2015 Interim Results

7 August 2015

DRAGON OIL PLC

(the "Company" or together with its subsidiaries "Dragon Oil" or the "Group")

2015 Interim Results

Dragon Oil plc (Ticker: DGO), an international oil and gas exploration, development and production company, today announces its interim financial and operational results for the period ended 30 June 2015. These results are prepared in accordance with International Accounting Standard 34, "Interim financial reporting" ("IAS 34") as adopted by the European Union.

Financial highlights

Operational performance

Outlook

Dr Abdul Jaleel Al Khalifa, Chief Executive Officer, commented:

"Gross production has increased compared to the level in 1H 2014 on the back of strong initial flow rates from new development wells, additional perforations in certain existing wells and the application of jet pumping systems. The significant decline in crude oil prices is reflected in the financial results, and we generated US$139mn of net income, a drop of 52% from the levels achieved in the corresponding period last year.

"We surpassed the 100,000 bopd mark on 9 June 2015 - an achievement of which, we, the team at Dragon Oil, are very proud of. Since then, we are hovering around that rate. Work on our exploration assets progresses in line with programmes agreed with our respective partners and host governments."

Update on Offer from Emirates National Oil Company Ltd L.L.C ("ENOC")

On 1 July 2015, ENOC issued a document containing (among other things) the full terms of, and conditions to, a recommended cash offer by ENOC of 750 pence for each Dragon Oil ordinary share not already owned by ENOC (the "Offer") and the procedures for acceptance (the "Offer Document") together with a form of acceptance.

On 2 August 2015, the Board of ENOC announced a revision to the Offer (the "Increased Offer") and declared the Increased Offer unconditional in all respects. Under the terms of the Increased Offer, Dragon Oil Shareholders are entitled to receive 800 pence in cash for each Dragon Oil ordinary share.

The Increased Offer will remain open for acceptance until 3:00 p.m. (Dublin time) on 28 August 2015 (or such later time as ENOC may determine). Dragon Oil Shareholders who have not already done so should complete and return a Form of Acceptance as soon as possible. Completion and return of the Form of Acceptance that accompanied the Offer Document, being the Form of Acceptance for the Original Offer will be treated by ENOC as an acceptance of the Increased Offer.

For further information please contact:

About Dragon Oil

Dragon Oil plc is an international oil and gas exploration, development and production company, quoted on the London and Irish Stock exchanges (Ticker symbol: DGO). Its principal producing asset is in the Cheleken Contract Area, in the eastern section of the Caspian Sea, offshore Turkmenistan.

Dragon Oil (Turkmenistan) Ltd., a wholly owned subsidiary of Dragon Oil plc, holds 100% interest in, and is the operator of, the Production Sharing Agreement for the Cheleken Contract Area. The operational focus is on the re-development of two oil and gas producing fields, Dzheitune (Lam) and Dzhygalybeg (Zhdanov).

The Group has exploration blocks in Tunisia, Iraq, Afghanistan, Egypt, the Philippines and Algeria. Dragon Oil's diversification strategy is to add exploration and production assets within Africa, parts of Asia and the Middle East in order to create a diversified and balanced portfolio of assets for the Group.

www.dragonoil.com 

Disclaimer

This news release may contain forward-looking statements concerning the financial condition and results of operations of Dragon Oil. Forward-looking statements are statements of future expectations that are based on management's current expectations and assumptions and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements. No assurances can be given as to future results, levels of activity and achievements and actual results, levels of activity and achievements may differ materially from those expressed or implied by any forward-looking statements contained in this report. Dragon Oil does not undertake any obligation to update publicly or revise any forward-looking statement as a result of new information, future events or other information.

2015 Interim Results

Chief Executive Officer's Statement

OVERVIEW

We generated US$450mn in revenues in the first half of the year, 18% lower than during the same period in 2014. This was primarily due to lower realised crude oil prices at US$44 per barrel given the average Dated Brent of US$58/barrel during this period and the weighted average discount of US$13.9/barrel between two buyers to export our entitlement share of gross production from the Cheleken Contract Area. This was partially offset by higher sales volumes of 10.2 million barrels of crude oil as a result of a higher entitlement share for Dragon Oil in the Cheleken Contract Area.

Average gross production in 1H 2015 increased to 92,060 bopd and we surpassed the 100,000 bopd mark on 9 June 2015. Since the beginning of the year, Dragon OiI completed eight wells; two of which were completed early in 3Q 2015 and will be contributing to production in 2H 2015. We have also been adding perforations in certain existing wells improving or in some instances restoring the wells' production potential. The Group expects to commence drilling operations using the Caspian Driller later this quarter. We plan to drill a further seven to 10 wells before the end of the year.

We have installed four jet pumping systems and are in the process of installing and commissioning more systems later this year. The pilot water injection project is ongoing in the Dzheitune (Lam) 75 area and we plan to roll out water injection programmes at other platforms.

Total capital expenditure of the Group was US$313mn during the period, of which US$306mn is attributable to the Cheleken Contract Area. Fabrication of the new wellhead and production platform Dzheitune (Lam) E is ongoing. The Dzheitune (Lam) F platform has been installed and is ready for drilling operations. Work continues on structural upgrades to a number of platforms to extend their useful lives and accelerate production from these areas.

Our diversification strategy remains to screen, evaluate and acquire development and exploration targets that fit our criteria within Africa, parts of Asia and the Middle East, in order to create a diversified and balanced portfolio of assets for the Group.

OPERATIONAL OVERVIEW

DEVELOPMENT

Turkmenistan

Production and Entitlement

In 1H 2015, the gross average field production was 92,060 bopd (1H 2014: 73,440 bopd). Eight wells were completed from 1 January 2015 to date, including two wells completed in July 2015.

The entitlement production for 1H 2015 was approximately 68% (1H 2014: 52%) of the gross production. Entitlement barrels are finalised in arrears and are dependent on, amongst other factors, fiscal terms of the Production Sharing Agreement, operating and development expenditure in the period and the realised crude oil price. Entitlement barrels are higher in 1H 2015 primarily due to lower realised crude oil prices, coupled with increased production.

Marketing

Dragon Oil sold 10.2 million barrels of crude oil in 1H 2015 (1H 2014: 5.9 million barrels). The sales volumes increased over the comparable period's level as a result of higher entitlement and changes in the lifting position.

In 1H 2015, Dragon Oil exported 87% (1H 2014: 100%) of its crude oil production through Baku, Azerbaijan with the balance of volumes exported through Makhachkala in Russia (1H 2014: nil).

In December 2014, the Dragon Oil Group reached one-year agreements with two buyers for all of its anticipated entitlement export production in 2015, achieving a diversification in its export marketing routes, via Baku, Azerbaijan as well as via Makhachkala, Russia. The discount to Brent is expected to be approximately US$13.50 - US$14.00 per barrel in 2015. The current contracts are valid until 31 December 2015 and we continue to examine options, which include renewal of existing contracts and the development of alternative arrangements.

The Group was in an underlift position of approximately 2.9 million barrels of crude oil as at 30 June 2015 (31 December 2014: underlift position of 2.1 million barrels of crude oil).

Drilling

Since the beginning of the year, Dragon Oil has completed eight wells, with a further three wells in progress, in the Dzheitune (Lam) and Dzhygalybeg (Zhdanov) fields. The following table summarises the results of the drilling programme:

Production has been added through additional perforations in certain existing wells as well as four jet pump installations in the area.

Post completion of the Dzheitune (Lam) 22/194 well by Land Rig 1 in December 2014, an additional perforation was performed in late May followed by jet pump application in early June resulting in current production of 1,398 bopd.

The Caspian Driller is expected to commence operations in 3Q 2015.

The Group is working with its contractor and anticipates to resolve intermittent issues with certain critical equipment on Land Rig 2.

Water injection project and artificial lift

The water injection pilot project is ongoing in the pilot Dzheitune (Lam) 75 area. We are in the process of acquiring additional water injection facilities to be installed and commissioned in the Dzheitune (Lam) field. The aim of the water injection programme is for pressure maintenance, to arrest reservoir pressure decline, sustain production rates and increase reserves recovery.

Four jet pumping systems have been installed so far in 2015 in the Cheleken Contract Area, including one system on the Dzheitune (Lam) 22 platform, while additional jet pumping systems are currently being installed and expected to be commissioned during 2H 2015 on other platforms. The objective of this artificial lift application is to increase production and enhance recovery.

In parallel, Dragon Oil is procuring electric submersible pumps (ESP) with an aim to commence their application in a pilot in 1H 2016.

Infrastructure

Fabrication of the topside structure and jacket is ongoing for the new wellhead and production platform Dzheitune (Lam) E. The platform will have eight slots with provision for another four slots to be installed later, and is suitable for drilling by a jack-up drilling rig. It is anticipated that the platform will be ready in 1H 2016.

Installation of the Dzheitune (Lam) F production platform is completed and the platform is ready for drilling. Work on remaining items is ongoing to prepare for the commissioning of the platform.

We are currently conducting tenders to award contracts to extend the Dzheitune (Lam) A and B platforms with an aim to add slots for future drilling.

The project to quadruple our crude oil storage capacity at the Central Processing Facility is ongoing. The tank farm is anticipated to be completed in 1Q 2016, of which three tanks will be built on a priority basis and commissioning is expected to be in 2H 2015.

The previously deferred project to build another 30-inch trunkline from the Dzheitune (Lam) field will be re-tendered. While the new trunkline will transport oil, water and gas, its principal benefit is to transport more gas onshore, which otherwise would have had to be flared. This gas will feed the planned Gas Treatment Plant, which will have capacity to process 360 mmscf/day of gas. The Gas Treatment Plant will be constructed over three years after the contract has been awarded, and is expected to produce approximately 4,000 barrels of condensate per day. The Group believes that re-tendering for this trunkline in the current lower oil price environment may lead to cost savings.

Dragon Oil is increasing the loading capacity at the Aladja Jetty by installing another 16-inch pipeline and associated loading arms to support simultaneous loading of two tankers in 2H 2015.

Within the first phase of its strategy for plugging, abandonment and decommissioning of the old non-producing wells and non-producing platforms in the Cheleken Contract Area, Dragon Oil confirmed that another two non-producing old wells have already been plugged and abandoned, bringing the total of plugged and abandoned wells to 13 to-date. Up to 26 non-producing old wells are scheduled to be plugged and abandoned over a three-year period commencing in 2016. The execution of this strategy is part of the abandonment and decommissioning activities the Group plans to undertake to fulfil its obligations under the Production Sharing Agreement. The cost of these activities will be charged to the abandonment and decommissioning funds.

Gas Treatment Plant

The bids for an engineering, procurement, installation and construction project of the Gas Treatment Plant are in the evaluation stage. We anticipate the construction phase to take three years after the contract is awarded.

EXPLORATION

Iraq

In 2014, the partners in Block 9 in Iraq, announced the discovery of oil in two formations in the consortium's first exploration well, Faihaa-1, in which Dragon Oil holds 30%. Open and cased hole tests were conducted in the Mishrif and Yamama formations with encouraging results. The well has been tested at 5,230 bopd on a 32"/64" choke from the Yamama reservoir. A completion string has been run in the well and the drilling rig has been released. The consortium plans to drill two additional appraisal wells in 2H 2015 in order to fast track the development.

Commencing in 2016, the operator, Kuwait Energy Company, plans to accelerate the first production from the Faihaa field utilising a temporary production facility.

Algeria

In 2014, Dragon Oil in partnership with ENEL Trade S.p.A. ("Enel") was awarded two exploration perimeters in Algeria, Tinrhert Nord Perimeter (Dragon Oil 70% paying interest and operator, Enel 30%) and Msari Akabli Perimeter (Dragon Oil 30% paying interest, Enel 70% and operator). The contract for the exploration and exploitation of hydrocarbons was signed on 29 October 2014. Work is ongoing to secure environmental permits, interpret available 3D seismic data, select drilling targets and progress the necessary tenders to enable the drilling of the first exploration well in 2H 2016.

Egypt

Work as per the Concession Agreement is ongoing for the exploration of the East Zeit Bay (Dragon Oil 100%), offshore the Gulf of Suez, Egypt. We are currently employing an international contractor to reprocess existing seismic data in the block using advanced technologies with an aim to improve the quality of analysis and interpretation of the data. The Group has commenced the implementation of the approved work programme for the year.

Afghanistan

In early 2015, the consortium, comprising Dragon Oil (40%, operator of Sanduqli block), TP Afghanistan Ltd. (TPAL, 40% and operator of Mazar-i-Sharif block) and the Ghazanfar Group (20%), commenced the airborne gravity and magnetic survey in both blocks, which is expected to resume in August pending the delivery of a new aircraft and be completed at the end of 2015.

Tunisia

The joint venture partners (Dragon Oil, 55%; Cooper Energy, 30% and operator; and Jacka Resources Ltd, 15%) are seeking to extend the permit for one year taking it to 6 August 2016 in order to abandon the Hammamet-West 3 well in a rigless operation and to acquire 500 square kilometres of 3D seismic survey to assess further potential.

The Philippines

As we reported on 17 February 2015, the partners, Dragon Oil (Philippines SC 63) Limited (40%), Nido Petroleum Philippines Pty Ltd (ASX: NDO, 20% participating interest) and PNOC-EC (40% and operator) are in the process of integrating information and data obtained from the Baragatan-1 well into current geological models and Dragon Oil is assessing its future interest in the block.

MATERIAL EVENTS

Update on Offer from ENOC

On 17 March 2015, Dragon Oil announced that it had received an approach from ENOC regarding a possible offer for the entire issued and to be issued share capital of Dragon Oil that it does not already own. The proposal received valued Dragon Oil at 650 pence per Dragon Oil Share. The Independent Committee rejected this proposal, engaged in extensive discussions with ENOC, and undertook shareholder consultation regarding the approach.

On 21 May 2015, after a series of further proposals, which were also rejected, ENOC announced a revised proposal of 735 pence per Dragon Oil Share. The Independent Committee considered this proposal and again consulted with shareholders as part of its assessment.

On 15 June 2015, the Independent Committee and ENOC announced a recommended cash offer by ENOC of 750 pence per Dragon Oil Share.

In coming to a view on its recommendation, the Independent Committee had taken into account the value being offered by ENOC and the Independent Committee's views on the current position and the future prospects of Dragon Oil. The Independent Committee, assisted by its financial advisers, Nomura and Davy Corporate Finance, had modelled numerous macro and operational growth scenarios and undertaken a detailed valuation exercise of the assets and prospects of the Dragon Oil Group. In addition, the Independent Committee had engaged with minority shareholders throughout its consideration of the proposed transaction.

The Independent Committee has confidence in the management of Dragon Oil and the future prospects of the Dragon Oil Group and was of the view that the Offer reflected these prospects, offering Dragon Oil minority shareholders an attractive exit price, and was in the best interests of Dragon Oil minority shareholders as a whole.

The document containing (among other things) the full terms of, and conditions to, the Offer and the procedures for acceptance (the "Offer Document") was posted by ENOC to Dragon Oil Shareholders together with the Form of Acceptance on 1 July 2015.

As at 1:00 p.m. (Dublin time) on 31 July 2015, ENOC had received acceptances of the Original Offer valid in all respects relating to 76,568,990 Dragon Oil Shares (the "Valid Acceptances"), representing (i) approximately 15.5 per cent of the current issued share capital of Dragon Oil and (ii) approximately 33.1 per cent of the voting rights held by the Independent Shareholders on the date of the Rule 2.5 Announcement, which ENOC may count towards the satisfaction of the acceptance condition to the Offer. ENOC also had intended acceptances of the Original Offer relating to 6,502,572 Dragon Oil Shares (the "Intended Acceptances"), representing approximately 1.32 per cent of the current issued share capital of Dragon Oil.

On 2 August 2015, the Board of ENOC announced a revision to the original offer price of 750 pence for each Dragon Oil Share (the "Increased Offer"). Under the terms of the Increased Offer, Dragon Oil Shareholders are entitled to receive 800 pence in cash for each Dragon Oil Share. The Independent Committee unanimously recommended that minority shareholders accept the Increased Offer.

ENOC received firm irrevocable undertakings from Baillie Gifford and Elliott Capital Advisors to accept or procure the acceptance of the Increased Offer in respect of 64,505,038 Dragon Oil Shares representing 13.1 per cent (in aggregate) of the issued share capital of Dragon Oil (the "Further Irrevocables").

ENOC waived the acceptance condition set out in paragraph 2(a) of Appendix I of the Offer Document together with the conditions set out in paragraphs 2(b) to (i) in Appendix I of the Offer Document and declared the Offer unconditional in all respects on 2 August 2015.

Subject to the applicable requirements being met, ENOC intends to procure the de-listing of the Dragon Oil Shares from the Irish Stock Exchange and the London Stock Exchange.

Dragon Oil Shareholders who have already validly accepted the Original Offer need take no further action; their acceptances will be treated as acceptances of the Increased Offer.

The Increased Offer will remain open for acceptance until 3:00 p.m. (Irish time) on 28 August 2015 (or such later time as ENOC may determine).

The procedure for acceptance of the Offer is set out in paragraph 10 (Procedure for acceptance of the Offer) of Part II of the Offer Document and in the Form of Acceptance.

Dragon Oil Shareholders who have not already done so should complete and return a Form of Acceptance as soon as possible. Completion and return of the Form of Acceptance that accompanied the Offer Document, being the Form of Acceptance for the Original Offer will be treated by ENOC as an acceptance of the Increased Offer.

The Offer Document and Form of Acceptance are available at www.dragonoiloffer.com and www.dragonoil.com/investors. For the avoidance of doubt, the content of such website is not incorporated into, and does not form part of, this announcement.

Defined terms used but not defined in this announcement have the meanings set out in the Offer Document.

Change of Membership of the Independent Committee

On 22 July 2015, Dragon Oil plc was notified that Mr Ahmad Al Muhairbi had resigned from the independent committee of the Board of Dragon Oil (the "Independent Committee") effective 13 July 2015 as a result of his appointment as a Director to the Board of ENOC on 12 July 2015. This is as a result of a broader restructuring process of the ENOC Board.

Mr Ahmad Al Muhairbi confirmed that he would recuse himself from any discussions and decision-making with respect to the ENOC offer process.

Mr Ahmad Al Muhairbi will remain on the Board of Dragon Oil as a non-independent Non-executive Director. However, owing to his appointment to the ENOC Board, he ceases to be a member of the Audit Committee.

References to the Independent Committee post 13 July 2015 therefore refer to the committee comprising the three remaining members of the Independent Committee.

Interim dividend

According to the terms of the offer set out in the Offer Document, the offer is conditional on no dividend being recommended, announced or declared. The Board of Dragon Oil therefore advises that no interim dividend for 1H 2015 is being declared.

2015 Principal risks and uncertainties

In accordance with the Transparency (Directive 2004/109/EC) Regulations 2007, a description of the principal risks and uncertainties facing the Group in the six months to 31 December 2015 is set out below:

§ Oil prices

The Group's primary business is the production of hydrocarbons from the Cheleken Contract Area in the Caspian Sea, Turkmenistan. The financial performance of the Group and its ability to fund its exploration and development plans may, therefore, be negatively affected by adverse movements in the price of oil. The Group actively monitors its exposure to oil prices and retains flexibility in sizing its development programme.

§ Export routes

Current available export routes to sell crude oil from the Caspian Sea region to international markets are via Azerbaijan, Russia and Kazakhstan. The Group currently exports its entitlement of crude oil production via Azerbaijan and Russia. Opportunities to continue using this marketing arrangement are constantly evaluated over the longer term. At the same time, we are also evaluating alternative export arrangements.

§ Other

Other medium to long-term principal risks and uncertainties facing the Group include, among other risks and uncertainties, strategic, operational, financial and compliance risks as disclosed in the 2014 Annual Report, available on Dragon Oil's website at www.dragonoil.com.

FINANCIAL OVERVIEW

Income Statement

Revenue

In the first half of 2015, the Group's revenue decreased by 18% to US$449.9mn (1H 2014: US$547.0mn). The Group sold 10.2mn barrels of crude oil (1H 2014: 5.9mn barrels) at a realised price of US$44/bbl (1H 2014: US$93/bbl). The overall revenue decrease was attributed to a lower realised crude oil price, significantly offset by higher sales volumes.

Operating profit

Cost of sales increased by US$121.8mn to US$242.4mn (1H 2014: US$120.6mn). Cost of sales includes operating and production costs and the depletion charge. The depletion charge of US$221.4mn (1H 2014: US$133.2mn) was higher by 66% than the charge in the corresponding period in 2014, primarily due to increased entitlement barrels during the period. Operating and production costs are higher by US$33.6mn primarily attributed to changes in the lifting positions. The operating costs per barrel have marginally reduced over the comparable period on account of higher production.

The Group generated an operating profit of US$179.1mn in 1H 2015 (1H 2014: US$388.5mn), which was lower by 54% over the comparable period. The decrease in operating profit of US$209.4mn was primarily on account of lower revenue and higher cost of sales. Administrative expenses (net of other income) at US$28.3mn (1H 2014: US$19.9mn) were higher by 42% on account of increased manpower costs and higher corporate activities. A provision for impairment of US$0.04mn (1H 2014: US$18.1mn) was recognised towards the exploration and evaluation costs of the Baragatan-1A well, offshore the Philippines. The exploration well did not discover commercial hydrocarbons and has been plugged and abandoned. The future interest in the block remains to be assessed.

Profit for the period

The profit for the first six months of 2015, at US$139.0mn (1H 2014: US$289.0mn), includes a taxation charge of US$43.8mn (1H 2014: US$105.0mn), and finance income of US$5.6mn (1H 2015: US$5.5mn). The taxation charge was lower during the period on account of lower profits and a lower applicable tax rate at 20% for 2015 (2014: 25%). The finance income was marginally higher by US$0.1mn due to higher interest yields achieved despite lower average cash balance on deposit during the first six months of the year. Finance costs of US$1.9mn (1H 2014: nil) during the period were on account of the unwinding of the discount on the provision for corporate social obligations relating to Turkmenistan.

Basic EPS of 28.26 US cents in the first half of this year were 52% lower than the basic EPS in the same period last year (1H 2014: 58.79 US cents) primarily due to lower net profit combined with an increase in the number of shares in issue during the period.

Balance Sheet

Net book value of property, plant and equipment increased by US$84.5mn due to capital expenditure of US$306.0mn incurred (1H 2014: US$278.7mn) offset by the depletion and depreciation charge of US$221.5mn (1H 2014: US$133.3mn) during the period. Of the total capital expenditure, US$160.3mn (1H 2014: US$134.8mn) was attributable to development and appraisal drilling with the balance spent on infrastructure in Turkmenistan. The infrastructure spend during the period included construction of the Dzheitune (Lam) E and infield pipelines, installation of the Dzheitune (Lam) F platform and construction of the tank farm.

The net book value of intangible assets increased by US$7.2mn, net of a further provision for impairment of US$0.04mn towards the Baragatan-1A well exploration and evaluation costs, and is primarily attributable to the spend on exploration and evaluation assets.

Current Assets and Liabilities

Current assets decreased by US$124.4mn, due to lower term deposits, trade and other receivables and inventories held at the period-end, offset primarily by higher cash and cash equivalents and abandonment and decommissioning funds, as compared to 2014 year-end. The trade and other receivables decreased by US$18.9mn primarily due to a decrease in receivables from the sale of crude oil, offset primarily by an increase in underlift receivables.  

Cash and cash equivalents and term deposits as at 30 June 2015 were US$1,855.9mn (31 December 2014: US$1,974.9mn), excluding funds held for abandonment and decommissioning activities. Funds held for abandonment and decommissioning activities as at 30 June 2015 were US$686.7mn (31 December 2014: US$664.0mn).

Current liabilities decreased by US$106.9mn due to a decrease of US$101.6mn in the current income tax liability and US$24.8mn trade and other payables, partly offset by a higher abandonment and decommissioning liability at the period end. 

Cash flows

Net cash generated from operating activities in 1H 2015 of US$265.1mn was 12% lower than net cash generated in the same period last year (1H 2014: US$300.7mn). The decrease was primarily attributable to lower revenue and higher tax paid, despite the change in the working capital position and lower amounts transferred to abandonment and decommissioning funds.

Net cash used in investing activities in 1H 2015 was US$154.6mn (1H 2014: US$176.4mn) comprising of capital expenditure of US$319.9mn offset by withdrawal from term deposits of US$159.7mn and interest income of US$5.6mn received during the period.

Net cash used in financing activities in 1H 2015 was US$69.8mn (1H 2014: US$86.5mn), primarily due to the payment of 2014 final dividends of US$78.7mn and partly offset by an inflow of US$9.1mn on issue of new shares following the exercise of share options. 

OUTLOOK

On 15 June 2015, Dragon Oil updated its target for average production growth for 2015 to be around 15%. We expect to drill and complete between 15 and 18 wells, of which eight wells have already been completed; we will continue to add perforations in existing wells to maintain and grow production.

The Group maintains its guidance for an exit rate of 100,000 bopd - the level we first achieved on 9 June 2015 - in 2015 and plans to sustain the 100,000 bopd average gross production for a minimum of five years from 2016.

Our capital expenditure for infrastructure and drilling excluding the Gas Treatment Plant cost in Turkmenistan in 2015 is estimated to be at the upper end of the US$500mn to US$600mn guidance at around US$600mn and around US$50-100mn for exploration assets.

Dr Abdul Jaleel Al Khalifa

Chief Executive Officer 

Dragon Oil plc

end -

Legal Information

The directors of Dragon Oil accept responsibility for the information contained in this announcement. To the best of the knowledge and belief of the directors of Dragon Oil (who have taken all reasonable care to ensure such is the case), the information contained in this announcement is in accordance with the facts and does not omit anything likely to affect the import of such information.

The members of the Independent Committee accept responsibility for the information in relation to the Offer contained in this announcement. To the best of the knowledge and belief of the members of the Independent Committee (who have taken all reasonable care to ensure that such is the case), the information contained in this announcement for which they accept responsibility is in accordance with the facts and does not omit anything likely to affect the import of such information.

Nomura, which is authorised by the Prudential Regulation Authority and regulated in the United Kingdom by the Financial Conduct Authority and Prudential Regulation Authority, is acting exclusively for the Independent Committee and no one else in connection with this announcement and will not be responsible to anyone other than the Independent Committee for providing the protections afforded to clients of Nomura nor for providing advice in connection with this announcement or any matter referred to herein.

Davy, which is authorised and regulated by the Central Bank of Ireland, is acting exclusively for the Independent Committee and no one else in connection with this announcement and will not be responsible to anyone other than the Independent Committee for providing the protections afforded to clients of Davy nor for providing advice in connection with this announcement or any matter referred to herein

Condensed group balance sheet

Condensed group income statement

Condensed group statement of comprehensive income

Condensed group statement of changes in equity

Condensed group cash flow statement

Comparative information presented above has been amended to accord to the current period presentation (refer to Note 21).

1 General information

Dragon Oil plc (the "Company") and its subsidiaries (together, "the Group") are engaged in upstream oil and gas exploration, development and production activities primarily in Turkmenistan under a Production Sharing Agreement (PSA) signed between Dragon Oil (Turkmenistan) Limited and The State Agency for Management and Use of Hydrocarbon Resources at the President of Turkmenistan ("the Agency"). The production of crude oil is shared between the Group and the Government of Turkmenistan as determined in accordance with the fiscal terms as contained in the PSA. The Group headquarters is based in Dubai, United Arab Emirates.

The Company is a public limited company, incorporated and domiciled in the Republic of Ireland in September 1971. The address of its registered office is 6th Floor, South Bank House, Barrow Street, Dublin 4, Ireland. The registration number is 35228.

The Company's ordinary shares have a primary listing on the Irish Stock Exchange and premium listing on the London Stock Exchange.

This condensed consolidated interim financial information (interim financial information) was approved for issue by the Board of Directors on 6 August 2015.

2 Basis of preparation of interim financial information

This interim financial information for the six months ended 30 June 2015 has been prepared in accordance with the Transparency (Directive 2004/109/EC) Regulations 2007, the related Transparency Rules of the Central Bank of Ireland and with International Accounting Standard 34, "Interim financial reporting" ("IAS 34") as adopted by the European Union. The interim financial information should be read in conjunction with the annual financial statements for the year ended 31 December 2014, which have been prepared in accordance with International Financial Reporting Standards (IFRS), as adopted by the European Union. The interim financial information has been prepared under the historical cost convention except for the measurement at fair value of under lift receivables/over lift payables.

The preparation of the interim financial information includes the use of estimates and assumptions that affect items reported in the condensed Group balance sheet and the condensed Group income statement. Although these estimates are based on management's best knowledge of current circumstances and assumptions about future events and actions, actual results may differ from those estimates.

Taxes on income in the interim periods are accrued using the tax rate that would be applicable to expected total annual earnings.

3 Accounting policies

The accounting policies applied are consistent with those of the annual financial statements for the year ended 31 December 2014, as described in those annual financial statements, except for the adoption of new standards and interpretations as of 1 January 2015.

New standards, interpretations and amendments adopted by the Group

The Group applies, for the first time, certain standards and amendments. As required by IAS 34, the nature and the effect of these changes are disclosed below.

The following amended standards and interpretations became effective for the first time in 2015 but have no impact on the annual consolidated financial statements of the Group or the interim condensed consolidated financial statements of the Group.

· Defined benefit plans: Employee contributions (Amendments to IAS 19)

4 Segment information

In accordance with IFRS 8 'Operating Segments', the Group has three principal reporting segments which are as follows:

· Central Asia : Development and production assets located in Turkmenistan in the Caspian region

· North Africa : Exploration and evaluation assets in Tunisia, Egypt and Algeria

· South East Asia and Middle East: Exploration and evaluation assets in Philippines, Iraq and Afghanistan

The segment information presented is based on the financial performance as reported in the internal reporting provided to the Chief Operating Decision-maker (CODM). The Board of Directors (BOD), which is responsible for allocating resources and assessing performance of the operating segments, has been identified as the CODM that makes strategic decisions.

The financial information reviewed by the CODM is based on the IFRS financial information for the Group.

'Corporate' primarily includes cash resources held by the Group, interest income earned and other operational expenditure incurred by the Group which are not specifically attributable to identified operating segments.

For the six months ended 30 June 2015 (Unaudited)

4 Segment information (continued)

For the six months ended 30 June 2014 (Unaudited)

4 Segment information (continued)

5 Critical accounting judgements and estimates

The preparation of the interim financial information in conformity with IAS 34 requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities as well as contingent assets and liabilities at the date of the balance sheet, and the reported amounts of revenues and expenses during a reporting period. The resulting accounting estimates will, by definition, seldom equal the related actual results.

The critical accounting judgements and estimates that could result in material adjustments to the income statement and the carrying amounts of assets and liabilities are discussed below:

(a) Carrying value of development and production assets

In arriving at the carrying value of the Group's development and production assets, significant assumptions in respect of the depletion charge have been made. These significant assumptions include estimates of oil and gas reserves, future oil and gas prices, finalisation of the gas sales agreement and future development costs including the cost of drilling, infrastructure facilities and other capital and operating costs.

If the gas sales were delayed to 2019, the depletion charge would increase by US$ 3.2 million for 1H 2015. Should there be a significant delay in signing of the gas sales agreement at appropriate commercial terms beyond 2019, it would change the timing of the recognition of the depletion charge. Inclusion of the gas reserves has deferred a current period depletion charge in the amount of US$ 57.5 million over the remaining life of the PSA.

Effective August 2014, the Group's estimated long-term view of oil prices was based on a 3 year Brent forward curve for 2015-17 and US$ 85 per barrel thereafter. Effective 1 January 2015, the Group revised its estimated long-term view of oil prices based on a 5 year Brent forward curve and US$ 75 per barrel in real terms thereafter.

Effective 1 January 2015, the Group revised its estimated long-term view of netback prices for gas from US$ 0.5 per Mscf to US$ 0.5 per Mscf for 5 years and stated in real terms thereafter, based on the current outlook.

If the estimate of the long-term oil price had been US$ 40 per barrel higher and the netback price of gas had been US$ 2 per Mscf higher from 1 January 2015, the reserves attributable to the Group would decrease, with a consequent increase in the depletion charge of US$ 34.9 million for the six months period ended 30 June 2015.

If the estimate of the long-term oil price had been US$ 40 per barrel lower and the netback price of gas had been US$ 0.25 per Mscf lower from 1 January 2015, reserves attributable to the Group would increase, with a consequent decrease in the depletion charge of US$ 82.5 million for the six months period ended 30 June 2015.

The depletion computation assumes the continued development of the field to extract the assessed oil and gas reserves and the required underlying capital expenditure to achieve the same. For this purpose, it assumes that a gas sales agreement will be signed and that the PSA, which is valid up to 2025, will be extended on similar terms up to 2035 under an exclusive right to negotiate for an extension period of not less than ten years, provided for in the PSA.

5. Critical accounting judgements and estimates (continued)

(b) Exploration and evaluation (E&E) assets

The application of the Group's accounting policy for exploration and evaluation expenditure requires judgement to determine whether it is likely that future economic benefits will arise, from either exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves.

(c) Classifications of joint arrangements

Judgement is required to determine when the Group has joint control over an arrangement, which requires an assessment of the relevant activities and when the decisions in relation to those activities require unanimous consent. The Group has determined that the relevant activities for its joint arrangements are those relating to the operating and capital decisions of the arrangement, as stated in the joint operating agreement such as approval of the capital expenditure program for each year. The considerations made in determining joint control are similar to those necessary to determine control over subsidiaries. Classifying a joint arrangement requires the Group to assess its rights and obligations arising from the arrangement. Specifically, the Group considers whether it is structured through a separate vehicle.

6 Property, plant and equipment

During the six months period ended 30 June 2015, the Group acquired development and production assets with a cost of US$ 306 million (1H 2014: US$ 278.6 million). The depletion and depreciation charge was US$ 221.5 million (1H 2014: US$ 133.3 million).

7 Intangible assets

The intangible assets consist of exploration and evaluation assets and other intangible assets which total US$ 99.9 million (31 December 2014: US$ 92.7 million) primarily relating to the Group's interest in certain exploration blocks in North Africa, South East Asia and Middle East and is net of a provision for impairment of US$ 24 million (1H 2014: US$ 18.1 million) towards the Baragatan-1A well, offshore the Philippines. The exploration well did not discover commercial hydrocarbons and has been plugged and abandoned. The future interest in the block remains to be assessed.

8 Financial instruments

(i) Financial instruments by category

The carrying value of the financial instruments is a reasonable approximation of their fair value.

* In the disclosure for the year ended 31 December 2014 the crude oil underlift receivable of US$ 84.9 million was also included in loans and receivables, and as such has been amended. This does not have an impact upon the balance sheet or upon earnings per share.

8 Financial instruments (continued)

(ii) Fair value hierarchy

All financial instruments for which fair value is recognised or disclosed are categorised within the fair value hierarchy, described as follows, based on the lowest level input that is significant to the fair value measurement as a whole:

Level 1: Quoted market prices in an active market (that are unadjusted) for identical assets or liabilities;

Level 2: Valuation techniques (for which the lowest level input that is significant to the fair value measurement is directly or indirectly observable); and

Level 3: Valuation techniques (for which the lowest level input that is significant to the fair value measurement is unobservable).

As at 30 June 2015, the Group held the following classes of financial instruments measured at fair value:

9 Cash and bank balances

(a) Term deposits and cash and cash equivalents

Cash and cash equivalents do not include any interest bearing deposits with original maturities of three months or less during the period (31 December 2014: nil).

9 Cash and bank balances (continued)

(b) Abandonment and decommissioning funds

The related abandonment and decommissioning liability is shown under Note 12.

10a Share capital and premium

Trade payables and accruals include amounts of US$ 59.6 million (31 December 2014: US$ 64.7 million) and US$ 90.1 million (31 December 2014: US$ 91.6 million) respectively, relating to additions to property, plant and equipment - development and production assets. The carrying value of trade and other payables approximate their fair values.

Corporate social obligations

In December 2014, the Group and the state authorities in Turkmenistan agreed to amend the provisions of the PSA to clarify the tax rate applicable to the Group and to include certain contractual obligations for community social expenses. Under the terms of the amendment, the Group is committed to corporate social obligations and training programmes in Turkmenistan of approximately US$ 10 million per year over the remaining initial period of the PSA. A number of the joint operations in which the Group participates have similar contractual obligations. These obligations are measured at the present value of future payments. The present value was determined using a discount rate of 4.5%.

Corporate social obligations include US$ 87.2 million (31 December 2014: US$ 85.3 million) relating to Turkmenistan and US$ 2.6 million (31 December 2014: US$ 2.6 million) relating to other exploration and evaluation assets.

12 Abandonment and decommissioning liability

The abandonment and decommissioning liability represents amounts relating to the sale of crude oil set aside to cover abandonment and decommissioning liabilities under the terms of the PSA. The related abandonment and decommissioning fund is shown under Note 9b.

13 Revenue

Revenue of US$ 449.9 million (1H 2014: US$ 547.0 million) comprises an amount of US$ 391.7 million (1H 2014: US$ 546.9 million) arising from the sale of crude oil through Baku, Azerbaijan and US$ 58.1 million (1H 2014: nil) arising from the sale of crude oil through Makhachkala, Russia and US$ 0.1 million (1H 2014: US$ 0.1 million) arising from other sales.

Revenue from the sales of crude oil was from two customers (1H 2014: one customer).

14 Dividends paid and proposed

15 Earnings per share

The calculation of basic earnings per ordinary share is based on the weighted average number of 491,758,475 ordinary shares in issue during the six months to 30 June 2015 (1H 2014: 491,552,245 ordinary shares) and on the profit for the period of US$ 139 million (1H 2014: US$ 289 million).

The calculation of diluted earnings per ordinary share is based on the number of 492,033,456 ordinary shares in issue during the six months to 30 June 2015 (1H 2014: 491,737,410 ordinary shares) adjusted to assume conversion of potential dilutive options over ordinary shares.

16 Cash generated from operating activities

17 Income tax expense

Income tax expense is recognised based on management's best estimate of the weighted average annual income tax rate expected for the full financial year. The estimated average annual tax rate used for 2015 is 20% (2014: 25%).

During 2008, the effective tax rate applicable to the Group's operations in Turkmenistan was increased by 5% to 25% by the Hydrocarbon Resources Law of 2008. The Group had applied this rate in determining its tax liabilities in prior years.

In December 2014, the Group and the state authorities in Turkmenistan agreed to amend the provisions of the PSA to bring the tax rate into line with the provisions of the Tax Code of Turkmenistan. The rate of 20% is now applicable to the Group in respect of its petroleum operations in Turkmenistan. The impact of the reduction in the tax rate in 2014 was a reversal of US$160 million in respect of an overprovision for prior years up to 2013, no longer payable. The Group has applied this rate in determining its tax liabilities as at 30 June 2015.

During the period, the Group recognised a current tax charge of US$ 46.5 million (1H 2014: US$ 90.9 million) and a net deferred tax credit of US$ 2.7 million (1H 2014: net deferred tax charge of US$ 14.1 million).

18 Related party transactions

a) Transactions and balances

The Company's largest shareholder is Emirates National Oil Company Limited (ENOC) L.L.C ("ENOC"), which owns approximately 53.84% of the Company's ordinary share capital. ENOC is ultimately a wholly owned entity of the Government of Dubai. Three members of the Board, Mr. Ahmad Sharaf, Mr. Mohammed Al Ghurair and Mr. Ahmad Al Muhairbi are nominees of ENOC. All transactions with related parties are on an arm's length basis.

18 Related party transactions (continued)

a) Transactions and balances (continued)

b) Key management compensation

19 Commitments and contingencies

a) Capital commitments

(i) The capital commitments at 30 June 2015 were as follows:

b) Operational commitments

Letters of credit of US$110.6 million were in issue at 30 June 2015 (31 December 2014: US$112.4 million) towards the supply of equipment and services.

At 30 June 2015, the Company had a continuing guarantee for US$200 million (31 December 2014: US$172 million) for undrawn trade finance facilities of subsidiary undertakings.

19 Commitments and contingencies (continued)