Seplat Energy Regulatory News (SEPL)

Seplat Petroleum Development Company Plc

Full year 2014 preliminary financial results

26 March 2015

Announcement

Lagos and London, 26 March 2015: Seplat Petroleum Development Company Plc ("Seplat" or the "Company"), a leading Nigerian indigenous oil and gas company, listed on both the Nigerian Stock Exchange and London Stock Exchange, today announces its full year 2014 financial results and provides an operational update.

Commenting on the results, Austin Avuru, Seplat's Chief Executive Officer, said "Our financial results reflect the deterioration in oil price and extended periods of downtime on third party export infrastructure in 2014. Despite this we made good progress towards our long term strategic aims. We have materially grown our reserves base, delivered full year average daily production in line with guidance and exceeded peak rate objectives. Expansion plans for our gas business gathered pace and the new Oben gas processing plant will allow us to increase supply to the domestic market. Looking ahead, in 2015 we will take a prudent approach and seek to align spend with cash flow, allocate our capital selectively and prioritise the investments that offer the highest returns. We will capitalise on opportunities to re-base our cost structure and maintain a robust capital structure, positioning Seplat well to benefit from any future recovery of the sector."

Full year results highlights

· Working interest 2P reserves at end 2014 independently estimated to be 281 MMboe representing a movement of +24% year-on-year and 400% replacement ratio of production in the year. Working interest 2C resources stand at 281 MMboe(1)

· Full year working interest production of 30,823 boepd in line with guidance of 29,000 - 33,000 boepd; excluding 40 days un-budgeted downtime on third party infrastructure, average working interest production was 34,616 boepd

· Net profit for 2014 was US$252 million. Normalised for one off charges of US$70 million, net profit would have totalled US$322 million; cash flow from operations before movements in working capital was US$353 million, ahead of capital investments of US$294 million

· Cash at bank and net debt at year end (excluding the amount held as a deposit for investment of US$453 million) stood at US$285 million and US$304 million respectively; successfully completed US$1 billion debt re-financing in January 2015

· Installation and commissioning of the new 150 MMscfd Oben gas processing facility is a major step forward for Seplat's gas business and increases volumes available to the domestic market; new pipeline to Warri refinery commissioned in March 2014; good progress made at the other capital projects in 2014

· Completed the acquisition of interests in OML 53 and OML 55 post period end materially expanding the Company's portfolio in the Niger Delta

· Working interest production and capex guidance for 2015 is 32,000 boepd to 36,000 boped and US$168 million respectively

· Key strategic initiative achieved through successful IPO in April 2014 and dual listing on the Nigeria Stock Exchange and London Stock Exchange; gross proceeds of US$535 million raised

Financial overview

(1) Includes management estimates for OML 53 and OML 55 which remain subject to independent assessment and classification

(2) Before movements in working capital

Webcast and conference call

At 9:00 am GMT (London) / 10:00 am WAT (Lagos), Austin Avuru (CEO), Stuart Connal (COO), and Roger Brown (CFO) will host a webcast and conference call to discuss the Company's results.

The webcast can be accessed via the Company's website www.seplatpetroleum.com or at the following address:

https://webconnect.webex.com/webconnect/onstage/g.php?MTID=e623508ea8adbc86c338348e1f32eaa9b

To listen to the audio commentary only, participants can use the following telephone number:

Telephone Number: +44 (0) 1452 569 393

Conference ID: Seplat Petroleum

The presentation slides will also be available on the Company's website www.seplatpetroleum.com at 7:00am GMT (London) / 8:00am WAT (Lagos).

Enquiries

Notes to editors

Seplat Petroleum Development Company Plc is a leading indigenous Nigerian oil and gas exploration and production company with a strategic focus on Nigeria, listed on the Main Market of the London Stock Exchange ("LSE") (LSE:SEPL) and Nigerian Stock Exchange ("NSE") (NSE:SEPLAT).

In July 2010, Seplat acquired a 45 percent participating interest in, and was appointed operator of, a portfolio of three onshore producing oil and gas leases in the Niger Delta (OMLs 4, 38 and 41), which includes the producing Oben, Ovhor, Sapele, Okporhuru, Amukpe and Orogho fields. Since acquisition, Seplat has more than tripled production from these OMLs.

In June 2013, Newton Energy Limited, a wholly-owned subsidiary of the Company, entered into an agreement with Pillar Oil Limited to acquire a 40 percent participating interest in the Umuseti/Igbuku marginal field area within OPL 283. In February 2015, Seplat completed the acquisition of a 40 percent operated working interest in OML 53 and a 22.5 percent operated working interest in OML 55, Onshore Nigeria.

Seplat is pursuing a Nigeria focused growth strategy and is well-positioned to participate in future divestment programmes by the international oil companies, farm-in opportunities and future licensing rounds. For further information please refer to the company website, http://seplatpetroleum.com/

Full year 2014 results overview

Reserves

Working interest 2P reserves at 31 December 2014 stood at 281 MMboe, comprising 139 MMbbls of oil and condensate and 827 Bscf of natural gas. This represents an increase in overall 2P reserves of 24% year-on-year. The key drivers of the upwards revision is the recognition of reserves at Orogho, Sapele Shallow and Okwefe following review of 2014 well performance data and the conversion from 2C to 2P as a result of 2014 development activities.

Full year average daily production

Note: Liquid production volumes as measured at the LACT unit for OMLs 4, 38 and 41 and OPL 283 flow station. Volumes stated are subject to reconciliation and will differ from sales volumes within the period.

Despite a total of 40 days of un-budgeted downtime of the Trans Forcados System (out of a total of 75 days) in 2014, Seplat's full year average working interest production was marginally up on 2013 at 30,823 boepd. The impact of more reliable gas offtake by customers together with increased oil and gas production capacity through the drilling of new wells and the inclusion of Pillar production offset the periods of downtime. Excluding the unplanned days when the fields were shut in, Seplat's total average working interest production was approximately 34,600 boepd.

During 2014 approximately 98.5% of liquids production from OMLs 4, 38 and 41 was transported through the Trans Forcados System (TFS). Overall reconciliation losses arising from use of the TFS were 10.6%. First deliveries were made to the Warri refinery in March, and gross deliveries at year end stood at 288,811 barrels. It is intended that availability of an alternative export route will mitigate sole reliance on one export system and allow for improved uptime and operational efficiency. The Company achieved a new production record in December 2014 when gross daily liquids production at OMLs 4, 38 and 41 exceeded 76,000 bopd for the first time.

In 2015, the Company expects full year average working interest production of 32,000 boepd to 36,000 boepd based on the current work programme.

Positioning Seplat in a lower oil price environment

Following the abrupt decline in oil prices during the second half of 2014 and continued weakness in 2015 year-to-date, Seplat will prioritise the allocation of capital to production and development opportunities that offer the most robust economic returns. The Company anticipates modest exploration and appraisal expenditure under current conditions, and aims to align spend with cash flow. Seplat is the designated operator at its key projects, and as such is able to influence the magnitude and timing of expenditures. The Company constantly reviews its cost structures, and will take every opportunity to apply downward pressure to its overall cost base. By also investing in its natural gas business and growing gas production the Company is able to partially offset its exposure to oil price volatility, benefitting from a revenue stream derived from gas prices that are not linked to the oil price.

Finance

Seplat is underpinned by a platform of cash generative production and a robust capital structure. Although production was up, the un-budgeted downtime of the TFS adversely impacted revenue growth. Revenue for 2014 was down 12% from 2013 at US$775 million as a result of the decline in oil price in the second half along with a one-off non-recurring payment of US$82 million in 2013 from Shell relating to prior years' barrels not recognised. Net profit for the year stood at US$252 million following one-off costs of US$70 million. Normalised for these charges, net profit would have totaled US$322 million. Cash flow from operations before movements in working capital was US$353 million, ahead of capital investments of US$296 million. Cash at bank and net debt at year end (excluding amounts held as deposit for investment of US$453 million) stood at US$285 million and US$304 million respectively. Post period end the Company successfully refinanced its existing debt facilities with a new US$700 million seven year secured term facility and US$300 million three year secured revolving credit facility. The seven year facility also includes an option to upsize the facility by up to an additional US$700 million for qualifying acquisition opportunities.

Capital projects and rig based activity

The Company made good progress at its capital projects in 2014. Work has progressed well on the new 150 MMscfd Oben gas processing facility that will make additional volumes available to the domestic market and the gas lift project at Amukpe, targeting the Ovhor field, was operational before year end. Work is expected to be completed on the construction and installation of two 50,000 barrel storage tanks at the Amukpe field in 2015. The Company completed and commissioned a new 100,000 bopd liquids pipeline in the first quarter of 2014, linking production from OMLs 4, 38 and 41 directly to the Warri refinery, and also commissioned a new liquid treatment facility to allow for deliveries of dry crude to the Warri refinery. High levels of rig based activity were undertaken in 2014. Over the course of the year the Company had up to seven rigs operating concurrently. The Company drilled and completed 23 wells comprising 12 development wells, four appraisal wells, five workovers, one water injector and one water producer during the year.

New ventures

Seplat has an active new ventures pipeline. In 2014 the Company reported that US$453 million had been allocated as a refundable deposit against a potential investment. The Company will no longer proceed with the potential investment and has initiated the process to withdraw the funds from escrow and reinstate as cash at bank. Post period end the Company completed the acquisition of a 40.00% working interest in OML 53 and a 22.50% working interest in OML 55. The acquisitions are consistent with Seplat's growth strategy which is to maintain price discipline and prioritise opportunities in the onshore and shallow waters offshore Nigeria that offer near-term production, cash-flow and reserve replacement potential.

Gas business

Alongside the oil business, the Company has also prioritised the commercialisation and development of the substantial gas reserves and resources identified at its blocks and is today a leading supplier of gas to the domestic market in Nigeria. Going forward, Seplat plans to further increase its gas production and processing capacity to help meet Nigeria's growing demand, particularly in the gas to power sector. A major step forward in this respect is the modular build-up of processing capacity at the Oben facility to create a strategic gas hub ideally located to aggregate and supply gas to Nigeria's main demand centres. The new 150 MMscfd Oben gas processing facility will take overall gross production capacity at the Company's assets up to 300 MMscfd in 2015 and the Company intends to grow this further to at least 450 MMscfd by 2017.

Landmark IPO and dual listing

In April 2014 Seplat completed the first ever IPO involving a dual listing on both the London Stock Exchange and the Nigerian Stock Exchange. The Company raised gross proceeds of US$535 million at N576 per share (GBP2.10 per share). The IPO ranked as the largest for an African sub-Sahara company since 2008 and the second largest ever for a Nigerian company. The capital raised and listed status will enhance Seplat's ability to further implement its growth strategy.

Recommended full year dividend

The board of Seplat is recommending a final dividend of US$0.09 per share, bringing the total payment for the year to US$0.15 per share. Subject to approval of shareholders, the dividend will be paid on or shortly after the AGM which will be held on 2nd June 2015 in Lagos, Nigeria.

Operations review

Since inception, Seplat has acquired an attractive portfolio of assets in the prolific Niger Delta region. The Company's portfolio provides a strong platform of oil and natural gas reserves and production together with material upside opportunities through 2C to 2P conversion and exploration and appraisal drilling. Seplat's initial focus has been on securing assets in the onshore regions of the Niger Delta, but the Company also views the shallow water offshore areas of the Niger Delta as an appealing opportunity set and one it aims to access in the future.

OMLs 4, 38 & 41

Seplat has a 45% working interest in OMLs 4, 38 and 41 which are located in Edo (OML 4) and Delta (OMLs 38 and 41) States onshore Nigeria. Seplat is operator of the three blocks on behalf of the NPDC/Seplat Joint Venture and, to date, is the only company that has secured NPDC approval for operatorship over blocks acquired as part of recent divestment programmes by the major IOCs. Production is predominantly from six fields, namely Amukpe, Oben, Okporhuru, Ovhor, Orogho and Sapele and the partners aim to bring additional fields on stream in the future. 

Since acquiring the blocks in July 2010 the Company has consistently grown oil production, primarily through the drilling of new wells and employing advanced and proven technologies to increase production in mature fields. The Company became the first operator in the Niger Delta to install a lease automated custody transfer (LACT) unit, enabling significantly improved measurement of produced oil prior to injection into the Trans Forcados Pipeline system. This has greatly reduced the reconciliation losses applied to the Company's oil production to a level of approximately 10%, compared to an average of approximately 18% prior to installation of the LACT unit. The installation and commissioning of a new liquids pipeline in 2014, linking the Company's fields directly to the Warri Refinery, will mitigate sole reliance on one export pipeline system and offer scope to further reduce losses in the future.

OML 4

Background

OML 4 covers an area of 267 km2 and is located 78 km North East of Warri, Delta State. The Oben field is located in OML 4 and is the main producing field on the block. Facilities on the block include a 60,000 bpd capacity flow station and a 90 MMscfd capacity non-associated gas plant. The gas plant exports gas to the Nigerian gas network via the ELPS. The Company expects to complete installation and commissioning of a new 150 MMscfd gas processing plant in Oben by early 2015. Oil exports from the Oben flow station are routed via the Oben - Amukpe pipeline to the Amukpe facilities and onwards to either the Forcados terminal or Warri Refinery. Also expected for installation and commissioning in the first quarter of 2015 is a new 30 MMscfd associated gas processing and compressor station to eliminate and monetise currently flared associated gas from the Oben flow station. Production operations and facilities are supported by the Oben Field Logistics Base. The Oben field in particular is central to the Company's future gas expansion plans and is strategically located as an important gas hub with access to Nigeria's main gas demand centres. The licence was renewed in 1989 for a further 30 years and is due to expire on 30 June 2019.

2014 activity

In 2014 fabrication work was completed and the Company took delivery of the new 150 MMscfd gas processing facility and commenced installation work at the Oben field location. This represents the first phase of a programme designed to expand gas processing capacity at the Oben field to 240 MMscfd in 2015 and at least 450 MMscfd by 2017. Installation work was ongoing at year end with commissioning work underway in the first quarter of 2015 that will make additional gas volumes available to the domestic market. Also in 2014, three units of 10 MMscfd capacity associated gas compressors and ancillary equipment were delivered to the Oben field in the fourth quarter for the purpose of building the new compressor station that will provide an associated gas solution for the Oben flow station. Installation is ongoing and commissioning is planned to begin at the end of the first quarter of 2015. During the year the partners drilled two appraisal wells, eight development wells and two workover wells on the block.

OML 38

Background

OML 38 covers an area of 2,094 km2 and is located 48 km North of Warri, Delta State. The Amukpe field is one of the three producing fields in the block. The second producing field, Ovhor, straddles OML 38 and OML 41. The Company commenced production from the third producing field, Okporhuru, in May 2013. There are two further discoveries on OML 38 that have not been brought into production, the Mosogar and Jesse discoveries. Facilities on the block include a 45,000 bpd capacity flow station located at Amukpe. The licence was renewed in 1989 for a further 30 years expiring on 30 June 2019.

2014 activity

In 2014 the Company commissioned a new liquid treatment facility (LTF) which is located adjacent to the flow station and has a 100,000 bpd capacity. The LTF has been designed and located to receive and de-water liquids production for the Oben, Amukpe and Sapele flow stations. The produced oil is then exported via the existing Amukpe - Rapele pipeline to either the Forcados terminal or Warri Refinery. Modification work is ongoing to address issues with the composition of separated water to enable full continuous injection.

During the year the partners drilled two appraisal wells and three development wells on the block and one exploration well on the Ogegere prospect. The Ogegere-1 exploration well encountered oil bearing sands at depths below the primary target, indicating potential for a new exploration play on the block. The well was suspended for further evaluation. Work also commenced and good progress was made on the construction and installation of two new 50,000 barrel oil storage tanks at the Amukpe field, the completion and commissioning of which will occur in 2015. The integrated Amukpe Associated gas flare-out and Ovhor gas-lift project became operational towards the end of the period. The project will provide artificial lift in the Ovhor field for improved oil recovery by re-injecting the associated gas produced at Amukpe.

OML 41

Background

OML 41 covers an area of 291 km2 and is located 50 km from Warri, Delta State. The block contains two producing fields, Sapele and Ovhor (which straddles OML 41 and OML 38), and two discoveries with contingent resources, Ubaleme and Okoporo. Overlying the main productive reservoirs in the Sapele field is the Sapele Shallow discovery, a significant accumulation of oil that has remained largely undeveloped due to the heavier nature of the oil (21° API) relative to that in neighbouring blocks. The Company believes that full development of Sapele Shallow represents a material upside opportunity and intends to pursue this in the near term. Facilities on the block include a flow station with 60,000 bpd capacity, a 60 MMscfd capacity non associated gas plant and a 26 MMscfd NGC owned compressor station. Produced oil is exported via the Sapele - Amukpe delivery line to the Amukpe facilities and onwards to either the Forcados terminal or Warri Refinery. The condensate stream is combined with the oil for export and produced gas is exported via the NGC owned Oben-Sapele pipeline system which feeds into the Sapele power plant. The licence was renewed in 1989 for a further 30 years expiring on 30 June 2019.

2014 activity

The integrated Amukpe Associated gas flare-out and Ovhor gas-lift project became operational towards the end of the period. The project will provide artificial lift in the Ovhor field, which straddles OMLs 41 and 38, for improved oil recovery by re-injecting the associated gas produced at Amukpe. During the year the partners drilled two appraisal wells, three development wells and three workover wells on the block.

OPL 283 marginal field area (pillar)

Background

Seplat has a 40% non-operated working interest in OPL 283 Marginal Field Area. The block is located in the northern onshore depo-belt of the Niger Delta and contains the Umuseti and Igbuku fields. The block is operated by Pillar Oil. The Umuseti field came on stream in May 2012 and is currently producing from three development wells. There are 14 identified oil‑bearing reservoirs in Umuseti with an average sand thickness of 30 feet. Production currently comes from four of these reservoirs and more wells will be needed to drain the remaining reservoirs. The Igbuku field that contains predominantly gas and condensate is currently undergoing appraisal prior to development. The block also contains two satellite exploration leads Igbuku‑North and Umuseti‑East that the operating partners intend to further evaluate. Facilities on the block include a 5,000 bopd Early Production Facility (EPF) and Crude Storage Tanks. The operator plans to install additional production handling facilities and increase storage capacity as new wells are drilled and additional production brought on stream. Umuseti production is evacuated to a Group Gathering Facility (GGF) where it is metered and thereafter exported via Agip's Kwale facilities to Brass terminal and NPDC's pipeline to Forcados.

2014 activity

Activity in 2014 focused on running production operations at the existing oil wells in the Umuseti field and ongoing studies to define the optimal development strategy to access additional oil reservoirs in the Umuseti field and monetisation of the Igbuku gas reserves. During the year the partners completed one development well that had been spudded in 2013 and drilled one new development well. The completion and commissioning of two new 20,000 bbls crude storage tanks in the last quarter of the year brought about a significant reduction in down-time. As a result of this, the daily oil production rate was optimised, averaging 3,000 bopd in December.

Acquisition of new blocks post period end

In February 2015 the Company announced that it had acquired a 40% working interest in OML 53 and an effective 22.5% working interest in OML 55.

OML 53

OML 53 covers an area of approximately 1,585km2 and is located onshore in the north eastern Niger Delta. The Jisike oil field, located in the north western area of the block, is currently the only producing field on OML 53. Gross production from Jisike at the time of acquisition was approximately 2,000 bopd (approximately 800 bopd on a working interest basis). Existing infrastructure on OML 53 at Jisike comprises flow-lines, phase one separation facilities and a flow station with a design capacity of 12,000 bopd and 8 MMscfd. Oil production is then sent for further processing at the nearby Izombe facilities on OML 124 from where it is exported via pipeline to the Brass oil terminal. The block also contains the large undeveloped Ohaji South gas and condensate field, the development of which will be co-ordinated with the SPDC operated Assa North field on adjacent OML 21, together referred to as the ANOS project. The expectation is that future gas production from the ANOS project will supply the domestic market, for which significant work on commercialisation terms and development concepts has been undertaken. There is also shallow oil development potential at Ohaji South that could be pursued as a separate standalone project in the near term. Prior to initiating development of the ANOS project, Seplat expects to focus efforts on increasing oil production at the Jisike field and development of the shallow oil reservoirs in Ohaji South. The Company estimates net recoverable hydrocarbon volumes attributable to its 40.00% working interest to be approximately 51 MMbbls of oil and condensate and 611 Bscf of gas (total 151 MMboe). Pursuant to the Joint Operating Model approved by the Honourable Nigerian Minister of Petroleum Resources, Seplat has been designated operator of OML 53. Seplat's partner on the block is NNPC (60%).

OML 55

OML 55 covers an area of approximately 840km2 and is located in the swamp to shallow water offshore areas in the south eastern Niger Delta. The block contains five producing fields (Robertkiri, Inda, Belema North, Idama and Jokka). Gross production at the time of acquisition was approximately 8,000 bopd (1,800 bopd on a working interest basis). The majority of production on the block is from the Robertkiri, Idama and Inda fields. The Robertkiri field is located in swamp at a water depth of five metres and has a production platform and utility platform installed. Production capacity at the Robertkiri facilities is 20,000 bpd and 10 MMscfd. Production facilities at the Idama field comprise a jack-up mobile offshore production unit ("MOPU") and riser platform that have a capacity of 30,000 bpd of total fluids and 34 MMscfd. The Jokka field is produced through a manifold tied-back to the Idama facilities. Production facilities at the Inda field comprise a MOPU with a capacity of 30,000 bpd of total liquids and 34 MMscfd. Overall, the infrastructure on OML 55 comprises four flow-stations, a network of flow-lines and two eight-inch pipelines that connect to third party operated infrastructure. The Belema field is unitised with OML 25 and is produced via a flow-station on that block. All produced liquids from OML 55 are delivered via third party infrastructure to the Bonny terminal for processing and shipping. In addition to the oil potential on the block there is also an opportunity to develop the significant gas resources that have also been identified. The Company estimates net recoverable hydrocarbon volumes attributable to its 22.50% effective working interest to be approximately 20 MMbbls of oil and condensate and 156 Bscf of gas (total 46 MMboe). Pursuant to the Joint Operating Model approved by the Honourable Nigerian Minister of Petroleum Resources, Seplat has been designated operator of OML 55. Seplat's partners on the block are NNPC (60%) and Belemaoil (17.5%).

Finance review

The Group has invested significantly in new wells and facilities during the year together with the acquisition of interests in OML 53 & 55 in Feb 2015 which together put us in a strong position to realise the value of these assets going forward.

Revenue

Despite reaching record levels of peak oil production on OMLs 4, 38 & 41 in December 2014 of over 76,000 bopd, the full effect has not been reflected in the revenues due to significant outages on the Trans-Forcados System. In addition Revenues have declined as a result of the impact of the reduction of the global oil price in the second half of 2014. Revenue for 2014 was US$775 million, a decrease of 12% from 2013 (2013: US$880 million).

Oil revenues (after stock movements) of US$748 million continued to account for the majority of revenues in 2014 (2013: US$862 million). Average working interest production for the year was 32,295 boepd compared to 31,219 boepd in 2013. In 2013 barrels sold includes the 0.7 million barrels returned under the Memorandum of Understanding relating to prior year volumes of oil delivered to the Forcados Terminal but not recognised by Shell. The one off payment was US$82 million which did not reoccur in 2014.

The global oil price decline has negatively impacted the Group's realised oil price with an achieved average price of US$97.2/bbl (2013: US$110.2/bbl) before royalties. The average premium to Brent achieved in 2014 was US$2.4/bbl (2013: US$3.9/bbl) In order to reduce the impact of volatility of oil prices in the future the Board are considering various possible hedging strategies that could be employed in the coming years.

The closure of the Trans-Forcados System resulted in production down time of 75 days (2013: 29 days). This shutdown, together with the associated time required to re-establish full production levels, resulted in deferred liquids production of approximately 1.7 million barrels assuming all other factors constant. To assist in minimising the impact of future pipeline shut downs, the Group installed and commissioned an alternative export route to the Warri Refinery in 2014.

Gas revenues increased by 51% to US$27.4 million (2013: US$18.1 million) due to both a 15% increase in the average gas price to US$1.90/MMscf (2013: 1.70/MMscf) together with an increase in volumes produced. Working interest production for the year was 14.4 Bscf compared to 10.7 Bscf in 2013. The Group took delivery of a new 150 MMscfd gas processing facility in 2014. Installation is ongoing and commissioning is planned to begin at the end of the first quarter of 2015. Management remains in active negotiations with new gas offtake customers.

Gross profit

Gross profit for the year was US$459 million, a decrease of 16% on the prior year (2013: US$549 million). This principally reflects increased field activity together with the increase in the rate of DD&A.

Direct operating costs, being crude handling fees, rig related costs and other field expenses, increased to US$9.67/boe in 2014 (2013: US$8.60/boe), principally reflecting the increased levels of field expenditures, work overs, against slightly lower crude handling fees. Management is aware of the need to operate as efficiently as possible in the current low oil price environment whilst maximising the production and cash flows from existing assets.

The DD&A charge for oil and gas assets, has increased during 2014 to US$41 million (2013: US$28 million) reflecting the increased levels of field investment, forecast levels of production and estimates of future capital commitments. These increases were partly offset by the reduction in the level of royalties in 2014 which despite the increased level of production to US$150 million (2013: US$192 million) declined due to the fall in realised oil prices.

Operating profit

Operating profit for the year was US$290 million, a decrease of 39% on the prior year (2013: US$479 million).

Having undertaken an Initial Public Offering as well as refinancing the business during the year, the Group incurred several expenses that are not expected to reoccur going forward. These include approximately US$9 million in relation to the IPO, US$16 million in respect of the Group's new debt facilities and US$19 million of regulatory and other payments including new systems.

The increase in recurring G&A expenses of 62% from US$45 million in 2013 to US$72 million in 2014 were primarily driven by the growth in staff costs and investment in office spaces as Seplat strengthened its team.

Tax

The Group continued to benefit from pioneer tax status in 2014 which resulted in the effective tax rate remaining consistent with 2013 (2014 and 2013: nil%). There was a tax credit in the prior year relating to the reversal of the deferred tax balance as a result of being granted pioneer tax status. Post period end the Nigeria Investment Promotion Council (NIPC) notified oil and gas companies that are in receipt of the pioneer tax incentive of its intention to test compliance with the conditions under which the pioneer tax status was awarded to all companies, including Seplat, in order that the final two out of five years of the incentive be received. The Group is currently in its third year of the scheme and considers that is has met or exceeded these requirements, as evidenced by the investments it has made to develop its blocks and in particular accelerate the expansion of its gas business to supply the domestic market.

Profit for the year

Profit for the year was US$252 million, a decrease of 54% on the prior year (2013: US$550 million). The resultant EPS for 2014 was US$0.5 (2013: US$1.37).

The Group's results include a number of one-off of items which by their nature would not be expected to reoccur. After adjusting for these items, underlying profit from the year was US$296 million (2013: US$375million). In 2014 adjustments have been made in respect of IPO costs of US$9 million, regulatory payments of US$16 million, payments made for Group's new debt facilities of US$16 million and US$19 million of regulatory and other payments including procurement of new systems and aborted acquisition costs of US$26 million. In 2013 adjustments have been made in respect of Shell MoU revenues and the release of deferred tax in relation to Pioneer Tax Status.

Dividends

The Board has decided to recommend a final dividend of US$0.09 per share (2013: N/A) bringing total dividends for the year to US$0.15 per share (2013: N/A).

Cash flows and liquidity

Cash flows from operating activities

Operating cash flow before movements in working capital was US$353 million (2013: US$458 million). The outstanding NPDC receivable at the year-end was US$463 million, (2013: US$283 million). Receipts from NPDC amounted to US$362 million as against agreed payments of US$542 million which has led to an increase in the receivable of US$180 million during the year. There continues to be constructive dialogue with NPDC and management are confident that this will not become an inhibitor to future investment. The Group are investigating possible strategies and commercial arrangements with NPDC to return the cash to Seplat in a mutually agreeable time frame. Due to increased drilling activities in Q4 and indeed at year end, accruals and other payables increased by US$157mm over 2013.

Cash flows from investing activities

Total cash flows from investing activities were US$780 million (2013: US$220 million), including deposits and advances made against investments of US$497 million. Post the year end, the Group will no longer proceed with its US$453 million deposit for investment and is in the process of cancelling the option agreement and recovering its deposit and refundable costs.

Subsequent to the year end, in February 2015, Seplat acquired a 40% interest in OML53 from Chevron Nigeria Limited for an upfront consideration of US$259 million, less the US$69 million deposit paid previously. At the same time the Company also acquired a 56.25% stake in Belemaoil Producing Limited ("Belemaoil") for US$132.2 million. Belemaoil holds a 40% interest in OML55.

Total capital expenditure amounted to US$296million (2013: US$221 million). Capital expenditure includes drilling costs in relation to 21 development and appraisal, one pilot, one exploration and one water disposal wells; and facility costs which included the new natural gas facilities, new flow lines, and alternative crude storage facilities.

Cash flows from financing activities

Net debt at the year-end was US$304 million, compared to US$141.1 million at December 2013. Total cash inflows from financing activities were US$671million (2013: US$42 million). These principally reflect the refinancing of the business during the year through both equity and debt markets. In January 2015, the Group successfully refinanced its existing debt facilities with a new US$700 million seven year secured term facility and US$300 million three year secured revolving credit facility. The seven year facility also includes an option for the Group to upsize the facility by up to an additional US$700 million for qualifying acquisition opportunities.

Outlook

Having secured appropriate funding through our equity and debt refinancing, our financial strategy continues to be to maintain the flexibility required to realise the value of our growing asset base. The Group will continue to use the cash generated from its growing production base to support the significant appraisal and development activities in Nigeria.

Seplat Petroleum Development Company Plc

Preliminary Financial Statements

For the year ended 31 December 2014(Expressed in US Dollars)

Contents

Content Page reference

General information 3

Report of the directors 4

Statement of directors' responsibility 11

Independent auditors' report 12

Statement of profit or loss and othercomprehensive income 14

Statement of financial position 15

Statement of changes in equity 16

Statement of cash flows 17

Notes to the financial statements 20

Statement of value added 66

Five year financial summary 67

Supplementary financial information

Estimated quantities of proved reserves 69

Capitalized costs related to oil producing activities 69

Concessions 70

Results of operations for oil producing activities 70

General information

Board of directors:

Report of the directors

For the year ended 31 December 2014

The Directors are pleased to present to the shareholders of the Company their report with the audited consolidated financial statements for the year ended 31 December 2014.

Principal activity

The Company is principally engaged in oil and gas exploration and production. The company's registered office address is 25a Lugard Avenue, Ikoyi, Lagos, Nigeria.

Corporate structure and business

SEPLAT Petroleum Development Company Plc (''SEPLAT'' or the ''Company''), the parent of the Group, was incorporated on 17 June 2009 as a private limited liability company and re-registered as a public company on 3 October 2013, under the Company and Allied Matters Act 2004. The Company commenced operations on 1 August 2010. The Company is principally engaged in oil and gas exploration and production.

The significant shareholders of the Group have been disclosed in the related party transactions note (note 28).

The Company acquired, pursuant to an agreement for assignment dated 31 January 2010 between the Company, SPDC, TOTAL and AGIP, a 45 percent participating interest in the following producing assets: OML 4, OML 38 and OML 41 located in Nigeria. The total purchase price for these assets was $340 million paid at the completion of the acquisition on 31 July 2010 and a contingent payment of $33 million payable 30 days after the second anniversary, 31 July 2012, if the average price per barrel of Brent Crude oil over the period from acquisition up to 31 July 2012 exceeds $80 per barrel.

$358.6 million was allocated to the producing assets including $18.6 million as the fair value of the contingent consideration as calculated on acquisition date. The contingent consideration of $33 million was paid on 22 October 2012.

Seplat Petroleum Development Company Plc was successfully listed on the Nigerian Stock Exchange and main market of the London Stock Exchange on 14 April 2014.

On 1 June 2013, Newton Energy Limited (''Newton Energy''), an entity previously beneficially owned by the same shareholders as SEPLAT, became a subsidiary of the Company. On 1 June 2013, Newton Energy acquired from Pillar Oil Limited (''Pillar Oil'') a 40 percent participant interest in producing assets: the Umuseti/Igbuku marginal field area located within OPL 283 (the ''Umuseti/Igbuku Fields''). The total purchase price for these assets was $50 million paid at the completion of the acquisition in June 2013 and a contingent payment of $10 million payable upon reaching certain production milestones.

$57.7 million was allocated to the producing assets including $7.7 million as the fair value of the contingent consideration as calculated on acquisition date.

The Company's registered address is: 25a Lugard Avenue, Ikoyi, Lagos, Nigeria.

The Company together with its subsidiary, Newton Energy, and four new wholly owned subsidiaries, namely, SEPLAT Petroleum Development Company UK Limited (''SEPLAT UK''), which was incorporated on 21 August 2013, SEPLAT East Onshore Limited (''SEPLAT East''), which was incorporated on 12 December 2013, SEPLAT East Swamp Company Limited (''SEPLAT Swamp''), which was incorporated on 12 December 2013, and SEPLAT Gas Company Limited (''SEPLAT GAS''), which was incorporated on 12 December 2013, is referred to as the Group.

Results:

Dividend:

During the year, the directors recommended to members an interim dividend of $0.06 per 50kobo share amounting to $33 million (2013: Nil)

The Directors are recommending to members the payment of a dividend of $0.09 per 50kobo share amounting to $49.8 million (2013: $40 million @ $0.10 per share).

If the recommended dividend is approved, it will be paid to members, whose names appeared in the Company's register of members as at close of business on 31 December 2014.

Changes in property, plant and equipments

Movements in the Property, plant and equipment and significant additions thereto are shown in note 11 to the financial statements.

Board of directors

The names of the Directors are shown on page 6. In accordance with the provisions of Section 259 of the Companies & Allied Matters Act, CAP C20, Laws of the Federation of Nigeria (LFN) 2004, one third of the directors of the Company shall retire from office. The directors to retire every year shall be those who have been longest in office since their last election. Apart from the Executive Directors and Founding Directors, all other Directors are appointed for a fixed term. At expiration of the terms, they may be eligible for re-appointment.

The Board has the following Committees:

Record of attendance of board and committee meetings

In accordance with Section 258 Subsection 2 of the Companies and Allied Matters Act, CAP C20, LFN, 2004 the record of attendance of Directors at Board Meetings and that of its Committees in the year under review is published herewith:

Board of Directors

Finance Committee

Record of attendance of board and committee meetings continued

Nomination and Establishment Committee

Board of Directors:

Remuneration Committee

Risk Management, HSE and Communities Committee

Corporate Social Responsibility Committee

Audit Committee

Directors' interest in shares

The interests of the Directors (and of persons connected with them) in the share capital of the Company (all of which are beneficial unless otherwise stated) as at 31 December 2014, are as follows:

Notes:

 (1) 72,136,912 Ordinary Shares are held by Shebah Petroleum Development Company Limited, which is an entity controlled by A.B.C. Orjiako and members of his family and 12,600,000 Ordinary Shares are held directly by Mr. Orjiako's siblings and 1 Ordinary Share held by A.B.C. Orjiako.

(2) 27,217,010 Ordinary Shares are held by Professional Support Limited and 1,920,000 Ordinary Shares are held by Abtrust Integrated Services Limited, each of which is an entity controlled by Austin Avuru. 44,160,000 Ordinary Shares, are held by Platform Petroleum Limited, which is an entity in which Austin Avuru has a 23 per cent equity interest and 1 ordinary share held by Mr Augustine O. Avuru.

Director's interest in contracts

The Chairman and the Managing Director have disclosable indirect interest in contracts with which the Company was involved as at 31 December 2014 for the purpose of section 277 of the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria in 2014.

Substantial interest in shares

The issued and fully paid share capital of the Company as at 31 December 2014 is beneficially owned as follows:

(1) 72,136,912 Ordinary Shares are held by Shebah Petroleum Development Company Limited, which is an entity controlled by A.B.C. Orjiako and members of his family and 12,600,000 Ordinary Shares are held directly by Mr. Orjiako's siblings and 1 Ordinary Share held by A.B.C. Orjiako.

(2) 27,217,010 Ordinary Shares are held by Professional Support Limited and 1,920,000 Ordinary Shares are held by Abtrust Integrated Services Limited, each of which is an entity controlled by Austin Avuru. 44,160,000 Ordinary Shares, are held by Platform Petroleum Limited, which is an entity in which Austin Avuru has a 23 per cent equity interest and 1 ordinary share held by Mr Augustine O. Avuru.

Acquisition of own shares:

The company did not acquire any of its shares during the year.

Corporate governance

The Board of Directors of the company is aware of the Code of Corporate Governance issued by the Securities and Exchange Commission in the administration of the company and is ensuring that the company complies with it.

The Board is responsible for keeping proper accounting records with reasonable accuracy. It is also responsible for safe guarding the assets of the company through prevention and detection of fraud and other irregularities.

The Board has a Remuneration Committee made up of four of its members, other committees are:

Finance Committee

Nomination and Establishment Committee

Risk Management, HSE and Communities Committee

Corporate Social Responsibility Committee

Audit Committee

The report of the committee and details of its membership are set out on page 2.

Donation

The following donations were made by the company during the year (2013: $22,160).

Employment and employees

a) Employees involvement and training:

The company continues to observe industrial relations practices such as joint Consultative Committee and briefing employees on the developments in the company during the year under review.

Various incentive schemes for staff were maintained during the year while regular training courses were carried out for the employees.

Educational assistance is provided to members of staff. Different cadres of staff were also assisted with payment of subscriptions to various professional bodies during the year.

The Company will provide appropriate HSE training to all staff, and Personal Protective Equipment (PPE) to the appropriate staff.

b) Health, safety and welfare of employees:

The company continues to enforce strict health and safety rules and practices at the work environment which are reviewed and tested regularly. The company provides free medical care for its employees and their families through designated hospitals and clinics. Fire prevention and fire-fighting equipment are installed in strategic locations within the Company's premises. The Company operates Group life Insurance cover for the benefit of its employees. It also complies with the requirements of the Pension Reform Act, 2004 regarding its employees.

c) Employment of disabled or physically challenged persons:

The company has a policy of fair consideration of job applications by disabled persons having regard to their abilities and aptitude. The company's policy prohibits discrimination of disabled persons in the recruitment, training and career development of its employees.

Auditors

The Auditors, Ernst and Young have indicated their willingness to continue in office in accordance with Section 357(2) of the Companies and Allied Matters Act, 1990. A resolution will be proposed authorizing the Directors to fix their remuneration.

By Order of the Board

Mirian Kachikwu

FRC/2015/NBA/00000010739

Company Secretary,

Seplat Petroleum Development Company Plc

25a Lugard Avenue

Ikoyi

Lagos

Nigeria

Seplat Petroleum Development Company Plc

Statement of directors' responsibilities for the year ended 31 December 2014

The Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004, requires the directors to prepare financial statements for each financial year that give a true and fair view of the state of financial affairs of the Company at the end of the year and of its profit or loss. The responsibilities include ensuring that the Company:

a) keeps proper accounting records that disclose, with reasonable accuracy, the financial position of the company and comply with the requirements of the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004;

b) establishes adequate internal controls to safeguard its assets and to prevent and detect fraud and other irregularities; and

c) prepares its financial statements using suitable accounting policies supported by reasonable and prudent judgments and estimates, and are consistently applied.

The directors accept responsibility for the annual financial statements, which have been prepared using appropriate accounting policies supported by reasonable and prudent judgments and estimates, in conformity with International Financial Reporting Standards (IFRS), the requirements of the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004 and Financial Reporting Council of Nigeria Act, No 6, 2011.

The directors are of the opinion that the financial statements give a true and fair view of the state of the financial affairs of the Company and of its profit. The Directors further accept responsibility for the maintenance of accounting records that may be relied upon in the preparation of financial statements, as well as adequate systems of internal financial control.

Nothing has come to the attention of the directors to indicate that the Company will not remain a going concern for at least twelve months from the date of this statement.

Signed On Behalf Of the Directors By

Ambrosie Bryant Chukwueloka Orjiako Ojunekwu Augustine Avuru

Chairman Chief Executive Officer

FRC/2013/IODN/00000003161. FRC/2013/IODN/00000003100

Statement of profit or loss and other comprehensive income

For the year ended 31 December 2014

Statement of financial position

Notes 1-35 are an integral part of the financial statements

The financial statements of Seplat Development Company Plc for the year ended 31 December 2014 were authorised for issue in accordance with a resolution of the directors on 26 March 2015 and were signed on its behalf by:

Statement of changes in equity

For the year ended 31 December 2014

Statement of cash flows

For the year ended 31 December 2014

Notes to the financial statements

1. Corporate information and business

SEPLAT Petroleum Development Company Plc (''SEPLAT'' or the ''Company''), the parent of the Group, was incorporated on 17 June 2009 as a private limited liability company and re-registered as a public company on 3 October 2013, under the Company and Allied Matters Act 2004. The Company commenced operations on 1 August 2010. The Company is principally engaged in oil and gas exploration and production.

The significant shareholders of the Group have been disclosed in the related party transactions note (note 28).

The Company acquired, pursuant to an agreement for assignment dated 31 January 2010 between the Company, SPDC, TOTAL and AGIP, a 45 per cent. participating interest in the following producing assets:

OML 4, OML 38 and OML 41 located in Nigeria. The total purchase price for these assets was $340 million paid at the completion of the acquisition on 31 July 2010 and a contingent payment of $33 million payable 30 days after the second anniversary, 31 July 2012, if the average price per barrel of Brent Crude oil over the period from acquisition up to 31 July 2012 exceeds $80 per barrel. $358.6 million was allocated to the producing assets including $18.6 million as the fair value of the contingent consideration as calculated on acquisition date. The contingent consideration of $33 million was paid on 22 October 2012.

During 2013, Newton Energy Limited (''Newton Energy''), an entity previously beneficially owned by the same shareholders as SEPLAT, became a subsidiary of the Company. On 1 June 2013, Newton Energy acquired from Pillar Oil Limited (''Pillar Oil'') a 40 per cent. Participant interest in producing assets: the Umuseti/Igbuku marginal field area located within OPL 283 (the ''Umuseti/Igbuku Fields''). The total purchase price for these assets was $50 million paid at the completion of the acquisition in June 2013 and a contingent payment of $10 million payable upon reaching certain production milestones.

$57.7 million was allocated to the producing assets including $7.7 million as the fair value of the contingent consideration as calculated on acquisition date.

The Company's registered address is: 25a Lugard Avenue, Ikoyi, Lagos, Nigeria.

The Company together with its subsidiary, Newton Energy, and four new wholly owned subsidiaries, namely, SEPLAT Petroleum Development Company UK Limited (''SEPLAT UK''), which was incorporated on 21 August 2013, SEPLAT East Onshore Limited (''SEPLAT East''), which was incorporated on 12 December 2013, SEPLAT East Swamp Company Limited (''SEPLAT Swamp''), which was incorporated on 12 December 2013, and SEPLAT Gas Company Limited (''SEPLAT GAS''), which was incorporated on 12 December 2013, is referred to as the Group.

2. Basis of preparation and significant accounting policies

2.1 Basis of preparation

The financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). The financial information has been prepared under the going concern assumption and historical cost convention, except for contingent consideration and borrowings on initial recognition that have been measured at fair value. The historical financial information is presented in US dollars and all values are rounded to the nearest thousand ($000), except when otherwise indicated.

2.2 Basis of consolidation

The consolidated financial information consolidates the financial information of the Company and its Subsidiaries drawn up to 31 December each year. Control is achieved when the Group is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee.

Specifically, the Group controls an investee if and only if the Group has:

· Power over the investee (i.e. existing rights that give it the current ability to direct the relevant activities of the investee);

· Exposure, or rights, to variable returns from its involvement with the investee; and

· The ability to use its power over the investee to affect its returns.

The Group re-assesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control. Consolidation of a subsidiary begins when the Group obtains control over the subsidiary and ceases when the Group loses control of the subsidiary. Assets, liabilities, income and expenses of a subsidiary acquired or disposed of during the year are included in the statement of comprehensive income from the date the Group gains control until the date the Group ceases to control the subsidiary.

The financial statements of the subsidiaries are prepared for the same reporting periods as the parent company using consistent accounting policies.

All intra-group balances, transactions and unrealised gains and losses resulting from intra-group transactions and dividends are eliminated in full.

A change in the ownership interest of a subsidiary, without a loss of control, is accounted for as an equity transaction. If the Group loses control over a subsidiary, it:

· Derecognises the assets (including goodwill) and liabilities of the subsidiary;

· Derecognises the carrying amount of any non-controlling interests;

· Derecognises the cumulative translation differences recorded in equity;

· Recognises the fair value of the consideration received;

· Recognises the fair value of any investment retained;

· Recognises any surplus or deficit in profit or loss; and

· Reclassifies the parent's share of components previously recognized in OCI to profit or loss or retained earnings, as appropriate, as would be required if the Group had directly disposed of the related assets or liabilities.

2.3 Summary of significant accounting policies

The following are the significant accounting policies applied by the company in preparing its financial statements.

2.3.1 Foreign currency translation

Functional and presentation currency

The Group's financial statements are presented in United States Dollars, which is also the Company's functional currency. For each entity the Group determines the functional currency and items included in the financial statements of each entity are measured using that functional currency.

Transactions and balances

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of foreign currency transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in the statement of comprehensive income within the line item gain/(loss) on foreign exchange, net.

Group companies

On consolidation, the assets and liabilities of foreign operations are translated into US$ at the rate of exchange prevailing at the reporting date and their income statements are translated at exchange rates prevailing at the dates of the transactions. The exchange differences arising on translation for consolidation are recognized in other comprehensive income. On disposal of a foreign operation, the component of other comprehensive income relating to that particular foreign operation is recognized in profit or loss.

2.3.2 Oil and gas accounting

i) Pre-license costs

Pre-license costs are expensed in the period in which they are incurred.

ii) Exploration license costs

Exploration license costs are capitalized within intangible assets. License costs paid in connection with a right to explore in an existing exploration area are capitalized and amortised on a straight-line basis over the life of the permit. 

License costs are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still under way or firmly planned, or that it has been determined, or work is under way to determine that the discovery is economically viable based on a range of technical and commercial considerations and sufficient progress is being made on establishing development plans and timing.

If no future activity is planned or the license has been relinquished or has expired, the carrying value of the license is written off through profit or loss.

iii) Acquisition of producing assets

Upon acquisition of producing assets, where the Group does not have control, the Group identifies and recognises the individual identifiable assets acquired (including those assets that meet the definition of, and recognition criteria for, intangible assets in IAS 38 Intangible Assets) and liabilities assumed. The purchase price paid for the group of assets is allocated to the individual identifiable assets and liabilities on the basis of their relative fair values at the date of purchase.

If the acquisition results in control over the assets and includes processes and personnel, then the acquisition is treated as an acquisition of a business. In this case, the excess of purchase price over fair value of the assets is recorded as goodwill.

iv) Exploration and evaluation expenditures

Geological and geophysical exploration costs are charged against income as incurred.

Exploration and evaluation expenditures incurred by the entity are accumulated separately for each area of interest. Such expenditures comprise net direct costs and an appropriate portion of related overhead expenditure, but do not include general overheads or administrative expenditure that is not directly related to a particular area of interest. Each area of interest is limited to a size related to a known or probable hydrocarbon resource capable of supporting an oil operation.

Costs directly associated with an exploration well, exploratory stratigraphic test well and delineation wells are temporarily suspended (capitalized) until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs, delay rentals and payments made to contractors. If hydrocarbons ('proved reserves') are not found, the exploration expenditure is written off as a dry hole and charged against income. If hydrocarbons are found, the costs continue to be capitalized.

Suspended exploration and evaluation expenditure in relation to each area of interest is carried forward as an asset provided that one of the following conditions is met:

· the costs are expected to be recouped through successful development and exploitation of the area of interest or alternatively, by its sale;

· and exploration and/or evaluation activities in the area of interest have not, at the reporting date, reached a stage which permits a reasonable assessment of the existence or otherwise of economically recoverable reserves, and active and significant operations in, or in relation to, the area of interest are continuing.

Exploration and/or evaluation expenditures which fail to meet at least one of the conditions outlined above is written off. In the event that an area is subsequently abandoned or exploration activities do not lead to the discovery of proved or probable reserves, or if the directors consider the expenditure to be of no value, any accumulated costs carried forward relating to the specified areas of interest are written off in the year in which the decision is made. While an area of interest is in the development phase, amortization of development costs is not charged pending the commencement of production. Exploration and evaluation costs are transferred from the exploration and/or evaluation phase to the development phase upon commitment to a commercial development.

v) Development expenditures

Development expenditures incurred by the entity is accumulated separately for each area of interest in which economically recoverable reserves have been identified to the satisfaction of the directors. Such expenditure comprises net direct costs and, in the same manner as for exploration and evaluation expenditure, an appropriate portion of related overhead expenditure directly related to the development property.

All expenditure incurred prior to the commencement of commercial levels of production from each development property is carried forward to the extent to which recoupment is expected out of revenue to be derived from the sale of production from the relevant development property.

vi) Joint operations

SEPLAT is the operator of the assets relating to OML 4, OML 38 and OML 41. The Nigerian Petroleum Development Company Limited (''NPDC''), a subsidiary of the Nigerian National Petroleum Corporation (''NNPC''), is the other venturer. SEPLAT holds a 45 per cent. interest, while NPDC holds 55 per cent. interest in the jointly controlled assets.

The Group also holds a 40 per cent. interest in the joint operations relating to OPL 283/OML 56 (the Umuseti/Igbuku Fields). Pillar Oil is the other venturer and the operator.

The accounting method specified for a joint operation apportions to each venturer its share of revenues, expenses, assets and liabilities. The Group recognises its share in its own accounting records as follows:

a. Its share of the mineral properties is shown within property, plant and equipment.

b. Any liabilities that it has incurred including those incurred to finance its share of the asset.

c. Its share of any liabilities incurred jointly with other venturers, including the decommissioning liability

of production and field facilities.

d. Any income from its sale or use of its share of the output, together with its share of any expenses

incurred by the joint operation.

e. Any expenses that it has incurred in respect of its interest in the venture.

In addition to joint costs, the Group also incurs exclusive costs, which are fully borne by the Group.

2.3.3 Revenue recognition

Revenue arises from the sale of crude oil and gas. Revenue comprises the realised value of crude oil lifted by customers. Revenue is recognized when crude products are lifted by a third party (buyer) Free on Board (FOB) at the Group's designated loading facility or lifting terminals. At the point of lifting, all risks and rewards are transferred to the buyer. Gas revenue is recognized when gas passes through the custody transfer point.

Over lift and underlift

The excess of the product sold during the period over the participant's ownership share of production is termed as an overlift and is accrued for as a liability and not as revenue. Conversely, an underlift is recognized as an asset and the corresponding revenue is also reported.

Overlifts and underlifts are initially measured at the market price of oil at the date of lifting, consistent with the measurement of the sale and purchase.

2.3.4 Borrowing costs

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. Borrowing costs consist of interest and other costs that an entity incurs in connection with the borrowing of funds.

All other borrowing costs are recognized in profit and loss in the period in which they are incurred.

2.3.5 Property, Plant and Equipment

Oil and Gas properties and other, plant and equipment are stated at cost, less accumulated depreciation and accumulated impairment losses.

The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of any decommissioning obligation and, for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. Where parts of an item of property, plant and equipment have different useful lives, they are accounted for as separate items of property, plant and equipment.

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated and is now written off is replaced and it is probable that future economic benefits associated with the item will flow to the entity, the expenditure is capitalized. Inspection costs associated with major maintenance programmes are capitalized and amortised over the period to the next inspection. Overhaul costs for major maintenance programmes are capitalized as incurred as long as these costs increase the efficiency of the unit or extend the useful life of the asset. All other maintenance costs are expensed as incurred.

Depreciation

Production and field facilities are depreciated/amortised on a unit-of-production basis over the estimated proved developed reserves. Other property, plant and equipment is depreciated on a straight-line basis over their estimated useful lives. Depreciation commences when an asset is available for use. The depreciation rate for each class is as follows:

The expected useful lives and residual values of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.

2.3.6 Impairment of non-financial assets

The entity assesses assets or group of assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If any such indication of impairment exists or when annual impairment testing for an asset group is required, the entity makes an estimate of its recoverable amount.

The recoverable amount is the higher of an asset's fair value less costs of disposal (FVLCD) and value in use (VIU). The recoverable amount is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or group of assets, in which case, the asset is tested as part of a larger cash generating unit to it belongs. Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount.

In calculating VIU, the estimated future cash flo ws are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset/CGU. In determining FVLCD, recent market transactions are taken into account. If no such transactions can be identified, an appropriate valuation model is used. These calculations are corroborated by valuation multiples, quoted share prices for publicly traded companies or other available fair value indicators.

A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset's recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to the recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in the statement of profit or loss after such a reversal and the depreciation charge is adjusted in future periods to allocate the asset's revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.

2.3.7 Cash and cash equivalents for the statement of cash flows

Cash and cash equivalents in the statement of cash flows comprise cash at banks and at hand and short-term deposits with an original maturity of three months or less, and excludes any restricted cash which is not available for use by the Group and therefore is not considered highly liquid.

2.3.8 Inventories

Inventories represent the value of tubulars, casing and wellheads. These are stated at the lower of cost and net realisable value. Cost is determined using the invoice value and all other directly attributable costs to bringing the inventory to the point of use determined on First in first out basis.

2.3.9 Financial instruments

i) Financial assets

Financial assets initial recognition and measurement

Financial assets in the scope of IAS 39 Financial Instruments: Recognition and Measurement are classified as financial assets at fair value through the statement of profit or loss, loans and receivables, held to maturity investments, available-for-sale financial assets, or derivatives designated as hedging instruments in an effective hedge, as appropriate. The Group determines the classification of its financial assets at initial recognition.

Notes to the financial statements

continued

All financial assets are recognized initially at fair value plus transaction costs, except in the case of financial assets recorded at fair value through the statement of profit or loss which do not include transaction costs.

The Group's financial assets include cash and short-term deposits, trade and other receivables and loan and other receivables.

Subsequent measurement

The subsequent measurement of financial assets depends on their classification, as follows:

Trade receivables, loans and other receivables

Trade receivables, loans and other receivables, which are non-derivative financial assets that have fixed or determinable payments that are not quoted in an active market, are classified as loans and receivables. They are included in the current assets, except for maturities greater than 12 months after the reporting date. The Group's loan and receivables comprise trade and other receivables in the consolidated historical financial information.

Loans and receivables are recognized initially at fair value and subsequently measured at amortised cost using the effective interest rate method net of any impairment.

A provision for impairment of trade receivables is established when there is objective evidence that the Group will not be able to collect all the amounts due according to the original terms of the receivable.

Significant financial difficulties of the debtor, probability that the debtor will enter bankruptcy or financial reorganisation and default or delinquency in payments are considered as indicators that the trade receivable is impaired. The amount of the provision is the difference between the asset's carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate.

The carrying amount of the asset is reduced through the use of an allowance account, and the amount of the loss is recognized in the statement of profit or loss. When a trade is uncollectable, it is written off against the allowance account for trade receivables.

Impairment of financial assets

The Group assesses at each reporting date whether there is objective evidence that a financial asset or a group of financial assets is impaired. A financial asset or a group of financial assets is deemed to be impaired if there is objective evidence of impairment as a result of one or more events that has occurred since the initial recognition of the asset (an incurred loss event) and that loss event has an impact on the estimated future cash flows of the financial asset or the group of financial assets that can be reliably estimated. Evidence of impairment may include indications that the debtor or a group of debtors is experiencing significant financial difficulty, default or delinquency in interest or principal payments, the probability that they will enter bankruptcy or other financial reorganisation and observable data indicating that there is a measurable decrease in the estimated future cash flows, such as changes in arrears or economic conditions that correlate with defaults.

ii) Financial liabilities

Financial liabilities in the scope of IAS 39 are classified as financial liabilities at fair value through the statement of profit or loss, loans and borrowings as appropriate. The Group determines the classification of its financial liabilities at initial recognition.

All financial liabilities are recognized initially at fair value and, in the case of loans and borrowings, net of directly attributable transaction costs.

The Group's financial liabilities include trade and other payables, bank overdrafts and loans and borrowings.

Subsequent measurement

The measurement of financial liabilities depends on their classification as described below.

Trade payables, loans and borrowings

Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Accounts payables are classified as current liabilities if payment is due within one year or less. If not, they are presented as non-current liabilities.Trade payables are recognized initially at fair value and subsequently measured at amortised cost using effective interest method.

Borrowings

Borrowings are recognized initially at fair value, net of transaction costs incurred. Borrowings are subsequently carried at amortised cost while any difference between the proceeds (net of transaction costs) and the redemption value is recognized in the statement of profit or loss over the period of borrowings using the effective interest method.

Fees paid on establishment of loan facilities are recognized as transaction costs of the loan to the extent that it is probable that some or all of the facility will be drawn down. In this case, the fee is deferred until the draw down occurs. To the extent that there is no evidence that it is probable that some or all of the facility will be drawn down, the fee is capitalized as a pre-payment for liquidity services and amortised over the period of the facility to which it relates.

Derecognition of financial liabilities

A financial liability is derecognised when the associated obligation is discharged or cancelled or expires. When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability. The difference in the respective carrying amounts is recognized in the statement of profit or loss & other comprehensive income.

 Derivative financial instruments

The Group uses derivative financial instruments, such as forward exchange contracts, to hedge its foreign exchange risks. However, such contracts are not accounted for as designated hedges. Derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Derivatives are carried as financial assets when the fair value is positive and as financial liabilities when the fair value is negative. Any gains or losses arising from changes in the fair value of derivatives are taken directly to the statement of profit or loss and other comprehensive income, and presented within operating profit.

Commodity contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the Group's expected purchase, sale or usage requirements fall within the exemption from IAS 32 and IAS 39, which is known as the 'normal purchase or sale exemption'. For these contracts and the host part of the contracts containing embedded derivatives, they are accounted for as executory contracts. The Group recognises such contracts in its statement of financial position only when one of the parties meets its obligation under the contract to deliver either cash or a non-financial asset. An analysis of fair values of financial instruments and further details as to how they are measured are provided in Note 18. instruments.

2.3.10 Fair value of financial instruments

The fair value of financial instruments that are traded in active markets at each reporting date is determined by reference to quoted market prices or dealer price quotations (bid price for long positions and ask price for short positions), without any deduction for transaction costs.

For financial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques. Such techniques may include using recent arm's length market transactions; reference to the current fair value of another instrument that is substantially the same; a discounted cash flow analysis or other valuation models.

2.3.11 Contingent consideration

A contingent consideration is recognized where payment is dependent on future events. On initial recognition, the fair value of the contingent consideration is calculated. The fair value is recognized as a liability and also capitalized to the producing facilities. Subsequently, the liability is tested for changes in fair value and the differences recorded in liability and in the statement profit or loss and other comprehensive income.

2.3.12 Share capital, earnings and dividends per share

Issued share capital has been translated at the exchange rate prevailing at the date of the transaction and is not retranslated subsequent to initial recognition.

Basic earnings per share is calculated by dividing the net profit for the year attributable to ordinary shareholders of the Group by the weighted average number of ordinary shares outstanding during the year. Dividends on ordinary shares are recognized as a liability in the period in which they are approved.

2.3.13 Employee benefits - Defined contribution scheme

The Group contributes to a defined contribution scheme for its employees in compliance with the provisions of the Pension Reform Act 2004. The scheme is fully funded and is managed by licensed Pension Fund Administrators. Membership of the scheme is automatic upon commencement of duties at the Group. The Group's contributions to the defined contribution schemes are charged to the profit and loss account in the year to which they relate.

A defined contribution plan is a pension plan under which the Group pays fixed contributions. Contribution to the scheme is 15 per cent of each employee's annual basic salary, housing and transport allowances which is paid wholly by the employer. The contributions to the defined contribution schemes are charged to the profit and loss account in the year to which they relate.

2.3.14 Provisions

Provisions are recognized when (i) the Group has a present legal or constructive obligation as a result of past events; (ii) it is probable that an outflow of economic resources will be required to settle the obligation as a whole; and (iii) the amount can be reliably estimated. Provisions are not recognized for future operating losses.

In measuring the provision:

· risks and uncertainties are taken into account;

· the provisions are discounted where the effects of the time value of money is considered to be material;

· when discounting is used, the increase of the provision over time is recognized as an interest expense;

· future events such as changes in law and technology, are taken into account where there is subjective audit evidence that they will occur; and;

· gains from expected disposal of assets are not taken into account, even if the expected disposal is closely linked to the event giving rise to the provision.

Decommissioning

Liabilities for decommissioning costs are recognized as a result of the constructive obligation of past practise in the oil and gas industry, when it is possible that an outflow of economic resources will be required to settle the liability and a reliable estimate can be made. The estimated costs, based on current requirements, technology and price levels, prevailing at the reporting date, are computed based on the latest assumptions as to the scope and method of abandonment.

Provisions are measured at the fair value of the expenditures expected to be required to settle the obligation using a pre-tax rate, updated at each reporting date that reflects current market assessments of the time value of money and the risks specific to the obligation. The corresponding amount is capitalized as part of the oil and gas properties and is amortised on a unit-of-production basis as part of the depreciation, depletion and amortization charge. Any adjustment arising from the estimated cost of the restoration and abandonment cost is capitalized, while the charge arising from the accretion of the discount applied to the expected expenditure is treated as a component of finance charges.

If the change in estimate results in an increase in the decommissioning provision and, therefore, an addition to the carrying value of the asset, the Group considers whether this is an indication of impairment of the asset as a whole, and if so, tests for impairment in accordance with IAS 36. If, for mature fields, the revised oil and gas assets net of decommissioning provisions exceed the recoverable value, that portion of the increase is charged directly to expense.

2.3.15 Contingencies

A contingent asset or contingent liability is a possible asset or obligation that arises from past events and whose existence will be confirmed by the occurrence or non-occurrence of uncertain future events. The assessment of the existence of the contingencies will involve management judgment regarding the outcome of future events.

2.3.16 Income taxation

Current income tax

The tax expense for the period comprises current and deferred tax. Tax is recognized in the statement of profit or loss and other comprehensive income, except to the extent that it relates to items recognized in other comprehensive income or directly in equity. In this case, the tax is also recognized in other comprehensive income or directly in equity.

The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the balance sheet date in the country where Group operates and generates taxable income. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulations are subject to interpretation. It establishes provisions where appropriate on the basis of amounts expected to be paid to the tax authorities.

Taxation on crude oil activities is provided in accordance with the Petroleum Profits Tax Act (PPTA) CAP. P13 Vol. 13 LFN 2004 and on gas operations in accordance with the Companies Income Tax Act (CITA) CAP. C21 Vol. 3 LFN 2004. Education tax is assessed at 2 per cent of the assessable profits.

Deferred tax

Deferred tax is recognized, using the liability method, on temporary differences arising between the carrying amounts of assets and liabilities in the consolidated historical financial information and the corresponding tax bases used in the computation of taxable profit.

A deferred income tax charge is determined using tax rates (and laws) that have been enacted or substantively enacted by the balance sheet date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled.

Deferred tax liabilities are generally recognized for all taxable temporary differences. Deferred tax assets are generally recognized for all deductible temporary differences to the extent that it is probable that taxable profits will be available against which those deductible temporary differences can be utilized. Such deferred tax assets and liabilities are not recognized if the temporary difference arises from goodwill or from the initial recognition (other than a business combination) of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit.

Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when the deferred income tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis.

2.3.17 New Tax Regime

Effective 1 January 2013, the Company was granted the pioneer tax status incentive by the Nigerian Investment Promotion Commission for a five-year period. For the period the incentive applies, the Company is exempt from petroleum profits tax on crude oil profits (which would be otherwise taxed at 65.75 per cent., to increase to 85 per cent. in 2015), corporate income tax on natural gas profits (currently taxed at 30 per cent.) and education tax of 2 per cent. Newton Energy was also granted pioneer tax status for a five-year term effective 1 June 2013. Accordingly, the new incentives form the basis of the reported nil current and deferred taxation in the financial statements.

2.3.18 Leases

The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement at the inception date. The arrangement is assessed for whether fulfilment of the arrangement is dependent on the use of a specific asset or assets or the arrangement conveys a right to use the asset or assets, even if that right is not explicitly specified in an arrangement.

Operating lease payments and capitalized prepaid operating leases are recognized as an operating expense in the statement of profit or loss and other comprehensive income on a straight-line basis over the lease term.

2.4 Judgments, estimates and assumptions

The preparation of the Group's consolidated historical financial information requires management to make judgments, estimates and assumptions that affect the reported amounts of revenues, expenses, assets and liabilities, and the accompanying disclosures, and the disclosure of contingent liabilities. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to the carrying amount of assets or liabilities affected in future periods.

Judgments

In the process of applying the Group's accounting policies, management has made the following judgments, which have the most significant effect on the amounts recognized in the consolidated historical financial information:

i) Acquisition of a 40 per cent participating interest in producing assets (note 11a)

The acquisition of a 40 per cent participating interest in OPL 283 (the Umuseti/Igbuku Fields), in 2013, has been accounted for as an acquisition of assets, with the exception of adopting IFRS 3, Business

combination, when accounting for the contingent consideration. This is on the basis that the Group does not have control.

ii) NPDC receivable (note 16)

NPDC continues to demonstrate its commitment to repay outstanding debts. After significant payments during 2014, the amounts owed by NPDC as at 31 December 2014 was $463 million (2013: $284 million), of which $256 million (2013: $248 million) is overdue. The Group considers that the current receivable balance remains fully recoverable as cash payments continue to be received and as at 5 February 2014, solely the amounts relating to 2013 and 2014 are overdue.

iii) Deposit for investment / prepayment (note 16)

i) The Group considers that the [deposit for investment / prepayment] of $453 million in relation to the acquisition of additional assets is fully recoverable in accordance with the terms of the deposit Estimates and assumptions

The key assumptions concerning the future and other key sources of estimation uncertainty at the reporting date that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are described below. The Group based its assumptions and estimates on parameters available when the consolidated financial statements were prepared. Existing circumstances and assumptions about future developments may change due to market changes or circumstances arising that are beyond the control of the Group. Such changes are reflected in the assumptions when they occur.

ii) Contingent consideration (note 23)

In 2013, the Group recognized the contingent consideration in relation to its acquisition of a participating interest in assets within OPL 283 (the Umuseti/Igbuku Fields). The contingency criteria are the achievement of certain production milestones. The Group expects these to be met in 2015. At inception, the present value was capitalized to the cost of the asset and a corresponding liability was recorded.

An additional consideration of $33 million was paid by SEPLAT on 22 October 2012 in connection with the acquisition agreement relating to OMLs 4, 38 and 41, which stated that if Brent price per barrel was greater than or equal to the average price of $80, as calculated over a period of 731 consecutive calendar days starting 30 July 2010, such additional consideration would become payable to the assignor.

At inception, the amount was capitalized to the cost of the asset and a corresponding liability was recorded based on the probability of the oil price being above $80 per barrel. A swap of $79.80 per barrel, which reflects the average price of Brent dated on the period from 26 August 2010 to 26 August 2012 was used in the calculation of the fair value of the liability and benchmarked against prices used by other industry experts.

iii) Oil and gas reserves

Proved oil and gas reserves are used in the units of production calculation for depletion as well as the determination of the timing of well closure and impairment analysis. There are numerous uncertainties inherent in estimating oil and gas reserves. Assumptions that are valid at the time of estimation may change significantly when new information becomes available. Changes in the forecast prices of commodities, exchange rates, production costs or recovery rates may change the economic status of reserves and may ultimately result in the reserves being restated.

The Group makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. Such estimates and assumptions are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

iv) Provision for decommissioning (note 24)

Provisions for environmental clean-up and remediation costs associated with the Group's drilling operations are based on current constructions, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology.

v) Recoverability of assets carrying amount (note 11a)

The Group assesses its property, plant and equipment, including exploration and evaluation assets, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable, or at least at every reporting date. Such indicators include changes in the Group's business plans, changes in commodity prices, evidence of physical damage and, for oil and gas properties, significant downward revisions of estimated recoverable volumes or increases in estimated future development expenditure.

If there are low oil prices or natural gas prices during an extended period the Group may need to recognize significant impairment charges. The assessment for impairment entails comparing the carrying value of the cash-generating unit with its recoverable amount, that is, value in use. Value in use is usually determined on the basis of discounted estimated future net cash flows. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation on operating expenses, discount rates, production profiles and the outlook for regional market supply-and-demand conditions for crude oil and natural gas.

In 2014, in response to the significant fall in commodity prices, the Group executed an impairment assessment. The Group used the fair value less costs of disposal method in determining the recoverable amount of the cash-generating unit. The assessment did not result in an impairment charge. In determining the fair value, the Group used a recent forward curve for 3 years, reverting to the Group's long term price assumption for impairment testing of $72 per barrel from 1 January 2018. The Group used a post-tax discount rate of 12% based on the Group weighted average cost of capital

vi) Contingencies (note 30c)

By their nature, contingencies will only be resolved when one or more uncertain future events occur or fail to occur. The assessment of the existence, and potential quantum, of contingencies inherently involves the exercise of significant judgment and the use of estimates regarding the outcome of future events.

vii) Income taxes (note 8)

The Group is subject to income taxes only by the Nigerian tax authority, which does not require much judgment in terms of provision for income taxes, but a certain level of judgment is required for recognition of the deferred tax assets. Management is required to assess the ability of the Group to generate future taxable economic earnings that will be used to recover all deferred tax assets. Assumptions about the generation of future taxable profits depend on management's estimates of future cash flows. The estimates are based on the future cash flow from operations taking into consideration the oil and gas prices, volumes produced, operational and capital expenditure.

2.5 Changes in accounting policies and disclosures

New and amended standards and interpretations

There were a number of new standards and interpretations, effective from 1 January 2014 that the Group applied for the first time in the current year.

The nature and the impact of each new standard and amendment that may have an impact on the Group now or in the future, is described below. Several other amendments apply for the first time in 2014, however, they do not impact the annual financial statements of the Group.

Other than the changes described below, the accounting policies adopted are consistent with those of the previous financial year.

IFRIC 21 Levies

IFRIC 21 clarifies that an entity recognises a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. For a levy that is triggered upon reaching a minimum threshold, the interpretation clarifies that no liability should be anticipated before the specified minimum threshold is reached.

Retrospective application is required for IFRIC 21. This interpretation has no impact on the Group as it has applied the recognition principles under IAS 37 consistent with the requirements of IFRIC 21 in prior years.

Recoverable Amount Disclosures for Non-Financial Assets - Amendments to IAS 36 Impairment of Assets. The amendment clarifies the disclosures required in relation to the recoverable amount of impaired assets if that amount is based on fair value less costs of disposal. The amendment to IAS 36 only resulted in certain disclosures being updated.

Annual Improvements 2010-2012 Cycle

In the 2010-2012 annual improvements cycle, the IASB issued seven amendments to six standards, which included an amendment to IFRS 13 Fair Value Measurement. The amendment to IFRS 13 is effective immediately, and thus for periods beginning at 1 January 2014, and clarifies in the Basis for Conclusions that short-term receivables and payables with no stated interest rates can be measured at invoice amounts when the effect of discounting is immaterial. This amendment to IFRS 13 has no impact on the Group.

2.6 Standards Issued but not effective

The following pronouncements from the IASB will become effective for future financial reporting periods and have not yet been adopted by the Group.

IFRS 9 Financial Instruments: Classification and Measurement

IFRS 9 reflects the IASB's work on the replacement of IAS 39 and was done in several phase since 2009. The final version of IFRS 9 was issued in May 2014 and applies to classification and measurement of financial assets and financial liabilities, impairment of financial assets as well as hedge accounting. IFRS 9 is effective for annual periods beginning on or after 1 January 2018.The adoption of IFRS 9 will have an effect on the classification and measurement of the financial assets and but not on financial liabilities.

IFRS 14 Regulatory deferral Accounts

IFRS 14 allows an entity, whose activities are subject to rate regulation, to continue applying most of its existing accounting policies for regulatory deferral account balances upon its first time adoption of IFRS. Existing IFRS 

preparers are prohibited from applying this standard. Also, an entity whose current GAAP does not allow the recognition of rate-regulated assets and liabilities, or that has not adopted such policy under its current GAAP, would not be allowed to recognise them on first time application of IFRS. IFRS 14 is effective for annual periods beginning on or after 1 January 2016. The Company does not expect that IFRS 14 will have material financial impact in future financial statements.

IFRS 15 Revenue from contracts with Customers

The IASB intends to replace all existing IFRS revenue requirements with IFRS 15. IFRS 15 establishes a five-step model that will apply to revenue earned from a contract with a customer (with limited exceptions), regardless of the type of revenue transaction or the industry. The standard's requirements will also apply to the recognition and measurement of gains and losses on the sale of some non-financial assets that are not an output of the entity's ordinary activities. Application is required for annual periods beginning on or after 1 January 2017. The Company is currently assessing the impact of the standard on its revenue recognition.

Amendments to IFRS 11 Joint Arrangements: Accounting for Acquisitions of Interests

The amendments to IFRS 11 require that a joint operator accounting for the acquisition of an interest in a joint operation, in which the activity of the joint operation constitutes a business must apply the relevant IFRS 3principles for business combinations accounting. The amendments also clarify that a previously held interest in a joint operation is not re-measured on the acquisition of an additional interest in the same joint operation while joint control is retained. In addition, scope exclusion has been added to IFRS 11 to specify that the amendments do not apply when the parties sharing joint control, including the reporting entity, are under common control of the same ultimate controlling party.

The amendments apply to both the acquisition of the initial interest in a joint operation and the acquisition of any additional interests in the same joint operation and are prospectively effective for annual periods beginning on or after 1 January 2016. The Company is currently assessing the impact of the standard on its Joint arrangement.

Amendments to IAS 27: Equity Method in Separate Financial Statements

The amendments will allow entities to use the equity method to account for investments in subsidiaries, joint ventures and associates in their separate financial statements. Entities already applying IFRS and electing to change to the equity method in its separate financial statements will have to apply that change retrospectively.

For first-time adopters of IFRS electing to use the equity method in its separate financial statements, they will be required to apply this method from the date of transition to IFRS. The amendments are effective for annual periods beginning on or after 1 January 2016, with early adoption permitted.

The Company is currently assessing the impact of the standard in its separate financial statement.

IFRS 10, IFRS 12 and IAS 28 Investment Entities: Applying the Consolidation Exception - Amendments to IFRS 10, IFRS 12 and IAS 28

The amendments address issues that have arisen in applying the investment entities exception under IFRS 10. The amendments to IFRS 10 clarify that the exemption (in IFRS 10.4) from presenting consolidated financial statements applies to a parent entity that is a subsidiary of an investment entity, when the investment entity measures all of its subsidiaries at fair value. Furthermore, the amendments to IFRS 10 clarify that only a subsidiary of an investment entity that is not an investment entity itself and that provides support services to the investment entity is consolidated. All other subsidiaries of an investment entity are measured at fair value.

The amendments to IAS 28 allow the investor, when applying the equity method, to retain the fair value measurement applied by the investment entity associate or joint venture to its interests in subsidiaries.

This amendment is effective for annual periods beginning on or after 1 January 2016. It is not expected that this amendment would be relevant to the Company.

IAS 1 Disclosure Initiative - Amendments to IAS 1

The amendments to IAS 1 Presentation of Financial Statements clarify, rather than significantly change, existing IAS 1 requirements. The amendments clarify

· The materiality requirements in IAS 1

· That specific line items in the statement(s) of profit or loss and OCI and the statement of financial position may be disaggregated

· That entities have flexibility as to the order in which they present the notes to financial statements

· That the share of OCI of associates and joint ventures accounted for using the equity method must be presented in aggregate as a single line item, and classified between those items that will or will not be subsequently reclassified to profit or loss

Furthermore, the amendments clarify the requirements that apply when additional subtotals are presented in the statement of financial position and the statement(s) of profit or loss and other comprehensive income.

This amendment is effective for annual periods beginning on or after 1 January 2016. The company is currently assessing the impact of the standard on the presentation of its financial statement.

2.7 Segment reporting

The Group operates one segment, being the exploration, development and production of oil and gas related projects located in Nigeria. Therefore, no segment reporting has been prepared.

3. Revenue

4. Cost of Sales  

Other field expenses includes costs of inventory charged to profit & loss, cost relating to operational expenditures that do not specifically relate to rigs such as minor clean-up cost, repair and maintenance of field equipment and field insurance.

5. Other operating income

5a. Sale of scraps

This represents the sale value of scrapped tubings from work-over wells.

6. Other general and administrative expenses

Other general expenses relate to costs such as office maintenance costs, rentals, telecommunication costs, and logistics costs.

6a. Salaries and employee related costs include the following: