Neptune Energy Announces H1 2019 Results

Source Press Release
Company
Tags Asset Deals, Deals, Upstream Activities, Financial & Operating Data
Date August 29, 2019

Neptune Energy, the global independent oil and gas exploration and production company, today announces its financial results for the period ended 30 June 2019.

Solid strategic progress, delivering long-life and low-cost production and increasing reserves

-      In July, interests were acquired in the Kutei Basin PSCs offshore Indonesia: the transaction includes the low-cost Merakes development in East Sepinggan PSC (20 per cent WI), which provides production growth from 2020. The East Ganal PSC (30 per cent WI) provides longer-term exploration potential.

-      Awarded the West Ganal PSC, strengthening strategic alignment with partners: provides further long-term growth potential in the strategically important Kutei Basin. The acreage contains world-class exploration potential, which can be commercialised via our existing Jangkrik infrastructure.

-      In July, increased interests were acquired in existing oil and gas assets in Emsland and Grafschaft Bentheim regions in Germany: adds around five per cent (600 boepd) to German production portfolio, building on project development in North-West Germany.

Strong project development, with ~100 kboepd of new production coming onstream between 2019 and 2021

-      Touat gas development, in Algeria, due onstream imminently: commissioning complete and ready to commence gas exports. Will contribute around 16 kboepd net production at plateau.

-      Operated Seagull oil development sanctioned and EPCI contract awarded: offshore construction campaign scheduled to start in Q2 2020. On track for first oil in 2021, adding 17 kboepd net production.

-      Operated Duva and Gjøa P1 project sanctioned and approved by Norwegian authorities: EPCIC contract awarded and drilling campaign expected to commence at the end of 2019. On track for first production in 2021, adding around 16 kboepd net production.

Robust financial and operating performance, with near record production expected by year end

-      Full year production weighted towards H2: expect near record production in December as a result of Touat plateau. Full year production guidance of 150-155 kboepd.

-      Strong cash flow of $613 million despite lower commodity prices, which were offset partially by our active hedging programme. Hedged approximately 64 per cent of gas volumes and 53 per cent of oil volumes for remainder of 2019.

-      H1 2019 opex down ~5 per cent on H1 2018: full year opex guidance of $10-11/boe. Cost efficiency programmes in place across the Group.

FINANCIAL SUMMARY

Neptune Energy   Q2 2019  Q1 2019                          H1 2019  H1 2018 (note a) 
  3 months to 30 June 2019  3 months to 31 March 2019  6 months to 30 June 2019  15 Feb - 30 June 2018 
Total daily production (kboepd)  145.6  151.8  148.5  165.6 
Average realised oil price ($/bbl) (note b)  65.9  58.5  62.7  69.8 
Average realised gas price ($/mcf) (note b)  4.4  6.5  5.5  7.9 
EBITDAX ($m)  428.7  451.3  880.0  767.2 
Operating costs ($/boe)  10.8  10.1  10.3  10.9 
Operating cash flow ($m)  250.7  362.3  613.0  585.1 

a) Results for 2018 reflect the acquired EPI business from 15 February to 30 June 2018. The unaudited results for the period ended 30 June 2018 as previously disclosed have been revised as they were based on provisional assigned fair values of the acquisition of the EPI business on 15 February 2018.

b) Average realised prices are stated before the impact of hedging.

Sam Laidlaw, Executive Chairman"

Neptune made important strategic progress in the first half of 2019, significantly strengthening our Asian gas position, which will deliver medium-term production and long-term growth opportunities. We also sanctioned key projects in Norway and the UK and increased our footprint in Germany, all of which improves our production profile in the medium term while also delivering short-term value.

"Despite lower commodity prices in the period, we have delivered strong cash flow and maintained a robust balance sheet, which provides us with ample headroom to continue to build a resilient business for the long term, both organically and through acquisition."

Jim House, Chief Executive Officer"

Neptune's production profile for 2019 will be weighted towards the second half, with our Touat gas development in Algeria reaching plateau and additional production from three infill wells at Fram, in Norway. As a result, we expect to end the year with near record volumes.

"Our key projects in Norway and the UK all remain on track and will add significant incremental production from 2021. Our exploration programme continues to grow, with new acreage and opportunities added in Norway, Indonesia, Germany, the Netherlands and Egypt."

We delivered a robust operational performance in the first six months of the year, with stable production across much of the portfolio. We have also maintained high safety levels and high production efficiency, while continuing to reduce costs."

GROUP OVERVIEW

Neptune Energy made significant strategic progress during the first half of 2019 with our agreement of value-accretive acquisitions, awards of key exploration licences, sanctioning of significant projects in Norway and the UK, and commissioning of our Touat gas development in Algeria. Together, these will deliver long-life and low-cost production, while increasing our reserves.

Our agreement to acquire PSC interests in the prolific Kutei Basin, along with organic growth in North Africa, result in a more geographically balanced portfolio that provides greater exposure to different markets and commodity prices.

The development of Merakes and the recent Merakes East discovery offer additional reserves and contingent resources to be developed in the near term, and the East and West Ganal PSCs provide longer-term, world-class exploration opportunities. All will be important factors in delivering growing production from the mid-2020s.

We also made good operational progress in the first half of the year, with production efficiency stable at high levels across our operated asset base, while maintaining cost discipline. Progress continues apace with our projects, with each of them remaining on track and on budget.

Health, safety, security and the environment (HSSE) remains our highest priority and we maintained our encouraging performance through the second quarter, with both our key metrics, Lost Time Injury Frequency (LTIF) rate and Total Recordable Incident Rate (TRIR), stable in comparison with the first quarter. We have renewed our focus on process safety, investing to increase awareness and reduce risk.

In the second quarter of 2019, we produced 145.6 kboepd. This reflected unexpected production deferrals in the Netherlands, offset partially by stable production across the rest of the portfolio and by our Norwegian portfolio producing above expectations. Across our operated assets, production efficiency was 88 per cent. This remains an important area of focus for us as we aim to maximise recovery from existing assets, realising incremental production at low cost.

Commissioning of the Touat gas development in Algeria is now complete and gas export is expected imminently, with a short ramp-up to plateau. Coupled with the incremental production from infill well drilling at Fram, we expect to produce 150-155 kboepd for the full year, with near record volumes in December.

Operating costs for the quarter remained within our expected range at $10.8/boe, reflecting tight cost control across the Group. For the first half of the year, we have produced more than 60 per cent of the Group's volumes at $7.1/boe or lower and we have efficiency programmes in place across our European operations as we keep a tight focus on cost. These programmes will be supplemented by savings from our ongoing focus on G&A costs across the Company, including reductions in the Netherlands and Germany, along with the proposed closure of the Paris office. This will result in some short-term restructuring costs but will significantly improve our operating efficiency.

During the second quarter, our average realised commodity prices, excluding the impact of hedging, were $65.9/boe for oil and $4.4/mcf for gas, reflecting lower commodity prices during the period. Our active hedging programme continues to provide some protection from lower prices and we currently have hedges in place for 53 per cent of our crude oil sales and 64 per cent of our dry gas for the remainder of 2019.

Solid operating cash flows of $251 million enabled us to invest $196 million in our projects in the second quarter, largely at Njord, Fenja and Jangkrik.

Net debt ended the period broadly unchanged from the previous quarter at $1,435 million, resulting in a net debt to EBITDA ratio of 0.75 times and 0.72 times on an EBITDAX basis, both well within desired levels. At the end of the period, we had $1,177 million of available headroom on our RBL, which, when combined with our cash position, provides liquidity of more than $1.3 billion, giving us sufficient headroom to pursue value-accretive growth opportunities.

We continue to make good progress with our development projects. At the beginning of the year, together with our partners, we sanctioned our operated developments at Duva/Gjøa P1 in Norway and Seagull in the UK and have now awarded the EPCI contracts for both. Project development of Njord, Fenja, Bauge, Snøhvit Nord and Askeladd also continues on track.

In July, our Q13a platform, in the Netherlands, was selected by Nexstep, the Dutch Association for Decommissioning and Re-Use, and TNO, the Dutch applied research and innovation organisation, to participate in a pioneering pilot project to create the first offshore hydrogen plant for power generation in the Dutch sector of the North Sea. The pilot will provide experience of producing hydrogen offshore, creating a testing ground for innovative technologies and integrated energy systems.

Our exploration programme continues on track. We have now completed well pad construction at our Schwegenheim prospect and we expect to commence well operations in the third quarter. We will spud our Isabella prospect in the UK during the fourth quarter and plan to drill the Sigrun East and Echino South wells in Norway before the end of the year. In early 2020, we will commence our exploration programme in Indonesia.

In July we continued to build capability and further strengthened our management team with the appointment of Ben Walker, who has previous IPO experience, as General Counsel.

Outlook

With additional volumes from the Touat gas development in Algeria and the Fram infill programme in Norway coming onstream in the second half of the year, we expect full year 2019 production of 150-155 kboepd.

We expect opex to be within our previously guided range of $10-11/boe. Full year 2019 capex is unchanged from previous guidance and is expected to be in the region of $700 million, before the impact of M&A activities. Project costs for 2019 are weighted to the second half, with some re-phasing from the first half.

OPERATING REVIEW

Health, safety, security and the environment

Our HSSE performance was stable and well below our targets for 2019 across all our countries in the second quarter of the year, resulting in an overall improvement on a half-yearly basis. There were no serious personal injuries and our LTIF rate was stable at 0.59 per million hours worked, versus 0.54 when compared with the first quarter of 2019. Our TRIR was stable at 2.08 per million hours worked versus 1.94 during the first quarter of 2019. These figures include cooperated joint venture activities.

At the start of 2019, we introduced a three-tiered Process Safety Event Rate (PSER) KPI to increase visibility and improve our organisational learning with regards to typically low-probability, but high-consequence, process safety events. The PSER for the first half year was 1.60 per million man hours, which is below our target of 5.0.

Production

Neptune Energy  Q2 2019  Q1 2019       H1 2019  H1 2018 (note a) 
  3 months to 30 June 2019  3 months to 31 March 2019  6 months to 30 June 2019  15 Feb - 30 June 2018 
Total production (mmboe)  13.3  13.7  26.9  22.5 
Dry gas production (kboepd)  74.6  79.0  76.7  87.4 
Gas production for sale as LNG (kboepd)  29.1  29.1  29.0  33.5 
Liquid production (kbpd)  41.9  43.7  42.8  44.7 
Total production (kboepd)  145.6  151.8  148.5  165.6 

a)    Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 June 2018.

Norway

Production

Neptune Energy - Norway  Q2 2019  Q1 2019       H1 2019  H1 2018 (note a) 
  3 months to
30 June 2019 
3 months to
31 March 2019 
6 months to
30 June 2019 
15 Feb - 30 June 2018 
Gas production (kboepd)  26.2  26.9  26.5  29.8 
Gas production for sale as LNG (kboepd)  13.5  12.5  13.0  13.6 
Liquid production (kbpd)  32.8  32.8  32.8  33.8 
Total production (kboepd)  72.5  72.2  72.3  77.2 

a)    Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 June 2018.

In Norway, production in the second quarter was marginally higher at 72.5 kboepd, reflecting a strong operational performance across the entire portfolio and improved production efficiency.

Operating costs for the quarter were $6.2/boe, down slightly from the first quarter. This was due to tight cost control, increased production and favourable foreign exchange movements. The business improvement programme we introduced in early 2019 is already having an impact, with production optimisation programmes already in place.   

Development and exploration

We continue to make good progress at our operated Duva/Gjøa P1 project. In April, we announced the contract award to Rosenberg Worley for modifications on the Gjøa semi-submersible platform and in June the Norwegian authorities approved development plans for Duva/Gjøa P1. The project remains on plan.

We are also making progress with our operated Fenja project. Fabrication of all subsea umbilicals, risers and flowlines for 2019 installation are complete and we expect to commence drilling early in 2020. First production remains on track for early 2021. The Njord project also remains on track.

The non-operated exploration wells, Sigrun East and Echino South, will be drilled later this year. We expect to drill operated wells targeting the Grind and Dugong prospects in 2020.

Netherlands

Production

Neptune Energy - Netherlands  Q2 2019  Q1 2019       H1 2019  H1 2018 (note a) 
  3 months to 30 June 2019  3 months to 31 March 2019  6 months to 30 June 2019  15 Feb - 30 June 2018 
Gas production (kboepd)  19.2  23.0  21.1  27.3 
Liquid production (kbpd)  1.0  2.7  1.8  2.8 
Total production (kboepd)  20.2  25.7  22.9  30.1 

a)    Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 June 2018.

We produced 20.2 kboepd in the Netherlands in the second quarter. This was lower than the prior period, largely as a result of unplanned shutdowns of L5a-D and Q13a, which resulted in lower production efficiency. In order to maximise production availability in the second half, we brought forward the planned maintenance programme for Q13 to coincide with the outage and are actively progressing production optimisation opportunities across the portfolio. The Q13a platform came back online in early August and operations to restart volumes through L5a-D have commenced.

Operating costs for the quarter were $16.5/boe, principally reflecting lower production. We are progressing on track with our plan to reduce G&A costs at out Dutch head office as we target recurring cost savings of $5 million per annum.

Development

The F17a oil development is on schedule with the FEED study awarded at the start of the year and final investment decision expected in November 2019. Drilling on E17a-A6 is progressing and we expect to achieve production in the third quarter, earlier than planned. We remain on schedule with drilling on L5-D4, which began in May.

The first production well at the D12-B Sillimanite development will be drilled in the second half of the year.

We have been preliminarily awarded the F5 exploration licence and are actively applying for new exploration opportunities in the region.

Decommissioning of L10-C, D and G is progressing in line with expectations, with heavy lift removal scheduled to start early in the fourth quarter of the year.

UK

Production

Neptune Energy - UK  Q2 2019  Q1 2019       H1 2019  H1 2018 (note a) 
  3 months to 30 June 2019  3 months to 31 March 2019  6 months to 30 June 2019  15 Feb - 30 June 2018 
Gas production (kboepd)  16.4  16.3  16.3  20.3 
Liquid production (kbpd)  0.4  0.4  0.4  0.3 
Total production (kboepd)  16.8  16.7  16.7  20.6 

a)    Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 June 2018.

Production from the UK during the second quarter of 2019 averaged 16.8 kboepd, marginally higher than the prior period. We continued to see a strong performance on Cygnus, with high levels of production efficiency throughout the period. Opex was $8.0/boe for the quarter.

While Cygnus continues to be constrained by the downstream third-party Trent platform, we achieved higher production in May as Trent was offline for a period of time. This created additional capacity allowing Cygnus to produce at record levels of more than 320 mmcf/d gross for 15 days in May.

As we look to unlock further value from Cygnus, we are continuing discussions with the Government and other stakeholders to allow Cygnus gas to enter the National Transmission System without the need for blending.

Through our focus on business improvement, we have identified cost savings of more than $3 million in 2019.

Development and exploration

Our operated Seagull oil development was sanctioned at the start of the year and is progressing on plan, with the EPCI contract awarded in July.

In June, we brought online the Cygnus A5 production well, which is producing at around 50 mmscfd gross. It is the ninth of 10 wells planned as part of the Cygnus development plan.

We participated in the Darach Central-1 well in the second quarter and remain on track to spud Isabella in the fourth quarter.

We continue to make good progress with decommissioning of the Minke and Juliet platforms.

Germany

Production

Neptune Energy - Germany  Q2 2019  Q1 2019       H1 2019  H1 2018 (note a) 
  3 months to 30 June 2019  3 months to 31 March 2019  6 months to 30 June 2019  15 Feb - 30 June 2018 
Gas production (kboepd)  6.9  7.3  7.1  7.2 
Liquid production (kbpd)  5.6  5.5  5.6  5.8 
Total production (kboepd)  12.5  12.8  12.7  13.0 

a)         Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 June 2018.

Production from Germany for the quarter was broadly flat at 12.5 kboepd, reflecting increased uptime at Schneeren/Husum, offset by a slight delay in production from the Rӧmerberg 8 well.

For the second quarter, operating costs, excluding royalties, declined to $21.4/boe. We continue to drive our cost base lower and remain on track to deliver a 10 per cent reduction in opex (excluding royalties) by the end of the year.

We are making good progress delivering on our business improvement plan. We are seeking additional efficiency savings in G&A and expect to realise annualised savings of $5 million from next year.

Development and exploration

In July we signed an agreement to acquire interests in a number of oil and gas fields in Emsland and the Grafschaft Bentheim region in Germany from Wintershall Dea. The agreement will increase Neptune's existing interest in the Bramberge, Meppen and Annaveen oilfields, located in the Emsland region and in various gas fields in the Grafschaft Bentheim region, adding approximately 600 boepd to our German production.

We have completed the construction of the well pad at Schwegenheim and will spud the exploration well in September. The Adorf Z15 well will commence in the fourth quarter, following completion of Schwegenheim.

In August we were awarded the Leda exploration licence in Northwest Germany.

North Africa

Production

Neptune Energy - North Africa  Q2 2019  Q1 2019       H1 2019  H1 2018 (note a) 
  3 months to 30 June 2019  3 months to 31 March 2019  6 months to 30 June 2019  15 Feb - 30 June 2018 
Gas production (kboepd)  2.9  2.8  2.9  2.8 
Liquid production (kbpd)  1.5  1.6  1.6  1.2 
Total production (kboepd)  4.4  4.4  4.5  4.0 

a)    Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 June 2018.

In Egypt, production was flat at 4.4 kboepd for the quarter following a successful workover campaign at Ashrafi and the infill activity at Alam El Shawish West. Operating costs were in line with the previous quarter at $9.3/boe. Drilling at the Karam 10 development well in Egypt, which began earlier in the year, is currently being completed.

At Touat in Algeria, first export gas is slightly later than expected, reflecting delays with the export pipeline. The processing plant is now fully operational and we expect first gas export production to commence imminently and ramp up to plateau quickly.

Development and exploration

With the gas processing facilities now complete at Touat, we have begun initial work on phase two, which involves the development of eight fields and will help to maintain gross production plateau at 450 mmscf/d for longer.

Asia Pacific

Production

Neptune Energy - Asia Pacific  Q2 2019  Q1 2019       H1 2019  H1 2018 (note a) 
  3 months to
30 June 2019 
3 months to
31 March 2019 
6 months to
 30 June 2019 
15 Feb - 30 June 2018 
Gas production (kboepd)  3.0  2.7  2.8  0.0 
Gas production for sale as LNG (kboepd)  15.6  16.6  16.0  19.9 
Liquid production (kbpd)  0.6  0.7  0.6  0.8 
Total production (kboepd)  19.2  20.0  19.4  20.7 

a)    Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 June 2018.

We produced 19.2 kboepd in Indonesia in the second quarter, reflecting Jangkrik coming off initial plateau and curtailment at the end of the period due to high inventory at Bontang, which reflected weaker Asian gas markets. We expect restrictions to ease as storage levels normalise.

The planned field shut down of Jangkrik in July and August (for the Merakes tie in and debottlenecking project) has been postponed to 2020. We also expect to increase production following the workover at JKK-5 and the infill wells JKK-12 and JNE-9, with the latter nearing completion. In the second quarter, additional pipeline gas sales were made to the domestic market.

Operating costs were $14.5/boe due to production curtailment on the field and higher levels of C3 and C4 needed to meet required specification levels for LNG export. We expect these volumes and associated costs to reduce once the second pipeline tie-in project, scheduled for the fourth quarter, is completed. The booster compression project is expected to be delivered in 2021.  

Development and exploration

In July we signed an agreement to acquire PSC interests in the Kutei Basin, offshore Indonesia. The agreement will see us acquiring a 20 per cent working interest in the East Sepinggan PSC and a 30 per cent working interest in the East Ganal PSC. We expect to complete the transaction in the fourth quarter.

The East Sepinggan PSC offers the fast-tracked, low-cost Merakes development and is expected to be cash flow positive shortly after start-up. Merakes is being developed as a subsea tie-back to Jangkrik, with first gas due by the end of 2020. The development will provide a natural diversification to Jangkrik.

Additionally, the recent discovery of Merakes East, located adjacent to Merakes, contributes additional contingent resources to be developed in the near term. The East Ganal PSC provides longer-term value potential through exploration.

In August, together with our partners, Eni and  Pertamina, we were awarded the West Ganal PSC. The block covers an area of 1,129 km2 and is also located in the Kutei Basin. The consortium has committed to drilling four exploration wells in the first exploration period.

Drilling on the high impact Geng North exploration well on North Ganal PSC is now scheduled by the operator for the second half of 2020.

In Australia, as operator of the Petrel licences, we are planning additional seismic with our partners for later this year and have commenced studies for the development of the field.

Summary of production by area

  Q2 2019  Q1 2019  H1 2019    H1 2018  (note 1) 
Gas production (kboepd)         
Norway  26.2   26.9  26.5  29.8 
UK  16.4   16.3  16.3  20.3 
The Netherlands  19.2   23.0  21.1  27.3 
Germany  6.9   7.3  7.1  7.2 
North Africa  2.9   2.8  2.9  2.8 
Asia Pacific  3.0  2.7  2.8 
Total Gas production (kboepd)  74.6   79.0  76.7  87.4 
Gas production for sale as LNG (kboepd)         
Norway  13.5   12.5  13.0  13.6 
Asia Pacific  15.6   16.6  16.0  19.9 
Total Gas production for sale as LNG (kboepd)  29.1   29.1  29.0  33.5 
Liquid production (kbpd) (note 2)         
Norway  32.8   32.8  32.8  33.8 
UK  0.4   0.4  0.4  0.3 
The Netherlands  1.0   2.7  1.8  2.8 
Germany  5.6   5.5  5.6  5.8 
   North Africa  1.5   1.6  1.6  1.2 
Asia Pacific  0.6  0.7  0.6  0.8 
Total Liquid production (kbpd)  41.9   43.7  42.8  44.7 
Total production (kboepd)         
Norway  72.5   72.2  72.3  77.2 
UK  16.8   16.7  16.7  20.6 
The Netherlands  20.2   25.7  22.9  30.1 
Germany  12.5   12.8  12.7  13.0 
North Africa  4.4   4.4  4.5  4.0 
Asia Pacific  19.2  20.0                          19.4  20.7 
Total production (kboepd)  145.6  151.8  148.5  165.6 
           

1)      Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 June 2018.

2)      Liquid includes oil and condensate and other natural gas liquids.

Financial review

This report includes the results of the acquisition of ENGIE E&P International S.A. ('EPI') since 15 February 2018 as that is when Neptune acquired control over EPI. EPI was the holding company for the worldwide exploration and production business of  ENGIE

Neptune has received the economic benefits of cash flows relating to the EPI business since that date so comparative data for the corresponding reporting period ended 30 June 2018 therefore includes only results contribution from the EPI business from 15 February to 30 June 2018.

In accordance with IFRS standards for accounting for business combinations, we have recorded the acquired assets and liabilities of EPI as at the acquisition date at their fair values, or otherwise as required by IFRS. Oil and gas assets acquired were recorded at the net present value of expected future cash flows, post-tax, based on independent reserves reports, management plans and expectations and using projections of oil and gas prices based on a combination of forward prices and long-term Company assumptions. Liabilities were established in respect of decommissioning costs, post-employment benefits and deferred taxes. The assigned fair values for the EPI business are now final.

The unaudited results for the period ended 30 June 2018 as previously disclosed have been revised as they were based on provisional assigned fair values of the acquisition of the EPI business on 15 February 2018. On conclusion of the business combination accounting for the audited results for the year ended 31 December 2018 the associated judgements and fair values were subsequently concluded.  Consequently, to ensure a more appropriate comparison, the 30 June 2018 comparative financial results (which consolidate the acquired EPI business from 15 February) and associated metrics incorporate this concluded position. The revisions to these unaudited financial statements and metrics do not constitute a restatement of the financial results as International Financial Reporting Standards allow a period of up to 12 months beyond the acquisition date of business combinations to finalise the associated judgements and assigned fair values.

The acquisition of 100 per cent of the share capital of VNG Norge, for cash consideration, was completed on 28 September 2018 and the results of VNG Norge were consolidated from the start of the fourth quarter 2018.The business combination accounting of EPI resulted in the recognition of $627.0 million of goodwill and the acquisition of VNG Norge on 28 September 2018 resulted in the recognition of goodwill of $80.7 million. In each case, the goodwill arises largely as a result of the requirement to recognise deferred tax liabilities in respect of temporary differences between the fair value of oil and gas assets recorded in PP&E and their tax base available as future tax deductions.

Results of operations

$ millions   6 months ended June 2019  6 months ended June 2018 (note a) 
Revenues  1,237.6  1,066.4 
Operating profit (note d)  523.1  458.4 
Profit before tax  384.7  336.0 
Net profit  115.5  15.0 
EBITDAX (note b)  880.0  767.2 
EBITDA (note c)  861.1  744.3 
Net profit before acquisition-related expenses (note e)  115.5  75.4 
Cash flow from operations, after tax before acquisition related expenses (note e)  613.0  645.5 
Adjusted development cash capital expenditure (note f)  383.1  166.6 
Net debt (book value)  1,434.8  969.1 

a)           Results for this period consolidate the acquired EPI business for the post acquisition period only, from 15 February 2018 to 30 June 2018.

b)          EBITDAX comprises net income for the period before income tax expense, financial expenses, financial income, non-recurring acquisition-related expenses, mark-to-market adjustments on commodity contracts, exploration expense and depreciation and amortisation.

c)           EBITDA comprises net income for the period before income tax expense, financial expenses, financial income, non-recurring acquisition-related expenses, mark-to-market adjustments on commodity contracts and depreciation and amortisation.

d)          Operating profit comprises current operating income after share in net income of entities accounted for using the equity method and is stated before tax, finance costs, mark- to-market on commodity contracts and non-recurring items.

e)           Adjusted for acquisition-related expenses and taxes of $60.4 million in 2018 incurred in connection with the EPI acquisition.

f)           Includes expenditure of $31 million for period to 30 June 2019 and $27 million for period from 15 February to 31 March 2018 in respect of the Touat project, held by a joint venture company which Neptune accounts for under the equity method.

Total sales for the six months ended 30 June 2019 were $1,237.6 million, reflecting total production of 26.9 mmboe and realised prices, before and after hedging, as shown in the table below. The Brent crude price averaged $66.2 per barrel for the six months ended 30 June 2019 and our average realised oil price was $65.9 per barrel for the period. The LNG sales prices are linked to a combination of movements in oil and gas market prices, depending on the contract.

Realised prices data:

Neptune Energy   Q2 2019  Q1 2019  6 months ended 30 June 2019  15 February to  
31 December 2018 (note a) 
Excluding impact of hedging:         
Average realised gas price ($/mcf)  4.4  6.5  5.5  7.9 
Average realised LNG price ($/mcf)  8.1  9.0  8.6  8.2 
Average realised oil price ($/bbl)  65.9  58.5  62.7  69.6 
Average realised price, other liquids ($/bbl) (note b)  39.1  42.2  40.8  58.3 
Including impact of hedging:         
Average realised gas price ($/mcf)  5.0  6.5  5.8  6.9 
Average realised LNG price ($/mcf)  8.1  9.0  8.6  8.2 
Average realised oil price ($/bbl)  64.6  57.8  61.6  67.5 
Average realised price, other liquids ($/bbl) (note b)  39.1  42.2  40.8  58.3 

a)                    Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 31 December 2018

b)                    Other liquids includes condensate and other natural gas liquids

Operating costs were $277.4 million for the six months to 30 June 2019 and our average operating cost per boe produced was $10.3/boe. This compares with average operating cost per boe of $10.2/boe for 2018 full year. Operating costs for the purpose of per boe expense are reduced by $33.8 million (2018 full year: $24.7 million reduction) for the six months ended 30 June 2019 to exclude changes in the value of under-lifted entitlement to production and to net-off income from tariffs and services which serve to recover costs. 

Depreciation and amortisation expense of $338.0 million reflects an uplift in asset carrying values as a result of fair valuation of assets required for purchase accounting for the EPI and VNG business combination in 2018. The charge represents $12.6/boe produced compared to $12.7/boe for the period 15 February to 30 June 2018.

Exploration expense of $18.9 million reflects costs incurred on G&G activities to scrutinise future strategic growth opportunities.

General and administration expense of $43.2 million for the period to 30 June 2019 consists primarily of costs that are not directly incurred for production or capital projects (including exploration), such as staff employment costs related to corporate functions and selling expenses, office costs and fees for services provided to us and is at an equivalent run-rate to the period 15 February to 30 June 2018.

Share in net income of entities accounted for under the equity method represents tariff income of one of our Dutch pipeline interests and the Touat joint venture.

The Group's operating profit for period to 30 June 2019 was $523.1 million before net finance costs and the impact of one-off group reorganisation costs of $47.9 million. EBITDAX for the same period was $880.0 million, compared with $767.2 million for the period 15 February to 30 June 2018. The increase in EBITDAX principally reflects the effect of consolidating a full half year result from the EPI acquisition offset in part by lower realised commodity prices in the period.

In the prior period, other operating expenses includes non-recurring acquisition-related expenses of $60.4 million, reflecting the requirement to charge business combination transaction expenses and related costs (such as taxes levied in respect of share transfers and change of control) to net income. In addition, 2019 includes $4.8 million in relation to an impairment of the Orca licence asset. In 2018 no impairment expense was required.

Net financing expenses were $103.3 million for the period and include $64.5 million of interest expense (cash impact $52.2 million) and unwinding of discount on abandonment provisions of $18.9 million.

The tax charge for the quarter represents 70 per cent of pre-tax income which includes restructuring costs of approximately $47.9 million on which limited tax relief is presently assumed. Adjusting for these costs, the effective tax rate would be 62 per cent of pre-tax income.

Net income for the period ended 30 June 2019 was $115.5 million on a reported basis.

Hedging

Group policy is to seek to reduce risk related to commodity price fluctuations by using hedging instruments to set a floor for the sales realisations for a proportion of forecast revenues on a rolling basis, with reducing levels of hedging for each of the next three years. The Group actively manages this hedging programme using a mix of swaps, forwards and options, including as option collar structures.

At acquisition of EPI in 2018, we inherited a substantial hedge book which was novated from the ENGIE group to Neptune's bank group. As at the acquisition date, the net fair value (mark-to-market) of this hedge book was a net liability of $53.8 million, which is reflected in the acquisition balance sheet. The liability reflected generally rising commodity prices since the hedges were put in place in prior years.

We have continued to hedge a proportion of revenues for future periods since closing the EPI acquisition, mostly using option collars. As at 30 June 2019, the approximate share of tax-effected production hedged for future periods was as shown in the table below. For oil, weighted average downside protection was $61/barrel for the remainder of 2019 and $62/barrel for 2020, with upside capped at around $75/barrel in 2019 and $77/barrel in 2020 for those hedged volumes.

For gas, hedging provided weighted average floor prices of $5.7/mmbtu for 2019, $6.0/mmbtu for 2020 and $6.0/mmbtu for 2021 with upside caps at $7.1/mmbtu, $7.8/mmbtu and $7.6/mmbtu, respectively.

Aggregate post-tax hedge ratio:

  2019  2020  2021 
Oil  53%  24%  0% 
Gas  64%  59%  46% 
Total  59%  44%  25% 

1)      Oil price hedges include hedges of realisations for gas production sold as LNG and priced in relation to oil prices.

2)      Post--tax hedge ratios adjust for different tax rates on physical sales and hedge gains and losses, which mean that effective post-tax hedges can be achieved through hedging contracts for volumes which may be significantly less than anticipated sales.

The estimated net fair value (comprised of current and non-current assets and liabilities) on a mark-to-market basis of all our commodity derivative instruments at 30 June 2019, was an asset of $75.8 million, before tax, of which $31.3 million relates to contracts expiring in 2019.

Cash flow

Operating cash flow, after cash taxes, for the period to 30 June 2019 was $613.0 million.

Cash taxes were $189.8 million and largely relate to Norwegian taxes. The effective rate of cash tax as a percentage of pre-tax operating cash flow was 24 per cent.

Capital expenditure

Cash capital expenditure for the period to 30 June 2019, was $352.1 million, including $17.3 million of capitalised exploration expenditure. This figure is significantly higher than the corresponding period last year as a result of expenditure on new development projects, primarily Njord, Duva, P1 and Fenja. This excludes expenditure at the Touat project, where the joint venture is accounted for under the equity method of accounting as a joint venture. Our statement of cash flows reflects investment at Touat in terms of the cash injections made to fund the joint venture company, which were $32.0 million in the period.

$ millions   6 months ended
30 June 2019 
6 months ended
30 June 2018 (note a) 
 
 
Investing cash flows:       
Development capex  334.8  128.9   
Exploration capex  17.3  10.7   
Acquisitions  3,205.2   
Total cash capital expenditure  352.1  3,344.8   

a)      Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 June 2018.

Total exploration expenditure comprised the $17.3 million cash capex and $18.2 million expensed in respect of G&G costs.

Development cash capex was $334.8 million. The majority of spend was in Norway on the Duva/Gjøa P1 and Fenja project as well as progressing projects in UK and Indonesia. This compares to capital expenditure for the six months ended 30 June 2018 of $128.9 million.

We incurred $23.2 million on decommissioning expenditure in the period to 30 June 2019, this was principally in the UK in relation to our equity share in our non-operated CMS assets and other legacy non-operated fields.

Acquisitions

There were no acquisitions in the six months ended 30 June 2019. In the six months ended 30 June 2018, the expenditure on acquisitions totalling $3,205.2 million relates to the EPI acquisition, including adjustment payments and receipts under the sale and purchase agreement (SPA) which arose subsequent to closing and associated acquisition costs of $60.4 million.

Financing and liquidity

Management's financial strategy is to manage Neptune's capital structure with the aim that, across the business cycle, net debt to EBITDA remains modest. Given the solid operational performance and rising commodity prices during 2Q19, we ended the quarter with a ratio of 0.75 times. This is compared to an EBITDAX ratio of 0.72.

We funded our business mainly with cash generated from operations and via drawdowns under the RBL. At 30 June 2019, we had the following debt outstanding:

·      $750 million drawn under a $2 billion, committed Reserve Base Lending (RBL) facility, which matures in 2024;

·      $550 million of senior notes, paying a 6.625% coupon, maturing in 2025;

·      $111 million Vendor Loan Note from ENGIE, maturing 2024; and

·      $233 million project finance facility for Touat, which is repayable from net revenues of the project.

At 30 June 2019, our cash balance totalled $146.6 million and our available and undrawn headroom under the RBL was $1,177 million. We also had $86 million of letters of credit outstanding, of which $73 million was drawn down under an ancillary facility under the RBL. Our weighted average cost of borrowing for the Group was 5.8 per cent.

In 2018, Neptune was attributed an inaugural credit rating of Ba3 by Moody's and BB- by Standard & Poor's. In 2019 the outlook for the two existing ratings were changed to positive and an inaugural BB rating was assigned from Fitch. We will continue to seek to consolidate and strengthen these ratings over time.

All debt, with the exception of the RBL, is carrying a fixed interest rate. However, we swapped a sizeable amount of the RBL into fixed rate debt, taking advantage of historically low interest rates available in the market earlier in 2018. As a result, 79 per cent of the debt portfolio at 30 June 2019 was fixed rate, which reduces Neptune exposure to increases in the USD Libor interest rate.

Financial condition

Operating cash flows of $613.0 million more than covered investing cash flows of $371.3 million and after financing costs and net debt repayment of $292.0 million resulted in a net cash outflow of $50.3 million for the period to 30 June 2019. We ended the period with gross interest-bearing debt of $1,581.4 million (book value) and net debt of $1,434.8 million. This represents a ratio of 0.72 times EBITDAX for the twelve months ended 30 June 2019 and leverage (net debt to total capital) was 43 per cent as at 30 June 2019.

Outlook

Our production guidance for the full year is revised to 150-155 kboepd due to the delayed start of Touat. Higher production is expected for the second half of the year due to Touat coming into production and the impact of three infill wells being drilled at Fram.

The full year 2019 capex is unchanged from previous guidance and is expected to be in the region of $700 million, before the impact of M&A activities.

We expect operating cost per boe to remain broadly in line with 2018, $10-11/boe.

Risks and Uncertainties

Investment in Neptune involves risks and uncertainties, these are summarised in detail in the Neptune Energy 2018 Annual Report and Accounts page 10.

As an oil and gas, exploration and production company, exploration results, reserve and resource estimates and estimates for capital and operating expenditures involve inherent uncertainties. A field's production performance may be uncertain over time. The Group is exposed to various forms of financial risks, including, but not limited to, fluctuation in oil and gas prices, currency exchange rates, interest rates and capital requirements. The Group is also exposed to uncertainties relating to political risks, the international capital markets and access to capital and this may influence the speed with which growth can be accomplished.

NEPTUNE ENERGY GROUP MIDCO LIMITED

UNAUDITED CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

For the six months ended 30 June 2019

Unaudited Condensed Consolidated Statement of Profit and Loss

In millions of US$  Notes  Six months ended 30 June 2019  Six months ended 30 June 2018   
 
 
Revenue  1,237.6  1,066.4   
Cost of sales     (650.7)  (560.8)   
GROSS PROFIT    586.9  505.6   
Exploration expenses    (18.9)  (23.0)   
General and administration expenses    (43.2)  (31.8)   
Share of net income from investments using equity method    (1.7)  7.6   
OPERATING PROFIT AFTER EQUITY ACCOUNTED INVESTMENTS  523.1  458.4   
Other operating gains/(losses)   5  (35.1)  (77.7)   
OPERATING PROFIT BEFORE FINANCIAL ITEMS    488.0  380.7   
Finance costs    (108.6)  (46.9)   
Finance income    5.3  2.2   
PROFIT BEFORE TAX    384.7  336.0   
Taxation  (269.2)  (321.0)   
NET PROFIT    115.5  15.0   

All profits and losses arise as a result of continuing operations.

Unaudited Condensed Consolidated Statement of Other Comprehensive Income

In millions of US$  Notes  Six months ended 30 June 2019  Six months ended 30 June 2018   
 
 
Profit for the Period    115.5  15.0   
Other comprehensive Income:         
Items that may be reclassified to the Profit and Loss         
Hedge adjustments net of tax (note 1)  12   53.8  (106.1)   
Foreign currency translation    22.7  (38.4)   
Other comprehensive income/(expense)    76.5  (144.5)   
Total comprehensive profit/(loss) for the period, net of tax    192.0  (129.5)   

1)        Income tax related to hedge adjustments is $15.7 million charge (2018: $69.2 million income).

Unaudited Condensed Consolidated Statement of Financial Position - Group

In millions of US$  Notes  30 June 2019  31 December 2018   
 
NON-CURRENT ASSETS         
Goodwill    657.3  646.8   
Intangible assets  111.2  112.5   
Property, plant and equipment  4,021.6  3,922.2   
Derivative instruments  12  66.1  40.1   
Investments in entities accounted for using the equity method    567.4  540.9   
Other non-current assets    125.9  8.8   
Equity instruments  12   19.6  19.7   
Deferred tax assets    461.5  438.6   
TOTAL NON-CURRENT ASSETS    6,030.6  5,729.6   
CURRENT ASSETS         
Derivative instruments  12  76.0  33.2   
Trade and other receivables    631.8  642.6   
Inventories    61.5  64.3   
Cash and cash equivalents  146.6  197.3   
Tax receivable    25.1  83.7   
TOTAL CURRENT ASSETS    941.0  1,021.1   
TOTAL ASSETS    6,971.6  6,750.7   
Share capital  13  1,977.2  1,977.2   
Hedging reserve    28.7  (25.1)   
Foreign currency translation    (120.1)  (142.8)   
Retained deficit    (6.9)  (122.4)   
TOTAL EQUITY    1,878.9  1,686.9   
NON-CURRENT LIABILITIES         
Provisions  11  1,681.4  1,675.2   
Long-term borrowings  12  1,581.4  1,788.2   
Derivative instruments  12  44.5  31.1   
Income tax payable    46.5  35.7   
Other non-current liabilities              10  163.7  59.6   
Deferred tax liabilities    662.4  582.2   
TOTAL NON-CURRENT LIABILITIES    4,179.9  4,172.0   
CURRENT LIABILITIES         
Provisions  11  114.2  69.3   
Derivative instruments  12  26.0  73.6   
Trade and other payables  10  238.1  94.5   
Income tax payable    249.8  188.1   
Other current liabilities  10  284.7  466.3   
TOTAL CURRENT LIABILITIES    912.8  891.8   
TOTAL EQUITY AND LIABILITIES    6,971.6  6,750.7   

Unaudited Condensed Consolidated Statement of Changes in Equity

In millions of US$  Share Capital  Hedging reserve  Foreign currency translation  Retained Surplus/(Deficit)  Total 
As at 1 January 2019  1,977.2  (25.1)  (142.8)  (122.4)  1,686.9 
Profit for the period  115.5  115.5 
Other comprehensive income for the period  53.8  22.7  76.5 
Total comprehensive income for the period  53.8  22.7  115.5  192.0 
Balance as at 30 June 2019  1,977.2  28.7  (120.1)  (6.9)  1,878.9 

The hedging reserve is shown net of tax of $12.4m.

In millions of US$  Share Capital  Hedging reserve  Foreign currency translation  Retained Surplus/(Deficit)  Total 
As at 1 January 2018  (3.8)  (3.8) 
Profit for the period    15.0  15.0 
Other comprehensive income for the period  (106.1)  (38.4)  (144.5) 
Total comprehensive income for the period  (106.1)  (38.4)  15.0  (129.5) 
Transactions with Owners of the Company:           
Issue of ordinary shares related to business combinations  1,977.2  1,977.2 
Total Contributions and Distributions  1,977.2  (106.1)  (38.4)  15.0  1,847.7 
Balance as at 30 June 2018  1,977.2  (106.1)  (38.4)  11.2  1,843.9 

Unaudited Condensed Consolidated Cash Flow Statement

In millions of US$  Six months ended 30 June 2019  Six months ended 30 June 2018   
 
 
Cash Flows from Operating Activities       
Profit before taxation  384.7  336.0   
Adjustments to reconcile profit before tax to net cash flows:       
Depreciation, amortisation and impairment  342.7  285.7   
Unsuccessful exploration costs written off  0.7   
Finance costs  108.6  46.9   
Finance income  (5.3)  (2.2)   
Net income from equity investments  1.7  (7.6)   
Other non-cash income and expenses  44.3   
Fair value movement on commodity based derivative instruments  (16.8)  7.4   
Movement in provisions including decommissioning expenditure  (33.6)  (10.6)   
Working capital adjustments  (24.2)  177.4   
Income tax paid  (189.8)  (247.9)   
Net cash flows from operating activities  613.0  585.1   
Cash Flows from Investing Activities       
Expenditure on exploration and evaluation assets  (17.3)  (10.7)   
Expenditure on property, plant and equipment  (334.8)  (128.9)   
Expenditure on business combination and acquisitions, net of cash acquired  (3,205.2)   
Proceeds from sale of equity investments  7.5   
Finance income received  5.3  2.2   
Investment made in equity accounted investments  (32.0)   
Net cash flows used in investing activities  (371.3)  (3,342.6)   
Cash Flows from Financing Activities       
Proceeds from issue of shares  1,977.2   
Proceeds from loans and borrowings  170.5  2,029.4   
Repayment of borrowings  (400.0)  (783.6)   
Payments on finance lease liabilities  (10.3)   
Finance costs paid  (52.2)  (98.7)   
Net cash flows from / (used) in financing activities  (292.0)  3,124.3   
Net increase/(decrease) in cash and cash equivalents  (50.3)  366.8   
Cash and cash equivalents at 1 January  197.3  0.4   
Net foreign exchange differences  (0.4)  9.8   
Cash and cash equivalents as at 30 June  146.6  377.0   

General information

Neptune Energy Group Midco Limited is a limited company, incorporated and domiciled in the United Kingdom. The registered office is located at Nova North, 11 Bressenden Place, London SW1E 5BY.

The condensed consolidated financial statements of Neptune Energy Group Midco Limited and its subsidiaries (collectively, the Group) for the six months ended 30 June 2019 were authorised for issue in accordance with a resolution of the Board on 28 August 2019. The Group is principally engaged in oil and gas exploration and production.

The information for the period ended 31 December 2018 contained within the condensed financial statements does not constitute statutory accounts within the meaning of section 434 of the Companies Act 2006. Statutory accounts for the period ended 31 December 2018 were approved by the Board of Directors on 2 April 2019 and delivered to the Registrar of Companies. The auditor reported on those accounts; the report was unqualified and did not contain any statement under section 498(2) or 498(3) of the Companies Act 2006.

1.       Basis of preparation

The condensed consolidated financial statements for the six months ended 30 June 2019 have been prepared in accordance with IAS 34 Interim Financial Reporting.

The condensed consolidated financial statements do not include all the information and disclosures required in the annual financial statements and should be read in conjunction with the Group's consolidated financial statements as at 31 December 2018 which contains additional accounting policy disclosure. The preparation of financial statements in conformity with IAS 34 requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements, are disclosed below in note 1.3.

The accounting policies adopted in the preparation of the consolidated financial statements are consistent with those followed in the preparation of the Group's annual consolidated financial statements for the period ending 31 December 2018 except where, due to the adoption of new standards effective as of 1 January 2019 (see note 1.1). The Group has not early-adopted any other standard, interpretation or amendment that has been issued but is not yet effective.

The unaudited results for the period ended 30 June 2018 as previously disclosed have been adjusted as they were based on provisional assigned fair values of the acquisition of the EPI business on 15 February 2018. On completion of the business combination accounting for the audited results for the year ended 31 December 2018 the associated judgements and fair values were subsequently concluded.  Consequently, to ensure a more appropriate comparison, the 30 June 2018 comparative financial results (which consolidate the acquired EPI business from 15 February) and associated metrics incorporate this concluded position. The revisions to these unaudited financial statements and metrics do not constitute a restatement of the financial results as International Financial Reporting Standards allow a period of up to 12 months beyond the acquisition date of business combinations to finalise the associated judgements and assigned fair values.

1.1    New standards, interpretations and amendments adopted by the Group

IFRS 16 Leases was issued in 2016 to replace IAS 17 Leases and is required to be adopted by 2019. Under the new standard all lease contracts, with limited exceptions, are recognised in financial statements by way of right-of-use assets and corresponding lease liabilities. The Group has applied the modified retrospective approach, which means that the cumulative effect of initially applying the standard is recognised at the date of initial application and there is no restatement of comparative information.

In March 2019, the IFRS Interpretations Committee (IFRIC) finalised its decision regarding "liabilities in relation to a Joint Operator's Interest in a Joint Operation (IFRS 11 Joint Arrangements)", concluding that a joint operator should recognise the liabilities for which it has primary responsibility, which may be different from its share in the joint operation. As a consequence of this ruling the Group has recognised the full value of joint venture lease liabilities for which it has primary responsibility, recognising its joint venture share as a right of use asset and the partners share as a joint venture receivable.

The application of the standard has impacted both the measurement and disclosures of leases over a low-value threshold, with terms longer than one year and on the classification of expenditures and consequently the classification of cash flow from operating activities, cash flow from investing activities and cash flow from financing activities. It has also impacted the timing of expenses recognised in the statement of income. The adoption of the new standard at 1 January 2019, on a gross basis has had a negligible impact on equity following the recognition of lease liabilities of $155 million and additional right of use assets of $90 million and JV partner receivables of $65 million. These liabilities have been measured at the present value of the remaining lease payments, discounted using the Group's marginal cost of finance as of 1 January 2019, which is the Company's rate on its corporate reserve-based lending facility currently 5.7 per cent. A 1 per cent change in the cost of borrowing would have impacted the value of lease liabilities on transition by $5.4 million.

The following categories of leases have been identified: land, buildings (offices, warehouses and supply bases), transportation assets (helicopter, supply and standby vessels), Plant, Property and Equipment. 

Where the asset is dedicated to an Operated Joint Venture and Neptune has transferred substantially all the risks and rewards incidental to ownership on a pro rata base to joint venture (JV) partner(s) Neptune recognises the gross lease liability but derecognises the proportion of the right of use asset that is sub leased which is recognised as a JV receivable. Where there are options to extend a contract and it is reasonably certain that the contract will be extended the lease period extension is included in the assessment. The right of use asset is recognised within property plant and equipment at the present value of the liability at the commencement date of the lease, adding any directly attributable costs. The right-of-use asset is depreciated on a straight-line basis over the lease term.

The Group has elected to use the exemptions proposed by the standard on lease contracts for which the lease terms ends within 12 months as of the date of initial application, and lease contracts for which the underlying asset is of low value. These leases will continue to be accounted as operating leases and are not material in the context of the Group financial results. Furthermore, the use of a single discount rate is applied to a portfolio of leases with reasonably similar characteristics.

The impact of adopting IFRS 16 on 1 January 2019 has been the immediate recognition of right-of-use assets of $90 million, a JV partner receivable of $65 million and lease liabilities of circa $155 million, with a reclassification of costs from 1 January 2019 that would have previously been reported under operating lease expenses to depreciation of leased assets and unwinding of the discount on leased assets.

Initial recognition of lease liability  Current  Non-current  Value on transition $m 
Land 
Buildings  52  60 
Transportation  23  69  92 
Plant, Property and Equipment 
Total  31  124  155 

The difference between the closing 2018 value of operating lease commitments of $189 million and the opening value to be recognised as the lease liability of $155 million is $34 million. This arises primarily as a result of the deduction of $97 million of items outside the scope of IFRS 16 reporting, being pipeline capacity commitments and jointly shared assets, offset by the addition of $103 million of items within the scope of IFRS 16 while previously being outside the scope of IAS 17. These are extension options reasonably certain to be exercised, the inclusion of gross attribution of contracted assets within operated joint operations and $40 million as a result of applying a discount rate of 5.7 per cent being the Group's incremental borrowing rate.

In millions of US$       
       
Reconciliation of Operating Lease Commitments to IFRS 16 liability      1 January 2019 
Operating lease commitments as at 31 December 2018 as disclosed in the Group's Consolidated Financial Statements  189 
Recognition exemption- jointly controlled assets (note a)      (11) 
Recognition exemption- pipeline booking capacity commitments      (86) 
Extension options reasonably certain to be exercised      60 
Leases within Joint Operations      37 
Other     
Discounted using incremental borrowing rate at 1 January 2019 of 5.7%      (40) 
Lease liabilities recognised at 1 January 2019      155 

a)         Also includes the recognition exemption for low- value assets and short-term leases of $0.1 million

IFRIC 23 Uncertainty over Income Tax Positions (effective 1 January 2019)

IFRIC 23, Uncertainty over Income Tax Treatments, was issued by IASB on 7 June 2017. The interpretation provides guidance on the accounting for current and deferred tax assets and liabilities in circumstances in which there is uncertainty over income tax treatments. IFRIC 23 requires the entity to contemplate whether uncertain tax treatments should be considered separately or as a group based on the predictability of the resolution. In addition, the entity should assess if the tax authority will accept uncertain tax treatments, and in the case where it is not probable, the interpretation requires the entity to reflect the uncertainty with disclosure of the most likely amount and the expected value of the income tax payable or recoverable. The interpretation became effective for annual periods beginning on January 1, 2019. The adoption of this interpretation did not have a material impact on the condensed consolidated interim financial statements.

Several other financial reporting amendments and interpretations apply for the first time in 2019, but do not have an impact on the interim condensed consolidated financial statements of the Group.

1.2    Measurement and presentation basis

The condensed consolidated financial statements have been prepared using the historical cost convention, except for financial instruments that are accounted for according to the financial instrument categories defined by IFRS 9.

The consolidated financial statements are presented in US dollars and rounded to millions, except when otherwise indicated.

1.3    Significant judgements and estimates

Estimates and judgements are continually evaluated and are based on historical experiences and other factors, including expectations of future events that are believed to be reasonable under the circumstances. 

1.3.1 Estimates

The preparation of condensed consolidated financial statements requires the use of estimates and assumptions to determine the value of assets and liabilities and contingent assets and liabilities at the reporting date, as well as revenues and expenses reported during the period.

The key estimates used in preparing the Group's consolidated financial statements relate mainly to:

-      measurement of the recoverable amount of property, plant and equipment, other intangible exploration assets and goodwill;

-      assessments of fair value of assets and liabilities acquired as part of a business combination;

-      calculations of depreciation and amortisation which involve estimates of volumes of commercial reserves of oil and gas;

-      measurement of provisions, particularly for decommissioning obligations, pensions and other employee post-retirement benefits; and measurement of recognised tax loss carry-forwards.

Each of these categories of key estimates are described further below. Due to uncertainties inherent in the estimation process, the Group regularly revises its estimates in light of currently available information. Final outcomes could differ from those estimates.

Recoverable amount of intangible assets and property, plant and equipment and goodwill

The recoverable amounts of intangible assets and property, plant and equipment and goodwill are based on estimates and assumptions, regarding in particular the expected market outlook (including future commodity prices) used for the measurement of cash flows, estimates of the volume of commercially recoverable reserves and resources of oil and gas future production rates and costs to develop reserves and resources, and the determination of the discount rate.

Any changes in these assumptions may have a material impact on the measurement of the recoverable amount and could result in adjustments to any impairment losses to be recognised.

Business combination

In accounting for the acquisition, as disclosed in note 4, the identifiable assets and liabilities acquired were recognised at their fair value in accordance with IFRS 3 'Business combinations'. The determination of their fair values is based, to a considerable extent, on estimates and judgements.

Commercial reserves and depreciation of oil and gas production assets

Charges for depreciation and amortisation of oil and gas producing properties are calculated on a unit of production rate based on production as a proportion of estimated quantities of proved and probable oil and gas reserves. The Group has adopted the definitions and guidelines presented in the Petroleum Resources Management System (SPE-PRMS 2007) for the classification and reporting of commercial reserves and resources of oil and gas. Commercial reserves are those in the proved and probable categories of reserves.

Estimates of reserves is a subjective process involving estimating underground resource accumulations and recovery rates, and is a function of many factors, such as the properties of the reservoir rock and petroleum fluid. Changes in the estimates of commercial reserves will consequently impact depreciation and amortisation expense.  Changes in factors or assumptions used in estimating reserves could include:

-      changes due to revised estimates of volumes in place and recovery factors;

-      the effect on proved and probable reserves of differences between actual commodity prices and assumptions; and

-      unforeseen operational issues.

Estimates of decommissioning provisions

Parameters having a significant influence on the amount of provisions for decommissioning costs include the forecast of costs to be incurred to decommission facilities, plug wells and restore sites used for production and drilling, the anticipated scope of such decommissioning obligations, which may depend on laws and regulation in force at the time, the timing of such expenditure and the discount rate applied to forecast cash flows. These parameters are based on information and estimates deemed to be appropriate by the Group at the current time.

The modification of certain parameters could involve a significant adjustment of these provisions.

Pensions and post-employment benefit obligations

Pension commitments are measured on the basis of actuarial assumptions. These include assumptions in respect of mortality rates and future salary increases, as well as appropriate discount rates. The Group considers that the assumptions used to measure its obligations are appropriate and documented. However, any changes in these assumptions may have a material impact on the resulting calculations.

Pension costs for interim periods are calculated on the basis of the actuarial valuations performed at the end of the prior year. If necessary, these valuations are adjusted to take account of curtailments, settlements or other major non-recurring events that have occurred during the period.

Measurement of recognised tax loss carry-forwards

Deferred tax assets are recognised on tax loss carry-forwards when it is probable that taxable profit will be available against which the tax loss carry-forwards can be utilised. The estimates of the taxable profit that will be available against which the unused tax losses can be utilised, are based on taxable temporary differences relating to the same taxation authority and the same taxable entity and estimates future taxable profits. These estimates and utilisations of tax loss carry-forwards are prepared on the basis of profit and loss forecasts as included in the medium-term business plan and, if necessary, on the basis of additional forecasts.

1.3.2 Judgements

As well as relying on estimates, the Directors make judgments to define the appropriate accounting policies and decisions to apply to certain activities and transactions, including when the effective IFRS standards and interpretations do not specifically deal with the related accounting issues. Key areas of judgement include:

Carrying value of intangible exploration and evaluation assets: the amounts capitalised for exploration and evaluation assets represent cost in respect of active exploration and appraisal projects. These amounts will be written off to the income statement as exploration expense unless commercial reserves are established or the determination process as to the success or otherwise of the activity is not yet completed and there are no indications of impairment in accordance with the Group's accounting policy. The process of determining whether there is an indicator for impairment or calculating the impairment requires critical judgement, including: the Group's intention to proceed with a future work programme for a prospect or licence; the likelihood of licence renewal or extension; the assessment of whether sufficient data exists to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale, and the success of a well result.

Commercial reserves: the estimation of commercial reserves of oil and gas in accordance with SPE-PRMS guidelines, as outlined above, involves complex technical judgements.

2.       Financial risk management

Group financial risk factors

The Group's activities expose it to a variety of financial risks: market risk (e.g. currency risks), commodity risk, credit risk and liquidity risk. The group's overall risk management programme focusses on the unpredictability of financial markets and seeks to minimise potential adverse effects on the Group's financial performance.

Market risk (foreign exchange risk)

The Group operates internationally and therefore exposed to foreign exchange risk arising from various currency exposures, primarily with respect to the Pound Sterling (GBP), Norwegian Krone (NOK) and Euros. Foreign exchange risk arises from future commercial transactions, recognised assets and liabilities and net investments in foreign operations. 

Credit risk

Currently credit risk only arises from cash and cash equivalents, sales receivables, hedging derivatives. For banks and financial institutions, only independently rated parties with a minimum rating of 'BBB' are accepted.

Liquidity risk

Liquidity risk is the risk that the Group might not have sources of funding to meet its business needs. The Directors believe that the Group has sufficient cash, undrawn committed funds under its borrowing base facility and expected sources of liquidity to meet the business's forecast requirements.

3.       Segment information

Revenue from contracts with customers

The Group's activities consist of a single class of business (Upstream), representing the acquisition, exploration, development and production of the Group's own oil and gas reserves and resources and is focused on seven geographical regions; UK, Norway, Netherlands, Germany, North Africa, Asia Pacific and Corporate.

  Six months ended 30 June 2019 
In millions of US$  UK  Norway  Netherlands  Germany  North Africa  Asia Pacific  Corporate  2019 Total 
 
Production revenue by origin  102.8  589.8  145.7  99.3  24.8  221.1  1,183.5 
Other revenue  3.0  1.4  47.1  1.8  0.8  54.1 
Revenue  105.8  591.2  192.8  101.1  24.8  221.1  0.8  1,237.6 
Current Operating Income  35.4  339.8  72.1  (3.0)  9.0  69.4  2.1  524.8 
Share of net income from investments using equity method  0.3  (2.0)  (1.7) 
Net Operating Profit After Equity Accounted Investments  35.4  339.8  72.4  (3.0)  7.0  69.4  2.1  523.1 
Other operating gains/(losses)            (35.1) 
Profit Before Financial Items                488.0 
Finance costs                (108.6) 
Finance income                5.3 
Profit Before Tax                384.7 
  Six months ended 30 June 2018   
In millions of US$  UK  Norway    Netherlands  Germany  North Africa  Asia Pacific  Corporate  2018 Total   
 
Production revenue by origin  103.6  512.6  143.1  75.6  17.0  200.7  1,052.6   
Other revenue  5.5  0.1  4.3  2.9  1.0  13.8   
Revenue  109.1  512.7  147.4  78.5  17.0  200.7  1.0  1,066.4   
Current Operating Income  41.3  308.6  39.3  (2.9)  2.6  80.1  (18.2)  450.8   
Share of net income from investments using equity method  3.4  4.2  7.6   
Net Operating Profit After Equity Accounted Investments  41.3  308.6  42.7  (2.9)  6.8  80.1  (18.2)  458.4   
Other operating gains/(losses)        (77.7)   
Profit Before Financial Items                380.7   
Finance costs                (46.9)   
Finance income                2.2   
Profit Before Tax                336.0   
                     
  Six months ended 30 June 2019   
In millions of US$  UK  Norway  Netherlands  Germany  North Africa  Asia Pacific  Corporate  Total   
 
EBITDAX  79.8  447.5  128.4  27.2  13.8  179.9  3.4  880.0   
  Six months ended 30 June 2018   
In millions of US$  UK  Norway  Netherlands  Germany  North Africa  Asia Pacific  Corporate  Total   
 
EBITDAX  74.0  425.5  94.8  21.1  8.6  161.3  (18.1)  767.2   
  As at 30 June 2019 
In millions of US$  UK  Norway  Netherlands  Germany  North Africa  Asia Pacific  Corporate  Total 
Balance Sheet                 
Assets  1,137.1  2,389.2  814.7  556.9  643.7  1,254.7  175.3  6,971.6 
Liabilities  (304.6)  (1,459.2)  (941.3)  (608.4)  (12.4)  (289.4)  (1,477.4)  (5,092.7) 
Net Assets  832.5  930.0  (126.6)  (51.5)  631.3  965.3  (1,302.1)  1,878.9 

4.       Business combinations

4.1 Acquisition of ENGIE E&P International SA

During 2018, the Group finalised the fair values of the assets and liabilities of Engie E&P International SA which completed on 15 February 2018.  All contingent consideration relating to the transaction was settled prior to the commencement of 2019.  

4.2 Acquisition of VNG Norge AS

On 28 September 2018, the Group acquired 100 per cent of the voting shares of VNG Norge AS (an unlisted company based in Norway) from its parent VNG AG (a German natural gas and energy service provider).  

VNG Norge AS has a portfolio of 42 licences, five producing fields and three development projects including, in Norway: the Fenja oil development (30 per cent and operator), Bauge (2.5 per cent); and in Denmark: Solsort (13.8 per cent). The VNG Norge asset base is highly complementary to Neptune's existing Norwegian portfolio. The fair values of the identifiable assets and liabilities of VNG Norge AS as at the date of acquisition were:

In millions of US$   Fair value recognised on acquisition 
Non-Current Assets   
Intangible assets  11.9 
Property, plant and equipment  293.1 
Deferred tax asset  117.1 
Total Non-Current Assets  422.1 
Current Assets   
Trade and other receivables  56.4 
Inventories 
Cash and cash equivalents  71.2 
Total Current-Assets  127.6 
Total Assets  549.7 
Non-Current Liabilities   
Provisions  (112.4) 
Total Non-Current Liabilities  (112.4) 
Current Liabilities   
Trade and other payables  (1.2) 
Other current liabilities  (80.0) 
Total Current Liabilities  (81.2) 
Total Identifiable Net Assets At Fair Value  356.1 
Goodwill arising on acquisition (provisional)  80.7 
Purchase Consideration  436.8 
Analysis Of Cash Flows On Consideration   
Net cash acquired with the subsidiary (including cash flows from investing activities)  71.2 
Purchase consideration  (436.8) 
Contingent consideration outstanding  24.3 
Net Cash Flow On Acquisition  (341.3) 

Purchase consideration comprised cash of $412.5 million and contingent consideration of $24.3 million.

The goodwill recognised arises principally as a result of recognition of deferred tax liabilities for the temporary difference between assigned fair values of oil and gas properties, which are based on post-tax values, and their tax base. The goodwill is not deductible for income tax purposes.

Contingent Consideration

Included in the purchase consideration at acquisition was $24.3 million which would be payable based upon satisfaction of certain tests linked to project success factors and milestones. No contingent consideration is payable if the tests are not achieved. The fair value of this contingent consideration was $23.6 million as at 30 June 2019 all the difference being due to currency translation adjustments between the two reporting dates. The possible outcome for contingent consideration ranges from $nil million to $50 million.

The fair values recognised on acquisition are provisional at the period ended 30 June 2019. The accounting for the business combination will be completed before year end taking into account any measurement period adjustments that may arise.

5.       Other Operating Losses/(Gains)

In millions of US$  Six months ended 30 June 2019  Six months ended 30 June 2018 
Mark-to-market on commodity contracts other than trading instruments losses/ (gains)  (16.7)  20.1 
Group reorganisation costs  47.9  (2.8) 
Business combination transaction costs  60.4 
Other losses  3.9 
Total  35.1  77.7 

6.       Taxation 

The Group calculates the period income tax expense using the tax rate that would be applicable to the expected total annual earnings. The major components of income tax expense in the condensed statement of profit or loss are:

In millions of US$  Six months ended 30 June 2019  Six months ended 30 June 2018 
Current taxation  240.6  356.4 
Deferred taxation  28.6  (35.4) 
Total Income tax expense recognised in income statement  269.2  321.0 

The tax (credit)/charge reconciles with the expected weighted average statutory tax rate of 78.3% (2018: 71.0%).

7.       Intangible assets

In millions of US$  Exploration and evaluation  Other  Total 
Cost at 1 January 2019  81.6  37.6  119.2 
Disposal  (6.6)  (6.6) 
Additions  15.3  1.0  16.3 
Unsuccessful exploration expenditure  (0.7)  (0.7) 
Transfers to property, plant and equipment  (5.2)  (5.2) 
Currency translation adjustments  0.2  0.2 
Cost at 30 June 2019  84.6  38.6  123.2 
Amortisation at 1 January 2019  (6.7)  (6.7) 
Charge for the period  (0.6)  (4.7)  (5.3) 
Amortisation at 30 June 2019  (0.6)  (11.4)  (12.0) 
Net book value at 30 June 2019  84.0  27.2  111.2 
Net book value at 31 December 2018  81.6  30.9  112.5 

8.       Property, plant and equipment

In millions of US$  Oil and gas properties  Other fixed assets  Total 
Cost at 1 January 2019  4,520.2  33.4  4,553.6 
IFRS 16 opening balance restatements  38.3  51.7  90.0 
Disposal  (3.5)  (0.1)  (3.6) 
Additions  322.9  0.2  323.1 
Transfers from exploration and evaluation  5.2  5.2 
Currency translation adjustments  22.1  (0.2)  21.9 
Cost at 30 June 2019  4,905.2  85.0  4,990.2 
Accumulated depreciation at 1 January 2019  (628.9)  (2.5)  (631.4) 
Charge for period  (327.0)  (5.7)  (332.7) 
Impairment  (4.8)  (4.8) 
Disposal  3.4  0.1  3.5 
Currency translation adjustments  (3.1)  (0.1)  (3.2) 
Accumulated depreciation at 30 June 2019  (960.4)  (8.2)  (968.6) 
Net book value at 30 June 2019  3,944.8  76.8  4,021.6 
Net book value at 31 December 2018  3,891.3  30.9  3,922.2 

9.       Cash and cash equivalents

For the purposes of the condensed statement of cash flows, cash and cash equivalents comprise the following:

In millions of US$  30 June 2019  31 December 2018 
Cash at bank and in hand  138.4  191.1 
Restricted cash  8.2  6.2   
Total cash and cash equivalents  146.6  197.3 

Cash and cash equivalents comprise cash in hand, deposits with maturity of three months or less and other short-term money market deposit accounts that are readily convertible into known amounts of cash. Restricted cash includes monies held for decommissioning obligations.

10.    Trade payables and accruals

Trade payables are usually paid within 30 days of recognition. The carrying amount of financial assets and financial liabilities approximates their fair value. The finance lease liabilities are included within other current and non-current liabilities of $31.6 million and $105.0 million respectively.

In millions of US$              30 June 2019  31 December 2018 
Trade and other payables  238.1  94.5 
Current tax payable  249.8  188.1 
Other current liabilities     
Lease liabilities  31.6 
Other  253.1  466.3 
Current trade payables and accruals  772.6  748.9 
Other non-current liabilities     
Lease liabilities  105.0 
Other  58.7  59.6 
Non-Current trade payables and accruals  163.7  59.6 
 Total  936.3  808.5 

11.    Provisions

In millions of US$  30 June 2019  31 December 2018 
Current     
Group reorganisation  52.9  5.7 
Decommissioning  61.2  62.1 
Other  0.1  1.5 
 Current Total  114.2  69.3 
Non-Current     
Post-employment benefit and other long-term benefits  229.0  232.5 
Decommissioning  1,452.4  1,442.7 
Non-Current Total  1,681.4  1,675.2 
 Total  1,795.6  1,744.5 

12.    Financial assets and financial liabilities

Set out below is an overview of financial assets and liabilities, other than cash and short-term deposits, held by the Group as at 30 June 2019 and 31 December 2018.

In millions of US$  30 June 2019  31 December 2018 
Financial assets at fair values     
Commodity derivatives at fair value through profit and loss  6.5  3.4 
Commodity derivatives in qualifying hedging relationships  133.2  69.9 
Foreign forward exchange contracts at fair value through profit and loss  2.4 
Equity instruments designated at fair value through OCI     
10.58% interest in Erdgas-Verkaufs-Gesellschaft mbH, Münster  19.6  19.7 
Financial assets at amortised cost     
Trade and other receivables  631.8  642.6 
Tax receivable  25.1  83.7 
Other non-current assets  125.9  8.8 
Total  944.5  828.1 
Total current  732.9  759.5 
Total Non-current  211.6  68.6 

Fair value is the amount at which a financial instrument could be exchanged in an arm's length transaction, other than in a forced or liquidated sale. Where available, market values have been used to determine fair values. The estimated fair values have been determined using market information and appropriate valuation methodologies. Values recorded are as at the balance sheet date and will not necessarily be realised. Non-interest bearing financial instruments, which include amounts receivable from customers and accounts payable are also recorded materially at fair value reflecting their short-term maturity.

The Fair values of all derivative financial instruments are based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy.

Other non-current assets comprises of joint venture lease receivables of $41.3m and other joint venture receivables of $84.6m 

The valuation of Neptune's interest in Erdgas Münster its sole equity investment, has been calculated based on an enterprise value/EBITDA multiple taking into account recent transactions involving suitable comparative infrastructure companies, which are based on unobservable inputs and are level 3 in the IFRS 13 hierarchy.

The valuation of contingent consideration relates to the Company's acquisition of VNG and is based on management's view of the most likely future liability that will be settled which are based on unobservable inputs and are level 3 in the IFRS 13 hierarchy.

Set out below is an overview of financial liabilities, other than cash and short-term deposits, held by the Group as at 30 June 2019. The Senior Notes held by the Group have a fair value of $558.3 million, compared to the carrying amount of $538.6 million. This financial liability is classed as Level 1. For all other items held at amortised cost there is no significant difference between their fair value and amortised cost value.

In millions of US$  30 June 2019  31 December 2018 
Financial liabilities at fair values     
Commodity derivatives at fair value through profit and loss  9.6  14.1 
Commodity derivatives in qualifying hedging relationships  54.2  76.3 
Interest rate derivatives in qualifying hedging relationships  6.6  2.1 
Foreign forward exchange contracts at fair value through profit and loss  0.1  12.2 
Contingent consideration of the VNG Norge AS acquisition  23.6  24.3 
Financial Liabilities amortised at cost     
Trade and other payables  238.1  94.5 
Income taxes payable  296.3  223.8 
Other current liabilities  284.7  442.0 
Other non-current liabilities  140.1  59.6 
Long Term borrowings     
Reserve base lending facility  698.7  943.4 
Senior Notes  538.6  537.7 
Touat project finance facility  233.1  200.2 
Subordinated Neptune Energy Group Limited loan  111.0  106.9 
Total  2.634.7  2,737.1 
Total current  798.6  822.5 
Total Non-current  1,836.1  1,914.6 

12.1  Financial assets and financial liabilities - hierarchy

Set out below is an overview of the hierarchy of financial assets and financial liabilities, other than cash and short- term deposits, held by the Group as at 30 June 2019 and 31 December 2018. For items held at amortised cost, there is no significant difference between their fair value and amortised cost value.

There have been no transfers between levels during the period.

    30 June 2019 
In millions of US$  Date of valuation  Total  Significant observable inputs (Level 2)  Significant unobservable inputs (Level 3) 
         
Assets measured at fair value         
Derivative financial assets         
Commodity derivatives in qualifying hedging relationships  30.06.2019  133.2  133.2 
Commodity derivatives at fair value through profit and loss  30.06.2019  6.5  6.5 
Foreign forward exchange contracts at fair value through profit and loss  30.06.2019  2.4  2.4 
Non-Listed equity Instruments         
10.58% interest in Erdgas Münster GMBH  30.06.2019  19.6  19.6 
Total    161.7  142.1  19.6 
           
    31 December 2018 
In millions of US$  Date of valuation  Total  Significant observable inputs (Level 2)  Significant unobservable inputs (Level 3) 
         
Assets measured at fair value         
Derivative financial assets         
Commodity derivatives in qualifying hedging relationships  31.12.2018  69.9  69.9 
Commodity derivatives at fair value through profit and loss  31.12.2018  3.4  3.4 
Non-Listed equity Instruments         
10.58% interest in Erdgas Münster GMBH  31.12.2018  19.7  19.7 
Total    93.0  73.3  19.7 
           
    30 June 2019 
In millions of US$  Date of valuation  Total  Significant observable inputs (Level 2)  Significant unobservable inputs (Level 3) 
         
Liabilities measured at fair value         
Derivatives financial liabilities         
Commodity derivatives in qualifying hedging relationships  30.06.2019  54.2  54.2 
Commodity derivatives at fair value through profit and loss  30.06.2019  9.6  9.6 
Interest rate derivatives in qualifying hedging relationships  30.06.2019  6.6  6.6 
Forward foreign exchange contracts at fair value through profit and loss  30.06.2019  0.1  0.1 
Contingent consideration  30.06.2019   23.6  23.6 
Total    94.1  70.5  23.6 
           
    31 December 2018 
In millions of US$  Date of valuation  Total  Significant observable inputs (Level 2)  Significant unobservable inputs (Level 3) 
         
Liabilities measured at fair value         
Derivatives financial liabilities         
Commodity derivatives in qualifying hedging relationships  31.12.2018  76.3  76.3 
Commodity derivatives at fair value through profit and loss  31.12.2018  14.1  14.1 
Interest rate derivatives in qualifying hedging relationships  31.12.2018  2.1  2.1 
Forward Foreign exchange contracts at fair value through profit and loss  31.12.2018  12.2  12.2 
Contingent consideration  31.12.2018   24.3  24.3 
Total    129.0  104.7  24.3 

12.2  Change in the value of Level 3 Instruments

The following table presents the changes in Level 3 instruments for the 6 months ended 30 June 2019.

In millions of US$  Equity investments  Contingent consideration  Total 
       
Opening balance at 31 December 2018  19.7  (24.3)  (4.6) 
Gains recognised in other income *  0.7  0.7 
Losses recognised in other comprehensive income  (0.1)  (0.1) 
Closing balance at 30 June 2019  19.6  (23.6)  (4.0) 

* Includes unrealised gains or (losses) recognised in profit or loss attributable to balances held at the end of the reporting period.

A 5 per cent change in the EBITDA multiple to the Level 3 instrument above as applied would result in a $1 million change in valuation.

12.3 Hedging reserve

The hedge reserve represents the portion of deferred gains and losses on hedging instruments deemed to be effective cash flow hedges. The movement in the reserve for the period is recognised in other comprehensive income. The following table summarises the hedge reserve by type of derivative, net of tax effects.

In millions of US$  Cash flow commodity hedge reserve  Cost of commodity hedging reserve  Cash flow Interest rate hedge reserve  Cost of interest rate hedging reserve  Total hedge reserve 
At 1 January 2019  17.0  6.9  1.2                     -     25.1 
Add costs of hedging deferred and recognised in OCI  (78.2)  (5.0)  6.2  (0.1)  (77.1) 
Less reclassified from OCI to profit or loss or included in finance costs  13.3  (5.4)  (0.3)  7.6 
Less deferred tax  11.2  4.5  15.7 
At 30 June 2019  (36.7)  1.0  7.1  (0.1)  (28.7) 

The Company has identified the following potential sources of hedge ineffectiveness in its hedging relationships:

-      CVA/DVA mismatches between the hedging instrument and the hedged item

-      the effects from discounting arising from settlement date mismatches between the hedging instrument and hedged item

-      the effects from the unwind of discounting from the designation of certain off-market hedging instruments in hedging relationships.

13.    Share capital

  Number  $million 
Allotted, called up and fully paid     
At 31 December 2018  1,977,175,201  1,977.2 
Issued in the period 
At 30 June 2019  1,977,175,201  1,977.2 

14.    Contingent liabilities

During the normal course of its business, the Group may be involved in disputes, including tax disputes. The group has made accruals for probable liabilities related to litigation and claims based on management's best judgement and in line with IAS 37 and IAS 12. There have been no changes in the period since the 2018 year end disclosure. Further details on contingencies can be found in Note 25 of the Neptune Energy Annual Report and Accounts 2018.

15.    Related party transactions

There were no related party transactions in the six months ended 30 June 2019.

16. Adoption of new accounting standards - financial impact of implementation of IFRS 16

Balance sheet

The Group impact on the balance sheet of the implementation of IFRS16 has resulted in higher property, plant and equipment, current and non-current other assets and current and non-current lease liabilities.

In millions of US$                30 June 2019   
 
Property, plant and equipment       
Non-Current    78.8   
Other Assets       
Non-Current    41.3   
Current    14.9   
Lease Liabilities       
Non-Current    105.0   
Current    31.6   
       

Income statement 

The Group impact of the implementation of IFRS16 is a small increase in operating costs, along with a $4.8m increase in finance costs. The Group has recognised depreciation on right of use assets in the first half of 2019 of $8.9m. Interest on the Group's finance lease liabilities for the first half of 2019 was $4.8m, partly offset by interest on amounts due from joint venture partners of $1.9m. Other income of $1.8m has also be recognised reflecting reimbursements from partners.

Cash flow statement

Lease payments are now split between financing cash flows and operating cash flows in the cash flow statement. Financing cash flows represent repayment of principal, and operating cash flow payments of interest. In prior periods operating lease payments were all presented as operating cash flows under IAS 17. During the first half of 2019, the Group has a total cash outflow of $10.3m on qualifying leases.

17.    Events after the reporting period 

On 26 July, the Group announced it had agreed to acquire interests in two Production Sharing Contracts (PSC) in the Kutei basin, offshore Indonesia (a 20 per cent working interest in the East Sepinggan PSC and a 30 per cent working interest in the East Ganal PSC).

The transaction is subject to customary regulatory approvals, with completion expected in the fourth quarter of 2019.

On 26 August, the Group announced it and its partners Eni (Operator) and  Pertamina had been awarded the West Ganal PSC in Indonesia, also located in the Kutei basin. The consortium has committed to drilling four exploration wells during the first exploration period, in addition to acquiring seismic data.

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