Genel Energy plc ('Genel' or 'the Company') announces its unaudited results for the six months ended 30 June 2018.
Murat Özgül, Chief Executive of Genel, said:
"Genel continues to deliver on its focus. We are generating significant free cash flow, averaging over $10 million a month in the first half of 2018 and moving us rapidly towards a net cash position. The impressive performance we have seen at Peshkabir will further increase cash generation, and the ongoing appraisal success provides the potential for both production to exceed guidance and for proven and probable reserves to increase.
Growing cash generation provides a solid bedrock from which we are able to pursue multiple growth opportunities, with Bina Bawi oil offering exciting potential within the Genel portfolio.
With 11 wells currently drilling or to be drilled on our producing assets in the Kurdistan Region of Iraq in H2 2018, of which eight are expected to be completed and adding to production by the end of the year, we are well positioned to both add value through the drill bit and further bolster our financial strength."
Results summary ($ million unless stated)
Production (bopd, working interest)
Net gain arising from the RSA
Depreciation and amortisation
Impairment of property, plant and equipment
Cash flow from operating activities
Free cash flow2
Basic EPS (¢ per share)
- Tawke PSC and Taq Taq net to Genel of $70-80 million (previously $60-85 million), as work ramps up across both licences
- Miran and Bina Bawi capex of $15-30 million (previously $25-40 million), as the work programme focuses on progression of the high-value oil opportunity at Bina Bawi
- African exploration cost unchanged at$10-15 million, with the majority relating to seismic shooting offshore Morocco, which will be covered by restricted cash
- Opex of c.$30 million and G&A of c.$15 million cash cost unchanged
For further information, please contact:
Andrew Benbow, Head of Communications
+44 20 7659 5100
+44 20 7390 0230
There will be a presentation for analysts and investors today at 0930 BST, with an associated webcast available on the Company's website, www.genelenergy.com.
This announcement includes inside information.
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.
Net working interest production in H1 2018 averaged 32,100 bopd, in line with guidance.
(by PSC in bopd)
Export via pipeline
Genel net production
Tawke (inc. Peshkabir)
1 Refinery sales at Taq Taq denote sales to the Bazian refinery
2 Difference between production and sales relates to inventory movements
All sales during the period were invoiced at the wellhead export netback price.
KRI OIL ASSETS
Five wells were spud across our assets in the KRI in the period, four of which were on the Peshkabir field. Drilling work is heavily loaded towards the second half of the year, with 11 wells set to be under operation in H2 on our producing fields, with eight expected to be adding to production by the end of the year.
TAWKE PSC (25% working interest)
The Tawke PSC produced an average of 105,800 bopd in H1 2018, slightly down on H1 2017 (109,700 bopd), with additional production from the successful drilling campaign at the Peshkabir field coming post-period end. Current Tawke PSC production is c.121,000 bopd, with success from the remaining Peshkabir wells, and the resumption of drilling at the Tawkefield, having the potential to further increase this figure.
Production from the Tawke PSC benefits from the Receivable Settlement Agreement ('RSA'), and these increases bolster our already significant free cash flow generation.
Activity in H1 included ongoing workovers of existing wells, which has mitigated decline at the Tawke field in the last three months. Drilling will resume at the field in the second half of the year, with up to four production wells set to be spud. Two are scheduled as Jeribe producers, and up to two as Cretaceous producers.
Drilling will arrest production decline at Tawke, as expected with mature field infill drilling, with the overall objective to maximise production and cash-generation.
Peshkabir continues to exceed expectations, with the benefit of ongoing appraisal success increasing production in H2 2018. Peshkabir-4 is now adding to production at a stable rate of 12,000 bopd, with Peshkabir-5 adding a further 8,000 bopd, materially surpassing the operator's previously announced summer 2018 Peshkabir production target of 30,000 bopd. The field is currently producing c.35,000 bopd, with another four wells set to be completed in 2018.
Peshkabir-5 was drilled seven kilometres west of Peshkabir-3, and has successfully proved the westward extension of the field. As it was drilled in an area designated P3 (possible)reserves, should production continue to match current expectations then it would lead to an increase in proven and probable reserves at the field. With 217 MMboe of reserves booked in the in the P3 (possible) category as at the end of 2018, this increase is potentially significant.
Activity continues apace at Peshkabir. Two wells, Peshkabir-6 and Peshkabir-7, are now at target depth, with the former aiming to establish the Cretaceous oil/water contact and exploring the field's untested deeper Triassic formation, and the latter targeting infill production. Peshkabir-8 will also target further production, with Peshkabir-9 being drilled to test the eastern extension of the field, as we work with the operator to ascertain the full extent of Peshkabir's potential.
Given the potential for a material increase from current production levels, work is being undertaken on facilities at the field. The central processing facility, which has been brought across from Taq Taq and is expected onstream later this year, is set to ensure that surface capacity is sufficient to service production.
Discussions are ongoing with the operator regarding the Enhanced Oil Recovery project, under which excess gas from Peshkabir would be used to boost oil production from the Tawkelicence.
TAQ TAQ (44% working interest, joint operator)
Production at Taq Taq remained stable in H1 as the well intervention and production optimisation programme, focused on the provision of artificial lift and water shut off in existing wells, continued to give encouraging results.
The stabilisation of production provides a solid base from which to ramp up activity at the field. Work to analyse the result of the TT-29w well, which encountered a deeper free water level and more extensive oil bearing cretaceous reservoirs on the northern flank of the field than previously forecast, has now been completed. The results have helped in the formulation of an updated field development plan ('FDP'), which has now been completed and agreed with our field partners and the Ministry of Natural Resources.
Phase one of the FDP is a five well programme, starting towards the end of Q3, and ending in Q2 2019. The drilling programme will target the flanks in order to prove up the remaining potential of the field, starting with the TT-32 well, which will test the extent of oil to the north of the TT-29w well. The next well will then be drilled as a sidetrack on the western flank of the field, before the rig moves to the southern flank. Drill locations will follow depending on results.
Given the stabilisation of production at Taq Taq, we expect these wells to increase field production, with the benefits starting to be seen towards the end of the year. The field continues to generate meaningful free cash flow, boosted by an ongoing cost reduction programme.
BINA BAWI AND MIRAN (100% working interests and operator)
Work continues to unlock the transformational potential of the Bina Bawi and Miran licences. The focus in H1 has been on the progression of the high-value early oil development at Bina Bawi.
The field development plan for Bina Bawi oil has now been completed, and is set to be submitted to the Ministry of Natural Resources. The FDP confirms Genel's expectation that first oil would be achievable around six months after the final investment decision. Light oil (44-47◦ API) has already been tested at Bina Bawi, with the Bina Bawi-3 well having flowed at c.3,500 bopd. Phase one of the development would see the recompletion of this well, and a sidetrack of the Bina Bawi-1 well, both of which target the proven Mus reservoir, and would aim for a combined 5,000 bopd of initial production. The cost to first oil is estimated at c.$20 million.
Phase two, to be executed simultaneously to phase one, would be the drilling of up to four new wells, targeting a production plateau of 10-15,000 bopd, achievable a year from the beginning of work. Phase three would then constitute additional infill wells as required.
Oil production from Bina Bawi would benefit from cost-recovery of the significant capital outlay already made by Genel at Bina Bawi, and has the potential to add material cash flow. Discussions are ongoing with the Ministry of Natural Resources in order to expedite the development of Bina Bawi oil.
Genel estimates that 34 MMbbls of light oil is recoverable under the FDP, and would be converted to 2P reserves upon final investment decision.
In January 2018 Bina Bawi and Miran CPRs confirmed a c.45% uplift to gross 2C raw gas resources to 14.8 Tcf. The upstream part of the project has been materially de-risked, with 1C volumes more than sufficient for the gas volumes required under the gas lifting agreement. Following the CPR, further reservoir engineering has demonstrated the viability of high-rate gas wells, which in turn more than halves the number of wells required to produce the volumes under the gas lifting agreement, materially reducing the overall cost of the project.
A field development plan regarding Bina Bawi gas is set to be submitted to the Ministry of Natural Resources around the end of Q3 2018, with one for the Miran field around the end of the year.
Genel is ready to progress the upstream as required, with further investment to be made appropriate to progress on the midstream.
Onshore Somaliland, the processing of c.3,500 km of raw 2D seismic data on the SL-10B/13 (Genel 75% working interest, operator) and Odewayne (Genel 50% working interest, operator) is almost complete. Analysis and interpretation is underway. Evidence of a thick Mesozoic rift basin continues to provide encouragement, and the first analysis of this highly-prospective region in over 25 years is expected to complete in Q4. A prospect inventory will then be developed, guiding the optimal strategy to maximise future value, with the potential to spud a well around the end of 2019.
The 3D seismic campaign on the Sidi Moussa licence (Genel 75% working interest, operator), offshore Morocco, has now begun. Seismic acquisition is expected to be completed in the middle of Q4 2018. Fast-track processing will begin ahead of the completion of this acquisition, as Genel de-risks the licence and assesses future activity.
For 2018 the financial priorities of the Company are the following:
In the first half of the year, successful delivery of these priorities, together with an improving oil price, has produced positive results, with free cash flow of $70 million representing an increase of 28% on the previous year.
Our net debt has reduced significantly to $64 million compared to $135 million at the end of 2017 and we expect to be in a net cash position around the end of 2018.
We will continue to be disciplined in our capital allocation and invest in areas where we can deliver value. Currently this means investment in Peshkabir, where success will provide incremental cash generation in the second half, and our other producing assets, which also offer opportunities to increase near-term cash flow.
We will make further investment in Bina Bawi oil and our gas potential when we can see a clear roadmap to unlocking value. As there remains limited visibility on the gas developments at Bina Bawi and Miran, spend has been minimised, with the focus on completing the FDP for Bina Bawi oil.
Rigorous cost management is maintained across all operations, while ensuring spend is sufficient to take advantage of the growth opportunities in the portfolio.
A summary of the financial results for the year is provided below.
As regular payments for oil sales have now been received from the KRG for almost three years, the Company will cease to make monthly announcements, and will instead update on cash receipts as part of its standard corporate reporting schedule.
Financial results for the half-year
Revenue has increased by 85% year-on-year, from $87.1 million to $161.1 million. This is principally a result of the improved revenue generation from the Tawke PSC arising from the RSA, which was signed in August 2017 and generated incremental revenue of $48.2 million in the first half of 2018. Additional benefit has arisen from improved Brent oil price of $71/bbl (H1 2017: $52/bbl).
Working interest production of 32,100 bopd was lower than the first half last year (H1 2017: 37,100 bopd), which benefited from Taq Taq working interest daily production being around 5,000 bopd higher since around May 2017.
Production costs of $12.1 million (H1 2017: $13.2 million) are broadly in line with last year, with $/bbl staying around $2/bbl.
Depreciation and amortisation of oil assets has increased overall by $18.6 million as a result of the inclusion of amortisation of $28.8 million relating to intangible assets arising from the RSA. This was offset by a $10.2 million decrease in depreciation as a result of lower production.
General and administration costs were $11.8 million (H1 2017: $10.1 million), of which cash costs were $8.6 million (H1 2017: $6.4 million). Gross cost was reduced by 8% from the prior year, with the net increase caused primarily by movement in the exchange rates between sterling and US dollar.
Under the KRI PSC's, tax due is paid on behalf of the Company 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.
Capital expenditure for the period was $34.1 million (H1 2017: $41.0 million). Cost recovered spend on producing assets in the KRI was $27.8 million (H1 2017: $28.1 million) with spend on exploration and appraisal assets amounting to $6.3 million (H1 2017: $12.9 million), principally incurred on the Miran PSC and the Bina Bawi PSC.
Cash flow and cash
Net cash flow from operations was increased as a result of higher revenue to $125.1 million (H1 2017: $114.2 million), with last year benefiting from $50.9 million of one-off positive working capital movements relating to the overdue KRG receivable.
Free cash flow after interest was $70.1 million (H1 2017: $54.6 million).
$17.5 million (H1 2017: $18.5 million) of cash is restricted and therefore excluded from reported cash of $233.2 million (H1 2017: $245.7 million). Overall, there was a net increase in cash of $71.1 million compared to a decrease of $161.1 million last period after $216.7 million of cash was used to buy back of Company bonds in H1 2017.
Reported IFRS debt was $297.0 million (31 December 2017: $296.8 million) and net debt was $63.8 million (31 December 2017: $134.8 million).
The bond has three financial covenant maintenance tests:
Net debt / EBITDAX (rolling 12 months)
Equity ratio (Total equity/Total assets)
Net assets at 30 June 2018 were $1,672.9 million (31 December 2017: $1,609.8 million) and consist primarily of oil and gas assets of $1,823.6 million (31 December 2017: $1,847.9million), trade receivables of $84.4 million (31 December 2017: $73.3 million) and net debt of $63.8 million (31 December 2017: $134.8 million).
Liquidity / cash counterparty risk management
The Company monitors its cash position, cash forecasts and liquidity on a regular basis. The Company holds surplus cash in treasury bills or on time deposits with a number of major financial institutions. Suitability of banks is assessed using a combination of sovereign risk, credit default swap pricing and credit rating.
No interim dividend will be paid (H1 2017: nil) or is expected to be paid in the near future.