Interim / Quarterly Report • Jul 31, 2019
Interim / Quarterly Report
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Lundin Petroleum AB (publ) company registration number 556610-8055
| 1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|
|---|---|---|---|---|---|
| Production in Mboepd | 77.5 | 76.1 | 82.1 | 81.2 | 81.1 |
| Revenue and other income in MUSD | 984.0 | 499.9 | 1,383.9 | 681.5 | 2,640.7 |
| Operating cash flow in MUSD | 778.9 | 400.2 | 978.4 | 510.4 | 1,864.1 |
| EBITDA in MUSD | 811.6 | 411.9 | 975.0 | 512.3 | 1,932.5 |
| Free cash flow in MUSD | 167.4 | 71.6 | 261.0 | 89.2 | 663.0 |
| Net result in MUSD | 149.7 | 96.2 | 267.2 | 37.0 | 225.7 |
| Earnings/share in USD | 0.44 | 0.28 | 0.79 | 0.11 | 0.67 |
| Net debt | 3,359.3 | 3,359.3 | 3,798.5 | 3,798.5 | 3,398.2 |
"The first half of 2019 has been one of the busiest to date in all areas of our business and I am pleased to report another period of sustained strong financial performance and operational delivery, driven by our portfolio of world class assets which continue to outperform quarter on quarter.
"We are now on the final countdown to first oil from Johan Sverdrup in November 2019. With the offshore installation having been completed at the front end of the weather window in March 2019, the hook up and commissioning of the installed facilities is progressing on plan. The project is now over 90 percent complete and the operator has further reduced Phase 1 gross capital expenditure guidance to NOK 83 billion from NOK 86 billion.
"Our key producing assets at Edvard Grieg and Alvheim continue to deliver, both in production performance and efficiency. At Edvard Grieg, the Solveig tie-back development project kicked off during the period, following PDO approval in June 2019, alongside the Rolvsnes EWT which was also approved in July 2019. With the two tie-back projects now sanctioned, plus a committed infill programme, the plateau production period through the Edvard Grieg facilities has now been extended to around the end of 2022, from mid-2020.
"We remain focussed on organic growth and the last six months have been a very active period in the Company from an exploration and appraisal perspective with 12 wells drilled to date, resulting in four discoveries and one appraisal success. Seven further exploration and appraisal wells will be drilled this year targeting approximately 200 MMboe of net unrisked resources; including the basement target at Goddo, near Edvard Grieg which has the opportunity to unlock a significant resource potential in this new geological play type to Norway.
"In terms of business development we announced a transaction post period end which, once complete, will see us redeem 16 percent of our shares in issue and sell of 2.6 percent of Johan Sverdrup to Equinor. This transaction rationalises our shareholder structure and increases all investors' leverage to the continuing performance of our world class portfolio of assets, the soon to be producing Johan Sverdrup field and the Company's organic growth strategy. As such we have also updated our guidance for the near and long term, which sees our capital expenditure coming down while production post the start-up of Johan Sverdrup remains above 150Mboepd.
"Looking towards the second half of the year, one of the stand out events will be first oil at Johan Sverdrup expected in November, which is a significant moment for our business since our first discovery well there. We will also continue to be busy with the exploration drill bit and I look forward to further progress from the new projects currently in the development phase. With our industry leading low operating cost base, production growth profile and high HSE track record, I remain very confident in our business' ability to continue to outperform."
For definitions and abbreviations, see pages 31 and 34.
Lundin Petroleum is one of Europe's leading independent oil and gas exploration and production companies with operations focused on Norway and listed on NASDAQ Stockholm (ticker "LUPE"). Read more about Lundin Petroleum's business and operations at www.lundin-petroleum.com
All the reported numbers and updates in the operational review relate to the six month period ending 30 June 2019 (reporting period) unless otherwise specified.
In July 2019, the Company announced a proposal to redeem 16 percent of the outstanding Lundin Petroleum shares held by Equinor and also divest 2.6 percentage points of the Company's interest in the Johan Sverdrup development project to Equinor, retaining a 20 percent interest going forward. Upon closing of this divestment, anticipated in the third or fourth quarter of 2019, the adjustments to guidance inclusive of other operational updates are as follow:
| 2019 full year guidance | Updated | Previous |
|---|---|---|
| Production | 75 to 95 Mboepd | 75 to 95 Mboepd |
| Operating Cost | USD 4.25 per boe | USD 4.25 per boe |
| Development Capital Expenditure | MUSD 7851 | MUSD 930 |
| Exploration and Appraisal Expenditure | MUSD 3252 | MUSD 300 |
| Long-term guidance | Updated | Previous |
| Production Johan Sverdrup Phase 1 - | More than150 Mboepd | More than150 Mboepd |
| Plateau 2020 | ||
| Production Johan Sverdrup Phase 2 - | Approximately 170 Mboepd | More than 170 Mboepd |
| Plateau 2023 | ||
| Operating cost from 2020 onwards 1 Reflecting both revised project cost and the reduced working interest in Johan Sverdrup effective from 1 January 2019 |
USD 3.4 to 4.4 per boe | USD 3.2 to 4.2 per boe |
2 Reflecting both increased activity levels and increased working interests in PL820S and PL896
Production was 77.5 thousand barrels of oil equivalent per day (Mboepd) which was 2 percent above mid-point of the production guidance for the reporting period. This result is due to continued good performance at both Edvard Grieg and the Alvheim area. Production guidance for the full year remains between 75 and 95 Mboepd, reflecting a range around the expected start-up of the Johan Sverdrup field, in November 2019.
Operating cost, including netting off tariff income, was USD 4.49 per barrel, which is in line with guidance. Full year operating cost guidance remains USD 4.25 per barrel.
| 1 Jan 2019- | 1 Apr 2019- | 1 Jan 2018- | 1 Apr 2018- | 1 Jan 2018- | ||
|---|---|---|---|---|---|---|
| Production in Mboepd |
30 Jun 2019 6 months |
30 Jun 2019 3 months |
30 Jun 2018 6 months |
30 Jun 2018 3 months |
31 Dec 2018 12 months |
|
| Norway | ||||||
| Crude oil | 68.7 | 67.2 | 72.6 | 71.6 | 71.9 | |
| Gas | 8.8 | 8.9 | 9.5 | 9.6 | 9.2 | |
| Total production | 77.5 | 76.1 | 82.1 | 81.2 | 81.1 | |
| 1 Jan 2019- | 1 Apr 2019- | 1 Jan 2018- | 1 Apr 2018- | |||
| Production | 30 Jun 2019 | 30 Jun 2019 | 30 Jun 2018 | 30 Jun 2018 | 1 Jan 2018- 31 Dec 2018 |
|
| in Mboepd | WI1 | 6 months | 3 months | 6 months | 3 months | 12 months |
| Edvard Grieg | 65% | 62.2 | 61.0 | 63.7 | 63.4 | 63.6 |
| Ivar Aasen | 1.385% | 0.8 | 0.8 | 0.9 | 0.9 | 0.9 |
| Alvheim | 15% | 9.6 | 9.2 | 9.1 | 9.2 | 9.3 |
| Volund | 35% | 4.4 | 4.6 | 7.5 | 6.8 | 6.5 |
| Bøyla | 15% | 0.5 | 0.5 | 0.9 | 0.7 | 0.7 |
| Brynhild | 51% | - | - | 0.0 | - | – |
| Gaupe | 40% | - | - | 0.1 | 0.1 | 0.1 |
| 77.5 | 76.1 | 82.1 | 81.2 | 81.1 |
1 Lundin Petroleum's working interest (WI).
Production from the Edvard Grieg field was slightly above forecast, with production efficiency in line with guidance at 96 percent. Reservoir performance continues to exceed expectations; with limited water production and total well potential significantly higher than available facilities capacity. An infill drilling programme is planned to commence in 2020, targeting 16 MMboe of gross contingent resources, based on a three well programme. The Rowan Viking jack-up rig, used to drill all the existing development wells at the Edvard Grieg field, has been contracted for the infill programme on the basis of three firm well slots plus a number of optional slots. Based on the performance at Edvard Grieg and the addition of the Solveig and Rolvsnes tie-back projects, the forecast plateau production period through the Edvard Grieg facilities is being extended from mid-2020 to around the end of 2022. During the second quarter 2019, a dualbranch exploration well made oil discoveries at Jorvik and Tellus East on the eastern edge of the Edvard Grieg field. Both areas are potential targets for future infill wells drilled from the platform. Operating cost for the Edvard Grieg field, including netting off tariff income, was USD 4.49 per barrel.
Production from the Ivar Aasen field was slightly below forecast. During the second quarter 2019, the first of two planned infill production wells was completed and is producing in line with expectations, and the second well is currently drilling.
Production from the Alvheim area, consisting of the Alvheim, Volund and Bøyla fields, was in line with forecast. Production efficiency for the Alvheim FPSO was ahead of expectations at 97 percent. During the second quarter 2019, a sidetrack infill well at the Volund field was successfully completed and is producing in line with expectations. The two-branch Frosk test producer, which will be produced through the Bøyla facilities, has successfully been completed and is expected to come on stream during the third quarter of 2019. The Frosk well also included two pilot holes, one of which tested the Froskelår North East prospect making a small oil discovery. A twobranch pilot well, to be drilled in the third quarter of 2019, has been added to the programme and is aimed at de-risking infill well opportunities in the Alvheim field for a potential 2020 infill well programme. Operating cost for the Alvheim area was USD 5.53 per barrel.
| Field | WI | Operator | Estimated gross reserves |
Production start expected |
Expected gross plateau production |
|---|---|---|---|---|---|
| Johan Sverdrup | 22.6%1 | Equinor | 2.2 – 3.2 Bn boe | November 2019 | 660 Mbopd |
| Solveig Phase 1 | 65% | Lundin Norway | 57 MMboe | Q1 2021 | 30 Mboepd |
| Rolvsnes EWT | 80% | Lundin Norway | - | Q2 2021 | 3 Mboepd |
1 Lundin's working interest will decrease to 20.0% on completion of the Equinor transaction
Phase 1 of the Johan Sverdrup project continues to progress according to schedule and is now over 90 percent complete. In March 2019, the processing platform topsides and the living quarters topsides together, with two connecting bridges, were successfully installed. This operation concluded the main installation activities for Phase 1 of the project, which consists of four jackets and topsides, three subsea water injection templates, oil and gas export pipelines and power supply from shore. Hook-up and commissioning of the installed facilities is progressing on plan together with tie-back of the eight pre-drilled production wells. The good progress being made with hook-up and commissioning, means the project is firmly on track to achieve expected first oil in November 2019. The gross production capacity of Phase 1 is estimated at 440 Mbopd, with ramp-up to plateau production levels expected to take until summer 2020.
The capital expenditure estimate for Phase 1 has been further reduced by the operator to gross NOK 83 billion (nominal), due to further improvements in project execution and delivery, which compares to the Phase 1 PDO estimate in 2015 of gross NOK 123 billion (nominal). This represents a saving of over 30 percent, excluding additional foreign exchange rate savings in US dollar terms.
The Phase 2 PDO was submitted to the Norwegian Ministry of Petroleum and Energy in August 2018 and was approved in May 2019. Phase 2 involves a second processing platform bridge linked to the Phase 1 field centre, subsea facilities to allow for tie-in of additional wells to access the Avaldsnes, Kvitsøy and Geitungen satellite areas of the field and implementation of full field water alternating gas injection (WAG) for enhanced recovery. 28 wells are planned to be drilled in connection with the Phase 2 development. Phase 2 first oil is scheduled in the fourth quarter 2022, which will take the gross plateau production capacity to 660 Mbopd. Full field breakeven oil price is estimated at below USD 20 per barrel.
The Phase 2 capital expenditure is estimated at gross NOK 41 billion (nominal), which is unchanged from the Phase 2 PDO estimate and over a 50 percent saving from the original estimate in the Phase 1 PDO. The major topsides, jacket and Subsea Production System contracts, have been awarded. Construction has commenced on the second processing platform topsides and as well as the new modules to be installed on the existing Riser Platform. Phase 2 of the project is progressing to plan and is approximately 10 percent complete.
The PDO for the Solveig Phase 1 project was approved by the Norwegian Ministry of Petroleum and Energy in June 2019. Solveig is the first Edvard Grieg subsea tie-back development and will contribute to keeping the Edvard Grieg platform filled to capacity for an extended time period. Phase 1 will be developed with three oil production wells and two water injection wells and will achieve gross peak production of 30 Mboepd, with first oil scheduled in the first quarter 2021.
Solveig Phase 1 gross proved plus probable reserves are estimated at 57 MMboe. The capital cost of the development is estimated at MUSD 810 gross, with a breakeven oil price of below USD 30 per barrel. The potential for further phases of development, which will capture the upside potential in the discovered resources, will be de-risked by production performance from Phase 1.
The Solveig Phase 1 project is progressing to plan. All of the key contracts have been awarded and modifications at the Edvard Grieg platform commenced in May 2019.
The production application for the Rolvsnes Extended Well Test (EWT) was approved by the Norwegian Ministry of Petroleum and Energy in July 2019. The Rolvsnes EWT project will be conducted through a 3 km subsea tie-back of the existing Rolvsnes horizontal well to the Edvard Grieg platform. The project is being implemented together with the Solveig project to take advantage of contracting and implementation synergies, with first oil scheduled in the second quarter 2021.
| Licence | Operator | WI | Well | Spud Date | Status |
|---|---|---|---|---|---|
| PL167 | Equinor | 20% | Lille Prinsen | May 2019 | Completed July 2019 |
| PL203 | AkerBP | 15% | Alvheim Infill Pilots | Third Quarter 2019 |
In July 2019, an appraisal well was completed on the Lille Prinsen oil discovery made in 2018 in PL167 located in the Utsira High area of the North Sea. The original discovery, Lille Prinsen Main, is estimated to contain gross resources of between 15 and 35 MMboe. The appraisal well was drilled 1 km west of the discovery well in the downdip Outer Wedge area, making an oil discovery, with the resource estimate pending full assessment of the well results. Other segments of Lille Prinsen will be evaluated for further delineation.
Following the extended well test on the Alta discovery in 2018, technical work is ongoing to determine the forward appraisal strategy for Alta and the nearby Gohta discovery.
| Licence | Operator | WI | Well | Spud Date | Result |
|---|---|---|---|---|---|
| PL857 | Equinor | 20% | Gjøkåsen Shallow | December 2018 | Dry |
| PL767 | Lundin Norway | 50% | Pointer/Setter | January 2019 | Dry |
| PL869 | AkerBP | 20% | Froskelår Main | January 2019 | Oil & Gas Discovery |
| PL857 | Equinor | 20% | Gjøkåsen Deep | February 2019 | Dry |
| PL338 | Lundin Norway | 65% | Jorvik/Tellus East | March 2019 | Two Oil Discoveries |
| PL869 | AkerBP | 20% | Froskelår North East | March 2019 | Oil Discovery |
| PL539 | MOL | 20% | Vinstra/Otta | April 2019 | Dry |
| PL916 | AkerBP | 20% | JK | April 2019 | Dry |
| PL859 | Equinor | 15% | Korpfjell Deep | June 2019 | Dry |
| PL758 | Capricorn | 20% | Lynghaug | June 2019 | Dry |
| PL869 | AkerBP | 20% | Rumpetroll | June 2019 | Dry |
| PL815 | Lundin Norway | 60% | Goddo | July 2019 | Ongoing |
| PL820S1 | MOL | 30% | Evra/Iving | Third Quarter 2019 | |
| PL8961 | Wintershall DEA | 20% | Toutatis | Third Quarter 2019 | |
| PL921 | Equinor | 15% | Gladsheim | Fourth Quarter 2019 | |
| PL917 | ConocoPhillips | 20% | Enniberg | Fourth Quarter 2019 | |
| PL917 | ConocoPhillips | 20% | Hasselbaink | Fourth Quarter 2019 |
1 Lundin's working interest will increase to 40% in PL820S, and to 30% in PL896 on closing of the Wintershall DEA transaction
The 2019 exploration drilling programme involves 17 wells, of which 11 have been completed yielding four oil discoveries. The successful exploration and appraisal wells drilled so far in 2019, have added net resources of between 10 and 40 MMboe. The remaining exploration programme is targeting net unrisked resources of approximately 200 MMboe.
In February 2019, the Gjøkåsen Shallow prospect in PL857 and the Pointer/Setter dual target prospect in PL767, both located in the southern Barents Sea, were drilled and both wells were dry.
In March 2019, the Froskelår Main prospect in PL869 in the Alvheim area proved an oil and gas discovery. The discovery is estimated by the operator to contain gross resources of between 60 and 130 MMboe with part of the discovery potentially extending into the UK. Froskelår Main will be evaluated as part of a potential joint development with the Frosk discovery.
In April 2019, the Gjøkåsen Deep prospect in PL857 in the southeastern Barents Sea, the Vinstra/Otta prospect in PL539 located in the Mandal High area of the North Sea and the JK prospect in PL916 located in the north of the Utsira High area of the North Sea, were all drilled and all three wells were dry.
In June 2019, the Korpfjell Deep prospect in PL859 in the southeastern Barents Sea was drilled and was dry.
In June 2019, the Jorvik and Tellus East prospects on the eastern edge of the Edvard Grieg field in PL338 proved two oil discoveries. At Jorvik, the well encountered oil in 30 metres of conglomerate reservoir of Triassic age with a thin, high quality sandstone above. This combination of conglomerate and sandstone reservoir types are also found on the southern and eastern part of Edvard Grieg. At Tellus East, the well encountered a gross oil column of 60 metres in porous, weathered basement reservoir. The combined gross resources of Jorvik and Tellus East are estimated to be between 4 and 37 MMboe and both can be developed with wells from the Edvard Grieg platform, which will be evaluated in parallel with other infill targets and tie-in opportunities in the area.
In June 2019, the Froskelår North East prospect was drilled as part of the Frosk test producer and proved an oil discovery. The discovery is estimated by the operator to contain gross resources of between 2 and 10 MMboe and is potentially commercial as part of a Frosk/Froskelår development.
In July 2019, the Rumpetroll prospect in PL869 in the Alvheim area was drilled and was dry.
In July 2019, drilling commenced on the Goddo prospect in PL815 located on the Utsira High. Goddo will test the extension of the Rolvsnes weathered basement oil discovery into the adjacent licence, where the combined area is estimated to contain gross potential resources of more than 250 MMboe. Rolvsnes/Goddo located to the south of the Edvard Grieg field is targeting the same porous, weathered basement reservoir currently being produced from the Tellus area of Edvard Grieg.
Preparation of the decommissioning plan for the Brynhild field is ongoing with operations anticipated to be conducted during 2020/2021. The Rowan Viking jack-up drilling rig has been secured to plug and abandon the four Brynhild wells.
The Gaupe field ceased production during the fourth quarter of 2018 and preparation of the decommissioning plan for the field is also ongoing.
In January 2019, Lundin Petroleum was awarded 15 licences in the 2018 APA licensing round, of which nine are as operator.
In January 2019, Lundin Petroleum entered into a sales and purchase agreement involving the acquisition of Lime Petroleum's 30 percent working interest in each of PL338C and PL338E and 20 percent working interest in PL815, which contain the Rolvsnes oil discovery and Goddo prospect. The transaction increased the Company's working interest in each of PL338C and PL338E to 80 percent and in PL815 to 60 percent. The transaction involved a cash consideration payable to Lime Petroleum and was completed in May 2019, with economic effect from 1 January 2019.
In June 2019, Lundin Petroleum entered into a sales and purchase agreement involving the acquisition of a 10 percent working interest in each of PL896 and PL820S from Wintershall DEA. The transaction will increase the Company's working interest to 40 percent in PL820S which contains the Evra/Iving prospects located in the North Sea and to 30 percent in PL896 which contains the Toutatis prospect located in the Norwegian Sea. The transaction is subject to customary government approvals and is expected to complete in the third quarter of 2019.
In July 2019, as part of a proposed transaction to redeem 16 percent of the outstanding Lundin Petroleum shares held by Equinor, the Company further entered into an asset transfer agreement to sell 2.6 percentage points of the Johan Sverdrup development project to Equinor for a cash consideration of MUSD 962 with an effective date of 1 January 2019, which includes a MUSD 52 contingent payment on future reserve attainment. The asset transaction is subject to customary government approvals and is expected to complete in the third or fourth quarter of 2019.
Currently the Company holds 79 licences in Norway, which is an increase of approximately 60 percent from the beginning of 2018.
Lundin Petroleum has previously written down the entire contingent resources and book value for the Morskaya oil discovery in Russia, as it was deemed unlikely that the discovery could commercially be developed in the foreseeable future. Having reviewed potential options, the partnership concluded that it is not possible for the partnership to create value from the asset and consequently the Morskaya licence has been relinquished.
During the reporting period, no lost time incidents and one medical treatment incident occurred, resulting in a Lost Time Incident Rate of 0.0 per million hours worked and a Total Recordable Incident Rate of 1.2 per million hours worked. There were no material safety or environmental incidents. The trend of industry leading low carbon operations continued at the Edvard Grieg field with a carbon intensity of 5.4 kgCO2e per boe during the reporting period.
The operating profit for the reporting period amounted to MUSD 540.7 (MUSD 735.0). The decrease compared to the comparative period was mainly driven by higher expensed exploration costs during the reporting period and lower sold volumes and lower oil prices, somewhat offset by lower depletion costs.
The net result for the reporting period amounted to MUSD 149.7 (MUSD 267.2) representing earnings per share of USD 0.44 (USD 0.79) and impacted by a higher foreign currency exchange gain of MUSD 34.7 (MUSD 9.6). The net result excluding foreign currency exchange results amounted to MUSD 115.0 (MUSD 257.6). The decrease compared to the comparative period was mainly driven by a lower operating profit and a post-tax accounting gain of MUSD 98.1 in the comparative period as a result of the re-negotiated improved borrowing terms for the reserve-based lending facility.
Earnings before interest, tax, depletion and amortisation (EBITDA) for the reporting period amounted to MUSD 811.6 (MUSD 975.0) representing EBITDA per share of USD 2.40 (USD 2.88) with the decrease compared to the comparative period mainly relating to a lower realized price per boe and lower sales volumes. Operating cash flow for the reporting period amounted to MUSD 778.9 (MUSD 978.4) representing operating cash flow per share of USD 2.30 (USD 2.89) with the decrease compared to the comparative period further impacted by a higher current tax charge. Free cash flow for the reporting period amounted to MUSD 167.4 (MUSD 261.0) representing free cash flow per share of USD 0.49 (USD 0.77) with the decrease compared to the comparative period further impacted by a higher cash outflow from investing activities offset by a cash inflow from working capital balances.
In January 2019, Lundin Petroleum entered into a sales and purchase agreement for the acquisition of Lime Petroleum's 30 percent working interest in each of PL338C and PL338E and 20 percent working interest in PL815, which contain the Rolvsnes oil discovery and Goddo prospect. The transaction increased the Company's working interest in each of PL338C and PL338E to 80 percent and in PL815 to 60 percent. The transaction involved a cash consideration payable to Lime Petroleum of MUSD 43.0 and was completed in May 2019, with economic effect from 1 January 2019.
Revenue and other income for the reporting period amounted to MUSD 984.0 (MUSD 1,383.9) and was comprised of net sales of oil and gas and other revenue as detailed in Note 1.
Net sales of oil and gas for the reporting period amounted to MUSD 967.8 (MUSD 1,366.7). The average price achieved by Lundin Petroleum for a barrel of oil equivalent from own production amounted to USD 63.09 (USD 68.04) and is detailed in the following table. The average Dated Brent price for the reporting period amounted to USD 65.95 (USD 70.58) per barrel.
Net sales of oil and gas from own production for the reporting period are detailed in Note 3 and were comprised as follows:
| Sales from own production Average price per boe expressed in USD |
1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Crude oil sales | |||||
| – Quantity in Mboe | 12,011.0 | 6,012.5 | 13,715.8 | 6,757.7 | 26,834.7 |
| – Average price per bbl | 67.54 | 70.30 | 70.08 | 74.04 | 69.97 |
| Gas and NGL sales | |||||
| – Quantity in Mboe | 1,992.2 | 823.0 | 1,571.7 | 788.8 | 3,682.0 |
| – Average price per boe | 36.25 | 29.68 | 50.28 | 49.55 | 52.74 |
| Total sales | |||||
| – Quantity in Mboe | 14,003.2 | 6,835.5 | 15,287.5 | 7,546.5 | 30,516.7 |
| – Average price per boe | 63.09 | 65.41 | 68.04 | 71.48 | 67.89 |
The table above excludes crude oil revenue from third party activities.
Net sales of crude oil from third party activities for the reporting period amounted to MUSD 84.3 (MUSD 326.5) and consisted of Grane Blend crude oil purchased from outside the Group by Lundin Petroleum Marketing SA and sold to the market.
Sales of oil and gas are recognised when the risk of ownership is transferred to the purchaser.
Other income for the reporting period amounted to MUSD 16.2 (MUSD 17.2) and mainly included tariff income of MUSD 13.2 (MUSD 15.4) which is due to net income from Ivar Aasen tariffs paid to Edvard Grieg.
Production costs including under/over lift movements and inventory movements for the reporting period amounted to MUSD 77.0 (MUSD 72.0) and are detailed in Note 2. The total production cost per barrel of oil equivalent produced is detailed in the table below:
| 1 Jan 2019- | 1 Apr 2019- | 1 Jan 2018- | 1 Apr 2018- | 1 Jan 2018- | |
|---|---|---|---|---|---|
| 30 Jun 2019 | 30 Jun 2019 | 30 Jun 2018 | 30 Jun 2018 | 31 Dec 2018 | |
| Production costs | 6 months | 3 months | 6 months | 3 months | 12 months |
| Cost of operations | |||||
| – In MUSD | 56.4 | 28.4 | 47.4 | 20.1 | 102.5 |
| – In USD per boe | 4.02 | 4.09 | 3.19 | 2.72 | 3.46 |
| Tariff and transportation expenses | |||||
| – In MUSD | 19.8 | 8.8 | 17.2 | 8.3 | 35.2 |
| – In USD per boe | 1.41 | 1.28 | 1.16 | 1.13 | 1.19 |
| Operating costs | |||||
| – In MUSD | 76.2 | 37.2 | 64.6 | 28.4 | 137.7 |
| – In USD per boe1 | 5.43 | 5.37 | 4.35 | 3.85 | 4.65 |
| Change in under/over lift position | |||||
| – In MUSD | -1.6 | -0.4 | 3.1 | -0.2 | 7.0 |
| – In USD per boe | -0.11 | -0.06 | 0.21 | -0.03 | 0.24 |
| Change in inventory position | |||||
| – In MUSD | 0.3 | 0.3 | 0.6 | 0.0 | 0.6 |
| – In USD per boe | 0.02 | 0.04 | 0.04 | 0.00 | 0.02 |
| Other | |||||
| – In MUSD | 2.1 | 1.0 | 3.7 | 1.9 | 7.1 |
| – In USD per boe | 0.15 | 0.15 | 0.24 | 0.25 | 0.24 |
| Production costs | |||||
| – In MUSD | 77.0 | 38.1 | 72.0 | 30.1 | 152.4 |
| – In USD per boe | 5.49 | 5.50 | 4.84 | 4.07 | 5.15 |
Note: USD per boe is calculated by dividing the cost by total production volume for the period.
1 The numbers in this table are excluding tariff income netting. Lundin Petroleum's operating cost for the reporting period of USD 5.43 (USD 4.35) per barrel is reduced to USD 4.49 (USD 3.30) when tariff income is netted off. The operating cost for the second quarter of USD 5.37 (USD 3.85) per barrel is reduced to USD 4.46 (USD 2.78) when tariff income is netted off.
The total cost of operations for the reporting period amounted to MUSD 56.4 (MUSD 47.4) and the total cost of operations excluding operational projects amounted to MUSD 50.2 (MUSD 43.0). The increase compared to the comparative period included the reversal in the comparative period of an accrual as a result of the termination of production from the Brynhild field of MUSD 5.5.
The cost of operations per barrel for the reporting period amounted to USD 4.02 (USD 3.19) including operational projects and USD 3.58 (USD 2.89) excluding operational projects.
Tariff and transportation expenses for the reporting period amounted to MUSD 19.8 (MUSD 17.2) or USD 1.41 (USD 1.16) per barrel. The increase compared to the comparative period is driven by higher pipeline tariff rates in combination with freight costs for crude oil sales in relation to some cargoes being sold on a CFR basis during the period.
Sales quantities in a period can differ from production quantities as a result of permanent and timing differences. Timing differences can arise due to under/over lift of entitlement, inventory, storage and pipeline balances effects. The change in under/over lift position is valued at production cost including depletion cost, and amounted to an income of MUSD 1.6 (expense of MUSD 3.1) in the reporting period due to the timing of the cargo liftings compared to production. Sales quantities and production quantities are detailed in the table below:
| 1 Jan 2019- | 1 Apr 2019- | 1 Jan 2018- | 1 Apr 2018- | 1 Jan 2018- | |
|---|---|---|---|---|---|
| Change in over/underlift position | 30 Jun 2019 | 30 Jun 2019 | 30 Jun 2018 | 30 Jun 2018 | 31 Dec 2018 |
| In Mboepd | 6 months | 3 months | 6 months | 3 months | 12 months |
| Production volumes | 77.5 | 76.1 | 82.1 | 81.2 | 81.1 |
| Sales volumes from own production | -77.4 | -75.1 | 84.5 | 82.9 | 83.6 |
| Change in underlift / overlift position | 0.1 | 1.0 | -2.4 | -1.7 | -2.5 |
Other costs for the reporting period amounted to MUSD 2.1 (MUSD 3.7) and related to the business interruption insurance.
Depletion and decommissioning costs for the reporting period amounted to MUSD 196.6 (MUSD 232.7) at an average rate of USD 14.02 (USD 15.65) per barrel and are detailed in Note 3. The lower depletion costs for the reporting period compared to the comparative period is due to lower production volumes in combination with a lower depletion rate per barrel in USD terms as the depletion rate per barrel is calculated in Norwegian Kroner and with the Norwegian Kroner having weakened the USD depletion rate has been reduced.
Exploration costs expensed in the income statement for the reporting period amounted to MUSD 70.9 (MUSD 5.9) and are detailed in Note 3. Exploration and appraisal costs are capitalised as they are incurred. When exploration drilling is unsuccessful, the capitalised costs are expensed. All capitalised exploration costs are reviewed on a regular basis and are expensed where their recoverability is considered highly uncertain.
Purchase of crude oil from third parties for the reporting period amounted to MUSD 84.3 (MUSD 324.8) and related to Grane Blend crude oil purchased from outside the Group.
The general administrative and depreciation expenses for the reporting period amounted to MUSD 14.5 (MUSD 13.5) which included a charge of MUSD 2.3 (MUSD 2.4) in relation to the Group's long-term incentive plans (LTIP), see also Remuneration section on page 13. Fixed asset depreciation expenses for the reporting period amounted to MUSD 3.4 (MUSD 1.4) with the increase compared to the comparative period mainly caused by the implementation of IFRS 16 with effective date 1 January 2019 based on which depreciation expenses relating to right of use assets are included in the reporting period.
Finance income for the reporting period amounted to MUSD 51.5 (MUSD 197.4) and is detailed in Note 4.
The net foreign currency exchange gain for the reporting period amounted to MUSD 34.7 (MUSD 9.6). Foreign exchange movements occur on the settlement of transactions denominated in foreign currencies and the revaluation of working capital and loan balances to the prevailing exchange rate at the balance sheet date where those monetary assets and liabilities are held in currencies other than the functional currencies of the Group's reporting entities. Lundin Petroleum has hedged certain foreign currency capital expenditure amounts against the US Dollar and for the reporting period, the net realised exchange loss on these settled foreign exchange hedges amounted to MUSD 8.9 (gain of MUSD 7.6).
The US Dollar strengthened against the Euro during the reporting period resulting in a net foreign currency exchange loss on the US Dollar denominated external loan, which is borrowed by a subsidiary using Euro as functional currency. In addition, the Norwegian Krone strengthened against the Euro in the reporting period, generating a net foreign currency exchange gain on an intercompany loan balance denominated in Norwegian Krone.
The reserve-based lending facility was successfully re-negotiated during the comparative period, resulting in the interest rate margin over LIBOR being reduced from 3.15 percent to a current rate of 2.25 percent effective as of 1 June 2018. The amendment of the interest rate margin resulted in an accounting gain of MUSD 183.7 in the comparative period in accordance with IFRS 9.
The result on interest rate hedge settlements amounted to a gain of MUSD 16.0 (loss of MUSD 1.7).
Finance costs for the reporting period amounted to MUSD 78.4 (MUSD 96.1) and are detailed in Note 5.
Interest expenses for the reporting period amounted to MUSD 31.9 (MUSD 49.1) and represented the portion of interest charged to the income statement. An additional amount of interest of MUSD 51.3 (MUSD 43.1) associated with the funding of the Norwegian development projects was capitalised in the reporting period. The total interest expense reduced compared to the comparative period mainly due to lower drawn debt under the reserve-based lending facility.
The amortisation of the deferred financing fees for the reporting period amounted to MUSD 8.4 (MUSD 9.2) and related to the fees incurred in establishing the reserve-based lending facility. The fees are being expensed over the expected life of the facility.
Loan facility commitment fees for the reporting period amounted to MUSD 7.0 (MUSD 6.8) with the lower drawn debt under the reservebased lending facility compared to the comparative period being offset by a lower margin for commitment fees as agreed through the amendment of the facility effective as of 1 June 2018.
The unwinding of the loan modification gain for the reporting period amounted to MUSD 21.1 (MUSD 3.7) and related to the expensing of the accounting gain from the re-negotiated improved borrowing terms for the reserve-based lending facility over the period of usage of the facility.
As a result of the successful re-negotiated reserve-based lending facility during the comparative period, loan modification fees amounting to MUSD 17.3 were incurred. The net accounting gain in the comparative period when offsetting these loan modification fees against the reported loan modification gain amounted to MUSD 166.4. The associated deferred taxes amounted to MUSD 68.3 resulting in an after tax accounting gain of MUSD 98.1 in the comparative period that unwinds to the income statement over the remaining period of the facility.
Share in result of associated company for the reporting period amounted to MUSD -1.0 (MUSD -0.0) and related to the share in the result of the investment in Mintley Caspian Ltd.
The overall tax charge for the reporting period amounted to MUSD 363.1 (MUSD 569.1) and is detailed in Note 6.
The current tax charge for the reporting period amounted to MUSD 43.8 (MUSD 8.7) of which MUSD 43.8 (MUSD 8.2) related to Norway. The current tax charge for Norway related to Corporate Tax only with no current tax charge to the income statement in relation to the Special Petroleum Tax (SPT) as the Company continues to be sheltered from SPT tax losses. The paid tax installments in Norway during the reporting period amounted to MUSD 15.8 which has resulted in an increase in current tax liabilities compared to the comparative period.
The deferred tax charge for the reporting period amounted to MUSD 319.3 (MUSD 560.4) and related to Norway. The deferred tax amount arises primarily where there is a difference in depletion for tax and accounting purposes.
The Group operates in various countries and fiscal regimes where corporate income tax rates are different from the regulations in Sweden. Corporate income tax rates for the Group vary between 21.4 and 78 percent. The effective tax rate for the reporting period is affected by items which do not receive a full tax credit such as the reported net foreign currency exchange results, Norwegian financial items and by the uplift allowance applicable in Norway for development expenditures against the offshore tax regime.
Oil and gas properties amounted to MUSD 5,859.3 (MUSD 5,341.1) and are detailed in Note 7.
Development, exploration and appraisal expenditure incurred for the reporting period was as follows:
| Development expenditure in MUSD |
1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Norway | 357.2 | 195.5 | 376.3 | 205.3 | 701.9 |
| Development expenditure | 357.2 | 195.5 | 376.3 | 205.3 | 701.9 |
Development expenditure of MUSD 357.2 (MUSD 376.3) was incurred in Norway during the reporting period, primarily on the Johan Sverdrup field. In addition an amount of MUSD 51.3 (MUSD 43.1) of interest was capitalised.
| Exploration and appraisal expenditure in MUSD |
1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Norway | 183.3 | 96.0 | 172.7 | 118.6 | 310.6 |
| Exploration and appraisal expenditure | 183.3 | 96.0 | 172.7 | 118.6 | 310.6 |
Exploration and appraisal expenditure of MUSD 183.3 (MUSD 172.7) was incurred in Norway during the reporting period, primarily for the exploration and appraisal wells as summarized on pages 4 and 5.
Other tangible fixed assets amounted to MUSD 48.4 (MUSD 13.6) and are detailed in Note 8. Following the implementation of IFRS 16 with effective date 1 January 2019, the company recognized right of use assets that amounted to MUSD 35.2 (MUSD –).
Goodwill associated with the accounting for the Edvard Grieg transaction during 2016 amounted to MUSD 128.1 (MUSD 128.1).
Inventories amounted to MUSD 38.8 (MUSD 36.5) and included both well supplies and hydrocarbon inventories.
Trade and other receivables amounted to MUSD 201.6 (MUSD 216.6) and are detailed in Note 9. Trade receivables, which are all current, amounted to MUSD 146.4 (MUSD 153.7). Underlift amounted to MUSD 9.5 (MUSD 1.9) and was attributable to an underlift position on the producing fields, mainly from the Edvard Grieg field. Joint operations debtors relating to various joint venture receivables amounted to MUSD 12.9 (MUSD 17.0). Prepaid expenses and accrued income amounted to MUSD 31.7 (MUSD 26.9) and represented mainly prepaid operational and insurance expenditure. Other current assets amounted to MUSD 1.1 (MUSD 17.1) with the reduction mainly caused by the receipt during the reporting period of the short term receivable from IPC relating to certain working capital balances following the IPC spin-off.
Derivative instruments amounted to MUSD 6.9 (MUSD 34.0) and related to the marked-to-market gain on the outstanding interest rate hedge contracts due to be settled within twelve months.
Cash and cash equivalents amounted to MUSD 100.7 (MUSD 66.8) of which MUSD 10.8 (MUSD 16.7) is restricted. Cash balances are mainly held to meet ongoing operational funding requirements.
Financial liabilities amounted to MUSD 3,313.5 (MUSD 3,262.0) and are detailed in Note 10. Bank loans amounted to MUSD 3,460 (MUSD 3,465.0) and related to the outstanding loan under the reserve-based lending facility. Capitalised financing fees relating to the establishment of the facility amounted to MUSD 46.8 (MUSD 54.1) and are being amortised over the expected life of the facility. The capitalised loan modification gain relating to the re-negotiated improved borrowing terms for the lending facility during 2018 amounted to MUSD 129.9 (MUSD 148.9) and are being amortised over the expected life of the facility. The lease commitments amounted to MUSD 30.2 (MUSD –) and related to the long-term portion of the lease commitments following the implementation of IFRS 16 with effective date 1 January 2019. The short-term portion of the lease commitments was classified as current liabilities.
Provisions amounted to MUSD 511.0 (MUSD 489.1) and are detailed in Note 11. The provision for site restoration amounted to MUSD 506.7 (MUSD 483.9) and related to the long-term portion of the future decommissioning obligations. The increase mainly reflects the additional liability for the Johan Sverdrup development project with the installation of two platforms during the reporting period. The short-term portion of the future decommissioning obligations was classified as current liabilities.
Deferred tax liabilities amounted to MUSD 2,468.7 (MUSD 2,103.8). The provision mainly arises on the excess of book value over the tax value of oil and gas properties. Deferred tax assets are netted off against deferred tax liabilities where they relate to the same jurisdiction.
Derivative instruments amounted to MUSD 102.7 (MUSD 64.9) and related to the marked-to-market loss on outstanding interest rate and currency hedge contracts due to be settled after twelve months.
Current financial liabilities amounted to MUSD 17.1 (MUSD –) and are detailed in Note 10. Current financial liabilities related to the short-term portion of the lease commitments and to the obligation to settle the 2016 long-term performance based incentive plan in respect of Group management and a number of key employees, see also the Remuneration section on page 13.
Dividends amounted to MUSD 375.6 (MUSD –) and related to the cash dividend approved by the AGM held on 29 March 2019 in Stockholm, which will be paid in quarterly installments.
Trade and other payables amounted to MUSD 237.3 (MUSD 200.9) and are detailed in Note 12. Overlift amounted to MUSD 7.8 (MUSD 1.7) and was attributable to an overlift position in relation to the Alvheim Area. Joint operations creditors and accrued expenses amounted to MUSD 174.8 (MUSD 147.4) and related to activity in Norway. Other accrued expenses amounted to MUSD 21.7 (MUSD 17.6) and other current liabilities amounted to MUSD 14.0 (MUSD 7.6).
Derivative instruments amounted to MUSD 22.3 (MUSD 20.0) and related to the marked-to-market loss on outstanding interest rate and currency hedge contracts due to be settled within twelve months.
Current tax liabilities amounted to MUSD 100.0 (MUSD 70.4) and related mainly to Corporate Tax due in Norway.
Current provisions amounted to MUSD 37.7 (MUSD 12.5) and are detailed in Note 11. The short-term portion of the future decommissioning obligations amounted to MUSD 34.0 (MUSD 6.6) mainly relating to the Brynhild field and the current portion of the provision for Lundin Petroleum's Unit Bonus Plan amounted to MUSD 3.7 (MUSD 5.9).
The business of the Parent Company is investment in and management of oil and gas assets. The net result for the Parent Company for the reporting period amounted to MSEK 4,560.8 (MSEK 1,662.2). The net result for the reporting period included MSEK 4,638.1 (MSEK 1,714.6) financial income as a result of received dividends from a subsidiary. The net result excluding received dividends amounted to MSEK -77.3 (MSEK -52.4).
The net result for the reporting period included general and administrative expenses of MSEK 86.6 (MSEK 66.8) and net finance income of MSEK 0.8 (MSEK 6.1) when excluding the received dividends as mentioned above.
Pledged assets of MSEK 55,118.9 (MSEK 55,118.9) relate to the carrying value of the pledge of the shares in respect of the reserve-based lending facility entered into by its wholly-owned subsidiary Lundin Petroleum Holding BV, see also the Liquidity section below.
During the reporting period, the Group has entered into various transactions with related parties on a commercial basis including the transactions described below.
The Group has purchased oil from the Equinor group on an arm's-length basis amounting to MUSD – (MUSD 203.1).
The Group has sold oil and related products to the Equinor group on an arm's-length basis amounting to MUSD 50.6 (MUSD 650.2).
As at the date of the IPC spin-off, the Group had a residual receivable for working capital from IPC of MUSD 27.4 of which the last portion was received during the reporting period.
In February 2016, Lundin Petroleum entered into a committed seven year senior secured reserve-based lending facility of USD 5.0 billion. The facility was amended during the second quarter of 2018 resulting in the interest rate margin over LIBOR being reduced from 3.15 percent to a current rate of 2.25 percent. The facility is secured against certain cash flows generated by the Group. The amount available under the facility is recalculated every twelve months based upon the calculated cash flow generated by certain producing fields and fields under development at an oil price and economic assumptions agreed with the banking syndicate providing the facility. The facility is secured by a pledge over the shares of certain Group companies, a pledge over the Company's working interest in some production licenses and a charge over some of the bank accounts of the pledged companies.
The Swedish Prosecution Authority issued a notification of a corporate fine and forfeiture of economic benefits against Lundin Petroleum in relation to past operations in Sudan from 1997 to 2003. The notification indicated that the Prosecutor might seek a corporate fine of SEK 3 million and forfeiture of economic benefits from the alleged offense in the amount of SEK 3,282 million, based on the profit of the sale of the Block 5A asset in 2003 of SEK 720 million. Any potential corporate fine or forfeiture would only be imposed after the conclusion of a trial, should one occur. The investigation is in its tenth year and Lundin Petroleum remains convinced that there are absolutely no grounds for any allegations of wrongdoing by any Company representative and the Company will firmly contest any corporate fine or forfeiture of economic benefits. The Company considers this to be a contingent liability and therefore no provision has been recognised.
Lundin Petroleum announced on 7 July 2019 a proposed transaction with Equinor which involves a proposal to redeem 16 percent of the outstanding Lundin Petroleum shares and to sell a 2.6 percent stake in the Johan Sverdrup development project. The highlights of the proposed transaction are:
Lundin Petroleum will fund the transaction in part by utilizing funds under the existing USD 5 billion reserve-based lending facility and in part through a short term bridge facility of up to USD 500 million which will provide additional liquidity, until the completion of the divestment of the 2.6 percent in the Johan Sverdrup development project.
An Extraordinary General Meeting will be held on 31 July 2019 in Stockholm regarding the proposed transaction.
The transaction was subject to RBL facility lender approval as well as subject to the company entering into a short term bridge facility agreement. Both these conditions were met during July 2019. The 2.6 percent divestment of Johan Sverdrup is subject to customary government approvals in Norway. The transaction is anticipated to complete in the third or fourth quarter of 2019.
During July 2019, Lundin Petroleum entered into forward currency hedges to meet its SEK funding requirements relating to the consideration for the share redemption as summarised below:
| Buy | Sell | Average contractual Exchange rate |
Settlement date |
|---|---|---|---|
| MSEK 14,510.3 | MUSD 1,549.5 | SEK 9.36:USD 1 | 31 Jul 2019 |
During July 2019, Lundin Petroleum entered into additional interest rate hedge contracts as summarised follows:
| Borrowings expressed in MUSD |
Fixing of floating LIBOR average rate per annum |
Settlement period |
|---|---|---|
| 1,300 | 1.67% | Jan 2020 – Dec 2020 |
| 1,100 | 1.58% | Jan 2021 – Dec 2021 |
| 900 | 1.68% | Jan 2022 – Dec 2022 |
| 2,000 | 1.75% | Jan 2023 – Dec 2023 |
| 1,500 | 1.91% | Jan 2024 – Dec 2024 |
In July 2019, the Rumpetroll prospect in PL869 in the Alvheim area was drilled and was dry and will be expensed in the third quarter.
Lundin Petroleum AB's issued share capital amounted to SEK 3,478,713 represented by 340,386,445 shares with a quota value of SEK 0.01 each (rounded off).
During 2017, Lundin Petroleum purchased 1,233,310 of its own shares at an average price of SEK 186.14 based on the approval granted at the AGM 2017. During 2018, Lundin Petroleum purchased an additional 640,000 of its own shares at an average price of SEK 186.77 based on the approval granted at the AGM 2017 resulting in 1,873,310 of its own shares held by the Company.
The AGM of Lundin Petroleum held on 29 March 2019 in Stockholm approved a cash dividend distribution for the year 2018 of USD 1.48 per share, to be paid in quarterly installments of USD 0.37 per share. Before payment, each quarterly dividend of USD 0.37 per share shall be converted into a SEK amount, and paid out in SEK, based on the USD to SEK exchange rate published by Sweden's central bank (Riksbanken) four business days prior to each record date (rounded off to the nearest whole SEK 0.01 per share). The final USD equivalent amount received by the shareholders may therefore slightly differ depending on what the USD to SEK exchange rate is on the date of the dividend payment. Based on the number of shares outstanding, excluding own shares held by the Company, the approved dividend distribution amounted to MSEK 4,638.7, equaling MUSD 501.0 based on the exchange rate on the date of AGM approval.
The first dividend payment was made on 5 April 2019 and the second dividend payment was made on 8 July 2019. The third dividend payment is expected to be paid around 7 October 2019, with an expected record date of 2 October 2019 and an expected ex-dividend date of 1 October 2019. The fourth dividend payment is expected to be paid around 9 January 2020, with an expected record date of 3 January 2020 and an expected ex-dividend date of 2 January 2020.
In order to comply with Swedish company law, a maximum total SEK amount shall be pre-determined to ensure that the dividend distributed does not exceed the available distributable reserves of the Company and such maximum amount for the 2018 dividend has been set to a cap of SEK 7.665 billion (i.e., SEK 1.916 billion per quarter). If the total dividend would exceed the cap of SEK 7.665 billion, the dividend will be automatically adjusted downwards so that the total dividend corresponds to the cap of SEK 7.665 billion.
Lundin Petroleum's principles for remuneration and details of the long-term incentive plans are provided in the Company's 2018 Annual Report and in the materials provided to shareholders in respect of the 2019 AGM, available on www.lundin-petroleum.com
The number of units relating to the awards made in 2017, 2018 and 2019 under the Unit Bonus Plan outstanding as at 30 June 2019 were 188,064, 226,389 and 190,161 respectively.
The AGM 2018 resolved a long-term performance based incentive plan in respect of Group management and a number of key employees. The plan is effective from 1 July 2018 and the 2018 award is accounted for from the second half of 2018. The total outstanding number of awards at 30 June 2019 was 278,917 and the awards vest over three years from 1 July 2018 subject to certain performance conditions being met. Each original award was fair valued at the date of grant at SEK 167.10 using an option pricing model.
The 2017 plan is effective from 1 July 2017 and the total outstanding number of awards at 30 June 2019 was 355,954 and the awards vest over three years from 1 July 2017 subject to certain performance conditions being met. Each original award was fair valued at the date of grant at SEK 100.10 using an option pricing model.
The 2016 plan is effective from 1 July 2016 and the total outstanding number of awards at 30 June 2019 was 409,343 and the awards vest over three years from 1 July 2016 subject to certain performance conditions being met. The outstanding number of awards increased compared to the original number of awards as a result of the dividend distribution of the IPC business as per the plan rules. Each original award was fair valued at the date of grant at SEK 89.30 using an option pricing model. Awards given to employees now employed by IPC following the IPC spin-off have been pro-rated until the spin-off date 24 April 2017.
This interim report has been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial Reporting, and the Swedish Annual Accounts Act (SFS 1995:1554).
IFRS 16 has come into effect with effective date 1 January 2019. IFRS16 Leases, addresses the recognition in the balance sheet of each contract, with some exceptions, that meets the definition of a lease as a right of use asset and lease liability, while lease payments are to be reflected as interest expense and a reduction of lease liability. The Group has made the following transition choices in relation to IFRS 16: (a) application of the modified retrospective method, (b) right of use assets are measured at an amount equal to the lease liability and (c) leases with a less than 12 months remaining lease term at year end 2018 are not reflected as leases. The Group has made the following application policy choice: short term leases (less than 12 months) and leases of low value assets are not reflected in the balance sheet, but will be expensed as incurred.
Lundin Petroleum has assessed the impact of IFRS 16 on the financial statements of the Group and only identified one relevant contract containing a lease with no material impact on the financial statements of the Group. The Company accounted for right of use assets and lease commitments amounting to MUSD 36.6 per effective date 1 January 2019.
Lundin Petroleum has changed its accounting principle for revenue recognition relating to under/overlift balances. The Group previously recognized income based on its produced volumes (entitlement method) for the period. Lundin Petroleum has decided to change the accounting treatment of such under/overlift so that from 1 April 2019 the income will reflect sold volumes (sales method). This means that changes in under/overlift balances are no longer reported as other income valued at market price, but will instead be reported as an adjustment to cost valued at production cost including depletion. Comparative figures have been restated in line with IAS 8 as per the table below:
| Restated net result previous quarters MUSD |
Q1 2019 | Q4 2018 | Q3 2018 | Q2 2018 | Q1 2018 |
|---|---|---|---|---|---|
| Reported net result previous quarters | 54.9 | -105.3 | 62.6 | 36.0 | 228.8 |
| Changes due to change in accounting principle | |||||
| Adjustment in other income | -7.5 | 41.2 | -31.8 | 4.4 | 9.5 |
| Adjustment in production costs | 1.2 | -9.0 | 5.1 | 0.2 | -3.3 |
| Adjustment in deferred tax | 4.9 | -25.1 | 20.8 | -3.6 | -4.8 |
| Impact of change in accounting principle | -1.4 | 7.1 | -5.9 | 1.0 | 1.4 |
| Restated net result previous quarters | 53.5 | -98.2 | 56.7 | 37.0 | 230.2 |
Apart from the changes in accounting principles as mentioned above, the accounting policies adopted are in all other aspects consistent with those followed in the preparation of the Group's annual financial statements for the year ended 31 December 2018.
The financial reporting of the Parent Company has been prepared in accordance with accounting principles generally accepted in Sweden, applying RFR 2 Reporting for legal entities, issued by the Swedish Financial Reporting Board and the Annual Accounts Act (SFS 1995:1554).
Under Swedish company regulations it is not allowed to report the Parent Company results in any other currency than Swedish Krona or Euro and consequently the Parent Company's financial information is reported in Swedish Krona and not the Group's reporting currency of US Dollar.
The objective of Business Risk Management is to identify, understand and manage threats and opportunities within the business on a continual basis. This objective is achieved by creating a mandate and commitment to risk management at all levels of the business. This approach actively addresses risk as an integral and continual part of decision making within the Group and is designed to ensure that all risks are identified, fully acknowledged, understood and communicated well in advance. The ability to manage and or mitigate these risks represents a key component in ensuring that the business aim of the Company is achieved. Nevertheless, oil and gas exploration, development and production involve high operational and financial risks, which even a combination of experience, knowledge and careful evaluation may not be able to fully eliminate or which are beyond the Company's control.
A detailed analysis of Lundin Petroleum's strategic, operational, financial and external risks and mitigation of those risks through risk management is described in Lundin Petroleum's 2018 Annual Report.
Lundin Petroleum has entered into forward currency hedges to meet part of its future NOK capital requirements relating to its committed field development projects and to meet part of its future NOK Corporate Tax requirements. At 30 June 2019, Lundin Petroleum had outstanding currency hedges as summarised below:
| Buy | Sell | Average contractual Exchange rate |
Settlement period |
|---|---|---|---|
| MNOK 2,196.4 | MUSD 266.6 | NOK 8.24:USD 1 | Jul 2019 – Dec 2019 |
| MNOK 2,405.0 | MUSD 306.0 | NOK 7.86:USD 1 | Jan 2020 – Dec 2020 |
| MNOK 2,130.0 | MUSD 272.7 | NOK 7.81:USD 1 | Jan 2021 – Dec 2021 |
| MNOK 1,200.0 | MUSD 158.2 | NOK 7.59:USD 1 | Jan 2022 – Dec 2022 |
| MNOK 410.0 | MUSD 51.0 | NOK 8.04:USD 1 | Jan 2023 – Dec 2023 |
Lundin Petroleum entered into interest rate hedge contracts and at 30 June 2019 had outstanding interest rate hedge contracts as follows:
| Borrowings expressed in MUSD |
Fixing of floating LIBOR average rate per annum |
Settlement period |
|---|---|---|
| 3,000 | 1.42% | Jul 2019 – Dec 2019 |
| 2,000 | 2.15% | Jan 2020 – Dec 2020 |
| 2,000 | 2.67% | Jan 2021 – Dec 2021 |
| 2,000 | 2.74% | Jan 2022 – Dec 2022 |
Under IFRS 9, subject to hedge effectiveness testing, all of the hedges are treated as effective and changes to the fair value are reflected in other comprehensive income.
For the preparation of the financial statements for the reporting period, the following currency exchange rates have been used.
| 30 Jun 2019 | 30 Jun 2018 | 31 Dec 2018 | ||||
|---|---|---|---|---|---|---|
| Average | Period end | Average | Period end | Average | Period end | |
| 1 USD equals NOK | 8.6118 | 8.5183 | 7.9264 | 8.1588 | 8.1329 | 8.6885 |
| 1 USD equals Euro | 0.8851 | 0.8787 | 0.8259 | 0.8578 | 0.8464 | 0.8734 |
| 1 USD equals SEK | 9.3118 | 9.2823 | 8.3902 | 8.9664 | 8.6921 | 8.9562 |
| 1 Jan 2019- 30 Jun 2019 |
1 Apr 2019- 30 Jun 2019 |
1 Jan 2018- 30 Jun 2018 |
1 Apr 2018- 30 Jun 2018 |
1 Jan 2018- 31 Dec 2018 |
||
|---|---|---|---|---|---|---|
| Expressed in MUSD | Note | 6 months | 3 months | 6 months | 3 months | 12 months |
| Revenue and other income | 1 | |||||
| Revenue | 967.8 | 491.3 | 1,366.7 | 672.5 | 2,607.9 | |
| Other income | 16.2 | 8.6 | 17.2 | 9.0 | 32.8 | |
| 984.0 | 499.9 | 1,383.9 | 681.5 | 2,640.7 | ||
| Cost of sales | ||||||
| Production costs | 2 | -77.0 | -38.1 | -72.0 | -30.1 | -152.4 |
| Depletion and decommissioning costs | -196.6 | -96.8 | -232.7 | -114.2 | -458.0 | |
| Exploration costs | -70.9 | -33.6 | -5.9 | -6.2 | -53.2 | |
| Purchase of crude oil from third parties | -84.3 | -44.2 | -324.8 | -132.6 | -533.8 | |
| Gross profit | 3 | 555.2 | 287.2 | 748.5 | 398.4 | 1,443.3 |
| General, administration and depreciation | ||||||
| expenses | -14.5 | -7.4 | -13.5 | -7.2 | -24.6 | |
| Operating profit | 540.7 | 279.8 | 735.0 | 391.2 | 1,418.7 | |
| Net financial items | ||||||
| Finance income | 4 | 51.5 | 42.4 | 197.4 | 35.0 | 192.2 |
| Finance costs | 5 | -78.4 | -38.5 | -96.1 | -57.1 | -345.4 |
| -26.9 | 3.9 | 101.3 | -22.1 | -153.2 | ||
| Share in result of associated company | -1.0 | -0.8 | -0.0 | -0.0 | -1.3 | |
| Profit before tax | 512.8 | 282.9 | 836.3 | 369.1 | 1,264.2 | |
| Income tax | 6 | -363.1 | -186.7 | -569.1 | -332.1 | -1,038.5 |
| Net result | 149.7 | 96.2 | 267.2 | 37.0 | 225.7 | |
| Attributable to: | ||||||
| Shareholders of the Parent Company | 149.7 | 96.2 | 267.2 | 37.0 | 225.7 | |
| Non-controlling interest | – | – | – | – | – | |
| 149.7 | 96.2 | 267.2 | 37.0 | 225.7 | ||
| Earnings per share – USD | 0.44 | 0.28 | 0.79 | 0.11 | 0.67 | |
| Earnings per share fully diluted – USD | 0.44 | 0.28 | 0.79 | 0.11 | 0.66 | |
| Expressed in MUSD | 1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Net result | 149.7 | 96.2 | 267.2 | 37.0 | 225.7 |
| Items that may be subsequently reclassified to profit or loss: |
|||||
| Exchange differences foreign operations | 12.6 | -14.0 | 12.3 | 21.2 | 1.5 |
| Cash flow hedges | -69.6 | -41.7 | 39.2 | -26.2 | -74.1 |
| Other comprehensive income, net of tax | -57.0 | -55.7 | 51.5 | -5.0 | -72.6 |
| Total comprehensive income | 92.7 | 40.5 | 318.7 | 32.0 | 153.1 |
| Attributable to: | |||||
| Shareholders of the Parent Company | 92.7 | 40.5 | 318.7 | 32.0 | 153.1 |
| Non-controlling interest | – | – | – | – | – |
| 92.7 | 40.5 | 318.7 | 32.0 | 153.1 |
| Expressed in MUSD | Note | 30 June 2019 | 31 December 2018 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Oil and gas properties | 7 | 5,859.3 | 5,341.1 |
| Other tangible fixed assets | 8 | 48.4 | 13.6 |
| Goodwill | 128.1 | 128.1 | |
| Financial assets | 0.4 | 0.4 | |
| Derivative instruments | 13 | – | 2.7 |
| Total non-current assets | 6,036.2 | 5,485.9 | |
| Current assets | |||
| Inventories | 38.8 | 36.5 | |
| Trade and other receivables | 9 | 201.6 | 216.6 |
| Derivative instruments | 13 | 6.9 | 34.0 |
| Cash and cash equivalents | 100.7 | 66.8 | |
| Total current assets | 348.0 | 353.9 | |
| TOTAL ASSETS | 6,384.2 | 5,839.8 | |
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Shareholders´ equity | -801.7 | -383.8 | |
| Liabilities | |||
| Non-current liabilities | |||
| Financial liabilities | 10 | 3,313.5 | 3,262.0 |
| Provisions | 11 | 511.0 | 489.1 |
| Deferred tax liabilities | 2,468.7 | 2,103.8 | |
| Derivative instruments | 13 | 102.7 | 64.9 |
| Total non-current liabilities | 6,395.9 | 5,919.8 | |
| Current liabilities | |||
| Financial liabilities | 10 | 17.1 | – |
| Dividends | 375.6 | – | |
| Trade and other payables | 12 | 237.3 | 200.9 |
| Derivative instruments | 13 | 22.3 | 20.0 |
| Current tax liabilities | 100.0 | 70.4 | |
| Provisions | 11 | 37.7 | 12.5 |
| Total current liabilities | 790.0 | 303.8 | |
| Total liabilities | 7,185.9 | 6,223.6 | |
| TOTAL EQUITY AND LIABILITIES | 6,384.2 | 5,839.8 |
| Expressed in MUSD | 1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Cash flows from operating activities | |||||
| Net result | 149.7 | 96.2 | 267.2 | 37.0 | 225.7 |
| Adjustments for: | |||||
| Exploration costs | 70.9 | 33.6 | 5.9 | 6.2 | 53.2 |
| Depletion, depreciation and amortisation | 200.0 | 98.5 | 234.1 | 114.9 | 460.6 |
| Current tax | 43.8 | 17.4 | 8.7 | 8.4 | 90.4 |
| Deferred tax | 319.3 | 169.3 | 560.4 | 323.7 | 948.1 |
| Long-term incentive plans | 6.7 | – | 9.9 | 6.2 | 14.6 |
| Foreign currency exchange gain/ loss | -43.6 | -39.0 | -9.7 | 147.0 | 162.5 |
| Interest expense | 31.9 | 15.1 | 49.1 | 24.6 | 88.7 |
| Loan modification gain | – | – | -183.7 | -183.7 | -183.7 |
| Loan modification fees | – | – | 17.3 | 17.3 | 17.3 |
| Unwinding of loan modification gain | 21.1 | 10.5 | 3.7 | 3.7 | 26.1 |
| Capitalised financing fees | 8.4 | 4.2 | 9.2 | 4.6 | 17.8 |
| Other | 9.2 | 5.0 | 3.6 | – | 12.8 |
| Interest received | 0.8 | 0.5 | 0.6 | 0.4 | 1.1 |
| Interest paid | -83.2 | -42.3 | -91.9 | -45.9 | -176.0 |
| Income taxes paid / received | -15.8 | -9.4 | -0.7 | -0.4 | -15.8 |
| Changes in working capital | 35.3 | 49.1 | -76.3 | -59.2 | -25.1 |
| Total cash flows from operating activities | 754.5 | 408.7 | 807.4 | 404.8 | 1,718.3 |
| Cash flows from investing activities | |||||
| Investment in oil and gas properties | -584.3 | -335.3 | -553.7 | -323.8 | -1,060.1 |
| Investment in other fixed assets | -0.9 | -0.8 | -2.0 | -1.1 | -3.2 |
| Investment in other shares and participations1 | – | – | 9.3 | 9.3 | 9.3 |
| Decommissioning costs paid | -1.9 | -1.0 | – | – | -1.3 |
| Total cash flows from investing activities | -587.1 | -337.1 | -546.4 | -315.6 | -1,055.3 |
| Cash flows from financing activities | |||||
| Changes in long-term bank loans | -5.0 | 65.0 | -60.0 | 70.0 | -490.0 |
| Changes in lease commitments2 | -1.8 | -0.9 | – | – | – |
| Financing fees paid | – | – | -16.9 | -16.9 | -17.3 |
| Dividends paid | -125.2 | -125.2 | -153.1 | -153.1 | -153.1 |
| Purchase of own shares | – | – | -14.3 | – | -14.3 |
| Total cash flows from financing activities | -132.0 | -61.1 | -244.3 | -100.0 | -674.7 |
| Change in cash and cash equivalents | 35.4 | 10.5 | 16.7 | -10.8 | -11.7 |
| Cash and cash equivalents at the beginning | |||||
| of the period | 66.8 | 91.3 | 71.4 | 100.6 | 71.4 |
| Currency exchange difference in cash and | |||||
| cash equivalents | -1.5 | -1.1 | 8.4 | 6.7 | 7.1 |
| Cash and cash equivalents at the end of the period |
100.7 | 100.7 | 96.5 | 96.5 | 66.8 |
1 Cash received on the sale of the shares held in ShaMaran.
2 Changes in lease commitments subsequent to initial recognition of lease commitments based on IFRS16
| Additional paid-in |
|||||
|---|---|---|---|---|---|
| capital/Other | Retained | ||||
| Expressed in MUSD | Share capital | reserves | earnings | Dividends | Total equity |
| At 1 January 2018 | 0.5 | 82.2 | -433.5 | – | -350.8 |
| Change of accounting principle1 | – | – | -3.4 | – | -3.4 |
| Restated equity at 1 January 2018 | 0.5 | 82.2 | -436.9 | – | -354.2 |
| Comprehensive income | |||||
| Net result | – | – | 267.2 | – | 267.2 |
| Other comprehensive income | – | 51.5 | – | – | 51.5 |
| Total comprehensive income | – | 51.5 | 267.2 | – | 318.7 |
| Transactions with owners | |||||
| Distributions | – | – | – | -153.1 | -153.1 |
| Purchase of own shares | – | -14.3 | – | – | -14.3 |
| Share based payments | – | -17.9 | – | – | -17.9 |
| Value of employee services | – | – | 1.9 | – | 1.9 |
| Total transactions with owners | – | -32.2 | 1.9 | -153.1 | -183.4 |
| At 30 June 2018 | 0.5 | 101.5 | -167.8 | -153.1 | -218.9 |
| Comprehensive income | |||||
| Net result | – | – | -41.5 | – | -41.5 |
| Other comprehensive income | – | -124.1 | – | – | -124.1 |
| Total comprehensive income | – | -124.1 | -41.5 | – | -165.6 |
| Transactions with owners | |||||
| Share based payments | – | -2.9 | – | – | -2.9 |
| Value of employee services | – | – | 3.6 | – | 3.6 |
| Total transaction with owners | – | -2.9 | 3.6 | – | 0.7 |
| At 31 December 2018 | 0.5 | -25.5 | -205.7 | -153.1 | -383.8 |
| Transfer of prior year dividends | – | -153.1 | – | 153.1 | – |
| Comprehensive income | |||||
| Net result | – | – | 149.7 | – | 149.7 |
| Other comprehensive income | – | -57.0 | – | – | -57.0 |
| Total comprehensive income | – | -57.0 | 149.7 | – | 92.7 |
| Transactions with owners | |||||
| Distributions | – | – | – | -501.0 | -501.0 |
| Share based payments | – | -11.8 | – | – | -11.8 |
| Value of employee services | – | – | 2.2 | – | 2.2 |
| Total transaction with owners | – | -11.8 | 2.2 | -501.0 | -510.6 |
| At 30 June 2019 | 0.5 | -247.4 | -53.8 | -501.0 | -801.7 |
1 Relates to change in accounting principle for revenue recognition relating to under/overlift balances as mentioned on page 13.
| Note 1 – Revenue and other income MUSD |
1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Revenue | |||||
| Crude oil from own production | 811.3 | 422.7 | 961.2 | 500.4 | 1,877.6 |
| Crude oil from third party activities | 84.3 | 44.2 | 326.5 | 133.1 | 536.1 |
| Condensate | 23.4 | 6.1 | 9.0 | 5.2 | 41.8 |
| Gas | 48.8 | 18.3 | 70.0 | 33.8 | 152.4 |
| Sales of oil and gas | 967.8 | 491.3 | 1,366.7 | 672.5 | 2,607.9 |
| Other income | 16.2 | 8.6 | 17.2 | 9.0 | 32.8 |
| Revenue and other income | 984.0 | 499.9 | 1,383.9 | 681.5 | 2,640.7 |
| 1 Jan 2019- | 1 Apr 2019- | 1 Jan 2018- | 1 Apr 2018- | 1 Jan 2018- | |
|---|---|---|---|---|---|
| Note 2 – Production costs | 30 Jun 2019 | 30 Jun 2019 | 30 Jun 2018 | 30 Jun 2018 | 31 Dec 2018 |
| MUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Cost of operations | 56.4 | 28.4 | 47.4 | 20.1 | 102.5 |
| Tariff and transportation expenses | 19.8 | 8.8 | 17.2 | 8.3 | 35.2 |
| Change in under/over lift position | -1.6 | -0.4 | 3.1 | -0.2 | 7.0 |
| Change in inventory position | 0.3 | 0.3 | 0.6 | – | 0.6 |
| Other | 2.1 | 1.0 | 3.7 | 1.9 | 7.1 |
| Production costs | 77.0 | 38.1 | 72.0 | 30.1 | 152.4 |
| Note 3 – Segment information MUSD |
1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Norway | |||||
| Crude oil from own production | 811.3 | 422.7 | 961.2 | 500.4 | 1,877.6 |
| Condensate | 23.4 | 6.1 | 9.0 | 5.2 | 41.8 |
| Gas | 48.8 | 18.3 | 70.0 | 33.8 | 152.4 |
| Revenue | 883.5 | 447.1 | 1,040.2 | 539.4 | 2,071.8 |
| Other income | 16.2 | 8.6 | 17.2 | 9.0 | 32.8 |
| Revenue and other income | 899.7 | 455.7 | 1,057.4 | 548.4 | 2,104.6 |
| Production costs | -77.0 | -38.1 | -72.0 | -30.1 | -152.4 |
| Depletion and decommissioning costs | -196.6 | -96.8 | -232.7 | -114.2 | -458.0 |
| Exploration costs | -70.9 | -33.6 | -5.9 | -6.2 | -53.2 |
| Gross profit | 555.2 | 287.2 | 746.8 | 397.9 | 1,441.0 |
| Other | |||||
| Crude oil from third party activities | 84.3 | 44.2 | 326.5 | 133.1 | 536.1 |
| Revenue | 84.3 | 44.2 | 326.5 | 133.1 | 536.1 |
| Purchase of crude oil from third parties | -84.3 | -44.2 | -324.8 | -132.6 | -533.8 |
| Gross profit | 0.0 | 0.0 | 1.7 | 0.5 | 2.3 |
| 1 Jan 2019- | 1 Apr 2019- | 1 Jan 2018- | 1 Apr 2018- | 1 Jan 2018- | |
|---|---|---|---|---|---|
| Note 3 – Segment information cont. | 30 Jun 2019 | 30 Jun 2019 | 30 Jun 2018 | 30 Jun 2018 | 31 Dec 2018 |
| MUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Total | |||||
| Crude oil from own production | 811.3 | 422.7 | 961.2 | 500.4 | 1,877.6 |
| Crude oil from third party activities | 84.3 | 44.2 | 326.5 | 133.1 | 536.1 |
| Condensate | 23.4 | 6.1 | 9.0 | 5.2 | 41.8 |
| Gas | 48.8 | 18.3 | 70.0 | 33.8 | 152.4 |
| Revenue | 967.8 | 491.3 | 1,366.7 | 672.5 | 2,607.9 |
| Other income | 16.2 | 8.6 | 17.2 | 9.0 | 32.8 |
| Revenue and other income | 984.0 | 499.9 | 1,383.9 | 681.5 | 2,640.7 |
| Production costs | -77.0 | -38.1 | -72.0 | -30.1 | -152.4 |
| Depletion and decommissioning costs | -196.6 | -96.8 | -232.7 | -114.2 | -458.0 |
| Exploration costs | -70.9 | -33.6 | -5.9 | -6.2 | -53.2 |
| Purchase of crude oil from third parties | -84.3 | -44.2 | -324.8 | -132.6 | -533.8 |
| Gross profit | 555.2 | 287.2 | 748.5 | 398.4 | 1,443.3 |
Within each segment, revenues from transactions with a single external customer amount to ten percent or more of revenue for that segment.
| Note 4 – Finance income MUSD |
1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Foreign currency exchange gain, net | 34.7 | 33.9 | 9.6 | -152.5 | – |
| Loan modification gain | – | – | 183.7 | 183.7 | 183.7 |
| Interest income | 0.8 | 0.4 | 0.8 | 0.6 | 1.7 |
| Gain on interest rate hedge settlement | 16.0 | 8.1 | – | – | 3.5 |
| Other | – | – | 3.3 | 3.2 | 3.3 |
| Finance income | 51.5 | 42.4 | 197.4 | 35.0 | 192.2 |
| Note 5 – Finance costs MUSD |
1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Foreign currency exchange loss, net | – | – | – | – | 164.9 |
| Interest expense | 31.9 | 15.1 | 49.1 | 24.6 | 88.7 |
| Loss on interest rate hedge settlement | – | – | 1.7 | -0.3 | – |
| Unwinding of site restoration discount | 9.0 | 4.6 | 7.7 | 3.8 | 16.4 |
| Amortisation of deferred financing fees | 8.4 | 4.2 | 9.2 | 4.6 | 17.8 |
| Loan facility commitment fees | 7.0 | 3.6 | 6.8 | 3.3 | 13.0 |
| Loan modification fees | – | – | 17.3 | 17.3 | 17.3 |
| Unwinding of loan modification gain | 21.1 | 10.5 | 3.7 | 3.7 | 26.1 |
| Other | 1.0 | 0.5 | 0.6 | 0.1 | 1.2 |
| Finance costs | 78.4 | 38.5 | 96.1 | 57.1 | 345.4 |
| 1 Jan 2019- | 1 Apr 2019- | 1 Jan 2018- | 1 Apr 2018- | 1 Jan 2018- | |
|---|---|---|---|---|---|
| Note 6 – Income tax | 30 Jun 2019 | 30 Jun 2019 | 30 Jun 2018 | 30 Jun 2018 | 31 Dec 2018 |
| MUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Current tax | 43.8 | 17.4 | 8.7 | 8.4 | 90.4 |
| Deferred tax | 319.3 | 169.3 | 560.4 | 323.7 | 948.1 |
| Income tax | 363.1 | 186.7 | 569.1 | 332.1 | 1,038.5 |
| Note 7 – Oil and gas properties MUSD |
30 Jun 2019 | 31 Dec 2018 |
|---|---|---|
| Norway | ||
| Producing assets | 1,595.3 | 1,759.3 |
| Assets under development | 3,405.2 | 2,750.1 |
| Capitalised exploration and appraisal expenditure | 858.8 | 831.7 |
| 5,859.3 | 5,341.1 |
| Note 8 – Other tangible fixed assets MUSD |
30 Jun 2019 | 31 Dec 2018 |
|---|---|---|
| Right of use assets | 35.2 | – |
| Other | 13.2 | 13.6 |
| 48.4 | 13.6 |
| Note 9 – Trade and other receivables | |
|---|---|
| MUSD | 30 Jun 2019 | 31 Dec 2018 |
|---|---|---|
| Trade receivables | 146.4 | 153.7 |
| Underlift | 9.5 | 1.9 |
| Joint operations debtors | 12.9 | 17.0 |
| Prepaid expenses and accrued income | 31.7 | 26.9 |
| Other | 1.1 | 17.1 |
| 201.6 | 216.6 |
| MUSD | 30 Jun 2019 | 31 Dec 2018 |
|---|---|---|
| Non-current: | ||
| Bank loans | 3,460.0 | 3,465.0 |
| Capitalised financing fees | -46.8 | -54.1 |
| Capitalised loan modification gain | -129.9 | -148.9 |
| Lease commitments | 30.2 | – |
| 3,313.5 | 3,262.0 | |
| Current: | ||
| Lease commitments | 5.3 | – |
| Other | 11.8 | – |
| 17.1 | – | |
| 3,330.6 | 3,262.0 |
| Note 11 – Provisions MUSD |
30 Jun 2019 | 31 Dec 2018 |
|---|---|---|
| Non-current: | ||
| Site restoration | 506.7 | 483.9 |
| Long-term incentive plans | 1.1 | 2.4 |
| Other | 3.2 | 2.8 |
| 511.0 | 489.1 | |
| Current: | ||
| Site restoration | 34.0 | 6.6 |
| Long-term incentive plans | 3.7 | 5.9 |
| 37.7 | 12.5 | |
| 548.7 | 501.6 |
| Note 12 – Trade and other payables | ||
|---|---|---|
| MUSD | 30 Jun 2019 | 31 Dec 2018 |
| Trade payables | 19.0 | 26.6 |
| Overlift | 7.8 | 1.7 |
| Joint operations creditors and accrued expenses | 174.8 | 147.4 |
| Other accrued expenses | 21.7 | 17.6 |
| Other | 14.0 | 7.6 |
| 237.3 | 200.9 |
For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
– Level 1: based on quoted prices in active markets;
– Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
– Level 3: based on inputs which are not based on observable market data.
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
| MUSD | Level 1 | Level 2 | Level 3 |
|---|---|---|---|
| Assets | |||
| Derivative instruments – non-current | – | – | – |
| Derivative instruments – current | – | 6.9 | – |
| – | 6.9 | – | |
| Liabilities | |||
| Derivative instruments – non-current | – | 102.7 | – |
| Derivative instruments – current | – | 22.3 | – |
| – | 125.0 | – |
| 31 December 2018 MUSD |
Level 1 | Level 2 | Level 3 |
|---|---|---|---|
| Assets | |||
| Derivative instruments – non-current | – | 2.7 | – |
| Derivative instruments – current | – | 34.0 | – |
| – | 36.7 | – | |
| Liabilities | |||
| Derivative instruments – non-current | – | 64.9 | – |
| Derivative instruments – current | – | 20.0 | – |
| – | 84.9 | – |
There were no transfers between the levels during the reporting period.
The fair value of the financial assets is estimated to equal the carrying value. The fair value of the derivative instruments is calculated using the forward interest rate curve and the forward exchange rate curve respectively for the interest rate swap and the currency hedging contracts. The hedge counterparties are all banks which are party to the loan facility agreement.
| 1 Jan 2019- | 1 Apr 2019- | 1 Jan 2018- | 1 Apr 2018- | 1 Jan 2018- | |
|---|---|---|---|---|---|
| Expressed in MSEK | 30 Jun 2019 6 months |
30 Jun 2019 3 months |
30 Jun 2018 6 months |
30 Jun 2018 3 months |
31 Dec 2018 12 months |
| Revenue | 8.5 | 1.1 | 8.3 | 1.0 | 21.0 |
| General and administration expenses | -86.6 | -44.3 | -66.8 | -39.6 | -180.9 |
| Operating loss | -78.1 | -43.2 | -58.5 | -38.6 | -159.9 |
| Net financial items | |||||
| Finance income | 4,639.0 | 0.2 | 1,720.9 | 1,716.2 | 1,818.1 |
| Finance costs | -0.1 | – | -0.2 | – | -0.4 |
| 4,638.9 | 0.2 | 1,720.7 | 1,716.2 | 1,817.7 | |
| Profit before tax | 4,560.8 | -43.0 | 1,662.2 | 1,677.6 | 1,657.8 |
| Income tax | – | – | – | – | – |
| Net result | 4,560.8 | -43.0 | 1,662.2 | 1,677.6 | 1,657.8 |
| Expressed in MSEK | 1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Net result | 4,560.8 | -43.0 | 1,662.2 | 1,677.6 | 1,657.8 |
| Other comprehensive income | – | – | – | – | – |
| Total comprehensive income | 4,560.8 | -43.0 | 1,662.2 | 1,677.6 | 1,657.8 |
| Attributable to: | |||||
| Shareholders of the Parent Company | 4,560.8 | -43.0 | 1,662.2 | 1,677.6 | 1,657.8 |
| 4,560.8 | -43.0 | 1,662.2 | 1,677.6 | 1,657.8 |
| Expressed in MSEK | 30 June 2019 | 31 December 2018 |
|---|---|---|
| ASSETS | ||
| Non-current assets | ||
| Shares in subsidiaries | 55,118.9 | 55,118.9 |
| Other tangible fixed assets | 0.4 | 0.4 |
| Total non-current assets | 55,119.3 | 55,119.3 |
| Current assets | ||
| Receivables | 3,399.2 | 5.4 |
| Cash and cash equivalents | 30.6 | 29.5 |
| Total current assets | 3,429.8 | 34.9 |
| TOTAL ASSETS | 58,549.1 | 55,154.2 |
| SHAREHOLDERS´EQUITY AND LIABILITIES | ||
| Shareholders´ equity including net result for the period | 55,042.9 | 55,120.8 |
| Non-current liabilities | ||
| Provisions | 0.5 | 0.7 |
| Total non-current liabilities | 0.5 | 0.7 |
| Current liabilities | ||
| Dividends | 3,486.3 | – |
| Other liabilities | 19.4 | 32.7 |
| Total current liabilities | 3,505.7 | 32.7 |
| Total liabilities | 3,506.2 | 33.4 |
| TOTAL EQUITY AND LIABILITIES | 58,549.1 | 55,154.2 |
| 1 Jan 2019- 30 Jun 2019 |
1 Apr 2019- 30 Jun 2019 |
1 Jan 2018- 30 Jun 2018 |
1 Apr 2018- 30 Jun 2018 |
1 Jan 2018- 31 Dec 2018 |
|
|---|---|---|---|---|---|
| Expressed in MSEK | 6 months | 3 months | 6 months | 3 months | 12 months |
| Cash flow from operations | |||||
| Net result | 4,560.8 | -43.0 | 1,662.2 | 1,677.6 | 1,657.8 |
| Adjustment for non-cash related items | -3,478.8 | 1,159.5 | -5.6 | -1.3 | -4.8 |
| Changes in working capital | 79.4 | 40.3 | -160.6 | -326.3 | -159.9 |
| Total cash flow from operations | 1,161.4 | 1,156.8 | 1,496.0 | 1,350.0 | 1,493.1 |
| Cash flow from investing | |||||
| Investments in other fixed assets | – | – | -0.1 | -0.1 | -0.4 |
| Total cash flow from investing | – | – | -0.1 | -0.1 | -0.4 |
| Cash flow from financing | |||||
| Dividends paid | -1,161.1 | -1,161.1 | -1,354.1 | -1,354.1 | -1,354.1 |
| Purchase of own shares | – | – | -119.5 | – | -119.5 |
| Total cash flow from financing | -1,161.1 | -1,161.1 | -1,473.6 | -1,354.1 | -1,473.6 |
| Change in cash and cash equivalents | 0.3 | -4.3 | 22.3 | -4.2 | 19.1 |
| Cash and cash equivalents at the beginning of the period |
29.5 | 34.9 | 4.8 | 31.3 | 4.8 |
| Currency exchange difference in cash and cash equivalents |
0.8 | – | 6.3 | 6.3 | 5.6 |
| Cash and cash equivalents at the end of the period |
30.6 | 30.6 | 33.4 | 33.4 | 29.5 |
| Restricted equity | Unrestricted equity | ||||||
|---|---|---|---|---|---|---|---|
| Expressed in MSEK | Share capital |
Statutory reserve |
Other reserves |
Retained earnings |
Dividends | Total | Total equity |
| Balance at 1 January 2018 | 3.5 | 861.3 | 6,599.2 | 47,472.6 | – | 54,071.8 | 54,936.6 |
| Total comprehensive income | – | – | – | 1,662.2 | – | 1,662.2 | 1,662.2 |
| Transactions with owners | |||||||
| Distributions | – | – | – | – | -1,354.1 | -1,354.1 | -1,354.1 |
| Purchase of own shares | – | – | -119.5 | – | – | -119.5 | -119.5 |
| Total transactions with owners | – | – | -119.5 | – | -1,354.1 | -1,473.6 | -1,473.6 |
| Balance at 30 June 2018 | 3.5 | 861.3 | 6,479.7 | 49,134.8 | -1,354.1 | 54,260.4 | 55,125.2 |
| Total comprehensive income | – | – | – | -4.4 | – | -4.4 | -4.4 |
| Transactions with owners | |||||||
| Distributions | – | – | – | – | – | – | – |
| Total transactions with owners | – | – | – | – | – | – | – |
| Balance at 31 December 2018 | 3.5 | 861.3 | 6,479.7 | 49,130.4 | -1,354.1 | 54,256.0 | 55,120.8 |
| Transfer of prior year dividends | – | – | – | -1,354.1 | 1,354.1 | – | – |
| Total comprehensive income | – | – | – | 4,560.8 | – | 4,560.8 | 4,560.8 |
| Transactions with owners | |||||||
| Distributions | – | – | – | – | -4,638.7 | -4,638.7 | -4,638.7 |
| Total transactions with owners | – | – | – | – | -4,638.7 | -4,638.7 | -4,638.7 |
| Balance at 30 June 2019 | 3.5 | 861.3 | 6,479.7 | 52,337.1 | -4,638.7 | 54,178.1 | 55,042.9 |
Lundin Petroleum discloses alternative performance measures as part of its financial statements prepared in accordance with ESMA's (European Securities and Markets Authority) guidelines. Lundin Petroleum believes that the alternative performance measures provide useful supplement information to management, investors, security analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of Lundin Petroleum's business operations and to improve comparability between periods. Reconciliations of relevant alternative performance measures are provided on the following page. Definitions of the performance measures are provided under the key ratio definitions below:
| Financial data MUSD |
1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Revenue and other income | 984.0 | 499.9 | 1,383.9 | 681.5 | 2,640.7 |
| Operating cash flow | 778.9 | 400.2 | 978.4 | 510.4 | 1,864.1 |
| EBITDA | 811.6 | 411.9 | 975.0 | 512.3 | 1,932.5 |
| Free cash flow | 167.4 | 71.6 | 261.0 | 89.2 | 663.0 |
| Net result | 149.7 | 96.2 | 267.2 | 37.0 | 225.7 |
| Net debt | 3,359.3 | 3,359.3 | 3,798.5 | 3,798.5 | 3,398.2 |
| Data per share USD |
|||||
| Shareholders' equity per share | -2.37 | -2.37 | -0.65 | -0.65 | -1.13 |
| Operating cash flow per share | 2.30 | 1.18 | 2.89 | 1.51 | 5.51 |
| Cash flow from operations per share | 2.23 | 1.21 | 2.38 | 1.20 | 5.07 |
| Free cash flow per share | 0.49 | 0.21 | 0.77 | 0.26 | 1.96 |
| Earnings per share | 0.44 | 0.28 | 0.79 | 0.11 | 0.67 |
| Earnings per share fully diluted | 0.44 | 0.28 | 0.79 | 0.11 | 0.66 |
| EBITDA per share | 2.40 | 1.22 | 2.88 | 1.51 | 5.71 |
| EBITDA per share – fully diluted | 2.39 | 1.21 | 2.87 | 1.51 | 5.69 |
| Dividend per share1 | 0.37 | 0.37 | 0.45 | 0.45 | 0.45 |
| Number of shares issued at period end | 340,386,445 | 340,386,445 | 340,386,445 | 340,386,445 | 340,386,445 |
| Number of shares in circulation at period end | 338,513,135 | 338,513,135 | 338,513,135 | 338,513,135 | 338,513,135 |
| Weighted average number of shares for the period |
338,513,135 | 338,513,135 | 338,672,675 | 338,513,135 | 338,592,250 |
| Weighted average number of shares for the period fully diluted |
339,252,753 | 339,252,753 | 339,709,098 | 339,549,557 | 339,513,634 |
| Share price | |||||
| Share price at period end in SEK | 287.90 | 287.90 | 285.70 | 285.70 | 221.40 |
| Share price at period end in USD2 | 31.02 | 31.02 | 31.86 | 31.86 | 24.72 |
| Key ratios | |||||
| Return on equity (%)3 | – | – | – | – | – |
| Return on capital employed (%) | 19 | 10 | 25 | 16 | 47 |
| Net debt/equity ratio (%)3 | – | – | – | – | – |
| Net debt/EBITDA ratio | 1.9 | 1.9 | 2.1 | 2.1 | 1.8 |
| Equity ratio (%) | -13 | -13 | -4 | -4 | -7 |
| Share of risk capital (%) | 26 | 26 | 27 | 27 | 29 |
| Interest coverage ratio | 16 | 17 | 17 | 23 | 17 |
| Operating cash flow/interest ratio | 24 | 26 | 19 | 21 | 21 |
| Yield | 1 | 1 | 1 | 1 | 2 |
1 Dividend per share represents the actual paid out dividend per share.
2 Share price at period end in USD is calculated based on quoted share price in SEK and applicable SEK/USD exchange rate as per period end.
3 As the equity at 30 June 2019, 31 December 2018 and 30 June 2018 is negative, these ratios have not been calculated.
| EBITDA MUSD |
1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Operating profit | 540.7 | 279.8 | 735.0 | 391.2 | 1,418.7 |
| Add: depletion of oil and gas properties | 196.6 | 96.8 | 232.7 | 114.2 | 458.0 |
| Add: exploration costs | 70.9 | 33.6 | 5.9 | 6.2 | 53.2 |
| Add: depreciation of other tangible assets | 3.4 | 1.7 | 1.4 | 0.7 | 2.6 |
| EBITDA | 811.6 | 411.9 | 975.0 | 512.3 | 1,932.5 |
| Operating cash flow MUSD |
1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Revenue and other income | 984.0 | 499.9 | 1,383.9 | 681.5 | 2,640.7 |
| Minus: production costs | -77.0 | -38.1 | -72.0 | -30.1 | -152.4 |
| Minus: purchase of crude oil from third parties | -84.3 | -44.2 | -324.8 | -132.6 | -533.8 |
| Minus: current taxes | -43.8 | -17.4 | -8.7 | -8.4 | -90.4 |
| Operating cash flow | 778.9 | 400.2 | 978.4 | 510.4 | 1,864.1 |
| Free cash flow MUSD |
1 Jan 2019- 30 Jun 2019 6 months |
1 Apr 2019- 30 Jun 2019 3 months |
1 Jan 2018- 30 Jun 2018 6 months |
1 Apr 2018- 30 Jun 2018 3 months |
1 Jan 2018- 31 Dec 2018 12 months |
|---|---|---|---|---|---|
| Cash flows from operating activities | 754.5 | 408.7 | 807.4 | 404.8 | 1,718.3 |
| Minus: cash flows from investing activities | -587.1 | -337.1 | -546.4 | -315.6 | -1,055.3 |
| Free cash flow | 167.4 | 71.6 | 261.0 | 89.2 | 663.0 |
| 1 Jan 2019- | 1 Apr 2019- | 1 Jan 2018- | 1 Apr 2018- | 1 Jan 2018- | |
|---|---|---|---|---|---|
| Net debt | 30 Jun 2019 | 30 Jun 2019 | 30 Jun 2018 | 30 Jun 2018 | 31 Dec 2018 |
| MUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Bank loans | 3,460.0 | 3,460.0 | 3,895.0 | 3,895.0 | 3,465.0 |
| Minus: cash and cash equivalents | -100.7 | -100.7 | -96.5 | -96.5 | -66.8 |
| Net debt | 3,359.3 | 3,359.3 | 3,798.5 | 3,798.5 | 3,398.2 |
Operating cash flow: Revenue and other income less production costs less purchase of crude oil from third parties and less current taxes.
EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortisation): Operating EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortisation): Operating profit before depletion of oil and gas properties, exploration costs, impairment costs, depreciation of other tangible assets and gain on sale of assets.
Free cash flow: Cash flow from operating activities less cash flow from investing activities in accordance with the consolidated statement of cash flow.
Net debt: Bank loan less cash and cash equivalents.
Shareholders' equity per share: Shareholders' equity divided by the number of shares in circulation at period end.
Operating cash flow per share: Operating cash flow divided by the weighted average number of shares for the period.
Cash flow from operations per share: Cash flow from operating activities in accordance with the consolidated statement of cash flow divided by the weighted average number of shares for the period.
Free cash flow per share: Free cash flow divided by the weighted average number of shares for the period.
Earnings per share: Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the period.
Earnings per share fully diluted: Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the period after considering any dilution effect.
EBITDA per share: EBITDA divided by the weighted average number of shares for the period.
EBITDA per share fully diluted: EBITDA divided by the weighted average number of shares for the period after considering any dilution effect.
Dividend per share: paid out dividends per share for the period.
Weighted average number of shares for the period: The number of shares at the beginning of the period with changes in the number of shares weighted for the proportion of the period they are in issue.
Weighted average number of shares for the period fully diluted: The number of shares at the beginning of the period with changes in the number of shares weighted for the proportion of the period they are in issue after considering any dilution effect.
Return on equity: Net result divided by average total equity.
Return on capital employed: Income before tax plus interest expenses plus/less currency exchange differences on financial loans divided by the average capital employed (the average balance sheet total less non-interest bearing liabilities).
Net debt/equity ratio: Bank loan less cash and cash equivalents divided by shareholders' equity.
Net debt/EBITDA ratio: Bank loan less cash and cash equivalents divided by EBITDA of the last four quarters.
Equity ratio: Total equity divided by the balance sheet total.
Share of risk capital: The sum of the total equity and the deferred tax provision divided by the balance sheet total.
Interest coverage ratio: Result after financial items plus interest expenses plus/less currency exchange differences on financial loans divided by interest expenses.
Operating cash flow/interest ratio: Revenue less production costs and less current taxes divided by the interest expense for the period.
Yield: dividend per share in relation to quoted share price at the end of the period.
The Board of Directors and the President and CEO certify that the financial report for the six months ended 30 June 2019 gives a fair view of the performance of the business, position and profit or loss of the Company and the Group, and describes the principal risks and uncertainties that the Company and the companies in the Group face.
Stockholm, 31 July 2019
Ian H. Lundin Chairman
Alex Schneiter President and CEO Peggy Bruzelius
C. Ashley Heppenstall Lukas H. Lundin Torstein Sanness
Grace Reksten Skaugen Jakob Thomasen Cecilia Vieweg
We have reviewed this report for the period 1 January 2019 to 30 June 2019 for Lundin Petroleum AB (publ). The board of directors and the President and CEO are responsible for the preparation and presentation of this interim report in accordance with IAS 34 and the Swedish Annual Accounts Act. Our responsibility is to express a conclusion on this interim report based on our review.
We conducted our review in accordance with the International Standard on Review Engagements ISRE 2410, Review of Interim Report Performed by the Independent Auditor of the Entity. A review consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing, ISA, and other generally accepted auditing standards in Sweden. The procedures performed in a review do not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
Based on our review, nothing has come to our attention that causes us to believe that the interim report is not prepared, in all material respects, in accordance with IAS 34 and the Swedish Annual Accounts Act, regarding the Group, and with the Swedish Annual Accounts Act, regarding the Parent Company.
Stockholm, 31 July 2019
PricewaterhouseCoopers AB
Johan Rippe Authorised Public Accountant Lead Partner
The AGM will be held on 31 March 2020 in Stockholm, Sweden.
For further information, please contact:
Edward Westropp Sofia Antunes Robert Eriksson VP Investor Relations Tel: +41 22 595 10 14
Investor Relations Officer Tel: +41 795 23 60 75
Head of Media Communications Tel: +46 701 11 26 15 [email protected] [email protected] [email protected]
An extensive list of definitions can be found on www.lundin-petroleum.com under the heading "Definitions".
| EBITDA | Earnings Before Interest, Tax, Depreciation and Amortisation |
|---|---|
| CHF | Swiss franc |
| EUR | Euro |
| NOK | Norwegian Krone |
| SEK | Swedish Krona |
| USD | US dollar |
| TSEK | Thousand SEK |
| TUSD | Thousand USD |
| MSEK | Million SEK |
| MUSD | Million USD |
| boe | Barrels of oil equivalents |
|---|---|
| boepd | Barrels of oil equivalents per day |
| bopd | Barrels of oil per day |
| Mbbl | Thousand barrels |
| Mboe | Thousand barrels of oil equivalents |
| Mboepd | Thousand barrels of oil equivalents per day |
| Mbopd | Thousand barrels of oil per day |
| Mcf | Thousand cubic feet |
This information is information that Lundin Petroleum AB is required to make public pursuant to the Securities Markets Act. The information was submitted for publication, through the contact persons set out above, at 07.30 CET on 31 July 2019.
Certain statements made and information contained herein constitute "forward-looking information" (within the meaning of applicable securities legislation). Such statements and information (together, "forward-looking statements") relate to future events, including Lundin Petroleum's future performance, business prospects or opportunities. Forward-looking statements include, but are not limited to, statements with respect to estimates of reserves and/or resources, future production levels, future capital expenditures and their allocation to exploration and development activities, future drilling and other exploration and development activities. Ultimate recovery of reserves or resources are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.
All statements other than statements of historical fact may be forward-looking statements. Statements concerning proven and probable reserves and resource estimates may also be deemed to constitute forward-looking statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions) are not statements of historical fact and may be "forward-looking statements". Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. No assurance can be given that these expectations and assumptions will prove to be correct and such forward-looking statements should not be relied upon. These statements speak only as on the date of the information and Lundin Petroleum does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws. These forward-looking statements involve risks and uncertainties relating to, among other things, operational risks (including exploration and development risks), productions costs, availability of drilling equipment, reliance on key personnel, reserve estimates, health, safety and environmental issues, legal risks and regulatory changes, competition, geopolitical risk, and financial risks. These risks and uncertainties are described in more detail under the heading "Risks and Risk Management" and elsewhere in Lundin Petroleum's annual report. Readers are cautioned that the foregoing list of risk factors should not be construed as exhaustive. Actual results may differ materially from those expressed or implied by such forward-looking statements. Forward-looking statements are expressly qualified by this cautionary statement.
Corporate Head Office Lundin Petroleum AB (publ) Hovslagargatan 5 SE-111 48 Stockholm, Sweden T +46-8-440 54 50 Wlundin-petroleum.com
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