Quarterly Report • Oct 29, 2021
Quarterly Report
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Lundin Energy AB (publ) company registration number 556610-8055
| 1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|
|---|---|---|---|---|---|
| Production in Mboepd | 188.8 | 193.6 | 157.6 | 157.5 | 164.5 |
| Revenue and other income in MUSD | 3,862.9 | 1,478.2 | 1,784.7 | 687.0 | 2,564.4 |
| CFFO in MUSD | 2,499.9 | 1,012.0 | 1,251.3 | 353.2 | 1,528.0 |
| Per share in USD | 8.79 | 3.56 | 4.40 | 1.24 | 5.38 |
| EBITDAX in MUSD | 3,360.6 | 1,282.6 | 1,431.8 | 515.6 | 2,140.2 |
| Per share in USD | 11.82 | 4.51 | 5.04 | 1.81 | 7.53 |
| Free cash flow in MUSD | 1,622.9 | 673.8 | 545.7 | 164.2 | 448.2 |
| Per share in USD | 5.71 | 2.37 | 1.92 | 0.58 | 1.58 |
| Net result in MUSD | 372.1 | 137.5 | 80.5 | 212.3 | 384.2 |
| Per share in USD | 1.31 | 0.48 | 0.28 | 0.74 | 1.35 |
| Adjusted net result in MUSD | 542.4 | 234.0 | 193.1 | 75.8 | 280.0 |
| Per share in USD | 1.91 | 0.83 | 0.68 | 0.27 | 0.99 |
| Net debt in MUSD | 2,646.9 | 2,646.9 | 3,706.8 | 3,706.8 | 3,911.5 |
"I'm pleased to report another set of record production and financial results in the third quarter, underpinned by continued strong operational performance and further strengthening of oil and gas prices. Whilst certain challenges of the COVID-19 crisis remain, we've normalised the management of these and continue to deliver on our key business priorities.
"Our world class producing assets keep on outperforming, with excellent production efficiency and industry leading low operating costs, delivering record production in the third quarter. Full year production is anticipated to be towards the upper end of our guidance range.
"Johan Sverdrup continues to consistently perform at a high level and Phase 2 of the project, which will boost gross production to 755 Mbopd, is making great progress and remains firmly on track for first oil in the fourth quarter of 2022.
"At the Greater Edvard Grieg Area we're delivering on our projects that support the long term plateau extension, with excellent results from the completed Edvard Grieg infill well programme, and first oil achieved at the Rolvsnes and Solveig projects; all these projects delivered on schedule and below budget. We are set to see reserves increases at year end due to the continued strong Edvard Grieg performance and the excellent drilling results at Solveig. There's lots more upside in the area and we're working hard to bring forward a number of new projects.
"I'm pleased to announce the purchase of a further 25 percent interest in the Wisting oil development, which adds resources of almost two times our 2021 production volumes. The deal takes the Company's interest to 35 percent in this high quality, 500 MMbo development, which has strong economics and will be powered from shore. This strategic deal, done at a purchase price of USD 2.5 per boe, is very value accretive and fits with our ambition to sustain the business long term with low carbon emission barrels.
"We delivered free cash flow of USD 1.6 billion for the first nine months, enabling net debt to be reduced to USD 2.6 billion. Due to the strong financial outlook for the business, I'm pleased to note that the Board of Directors anticipates to propose to the AGM 2022, a 25 percent increased dividend for 2021 of USD 2.25 per share (in total MUSD 640), clearly demonstrating our commitment to grow shareholder returns.
"We continue to be firmly positioned as an industry leader on carbon emissions and during the third quarter we further accelerated our decarbonisation plans to become carbon neutral by 2023 from operational emissions. With around 60 percent of our production today produced as carbon neutral and with a clear deliverable pathway to carbon neutrality, I see this as a key value differentiator for Lundin Energy.
"The Company has again delivered excellent results, all our key business priorities are on track and we've made a strategic value accretive acquisition, which together positions us to keep delivering resilient sustainable growth."
Lundin Energy is an experienced Nordic oil and gas company that explores for, develops and produces resources economically, efficiently and responsibly. We focus on value creation for our shareholders and wider stakeholders through three strategic pillars: Resilience, Sustainability and Growth. Our high quality, low cost assets mean we are resilient to oil price volatility, and our organic growth strategy, combined with our sustainable approach and commitment to decarbonisation, firmly establishes our leadership role in a lower carbon energy future. (Nasdaq Stockholm: LUNE). For more information, please visit us at www.lundin-energy.com or download our App www.myirapp.com/lundin
All the reported numbers and updates in the operational review relate to the nine month period ending 30 September 2021 (reporting period) unless otherwise specified.
Lundin Energy has maintained a proactive approach in safeguarding the wellbeing of the Company's employees and contractors and ensuring the virus has minimal impact on its operations. To date there have been no disruptions to production due to the COVID-19 situation and while certain project activities have been affected, the disruptions have been successfully managed to avoid any negative impact on the production outlook.
Production guidance for the full year 2021 is 180 to 195 thousand barrels of oil equivalent per day (Mboepd), which was increased in June 2021, from the original guidance of 170 to 190 Mboepd.
| 2021 guidance | Previous | Current |
|---|---|---|
| Production | 180 to 195 Mboepd | 180 to 195 Mboepd |
| Operating Cost | USD 3.00 per boe | USD 3.00 per boe |
| Development expenditure | MUSD 850 | MUSD 770 |
| Exploration and Appraisal expenditure | MUSD 260 | MUSD 3251 |
| Decommissioning expenditure | MUSD 20 | MUSD 15 |
| Renewables Investments | MUSD 100 | MUSD 100 |
1 Including the additional 25 percent working interest in Wisting, effective from 1 January 2021.
Production in the third quarter of 2021 was 194 Mboepd, a record quarterly production rate for the Company and ahead of the revised guidance, due to continued high production efficiency across all assets and additional facilities capacity available at Edvard Grieg due to the Ivar Aasen field not utilizing its contractual capacity.
Operating costs, net of tariff income, were USD 2.90 per boe, which was below guidance for the reporting period. Full year operating cost guidance remains USD 3.00 per boe.
| Production in Mboepd |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Crude oil | 176.3 | 179.6 | 146.3 | 147.0 | 152.7 |
| Gas | 12.5 | 14.0 | 11.3 | 10.5 | 11.8 |
| Total production | 188.8 | 193.6 | 157.6 | 157.5 | 164.5 |
| Production in Mboepd |
WI1 | 1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|---|
| Johan Sverdrup | 20% | 106.1 | 107.0 | 83.3 | 89.8 | 87.6 |
| Greater Edvard Grieg Area2 | 65% - 80% | 71.3 | 75.7 | 60.7 | 56.1 | 63.6 |
| Ivar Aasen | 1.385% | 0.7 | 0.6 | 0.8 | 0.7 | 0.8 |
| Alvheim Area | 15% - 35% | 10.7 | 10.3 | 12.8 | 11.0 | 12.5 |
| 188.8 | 193.6 | 157.6 | 157.5 | 164.5 |
1 Lundin Energy's working interest (WI)
2 Consisting – Edvard Grieg, Solveig and Rolvsnes EWT
Production from Johan Sverdrup Phase 1 was slightly above the updated production guidance with a production efficiency of 98 percent. In May 2021, the Phase 1 processing capacity was increased from 500 thousand barrels of oil per day (Mbopd) gross to 535 Mbopd, following upgrade of the water injection system, which were required to support the higher offtake rates. This represents a gross increase of 95 Mbopd since first oil in late 2019. Reservoir performance continues to be strong with high well productivities and excellent communication across the field. One production well was completed in the reporting period, with results in line with expectations and the field is currently producing from 14 wells. Johan Sverdrup is being operated with power supplied from shore and is one of the lowest CO2 emitting offshore fields in the world, with CO2 emissions of less than 0.1 kg per boe for the reporting period. Operating costs were USD 1.66 per boe.
Production from the Edvard Grieg field was slightly above the updated production guidance, with a production efficiency of 98 percent. The infill drilling programme at Edvard Grieg commenced in January 2021, using the Rowan Viking jack-up rig, and has progressed according to plan. The first infill well came on stream in June 2021, equipped with the innovative 'Fishbones' completion which has contributed to well productivity around 10 times greater than the original prognosis. The second and third infill wells have now been completed, with results in line with expectations, with production start-up from both wells expected in fourth quarter 2021. Reservoir performance from Edvard Grieg throughout 2021 has been above expectation and the Company expects to increase reserves at year end. Operating costs, net of tariff income, were USD 3.87 per boe.
Power from shore at Edvard Grieg is expected to be online in late 2022, with the project progressing on schedule. The power cable has been installed on Edvard Grieg and laid on the seabed at Johan Sverdrup, awaiting arrival of the Phase 2 processing platform in 2022. The retirement of the existing gas turbine power generation system on the platform and installation of electric boilers to provide process heat, is on schedule and is expected to be operational in late 2022. It is also estimated that the Company will benefit from approximately a 10 percent increase in gas sales from Edvard Grieg compared to the reporting period, due to the removal of the power generation turbines. Production from the Ivar Aasen field was in line with the updated forecast. The field water production rate continues to increase, which has resulted in accelerated oil production decline. Three infill wells were completed in the reporting period, with results below expectations.
Production from the Alvheim Area was slightly above guidance with a production efficiency of 95 percent. The first of two planned infill wells for the second half of 2021, have been completed with results in line with expectations. First oil from the well is expected in November 2021. Operating costs were USD 7.41 per boe.
The development expenditure guidance for 2021 has been reduced to MUSD 770, from the original guidance of MUSD 850. The reduction is due to better than expected drilling performance at Edvard Grieg and Solveig, as well as re-phasing of Johan Sverdrup costs into 2022.
| Project | WI | Operator | Estimated gross reserves |
Production start |
Expected gross plateau production |
|---|---|---|---|---|---|
| Johan Sverdrup Phase 2 | 20% | Equinor | 2.2 – 3.2 Bn boe1 | Q4 2022 | 755 Mbopd1 |
| Solveig Phase 1 | 65% | Lundin Energy | 57 MMboe | Sept 2021 | 30 Mboepd |
| Rolvsnes EWT2 | 80% | Lundin Energy | – | Aug 2021 | 3 Mboepd |
| Kobra East/Gekko (KEG) | 15% | AkerBP | 39 MMboe | Q1 2024 | 28 Mboepd |
| Frosk | 15% | AkerBP | 9 MMboe | Q2 2023 | 13 Mboepd |
| Wisting | 35%3 | Equinor | 500 MMboe | Q2 2028 | 150 Mboepd |
1 Johan Sverdrup full field
2 Extended Well Test
3 Increase to 35 percent is subject to Norwegian regulatory approvals and is expected to complete in the fourth quarter 2021
The Johan Sverdrup Phase 2 development project involves a second processing platform bridge linked to the Phase 1 field centre, subsea facilities to access the Avaldsnes, Kvitsøy and Geitungen satellite areas of the field, implementation of full field water alternating gas injection (WAG) for enhanced recovery and the drilling of 28 additional wells. The Johan Sverdrup gross field reserves are in the range of 2.2 to 3.2 billion boe and the ambition of the partners in the field, is to achieve a recovery factor of more than 70 percent. In June 2021, the Company announced that the full field gross processing capacity will be increased to 755 Mbopd once Phase 2 comes on stream. The increase is a result of debottlenecking work on the Phase 2 topsides and studies to optimise the full field integrated processing and export capacity. The full field breakeven oil price for Johan Sverdrup, including past investments, is less than USD 15 per boe.
The Phase 2 capital expenditure is estimated at gross NOK 41 billion (nominal), which is unchanged from the Phase 2 PDO estimate in 2019. The three modules that constitute the second processing platform topsides were successfully assembled in May 2021, the jacket for the second processing platform was successfully installed offshore in June 2021 and the new module on the existing riser platform was successfully installed offshore in July 2021. The operation to install the second processing platform topsides on the jacket is planned for the spring of 2022. The subsea facilities and flowlines installation work is progressing as per schedule and will be completed during 2021, allowing for drilling operations on the subsea wells to commence early 2022. The disruptions to project activities due to COVID-19 have been effectively managed and first oil remains on schedule for the fourth quarter of 2022, with progress now approximately 65 percent complete.
Solveig Phase 1 came on stream in September 2021 on schedule and is the first Edvard Grieg subsea tie-back development, significantly contributing to keeping the Edvard Grieg platform on plateau production until the end of 2023. Initial production performance is in line with expectations. Phase 1 gross proved plus probable (2P) reserves are estimated at 57 MMboe and are being developed with three oil production wells and two water injection wells, achieving gross peak production of 30 Mboepd. The PDO for Solveig Phase 1 was approved in June 2019. The capital cost for the development is below the PDO estimate of MUSD 810 gross, with a breakeven oil price below 20 USD per boe. Development drilling of the two first production wells have been completed with results above expectations, indicating an increase in reserves at year end 2021, and completion of the drilling programme is expected in the second quarter 2022.
The Rolvsnes EWT project, which was approved by the authorities in July 2019, has been developed through a 3km subsea tie-back of the existing Rolvsnes horizontal well to the Edvard Grieg platform. The EWT will provide important reservoir data to support a decision on the potential Rolvsnes full field development. The project has been developed in conjunction with the Solveig project, to take advantage of contracting and implementation synergies. The project achieved first oil, on schedule and below budget, in August 2021 with performance in line with expectations.
In June 2021, the PDO for the joint development of the two discoveries Kobra East and Gekko was submitted to the Norwegian Ministry of Petroleum and Energy. The development will be conducted as a subsea tie-back to the Alvheim FPSO and phase one of the development will include four tri-lateral production wells targeting the oil zones of the two discoveries. Phase two of the development consists of a gas production well targeting the gas cap at Gekko, which will be drilled at a later stage once gas processing capacity is available on the Alvheim FPSO. Drilling operations are expected to commence in early 2023, with first oil planned in the first quarter of 2024. Total gross 2P reserves for the project amount to 39 MMboe and the development will provide gross peak production of approximately 28 Mboepd. This project will be developed under the Norwegian temporary tax regime and has a breakeven oil price of less than USD 30 per boe.
In September 2021, the PDO for the development of the Frosk discovery was submitted to the Norwegian Ministry of Petroleum and Energy. The development will be conducted as a subsea tie-back to the Alvheim FPSO through the existing Bøyla manifold. The development includes the drilling of two new wells. Drilling operations are expected to commence in 2022, with first oil planned in the first half of 2023. Total gross reserves for the project amount to approximately 9 MMboe and the development will provide gross peak production of approximately 13 Mboepd, with a breakeven oil price of less than USD 25 per boe.
The Wisting project is scheduled to be one of the next Barents Sea production hubs and will be a significant contributor to sustaining the Company's long term production profile. With the acquisition of a further 25 percent working interest announced on 28 October 2021, the Company's working interest in the project will rise to 35 percent and will add material pre-development resources in a strategic core area for the Company, with significant surrounding prospectivity. Production is expected to start up in 2028 and Equinor, the operator of Wisting in the development phase, is targeting a PDO by end 2022 in order that the project will benefit from the temporary tax incentives established by the Norwegian Government in June 2020. The concept select milestone is expected to be taken in Q4 2021 with contract awards for the engineering phase placed shortly thereafter. With strong economics, the development is also aligned with Lundin Energy's decarbonisation strategy, with a power from shore solution being matured as part of the PDO.
The 2021 exploration and appraisal programme consists of eight wells, seven of which have been drilled, yielding oil discoveries at Segment D and Lille Prinsen. One well remains in the 2021 exploration and appraisal programme (Lyderhorn) which is expected to commence drilling in the fourth quarter 2021. The exploration and appraisal expenditure guidance for 2021 has been increased to MUSD 325 from the original guidance of MUSD 260, due to increased scope at the Segment D, Iving, Lille Prinsen wells and the additional 25 percent working interest in Wisting, effective from 1 January 2021.
| Licence | Operator | WI | Well | Spud Date | Status |
|---|---|---|---|---|---|
| PL359 | Lundin Energy | 40% | Segment D | February 2021 | Oil discovery |
| PL722 | Equinor | 20% | Shenzhou | April 2021 | Dry |
| PL820S | MOL | 41% | Iving (2 wells) | May 2021 | Completed - evaluation ongoing |
| PL167 | Equinor/Lundin Energy | 40% | Lille Prinsen | July 2021 | Oil discovery |
| PL981 | Lundin Energy | 60% | Merckx | September 2021 | Dry |
| PL976 | Lundin Energy | 40% | Dovregubben | October 2021 | Dry |
| PL1041 | AkerBP | 15% | Lyderhorn | Fourth Quarter 2021 |
In March 2021, the Segment D prospect, located north of the Solveig field on the Utsira High in the Norwegian North Sea in PL359, was drilled yielding an oil discovery. A 10 metre oil column was encountered in Triassic reservoir sandstones and the discovery is estimated to hold gross recoverable resources of 3 to 9 MMboe. A development will be evaluated in parallel with a potential future phase development at Solveig.
In July 2021, a two-well appraisal drilling campaign was completed on the Iving discovery located in the Central North Sea close to the Balder and Ringhorne fields. The results were below expectation and the feasibility of a commercial discovery is currently undergoing evaluation.
In September 2021, the exploration and appraisal programme was successfully completed on Lille Prinsen on the Utsira High in the Norwegian North Sea in PL167. The wells confirmed a combined gross resource range of 12 to 60 MMboe. A development solution is currently being matured, aiming for project sanction in 2022.
In 2020, the Norwegian Government introduced temporary tax incentives aiming to increase activity on the Norwegian Continental Shelf, which applies to projects with PDO's submitted before the end of 2022. These tax incentives significantly improve project economics and the Company has taken steps to accelerate activities for the potential projects, which could benefit from this opportunity. Further projects to be de-risked include Solveig Phase 2 (incorporating the Segment D discovery) and Rolvsnes Full Field, both of which require production experience to mature development solutions. At both Lille Prinsen and Trell and Trine, the field development and concept select studies are progressing well with possible project sanction before the end of 2022.
Decarbonisation is a key strategic pillar for Lundin Energy and a significant differentiator for the business. The decarbonisation plan is composed of four pillars – reducing operational emissions, powering key assets from shore, investing in renewable power to replace net electricity usage and investments in nature-based carbon capture projects to neutralise residual emissions. A critical step towards carbon neutrality will be the electrification of the Edvard Grieg platform, which will be executed in parallel with the Johan Sverdrup Phase 2 development and will be operational in late 2022. Carbon emissions were 2.9 kg of CO2 per boe in the reporting period, which is well within the Company's 2021 target of less than 4 kg of CO2 per boe. On completion of the electrification of Edvard Grieg, the Company's average net carbon intensity is expected to be approximately 1 kg CO2 per boe, over fifteen times lower than the industry average. In light of this, in September 2021, the decision was taken to accelerate decarbonisation by two years to achieve carbon neutrality for operational emissions from 2023.
In April 2021, the Company completed a transaction with OX2 AB (OX2) to acquire a 100 percent interest in the Karskruv onshore wind farm project in southern Sweden. The wind farm will become operational in late 2023 and will produce an estimated 290 GWh per annum, from 20 onshore wind turbines. The total investment in Karskruv, including the acquisition cost, will amount to MEUR 130 with the majority of the spend occurring in 2022 and 2023 and the project will be cash flow positive from 2024. Construction and commissioning of the second phase of the Leikanger hydropower project in Norway was completed in March 2021, and is now operational at full capacity. Power is being generated from the first turbine at the Metsälamminkangas (MLK) wind farm in Finland and construction and commissioning works on the remaining turbines are progressing well with commercial handover to the Company planned for late Q4 2021. The Company has now committed to three renewable projects, with a combined net power generation capacity of around 600 GWh per annum from late 2023, which will cover all of the Company's expected net electricity usage for the offshore producing assets, including the increased working interest in the Wisting development. This means that from end 2023 over 95 percent of the Company's oil production will be powered by its own generated renewable energy. Renewable energy expenditure guidance for 2021 remains MUSD 100.
In January 2021, the Company signed a partnership with Land Life Company B.V., to invest MUSD 35 in high quality re-forestation projects to plant approximately eight million trees between 2021 and 2025, capturing approximately 2.6 million tonnes of CO2 . During the reporting period, approximately 450,000 trees were planted in Spain and Ghana.
In September 2021, Lundin Energy signed a partnership with EcoPlanet Bamboo WA ll. The Company will invest MUSD 9 in sustainable bamboo plantations where over 1 million bamboo clumps will be planted on degraded land between 2022-2024, capturing approximately 1.7 million tonnes of CO2 over 10 years.
Over time, these carbon capture projects will be sufficient to capture all of the Company's net residual carbon emissions for the longterm, leading to carbon neutrality for operational emissions. Whilst these projects ramp-up over a five year period, the Company has entered into an agreement to source high quality carbon credits from reforestation projects, certified by the Verified Carbon Standard (VCS) or 'Gold Standard'. The sourcing of carbon credits will bridge the gap until the Company's proprietary projects begin delivering certified carbon credits, and the Company does not anticipate buying any further credits from the market post 2026.
In April 2021, Lundin Energy announced that it had sold a cargo of certified carbon neutrally produced Edvard Grieg crude to Saras S.p.A, the first such cargo in the world to have been traded and a significant step forward for the international oil market, in terms of a barrel of crude oil trading on the merits of its carbon emissions. Lundin Energy's Edvard Grieg field was the first oil field in the world to be independently certified by Intertek Group plc (Intertek), under its CarbonClearTM certification. The field is certified as low carbon at 3.4 kg of CO2 e per boe, including exploration, development and production.
Following the success of the first certified, carbon neutrally produced barrels at Edvard Grieg, in June 2021, Lundin Energy announced that all future barrels of oil the Company sells from the Johan Sverdrup field will be certified as carbon neutrally produced under the CarbonZeroTM standard. The field has been independently certified at 0.45 kg CO2 e per boe, approximately 40 times lower than the world average. The first carbon neutrally produced cargo from Johan Sverdrup was sold to GS Caltex, Korea in June 2021.
In order to supply a carbon neutrally produced barrel, residual emissions for both the Edvard Grieg and Johan Sverdrup fields were compensated through high quality, nature-based carbon capture projects, certified by VCS and independently certified by Intertek. Almost 60 percent of the Company's current net production is certified as carbon neutrally produced, rising to 100 percent by 2023. Carbon neutrally produced cargo sales have continued during the period, adding competitive advantage to our marketing efforts. There is a clear pathway that as the market for carbon neutrally produced crudes matures, a premium per barrel can be realised, adding significant value potential.
The Brynhild field ceased production in 2018 and the decommissioning plan was approved by Norwegian and UK authorities in 2020. Abandonment of the four Brynhild subsea wells was completed in 2020 and the marine campaign for removal of the subsea facilities was completed in July 2021. The Gaupe field ceased production in 2018 and preparation of the decommissioning plan for the field is ongoing, with decommissioning activities expected to commence in 2023. Following completion of Brynhild and Gaupe decommissioning, the Company has no further planned decommissioning spend until around 2035. The decommissioning expenditure guidance for 2021 has been reduced from MUSD 20 to MUSD 15.
In January 2021, the Company was awarded 19 licences in the 2020 APA licensing round, of which seven are as operator.
In February 2021, Lundin Energy entered into a sales and purchase agreement with AkerBP involving the acquisition of a six percent working interest in licences PL036E, PL036F, PL102H, PL102F, PL102D and PL102G which includes the Trell and Trine discoveries. The transaction included the sale of a five percent working interest in PL869 and a 15 percent working interest in PL1041.
In May 2021 Lundin Energy entered into a sales and purchase agreement with One-Dyas involving the divestment of ten percent working interest in PL976 which includes the Dovregubben prospect.
In June 2021, Lundin Energy was awarded two licences in the 25th licensing round.
In September 2021, Lundin Energy applied for licences in the 2021 APA licensing round where awards are anticipated in early 2022.
In October 2021, Lundin Energy entered into purchase agreement with OMV Norge AS involving the acquisition of an additional 25 percent working interest in licence PL537, which includes the Wisting discovery, bringing the Lundin Energy working interest to 35 percent. The transaction, which is effective from January 2021, adds estimated net contingent resources of approximately 130 MMboe for a cash consideration of MUSD 320, and is subject to the usual Norwegian regulatory approvals and is expected to complete in the fourth quarter 2021. There is a potential contingency payment also in place, capped at MUSD 20, based on sharing the benefit of any capital savings between the current estimate and the final PDO amount.
The Company currently holds 89 licences in Norway.
During the reporting period, there were no lost time incidents and six medical treatment incidents, resulting in a Lost Time Incident Rate of zero per million hours worked and a Total Recordable Incident Rate of 2.8 per million hours worked. There were no process safety or material environmental incidents during the reporting period.
The Company generated record high revenue and other income for the reporting period of MUSD 3,862.9 (MUSD 1,784.7) resulting in operating profit for the reporting period of MUSD 2,586.2 (MUSD 932.6). The increase compared to the comparative period was mainly driven by higher sales volumes and higher oil and gas prices. Sales volumes increased by 24 percent compared to the comparative period caused by better production performance, inventory movements and overlift movements during the reporting period. Realised prices per boe increased by 83 percent compared to the comparative period with realised gas and NGL prices during the third quarter being almost four times higher compared to the third quarter of 2020. Operating profit was negatively impacted by higher exploration costs compared to the comparative period. Production and depletion costs increased compared to the comparative period due to higher sales volumes.
The net result for the reporting period amounted to MUSD 372.1 (MUSD 80.5), representing earnings per share of USD 1.31 (USD 0.28). Net result was driven by the higher operating profit and negatively impacted by a largely non-cash foreign currency exchange loss during the reporting period of MUSD 132.5 (MUSD 85.2). Adjusted net result for the reporting period amounted to MUSD 542.4 (MUSD 193.1), representing adjusted earnings per share of USD 1.91 (USD 0.68). Adjusted net result separates out the effects of loan modification gains, foreign currency exchange results, ineffective interest rate hedge contracts, and the tax impacts from these items and better reflects the net result generated by the Company's operational performance for the reporting period. Adjusted net result for the third quarter amounted to MUSD 234.0 (MUSD 75.8) and represented a record high quarterly adjusted net result for the Company.
The Company generated earnings before interest, tax, depletion, amortization and exploration expenses (EBITDAX) for the reporting period of MUSD 3,360.6 (MUSD 1,431.8) representing EBITDAX per share of USD 11.82 (USD 5.04), with the increase compared to the comparative period mainly caused by the higher sales volumes and higher oil prices. EBITDAX for the third quarter amounted to MUSD 1,282.6 (MUSD 515.6) and represented a record high quarterly EBITDAX for the Company. Cash flow from operating activities (CFFO) for the reporting period amounted to MUSD 2,499.9 (MUSD 1,251.3), representing CFFO per share of USD 8.79 (USD 4.40) with the increase compared to the comparative period, again impacted by higher sales volumes and higher oil prices, but negatively impacted by working capital changes and higher tax payments during the reporting period. CFFO for the third quarter amounted to MUSD 1,012.0 (MUSD 353.2) and also represented a record high quarterly CFFO for the Company. Free cash flow for the reporting period amounted to MUSD 1,622.9 (MUSD 545.7), representing free cash flow per share of USD 5.71 (USD 1.92), with the increase compared to the comparative period mainly impacted by higher CFFO partly offset by higher investments in oil and gas properties. Free cash flow for the third quarter amounted to MUSD 673.8 (MUSD 164.2). Driven by the strong free cash flow generation during the reporting period, the Company reduced its net debt from MUSD 3,911.5 as per the end of 2020 to MUSD 2,646.9 as per the end of the reporting period, a reduction of approximately BUSD 1.3.
Based on an assumed Dated Brent oil price of USD 80 per bbl during the fourth quarter, the Company forecasts to generate a full year EBITDAX of between BUSD 4.8 to BUSD 4.9, a full year CFFO of between BUSD 2.9 to BUSD 3.0 and a full year Free cash flow of between BUSD 1.4 to BUSD 1.6. Among other items, this forecast is based on an assumed lifting programme for crude oil cargoes during the fourth quarter 2021 with the October and November programmes being known at the time of compiling the forecast, whilst the December lifting programme is based on a forecast.
In April 2021, the Company completed a transaction with OX2 AB (OX2) to acquire a 100 percent interest in the Karskruv onshore wind farm project in southern Sweden. The wind farm will become operational in late 2023 and will produce an estimated 290 GWh per annum, from 20 onshore wind turbines. The total investment in Karskruv, including the acquisition cost, will amount to MEUR 130 with the majority of the spend occurring in 2022 and 2023 and the project will be cash flow positive from 2024.
Revenue and other income for the reporting period amounted to MUSD 3,862.9 (MUSD 1,784.7) 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 3,837.1 (MUSD 1,759.8). The average price achieved by Lundin Energy for a barrel of oil equivalent (boe) from own production, amounted to USD 66.48 (USD 36.31) and is detailed in the following table. The average gas price achieved during the third quarter by Lundin Energy for a barrel of oil equivalent (boe) amounted to USD 100.74 (USD 18,89), more than five times higher compared to the third quarter of 2020. The average Dated Brent price for the reporting period amounted to USD 67.92 (USD 41.06) per barrel and USD 73.51 (USD 42.94) for the third quarter.
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 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Crude oil sales | |||||
| - Quantity in Mboe | 48,844.6 | 16,644.6 | 38,822.4 | 12,022.5 | 54,263.6 |
| - Average price per bbl | 66.79 | 71.62 | 38.07 | 42.94 | 39.96 |
| Gas and NGL sales | |||||
| - Quantity in Mboe | 4,484.0 | 1,866.2 | 4,231.7 | 1,418.1 | 6,013.2 |
| - Average price per boe | 63.19 | 83.36 | 20.15 | 21.26 | 23.80 |
| Total sales | |||||
| - Quantity in Mboe | 53,328.6 | 18,510.8 | 43,054.1 | 13,440.6 | 60,276.8 |
| - Average price per boe | 66,48 | 72.80 | 36.31 | 40.65 | 38.35 |
The table above excludes crude oil revenue from third party activities.
The sales of crude oil from third party activities for the reporting period amounted to MUSD 291.6 (MUSD 196.6) and consisted of crude oil purchased from outside the Group by Lundin Energy Marketing SA and sold to the market. Revenue from sale of oil and gas are recognised when control of the products is transferred to the customer.
Other income for the reporting period amounted to MUSD 25.8 (MUSD 24.9) and mainly included tariff income of MUSD 17.4 (MUSD 17.9), which is due to net income from Ivar Aasen tariffs paid to Edvard Grieg. Other income for the reporting period also included a gain of MUSD 2.0 (MUSD 0.8) relating to short-term oil price derivatives.
Production costs including under/over lift movements and inventory movements for the reporting period amounted to MUSD 187.4 (MUSD 139.2) and are detailed in Note 2. The total production cost per barrel of oil equivalent produced is detailed in the table below:
| 1 Jan 2021- 30 Sep 2021 |
1 Jul 2021- 30 Sep 2021 |
1 Jan 2020- 30 Sep 2020 |
1 Jul 2020- 30 Sep 2020 |
1 Jan 2020- 31 Dec 2020 |
|
|---|---|---|---|---|---|
| Production costs | 9 months | 3 months | 9 months | 3 months | 12 months |
| Cost of operations | |||||
| - In MUSD | 116.0 | 40.9 | 101.9 | 32.4 | 134.5 |
| - In USD per boe | 2.25 | 2.29 | 2.36 | 2.24 | 2.24 |
| Tariff and transportation expenses | |||||
| - In MUSD | 51.0 | 18.6 | 36.4 | 13.5 | 50.7 |
| - In USD per boe | 0.99 | 1.05 | 0.84 | 0.93 | 0.84 |
| Operating costs | |||||
| - In MUSD | 167.0 | 59.5 | 138.3 | 45.9 | 185.2 |
| - In USD per boe1 | 3.24 | 3.34 | 3.20 | 3.17 | 3.08 |
| Change in under/over lift position | |||||
| - In MUSD | 4.3 | 11.7 | -3.9 | -12.0 | -2.7 |
| - In USD per boe | 0.08 | 0.65 | -0.09 | -0.82 | -0.05 |
| Change in inventory position | |||||
| - In MUSD | 11.2 | -0.6 | 0.4 | 0.5 | -11.2 |
| - In USD per boe | 0.22 | -0.03 | 0.01 | 0.03 | -0.19 |
| Other | |||||
| - In MUSD | 4.9 | 1.6 | 4.4 | 1.5 | 5.9 |
| - In USD per boe | 0.09 | 0.09 | 0.10 | 0.11 | 0.10 |
| Production costs | |||||
| - In MUSD | 187.4 | 72.2 | 139.2 | 35.9 | 177.2 |
| - In USD per boe | 3.63 | 4.05 | 3.22 | 2.49 | 2.94 |
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 Energy's operating cost for the reporting period of USD 3.24 (USD 3.20) per barrel is reduced to USD 2.90 (USD 2.79) when tariff income is netted off. The operating cost for the third quarter of USD 3.34 (USD 3.17) per barrel is reduced to USD 3.05 (USD 2.80) when tariff income is netted off.
The total cost of operations for the reporting period amounted to MUSD 116.0 (MUSD 101.9) and the total cost of operations excluding operational projects amounted to MUSD 111.2 (MUSD 97.2). The cost of operations per barrel for the reporting period amounted to USD 2.25 (USD 2.36) including operational projects and USD 2.16 (USD 2.25) excluding operational projects. The lower unit costs compared to the comparative period are mainly caused by higher production volumes partly offset by a stronger Norwegian Krone.
Tariff and transportation expenses for the reporting period amounted to MUSD 51.0 (MUSD 36.4) or USD 0.99 (USD 0.84) per boe. The increase on a per barrel basis compared to the comparative period is caused by a stronger Norwegian Krone and an increase in a few crude and gas unit tariffs.
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 MUSD 4.3 (MUSD -3.9) in the reporting period due to the timing of the cargo liftings compared to production. The change in inventory position is also valued at production cost including depletion cost, and amounted to MUSD 11.2 (MUSD 0.4) in the reporting period due to a cargo in transit at the end of 2020 that was sold in early 2021. Sales quantities and production quantities are detailed in the table below:
| Change in over/underlift position In Mboepd |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Production volumes | 188.8 | 193.6 | 157.6 | 157.5 | 164.5 |
| Inventory movements | 2.3 | – | – | – | -1.7 |
| Production volumes including inventory movements | 191.1 | 193.6 | 157.6 | 157.5 | 162.8 |
| Sales volumes from own production | 195.3 | 201.2 | 157.1 | 146.1 | 164.7 |
| Change in over/underlift position | -4.2 | -7.6 | 0.5 | 11.4 | -1.9 |
Other costs for the reporting period amounted to MUSD 4.9 (MUSD 4.4) and related to the business interruption insurance.
Depletion and decommissioning costs for the reporting period amounted to MUSD 531.2 (MUSD 446.8), at an average rate of USD 10.30 (USD 10.35) per boe. Depletion costs on a per barrel basis compared to the comparative period were stable consisting of a lower depletion rate per barrel in Norwegian Krone as a result of increased reserves in Norway offset by a stronger Norwegian Krone as the depletion rate per boe is calculated in Norwegian Krone.
Exploration costs expensed in the income statement for the reporting period amounted to MUSD 237.9 (MUSD 47.3). Exploration and appraisal costs are capitalised as they are incurred. When exploration and appraisal drilling is unsuccessful, the capitalised costs are expensed. All capitalised exploration costs are reviewed on a regular basis and are expensed when facts and circumstances suggest that the carrying value of an exploration and evaluation asset may exceed its recoverable amount.
Purchase of crude oil from third parties for the reporting period amounted to MUSD 289.2 (MUSD 193.3) and related to crude oil purchased from outside the Group.
The general administrative and depreciation expenses for the reporting period amounted to MUSD 31.0 (MUSD 25.5), which included a charge of MUSD 4.8 (MUSD 3.2) 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 5.3 (MUSD 5.2).
Finance income for the reporting period amounted to MUSD 1.0 (MUSD 1.0) and is detailed in Note 4.
Finance costs for the reporting period amounted to MUSD 286.1 (MUSD 258.2) and are detailed in Note 5.
The net foreign currency exchange loss for the reporting period amounted to MUSD 132.5 (MUSD 85.2). 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 Energy is exposed to exchange rate fluctuations relating to the relationship between US Dollar and other currencies. Lundin Energy has entered into derivative financial instruments to address this exposure for exchange rate fluctuations for capital expenditure amounts and Corporate and Special Petroleum Tax amounts. For the reporting period, the net realised exchange gain on these settled foreign exchange instruments amounted to MUSD 1.6 (loss of MUSD 54.9).
The US Dollar strengthened six percent 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 and generating a net foreign currency exchange loss on an intercompany loan balance denominated in US Dollar, which is also borrowed by a subsidiary using Euro as functional currency. In addition, the Norwegian Krone strengthened three percent against the Euro during the reporting period, generating a net foreign currency exchange gain on an intercompany loan balance denominated in Norwegian Krone.
Interest expenses for the reporting period amounted to MUSD 35.0 (MUSD 77.9) and represented the portion of interest charged to the income statement. An additional amount of interest of MUSD 18.0 (MUSD 18.0), mainly associated with the funding of the Norwegian development projects was capitalised during the reporting period. The total interest expenses for the reporting period decreased compared to the comparative period as a result of a lower LIBOR rate, a lower interest rate margin over LIBOR following the refinancing in December 2020 and a lower average outstanding debt relative to the comparative period.
The result on interest rate hedge settlements for the reporting period amounted to a loss of MUSD 79.4 (MUSD 29.3), as a result of the lower LIBOR rate and included a MUSD 35.3 charge to the income statement in relation to interest rate hedge contracts no longer considered effective under hedge effectiveness testing. The Company issued USD 2 billion of Senior Notes in June 2021 with a fixed interest rate and used the net proceeds, in combination with cash on hand, to repay USD 2 billion of the corporate credit facility term loans with a floating interest rate. As a result, part of the outstanding interest rate hedge contracts are no longer effective under hedge effectiveness testing.
The amortisation of the deferred financing fees for the reporting period amounted to MUSD 17.3 (MUSD 12.3) and related to the expensing of the fees incurred in establishing the credit facility over the period of usage of the facility. In addition, the unamortised portion of the capitalised financing fees incurred in relation to the repaid USD 2 billion corporate credit facility term loans were expensed during the reporting period.
Loan facility commitment fees for the reporting period amounted to MUSD 5.3 (MUSD 8.7) and related to commitment fees for the undrawn amounts under the revolving corporate credit facility which was undrawn at the end of the reporting period.
The unwinding of the loan modification gain in the comparative period amounted to MUSD 29.1 and related to the expensing of the accounting gain from the re-negotiated improved borrowing terms in 2018 for the reserve-based lending facility over the period of usage of the facility.
Share in result of joint ventures for the reporting period amounted to MUSD 0.8 (MUSD 0.0) and related to the 50 percent non-operated interest in the Leikanger hydropower project in Norway.
The overall tax charge for the reporting period amounted to MUSD 1,929.8 (MUSD 594.9) and is detailed in Note 6.
The current tax charge for the reporting period amounted to MUSD 1,682.7 (MUSD 251.2) and mainly related to Norway. The current tax charge for Norway for the reporting period related to both Corporate Tax and Special Petroleum Tax (SPT). The paid tax installments in Norway during the reporting period amounted to MUSD 677.4, which has in combination with the current tax charge for the reporting period and exchange rate movements resulted in an increase in current tax liabilities, compared to the end 2020, from MUSD 444.4 to MUSD 1,410.5.
On 19th June 2020, certain temporary changes in the Norwegian Petroleum Tax Law were enacted. The temporary changes allow investments incurred in 2020 and 2021 to be fully deducted against SPT in the year of investment compared to a six year linear depreciation for the ordinary tax regime. There is a further deduction available against the SPT in the form of an uplift. For the years 2020 and 2021, the uplift has been changed to 24 percent of the investment incurred in the year and is fully deductible in the year the investment is incurred, versus the previous uplift treatment which stipulated that the investment incurred during the year qualified for an uplift of 5.2 percent annually over four years (i.e. 20.8 percent uplift). The temporary changes in the Petroleum Tax Law also apply for Plan for Development and Operations submitted within 2022. These tax rules changes resulted in a reduction on current taxes for 2020 and 2021 and an increase in deferred taxes.
The Norwegian Government has further proposed to revise the SPT system as of 2022, replacing the rules on depreciation and uplift with immediate investment expensing (cash-flow tax), though the combined tax rate for corporation tax and SPT will remain unchanged at 78%. The consultation deadline is 3rd December 2021. These changes have no implication for the rules for the temporary changes described above.
The deferred tax charge for the reporting period amounted to MUSD 247.1 (MUSD 343.7) and related to Norway. A deferred tax amount arises primarily where there is a difference in depletion for tax and accounting purposes, with the deferred tax charge decreased for the reporting period due to the temporary tax changes for the Special Petroleum Tax in Norway enacted in June 2020, as outlined above.
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 13.7 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. The effective tax rate for the reporting period was mainly impacted by the reported foreign currency exchange loss and the expensed interest rate hedge contracts which are no longer considered effective under hedge effectiveness testing. The effective tax rate on the adjusted net results for the reporting period amounted to 78 percent.
Oil and gas properties amounted to MUSD 5,872.5 (MUSD 5,902.4) and are detailed in Note 7. Oil and gas properties included Right of use assets as per IFRS16 and amounted to MUSD 20.0 (MUSD –) relating to a drilling rig recognised under IFRS 16 during the reporting period.
Development, exploration and appraisal expenditure incurred for the reporting period was as follows:
| 1 Jan 2021- | 1 Jul 2021- | 1 Jan 2020- | 1 Jul 2020- | 1 Jan 2020- | |
|---|---|---|---|---|---|
| Development expenditure | 30 Sep 2021 | 30 Sep 2021 | 30 Sep 2020 | 30 Sep 2020 | 31 Dec 2020 |
| In MUSD | 9 months | 3 months | 9 months | 3 months | 12 months |
| Norway | 562.3 | 219.7 | 491.4 | 139.5 | 639.8 |
| Development expenditure | 562.3 | 219.7 | 491.4 | 139.5 | 639.8 |
Development expenditure of MUSD 562.3 (MUSD 491.4) was incurred in Norway during the reporting period, primarily on the Johan Sverdrup, Edvard Grieg, Solveig and Rolvsnes fields. In addition an amount of MUSD 18.0 (MUSD 18.0) of interest was capitalised.
| 1 Jan 2021- | 1 Jul 2021- | 1 Jan 2020- | 1 Jul 2020- | 1 Jan 2020- | |
|---|---|---|---|---|---|
| Exploration and appraisal expenditure In MUSD |
30 Sep 2021 9 months |
30 Sep 2021 3 months |
30 Sep 2020 9 months |
30 Sep 2020 3 months |
31 Dec 2020 12 months |
| Norway | 242.2 | 102.4 | 85.8 | 21.3 | 152.9 |
| Exploration and appraisal expenditure | 242.2 | 102.4 | 85.8 | 21.3 | 152.9 |
Exploration and appraisal expenditure of MUSD 242.2 (MUSD 85.8) was incurred in Norway during the reporting period, primarily for the exploration and appraisal wells as summarised on page 5.
Renewable energy properties amounted to MUSD 31.8 (MUSD –) and related to the fully consolidated 100 percent interest in the Karskruv onshore wind farm project in southern Sweden. Lundin Energy also holds a 50 percent interest in the Metsälamminkangas (MLK) wind farm project in Finland and a 50 percent interest in the Leikanger hydropower project in Norway which are not fully consolidated and reported as investments in joint ventures instead and amounted to MUSD 145.0 (MUSD 110.6).
The net investments by the Company in the renewable energy business, part through its joint ventures, for the reporting period was at follows:
| Renewables investments In MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Karskruv Windfarm – Sweden | 30.9 | – | – | – | – |
| MLK Windfarm – Finland | 39.7 | 17.5 | 35.2 | 5.4 | 46.3 |
| Leikanger Hydropower – Norway | 0.6 | – | 44.9 | – | 49.8 |
| Natural Carbon Capture | 3.7 | 3.1 | – | – | – |
| Renewables investments | 74.9 | 20.6 | 80.1 | 5.4 | 96.1 |
Other tangible fixed assets amounted to MUSD 39.6 (MUSD 45.2) and are detailed in Note 8. Other tangible fixed assets included Right of use assets as per IFRS 16 and amounted to MUSD 27.0 (MUSD 31.8).
Goodwill associated with the accounting for the Edvard Grieg transaction during 2016 amounted to MUSD 128.1 (MUSD 128.1).
Financial assets amounted to MUSD 13.7 (MUSD 13.5) and are detailed in Note 9. The sale of 2.6 percent of Johan Sverdrup during 2019 included a contingent consideration based on future reserve reclassifications and is due in 2026. This contingent consideration was fair valued by the Company and amounted to MUSD 12.9 (MUSD 12.7).
Trade and other receivables amounted to MUSD 16.8 (MUSD 17.3) and related to prepayments with a long-term nature.
Derivative instruments amounted to MUSD 9.4 (MUSD 3.8) and related to the marked-to-market valuation of outstanding interest rate and currency hedge contracts, due to be settled after twelve months.
Inventories amounted to MUSD 46.2 (MUSD 59.1) and included both well supplies and hydrocarbon inventories. Hydrocarbon inventories as per end 2020 included a cargo lifting at the end of 2020, which was sold in early 2021.
Trade and other receivables amounted to MUSD 460.4 (MUSD 278.6) and are detailed in Note 10. Trade receivables, which are all current, amounted to MUSD 264.4 (MUSD 215.5). Underlift amounted to MUSD 5.6 (MUSD 5.7) and was attributable to an underlift position on the producing fields, mainly relating to oil from the Johan Sverdrup field and the Alvheim Area. Joint operations debtors relating to various joint venture receivables amounted to MUSD 29.1 (MUSD 21.8). Prepaid expenses and accrued income amounted to MUSD 150.4 (MUSD 26.5) and included MUSD 128.4 (MUSD –) related to cargo liftings during the reporting period not yet invoiced by the end of the reporting period and prepaid operational and insurance expenditure. Other current assets amounted to MUSD 10.9 (MUSD 9.1).
Derivative instruments amounted to MUSD 6.3 (MUSD 12.1) and related to the marked-to-market valuation of outstanding currency hedge contracts, due to be settled within twelve months.
Current tax assets amounted to MUSD 9.6 (MUSD –) and related to payments of tax installments outside Norway during the reporting period and expected to be recovered in the future.
Cash and cash equivalents amounted to MUSD 853.1 (MUSD 82.5). Cash balances are mainly held to meet ongoing operational funding requirements as well as to provide headroom liquidity.
Bonds amounted to MUSD 1,978.9 (MUSD –) and are detailed in Note 11. The Company issued USD 2 billion of Senior Notes in June 2021 consisting of USD 1 billion 2.0% Senior Notes due in 2026 at a price equal to 99.827 percent and USD 1 billion 3.1% Senior Notes due in 2031 at a price equal to 99.81 percent with interest payable semi-annually. Capitalised financing fees relating to the bonds issuance amounted to MUSD 17.6 (MUSD –) and are being amortised over the expected life of the bonds.
Financial liabilities amounted to MUSD 1,500.7 (MUSD 3,983.9) and are detailed in Note 12. Bank loans amounted to MUSD 1,500.0 (MUSD 3,994.0) and related to the outstanding term loans under the corporate credit facility. The Company repaid USD 2 billion of the corporate credit facility term loans in June 2021 following the bonds issuance. Capitalised financing fees relating to the establishment of the credit facility amounted to MUSD 19.7 (MUSD 37.1) and are being amortised over the expected life of the facility. The lease commitments amounted to MUSD 20.4 (MUSD 27.0) and related to the long-term portion of the lease commitments under IFRS 16. The short-term portion of the lease commitments was classified as current liabilities and amounted to MUSD 28.3 (MUSD 5.7). The increase in lease commitments is mainly caused by a drilling rig recognised under IFRS 16 during the reporting period.
Provisions amounted to MUSD 628.3 (MUSD 565.6) and are detailed in Note 13. The provision for site restoration amounted to MUSD 620.3 (MUSD 560.5) and related to the long-term portion of the future decommissioning obligations. The short-term portion of the future decommissioning obligations was classified as current liabilities and amounted to MUSD 9.0 (MUSD 16.0).
Deferred tax liabilities amounted to MUSD 3,053.1 (MUSD 2,893.9). 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 48.0 (MUSD 144.7) and related to the marked-to-market valuation of outstanding interest rate and currency hedge contracts, due to be settled after twelve months.
Current financial liabilities amounted to MUSD 28.3 (MUSD 6.1) and are detailed in Note 11. Current financial liabilities related to the shortterm portion of the outstanding lease commitments.
Dividends amounted to MUSD 255.4 (MUSD 72.3) and related to the cash dividend approved by the AGM held on 30 March 2021 in Stockholm, paid in quarterly installments.
Trade and other payables amounted to MUSD 318.4 (MUSD 202.5) and are detailed in Note 14. Trade payables amounted to MUSD 14.5 (MUSD 8.7). Joint operations creditors and accrued expenses amounted to MUSD 244.3 (MUSD 151.3) and related to activity in Norway. Other accrued expenses amounted to MUSD 39.7 (MUSD 31.7) and other current liabilities amounted to MUSD 14.2 (MUSD 9.2).
Derivative instruments amounted to MUSD 87.9 (MUSD 87.6) and related to the marked-to-market valuation of outstanding interest rate and currency hedge contracts, due to be settled within twelve months.
Current tax liabilities amounted to MUSD 1,410.5 (MUSD 444.4) and related mainly to Norway. The current tax liabilities have increased during the reporting period mainly due to a current tax charge for the reporting period of MUSD 1,682.7 offset by cash tax payments of MUSD 677.4 during the reporting period.
Current provisions amounted to MUSD 14.5 (MUSD 21.3) and are detailed in Note 13. The short-term portion of the future decommissioning obligations amounted to MUSD 9.0 (MUSD 16.0) relating to the Gaupe and Brynhild fields. The short-term portion of the provision for Lundin Energy's Unit Bonus Plan amounted to MUSD 5.5 (MUSD 5.3).
Changes in working capital for the reporting period, as included in the consolidated statement of cash flows, amounted to MUSD -86.2 (MUSD 92.4). Working capital increases mainly related to higher receivables at the end of the reporting period as a result of increasing oil and gas prices, partly offset by higher payables.
The business of the Parent Company is investment in and management of oil and gas assets and renewable energy projects. The net result for the Parent Company for the reporting period amounted to MSEK 4,295.9 (MSEK 2,700.3). The net result for the reporting period included MSEK 4,467.2 (MSEK 2,867.8) financial income as a result of received dividends from a subsidiary. The net result excluding received dividends amounted to MSEK -171.3 (MSEK -167.5).
The net result for the reporting period included general and administrative expenses of MSEK 181.6 (MSEK 175.7) and net finance costs of MSEK 0.3 (MSEK 4.1) when excluding the received dividends as mentioned above.
Lundin Energy recognises the following related parties: associated companies, jointly controlled entities, key management personnel and members of their close family or other parties that are partly, directly or indirectly controlled by key management personnel or of its family or of any individual that controls, or has joint control or significant influence over the entity.
During the second quarter, the Group entered into a sponsorship agreement with Team Tilt SA, a Swiss sailing racing team, for their participation in the SailGP high-speed racing catamaran series. The sponsorship agreement spans over three years, with an annual payment of between MUSD 2.6 to MUSD 3.5, with the first payment expected to be made in the fourth quarter of 2021.
Team Tilt SA's majority owner is Sebastien Schneiter, an internationally recognised sailor who has represented Switzerland at European, World and Olympic events. Sebastien Schneiter is a close family member of the Company's current Board member and former CEO Alex Schneiter.
In June 2021, Lundin Energy issued USD 2 billion of Senior Notes consisting of USD 1 billion 2.0% Senior Notes due in 2026 at a price equal to 99.827 percent and USD 1 billion 3.1% Senior Notes due in 2031 at a price equal to 99.81 percent. Interest will be payable semiannually and none of the bonds have financial covenants. The Company used the net proceeds, in combination with cash on hand, to repay USD 2.0 billion of the corporate credit facility term loans entered into in December 2020. On 15 July 2021, the Senior Notes were listed on the Securities Official List of the Luxembourg Stock Exchange.
In December 2020, Lundin Energy entered into a five year corporate credit facility of USD 5 billion. The facility is a combination of a five-year USD 1.5 billion revolving credit facility and USD 3.5 billion term loans, split across two, three, four and five year maturities with USD 2.0 billion term loans being repaid in June 2021 leaving USD 1.5 billion term loans, split across three, four and five year maturities. The facility also includes the option to bring in additional commitments in an accordion option of up to USD 1 billion. In line with the Company's best in class environmental profile, ESG KPIs on carbon intensity and renewable electricity generation have been incorporated into the margin structure, providing further financial incentives for the delivery of the Decarbonisation Strategy and the 2025 carbon neutrality target. The Company achieved a lower interest rate margin over LIBOR during the reporting period based on the ESG KPIs incorporated in the margin structure. The structure of the Facility is such, that it is compatible with the issued unsecured bonds through the debt capital markets at pari passu terms.
The Company currently has Baa3, BBB- and BBB- credit ratings from Moody's, S&P and Fitch respectively, all with a stable outlook.
The Swedish Prosecution Authority issued a notification of a corporate fine and forfeiture of economic benefits against Lundin Energy 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 twelfth year and Lundin Energy 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.
In October 2021, Lundin Energy entered into purchase agreement with OMV Norge AS involving the acquisition of an additional 25 percent working interest in licence PL537, which includes the Wisting discovery, bringing the Lundin Energy working interest to 35 percent. The transaction, which is effective from January 2021, adds estimated net contingent resources of approximately 130 MMboe for a cash consideration of MUSD 320, and is subject to the usual Norwegian regulatory approvals and is expected to complete in the fourth quarter 2021. There is a potential contingency payment also in place, capped at MUSD 20, based on sharing the benefit of any capital savings between the current estimate and the final PDO amount.
In October 2021. the Dovregubben well in PL976 was drilled as a dry well and this well will be expensed in the fourth quarter.
In October 2021, Lundin Energy entered into foreign currency contracts to buy MNOK 629.0 for MUSD 73.6 at an average contractual exchange rate of NOK 8.55:USD 1 for the fourth quarter of 2021. Lundin Energy also acquired foreign currency put options to buy MNOK 822.0 at an average strike price of 8.11 for the first half of 2022.
Lundin Energy AB's issued share capital amounted to SEK 3,478,713 represented by 285,924,614 shares with a quota value of SEK 0.01 each (rounded off) with the issued share capital including a bonus issue (sw. fondemission) of SEK 556,594 during 2019, to restore the share capital of Lundin Energy to the same amount as immediately prior to the share redemption as approved by the EGM of Lundin Energy held on 31 July 2019.
During 2017, Lundin Energy 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 Energy 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.
During 2020, Lundin Energy used 300,167 of the purchased own shares for settlement of the 2017 performance based incentive plan and during 2021, Lundin Energy used 216,708 of the purchased own shares for settlement of the 2018 performance based incentive plan resulting in 1,356,435 of its own shares held by the Company by the end of the reporting period.
The AGM of Lundin Energy held on 30 March 2021 in Stockholm approved a cash dividend distribution for the year 2020 of USD 1.80 per share, to be paid in quarterly installments of USD 0.45 per share. Before payment, each quarterly dividend of USD 0.45 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 4,467.2, equaling MUSD 511.8 based on the exchange rate on the date of AGM approval.
The first dividend payment was made on 8 April 2021, the second dividend payment was made on 7 July 2021 and the third dividend payment was made on 7 October 2021. The fourth dividend payment is expected to be paid on 11 January 2022, with an expected record date of 5 January 2022 and expected ex-dividend date of 4 January 2022.
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 2020 dividend has been set to a cap of SEK 7.636 billion (i.e., SEK 1.909 billion per quarter). If the total dividend would exceed the cap of SEK 7.636 billion, the dividend will be automatically adjusted downwards so that the total dividend corresponds to the cap of SEK 7.636 billion.
Given the current favourable market conditions, and should such conditions prevail for the rest of the year, the Board of Directors anticipates to propose to the Annual General Meeting 2022 to increase the 2021 dividend by 25 percent to USD 2.25 per share, corresponding to MUSD 640, to be paid in quarterly installments.
Lundin Energy's principles for remuneration and details of the long-term incentive plans are provided in the Company's 2020 Annual Report, Remuneration Report and in the materials provided to shareholders in respect of the 2021 AGM, available on www.lundin-energy.com
The number of units relating to the awards made in 2019, 2020 and 2021 under the Unit Bonus Plan outstanding as at 30 September 2021 were 60,478, 174,316 and 221,535 respectively.
The AGM 2021 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 2021 and the 2021 award is accounted for from the second half of 2021. The total outstanding number of awards at 30 September 2021 was 262,902 and the awards vest over three years from 1 July 2021 subject to certain performance conditions being met. Each original award was fair valued at the date of grant at SEK 173.10 using an option pricing model.
The 2020 plan is effective from 1 July 2020 and the 2020 award is accounted for from the second half of 2020. The total outstanding number of awards at 30 September 2021 was 417,051 and the awards vest over three years from 1 July 2020 subject to certain performance conditions being met. The outstanding number of awards has increased from the original number of awards reflecting dividends paid since the award date. Each original award was fair valued at the date of grant at SEK 147.10 using an option pricing model.
The 2019 plan is effective from 1 July 2019 and the total outstanding number of awards at 30 June 2021 was 336,891 and the awards vest over three years from 1 July 2019 subject to certain performance conditions being met. The outstanding number of awards has increased from the original number of awards reflecting dividends paid since the award date. Each original award was fair valued at the date of grant at SEK 169.00 using an option pricing model.
The interim Group report has been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial Reporting.
The accounting policies adopted are in all aspects consistent with those followed in the preparation of the Group's annual financial statements for the year ended 31 December 2020.
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 presentation 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 Energy's strategic, operational, financial and external risks and mitigation of those risks through risk management is described in Lundin Energy's 2020 Annual Report.
Lundin Energy has maintained a proactive approach in safeguarding the wellbeing of the Company's employees and contractors and ensuring the virus has minimal impact on its operations. To date there have been no disruptions to production due to the COVID-19 situation and while certain project activities have been affected, the disruptions have been successfully managed to avoid any negative impact on the production outlook.
Lundin Energy has entered into derivative financial instruments to address its exposure for exchange rate fluctuations for capital expenditure amounts relating to its committed field development projects and Corporate and Special Petroleum Tax amounts. At 30 September 2021, Lundin Energy had outstanding foreign currency contracts as summarised below:
| Buy | Sell | Average contractual Exchange rate |
Settlement period |
|---|---|---|---|
| MNOK 682.5 | MUSD 84.8 | NOK 8.05:USD 1 | Oct 2021 – Dec 2021 |
| MNOK 1,430.0 | MUSD 183.4 | NOK 7.80:USD 1 | Jan 2022 – Dec 2022 |
| MNOK 530.0 | MUSD 64.2 | NOK 8.26:USD 1 | Jan 2023 – Dec 2023 |
| MNOK 300.0 | MUSD 33.0 | NOK 9.09:USD 1 | Jan 2024 – Dec 2024 |
During the third quarter, Lundin Energy also entered into foreign currency option contracts. At 30 September 2021, Lundin Energy had outstanding foreign currency option contracts as summarised below:
| Buy | Sell | Average contractual strike price put options |
Settlement period |
|---|---|---|---|
| MNOK 1,431.0 | MUSD 172.9 | NOK 8.28:USD 1 | Nov 2021 |
| MNOK 5,502.0 | MUSD 665.2 | NOK 8.27:USD 1 | Jan 2022 –May 2022 |
Lundin Energy entered into interest rate hedge contracts and at 30 September 2021 had outstanding interest rate hedge contracts as follows:
| Borrowings expressed in MUSD |
Fixing of floating LIBOR average rate per annum |
Settlement period |
|---|---|---|
| 3,100 | 2.28% | Oct 2021 – Dec 2021 |
| 3,200 | 2.20% | Jan 2022 – Dec 2022 |
| 2,700 | 1.38% | Jan 2023 – Dec 2023 |
| 2,200 | 1.47% | Jan 2024 – Dec 2024 |
| 1,400 | 0.71% | Jan 2025 – Dec 2025 |
| 1,100 | 0.81% | Jan 2026 – Jun 2026 |
Under IFRS 9, subject to hedge effectiveness testing, changes to the fair value of effective hedges are reflected in other comprehensive income and changes to the fair value of ineffective hedges are reflected directly in the income statement.
For the preparation of the financial statements for the reporting period, the following currency exchange rates have been used.
| 30 Sep 2021 | 30 Sep 2020 | 31 Dec 2020 | |||||
|---|---|---|---|---|---|---|---|
| Average | Period end | Average | Period end | Average | Period end | ||
| 1 USD equals NOK | 8.5470 | 8.7788 | 9.5450 | 9.4814 | 9.4146 | 8.5326 | |
| 1 USD equals Euro | 0.8356 | 0.8636 | 0.8896 | 0.8541 | 0.8762 | 0.8149 | |
| 1 USD equals SEK | 8.4846 | 8.7817 | 9.4088 | 9.0291 | 9.2092 | 8.1772 |
| Third quarter 2021 | Third quarter 2020 | |
|---|---|---|
| Average | Average | |
| 1 USD equals NOK | 8.7612 | 9.1275 |
| 1 USD equals Euro | 0.8483 | 0.8551 |
| 1 USD equals SEK | 8.6485 | 8.8637 |
| Note | 1 Jan 2021- 30 Sep 2021 |
1 Jul 2021- 30 Sep 2021 |
1 Jan 2020- 30 Sep 2020 |
1 Jul 2020- 30 Sep 2020 |
1 Jan 2020- 31 Dec 2020 |
|
|---|---|---|---|---|---|---|
| Expressed in MUSD | 9 months | 3 months | 9 months | 3 months | 12 months | |
| Revenue and other income | 1 | |||||
| Revenue | 3,837.1 | 1,467.4 | 1,759.8 | 679.2 | 2,533.2 | |
| Other income | 25.8 | 10.8 | 24.9 | 7.8 | 31.2 | |
| 3,862.9 | 1,478.2 | 1,784.7 | 687.0 | 2,564.4 | ||
| Cost of sales | ||||||
| Production costs | 2 | -187.4 | -72.2 | -139.2 | -35.9 | -177.2 |
| Depletion and decommissioning costs | -531.2 | -180.5 | -446.8 | -150.9 | -607.7 | |
| Exploration costs | -237.9 | -37.9 | -47.3 | -0.6 | -104.9 | |
| Purchase of crude oil from third parties | -289.2 | -118.8 | -193.3 | -130.0 | -217.8 | |
| Gross profit | 3 | 2,617.2 | 1,068.8 | 958.1 | 369.6 | 1,456.8 |
| General, administration and depreciation expenses | -31.0 | -6.3 | -25.5 | -7.3 | -36.1 | |
| Operating profit | 2,586.2 | 1,062.5 | 932.6 | 362.3 | 1,420.7 | |
| Net financial items | ||||||
| Finance income | 4 | 1.0 | 0.2 | 1.0 | 0.2 | 172.3 |
| Finance costs | 5 | -286.1 | -126.7 | -258.2 | 84.9 | -318.6 |
| -285.1 | -126.5 | -257.2 | 85.1 | -146.3 | ||
| Share in result of joint ventures | 0.8 | 0.3 | 0.0 | 0.0 | -0.1 | |
| Profit before tax | 2,301.9 | 936.3 | 675.4 | 447.4 | 1,274.3 | |
| Income tax | 6 | -1,929.8 | -798.8 | -594.9 | -235.1 | -890.1 |
| Net result | 372.1 | 137.5 | 80.5 | 212.3 | 384.2 | |
| Attributable to: | ||||||
| Shareholders of the Parent Company | 372.1 | 137.5 | 80.5 | 212.3 | 384.2 | |
| Non-controlling interest | – | – | – | – | – | |
| 372.1 | 137.5 | 80.5 | 212.3 | 384.2 | ||
| Earnings per share – USD | 1.31 | 0.48 | 0.28 | 0.74 | 1.35 | |
| Earnings per share fully diluted – USD | 1.31 | 0.48 | 0.28 | 0.74 | 1.35 | |
| Adjusted earnings per share – USD | 1.91 | 0.83 | 0.68 | 0.27 | 0.99 | |
| Adjusted earnings per share fully diluted – USD | 1.90 | 0.82 | 0.68 | 0.27 | 0.98 |
| Expressed in MUSD | 1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Net result | 372.1 | 137.5 | 80.5 | 212.3 | 384.2 |
| Items that may be subsequently reclassified to profit or loss: | |||||
| Exchange differences foreign operations | 117.1 | 60.3 | -146.4 | -105.9 | -210.1 |
| Cash flow hedges | 98.5 | -3.3 | -178.5 | 78.4 | -63.4 |
| Other comprehensive income, net of tax | 215.6 | 57.0 | -324.9 | -27.5 | -273.5 |
| Total comprehensive income | 587.7 | 194.5 | -244.4 | 184.8 | 110.7 |
| Attributable to: | |||||
| Shareholders of the Parent Company | 587.7 | 194.5 | -244.4 | 184.8 | 110.7 |
| Non-controlling interest | – | – | – | – | – |
| 587.7 | 194.5 | -244.4 | 184.8 | 110.7 |
| Expressed in MUSD | Note | 30 September 2021 | 31 December 2020 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Oil and gas properties | 7 | 5,872.5 | 5,902.4 |
| Renewable energy properties | 31.8 | – | |
| Other tangible fixed assets | 8 | 39.6 | 45.2 |
| Goodwill | 128.1 | 128.1 | |
| Investments in joint ventures | 145.0 | 110.6 | |
| Financial assets | 9 | 13.7 | 13.5 |
| Trade and other receivables | 10 | 16.8 | 17.3 |
| Derivative instruments | 15 | 9.4 | 3.8 |
| Total non-current assets | 6,256.9 | 6,220.9 | |
| Current assets | |||
| Inventories | 46.2 | 59.1 | |
| Trade and other receivables | 10 | 460.4 | 278.6 |
| Derivative instruments | 15 | 6.3 | 12.1 |
| Current tax assets | 9.6 | – | |
| Cash and cash equivalents | 853.1 | 82.5 | |
| Total current assets | 1,375.6 | 432.3 | |
| TOTAL ASSETS | 7,632.5 | 6,653.2 | |
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Shareholders´ equity | -1,691.5 | -1,769.1 | |
| Liabilities | |||
| Non-current liabilities | |||
| Bonds | 11 | 1,978.9 | – |
| Financial liabilities | 12 | 1,500.7 | 3,983.9 |
| Provisions | 13 | 628.3 | 565.6 |
| Deferred tax liabilities | 3,053.1 | 2,893.9 | |
| Derivative instruments | 15 | 48.0 | 144.7 |
| Total non-current liabilities | 7,209.0 | 7,588.1 | |
| Current liabilities | |||
| Financial liabilities | 12 | 28.3 | 6.1 |
| Dividends | 255.4 | 72.3 | |
| Trade and other payables | 14 | 318.4 | 202.5 |
| Derivative instruments | 15 | 87.9 | 87.6 |
| Current tax liabilities | 1,410.5 | 444.4 | |
| Provisions | 13 | 14.5 | 21.3 |
| Total current liabilities | 2,115.0 | 834.2 | |
| Total liabilities | 9,324.0 | 8,422.3 | |
| TOTAL EQUITY AND LIABILITIES | 7,632.5 | 6,653.2 |
| Expressed in MUSD | 1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Cash flows from operating activities | |||||
| Net result | 372.1 | 137.5 | 80.5 | 212.3 | 384.2 |
| Adjustments for: | |||||
| Exploration costs | 237.9 | 37.9 | 47.3 | 0.6 | 104.9 |
| Depletion, depreciation and amortisation | 536.5 | 182.2 | 452.0 | 152.8 | 614.6 |
| Current tax | 1,682.7 | 661,3 | 251.2 | 121.7 | 511.8 |
| Deferred tax | 247.1 | 137.5 | 343.7 | 113.4 | 378.3 |
| Long-term incentive plans | 2.3 | -6.7 | 5.4 | 1.8 | 9.5 |
| Foreign currency exchange gain/ loss | 128.2 | 90.9 | 30.3 | -154.6 | -230.3 |
| Interest expense | 35.0 | 12.6 | 77.9 | 19.8 | 104.3 |
| Unwinding of loan modification gain | – | – | 29.1 | 10.1 | 99.7 |
| Amortisation of deferred financing fees | 17.3 | 1.9 | 12.3 | 4.4 | 37.6 |
| Ineffective interest rate hedge contracts | 27.2 | -10.8 | – | – | – |
| Other | 27.4 | 4.2 | 12.8 | 4.6 | 6.3 |
| Interest received | 0.8 | 0.3 | 0.6 | 0.1 | 0.8 |
| Interest paid | -40.8 | -6.4 | -93.3 | -25.6 | -126.6 |
| Income taxes paid / received | -687.6 | -321.1 | -90.9 | -37.8 | -428.5 |
| Changes in working capital | -86.2 | 90.7 | 92.4 | -70.4 | 61.4 |
| Total cash flows from operating activities | 2,499.9 | 1,012.0 | 1,251.3 | 353.2 | 1,528.0 |
| Cash flows from investing activities | |||||
| Investment in oil and gas properties | -790.2 | -314.1 | -579.2 | -160.8 | -919.7 |
| Investment in renewable energy business1 | -74.9 | -22.3 | -80.8 | -3.8 | -99.8 |
| Investment in other fixed assets | -1.0 | -0.4 | -1.6 | -0.3 | -2.4 |
| Decommissioning costs paid | -10.9 | -1.4 | -44.0 | -24.1 | -57.9 |
| Total cash flows from investing activities | -877.0 | -338.2 | -705.6 | -189.0 | -1,079.8 |
| Cash flows from financing activities | |||||
| Senior Notes | 1,996.4 | – | – | – | – |
| Net drawdown/repayment of corporate credit facility | -2,494.0 | – | – | – | 3,994.0 |
| Net drawdown/repayment of reserve-based lending facility | – | – | -256.0 | -35.0 | -4,092.0 |
| Repayment of principal portion of lease commitments | -17.4 | -9.1 | -2.4 | -0.9 | -3.2 |
| Financing fees paid | -21.3 | -6.2 | -2.5 | – | -36.8 |
| Dividends paid | -327.0 | -128.0 | -247.1 | -71.0 | -318.2 |
| Total cash flows from financing activities | -863.3 | -143.3 | -508.0 | -106.9 | -456.2 |
| Change in cash and cash equivalents | 759.6 | 530.5 | 37.7 | 57.3 | -8.0 |
| Cash and cash equivalents at the beginning of the period | 82.5 | 310.6 | 85.3 | 74.9 | 85.3 |
| Currency exchange difference in cash and cash equivalents | 11.0 | 12.0 | 6.2 | -3.0 | 5.2 |
| Cash and cash equivalents at the end of the period | 853.1 | 853.1 | 129.2 | 129.2 | 82.5 |
1 Includes incurred cost relating to the acquisition of the renewable energy business and working capital funding of joint ventures
| Share | Additional paid-in capital / |
Retained | Total | ||
|---|---|---|---|---|---|
| Expressed in MUSD | capital | Other reserves | earnings | Dividends | equity |
| At 1 January 2020 | 0.5 | -169.7 | -1,429.6 | – | -1,598.8 |
| Comprehensive income | |||||
| Net result | – | – | 80.5 | – | 80.5 |
| Other comprehensive income | – | -324.9 | – | – | -324.9 |
| Total comprehensive income | – | -324.9 | 80.5 | – | -244.4 |
| Transactions with owners | |||||
| Distributions | – | – | – | -284.1 | -284.1 |
| Issuance of treasury shares | – | 7.3 | – | – | 7.3 |
| Share based payments | – | -9.6 | – | – | -9.6 |
| Value of employee services | – | – | 4.0 | – | 4.0 |
| Total transaction with owners | – | -2.3 | 4.0 | -284.1 | -282.4 |
| At 30 September 2020 | 0.5 | -496.9 | -1,345.1 | -284.1 | -2,125.6 |
| Comprehensive income | |||||
| Net result | – | – | 303.7 | – | 303.7 |
| Other comprehensive income | – | 51.4 | – | – | 51.4 |
| Total comprehensive income | – | 51.4 | 303.7 | – | 355.1 |
| Transactions with owners | |||||
| Value of employee services | – | – | 1.4 | – | 1.4 |
| Total transaction with owners | – | – | 1.4 | – | 1.4 |
| At 31 December 2020 | 0.5 | -445.5 | -1,040.0 | -284.1 | -1,769.1 |
| Transfer of prior year dividends | – | – | -284.1 | 284.1 | – |
| Comprehensive income | |||||
| Net result | – | – | 372.1 | – | 372.1 |
| Other comprehensive income | – | 215.6 | – | – | 215.6 |
| Total comprehensive income | – | 215.6 | 372.1 | – | 587.7 |
| Transactions with owners | |||||
| Distributions | – | – | – | -511.8 | -511.8 |
| Issuance of treasury shares | – | 6.4 | – | – | 6.4 |
| Share based payments | – | -9.0 | – | – | -9.0 |
| Value of employee services | – | – | 4.3 | – | 4.3 |
| Total transaction with owners | – | -2.6 | 4.3 | -511.8 | -510.1 |
| At 30 September 2021 | 0.5 | -232.5 | -947.7 | -511.8 | -1,691.5 |
| Note 1 – Revenue and other income MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Revenue | |||||
| Crude oil from own production | 3,262.1 | 1,192.1 | 1,478.0 | 516.3 | 2,168.5 |
| Crude oil from third party activities | 291.6 | 119.8 | 196.6 | 132.8 | 221.5 |
| Condensate | 69.2 | 38.0 | 40.2 | 15.2 | 63.8 |
| Gas | 214.2 | 117,5 | 45.0 | 14.9 | 79.4 |
| Sales of oil and gas | 3,837.1 | 1,467.4 | 1,759.8 | 679.2 | 2,533.2 |
| Other income | 25,8 | 10.8 | 24.9 | 7.8 | 31.2 |
| Revenue and other income | 3,862.9 | 1,478.2 | 1,784.7 | 687.0 | 2,564.4 |
| Note 2 – Production costs MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Cost of operations | 116.0 | 40.9 | 101.9 | 32.4 | 134.5 |
| Tariff and transportation expenses | 51.0 | 18.6 | 36.4 | 13.5 | 50.7 |
| Change in under/over lift position | 4.3 | 11.7 | -3.9 | -12.0 | -2.7 |
| Change in inventory position | 11.2 | -0.6 | 0.4 | 0.5 | -11.2 |
| Other | 4.9 | 1.6 | 4.4 | 1.5 | 5.9 |
| Production costs | 187.4 | 72.2 | 139.2 | 35.9 | 177.2 |
| Note 3 – Segment information MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Norway | |||||
| Crude oil from own production | 3,262.1 | 1,192.1 | 1,478.0 | 516.3 | 2,168.5 |
| Condensate | 69.2 | 38.0 | 40.2 | 15.2 | 63.8 |
| Gas | 214.2 | 117.5 | 45.0 | 14.9 | 79.4 |
| Revenue | 3,545.5 | 1,347.6 | 1,563.2 | 546.4 | 2,311.7 |
| Other income | 25.8 | 10.8 | 24.0 | 7.7 | 30.3 |
| Revenue and other income | 3,571.3 | 1,358.4 | 1,587.2 | 554.1 | 2,342.0 |
| Production costs | -187.4 | -72.2 | -139.2 | -35.9 | -177.2 |
| Depletion and decommissioning costs | -531.2 | -180.5 | -446.8 | -150.9 | -607.7 |
| Exploration costs | -237.9 | -37.9 | -47.3 | -0.6 | -104.9 |
| Gross profit | 2,614.8 | 1,067.8 | 953.9 | 366.7 | 1,452.2 |
| Other | |||||
| Crude oil from third party activities | 291.6 | 119.8 | 196.6 | 132.8 | 221.5 |
| Revenue | 291.6 | 119.8 | 196.6 | 132.8 | 221.5 |
| Other income | – | – | 0.9 | 0.1 | 0.9 |
| Revenue and other income | 291.6 | 119.8 | 197.5 | 132.9 | 222.4 |
| Purchase of crude oil from third parties | -289.2 | -118.8 | -193.3 | -130.0 | -217.8 |
| Gross profit | 2.4 | 1.0 | 4.2 | 2.9 | 4.6 |
| Note 3 – Segment information cont. MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Total | |||||
| Crude oil from own production | 3,262.1 | 1,192.1 | 1,478.0 | 516.3 | 2,168.5 |
| Crude oil from third party activities | 291.6 | 119.8 | 196.6 | 132.8 | 221.5 |
| Condensate | 69.2 | 38.0 | 40.2 | 15.2 | 63.8 |
| Gas | 214.2 | 117.5 | 45.0 | 14.9 | 79.4 |
| Revenue | 3,837.1 | 1,467.4 | 1,759.8 | 679.2 | 2,533.2 |
| Other income | 25.8 | 10.8 | 24.9 | 7.8 | 31.2 |
| Revenue and other income | 3,862.9 | 1,478.2 | 1,784.7 | 687.0 | 2,564.4 |
| Production costs | -187.4 | -72.2 | -139.2 | -35.9 | -177.2 |
| Depletion and decommissioning costs | -531.2 | -180.5 | -446.8 | -150.9 | -607.7 |
| Exploration costs | -237.9 | -37.9 | -47.3 | -0.6 | -104.9 |
| Purchase of crude oil from third parties | -289.2 | -118.8 | -193.3 | -130.0 | -217.8 |
| Gross profit | 2,617.2 | 1,068.8 | 958.1 | 369.6 | 1,456.8 |
| Note 4 – Finance income MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Foreign currency exchange gain, net | – | – | – | – | 171.0 |
| Interest income | 1.0 | 0.2 | 1.0 | 0.2 | 1.3 |
| Finance income | 1.0 | 0.2 | 1.0 | 0.2 | 172.3 |
| Note 5 – Finance costs MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Foreign currency exchange loss, net | 132.5 | 97.3 | 85.2 | -142.6 | – |
| Interest expense | 35.0 | 12.2 | 77.9 | 19.8 | 104.4 |
| Loss on interest rate hedges | 79.4 | 7.5 | 29.3 | 14.9 | 44.5 |
| Unwinding of site restoration discount | 15.4 | 5.2 | 14.1 | 4.9 | 19.2 |
| Amortisation of deferred financing fees | 17.3 | 1.9 | 12.3 | 4.4 | 37.6 |
| Loan facility commitment fees | 5.3 | 1.8 | 8.7 | 3.0 | 11.5 |
| Unwinding of loan modification gain | – | – | 29.1 | 10.1 | 99.7 |
| Other | 1.2 | 0.8 | 1.6 | 0.6 | 1.7 |
| Finance costs | 286.1 | 126.7 | 258.2 | -84.9 | 318.6 |
| Note 6 – Income tax MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Current tax | 1,682.7 | 661.3 | 251.2 | 121.7 | 511.8 |
| Deferred tax | 247.1 | 137.5 | 343.7 | 113.4 | 378.3 |
| Income tax | 1,929.8 | 798.8 | 594.9 | 235.1 | 890.1 |
| Note 7 – Oil and gas properties MUSD |
30 September 2021 | 31 December 2020 |
|---|---|---|
| Producing assets | 4,317.6 | 3,776.9 |
| Assets under development | 883.6 | 1,216.1 |
| Capitalised exploration and appraisal expenditure | 651.3 | 909.4 |
| Right of use assets | 20.0 | – |
| 5,872.5 | 5,902.4 |
| Note 8 – Other tangible fixed assets MUSD |
30 September 2021 | 31 December 2020 |
|---|---|---|
| Right of use assets | 27.0 | 31.8 |
| Other | 12.6 | 13.4 |
| 39.6 | 45.2 |
| Note 9 – Financial assets MUSD |
30 September 2021 | 31 December 2020 |
|---|---|---|
| Contingent consideration | 12.9 | 12.7 |
| Associated companies | 0.3 | 0.3 |
| Other | 0.5 | 0.5 |
| 13.7 | 13.5 |
| Note 10 – Trade and other receivables MUSD |
30 September 2021 | 31 December 2020 |
|---|---|---|
| Non-current: | ||
| Prepaid expenses and accrued income | 16.8 | 17.3 |
| 16.8 | 17.3 | |
| Current: | ||
| Trade receivables | 264.4 | 215.5 |
| Underlift | 5.6 | 5.7 |
| Joint operations debtors | 29.1 | 21.8 |
| Prepaid expenses and accrued income | 150.4 | 26.5 |
| Other | 10.9 | 9.1 |
| 460.4 | 278.6 | |
| 477.2 | 295.9 |
| Note 11 – Bonds MUSD |
30 September 2021 | 31 December 2020 |
|---|---|---|
| Senior Notes 2.0% (21/26) - maturity July 2026 | 1,000.0 | – |
| Senior Notes 3.1% (21/31) - maturity July 2031 | 1,000.0 | – |
| Discount on bonds issuance | -3.5 | – |
| Capitalised financing fees | -17,6 | – |
| 1,978.9 | – |
| Note 12 – Financial liabilities MUSD |
30 September 2021 | 31 December 2020 |
|---|---|---|
| Non-current: | ||
| Bank loans | 1,500.0 | 3,994.0 |
| Capitalised financing fees | -19.7 | -37.1 |
| Lease commitments | 20.4 | 27.0 |
| 1,500.7 | 3,983.9 | |
| Current: | ||
| Lease commitments | 28.3 | 5.7 |
| Others | – | 0.4 |
| 28.3 | 6.1 | |
| 1,529.0 | 3,990.0 |
| Note 13 – Provisions MUSD |
30 September 2021 | 31 December 2020 |
|---|---|---|
| Non-current: | ||
| Site restoration | 620.3 | 560.5 |
| Long-term incentive plans | 2.6 | 2.3 |
| Other | 5.4 | 2.8 |
| 628.3 | 565.6 | |
| Current: | ||
| Site restoration | 9.0 | 16.0 |
| Long-term incentive plans | 5.5 | 5.3 |
| 14.5 | 21.3 | |
| 642.8 | 586.9 |
| Note 14 – Trade and other payables MUSD |
30 September 2021 | 31 December 2020 |
|---|---|---|
| Trade payables | 14.5 | 8.7 |
| Overlift | 5.7 | 1.6 |
| Joint operations creditors and accrued expenses | 244.3 | 151.3 |
| Other accrued expenses | 39.7 | 31.7 |
| Other | 14.2 | 9.2 |
| 318.4 | 202.5 |
For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
| 30 September 2021 MUSD |
Level 1 | Level 2 | Level 3 |
|---|---|---|---|
| Assets | |||
| Contingent consideration | – | – | 12.9 |
| Derivative instruments – non-current | – | 9.4 | – |
| Derivative instruments – current | – | 6.3 | – |
| – | 15.7 | 12.9 | |
| Liabilities | |||
| Derivative instruments – non-current | – | 48.0 | – |
| Derivative instruments – current | – | 87.9 | – |
| – | 135.9 | – | |
| 31 December 2020 MUSD |
Level 1 | Level 2 | Level 3 |
| Assets | |||
| Contingent consideration | – | – | 12.7 |
| Derivative instruments – non-current | – | 3.8 | – |
| Derivative instruments – current | – | 12.1 | – |
| – | 15.9 | 12.7 | |
| Liabilities | |||
| Derivative instruments – non-current | – | 144.7 | – |
| Derivative instruments – current | – | 87.6 | – |
| – | 232.3 | – |
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. The sale of 2.6 percent of Johan Sverdrup during 2019 included a contingent consideration based on future reserve reclassifications and is due in 2026, This contingent consideration was fair valued by the Company in 2019 with no changes in subsequent years.
Additional disclosures supplementing the financial statements are included in the Financial Review section of this report on pages 7-14.
| Expressed in MSEK | 1 Jan 2021- 30 Sep 2021 |
1 Jul 2021- 30 Sep 2021 |
1 Jan 2020- 30 Sep 2020 |
1 Jul 2020- 30 Sep 2020 |
1 Jan 2020- 31 Dec 2020 |
|---|---|---|---|---|---|
| 9 months | 3 months | 9 months | 3 months | 12 months | |
| Revenue | 10.6 | – | 12.3 | 0.7 | 19.5 |
| General and administration expenses | -181.6 | -58.3 | -175.7 | -56.4 | -240.1 |
| Operating loss | -171.0 | -58.3 | -163.4 | -55.7 | -220.6 |
| Net financial items | |||||
| Finance income | 4,467.2 | -0.6 | 2,867.8 | – | 2,867.8 |
| Finance costs | -0.3 | -0.2 | -4.1 | -2.8 | -5.3 |
| 4,466.9 | -0.8 | 2,863.7 | -2.8 | 2,862.5 | |
| Profit before tax | 4,295.9 | -59.1 | 2,700.3 | -58.5 | 2,641.9 |
| Income tax | – | – | – | – | – |
| Net result | 4,295.9 | -59.1 | 2,700.3 | -58.5 | 2,641.9 |
| Expressed in MSEK | 1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Net result | 4,295.9 | -59.1 | 2,700.3 | -58.5 | 2,641.9 |
| Other comprehensive income | – | – | – | – | – |
| Total comprehensive income | 4,295.9 | -59.1 | 2,700.3 | -58.5 | 2,641.9 |
| Attributable to: | |||||
| Shareholders of the Parent Company | 4,295.9 | -59.1 | 2,700.3 | -58.5 | 2,641.9 |
| 4,295.9 | -59.1 | 2,700.3 | -58.5 | 2,641.9 |
| Expressed in MSEK | 30 September 2021 | 31 December 2020 |
|---|---|---|
| ASSETS | ||
| Non-current assets | ||
| Shares in subsidiaries | 55,118.9 | 55,118.9 |
| Other tangible fixed assets | 0.4 | 0.5 |
| Total non-current assets | 55,119.3 | 55,119.4 |
| Current assets: | ||
| Receivables | 2,111.9 | 568.5 |
| Cash and cash equivalents | 38.0 | 26.6 |
| Total current assets | 2,149.9 | 595.1 |
| TOTAL ASSETS | 57,269.2 | 55,714.5 |
| SHAREHOLDERS´EQUITY AND LIABILITIES | ||
| Shareholders´ equity including net result for the period | 54,964.9 | 55,080.0 |
| Non-current liabilities | ||
| Provisions | 1.2 | 0.9 |
| Total non-current liabilities | 1.2 | 0.9 |
| Current liabilities | ||
| Dividends | 2,242.9 | 591.5 |
| Other liabilities | 60.2 | 42.1 |
| Total current liabilities | 2,303.1 | 633.6 |
| Total liabilities | 2,304.3 | 634.5 |
| TOTAL EQUITY AND LIABILITIES | 57,269.2 | 55,714.5 |
| 1 Jan 2021- | 1 Jul 2021- | 1 Jan 2020- | 1 Jul 2020- | 1 Jan 2020- | |
|---|---|---|---|---|---|
| Expressed in MSEK | 30 Sep 2021 9 months |
30 Sep 2021 3 months |
30 Sep 2020 9 months |
30 Sep 2020 3 months |
31 Dec 2020 12 months |
| Cash flow from operations | |||||
| Net result | 4,295.9 | -59.1 | 2,700.3 | -58.5 | 2,641.9 |
| Adjustment for non-cash related items | -2,231.8 | 2,234.9 | -1,429.6 | 719.8 | -711.0 |
| Changes in working capital | 671.1 | -1,146.5 | 1,022.8 | -61.5 | 1,007.3 |
| Total cash flow from operations | 2,735.2 | 1,029.3 | 2,293.5 | 599.8 | 2,938.2 |
| Cash flow from investing | |||||
| Investments in other fixed assets | – | – | -0.2 | – | -0.2 |
| Total cash flow from investing | – | – | -0.2 | – | -0.2 |
| Cash flow from financing | |||||
| Dividends paid | -2,781.0 | -1,083.4 | -2,354.8 | -661.9 | -3,003.1 |
| Issuance of treasury shares | 56.2 | 56.2 | 63.1 | 63.1 | 63.1 |
| Total cash flow from financing | -2,724.8 | -1,027.2 | -2,291.7 | -598.8 | -2,940.0 |
| Change in cash and cash equivalents | 10.4 | 2.1 | 1.6 | 1.0 | -2.0 |
| Cash and cash equivalents at the beginning of the period | 26.6 | 35.2 | 31.7 | 32.3 | 31.7 |
| Currency exchange difference in cash and cash equivalents | 1.0 | 0.7 | -1.2 | -1.2 | -3.1 |
| Cash and cash equivalents at the end of the period | 38.0 | 38.0 | 32.1 | 32.1 | 26.6 |
| Restricted equity | Unrestricted equity | ||||||
|---|---|---|---|---|---|---|---|
| Share | Statutory | Other | Retained | Total | |||
| Expressed in MSEK | capital | reserve | reserves | earnings | Dividends | Total | equity |
| Balance at 1 January 2020 | 3.5 | 861.3 | 6,479.7 | 47,898.3 | – | 54,378.0 | 55,242.8 |
| Total comprehensive income | – | – | – | 2,700.3 | – | 2,700.3 | 2,700.3 |
| Transactions with owners | |||||||
| Distributions | – | – | – | – | -2,867.8 | -2,867.8 | -2,867.8 |
| Issuance of treasury shares | – | – | 63.1 | – | – | 63.1 | 63.1 |
| Total transactions with owners | – | – | – | – | -2,867.8 | -2,804.7 | -2,804.7 |
| Balance at 30 September 2020 | 3.5 | 861.3 | 6,542.8 | 50,598.6 | -2,867.8 | 54,273.6 | 55,138.4 |
| Total comprehensive income | – | – | – | -58.4 | – | -58.4 | -58.4 |
| Balance at 31 December 2020 | 3.5 | 861.3 | 6,542.8 | 50.540.2 | -2,867.8 | 54,215.2 | 55,080.0 |
| Transfer of prior year dividends | – | – | – | -2,867.8 | 2,867.8 | – | – |
| Total comprehensive income | – | – | – | 4,295.9 | – | 4,295.9 | 4,295.9 |
| Transactions with owners | |||||||
| Distributions | – | – | – | – | -4,467.2 | -4,467.2 | -4,467.2 |
| Issuance of treasury shares | – | – | 56.2 | – | – | 56.2 | 56.2 |
| Total transactions with owners | – | – | 56.2 | – | -4,467.2 | -4,411.0 | -4,411.0 |
| Balance at 30 September 2021 | 3.5 | 861.3 | 6,599.0 | 51,968.3 | -4,467.2 | 54,100.1 | 54,964.9 |
Lundin Energy discloses alternative performance measures as part of its financial statements prepared in accordance with ESMA's (European Securities and Markets Authority) guidelines. Lundin Energy 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 Energy'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 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Revenue and other income | 3,862.9 | 1,478.2 | 1,784.7 | 687.0 | 2,564.4 |
| Operating cash flow | 1,703.6 | 625.9 | 1,201.0 | 399.4 | 1,657.6 |
| CFFO | 2,499.9 | 1,012.0 | 1,251.3 | 353.2 | 1,528.0 |
| EBITDAX | 3,360.6 | 1,282.6 | 1,431.8 | 515.6 | 2,140.2 |
| Free cash flow | 1,622.9 | 673.8 | 545.7 | 164.2 | 448.2 |
| Net result | 372.1 | 137.5 | 80.5 | 212.3 | 384.2 |
| Adjusted net result | 542.4 | 234.0 | 193.1 | 75.8 | 280.0 |
| Net debt | 2,646.9 | 2,646.9 | 3,706.8 | 3,706.8 | 3,911.5 |
| Data per share USD |
|||||
| Shareholders' equity per share | -5.94 | -5.94 | -7.48 | -7.48 | -6.22 |
| Operating cash flow per share | 5.99 | 2.20 | 4.23 | 1.40 | 5.83 |
| CFFO per share | 8.79 | 3.56 | 4.40 | 1.24 | 5.38 |
| EBITDAX per share | 11.82 | 4.51 | 5.04 | 1.81 | 7.53 |
| Free cash flow per share | 5.71 | 2.37 | 1.92 | 0.58 | 1.58 |
| Earnings per share | 1.31 | 0.48 | 0.28 | 0.74 | 1.35 |
| Earnings per share fully diluted | 1.31 | 0.48 | 0.28 | 0.74 | 1.35 |
| Adjusted earnings per share | 1.91 | 0.83 | 0.68 | 0.27 | 0.99 |
| Adjusted earnings per share fully diluted | 1.90 | 0.82 | 0.68 | 0.27 | 0.98 |
| Dividend per share1 | 1.15 | 0.45 | 0.87 | 0.25 | 1.12 |
| Number of shares issued at period end | 285,924,614 | 285,924,614 | 285,924,614 | 285,924,614 | 285,924,614 |
| Number of shares in circulation at period end | 284,568,178 | 284,568,178 | 284,351,471 | 284,351,471 | 284,351,471 |
| Weighted average number of shares for the period | 284,403,068 | 284,504,579 | 284,119,225 | 284,253,590 | 284,177,604 |
| Weighted average number of shares for the period fully diluted | 285,049,553 | 285,029,248 | 284,758,504 | 284,736,009 | 284,830,491 |
| Share price | |||||
| Share price at period end in SEK | 326.80 | 326.80 | 178.50 | 178.50 | 222.30 |
| Share price at period end in USD2 | 37.21 | 37.21 | 19.77 | 19.77 | 27.19 |
| Key ratios | |||||
| Return on equity (%)3 | – | – | – | – | – |
| Return on capital employed (%) | 44 | 19 | 18 | 7 | 22 |
| Net debt/equity ratio (%)3 | – | – | – | – | – |
| Net debt/EBITDAX ratio | 0.7 | 0.7 | 1.7 | 1.7 | 1.8 |
| Equity ratio (%) | -22 | -22 | -36 | -36 | -27 |
| Share of risk capital (%) | 18 | 18 | 8 | 8 | 17 |
| Interest coverage ratio | 33 | 53 | 8 | 10 | 8 |
| Operating cash flow/interest ratio | 22 | 32 | 11 | 12 | 11 |
| Yield | 3 | 1 | 4 | 1 | 4 |
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 September 2021, 31 December 2020 and 30 September 2020 is negative, these ratios have not been calculated.
| EBITDAX MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Operating profit | 2,586.2 | 1,062.5 | 932.6 | 362.3 | 1,420.7 |
| Add: depletion of oil and gas properties | 531.2 | 180.5 | 446.8 | 150.9 | 607.7 |
| Add: exploration costs | 237.9 | 37.9 | 47.3 | 0.6 | 104.9 |
| Add: depreciation of other tangible assets | 5.3 | 1.7 | 5.1 | 1.8 | 6.9 |
| EBITDAX | 3,360.6 | 1,282.6 | 1,431.8 | 515.6 | 2,140.2 |
| Operating cash flow MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Revenue and other income | 3,862.9 | 1,478.2 | 1,784.7 | 687.0 | 2,564.4 |
| Minus: production costs | -187.4 | -72.2 | -139.2 | -35.9 | -177.2 |
| Minus: purchase of crude oil from third parties | -289.2 | -118.8 | -193.3 | -130.0 | -217.8 |
| Minus: current taxes | -1,682.7 | -661.3 | -251.2 | -121.7 | -511.8 |
| Operating cash flow | 1,703.6 | 625.9 | 1,201.0 | 399.4 | 1,657.6 |
| Free cash flow MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Cash flows from operating activities (CFFO) | 2,499.9 | 1,012.0 | 1,251.3 | 353.2 | 1,528.0 |
| Minus: cash flows from investing activities | -877.0 | -338.2 | -705.6 | -189.0 | -1,079.8 |
| Free cash flow | 1,622.9 | 673.8 | 545.7 | 164.2 | 448.2 |
| Adjusted net result MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Net result | 372.1 | 137.5 | 80.5 | 212.3 | 384.2 |
| Adjusted for unwinding of loan modification gain | – | – | 29.1 | 10.1 | 99.7 |
| Adjusted for foreign currency exchange gain or loss | 132.5 | 97.3 | 85.2 | -142.6 | -171.0 |
| Adjusted for ineffective interest rate hedge contracts | 35.3 | -2.7 | – | – | – |
| Adjusted for tax effects of above mentioned items | 2.5 | 1.9 | -1.7 | -4.0 | -32.9 |
| Adjusted net result | 542.4 | 234.0 | 193.1 | 75.8 | 280.0 |
| Net debt MUSD |
1 Jan 2021- 30 Sep 2021 9 months |
1 Jul 2021- 30 Sep 2021 3 months |
1 Jan 2020- 30 Sep 2020 9 months |
1 Jul 2020- 30 Sep 2020 3 months |
1 Jan 2020- 31 Dec 2020 12 months |
|---|---|---|---|---|---|
| Senior Notes | 2,000.0 | 2,000.0 | – | – | – |
| Bank loans | 1,500.0 | 1,500.0 | 3,836.0 | 3,836.0 | 3,994.0 |
| Minus: cash and cash equivalents | -853.1 | -853.1 | -129.2 | -129.2 | -82.5 |
| Net debt | 2,646.9 | 2.646.9 | 3,706.8 | 3,706.8 | 3,911.5 |
Adjusted earnings per share: Adjusted net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the period.
Adjusted earnings per share fully diluted: Adjusted 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.
Adjusted net result: Net result adjusted for the following items:
CFFO per share: Cash flow from operating activities (CFFO) divided by the weighted average number of shares for the period.
Dividend per share: paid out dividends per share 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.
EBITDAX (Earnings Before Interest, Taxes, Depletion, Amortisation and Exploration expenses): Operating profit before depletion of oil and gas properties, exploration costs, impairment costs, depreciation of other tangible assets and gain on sale of assets.
EBITDAX per share: EBITDAX divided by the weighted average number of shares for the period.
Equity ratio: Total equity divided by the balance sheet total.
Free cash flow: Cash flow from operating activities less cash flow from investing activities in accordance with the consolidated statement of cash flow.
Free cash flow per share: Free cash flow divided by the weighted average number of shares for the period.
Interest coverage ratio: Result after financial items plus interest expenses plus/less currency exchange differences on financial loans divided by interest expenses.
Net debt: Bonds plus bank loan less cash and cash equivalents.
Net debt/EBITDAX ratio: Bonds plus bank loan less cash and cash equivalents divided by EBITDAX of the last four quarters.
Net debt/equity ratio: Bonds plus bank loan less cash and cash equivalents divided by shareholders' equity.
Operating cash flow: Revenue and other income less production costs less purchase of crude oil from third parties less current taxes and less gain on sale of assets.
Operating cash flow per share: Operating cash flow divided by the weighted average number of shares for the period.
Operating cash flow/interest ratio: Operating cash flow divided by the interest expense for the period.
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 current liabilities).
Return on equity: Net result divided by average total equity.
Shareholders' equity per share: Shareholders' equity divided by the number of shares in circulation at period end.
Share of risk capital: The sum of the total equity and the deferred tax provision divided by the balance sheet total.
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.
Yield: dividend per share in relation to quoted share price at the end of the period.
The financial information relating to the nine month period ended 30 September 2021 has not been subject to review by the auditors of the Company.
Stockholm, 29 October 2021
The AGM will be held on 31 March 2022 in Stockholm, Sweden.
For further information, please contact:
Edward Westropp VP Investor Relations Tel: +41 22 595 10 14 [email protected]
Robert Eriksson Head of Media Communications Tel: +46 701 11 26 15 [email protected]
| CHF | Swiss franc |
|---|---|
| EUR | Euro |
| NOK | Norwegian Krone |
| SEK | Swedish Krona |
| USD | US dollar |
| TSEK | Thousand SEK |
| TUSD | Thousand USD |
| MEUR | Million EUR |
| MSEK | Million SEK |
| MUSD | Million USD |
| BUSD | Billion USD |
| bo | Barrels of oil |
|---|---|
| boe | Barrels of oil equivalents |
| boepd | Barrels of oil equivalents per day |
| bopd | Barrels of oil per day |
| CO2 | Carbon dioxide |
| CO2 e |
Carbon dioxide equivalents |
| 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 |
| MMboe | Million barrels of oil equivalents |
| MMbo | Million barrels of oil |
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 Energy'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 Energy 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 Energy'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 Energy AB (publ) Hovslagargatan 5 SE-111 48 Stockholm, Sweden T +46-8-440 54 50 W lundin-energy.com
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