| at 31 december 2010 | 2,119 | 2,212 | 2,588 | 6,919 |
| Computer | ||||
| Leasehold | Fixtures and | hardware | ||
| improvements | equipment | and software | Total | |
| US\$000's | US\$000's | US\$000's | US\$000's | |
| cOmPany | ||||
| Other property, plant and equipment | ||||
| Cost | ||||
| At 1 January 2009 | 1,107 | 1,049 | 1,797 | 3,953 |
| Additions | 285 | 113 | 876 | 1,274 |
| At 1 January 2010 | 1,392 | 1,162 | 2,673 | 5,227 |
| Additions | 81 | 128 | 822 | 1,031 |
| At 31 December 2010 | 1,473 | 1,290 | 3,495 | 6,258 |
| Accumulated depreciation | ||||
| At 1 January 2009 | 649 | 496 | 509 | 1,654 |
| Charge for the year | 93 | 158 | 611 | 862 |
| At 1 January 2010 | 742 | 654 | 1,120 | 2,516 |
| Charge for the year | 216 | 161 | 978 | 1,355 |
| At 31 December 2010 | 958 | 815 | 2,098 | 3,871 |
| Carrying amount | ||||
| At 31 December 2009 | 650 | 508 | 1,553 | 2,711 |
| at 31 december 2010 | 515 | 475 | 1,397 | 2,387 |
For the year ended 31 December 2010 continued
Indirectly held
| Group | Company | |||
|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
|
| subsidiaries | ||||
| Shares at cost in subsidiary undertakings | – | – | 202,238 | 54,128 |
During the year the company acquired all the issued share capital of Black Marlin Energy Holdings Limited as described in note 31. The remaining movement relates to additional investment in Afren's US subsidiary, Afren USA inc.
A list of the significant investments in subsidiaries and associated undertakings, including the name, proportion of ownership interest, country of operation and country of registration, is given below:
| Name | Principal activity | % | Country of operation |
Country of registration |
|---|---|---|---|---|
| Directly held | ||||
| Afren CI (UK) Limited | Holding company | 100 | UK | England & Wales |
| Afren Congo Limited | Oil and gas exploration, development and production | 100 | Congo | Bahamas |
| Afren Energy International plc | Holding of loan notes | 100 | UK | England & Wales |
| Afren USA inc. | Service company | 100 | USA | USA, Delaware |
| Black Marlin Energy Holdings limited | Holding company | 100 | Dubai | British Virgin Islands |
| Afren JDZ One Limited | 100 | Norway | Norway | |
|---|---|---|---|---|
| Dangote Energy Equity Resources Limited | Oil and gas exploration, development and production | 49(i) | Nigeria | Nigeria |
| Afren Energy Resources Limited | Oil and gas exploration, development and production | 100 | Nigeria | Nigeria |
| Afren Okoro Limited | Holding company | 100 | UK | England & Wales |
| Afren Global Energy Resources Limited | Oil and gas exploration, development and production | 50(i) | Nigeria | Nigeria |
| Afren Investments Oil & Gas (Nigeria) Limited | Oil and gas exploration, development and production | 100 | Nigeria | Nigeria |
| Afren Energy Services Limited | Service company | 100 | Nigeria | Nigeria |
| Afren Exploration and Production Nigeria Alpha Limited | Oil and gas exploration, development and production | 100 | Nigeria | Nigeria |
| Afren Exploration and ProductionNigeria Beta Limited | Oil and gas exploration, development and production | 100 | Nigeria | Nigeria |
| Afren Nigeria Holdings (Nigeria) Limited | Holding company | 100 | Nigeria | Nigeria |
| Afren CI One Corporation | Oil and gas exploration, development and production | 100 | Côte d'lvoire | Cayman |
| Afren Cote D'lvoire Limited | Oil and gas exploration, development and production | 100 | Côte d'lvoire | Cayman |
| Lion GPL SA | Oil and gas exploration, development and production | 100 | Côte d'lvoire | Côte d'lvoire |
| Black Marlin Energy Limited | Holding company | 100 | Dubai | British Virgin Islands |
| East African Exploration (K) Limited | Oil and gas exploration, development and production | 100 | Kenya | Kenya |
| East African Exploration (Seychelles) Limited | Oil and gas exploration, development and production | 100 | Seychelles | British Virgin Islands |
| East African Exploration (Madagascar) Limited | Oil and gas exploration, development and production | 100 | Madagascar | British Virgin Islands |
| East African Exploration (Ethiopia) Limited | Oil and gas exploration, development and production | 100 | Ethiopia | British Virgin Islands |
| Afren Energy Ghana Limited | Oil and gas exploration, development and production | 100 | Ghana | Bahamas |
| Afren Resources Limited | Oil and gas exploration, development and production | 100 | Nigeria | Nigeria |
(i) Accounted for via proportional consolidation as the Group exercises joint control over its operations.
| Group | Company | |||
|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
|
| At the beginning of the year | 604 | – | 604 | – |
| Additions during the year | 1,998 | 1,881 | – | 1,881 |
| Share of associates gain/(loss) after tax* | 8,625 | (1,277) | (604) | (1,277) |
| At the end of the year | 11,227 | 604 | – | 604 |
* Group figure includes one-off gain of \$9.9million (2009: nil) and share of associates' losses of \$1.3million (2009: \$1.3million loss)
Aggregated amounts related to associates, representing Afren's interest, were as follows:
| Group | Company | |||
|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
|
| Total assets | 14,268 | 765 | 1,178 | 765 |
| Total liabilities | (2,802) | (108) | 939 | (108) |
| Revenues | – | – | – | – |
| Gain/(loss) after tax | 8,625 | (1,277) | (604) | (1,277) |
The group holds a 45% interest in First Hydrocarbon Nigeria Limited (FHN) and acquired shares amounting to US\$2.0 million during the year.
As at 31 December 2010 Afren plc held 226,421,354 ordinary shares in Gasol plc representing 20.9% of its issued share capital. The closing price on the 31 December 2010 was 2.33p per share. The fair value of the shares as at 31 December 2010 was US\$3.6 million compared with a book value of US\$0.8 million. The Company and the Group share of the unrecognised losses of Gasol plc was US\$0.4 million as at 31 December 2010.
The financial information accounted for using the equity method as at 31 December 2010 has been taken from the unaudited management information of FHN and Gasol plc as at that date. Gasol plc's year end is 31 March. As at 31 December 2010 FHN had a commitment amounting to \$132.7 million in respect of outstanding completion payment on acquisition of OML26, onshore Nigeria.
| Group | Company | |||
|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
|
| Oil and gas inventory | 14,204 | 20,099 | – | – |
| Spare parts | 24,851 | 14,465 | – | – |
| 39,055 | 34,564 | – | – |
Spare parts are stated net of a provision of US\$3.0 million (2009: US\$1.2 million) to write down the inventory to recoverable amount.
For the year ended 31 December 2010 continued
The Group has a 49% share of Dangote Energy Equity Resources Limited (DEER), a jointly controlled entity which is involved in operations in JDZ Block One.
The Group has a 50% interest in Afren Global Energy Resources Limited (AGER), a jointly controlled entity. AGER holds the Production Sharing Contracts for OPLs 907 and 917.
The Group's share of DEER's and AGER's assets, liabilities, income and expenses of the jointly controlled entities at 31 December 2010 and 2009 and for the years then ended, which are included in the consolidated financial statements, are as follows:
| 2010 | 2009 | |||
|---|---|---|---|---|
| 50% share in agER us\$000's |
49% share in dEER us\$000's |
50% share in AGER US\$000's |
49% share in DEER US\$000's |
|
| Current assets | 1,316 | 1,189 | 701 | 159 |
| Non-current assets | 4,690 | 18,076 | 4,384 | 17,597 |
| 6,006 | 19,265 | 5,085 | 17,756 | |
| Current liabilities | (64) | (633) | (21) | (385) |
| Non-current liabilities | – | – | – | – |
| 5,942 | 18,632 | 5,064 | 17,371 | |
| Administrative expenses | 56 | 9 | 55 | 1 |
| Bank interest received | – | (21) | – | – |
| Loss/(profit) before and after income tax | 56 | (12) | 55 | 1 |
| Group | Company | |||
|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
|
| Trade and other debtors | 29,708 | 14,449 | 12,088 | 982 |
| Prepayments and accrued income | 10,219 | 40,147 | 1,995 | 1,297 |
| VAT recoverable | 1,416 | 1,018 | 1,402 | 1,018 |
| Due from subsidiary undertakings* | – | – | 695,767 | 467,796 |
| Due from joint ventures | – | – | 12,390 | 14,322 |
| 41,343 | 55,614 | 723,642 | 485,415 |
* The amount in the Company is shown net of a provision for doubtful debt of US\$25.4 million (2009: US\$25.4 million).
Prepayments and accrued income in respect of the Group includes a US\$1.5 million (2009: US\$10.6 million) accrued income on crude and gas sales and US\$5.2 million (2009: US\$5.5 million) in prepayment of operating costs relating to the Floating Production and Storage Offtake vessel (FPSO) for the Okoro field, of which US\$2.0 million (2009: US\$3.4 million) is disclosed as non-current prepayment in the balance sheet.
There were no material past due not impaired receivables at either balance sheet date, nor any material bad debt provisions (other than as disclosed above in respect of intercompany balances).
| Group | Company | |||
|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
|
| Cash and cash equivalents | 140,221 | 321,312 | 5,258 | 203,117 |
Cash and cash equivalents comprise cash held by the Group and Company in the form of short-term bank deposits with an original maturity of three months or less and earn interest at respective short-term deposit rates. The carrying amount of these assets approximates their fair value.
Cash and cash equivalents at 31 December 2010 includes US\$31.9 million (2009: US\$5.4 million) that is restricted. This relates to short-term restrictions on project cash, pending completion of certain milestones and cash deposit for some of the letters of credit described in note 26.
| Group | Company | ||||
|---|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
||
| Trade creditors | 23,779 | 18,892 | 1,447 | 2,805 | |
| Other creditors and joint venture partners | 72,262 | 42,454 | 11,437 | 5,550 | |
| Accruals | 98,408 | 66,660 | 9,368 | 7,244 | |
| PAYE and social security | 2,165 | 5,789 | 2,120 | 5,677 | |
| VAT payable | – | 50 | – | – | |
| Corporation tax payable | 19,423 | 894 | – | – | |
| Due to subsidiary undertakings | – | – | 51,432 | 39,950 | |
| 216,037 | 134,739 | 75,804 | 61,226 |
Group accruals include interest payable of US\$3.5 million (2009: US\$5.7 million) relating to the bank borrowings described in note 21, and US\$0.3 million (2009: US\$0.3 million) of coupon interest relating to loan notes described in note 24.
For the year ended 31 December 2010 continued
Borrowings
| Group | |||||
|---|---|---|---|---|---|
| 2010 | 2009 | ||||
| current us\$000's |
non-current us\$000's |
Current US\$000's |
Non-current US\$000's |
||
| Loan notes (note 24) | 41,390 | – | – | 37,216 | |
| Bank borrowings | 47,864 | 178,467 | 117,634 | 112,230 | |
| 89,254 | 178,467 | 117,634 | 149,446 |
Bank borrowings at the year end included US\$27.7 million (US\$25.5 million net of financing arrangement costs), 2009: US\$74.4 million (US\$73.5 million net of financing arrangement costs), relating to the Okoro development facility from BNP Paribas. Interest on the loan is based on LIBOR plus a margin of 3.75% as at 31 December 2010. The facility is repayable in semi-annual instalments determined by borrowing base calculations linked to the certified reserves of the Okoro field. The loan is secured by the assets of the Okoro field. An agreement was reached with the bank in February 2011 whereby the full outstanding obligation was repaid.
The acquisition of operations in Côte d'lvoire was financed by a financing package arranged through BNP Paribas. The outstanding balance on the financing package at 31 December 2010 was US\$71.2 million (US\$69.8 million net of financing arrangement costs), 2009: US\$111.8 million (US\$108.5 million net of financing arrangement costs). Interest on the senior debt is based on LIBOR plus a margin of between 3.25% and 3.5% as at 31 December 2010. Interest on the subordinate debt is based on LIBOR plus a margin of 4.25%. The senior debt includes certain financial covenants which are assessed on a quarterly basis. Subsequent to the year end an agreement was reached with the banks in February 2011 whereby the full outstanding obligation was repaid.
Borrowings also include a balance of US\$33.3 million (US\$32.4 million net of financing arrangement costs), 2009: US\$50.0 million (US\$47.9 million net of financing arrangement costs), relating to an unsecured loan facility from First City Monument Bank plc (FCMB). Interest on the loan is based on LIBOR plus a margin of 4.45%. Subsequent to the year end an agreement was reached with the bank in February 2011 whereby the full outstanding obligation was repaid.
In March 2010 the Group entered into a bank facility agreement, for a maximum of five years, secured against the Ebok field reserves. The facility is repayable in semiannual instalments determined by borrowing base calculations linked to the certified reserves of the Ebok field. The amount drawndown, including certain capitalised financing costs amounted to US\$107.4 million (US\$98.6 million net of financing arrangement costs) as at 31 December 2010. Interest on the loan is based on LIBOR plus a margin of 5.5% as at 31 December 2010.
| Group | |||||
|---|---|---|---|---|---|
| 2010 | 2009 | ||||
| current us\$000's |
non-current us\$000's |
Current US\$000's |
Non-current US\$000's |
||
| Financial assets | – | – | 4,523 | 2,153 | |
| Financial liabilities | (4,927) | (499) | (5,240) | (379) | |
| (4,927) | (499) | (717) | 1,774 |
In 2007 the Group entered into derivative financial instruments (swaps and call options) to economically protect against exposures to variability in the price of Okoro crude oil production for the period 2008 to 2010. During the first half of 2009 an additional derivative contract in respect of the Okoro crude was entered into for the period 2009 to 2011. The Group will receive a minimum amount if the market falls, but will receive a set discount from the market price if the oil price is above that minimum. The arrangement protects the Group against the risk of a significant fall in the price of crude oil by establishing a minimum price for the Okoro crude. During 2008 on acquisition of CI-11 field in Côte d'lvoire, the Group entered into similar instruments to protect against variability in price of the CI-11 crude oil production for the period from 2008 to 2012. The loss of US\$8.9 million (2009: US\$33.6 million loss) arising during the year as a result of the changes in fair value of these derivative financial instruments has been accounted for in the income statement net of cash realisations, as the criteria for hedge accounting were not met.
In addition to the above commodity derivatives, the change in July 2008 of the functional currency of the holding company from pounds sterling to US dollar resulted in certain sterling denominated warrants being accounted for as derivatives from that date, as they are no longer convertible at a fixed price in that company's functional currency. The fair value of the warrants at 31 December 2010, recorded within other creditors, was US\$11.2 million (2009: US\$5.5 million) and the resultant loss during the year of US\$8.1 million (2009: US\$5.0 million loss) has been taken to the income statement.
The following table details the Group's remaining contractual maturity for its non-derivative financial liabilities with agreed maturity periods. The table has been drawn based on the undiscounted cash flows of the financial liabilities based on the earliest date on which the Group can be required to pay.
| Weighted average effective interest % |
Less than 1 month US\$000's |
1-3 months US\$000's |
3 months to 1 year US\$000's |
1-5 years US\$000's |
Total US\$000's |
|
|---|---|---|---|---|---|---|
| 31 December 2010 | ||||||
| Non-interest bearing | 0% | 13,177 | 50,405 | 152,455 | – | 216,037 |
| Variable interest rate borrowings | 4.6% | 6,667 | 8,908 | 88,967 | 203,778 | 308,320 |
| Total | 19,844 | 59,313 | 241,422 | 203,778 | 524,357 | |
| Weighted average effective interest % |
Less than 1 month US\$000's |
1-3 months US\$000's |
3 months to 1 year US\$000's |
1-5 years US\$000's |
Total US\$000's |
|
| 31 December 2009 | ||||||
| Non-interest bearing | 0% | 66,677 | 5,573 | 62,489 | – | 134,739 |
| Variable interest rate borrowings | 5.2% | 6,667 | 9,323 | 117,745 | 168,954 | 302,689 |
| Total | 73,344 | 14,896 | 180,234 | 168,954 | 437,428 |
The amounts reported in the balance sheet relating to the borrowings (excluding interest) mature as follows:
| 2010 us\$000's |
2009 US\$000's |
|
|---|---|---|
| Due within one year | 89,254 | 117,634 |
| Due within two to five years | 178,467 | 149,446 |
| 267,721 | 267,080 |
All borrowings are in US dollars.
Set out below is a comparison by category of carrying amounts and fair values of all the Group's financial instruments:
| Carrying amount | Fair value | ||||
|---|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
||
| Financial assets | |||||
| Derivative financial instruments | – | 6,676 | – | 6,676 | |
| Cash and cash equivalents | 140,221 | 321,312 | 140,221 | 321,312 | |
| Trade and other receivables | 31,124 | 41,634 | 31,124 | 41,634 | |
| 171,345 | 369,622 | 171,345 | 369,622 | ||
| Financial liabilities | |||||
| Derivative financial instruments | 5,426 | 5,619 | 5,426 | 5,619 | |
| Trade creditors | 23,779 | 18,892 | 23,779 | 18,892 | |
| Other creditors and accruals | 170,670 | 110,208 | 170,670 | 110,008 | |
| Borrowings – BNP Paribas | 25,533 | 73,464 | 26,111 | 72,239 | |
| Borrowings – FCMB | 32,400 | 47,900 | 32,365 | 47,985 | |
| Borrowings – Cote d'lvoire | 69,795 | 108,499 | 67,374 | 106,403 | |
| Borrowings – Ebok | 98,603 | – | 101,520 | – | |
| Loan notes | 41,390 | 37,216 | 42,801 | 41,745 | |
| 467,596 | 401,798 | 470,046 | 402,891 |
The fair values of the derivative financial instruments have been determined by reference to observable data in quoted markets at the balance sheet date and hence qualify as level 2 as defined in IFRS 7 (revised). The fair value of bank borrowings and loan notes have been determined by discounting future cash outflows relating to the borrowings and loan notes respectively.
For the year ended 31 December 2010 continued
The Group's exposure to the risk of changes in market interest rates relates primarily to the Group's bank borrowings. The Group has managed the interest rate risk by using a mix of fixed and variable rates on convertible bonds, loan notes and bank borrowings respectively.
The following table demonstrates the sensitivity to changes in LIBOR rate, with all other variables held constant, of the Group's profit before tax.
| 2010 | Increase | Increase in Group profit US\$000's |
Decrease | Decrease in Group profit US\$000's |
|---|---|---|---|---|
| Interest payable | 1% | (3,047) | 1% | 3,047 |
| 2009 | Increase | Increase in Group loss US\$000's |
Decrease | Decrease in Group loss US\$000's |
| Interest payable | 1% | (3,574) | 1% | 3,574 |
The Group's exposure to the risk of changes in oil price relates primarily to the Group's derivative financial instruments. The terms of the derivative financial instruments are such that the Group will receive a minimum amount if the market falls, but will receive a set discount from the market price if the oil price is above that minimum. The effect on Group loss and equity of changes in the oil price on the fair value of the derivative financial instruments is shown below:
| Positive/ (adverse) 2010 us\$000's |
Positive/ (adverse) 2009 US\$000's |
|
|---|---|---|
| Increase in oil price by 10% | (1,518) | (5,270) |
| Decrease in oil price by 10% | 2,669 | 6,728 |
The impact of a 10% change in the sterling to US dollar exchange rate is shown below:
| Positive/ | Positive/ | |
|---|---|---|
| (adverse) | (adverse) | |
| 2010 | 2009 | |
| us\$000's | US\$000's | |
| Increase in exchange rate by 10% | (1,994) | 14,636 |
| Decrease in exchange rate by 10% | 1,994 | (14,636) |
In 2010 the majority of foreign exchange risk was as a result of the outstanding warrants held by FCMB which are financial liabilities of the Group. In 2009 Sterling cash balances has the biggest impact. The impact of a 10% change in the Nigerian Naira to US dollar exchange rate would not be material in 2010 or in 2009.
The Group manages its capital to ensure that it remains sufficiently funded to support its business strategy and maximise shareholder value. The Group's funding needs are met through a combination of debt and equity. The Group monitors the net debt position on an ongoing basis. The Group includes within net debt, interest bearing loans and borrowings less cash and cash equivalents. Capital includes share capital, share premium, other reserves and accumulated losses.
| Group | Company | ||||
|---|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
||
| At 1 January | 21,836 | 20,276 | – | – | |
| Additions during the year | 11,815 | 510 | – | – | |
| Unwinding of discount | 1,468 | 1,050 | – | – | |
| At 31 December | 35,119 | 21,836 | – | – |
The provision for decommissioning was recognised following the start of drilling at the Okoro field and following the acquisition of the CI-11 field in 2008. The provision represents the present value of the amounts that are expected to be incurred up to 2016. Additions during the year were made on commencement of drilling on the Ebok field and also the infill wells on the Okoro field. The provision was made using Afren's internal estimates that management believe form a reasonable basis for the expected future costs of decommissioning.
Annual Report and Accounts 2010
As described in note 31, the Company acquired all the issued share capital of Black Marlin Energy Holdings limited (Black Marlin) during the year. The seismic business operated by Black Marlin mainly used marine and land seismic equipment and vehicles. The trade and assets of this business were identified as held for sale on acquisition as an active programme is in place to have them sold.
| Group | ||
|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
|
| Marine and land seismic equipment | 2,500 | – |
| Operational vehicles | 312 | – |
| 2,812 | – |
The seismic business will cease once the assets shown above are sold and therefore its result for the period to 31 December 2010 has been disclosed as discontinued operations in the income statement. It recorded a loss of US\$0.6 million during the period since acquisition.
| Group | ||
|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
|
| Liability component at 1 January | 37,492 | 33,619 |
| Unwinding of discount | 2,787 | 2,625 |
| Coupon interest | 1,138 | 1,822 |
| Interest paid | (1,151) | (1,960) |
| Amortised issue costs | 1,386 | 1,386 |
| At 31 December | 41,652 | 37,492 |
| Reported in: | Group | |
|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
|
| Interest payable in current liabilities | 262 | 276 |
| Borrowings – current liabilities | 41,390 | 37,216 |
| Total liability component | 41,652 | 37,492 |
On 9 October 2008 Afren entered into a strategic alliance with Sojitz, a Japanese investment and industrial conglomerate, to jointly pursue acquisition opportunities of scale in Africa. Sojitz invested US\$45 million in the form of loan notes in Afren which become convertible bonds at the time of entering into or announcing joint acquisitions. The loan notes bear a coupon based on LIBOR plus a margin of 2%. The net proceeds from the issue of the loan notes were split between a liability component and an equity component at the date of issue. The liability component of the loan notes was US\$41.4 million as at 31 December 2010 (2009: US\$37.2 million). The interest charged for the year is calculated by applying an effective interest rate of 8.7% (2009: 10.3%) to the liability component. The loan notes were originally repayable in full in October 2011, although subsequent to the balance sheet date, an agreement was reached and the full outstanding balance of US\$45 million on the notes was repaid in February 2011.
For the year ended 31 December 2010 continued
| Deferred tax liability | 2010 us\$000's |
2009 US\$000's |
|---|---|---|
| Property, plant and equipment | 32,513 | 18,186 |
| Intangible oil and gas assets | 39,817 | – |
| Other temporary differences | (8,860) | (5,726) |
| 63,470 | 12,460 |
| Analysis of movement during the year | At 1 January 2010 US\$'000's |
Charge for the year US\$'000's |
Acquisition of subsidiaries US\$'000's |
At 31 December 2010 US\$000's |
|---|---|---|---|---|
| Property, plant and equipment | 18,186 | 14,327 | – | 32,513 |
| Intangible oil and gas assets | – | – | 39,817 | 39,817 |
| Other temporary differences | (5,726) | (3,134) | – | (8,860) |
| 12,460 | 11,193 | 39,817 | 63,470 |
At the balance sheet date the Group and Company also had tax losses (primarily arising in the UK) of US\$105.3 million (2009: US\$97.2 million) and US\$54.2 million (2009: US\$77.1 million) respectively, in respect of which a deferred tax asset has not been recognised as there is insufficient evidence of future taxable profits against which these tax losses could be recovered. Such losses can be carried forward indefinitely. The Group and Company had temporary differences of US\$25.2 million (2009: US\$15.6 million) and US\$10.9 million (2009: US\$7.2 million) in respect of share-based payments, property, plant and equipment and pensions in respect of which deferred tax assets have not been recognised as there is insufficient evidence of future taxable profits against which these tax losses could be recovered.
Deferred tax has not been recognised on undistributed earnings of subsidiaries as the Group has no intention to remit the earnings to the UK in the foreseeable future. The extent of the unrecognised deferred tax in respect of this is not material.
| As at 31 December | ||
|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
|
| Performance bond issued by a bank in respect of OPL 907/917 | 24,100 | 24,100 |
| Standby letter of credit in respect of contractual agreements of the Okoro FPSO, Ebok MOPU/FSO |
12,000 | 6,000 |
| Performance bond issued by a bank in respect of Ethiopia exploration activities | 1,050 | – |
| Performance bond issued by a bank in respect of Kenya exploration activities | 488 | – |
| 37,638 | 30,100 |
In March 2010 a standby letter of credit for US\$6 million was issued by a bank in respect of the Ebok field's contractual arrangements. Following the acquisition of Black Marlin Energy Holdings Limited described on note 31, existing guarantees in respect of Ethiopia and Kenya exploration activities are also now the responsibility of the Group.
As part of the contractual arrangements on the Ofa field in Nigeria, Afren may be liable to contribute up to a maximum of US\$500,000 in respect of abandonment should certain events specified in the contract occur.
Additional amounts may also be payable in relation to JDZ Block One if proved reserves are discovered and upon approval of a field development programme. The amount payable is based on the level of proven reserves and prevailing oil and gas prices and is subject to adjustment upon any subsequent amendments to such oil and gas reserves.
| 2010 us\$000's |
2009 US\$000's |
||
|---|---|---|---|
| (i) Authorised | |||
| 1,200 million ordinary shares of 1p each (equivalent to approx \$1.59 cents) (2009: 1,200 million) | 19,111 | 19,111 | |
| Equity share capital allotted and fully paid |
Share premium |
||
| Number | US\$000's | US\$000's | |
| (ii) Allotted equity share capital and share premium | |||
| As at 1 January | 889,065,354 | 15,702 | 755,169 |
| Issued during the year for cash | 5,107,414 | 81 | 2,729 |
| Non-cash shares issued** | 76,776,096 | 1,224 | 138,914 |
| As at 31 December | 970,948,864 | 17,007 | 896,812 |
Share premium figure is shown net of issue costs of US\$2.4 million (2009: US\$14.2 million).
** Non-cash shares issued were primarily in respect of the Black Marlin acquisition described in note 31.
| 2010 us\$000's |
2009 US\$000's |
|
|---|---|---|
| UK corporation tax | – | – |
| Overseas corporation tax | 21,730 | 4,801 |
| 21,730 | 4,801 | |
| Deferred tax | 11,193 | 12,460 |
| 32,923 | 17,261 |
The current tax can be reconciled to the overall tax charge as follows:
| 2010 us\$000's |
2009 US\$000's |
|
|---|---|---|
| Pre-tax profit | 78,796 | 483 |
| Tax at the UK corporate tax rate of 28% (2009:28%) | 22,063 | 135 |
| Tax effect of items which are not deductible for tax | 15,687 | 9,149 |
| Items not subject to tax | (18,832) | (16,436) |
| Tax effect of share of associate results | (2,415) | 357 |
| Effect of different tax rates | 2,231 | 534 |
| Recognised tax losses | 5,985 | 13,348 |
| Loss not recognised | 8,204 | 10,174 |
| Tax charge for the year | 32,923 | 17,261 |
The Group's tax charge for the year includes current and deferred tax in Nigeria of US\$18.5 million (2009:US\$0.8 million) and US\$11.2 million (2009:US\$12.5 million) respectively. The detailed mechanics of the Group's tax filing arrangements in Nigeria are subject to agreement with the local tax authorities and while the Group is satisfied that the 2010 and 2009 charge is its best estimate of its tax position, adjustments may be required once these discussions have been finalised.
For the year ended 31 December 2010 continued
| Group | Company | |||
|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
|
| Minimum lease payments under operating leases recognised in income for the year | 44,593 | 41,605 | 1,128 | 1,004 |
At the balance sheet date, the Group had outstanding commitments for future minimum lease payments under non-cancellable operating leases, which fall due as follows:
| Group | Company | ||||
|---|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
||
| Within one year | 97,168 | 91,749 | 1,153 | 1,276 | |
| In the second to fifth years | 29,100 | 102,516 | 781 | 2,762 | |
| 126,268 | 194,265 | 1,934 | 4,038 |
Operating lease commitments include rentals of US\$14.8 million (2009: US\$29.5 million) within one year and US\$22.2 million (2009: US\$73.8 million) between two and five years for the FPSO that is used on the Okoro field production and US\$12.7 million (2009: US\$27.4 million) within one year, for the terminal, security boats and field transport rentals in respect of the Okoro field. During the year there was a reversion of interest on the Okoro Field from 95% to 50%, therefore operating leases commitments are based on the new economic interest. In addition, US\$65.2 million (2009: US\$30.6 million) within one year primarily relates to the lease of rig and field transport rentals in respect of the Ebok field. Other operating lease represents rentals payable by the Company and Group for certain of its office properties. Property leases are negotiated for an average term of three years and rentals are fixed for an average term of three years.
| 2010 us\$000's |
2009 US\$000's |
|
|---|---|---|
| Capital commitments – Group | ||
| Oil and gas assets – Development | 231,691 | 58,952 |
| Oil and gas assets – Exploration and evaluation | 124,594 | 5,637 |
| 356,285 | 64,589 |
Included in the capital commitments is \$163.0 million relating to the FSO MOPU in respect of the Ebok field offshore Nigeria.
During the year the Group had in place four share-based payment arrangements for its employees and has also issued warrants to contractors. The charge in relation to these arrangements is shown below, with further details of each scheme following:
| 2010 us\$000's |
2009 US\$000's |
|
|---|---|---|
| 2005 Share Option Scheme | 5,119 | 1,742 |
| Long Term Incentive Plan | 3,832 | 2,281 |
| Share Award Scheme | 408 | 2,404 |
| Founders and other warrants | 140 | 2,865 |
| 9,499 | 9,292 |
Excludes \$0.2m warrants issued in respect of the Black Marlin acquisition.
Equity-settled share award scheme
The Group operates a share option scheme for employees. The Group's policy is to award options to employees on appointment or completion of their probationary period and periodically thereafter. Options are issued at market price on the grant date and have vesting periods of up to three years. The options expire after 10 years if they remain unexercised and are forfeited if the employee leaves the Group before the options vest except at the discretion of the Board.
Details of the share options outstanding are as follows:
| 2010 | 2009 | |||
|---|---|---|---|---|
| number of share options |
weighted average exercise price £ |
Number of share options |
Weighted average exercise price £ |
|
| Outstanding at beginning of year | 55,687,999 | 0.72 | 26,452,998 | 0.77 |
| Granted during year | 4,425,000 | 1.12 | 33,315,000 | 0.65 |
| Exercised during year | (2,415,657) | 0.80 | (2,283,333) | 0.32 |
| Lapsed during year | (1,093,000) | 0.84 | (1,796,666) | 0.70 |
| 56,604,342 | 0.90 | 55,687,999 | 0.72 | |
| Exercisable at end of year | 22,971,677 | 0.72 | 15,858,337 | 0.69 |
The weighted average remaining contractual life of the options outstanding at 31 December 2010 was 7.7 years (31 December 2009 8.5 years). The weighted average share price at the date of exercise for share options exercised during the year ended 31 December 2009 was 108p.
In 2010 options were granted on 19, 26 and 29 January, 29 March, 23 April, 18 June, 1 September, 22 October, and 2 November. The aggregate of the estimated fair values of the options granted on those dates was \$2.4 million.
In 2009 options were granted on 23 January, 7 April, 1 July, 26 September,26, 30 and 31 December. The aggregate of the estimated fair values of the options granted on those dates was \$12.4 million.
The options granted during the year have been valued by reference to the Barrier option valuation model, consistent with the prior year. The inputs into the Barrier model were as follows:
| 2010 | 2009 | |
|---|---|---|
| Weighted average share price (pence) | 112.7 | 64.2 |
| Weighted average exercise price (pence) | 112.3 | 112.2 |
| Weighted average target price before eligibility to exercise (barrier) (pence) | 157.2 | 91.7 |
| Expected volatility | 40% | 50% |
| Expected life (years) | 3 | 3 |
| Risk free rate | 4.0% | 4.0% |
| Expected dividends | – | – |
The volatility of Afren shares was again reviewed following a further 12 months of share price data. The volatility was measured utilising several formulae, including an Exponentially Weighted Moving Average model and a GARCH (Generalised Autoregressive Conditional Heteroscedasticity) model, and over several time periods. These gave a range of estimates for the share price volatility with a reduction from the previous year. Therefore the volatility assumption was reduced, but will remain under review going forwards.
The Company and Group recognised total expenses related to equity settled share based payment transactions in the form of options in 2010 of US\$3,681,000 and US\$5,119,000 respectively, of which US\$5,054,000 related to employees, including executive directors, of the Group (2009: US\$1,298,000 and US\$1,742,000 respectively, of which US\$1,625,000 related to employees, including executive directors, of the Group).
For the year ended 31 December 2010 continued
An alternative share plan was introduced during 2007 (with first grants made in June 2008) to give awards to Directors and staff subject to outperforming a comparator group of similarly focused oil and gas exploration and production companies in terms of shareholder return over a three-year period. The Afren Performance Share Plan awards a number of shares to Directors and staff based on a multiple of salary. However, these shares only vest after a three-year period and the full award is made only if Afren has performed in the top quartile when compared against a selected peer group of upstream oil and gas companies: Borders & Southern Petroleum plc, Bowleven, Cairn Energy, Desire Petroleum, Enquest, Falkland Oil & Gas, Gulf Keystone Petroleum, Gulfsands Petroleum, Hardy Oil & Gas, Heritage Oil, Ithaca Energy, JKX Oil & Gas, Melrose Resources, Petroceltic International, Premier Oil, Rockhopper Exploration, Salamander Energy, Serica Energy, Soco International, Sterling Energy, Tullow Oil and Valiant Petroleum. If Afren does not achieve at least median performance in the peer group, no shares will be awarded. At the median level, 30% of the shares will vest and there is a sliding scale between median and top quartile performance where only a percentage of the total award will vest.
Awards are forfeited if the employee leaves the Group before the awards vest, except under certain circumstances e.g. redundancies, where the number of awards vesting will be prorated according to the length of time the employee has been employed during the three-year vesting period.
Details of the share awards outstanding are as follows:
| 2010 | ||||
|---|---|---|---|---|
| number of share options |
weighted average exercise price £ |
Number of share options |
Weighted average exercise price £ |
|
| Outstanding at beginning of period | 16,766,515 | 0.01 | 2,752,562 | 0.01 |
| Granted during the period | 4,895,609 | 0.01 | 15,552,824 | 0.01 |
| Exercised in period | (6,677) | 0.01 | (26,188) | 0.01 |
| Forfeited during the period | (344,626) | 0.01 | (1,512,683) | 0.01 |
| Outstanding at end of period | 21,310,821 | 0.01 | 16,766,515 | 0.01 |
| Exercisable at end of period | 62,081 | 0.01 | 6,677 | 0.01 |
The awards outstanding at the end of 31 December 2010 have a weighted average remaining contractual life of 2.3 years (at 31 December 2009 2.4 years) and an exercise price of £0.01 (at 30 June 2009 £0.01).
The aggregate of the fair value of the options granted during the year ended 31 December 2010 was US\$5.2 million (year ended 31 December 2009: US\$4.4 million).
The fair values were calculated using a stochastic model. The inputs used for fair valuing awards granted during the two periods were as follows:
| 2010 | 2009 | |
|---|---|---|
| Weighted average share price (pence) | 129.0 | 45.5 |
| Weighted average exercise price (pence) | 1.0 | 1.0 |
| Expected volatility | 40% | 50% |
| Expected life (years) | 3 | 3 |
| Risk free rate | – | 2.2% |
| Expected dividends | 0.0% | 0.0% |
The volatility of Afren shares was calculated by looking at the available historic movements in Afren's return index as defined by Datastream (an index which tracks share price plus reinvested dividends on the ex-dividend date) over the period commensurate with the proportion of the performance period that had not elapsed by the date of grant. The results were adjusted to take out anomolous period of extreme volatilty which are not expected to be typical for future periods. The resulting estimate was slightly lower than prior periods.
The Company and Group recognised total expenses related to the above equity settled share based payment transactions in the form of options in during the year ended 31 December 2010 of US\$2,604,000 and US\$3,832,000 respectively (2009: US\$1,626,000 and US\$2,281,000 respectively).
As part of the incentives to attract the Jefferies, Randall & Dewey technical team, a number of shares were awarded in 2008, subject to continuing employment in the most part, to the team. None of this team was eligible to an award under the Long Term Incentive Plan. The timing of the shares issued range from six months to three years over which the fair value was spread.
Details of the awards outstanding during the year are as follows:
| 2010 | 2009 | |||
|---|---|---|---|---|
| number of share awards |
weighted average exercise price £ |
Number of share awards |
Weighted average exercise price £ |
|
| Outstanding at the beginning of the period | 982,656 | 0.01 | 2,969,563 | 0.01 |
| Granted during the period | – | – | ||
| Exercised in the period | (585,080) | 0.01 | (1,902,357) | 0.01 |
| Lapsed in the period | 0.01 | (84,550) | 0.01 | |
| Outstanding at the end of the period | 397,576 | 0.01 | 982,656 | 0.01 |
| Exercisable at the end of the period | – | 0.01 | – | 0.01 |
The weighted average share price of awards exercised in the year to 31 December 2009 was £0.91.
The weighted average remaining contractual life of the options outstanding at 31 December 2009 was 0.4 years (31 December 2010 0.7 years).
All awards have an exercise price of £0.01.
In the year to 31 December 2008 awards were granted to 13 new employees on joining from Randall and Dewey. The aggregate of the fair value of the options granted during 2008 was \$11 million. No awards were made in 2009 or 2010.
As the exercise price for these awards is nominal and there are no market based vesting criteria, the awards granted were valued using the share prices on dates of grant which was 137p on a weighted average basis. The Company and Group recognised total expenses related to equity settled share based payment transactions in relation to the above awards in the year ended 31 December 2010 of US\$351,000 and US\$408,000 respectively (year ended 31 December 2009 US\$861,000 and US\$2,404,000 respectively).
From time to time, the Company will give consideration for services or assets in the form of warrants.
Details of the warrants outstanding during the year are as follows:
| 2010 | 2009 | ||||
|---|---|---|---|---|---|
| number of warrants |
weighted average exercise price £ |
Number of warrants |
Weighted average exercise price £ |
||
| Outstanding at beginning of year | 2,545,000 | 0.70 | 2,345,000 | 0.67 | |
| Granted during the year | – | – | 200,000 | 1.00 | |
| Exercised during the year | – | – | – | – | |
| Outstanding at end of year | 2,545,000 | 0.70 | 2,545,000 | 0.70 | |
| Exercisable at end of year | 2,545,000 | 0.70 | 2,461,666 | 0.68 |
The weighted average remaining contractual life of the options outstanding at 31 December 2010 was 1.6 years (2009: 2.6 years).
The aggregate of the fair value of the warrants granted in 2010 was US\$nil (2009: US\$0.1 million).
For the year ended 31 December 2010 continued
The warrants granted have been valued by reference to the Black Scholes option valuation model. The inputs into the Black Scholes model were as follows:
| 2010 | 2009 | |
|---|---|---|
| Weighted average share price (pence) | n/a | 84.8 |
| Weighted average exercise price (pence) | n/a | 100.0 |
| Expected volatility | n/a | 50% |
| Weighted average expected life (years) | n/a | 5 |
| Risk free rate | n/a | 5.0% |
| Expected dividends | n/a | nil |
The Company and Group recognised total costs of US\$140,000 (2009:US\$95,000) related to equity settled share based transactions in the form of warrants in 2010.
As presented to the AGM in June 2007, a Founders' Scheme has been introduced. Under this scheme the Founders of Afren undertook to invest a total of US\$5.0 million equivalent in Afren shares prior to 30 September 2008 and were granted a total of 40 million warrants. The agreements were finalised and warrants granted in January 2009. The warrants had an exercise price of £1.60 per share but were only exercisable if the share price reached £2.50 for at least 30 days (an increase of 56% above the exercise price). The warrants expired in December 2009. The warrants were also subject to certain anti-dilution clauses which meant that they were re-priced following the private placement in May 2009 to £0.38 being the lower of the share price over the five days prior to the issue of the shares or the issue price of the new shares plus 20%. The performance target was similarly repriced to 56% above the warrant price.
| 2009 | ||
|---|---|---|
| Number of share options |
Weighted average exercise price £ |
|
| Outstanding at beginning of period | – | – |
| Granted during the period | 40,000,000 | 1.60 |
| Exercised during the period | (40,000,000) | 0.38 |
| Outstanding at end of period | – | – |
| Exercisable at end of period | – | – |
The weighted average share price of awards exercised in 2009 was 81 pence.
The aggregate of the fair value of the warrants granted in 2009 was US\$2.77 million and the Group and Company recognised total expenses related to equity-settled share-based payments in relation to the above awards of US\$2.77 million.
The warrants granted under the Founders' Scheme were valued by reference to the Barrier Option Valuation Model, and probability weighted to reflect the 50% likelihood (being the Directors' estimate at the time of grant) of a repricing event occurring prior to the end of the life of the options due to a subsequent equity-raising event. The other inputs into the Barrier model at grant date (i.e. before May 2009 repricing) were as follows:
| 2009 | |
|---|---|
| Weighted average share price (pence) | 26 |
| Weighted average exercise price (pence) | 160 |
| Weighted average target price before eligibility to exercise (barrier) (pence) | 250 |
| Expected volatility | 90% |
| Weighted average expected life (years) | 0.96 |
| Risk free rate | 1% |
| Expected dividends | – |
The volatility of Afren shares was reviewed as part of the option valuation exercise and the volatility adjusted for the valuation of the warrants granted under the Founders' Scheme to reflect the one-year life of the warrants, and the relatively high volatility expected to continue over this time frame.
On 7 October 2010, the Company completed the acquisition of Black Marlin Energy Holdings Limited (Black Marlin) having received all necessary approvals. The acquisition comprised exploration acreage covering 12 assets in Kenya, Madagascar, Ethiopia and Seychelles. Afren issued 76,776,096 ordinary shares to holders of Black Marlin shares in return for 100% of the issued share capital. Afren's closing share price on completion was 114.5 pence. In addition, 1 million outstanding options to acquire Black Marlin shares were converted to acquire Afren shares on substantially equivalent terms and conditions.
The book values of identifiable assets and liabilities acquired and their provisional fair value to the Group is as follows:
| Provisional fair | |||
|---|---|---|---|
| Fair value | value to the | ||
| Book value | adjustments | Group | |
| US\$000's | US\$000's | US\$000's | |
| Intangible oil and gas assets | 16,428 | 170,512 | 186,940 |
| Marine and land seismic equipment and operational vehicles | 5,287 | (2,475) | 2,812 |
| Other property, plant and equipment | 407 | (213) | 194 |
| Trade and other receivables | 7,229 | (288) | 6,941 |
| Cash and cash equivalents | 2,395 | (106) | 2,289 |
| Trade and other payables | (7,527) | (11,521) | (19,048) |
| Deferred tax liability | – | (39,817) | (39,817) |
| 24,219 | 116,092 | 140,311 | |
| Total consideration | 140,311 | ||
| Total consideration | 140,311 | ||
| Cash and cash equivalents acquired | 2,289 | ||
| Less non- cash consideration* | (140,311) | ||
| Cash inflow on acquisition | 2,289 |
* Non-cash consideration relates to shares and options issued as described above.
Technical evaluation and assessment of the oil and gas assets acquired is ongoing and therefore the fair values assigned are provisional pending the completion of the evaluation.
The acquired business recorded a loss after taxation of US\$30.8 million in the year ended 31 December 2010 of which US\$29.4 million was made during the period from the beginning of the year to the acquisition date and a US\$1.4 million loss was recorded after acquisition, which included US\$0.6 million attributable to discontinued operations. The revenue for the year ended 31 December 2010 was US\$7.1 million of which US\$6.6 million arose from the discontinued operations.
Acquisition related costs amounting to US\$3.9 million have been recognised as an expense in the current year and are included in administrative expenses in the consolidated income statement.
If the acquistion had completed on 1 January 2010, the total Group revenues would have been US\$324.7 million of which US\$319.5 million is from continuing activities. The total Group profit for the year would have been US\$14.9 million and that from continuing activities US\$28.6 million. This proforma information is for illustrative purposes only and is not necessarily an indication of the revenues and results of the Group that actually would have been achieved had the acquisition been completed on 1 January 2010, nor is it intended to be a projection of future results.
For the year ended 31 December 2010 continued
| Share-based | |||||
|---|---|---|---|---|---|
| Translation | payment | Other | |||
| reserve | Loan notes | reserve | movements | Total | |
| US\$000's | US\$000's | US\$000's | US\$000's | US\$000's | |
| group | |||||
| At 1 January 2009 | (831) | 6,980 | 11,705 | 319 | 18,173 |
| Share based payments for services | – | – | 9,197 | – | 9,197 |
| Other share-based payments | – | – | 95 | – | 95 |
| Transfer to accumulated losses | – | (2,312) | (7,562) | – | (9,874) |
| Other movements | – | – | – | (319) | (319) |
| At 31 December 2009 | (831) | 4,668 | 13,435 | – | 17,272 |
| Share based payments for services | – | – | 9,359 | – | 9,359 |
| Other share-based payments | – | – | 313 | – | 313 |
| Transfer to accumulated losses | – | (2,474) | (2,206) | – | (4,680) |
| Shares to be issued | – | – | – | 500 | 500 |
| At 31 December 2010 | (831) | 2,194 | 20,901 | 500 | 22,764 |
| Share-based | |||||
|---|---|---|---|---|---|
| Translation | payment | Other | |||
| reserve | Loan notes | reserve | movements | Total | |
| US\$000's | US\$000's | US\$000's | US\$000's | US\$000's | |
| company | |||||
| At 1 January 2009 | 1,603 | 6,980 | 11,705 | 319 | 20,607 |
| Share based payments for services | – | – | 9,197 | – | 9,197 |
| Other share-based payments | – | – | 95 | – | 95 |
| Transfer to accumulated losses | – | (2,312) | (7,562) | – | (9,874) |
| Other movements | – | – | – | (319) | (319) |
| At 31 December 2009 | 1,603 | 4,668 | 13,435 | – | 19,706 |
| Share based payments for services | – | – | 9,359 | – | 9,359 |
| Other share-based payments | – | – | 313 | – | 313 |
| Transfer to accumulated losses | – | (2,474) | (2,206) | – | (4,680) |
| Shares to be issued | – | – | – | 500 | 500 |
| At 31 December 2010 | 1,603 | 2,194 | 20,901 | 500 | 25,198 |
| Group | Company | ||||
|---|---|---|---|---|---|
| 2010 us\$000's |
2009 US\$000's |
2010 us\$000's |
2009 US\$000's |
||
| At 1 January | (129,895) | (122,991) | (105,828) | (87,233) | |
| Profit/(loss) for the year | 45,259 | (16,778) | 17,764 | (28,469) | |
| Exercise of warrants designated as financial liabilities | 2,088 | – | 2,088 | – | |
| Transfer from other reserves | 4,680 | 9,874 | 4,680 | 9,874 | |
| At 31 December | (77,868) | (129,895) | (81,296) | (105,828) |
On 27 January 2011, Afren announced the successful pricing of its offering of U\$\$450 million aggregate principal amount of its 11.5% senior secured notes due 2016 (the Notes). The Notes will be guaranteed on a senior basis by certain subsidiaries of Afren plc and on a subordinate basis by Afren Resources Limited. Interest will be paid semi-annually. Part of the proceeds of the offering were used to settle borrowings amounting to US\$169 million (net of issue costs) and accrued interest of US\$2.4 million recorded in the balance sheet as at 31 December 2010.
On 11 February 2011, Afren announced offering of an additional US\$50 million of its 11.5% senior secured notes due 2016.
On 24 March 2011, Afren announced acquisition of a 74% operated interest in Tanga Block, located onshore and offshore and will Tanzania, from Petrodel Resources Limited (''Petrodel''). Afren reimbursed Petrodel a percentage of back costs (US\$2.8 million) in relation to the block, will fund costs of seismic survey and supported by the seismic, carry Petrodel through the drilling of one shallow water exploration well subject to a cumulative cap on gross costs of US\$40 million.
In 2011 to date the political situation in Côte d'Ivoire deteriorated significantly which also resulted in disruption to the local financial system. At 31 December 2010, Afren had no material financial assets that were exposed, and its production assets have continued in operation without interruption to date. Afren is monitoring the situation closely, including the impact of the sanctions regime imposed by the EU.
The transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation. Amounts owed by and to such subsidiaries are disclosed in notes 18 and 20 respectively. Transactions between the Company and its subsidiaries were as follows:
| 2010 | subsidiaries us\$000's |
joint ventures us\$000's |
|---|---|---|
| Net loan advances | 227,971 | (1,932) |
| Investments | 148,110 | – |
| 2009 | Subsidiaries US\$000's |
Joint Ventures US\$000's |
| Net loan advances | 159,054 | 929 |
| Investments | 3,716 | – |
For the year ended 31 December 2010 continued
Remuneration of key management personnel
The remuneration of the key management personnel of the Group is set out below in aggregate for each of the categories specified in IAS 24 'Related Party Disclosures'.
| 2010 us\$000's |
2009 US\$000's |
|
|---|---|---|
| Short-term employee benefits* | 4,835 | 3,201 |
| Other long-term benefits | 165 | 74 |
| Share-based payment | 3,331 | 5,577 |
| 8,331 | 8,852 |
* These amounts exclude amounts payable to Bert Cooper through Energy Investment Holdings Ltd as described further below.
| Purchase of goods/services | Amounts owed to related parties |
||||
|---|---|---|---|---|---|
| year ended 2010 us\$000's |
Year ended 2009 US\$000's |
year ended 2010 us\$000's |
Year ended 2009 US\$000's |
||
| Energy Investment Holdings Ltd | 465 | 3,092 | (102) | – | |
| St. John Advisors | 479 | 1,083 | – | 28 | |
| Tzell Travel Group | 1,007 | 367 | 17 | 22 | |
| H'Art of Africa | – | 69 | – | – |
Energy Investment Holdings Ltd is the contractor company for the consulting services of Bert Cooper, a member of the International Advisory Board and Special Adviser to Afren plc. The payments relate to consultancy services provided during the year.
St. John Advisors is the contractor company for the consulting services of John St. John for which they receive fees from the Company, a Non-Executive Director. St. John Advisors also receive a monthly retainer of £15,000 for consulting advice. This contract is for 12 months from 27 June 2008 and automatically continues thereafter unless terminated by either party. During the year a separate contract with STJ Advisors LLP, another contractor company related to John St John, was engaged for consulting services on the Senior Note offer which completed on 27 January 2011. John St.John received US\$185,000 in fees during 2010 in relation to this contract.
Tzell Travel Group operates as a franchise. The franchisee utilised by Afren for some of its travel needs is a close family member of the Chief Executive Officer and Tzell Travel Group is therefore considered a related party. Afren uses several travel agents as there is a significant travel element to its operations and Tzell competes on an even basis with these. Tzell provided approximately 18% (2009: 14%) of the travel arrangements by value.
H'Art of Africa is a business specialising in the importation of African art. It is owned and run by a close family member of a Director of Afren appointed in 2008 and was engaged to source art for the Afren office in the UK.
First Hydrocarbon Nigeria Limited (FHN) became an associate of Afren plc during the year. Constantine Ogunbiyi, former Executive Director of Afren has been seconded to FHN to serve in the capacity of Chief Executive Officer of FHN. FHN has an outstanding payable to Afren of US\$2.25 million. Information on the investment in FHN is disclosed in notes 14 and 15.
| country | date acquired | wi (%) | Operator | Partner | work programme |
|---|---|---|---|---|---|
| nigeria | |||||
| Ebok(7) | Q1 2008 | 100% / 50%(2) | Afren | Oriental | |
| Okoro Setu(7) | Q2 2006 | 95% / 50%(2) | Afren | Amni | |
| Okwok(7) | Q3 2009 | 70% / 56%(2) | Afren | Oriental | |
| OML 115(7) | Q1 2010 | 100% / 40%(2) | Afren | Oriental | |
| OML 26(4) | Q3 2010 | 45% | Afren | FHN | |
| OPL 310 | Q4 2008 | 91% / 70%(2) | Afren | Optimum | |
| OPL 907 | Q1 2008 | 51.25% / 41%(2,3) | AGER(6) | GEC | |
| OPL 917 | Q1 2008 | 70% / 42%(2,3) | AGER(6) | GEC | |
| Ofa | Q2 2007 | 32.5% | Afren | IEL | |
| côte d'ivoire | |||||
| Block CI-11 | Q3 2008 | 47.96% | Afren | PETROCI | |
| Block CI-01 | Q3 2008 | 65%(1) | Afren | PETROCI | |
| Lion Gas Plant | Q3 2008 | 100% | Afren | PETROCI | |
| ghana | |||||
| Keta Block | Q4 2007 | 35%(8) | ENI | GNPC | |
| nigeria & são Tomé & Principe jdZ | |||||
| Block 1 | Q1 2005 | 4.41%(5) | Total | Total | |
| congo (Brazzaville) | |||||
| La Noumbi | Q2 2006 | 14% | Maurel et Prom | ENI | |
| Ethiopia | |||||
| Blocks 2, 6, 7, 8 | Q3 2010 | 30% | Africa Oil | Africa Oil | |
| kenya | |||||
| Block 10A | Q3 2010 | 20% | Tullow Oil | Africa Oil | |
| Block L17/L18 | Q3 2010 | 100% | EAX(10) | – | |
| Block 1 | Q3 2010 | 50% | EAX(10) | Lion Petroleum | |
| seychelles | |||||
| Blocks A,B,C | Q3 2010 | 75% | EAX(10) | Avana Petroleum | |
| madagascar | |||||
| Block 1101 | Q3 2010 | 40% | Candax | Candax | |
| Tanzania | |||||
| Tanga Block | Q1 2011 | 74% | Afren | Petrodel | |
| south africa | |||||
| Block 2B | Q1 2011 | 25%(9) | Thombo | – |
* Not Audited
(1) Direct Participating Interest. Afren also holds rights over an additional 15% interest.
(2) Afren effective working interest pre/post cost recovery.
(3) Held through AGER in which Afren holds an 50% economic interest.
(4) Held through FHN in which Afren holds a 45% interest (subject to customary government approvals).
(5) Afren has a 49% interest in DEER which has a 9% working interest in JDZ Block 1.
(6) Afren Global Energy Resources.
(7) Note on the Okoro Setu project, Afren is the technical service provider to Amni, the named operator. On the Ebok project, Okwok and OML 115, Afren is the technical service provider to Oriental Energy Resources.
(8) The farm down of Afren's interest is subject to customary government and partner approvals. Following such approvals, Afren will retain a 35% participating interest and transfer operatorship to ENI.
(9) Subject to customary approvals; working interest increases to 50% and operatorship transferred to Afren upon completion of seismic acquisition programme.
(10) EAX is a wholly owned subsidiary of Afren plc.
Production Exploration Appraisal/planned development
Shareholder Information
at 31 December 2010
| working interest basis before royaltites | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| nigeria | côte d'ivoire | nigeria – são Tomé & Príncipe jdZ |
Total group | |||||||||
| Oil (mmbbl) |
Gas (bcf) |
mmboe | Oil (mmbbl) |
Gas (bcf) |
mmboe | Oil (mmbbl) |
Gas (bcf) |
mmboe | Oil (mmbbl) |
Gas (bcf) |
mmboe | |
| Group Proved and Probable Reserves |
||||||||||||
| At 31 December 2009 | 81.4 | – | 81.4 | 0.9 | 20.2 | 4.4 | – | – | – | 82.3 | 20.2 | 85.8 |
| Revisions of previous estimates | 0.2 | – | 0.2 | (0.3) | (4.9) | (1.2) | – | – | – | (0.1) | (4.9) | (1.0) |
| Discoveries and extensions | – | – | – | – | – | – | – | – | – | – | – | – |
| Acquisitions | – | – | – | – | – | – | – | – | – | – | – | – |
| Divestments | – | – | – | – | – | – | – | – | – | – | – | – |
| Production | (4.1) | – | (4.1) | (0.2) | (4.1) | (0.9) | – | – | – | (4.3) | (4.1) | (5.0) |
| At 31 December 2010 | 77.5 | – | 77.5 | 0.4 | 11.2 | 2.3 | – | – | – | 77.9 | 11.2 | 79.8 |
| Contingent Resources | ||||||||||||
| At 31 December 2009 | 0.8 | – | 0.8 | 12.9 | 66.0 | 24.2 | 1.9 | – | 1.9 | 15.5 | 66.0 | 26.9 |
| Revisions of previous estimates | – | – | – | – | – | – | – | – | – | – | – | – |
| Discoveries and extensions | 29.0 | – | 29.0 | – | – | – | – | – | – | 29.0 | – | 29.0 |
| Acquisitions | – | – | – | – | – | – | – | – | – | – | – | – |
| Divestments | – | – | – | – | – | – | – | – | – | – | – | – |
| At 31 December 2010 | 29.8 | – | 29.8 | 12.9 | 66.0 | 24.2 | 1.9 | – | 1.9 | 44.5 | 66.0 | 55.9 |
| Total Reserves and Contingent Resources |
||||||||||||
| At 31 December 2009 | 82.2 | – | 82.2 | 13.8 | 86.2 | 28.6 | 1.9 | – | 1.9 | 97.8 | 86.2 | 112.7 |
| Revisions of previous estimates | 0.2 | – | 0.2 | (0.3) | (4.9) | (1.2) | – | – | – | (0.1) | (4.9) | (1.0) |
| Discoveries and extensions | 29.0 | – | 29.0 | – | – | – | – | – | – | 29.0 | – | 29.0 |
| Acquisitions | – | – | – | – | – | – | – | – | – | – | – | – |
| Divestments | – | – | – | – | – | – | – | – | – | – | – | – |
| Production | (4.1) | – | (4.1) | (0.2) | (4.1) | (0.9) | – | – | – | (4.3) | (4.1) | (5.0) |
| At 31 December 2010 | 107.3 | – | 107.3 | 13.3 | 77.2 | 26.6 | 1.9 | – | 1.9 | 122.4 | 77.2 | 135.7 |
Notes:
– Reserves and resources above are stated on a working interest basis (i.e. for the Nigerian contracts our net effective ultimate working interest based on working interest to payback (95% to 100%) and WI post payback (50%).
– Proved plus Probable (2P) reserves have been prepared in accordance with the definitions and guidelines set forth in the 2007 PRMS approved by the SPE.
– Contingent resources are those quantities of petroleum that are estimated to be potentially recoverable from known accumulations but for which the projects are not yet considered mature enough for commercial development due to one or more contingencies.
– Quantities of oil equivalent are calculated using a gas-to-oil conversion factor of 5,800 scf of gas per barrel of oil equivalent.
– The oil price used by NSAI for their report as at 31/12/10 was US\$100/bbl for the first half of 2011, US\$80/bbl for the second half of 2011, increasing at a rate of 5% per annum thereafter.
The Group provides for depletion and amortisation of tangible fixed assets on a net entitlement basis, which reflects the terms of the licences and agreements relating to each field. Total net entitlement reserves were 68.1 mmboe at 31 December 2010.
AGM Annual General Meeting
appraisal well A well drilled to follow up a discovery and evaluate its commercial potential
bbls barrels of oil
bcf billion cubic feet of gas
boe barrels of oil equivalent
boepd barrels of oil equivalent per day
bopd barrels of oil per day
capital employed equity plus interest-bearing debt
CR Corporate Responsibility
deg API a measure of how heavy or light a petroleum liquid is compared with water
dwt dead weight tonnage
EHSS environment, health, safety and security
farm-in to acquire an interest in a licence from another party
farm-out to assign an interest in a licence to another party
FPSO Floating Production Storage and Offloading vessel ft feet
GOR Gas Oil Ratio
H1 first half
H2 second half
Hydrocarbons compounds containing only the elements hydrogen and carbon; they may exist as solids, liquids or gases
JDZ Joint Development Zone
joint venture or JV a group of companies who share the cost and rewards of exploring for and producing oil or gas from a permit or licence
JSE Johanesburg Stock Exchange
km2 square kilometres
licence or permit area of specified size, which is licensed to a company by the government for production of oil and gas
LSE London Stock Exchange
Major Major international oil company
m metres
mmbbl, mmbbls million barrels
mmboe millions of barrels of oil equivalent
mmcfd million cubic feet of gas per day
MOPP Mobile Offshore Production Platform MOU Memorandum of Understanding
OML Oil Mining Licence
operator a company which organises the exploration and production programmes in a permit or licence on behalf of all the interest holders in the permit or licence
OPL Oil Prospecting Licence
Q1 first quarter
Q2 second quarter
Q3 third quarter
Q4 fourth quarter
spud to commence drilling a well
STOIIP Stock Tank Oil Initially In Place
tcf trillion cubic feet of gas
working interest (WI) Afren's share of the field based on Afren's equity share of the field including pre-payback and post pay-back equity percentages and before deduction
1P proven
of royalties.
2P proven and probable
3P proven, probable and possible
3D three-dimensional
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