Genel Energy Regulatory News (GENL)

1 August 2017

Genel Energy plc

Unaudited results for the period ended 30 June 2017

Genel Energy plc ('Genel' or 'the Company') announces its unaudited results for the six months ended 30 June 2017.

Results summary ($ million unless stated)

1. EBITDAX is earnings before interest, tax, depreciation, amortisation, exploration expense and impairment which is operating loss adjusted for the add back of depreciation ($45.7 million), exploration costs written off ($4.8 million) and any impairments ($0 million)

2. Capital expenditure is additions of intangible assets and additions of property, plant and equipment (oil and gas assets only)

3. Free cash flow before interest paid is net cash generated from operating activities less cash outflow due to purchase of intangible assets and purchase of property, plant and equipment (oil and gas assets only)

4. Cash reported at 30 June 2017 excludes $18.5 of restricted cash and 31 December 2016 excludes $19.5 million of restricted cash

5. Net debt is reported debt less cash

Highlights

· Tawke and Taq Taq generated cash proceeds of $139 million in H1 2017, leading to free cash flow of $78 million in the period

· Successful bond repurchase in April 2017, with $253 million of nominal bonds acquired at a 14% discount to par. Annual interest charge reduced from $51 million to $32 million

· Unrestricted cash balances at 30 June 2017 of $246 million (31 December 2016: $407 million). IFRS net debt at the end of the period was $158 million, a 34% reduction on the end 2016 figure of $241 million 

· Net working interest production averaged 37,100 bopd in H1 2017. Tawke field gross production is currently averaging c.109,000 bopd, with a further c.4,500 bopd gross added from the Peshkabir-2 production testing

· Successful production test of Cretaceous horizons in the Peshkabir-2 well on the Tawke PSC. The well's Cretaceous Shiranish interval was placed on long-term test in late May, with the well producing consistently around 4,500 bopd to date and production trucked to Fishkhabur prior to export by the KRG through the KRI-Turkey pipeline

· Onshore Somaliland, the acquisition of 2D seismic data commenced in March 2017, with over 1,000 km obtained to date

Outlook

· Negotiations with potential partners for the Kurdistan Region of Iraq ('KRI') gas project are ongoing, with the Company expecting to be in a position to update the market on these discussions by the end of 2017

· The Company continues to work collaboratively with the KRG on a definitive mechanism to recover the receivable for unpaid oil sales

· Peshkabir-3 well spudded on 8 July 2017 and is expected to take three months to drill. Peshkabir early production facility to be installed by year-end 2017

· 2017 guidance:

- Capex:

o Tawke and Taq Taq net to Genel $60-75 million (from $50-75 million)

o KRI gas business capex of $10-15 million

o Somaliland 2D seismic capex budget expected at c.$15 million (from $10-15 million)

- Opex: $30-35 million (unchanged)

- G&A: income statement $20-25 million (from $30 million) and cash cost $15-20 million (from $20 million)

Murat Özgül, Chief Executive of Genel, said:

"I am pleased to report a strong financial performance in the first half of 2017. Regular payments from the KRG, the conversion of part of the booked receivable into cash, and our ongoing focus on costs, has allowed us to generate significant free cash flow. This in turn gave us the confidence to increase investment at Tawke and undertake a large scale bond repurchase, with net debt reducing by around a third since the end of 2016.

Negotiations with potential upstream partners for the gas business continue, and we expect to give an update on these in the second half of 2017 in line with our previously stated timetable. We are also encouraged by the preliminary results of the Peshkabir-2 testing programme, and look forward to drilling the Peshkabir-3 well."

Enquiries:

This announcement contains inside information.

There will be a conference call for analysts and investors today at 0800 BST, with an associated presentation available on the Company's website, www.genelenergy.com. The dial-in details are below:

The call will be recorded and made available on the Genel website shortly after it finishes.

Disclaimer

This announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration and production business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Company's control or within the Company's control where, for example, the Company decides on a change of plan or strategy. Accordingly no reliance may be placed on the figures contained in such forward looking statements. The information contained herein has not been audited and may be subject to further review.

OPERATING REVIEW

PRODUCTION

Net working interest production in H1 2017 averaged 37,100 bopd, a decrease of 34% on H1 2016.

At Tawke, gross production in the period of 108,700 bopd was a 4% increase on H1 2016 as the 2017 development programme continued to successfully offset natural field declines. At Taq Taq, field declines continued, resulting in average production of 22,100 bopd in H1 2017, compared to 68,800 bopd in the comparable period in 2016.

1 Refinery sales at Taq Taq denote sales to the Bazian refinery

2 Difference between production and sales relates to inventory movements

During the period practically all Tawke field output was sold by the KRG through the KRI-Turkey export pipeline. Taq Taq sales were evenly split between exports through the KRI-Turkey pipeline and deliveries to the Bazian refinery. Sales to the Bazian refinery during the period were invoiced at the wellhead export netback price, in line with the payment mechanism announced by the KRG in February 2016.

KRI OIL ASSETS

TAWKE PSC (25% working interest)

The Tawke PSC produced an average of 109,700 bopd in H1 2017, compared to 104,400 bopd in H1 2016. The first half figure included an average 1,000 bopd contribution from the Peshkabir-2 production testing.

Tawke field

The Tawke field produced an average of 108,700 bopd in H1 2017, a 4% increase on H1 2016 levels. Production during the period was broadly stable as development activity in the first half of the year successfully offset natural well decline at the field. Three further Cretaceous development wells (T-35, T-42 and T-41) were drilled and completed during the period. Two additional development wells and a water injector in shallow Jeribe reservoir were also successfully completed in the first half, as well as a rolling programme of workovers at existing wells (primarily focused on replacement of ESPs). Gross production from the Tawke field is currently averaging c.109,000 bopd.

In April 2017, the Tawke partners approved an expansion of the 2017 Tawke field development programme following continued momentum in KRG payment reliability and predictability. The T-43 Cretaceous development well is currently drilling, and a decision on the drilling of two additional contingent Cretaceous wells will be made in Q3 2017.

Peshkabir appraisal

During the period the Tawke partners made further progress on the appraisal of the Peshkabir discovery, which is wholly contained within the Tawke PSC. During April, the deeper Jurassic in the Peshkabir-2 ('P-2') well was successfully tested with two intervals flowing 2,700 bopd and 400 bopd of 25°API oil during a cased hole testing programme.

Following the Jurassic test, two Cretaceous reservoir intervals (Shiranish and Qamchuqa) flowed 28°API oil at 4,300 bopd, and 1,100 bopd, respectively during a two-week cased hole testing programme in May. The well's Cretaceous Shiranish interval was placed on long-term test in late May, with the well producing consistently around 4,500 bopd to date.

The P-2 Cretaceous test is expected to continue throughout the remainder of 2017, albeit subject to interruption from the wider Peshkabir activity programme. Test production from both the Jurassic and Cretaceous horizons has been trucked to the operator's export facility at Fishkhabur and subsequently exported by the KRG through the KRI-Turkey pipeline.

The Peshkabir-3 ('P-3') well spudded on 8 July 2017 and will take approximately three months to drill and complete. The well will target the lateral extent of the Cretaceous discovery to the north of the P-2 penetration over the poorly seismically imaged crest of the Peshkabir structure. The results of the P-3 well and any subsequent production testing will be important in determining the overall potential of the Peshkabir discovery.

Combined production from the P-2 and P-3 wells will be routed through an early production facility which is expected to be installed by year-end 2017.

TAQ TAQ (44% working interest, joint operator)

As previously reported, the Taq Taq field produced an average of 22,100 bopd in H1 2017, a 68% decrease compared to H1 2016. Field production declined in the first half of 2017 as a result of the continued increase in water cut and development activity being biased towards the second half of the year. The field is currently averaging 14,700 bopd with a water cut of c.50%.

The overriding strategy for the Taq Taq field is to generate free cash flow - with $32 million in free cash flow being generated in the first half of the year - and maximise gross ultimate recovery. As a result the field partners have decided to wait for the results of the TT-29 well ahead of sanctioning any further investment in the main Cretaceous reservoir. Accordingly, two planned sidetracks of existing Cretaceous producers have been moved into the contingent category pending results from TT-29.

The main objective in the TT-29 well, which has been drilling since February 2017, is to reduce the uncertainty on the free water level in the north flank of the field. Results were originally expected around mid-year, although challenging hole conditions experienced while deviated drilling through Palaeocene aged rocks immediately above the Cretaceous reservoirs in the field have resulted in well operations being behind schedule. The well has recently been plugged back, with the partners aiming to re-drill the Palaeocene lithology with a less aggressive well trajectory. As a consequence, TT-29 results are now expected in H2 2017. The TT-29 well was also targeting a shallower Tertiary anomaly which was proven not to be hydrocarbon bearing.

In the shallower Pilaspi reservoir the partners have agreed to drill two additional development wells, which are planned for H2 2017.

Well intervention operations continue within the existing well stock, notably including a rolling programme of jet pump testing in selected Cretaceous producers to assess the potential for increasing field off-take at higher levels of water cut using this form of artificial lift.

While the rate of decline in Taq Taq production has slowed in recent months, management believes it is still too early to extrapolate meaningful conclusions from this trend, particularly ahead of the results of the TT-29 well. Genel will continue with the practice of reporting monthly updates for Taq Taq production for the foreseeable future.

KRI GAS ASSETS

MIRAN AND BINA BAWI (100% working interests and operator)

The Company remains in negotiations with potential partners for the upstream development of the Miran and Bina Bawi gas fields. The Company expects to be in a position to update the market on the progress of these discussions by the end of 2017.

The Gas Lifting Agreements ('GLAs') signed for Miran and Bina Bawi in February 2017 contained a number of conditions precedent ('CPs'). If these CPs are not satisfied or waived by February 2018 the KRG has a right to terminate the GLAs. In the event of termination, and a subsequent failure to conclude new gas lifting agreements within a one year period, the KRG can also terminate the Miran and Bina Bawi PSCs. During the three year period following such a termination, Genel would have a right of first refusal to participate in the development of the Miran and Bina Bawi gas fields with a 49% working interest on the same terms offered to any third party.

Since signature of the GLAs, Genel has continued its constructive collaboration with the KRG in developing the gas project on a mutually attractive basis. The Company has been focusing on satisfying the CPs within its control, particularly updated competent person's reports for Miran and Bina Bawi, which are still expected to complete by the end of 2017. The KRG is leading negotiations with potential partners relating to agreements on the midstream gas processing facilities and pipeline transportation, and we hope to provide an update on these in the second half of 2017.

Separately, good progress has been made in preparing for further appraisal activity on Miran and Bina Bawi which may be required ahead of final investment decision.

EXPLORATION AND APPRAISAL

Onshore Somaliland, the acquisition of 2D seismic data on the SL-10B/13 (Genel 75%, operator) and Odewayne (Genel 50%, operator) blocks commenced in March 2017. The data is being acquired as part of a Somaliland government owned speculative 2D seismic acquisition project, with the Company purchasing the associated data from the government in tranches.

This new data will deliver a step change in the Company's understanding of this highly prospective but underexplored area. To date over 1,000 line km of 2D seismic data has been acquired. The scope of the 2017 seismic programme has recently been increased from 2,000 line km following good progress in the early stages of acquisition, as well supporting the objective of defining a drillable prospect inventory. The planned 2D seismic will satisfy the outstanding commitment in the current exploration phase on both licences. Any further activity beyond the current exploration phase is discretionary, and will be dependent on the analysis of seismic results amongst other factors.

The Company is in the final stages of discussions with the Moroccan government over the nature, scope and timing of the activity related to the remaining exploration commitment on the Sidi Moussa offshore licensed acreage.

In July 2017, the KRG approved the transfer of the Company's 40% interest in the Chia Surkh PSC to Petoil. Post-period end, Genel received the initial consideration of $2 million, with an additional $25 million in staged payments contingent on future crude oil production from the Chia Surkh licence.

The Company has formally relinquished its 40% working interest in the Ber Bahr licence in the KRI.

CHIEF FINANCIAL OFFICER'S REVIEW

Results summary ($ million unless stated)

1. EBITDAX is earnings before interest, tax, depreciation, amortisation, exploration expense and impairment which is operating loss adjusted for the add back of depreciation ($45.7 million), exploration costs written off ($4.8 million) and any impairments ($0 million)

2. Capital expenditure is additions of intangible assets and additions of property, plant and equipment (oil and gas assets only)

3. Free cash flow before interest paid is net cash generated from operating activities less cash outflow due to purchase of intangible assets and purchase of property, plant and equipment (oil and gas assets only)

4. Cash reported at 30 June 2017 excludes $18.5 of restricted cash and 31 December 2016 excludes $19.5 million of restricted cash

5. Net debt is reported debt less cash

The financial priorities of the Company remain in line with those reported at year-end:

· Continue engagement with the KRG to ensure timely and full payments for oil sales from Tawke and Taq Taq, and a definitive mechanism for reconciliation and recovery of the legacy KRG receivable

· Manage liquidity appropriately ahead of the 2019 maturity of the Company's bond debt

· Continue to focus on all aspects of the Company's cost base, whether capital, operating or administrative expenditure

· Secure equity and debt investment into the gas assets, thereby progressing the project towards final investment decision

Since the 2016 year-end results, an improved Brent oil price of $52/bbl (1H 2016: $40/bbl) price, steady asset performance from Tawke, consistent payments for both current oil sales and past receivables, and the offsetting of CBP, generated proceeds of $139.3 million compared to $118.8 million in 1H 2016. The increase in proceeds, together with the reduction in operating expenses and offsetting of CBP against the receivable has resulted in improved operating cash flow of $114.2 million (1H 2016: $79.7 million) and, together with reduced capital expenditure, improved free cash flow to $78.1 million (1H 2016: $33.1 million).

This strong cash generation, together with confidence in continued payments for current sales and recovery of the receivable, enabled the Board in April 2017 to approve the spend of $216.7 million to repurchase bonds with book value of $249.3 million (nominal value of $252.8 million) and consequently reduce net debt by $32.6 million. The Company sees this as a step towards refinancing the bonds, which mature in May 2019. When addressing the maturity of the bonds, the Company will take into account the reserves and production profiles of its assets, Tawke, Taq Taq and Peshkabir; the current status and likelihood of near-term progress on crystallising value from the KRI gas assets; and the expected cash generation of the receivable, together with available liquidity. In addition, the Board will continue to assess the appropriate cost structure for the business and assess the most appropriate allocation of capital.

Income statement and proceeds

Although production of 37,100 bopd was considerably lower than H1 last year (2016: 56,400 bopd), revenue benefited from higher oil prices and was $87.1 million compared to $91.1 million in H1 2016:

· Sales realisations used in calculating revenues for Tawke and Taq Taq during H1 2017 were $40/bbl and $47/bbl respectively (compared to $28/bbl and $35/bbl respectively in H1 2016). These figures are based on Platts Dated Brent less a $12/bbl discount for Tawke and $5/bbl for Taq Taq, with $4/bbl of these discounts reflecting handling and transportation costs. Brent averaged c.$52/bbl in H1 2017 (H1 2016: c.$40/bbl)

· Sales from Taq Taq to the Bazian refinery are invoiced at the wellhead export netback price, in line with the payment mechanism announced by the KRG on 1 February 2016

H1 2017 cash proceeds totalled $139.3 million, which included payments for exports, refinery and local KRI sales invoiced under the 1 February 2016 payment mechanism agreed between contractors and the KRG. Of this figure, $74.7 million was received for Tawke and $64.6m for Taq Taq. As per the terms of the Company's PSCs for Tawke and Taq Taq, CBP are due on the profit oil portion of sales proceeds. However, as part of its ongoing dialogue with the KRG over recovery of the receivable, CBP due on Tawke and Taq Taq sales in the period October 2016 to March 2017 (relating to proceeds received in H1 2017) of $37 million has not been paid, and the amount due permanently offset against the receivable balance. From an accounting perspective, any excess of net proceeds over revenue in a reporting period results in (all else equal) a positive working capital move in cash flow.

Cash proceeds received as payment on account against monthly PSC entitlements are calculated based on a temporary simple proxy formula based on a percentage of total field revenue. For 2017 this has been agreed as 26.0% for Tawke and 46.7% for Taq Taq, which on a combined basis for the half year generates payments broadly in line with PSC entitlement (the basis for revenue recognition). The Company expects there to be a reconciliation in the future when amounts paid on account under the proxy formula will be trued up to the amount due under the terms of the PSC.

Production costs have benefited from cost reduction programmes and were $13.2 million (H1 2016: $17.2 million) with depreciation at $44.8 million (H1 2016: $66.9 million) as a result of the lower production volumes. Exploration expense of $4.8 million was current year capital activity that has been expensed relating to Somaliland, Morocco and KRI.

General and administration costs were $10.1 million (H1 2016: $9.5million).

Finance income of $3.4 million (H1 2016: $11.3 million) is comprised of $2.7 million discount unwind on trade receivables and $0.7 million of bank interest income. Finance expense of $26.7 million (H1 2016: $30.9 million) was comprised of $20.9 million of bond interest together with non-cash discount unwind expense of $5.8 million.

Taxation

In the KRI, the Company is either exempt from tax or tax due has been paid on its behalf by the KRG from the KRG's own share of revenues, resulting in no tax payment required or expected to be made by the Company.

Dividend

No interim dividend will be paid (H1 2016: nil) or is expected to be paid in the near future. 

Capital expenditure

Capital expenditure for the period was $41.0 million (2016: $61.2 million). Cost recovered development spend of $28.1 million (2016: $40.3 million) was incurred on the producing assets in the KRI with spend on exploration and appraisal assets amounting to $12.9 million (2016: $20.9 million), approximately half of which was spent on the Miran and Bina Bawi PSCs with the other half split between Peshkabir and Somaliland.

Guidance on capital expenditure net to the Company on Tawke and Taq Taq is refined to $60-75 million (from $50-75 million), reflecting year to date spend, activity deferrals on Taq Taq pending the results of the TT-29 well, and the previously announced expansion of the 2017 Tawke drilling programme.

Estimated capex on Miran and Bina Bawi is updated to $10-15 million (from c.$10 million). Capex on the onshore Somaliland 2D seismic programme is estimated at c.$15 million, up from c.$10 million reflecting the recently sanctioned increase in the data acquisition.

Cash flow, cash and debt

The operating cash flow for the period was $114.2 million (H1 2016: $79.7 million), cash outflow from investing activities was $36.1 million (H1 2016: $46.6m) resulting in free cash flow for the period of $78.1 million (H1 2016: $33.1 million free cash flow).

Interest paid was $23.5 million (H1 2016: $26.9 million). $216.7 million of cash was used to buy back nominal value of $252.8 million (book value of $249.3 million) of Company bonds, reducing net debt by $32.6 million.

There was an overall net cash outflow of 161.1 million (H1 2016: net decrease of $29.2 million) with restricted cash reducing available cash by a further $18.5 million (H1 2016: $19.5 million).

Cash at period end was $245.7 million (2016: $407.0 million), which excludes restricted cash of $18.5 million principally relating to the Company's exploration activities in Morocco. Debt reported under IFRS was $404.0 million, reduced from $648.2 million reported at year end as a result of the bond buy back.

Net debt was $158.3 million (2016: $241.2 million).

Receivables

At 30 June 2017, the reported KRG receivable was $201.7 million (2016: $253.5 million). The balance reducing as a result of continued payments from the KRG towards the receivable together with offsetting of CBP due on proceeds received in the period from October 2016 to June 2017, offset by discount unwind of $2.7 million.

Net assets

Net assets at 30 June 2017 were $1,360.7 million (2016: $1,333.4 million)

Going concern

The Directors have assessed that the cash balance held provides the Company with adequate liquidity for at least 12 months following the signing of the half year financial statements for the period ended 30 June 2017 for the Company to be considered a going concern.

Principal risks and uncertainties

The Company is exposed to a number of risks and uncertainties that may seriously affect its performance, future prospects or reputation and may threaten its business model, future performance, solvency or liquidity. The following risks are the principal risks and uncertainties of the Company, which are not all of the risks and uncertainties faced by the Company: Development and recovery of reserves and resources; Commercialisation of KRI gas business; M&A activity; KRI natural resources industry; Recovery of amounts owed for export sales; Regional risk; Corporate governance failure; Capital structure and financing; Local communities; and Health and safety risks. Further detail on each risk was provided in the 2016 Annual Report. There has been no change in principal risks and uncertainties since year end.

Responsibility statement of the directors

The directors confirm that these condensed half year consolidated financial statements have been prepared in accordance with International Accounting Standard 34, "Interim Financial Reporting", as adopted by the European Union and that the half year management report includes a true and fair view of the information required by DTR 4.2.7 and DTR 4.2.8, namely:

· an indication of important events that have occurred during the six months ended 30 June 2017 and their impact on the condensed half year consolidated financial statements, and a description of the principal risks and uncertainties for the remaining period of the financial year; and

· material related-party transactions in the six months ended 30 June 2017 and any material changes in the related-party transactions described in the last annual report.

The directors of Genel Energy plc are listed in the Genel Energy annual report for 31 December 2016. A list of the current directors is maintained on the Genel Energy plc website: www.genelenergy.com

By order of the Board

Murat Ozgul

CEO

31 July 2017

Disclaimer

This announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration and production business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Company's control or within the Company's control where, for example, the Company decides on a change of plan or strategy. Accordingly no reliance may be placed on the figures contained in such forward looking statements.

Condensed consolidated statement of comprehensive income

Condensed consolidated balance sheet

Condensed consolidated statement of changes in equity

Condensed consolidated cash flow statement

Notes to the condensed consolidated financial statements

1. Basis of preparation

The Company is a public limited company incorporated and domiciled in Jersey with a listing on the London Stock Exchange. The address of its registered office is 12 Castle Street, St Helier, Jersey, JE2 3RT.

The half year financial statements for the six months ended 30 June 2017 and six months ended 30 June 2016 are unaudited and have been prepared in accordance with the Disclosure and Transparency Rules of the Financial Conduct Authority and with IAS 34 'Interim Financial Reporting' as adopted by the European Union and were approved for issue on 27 July 2016. They do not comprise statutory accounts within the meaning of Article 105 of the Companies (Jersey) Law 1991. The half year financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2016, which have been prepared in accordance with IFRS as adopted by the European Union. The annual financial statements for the period ended 31 December 2016 were approved by the board of directors on 29 March 2017. The report of the auditors was unqualified, did not contain an emphasis of matter paragraph and did not contain any statement under the Companies (Jersey) Law 1991. The financial information for the year to 31 December 2016 has been extracted from the audited accounts.

Going concern

At the time of approving the half year consolidated financial statements, the directors have a reasonable expectation that the Company has adequate resources to continue in operational existence for the 12 months from the balance sheet date and therefore its consolidated financial statements have been prepared on a going concern basis.

The Company provides non-Gaap measures to provide greater understanding of its financial performance and financial position. EBITDAX is presented in order for the users of the accounts to understand the underlying cash profitability of the Company, which excludes the impact of costs attributable to exploration activity, which tend to be one-off in nature, and the non-cash costs relating to depreciation, amortisation and impairments. Free cash flow before interest is presented in order to present the free cash flow generated that is available for the Board to use to finance or invest in the business. Net debt is reported in order for users of the accounts to understand how much debt remains unpaid if the Company paid its debt obligations from its available cash. There have been no changes in related parties since year-end other than the Board changes that have been reported to the market and there are not significant seasonal or cyclical variations in the Company's total revenues.

2. Accounting policies

The accounting policies adopted in preparation of these half year financial statements are consistent with those used in preparation of the annual financial statements for the year ended 31 December 2016.

The preparation of these half year statements in accordance with IFRS requires the Company to make judgements and assumptions that affect the reported results, assets and liabilities. Where judgements and estimates are made, there is a risk that the actual outcome could differ from the judgement or estimate made. The Company has assessed the following as being areas where changes in judgements, estimates or assumptions could have a significant impact on the financial statements.

Significant accounting judgements, estimates and assumptions

In preparing these half year financial statements, the following significant estimates and judgements have been made:

Estimation of future oil price

The estimation of future oil price has a significant impact throughout the financial statements, primarily in relation to the estimation of the recoverable value of property, plant and equipment, intangible assets and trade receivables. It is also relevant to the assessment of going concern and the viability statement.

The Company's forecast of average Brent oil price for future years is based on a range of publicly available market estimates and is summarised in the table below, with the 2021 price then inflated at 2% per annum.

Estimation of hydrocarbon reserves and resources and associated production profiles

Estimates of hydrocarbon reserves and resources are inherently imprecise, require the application of judgement and are subject to future revision. The Company's estimation of the quantum of oil and gas reserves and resources and the timing of its production and monetisation impact the Company's financial statements in a number of ways, including: testing recoverable values for impairment; the calculation of depreciation and amortisation; assessing the cost and likely timing of decommissioning activity and associated costs; and the carrying value of trade receivables. This estimation also impacts the assessment of going concern and the viability statement.

Proven and probable reserves are estimates of the amount of hydrocarbons that can be economically extracted from the Company's assets. The Company estimates its reserves using standard recognised evaluation techniques. Proven and probable reserves ("2P" - generally accepted to have circa 50% probability) are used for the assessment of the Company's assets classified as property, plant and equipment and therefore form the basis of testing for depreciation and testing for impairment. Under Petroleum Reserves Management System definition, 2P reserves only refers to projects that are currently justified for or are already in development.

Hydrocarbons that are not assessed as 2P are considered to be resources and are classified as exploration and evaluation assets. These assets are expenditures incurred before technical feasibility and commercial viability is demonstrable. Estimates of resources for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and being depleted and are likely to contain estimates and judgements with a wide range of possibilities.

Once a field commences production, the amount of proved reserves will be subject to future revision once additional information becomes available through, for example, the drilling of additional wells or the observation of long-term reservoir performance under producing conditions. As those fields are further developed, new information may lead to revisions.

Assessment of reserves and resources are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves.

Estimation of oil and gas asset values

Estimation of the asset value of oil and gas assets is calculated from a number of inputs that require varying degrees of estimation. Principally oil and gas assets are valued by estimating the future cash flows based on a combination of reserves and resources, costs of appraisal, development and production, production profile and future sales price and discounting those cash flows at an appropriate discount rate.

Future costs of appraisal, development and production are estimated taking into account the level of development required to produce those reserves and are based on past costs, experience and data from similar assets in the region, future petroleum prices and the planned development of the asset. However, actual costs may be different from those estimated.  

Discount rate is assessed by the Company using various inputs from market data, external advisers and internal calculations. Discount rates used for impairment testing are disclosed in the relevant note.For the year-ended 31 December 2016, changes in estimates resulted in impairments to exploration and evaluation assets and property plant and equipment. These impairments are disclosed in notes 8 and 9 with explanation provided in significant accounting judgements, estimates and assumptions in note 1 of the 2016 Annual Report.

Estimation of netback price and entitlement used to calculate reported revenue, trade receivables and forecast future cash flows

Netback price is used to value the Company's revenue, trade receivables and its forecast cash flows used for impairment testing and viability. The Company does not have direct visibility on the components of the netback price because sales are managed by the KRG, but invoices are currently raised for payments on account using a netback price that has been temporarily agreed with the KRG for the purpose of receiving interim payments. For revenue recognition, the Company has estimated the netback price using the methodology agreed with the KRG for receiving these payments on account.

In line with its IOC payment process, which began in September 2015 and was given structure by its announcement on 1 February 2016, last year the KRG commenced the audit of costs, production and revenue, including detailed analysis of the components of netback. Once this process is completed, the Company expects to then reach agreement with the KRG on the appropriate netback adjustment to use in the calculation of the Company's entitlement under the PSC and the resulting trade receivable balance. The audit and reconciliation process may take some time and conversations with the KRG are ongoing. The outputs of the reconciliation and settlement process may result in changes to the estimates made by the Company. A $1/bbl difference in netback price would impact half year revenue by circa $1 million and trade receivables by circa $1 million.

Estimation of the recoverable value of trade receivables

Trade receivables of $201.7 million relates to money owed by the KRG principally for export sales that were made after mid-2014. The KRG has stated publicly on a consistent basis that it intends to pay full entitlement following a reconciliation process.

When assessing the nominal value of the receivable the Company has taken into account the latest information on the entitlement it is owed under the PSC for oil that has been sold but not yet paid for. In addition, a calculation has been made for the interest that has accrued on the balance under the terms of the PSC at LIBOR plus 2%. The Company has excluded consideration of any value for export sales that were made before mid-2014 (including exports marketed by the State Oil Marketing Organisation ("SOMO") where payment is outstanding). The total unrecognised receivable balance relating to these sales excluding interest is estimated at circa $300m.

The Company expects that ultimately a reconciliation calculating full entitlement under the terms of the PSC will be agreed with the KRG - this reconciliation will form the basis for calculating amounts owed and for agreeing a mechanism to settle the balance.  

Subject to the reconciliation process that has been started by the KRG, the Company is fully confident of its contractual right to the nominal value of the receivable. The Company expectation is that it will be settled with cash, although it is possible that the debt could be settled in a number of ways such as with assets or through an improvement in future contractual terms. The success and pace of the recovery of the balance depends on some or all of a number of factors, including: the financial environment in the KRI and the financial budget of the KRG; oil price; volumes of production from the KRI as a whole as well as from the Company's fields; and ongoing negotiations with regard to various sources of potential finance for the KRI.

On 1 February 2016, the KRG announced an interim mechanism to make monthly payments to the IOCs. The mechanism has two components: the first component is a proxy for monthly entitlement due under the terms of the PSC; the second component is intended to contribute towards repayment of the receivable. The contribution towards the receivable was set at, and currently remains at, 5% of field revenue. The KRG stated that it intends to increase this percentage as the oil price improves - at the time the oil price was around $30/bbl but to date no increase to this percentage has been made.

Although the Company expects either an increase in payments, or an alternative structure to be agreed to accelerate the recovery of the receivable, the Company has assessed that there is not sufficient evidence to support the use of anything other than the existing payment terms of 5% of field revenue when assessing the trade receivable for impairment and does not currently take into account the potential for increased payments or alternative methods of settling the balance.

The carrying value of trade receivables is compared to the present value of the forecast monthly contributions using the effective interest rate for the period in which the revenue was recognised. For the period over which the receivable was recognised, the Company has assessed the effective interest rate to be between 8% and 13% using an adjusted prevailing Iraqi government 2028 bond as a proxy, resulting in a blended rate of 8.3%.

Business combinations

The recognition of business combinations requires the excess of the purchase price of acquisitions over the net book value of assets acquired to be allocated to the assets and liabilities of the acquired entity. The Company makes judgements and estimates in relation to the fair value allocation of the purchase price.

The fair value exercise is performed at the date of acquisition. Owing to the nature of fair value assessments in the oil and gas industry, the purchase price allocation exercise and acquisition-date fair value determinations require subjective judgements based on a wide range of complex variables at a point in time. The Company uses all available information to make the fair value determinations.

In determining fair value for acquisitions, the Company utilises valuation methodologies including discounted cash flow analysis. The assumptions made in performing these valuations include assumptions as to discount rates, foreign exchange rates, commodity prices, the timing of development, capital costs, and future operating costs. Any significant change in key assumptions may cause the acquisition accounting to be revised.

There are no new standards and amendments to standards as adopted by the European Union at 30 June 2016 which are mandatory for the first time for the financial year beginning 1 January 2016 and which have a significant impact on the Company. A number of new standards, amendments to standards and interpretations will be effective for annual periods beginning after 1 July 2016. None of these standards have been early adopted. The Company's review of IFRS15 and IFRS9 is underway but is not yet completed, with neither currently expected to have a material impact on the results or financial statements of the Company..

Financial risk factors

The Company's activities expose it to a variety of financial risks: credit risk, currency risk, interest risk and liquidity risk. The half year financial but do not include all financial risk management information and disclosures required in the annual financial statements; they should be read in conjunction with the Company's annual financial statements as at 31 December 2016. There have been no significant changes in any risk management policies since year end.

3. Segmental information

The Company has three reportable business segments: oil, gas and exploration. Capital expenditure decisions for the oil segment are considered in the context of the cash flows expected from the production and sale of crude oil. The oil segment is comprised of the producing assets, Taq Taq and Tawke, which are located in the KRI and make predominantly all sales to the KRG; the gas segment is comprised of the upstream and midstream activity on Miran and Bina Bawi also in the KRI; the exploration segment is comprised of the company's exploration activity, principally located in the KRI, Somaliland and Morocco.

6 months ended 30 June 2017

Total assets and liabilities in the other segment are predominantly cash and debt balances. 'Other' includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items.

6 months ended 30 June 2016

1The Company has changed its assessment of segments as explained above and consequently has restated its prior half year segmental reporting.

For the period ended 31 December 2016

Total assets and liabilities in the other segment are predominantly cash and debt balances. 'Other' includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items. All of the oil and gas segments are located in the KRI, with the exploration segment located principally in the KRI, Somaliland and Morocco. All revenue relates to sales made to the KRG.

4. Operating costs

Exploration expense relates to accruals for costs or obligations relating to licences where there is ongoing activity or that have been, or are in the process of being, relinquished.

5. Finance expense and income

6. Taxation

A taxation charge is incurred on the profits of the Turkish and UK services companies. All corporation tax due on petroleum sales has been paid on behalf of the Company by the government from the government's share of revenues and there is no tax payment required or expected to be made by the Company.

Under the terms of the KRI PSCs, the Company is not required to pay any cash taxes although it is uncertain whether the Company is exempt from tax or whether tax has been paid on its behalf. If tax has been paid on its behalf by the government, then it is not known at what rate tax has been paid due to uncertainty in relation to the workings of any existing tax payment mechanism. It is estimated that the tax rate would be between 0% and 40%. If tax has been paid it would result in a gross up of revenue with a corresponding debit entry to taxation expense with no net impact on the income statement or on cash. In addition, it would be assessed whether any deferred tax asset or liability was required to be recognised.

7. Earnings per share

Basic

Basic earnings per share is calculated by dividing the profit attributable to equity holders of the Company by the weighted average number of shares in issue during the period.

1Excluding shares held as treasury shares

Diluted

Because the Company purchases shares in the market to satisfy share plan requirements diluted earnings per share is the same as basic earnings per share:

1Excluding shares held as treasury shares

8. Intangible assets