Quarterly Report • Jul 26, 2022
Quarterly Report
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Interim report
| About Vår Energi | About Vår Energi | 2 |
|---|---|---|
| Vår Energi is a leading independent upstream oil and gas Company on the Norwegian continental shelf | Key figures | 3 |
| (NCS). The Company is founded on more than 50 years of NCS operations, a robust and diversified asset portfolio with ongoing development projects centred around hubs, and a strong exploration track record. |
Highlights | 4 |
| In first half 2022, Vår Energi produced net 226 kboepd of oil and gas from 36 fields. | Key metrics and targets | 5 |
| The Company has a target to increase production to 350 kboepd by end 2025 while reducing production cost to USD 8 per boe from USD 13.3 in first half 2022 as new projects come on stream and effects from improvement measures are achieved. Material cash |
||
| Operational review | 6 | |
| flow generation and an investment-grade balance sheet enable attractive and resilient dividend distributions. For 2022, Vår Energi | Projects and developments | 10 |
| guides for a dividend of minimum USD 1 billion. From 2023 and onwards, the Company plans to distribute 20–30% of cash flow | Exploration | 12 |
| from operations after tax (CFFO). | HSSE | 13 |
| On 16 February 2022, Vår Energi listed on Oslo Stock Exchange (OSE) under the ticker "VAR". The initial public offering (IPO) provides access to Norwegian and international capital markets, a diversification of the Company's ownership structure and supports |
Decarbonisation and environmental impact | 13 |
| employee participation. | Financial review | 14 |
| Outlook | 22 | |
| Vår Energi is committed to delivering a better future. The Company's ambition is to be the safest operator on the NCS, the partner of | Transactions with related parties | 22 |
| choice, an ESG leader and a net-zero producer (scope 1 and 2) by 2030. | Subsequent events | 22 |
| Risks and risk management | 22 | |
| To learn more, please visit: www.varenergi.no. | Alternative Performance Measures | 23 |
| Responsibility statement | 25 | |
| Financial statements | 26 | |
| Notes | 33 |
First quarter 2022 in brackets
Production kboepd
210 (242)
Petroleum revenues USD million
EBIT USD million
1 674 (1 718)
Profit before tax USD million
1 214 (1 695)
CFFO USD million
Capex USD million
(622)
FCF USD million
(1 580)
NIBD / EBITDAX x 0.4 (0.6)
Vår Energi reported USD 2 437 million in total income for the second quarter of 2022, EBIT was USD 1 674 million and cash flow from operations (CFFO) was USD 1 535 million in the quarter. Total income for the first six months was USD 4 927 million. EBIT for the period was USD 3 392 million and CFFO was USD 3 736 million. Vår Energi expects a minimum of USD 1 billion in dividends for 2022, under current market conditions, paid on quarterly basis. A dividend of USD 225 million for the first quarter was distributed in May and USD 260 million for the second quarter will be distributed in August. The Company plans to pay further USD 290 million in dividend for the third quarter of 2022 in November, a 12% increase from the second quarter.
| KPIs (USD million unless otherwise stated) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Actual serious injury frequency (x, 12 months rolling) | 0.1 | 0.1 | - | 0.1 | - | - |
| CO2 emissions intensity (operated licenses, kg/boe) | 8.6 | 7.6 | 9.7 | 8.6 | 9.7 | 9.5 |
| Production (kboepd) | 210 | 242 | 206 | 226 | 239 | 246 |
| Production cost (USD/boe) | 14.7 | 12.1 | 13.5 | 13.3 | 11.5 | 12.0 |
| Cash flow from operations before tax | 1 864 | 2 384 | 826 | 4 248 | 1 561 | 4 415 |
| Cash flow from operations (CFFO) | 1 535 | 2 201 | 1 310 | 3 736 | 2 279 | 4 579 |
| Free cash flow (FCF) | 962 | 1 580 | 710 | 2 541 | 1 133 | 1 994 |
| Dividends | 225 | - | 263 | - | - | 950 |
"The continued strong cash flow generation reflects another quarter of safe and efficient operations with high commodity prices and stable production and supply of gas to our customers in Europe. This supports our commitment to deliver on our strategy and a USD 1 billion minimum dividend expectation for 2022. Second-quarter production was impacted by seasonally high maintenance and turnaround activity across own and partner-operated licenses. Vår Energi executed maintenance on operated fields according to plan. We also made good progress on the development projects which together with a strengthened organisation position Vår Energi to become a net producer of 350.000 barrels of oil and gas per day by the end of 2025."
Torger Rød, CEO of Vår Energi.
| Production 1 (kboepd) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Crude oil | 113.3 | 137.0 | 130.0 | 125.1 | 136.6 | 136.9 |
| Gas | 84.6 | 85.1 | 60.3 | 84.8 | 80.1 | 86.7 |
| NGL | 11.9 | 19.9 | 15.3 | 15.9 | 22.0 | 22.2 |
| Total | 209.8 | 241.9 | 205.6 | 225.8 | 238.7 | 245.8 |
| Realised prices (USD/boe) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
| Crude oil price | 116.0 | 99.6 | 67.8 | 107.2 | 64.3 | 70.4 |
| Gas price | 151.3 | 163.4 | 41.6 | 157.4 | 37.9 | 79.5 |
| NGL price | 70.9 | 72.6 | 39.9 | 71.6 | 37.8 | 45.0 |
| Average (volume-weighted) | 124.1 | 119.8 | 57.8 | 121.9 | 53.3 | 70.9 |
| Financials | ||||||
| (USD million unless otherwise stated) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
| Total income | 2 437 | 2 491 | 1 114 | 4 927 | 2 178 | 6 073 |
| EBIT | 1 674 | 1 718 | 361 | 3 392 | 937 | 3 012 |
| Profit / (loss) before income taxes | 1 214 | 1 695 | 299 | 2 910 | 821 | 2 600 |
| Net earnings | 56 | 424 | 109 | 480 | 276 | 644 |
| Earnings per share (USD) | 0.02 | 0.17 | 0.04 | 0.19 | 0.11 | 0.26 |
| Dividend per share (USD) | 0.09 | - | 0.11 | 0.09 | 0.19 | 0.38 |
| NIBD / EBITDAX (including leasing) | 0.4 | 0.6 | 1.5 | 0.4 | 1.5 | 1.0 |
2022 guidance (USD million unless otherwise stated)
| Production | kboepd | 230 – 245 |
|---|---|---|
| Production cost | USD/boe | 12.5 – 13.5 |
| Development capex | 2 300 – 2 600 | |
| Exploration and abandonment capex | 200 | |
| Dividends for 2022, paid quarterly | Minimum USD 1 bn | |
| Dividends for the second quarter to be distributed in August |
260 | |
| Dividend guidance for the third quarter payable in the fourth quarter. |
290 | |
| Second half 2022 cash tax payment estimate 2 | 1 800 | |
| Other: | ||
| Final paymnent as part of t he 2019 acquisition of ExxonMobil's non operated assets on the NCS |
350 | |
| Long-term financial and operational targets | ||
| End 2025 production target | kboepd | > 350 |
| Medium term production cost | USD/boe | 8.0 |
| NIBD/ | ||
| Leverage through the cycle | EBITDAX | 1.3 |
1 Production numbers presented for 2021 are based on a gas conversion of 6.65, whereas production in 2022 are based on a factor of 6.29.
2 Assumed NOK/USD 9.5.
| Total production | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 | |
|---|---|---|---|---|---|---|---|
| Total production (mmboe) | 19.1 | 21.8 | 18.7 | 40.9 | 43.2 | 89.7 | |
| Operated (kboepd) | 41.5 | 48.5 | 46.0 | 45.0 | 46.0 | 44.9 | 6% |
| Partner operated (kboepd) | 168.3 | 193.4 | 159.6 | 180.8 | 192.6 | 201.0 | 20% |
| Total production (kboepd) | 209.8 | 241.9 | 205.6 | 225.8 | 238.7 | 245.8 | |
| Operated (kboepd) | 20% | 20% | 22% | 20% | 19% | 18% | |
| Partner operated (kboepd) | 80% | 80% | 78% | 80% | 81% | 82% | |
| Production by type (kboepd) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 | |
| Crude oil | 113.3 | 137.0 | 130.0 | 125.1 | 136.6 | 136.9 | |
| Gas | 84.6 | 85.1 | 60.3 | 84.8 | 80.1 | 86.7 | |
| NGL | 11.9 | 19.9 | 15.3 | 15.9 | 22.0 | 22.2 | |
| Total | 209.8 | 241.9 | 205.6 | 225.8 | 238.7 | 245.8 | |
| Production by type (percentage) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 | kboepd Total production |
| Crude oil | 54% | 57% | 63% | 55% | 57% | 56% | |
| Gas | 40% | 35% | 29% | 38% | 34% | 35% | |
| NGL | 6% | 8% | 7% | 7% | 9% | 9% | |
| Total | 100% | 100% | 100% | 100% | 100% | 100% | |
| Volumes sold / lifted (mmboe) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 | |
| Crude oil | 10.7 | 12.4 | 12.0 | 23.2 | 23.6 | 49.0 | |
| Gas | 6.9 | 7.1 | 5.0 | 14.0 | 12.6 | 28.0 | |
| NGL | 1.9 | 1.2 | 2.2 | 3.1 | 4.1 | 8.2 | |
| Total | 19.5 | 20.7 | 19.2 | 40.2 | 40.3 | 85.2 |
2 3.2% if adjusted gas conversion factor is applied to the second quarter 2021
Total production
Q2 2022, percentage based on kboepd
The Company's production of oil, liquids and natural gas averaged 210 kboepd in the second quarter of 2022, a decrease of 13% compared to 242 kboepd produced in the first quarter of 2022 and an increase of 2% 2 compared to the second quarter of 2021. The lower production in the second quarter of 2022, when compared to the previous quarter, was mainly due to seasonally high turnaround and maintenance activity, partneroperated turnaround activities which extended beyond plan, and minor operational issues at both operated and partner-operated fields.
Production from operated assets in the quarter was 42 kboepd (20%) whereas production from partner-operated assets was 168 kboepd (80%).
Production of crude oil and NGL (liquids) in the second quarter amounted to 60% (65% in the first quarter) whereas gas production was 40% (35% in the first quarter). During the quarter, the Company continued to reduce NGL recovery to increase gas volumes and gas sales due to favourable market conditions. This led to a net production decrease of 4 kboepd in the quarter.
Production in the first half of 2022 averaged 226 kboepd, a reduction of 13 kboepd (5%) when
The lower production was mainly related to the Balder/Ringhorne, Grane, Ekofisk, and Statfjord fields. The Åsgard. Goliat and Snorre fields performed better in the first half of 2022 compared to the same period last year.
Production from operated assets in the first half of 2022 was 45 kboepd whereas production from partner operated assets was 181 kboepd. Production of crude oil and NGL (liquids) in the first six months amounted to 62% (66% in the first six months of 2021) whereas gas production was 38% (34% in the first six months of 2021).
Total volumes produced in the second quarter were 19.1 mmboe whereas volumes sold in the quarter amounted to 19.5 mmboe. Total volumes produced in first half 2022 were 40.9 mmboe and volumes sold 40.2 mmboe.
Production efficiency (operated licenses) in the second quarter was 85%, down from 87% in the previous quarter. Production efficiency for Goliat was 75% in the quarter due to planned turnaround and maintenance activities successfully executed on time and budget, whereas production efficiency for Balder/Ringhorne was 91%.
As part of Vår Energi's hub strategy, the Company identifies strategic focus areas that provide a framework for evaluating exploration and development opportunities, maximising the use of existing infrastructure and optimising value creation throughout Vår Energi's portfolio.
The Company's core assets are located around four strategic hubs: the Balder/Grane area, the Barents Sea area, the Åsgard area and the Tampen area.
The Company's four hubs delivered 75% of the total production in the quarter and for the first half of 2022.
| Production – hubs (kboepd) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Åsgard area | 73.9 | 79.4 | 42.5 | 76.6 | 69.5 | 77.4 |
| Tampen area | 38.3 | 39.4 | 36.5 | 38.8 | 38.7 | 41.9 |
| Balder/Grane area | 25.4 | 33.5 | 40.4 | 29.4 | 39.6 | 36.0 |
| Barents sea area | 19.1 | 26.7 | 21.6 | 22.9 | 22.2 | 22.7 |
| Other | 53.1 | 63.0 | 64.7 | 58.0 | 68.7 | 67.8 |
| 209.8 | 241.9 | 205.6 | 225.8 | 238.7 | 245.8 | |
| Total production per hub (kboepd) | ||||||
| Production – hubs (percentage) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
| Åsgard area | 35% | 33% | 21% | 34% | 29% | 31% |
| Tampen area | 18% | 16% | 18% | 17% | 16% | 17% |
| Balder/Grane area | 12% | 14% | 20% | 13% | 17% | 15% |
| Barents sea area | 9% | 11% | 10% | 10% | 9% | 9% |
| Other | 25% | 26% | 31% | 26% | 29% | 28% |
Second quarter production from the Åsgard area was 73.9 kboepd (35% of total production), down from 79.4 kboepd in the previous quarter. The lower production, mainly on Åsgard and Trestakk when compared to the previous quarter, is due to reduced NGL recovery to increase gas volumes and gas sales due to favourable market conditions.
For the first six months of 2022, production from the Åsgard area was 76.6 kboepd, up from 69.5 kboepd when compared to the same period last year. The increase was due to absence of turnarounds this year.
Production from the Tampen area was 38.3 kboepd in the second quarter (18% of total production), down from 39.4 kboepd in the previous quarter. The lower production in the second quarter was due to the Statfjord B turnaround that started during the first quarter and extended into the second quarter.
For the first six months of 2022, production from the Tampen area was 38.8 kboepd, up from 38.7 kboepd when compared to the same period last year.
Second quarter production from the Balder/Grane area was 25.4 kboepd (12% of total production), down from 33.5 kboepd in the previous quarter. The lower production in the Balder/Grane area when compared to the previous quarter was due to a major turnaround on the Grane field that started in May and extended to the end of June. Balder/ Ringhorne production increased in the second quarter.
For the first six months of 2022, production from the Balder/Grane area was 29.4 kboepd, down from 39.6 kboepd when compared to the same period last year. The reduction was due to the extended Grane turnaround and Balder production efficiency.
Production from the Barents Sea area (Goliat) was 19.1 kboepd in the second quarter (9% of total production), down from 26.7 kboepd in the previous quarter. Goliat re-started production mid-June after completion of a successful turnaround that started in May.
Equinor operated: Johan Castberg
For the first six months of 2022, production from the Barents Sea area was 22.9 kboepd, up from 22.2 kboepd when compared to the same period last year.
Production from other assets, including Ekofisk, Ormen Lange, Fram and Sleipner, was 53.1 kboepd during the second quarter (25% of total production), down from 63.0 kboepd in the previous quarter. The lower production compared to the second quarter of 2022 was driven by Ekofisk turnaround that started in May and was completed end of June. The compressor failure on Sleipner B continued to impact production in the second quarter.
For the first six months of 2022, production from other assets was 57.5 kboepd, down from 68.7 kboepd when compared to the same period last year. The lower production was mainly due to the Sleipner compressor failure and turnaround on Ekofisk and Ormen Lange performance.
Total production cost was USD 14.7 per boe in the second quarter of 2022 compared to USD 12.1 in the first quarter. The increase is mainly due to seasonally high turnaround and maintenance activity in the second quarter. The increase in transportation cost in the second quarter was due to higher tariffs following continued high gas sales.
Production cost for the first half of 2022 was USD 13.3 per boe.
Vår Energi maintains its full-year 2022 guidance for production cost per barrel at USD 12.5 to 13.5.
For more information, see production cost detailed in the financial review section.
| Production cost (USD/boe) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Production cost | 11.6 | 9.4 | 10.5 | 10.5 | 8.6 | 9.3 |
| Transportation cost | 3.1 | 2.7 | 3.0 | 2.9 | 2.8 | 2.7 |
| Total production cost | 14.7 | 12.1 | 13.5 | 13.3 | 11.5 | 12.0 |
Vår Energi is participating in several significant development projects on the NCS which support the Company's target of producing more than 350 kboepd by end 2025. The Company's project portfolio, including developments such as Johan Castberg, Balder X, Breidablikk and Fenja, progressed generally according to plan in the second quarter. While Covid-19, supply chain disruptions, cost increases currently experienced by the energy sector also affect Vår Energi, time to market for the Company's value-adding growth projects and developments remain a key priority.
The Balder X Project (90% working interest) consists of the refurbishment of the Jotun FPSO as the Balder area hub centre with new production and water injection wells. The project is expected to contribute with more than 63 kboepd per day (Net to Vår Energi) at peak production in 2024.
The Jotun FPSO remains on critical path and mitigating actions have been established during the fourth quarter last year and year to date in 2022 in order to maintain the schedule. Critical milestones have been achieved such as completion of physical inspections which have enabled a firm-up of the scope. The project is progressing towards the targeted first oil in fourth quarter of 2023. The communicated scope increases following the inspections in the fourth quarter combined with
the impact from external factors such as Covid 19, waiting on weather and global supply chain disturbances continue to affect the project.
Key deliverables and achievements in the quarter include:
The Johan Castberg (30% working interest) development is progressing according to plan. The FPSO hull and living quarter arrived at Stord (Norway) on 8 April following heavy-lift transport from Singapore. The start-up of the Johan Castberg field is targeted in the fourth quarter of 2024. Peak gross production is expected at approximately 190 kboepd, with an expected production cost of approximately USD 3 per boe during the first year of full production. Vår Energi considers Johan Castberg to be a prosperous area with diverse prospects and significant upside potential as demonstrated with the two discoveries made in the area in 2022.
Key deliverables and achievements in the quarter include:
The Breidablikk field (34.4% working interest) is a significant field and includes two discoveries. The field is being developed with four subsea templates tied-back to the Grane platform. The Breidablikk PDO was delivered in September 2020 by operator Equinor and approved in June 2021. The field is targeted to start production in the first quarter of 2024. Once in operation, the field is expected to generate a peak production of approximately 62 kboepd (gross).
Key deliverables and achievements in the quarter include:
Fenja (45% working interest) will be developed as a subsea tie-back to Njord A, operated by Equinor. The Fenja development project is currently in the execution phase and development drilling commenced in 2021. Production start-up has previously been delayed (due to delays in the Njord Future project, in which Vår Energi has no working interest) and is now planned for the first quarter of 2023.
Key deliverables and achievements in the quarter include:
Vår Energi currently holds 143 licenses of which 44 are operated and has a proven track record in successful exploration due to the strong technical competencies and historical expertise on the entire NCS. Vår Energi maintains an active exploration strategy on the NCS and large inventory of potential exploration prospects across its portfolio.
Four out of eight exploration wells have been executed in the first half of 2022 with a 50% rate of success and a total maximum up to 60 million barrels of recoverable oil equivalent 1. The 2022 drilling campaign comprises of one high risk / high reward and seven wells located near our main hubs. Vår Energi is targeting around 200-250 mmboe in unrisked recoverable resources 1 by the end of 2022.
During the second quarter, Vår Energi confirmed two oil and gas discoveries in the Equinor-operated Snøfonn Nord (30-50 mmboe 1 ) and Skavl Stø (6-10 mmboe 1 ) exploration wells in the Johan
Castberg area (PL532). The successful results confirm the strategic approach to exploration in the Barents Sea, strengthening the value creation in the region. Both discoveries add valuable volumes to the Company's resource base, supporting long-term growth targets. The discoveries will be further assessed for a possible tie-back to Johan Castberg.
Key exploration priorities for 2022 include the drilling of the Vår Energi-operated Lupa and Countach wells adjacent to the Goliat field in the Barents Sea, and follow-up of partner-operated wells in general.
1 Reported numbers are 100% unrisked recoverable resources, nine wells target to be spudded in 2022.
| Key HSSE indicators | Unit | Q1 2022 | Q4 2021 | Q3 2021 | |
|---|---|---|---|---|---|
| Serious incident frequency (SIF Actual) 1 12M roll avg | Per mill. exp. hours | 0.1 | 0.1 | 0.0 | 0.0 |
| Serious incident frequency (SIF) 1 12M roll avg | Per mill. exp. hours | 1.4 | 1.6 | 1.3 | 1.3 |
| Total recordable injury frequency (TRIF) 2 12M roll avg | Per mill. exp. hours | 2.7 | 2.5 | 3.2 | 3.1 |
| Acute spill | Count | 0 | 1 | 2 | 0 |
| Process safety events Tier 1 and 2 3 | Count | 0 | 2 | 0 | 2 |
| CO2 emissions intensity 4 | Kg CO2/boe | 8.6 | 7.6 | 8.1 | 12.3 |
Vår Energi's highest priority is to carry out its activities without causing harm to people or the environment. The Company's strong focus on implementation of its safety initiatives continued through the second quarter of 2022, and through the first half of 2022 an overall positive trend on the Serious Incidents Frequency (SIF)1 has been observed. There is however an increase in number of recordable injuries, all of which had low actual consequence. None of the incidents had a higher potential consequence. An increase in the Total Recordable Injury Frequency (TRIF) 2 was observed. The 12-month rolling average SIF rate was at the end of second quarter 1.4, a decrease from the 1.6 in the first quarter 2022. No incidents in the quarter were classified with serious actual consequence.
For the second quarter, the 12-month rolling average TRIF was 2.7, an increase compared to 2.5 in the first quarter of 2022. The trend is primarily driven by incidents in the projects' yard activities. All incidents have been managed according to the Company's management system. Actions have been implemented and learnings are shared to enable continuous improvement. Further, Vår Energi focuses on major accident potential and continuously monitors key indicators through the Company's major accident risk indicator system (MARI).
To continuously strengthen the culture and focus on safety, Vår Energi and its contractors will continue to build on its key safety initiatives, such as the Always Safe Annual Wheel, the Life-Saving Rules and the Company's internal TIR tool (Take Time, Involve, Report).
Vår Energi considers the decarbonisation of oil and gas production a prerequisite for ensuring a resilient business model and driving longterm value creation. The Company has committed to reduce its GHG emissions in alignment with the Paris Agreement and has started to implement and operationalise its decarbonisation plan. The Company is committed to have net-zero Scope 1 GHG emissions4 in 2030 and net-zero Scope 2 GHG emissions and part of Scope 3 GHG emissions 5 in 2025.
In addition to commitments to reduce Scope 1, 2 and 3 GHG emissions from the Company's current activities, the decarbonisation plan outlines ambitions and commitments for GHG emissions in future acquisitions, projects and developments which is key for future growth towards a low carbon society.
The CO2 emissions intensity (operational control, equity share) in the second quarter is estimated to 8.6 kg CO2 per boe, versus 7.6 kg CO2 per boe in the first quarter. The increase reflects lower production volumes on Goliat due to planned maintenance activities.
No significant spills 6 to sea were recorded during the second quarter.
1 SIF: Serious incident and near-misses per million worked hours. Includes actual and potential consequence. SIF Actual: incidents that have an actual serious consequence.
2 TRIF: Personal injuries requiring medical treatment per million worked hours. Reporting boundaries SIF & TRIF: Health and safety incident data is reported for company sites as well as contracted drilling rigs, floatels, vessels, projects and modifications, and transportation of personnel, using a risk-based approach. 3 Classified according to IOGP RP 456.
4 Direct Scope 1 emissions of CO2 (kg) from exploration and production (Operational control, equity share) divided by total equity share production (boe) from Marulk, Goliat, Balder and Ringhorne East.
5 Scope 3 categories include business travels, employee commuting, and upstream transportation and distribution (selected vessel categories)
6 Significant spills as defined by GRI 306-3
| USD million | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Total income | 2 437 | 2 491 | 1 114 | 4 927 | 2 178 | 6 073 |
| Production costs | (378) | (297) | (328) | (675) | (501) | (1 188) |
| Exploration expenses | (26) | (12) | (19) | (39) | (28) | (57) |
| Depreciation and amortisation | (329) | (441) | (351) | (770) | (840) | (1 705) |
| Impairment loss and reversals | - | 11 | (26) | 11 | 177 | (1) |
| Other operating expenses | (29) | (33) | (28) | (62) | (49) | (110) |
| Total operating cost | (763) | (772) | (752) | (1 535) | (1 240) | (3 061) |
| Operating profit / (loss) (EBIT) | 1 674 | 1 718 | 361 | 3 392 | 937 | 3 012 |
| Net financial income / (expenses) | (33) | (29) | (51) | (62) | (109) | (269) |
| Net exchange rate gain / (loss) | (426) | 6 | (12) | (420) | (8) | (142) |
| Profit / (loss) before income taxes | 1 214 | 1 695 | 299 | 2 910 | 821 | 2 600 |
| Income tax (expense) / income | (1 158) | (1 271) | (190) | (2 429) | (545) | (1 956) |
| Profit / (loss) for the period | 56 | 424 | 109 | 480 | 276 | 644 |
Total income in the second quarter was USD 2 437 million (-2%) compared to USD 2 491 in the previous quarter. Total income for the first six months in 2022 was USD 4 927 million, an increase of USD 2 750 million when compared to the same period the previous year.
| Total income (USD million) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Petroleum revenues | 2 423 | 2 483 | 1 108 | 4 906 | 2 147 | 6 043 |
| Other operating income | 13 | 8 | 6 | 21 | 31 | 29 |
| Total income | 2 437 | 2 491 | 1 114 | 4 927 | 2 178 | 6 073 |
Revenues from sale of petroleum products in the second quarter were USD 2 423 million, a reduction of USD 54 million when compared to the USD 2 483 million reported for the first quarter 2022. Higher product prices impacted petroleum revenues positively by USD 84 million whereas lower volumes sold impacted petroleum revenues negatively with USD 144 million.
Total petroleum revenues were USD 4 906 million in the period, up from USD 2 147 million reported for the first six months in 2021.
Petroleum revenues from sale of liquids (USD 1 380 million) amounted to 57% of total petroleum revenues whereas revenues from sale of gas (USD 1 044 million) amounted to 43%. During the second quarter, the Company continued to divert gas from injection to gas sales. Vår Energi also reduced methanol production at Tjeldbergodden and added the ethane to the gas export from Kårstø to generate additional revenues.
The average oil price realised in the second quarter was USD 116.0 per boe, up from USD 99.6 per boe in the previous quarter.
The average realised gas price in the quarter was USD 151.3 per boe. In 2022, Vår Energi has sold 9.2% of its estimated 2022 gas production at a fixed price. In second quarter fixed price sales represented 8.9% of total sales with delivery point in the UK at an average price of 160 USD/boe, which was 65 USD/boe above the average UK spot price. This generated USD 41.5 million in additional revenues during the quarter compared to selling the gas into the spot market on a daily basis. 14.6% of the gas production for the remainder part of the year (17.4% in third quarter and 11.9% in fourth quarter) has been sold on a fixed price basis at an average price of 139.5 USD/boe.
| Revenue split by petroleum type (USD million) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Revenue from crude oil sales | 1 246 | 1 238 | 813 | 2 484 | 1 514 | 3 448 |
| Revenue from gas sales | 1 044 | 1 158 | 208 | 2 201 | 477 | 2 227 |
| Revenue from NGL sales | 133 | 87 | 86 | 221 | 155 | 368 |
| Total petroleum revenues | 2 423 | 2 483 | 1 108 | 4 906 | 2 147 | 6 043 |
| Revenue split by petroleum type (percentage) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
| Revenue from crude oil sales | 51% | 50% | 73% | 51% | 71% | 57% |
| Revenue from gas sales | 43% | 47% | 19% | 45% | 22% | 37% |
| Revenue from NGL sales | 6% | 4% | 8% | 4% | 7% | 6% |
| Total | 100% | 100% | 100% | 100% | 100% | 100% |
| Realised prices (USD/boe) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
| Crude oil | 116.0 | 99.6 | 67.8 | 107.2 | 64.3 | 70.4 |
| Gas | 151.3 | 163.4 | 41.6 | 157.4 | 37.9 | 79.5 |
| NGL | 71 | 72.6 | 39.9 | 71.6 | 37.8 | 45.0 |
| Average (volume-weighted) | 124.1 | 119.8 | 57.8 | 121.9 | 53.3 | 70.9 |
Total production cost (produced volumes) in the second quarter amounted to USD 281 million, an increase of 6% when compared to the USD 264 million in the first quarter.
The increase in production cost when compared to the previous quarter was mainly due to turnaround and maintenance activities on both operated assets and assets operated by others.
Production cost (sold volumes) was USD 378 million in the second quarter, an increase of USD 81 million when compared to the previous quarter.
Effective from second quarter 2022, Vår Energi has changed calculation of over-/underlift of NGL lifted at the Kårstø terminal to correct data quality issues in allocation of liftings at field level. Over-/underlift of NGL from the fields that are lifted at the Kårstø terminal are recognised at the net position of the Company's total portfolio.
| USD million | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Cost of operations | 182 | 162 | 159 | 344 | 301 | 688 |
| Transportation and processing | 58 | 58 | 57 | 117 | 122 | 243 |
| Environmental taxes | 28 | 34 | 26 | 62 | 49 | 102 |
| Insurances | 12 | 9 | 12 | 21 | 23 | 46 |
| Production cost (produced volumes) | 281 | 264 | 253 | 544 | 495 | 1 079 |
| Back-up cost shuttle tankers | 6 | (1) | 17 | 5 | 19 | 33 |
| Adjustment of over/underlift (-) | 82 | 24 | 43 | 105 | (41) | 15 |
| Premium expense for crude put options | 10 | 11 | 14 | 21 | 27 | 60 |
| Production (sold volumes) | 378 | 297 | 328 | 675 | 501 | 1 188 |
| Total produced volumes (mmboe) | 19.1 | 21.8 | 18.7 | 40.9 | 43.2 | 89.7 |
| Production cost (USD/boe) | 14.7 | 12.1 | 13.5 | 13.3 | 11.5 | 12.0 |
This was previously calculated at field level. Comparative figures have been restated accordingly. For more information, see note 1 in the consolidated financial statements.
Total production cost (produced volumes) in the first six months amounted to USD 544 million, an increase of USD 49 million when compared to the USD 495 million for the first six months in 2021. Production cost per barrel in the period was 13.3, an increase of USD 1.8 from the 11.5 reported for the first half of 2021.
Exploration expenses in the second quarter amounted to USD 26 million. The increase from the previous quarter is due to a combination of higher activity and additional costs following the two discoveries made in the second quarter. Exploration expenses in first half 2022 amounted to USD 39 million, up from USD 28 million when compared to the same period in 2021.
DD&A in the second quarter was USD 329 million (-26%) compared to USD 441 million in the previous quarter. The reduction was mainly due to the lower production. DD&A in first half of 2022 amounted to USD 770 million, down from USD 840 million when compared to the same period in 2021.
There were no impairment losses or reversals in the second quarter. The reversal in the previous quarter related to Brage following higher price assumptions.
For more details on impairments and reversal of impairments, see note 11 in the consolidated financial statements.
EBIT for the second quarter was USD 1 674 million, down 2.6% from USD 1 718 million reported in the first quarter. EBIT for the first six months was USD 3 392 million, up from USD 937 million in 2021.
Net financial expenses in the second quarter were USD 33 million and the net exchange rate loss amounted to USD 426 million of which USD 382 million are unrealised. For more details, see note 6 in the consolidated financial statements.
The income tax expense in the second quarter was USD 1 158 million (-9%) compared to USD 1 271 million in the first quarter. The effective tax rate in the second quarter was 95%, up from 75% in the previous quarter. The increase was mainly due to exchange rate losses not deductible in the special tax regime and effects of the new tax legislation enacted in June 2022.
Profit in the second quarter was USD 56 million, down from USD 424 million in the previous quarter due to the net exchange rate loss described above. Profit for the first six months was USD 480 million, up from USD 276 million in the same period previous year.
NIBD / EBITDAX
| Available liquidity | 30 Jun 22 | 31 Mar 22 | 30 Jun 21 | 31 Dec 21 |
|---|---|---|---|---|
| Cash and cash equivalents | 892 | 539 | 292 | 224 |
| RBL | - | - | 420 | - |
| RCF | 3 600 | 3 260 | 600 | 3 260 |
| Available liquidity | 4 492 | 3 799 | 1 311 | 3 484 |
Available liquidity
USD million
Total assets at the end of the second quarter amounted to USD 18 621 million. The reduction from the USD 20 592 million at the end of the first quarter is mainly due to a weaker NOK to USD when converting from NOK functional currency to USD reporting currency.
Tangible fixed assets including property, plant and equipment (PP&E) at the end of the period were USD 14 149 million and are detailed in note 9 in the consolidated financial statements.
Total equity amounted to USD 1 559 million, corresponding to an equity ratio of 8%.
Total cash and cash equivalents at the end of the first quarter were USD 892 million. In addition, at the end of the second quarter, the Company had USD 3 600 million in undrawn credit facilities bringing total available liquidity to USD 4 492 million.
Total interest-bearing debt (incl. leasing) at the end of the second quarter was USD 3 584 million, a decrease of USD 369 million from USD 3 954 million at the end of the previous quarter. For more details, see note 17 and 21 in the consolidated financial statements.
EBITDAX was USD 2 029 million in the quarter and free cash flow (FCF) was USD 962 million.
Due to the strong cash flow generated and repayments of interest-bearing debt in the first quarter the Company reduced its leverage ratio (NIBD including leasing/EBITDAX) to 0.4x at the end of the quarter, down from 0.6x at the end of the first quarter.
| Interest bearing debt excl. leasing (x) | 30 Jun 22 | 31 Mar 22 | 30 Jun 21 | 31 Dec 21 |
|---|---|---|---|---|
| Adjusted total interest bearing debt / EBITDAX | 0.5 | 0.6 | 1.5 | 1.0 |
| Adjusted net interest-bearing debt / EBITDAX | 0.3 | 0.5 | 1.4 | 1.0 |
| Interest bearing debt incl. leasing (USD million) | 30 Jun 22 | 31 Mar 22 | 30 Jun 21 | 31 Dec 21 |
|---|---|---|---|---|
| Interest-bearing loans and borrowings | 2 977 | 3 316 | 5 079 | 4 493 |
| Interest-bearing loans, current | 343 | 338 | - | 333 |
| Lease liabilities, non-current | 160 | 191 | 106 | 216 |
| Lease liabilities, current | 103 | 108 | 38 | 109 |
| Total interest bearing debt (TIBD) | 3 584 | 3 954 | 5 223 | 5 152 |
| Cash and cash equivalents | 892 | 539 | 292 | 224 |
| Net interest bearing debt (NIBD) | 2 692 | 3 415 | 4 932 | 4 928 |
| EBITDAX 4 quarters rolling | 7 336 | 6 065 | 3 355 | 4 774 |
| Total interest bearing debt / EBITDAX | 0.5 | 0.7 | 1.6 | 1.1 |
| Net interest-bearing debt / EBITDAX | 0.4 | 0.6 | 1.5 | 1.0 |
| Consolidated statements of cash flows (USD million) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Cash flow from operating activities (CFFO) | 1 535 | 2 201 | 1 310 | 3 736 | 2 279 | 4 579 |
| Cash flows used in investing activities | (596) | (650) | (631) | (1 246) | (1 172) | (2 633) |
| Cash flows from financing activities | (607) | (1 233) | (476) | (1 841) | (1 094) | (1 976) |
| Net change in cash and cash equivalents | 331 | 318 | 203 | 649 | 13 | (30) |
| Cash and cash equivalents, beginning of period |
539 | 224 | 82 | 224 | 272 | 272 |
| Effect of exchange rate fluctuation on cash held |
22 | (2) | 6 | 19 | 5 | (19) |
| Cash and cash equivalents, end of period | 892 | 539 | 291 | 892 | 290 | 224 |
Cash flow from operations before tax USD million
Cash flow from operating activities (CFFO) was USD 1 535 million in the second quarter, down from USD 2 201 million in the previous quarter. The lower CFFO is due to higher income taxes paid and working capital movements.
USD million
| Cash flows used in investing activities (USD million) | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Expenditures on exploration and evaluation assets | 21 | 6 | 59 | 27 | 82 | 104 |
| Expenditures on property, plant and equipment | 552 | 615 | 542 | 1 167 | 1 064 | 2 480 |
| Payment for decommissioning of oil and gas fields | 23 | 29 | 31 | 52 | 46 | 70 |
| Proceeds from sale of assets (sales price) | - | - | - | - | (21) | (24) |
| Expenditures on goodwill and other intangible assets | - | - | - | - | - | 3 |
| Total cash flows used in investing activities | 596 | 650 | 631 | 1 246 | 1 172 | 2 633 |
Net cash flow used in investing activities in the second quarter was USD 596 million. Expenditures on property, plant and equipment (PP&E) were USD 552 million and expenditures in the Balder Area, Johan Castberg and Grane totalled 64% of total expenditures on PP&E.
| Expenditures on PP&E (USD million, %) | Q2 2022 | Q2 2022 | Q1 2022 | Q1 2022 | Q2 2021 | Q2 2021 | FY 2021 | FY 2021 |
|---|---|---|---|---|---|---|---|---|
| Balder area | 215 | 43% | 299 | 49% | 221 | 41% | 1 150 | 46% |
| Johan Castberg | 74 | 10% | 92 | 15% | 74 | 14% | 320 | 13% |
| Fenja | 20 | 3% | 30 | 5% | 22 | 4% | 103 | 4% |
| Grane | 62 | 11% | 45 | 7% | 26 | 5% | 159 | 6% |
| Snorre | 31 | 6% | 24 | 4% | 47 | 9% | 151 | 6% |
| Statfjord area | 35 | 6% | 28 | 5% | 23 | 4% | 83 | 3% |
| Sleipner area | 2 | - | 3 | - | 6 | 1% | 31 | 1% |
| Ekofisk area | 22 | 4% | 25 | 4% | 25 | 5% | 89 | 4% |
| Goliat | 19 | 4% | 6 | 1% | 9 | 2% | 110 | 4% |
| Tommeliten | 9 | 2% | 8 | 1% | 2 | - | 18.4 | 1% |
| Other | 64 | 12% | 55 | 9% | 86 | 16% | 265 | 11% |
| Total expenditures on PP&E | 552 | 100% | 615 | 100% | 542 | 100% | 2 480 | 100% |
| Capex coverage | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Expenditures on exploration and evaluation assets |
21 | 6 | 59 | 27 | 82 | 104 |
| Expenditures on PP&E | 552 | 615 | 542 | 1 167 | 1 064 | 2 480 |
| Capex | 573 | 622 | 600 | 1 195 | 1 147 | 2 585 |
| CFFO | 1 535 | 2 201 | 1 310 | 3 736 | 2 279 | 4 579 |
| Capex coverage (x) | 2.7 | 3.5 | 2.2 | 3.1 | 2.0 | 1.8 |
Capex coverage in the second quarter was 2.7x.
From first quarter 2022, the Company presents payments of borrowing costs as financing activities, while they in prior periods were presented as operational and investment activities. The reason behind the change is that borrowing costs are directly linked to the Company's financing activities and are thus deemed more relevant to include under cash flows used in financing activities. Comparative figures have been restated accordingly. For more information, see note 1 in the consolidated financial statements.
| Cash flows from financing activities (USD million) |
Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Dividends paid | (225) | - | (263) | (225) | (476) | (950) |
| Net proceeds from bond issue | 497 | - | - | 497 | - | - |
| Net proceeds/(payments) of revolving credit facility |
(840) | (1 181) | - | (2 021) | - | 4 494 |
| Net proceeds/(payments) of reserve based lending facility |
- | - | (165) | - | (520) | (5 335) |
| Payment of other loans and borrowings | - | - | - | - | - | - |
| Payment of principal portion of lease liability |
(23) | (34) | (12) | (57) | (22) | (44) |
| Interest paid | (16) | (18) | (36) | (35) | (77) | (142) |
| Cash acquired in business combination | - | - | - | - | - | - |
| Total cash flows used in investing activities |
(607) | (1 233) | (476) | (1 841) | (1 094) | (1 976) |
Net cash outflow from financing activities amounted to USD 607 million in the second quarter. During the quarter, the Company raised an aggregate of USD 500 million in senior notes due 2027 for partial refinancing of bridge-to-bond facility maturing in November 2023.
Vår Energi has an ambition to deliver value-driven growth to support attractive and resilient long-term dividend distributions.
The Company targets production of more than 350 kboepd by end 2025, corresponding to over 50% growth compared to the midpoint of the guided 2022 range of 230–245 kboepd. The end-2025 ambition is based on:
Growth levers beyond 2025 include maturing and developing unsanctioned projects, continuing to leverage best-in-class NCS exploration capabilities to deliver new potential commercial discoveries and executing on accretive M&A in hub areas driving value and synergies.
Based on the potential for improving operations in currently producing fields and the attractive cost
profile in sanctioned developments, Vår Energi has an ambition to reduce production cost per boe to USD 8 in the medium term from USD 12 in 2021. This represents a reduction of 33%.
For 2022, the Company maintains its guidance for USD 2 300–2 600 million in development capex and USD 200 million in exploration and abandonment capex.
Vår Energi's material cash flow generation and investment-grade balance sheet support attractive and resilient distributions. For the second quarter of 2022, Vår Energi will pay a dividend of USD 260 million in August and the Company guides for a further USD 290 million to be paid for the third quarter.
From 2023 and onwards, the Company plans to distribute 20–30% of cash flow from operations after tax.
To ensure continuous access to capital at competitive cost, retaining investment-grade credit ratings is a priority for Vår Energi. As such, the Company targets a NIBD/EBITDAX of 1.3x through the cycle.
For details on transactions with related parties, see note 22 in the consolidated financial statements.
See note 24 in the consolidated financial statements.
A detailed analysis of Vår Energi's operational, financial and external risks and mitigation of those risks through risk management is described in the prospectus published in February 2022 and the 2021 annual report, both available on http://www.varenergi.no/.
Vår Energi is exposed to a variety of risks associated with oil and gas operations at the NCS, exploration, reserve and resource estimates and estimates for capital and operating cost expenditures are associated with uncertainty. The production performance of oil and gas fields may be variable over time.
The COVID-19 pandemic and war in Ukraine have caused significant business disruption globally. Although Vår Energi has no direct exposure
towards Russia, Ukraine or Belarus, the Company is indirectly exposed through increased macro uncertainties and supply chain disturbances. As previously mentioned, this has put pressure on the Company's growth projects and developments, but Vår Energi remains committed to mitigate project risk and progress towards targeted first oil.
Vår Energi is exposed to various forms of market and financial risks, non-exhaustive, commodity price fluctuations, exchange rates, interest rates and capital requirements. Vår Energi is also exposed to uncertainties relating to the capital markets and access to capital, this may influence the pace with which development projects can be brought on stream.
Risk management is an integral part of the Company's business activities, and the business areas consequently have the main responsibility for managing risks arising from its business activities.
These financial statements are the unaudited Interim Consolidated Financial Statements of Vår Energi for the second quarter and first half of 2022. The Interim Financial Statements are prepared in accordance with the International Accounting Standard 34 (IAS 34) – Interim Financial Reporting.
These Interim Financial Statements should be read in conjunction with the Consolidated Financial Statements for 2021 as they provide an update of previously reported information.
The accounting policies used in the Interim Financial Statements are consistent with those used in the 2021 Consolidated IFRS Financial Statements.
In this interim report, in order to enhance the understanding of the Group's performance and liquidity, Vår Energi presents certain alternative performance measures ("APMs") as defined by the European Securities and Markets Authority ("ESMA") in the ESMA Guidelines on Alternative Performance Measures 2015/1057.
Vår Energi presents the APMs: CAPEX, CAPEX Coverage, EBITDAX, EBITDAX Margin, Free Cash Flow, NIBD, Adjusted NIBD, NIBD/ EBITDAX Ratio, Adjusted NIBD/EBITDAX Ratio, TIBD/EBITDAX Ratio and Adjusted TIBD/EBITDAX Ratio.
The APMs are not measurement of performance under IFRS ("GAAP") and should not be considered to be an alternative to: (a) operating revenues or operating profit (as determined in accordance with GAAP), as a measure of Vår Energi's operating performance; or (b) any other measures of performance under GAAP. The APM presented herein may not be indicative of Vår Energi's historical operating results, nor is such measure meant to be predictive of the Group's future results.
Vår Energi believes that the APMs described herein are commonly reported by companies in the markets in which it competes and are widely used in comparing and analysing performance across companies within its industry.
The APMs used by Vår Energi are set out below (presented in alphabetical order):
"EBITDAX" is defined by Vår Energi as profit/(loss) for the period before income tax (expense)/income, net financial items, net exchange rate gain/(loss), depreciation and amortisation, impairments and exploration expenses.
"EBITDAX margin" is defined by Vår Energi as EBITDAX and EBITDA as a percentage of total income, respectively.
EBITDA and EBITDAX in the second quarter of 2022 amounted to USD 2 003 million and USD 2 029 million, respectively.
| USD million | Q2 2022 | Q1 2022 | Q2 2021 | YTD Q2 2022 | YTD Q2 2021 | FY 2021 |
|---|---|---|---|---|---|---|
| Profit / (loss) for the period | 56 | 424 | 109 | 480 | 276 | 644 |
| Income tax (expense)/income | (1 158) | (1 271) | (190) | (2 429) | (545) | (1 956) |
| Net financial income / (expenses) | (33) | (29) | (51) | (62) | (109) | (269) |
| Net exchange rate gain / (loss) | (426) | 6 | (12) | (420) | (8) | (142) |
| Depreciation and amortisation | (329) | (441) | (351) | (770) | (840) | (1 705) |
| Impairment loss and reversals | - | 11 | (26) | 11 | 177 | (1) |
| EBITDA | 2 003 | 2 149 | 739 | 4 151 | 1 600 | 4 717 |
| Exploration expenses | (26) | (12) | (19) | (39) | (28) | (57) |
| EBITDAX | 2 029 | 2 161 | 758 | 4 190 | 1 628 | 4 774 |
| Total income | 2 437 | 2 491 | 1 114 | 4 927 | 2 178 | 6 073 |
| EBITDA margin | 82% | 86% | 66% | 84% | 73% | 78% |
| EBITDAX margin | 83% | 87% | 68% | 85% | 75% | 79% |
Sandnes, 25 July 2022 Signed Electronically
Thorhild Widvey Chair
Liv Monica Bargem Stubholt Deputy Chair
Francesco Gattei Director
Guido Brusco Director
Clara Andreoletti Director
Marica Calabrese Director
Fabio Romeo Director
Ove Gusevik Director
Martha Skjæveland Director, employee representative Hege Susanne Blåsternes Director, employee representative
Bjørn Nysted Director, employee representative
Jan Inge Nesheim Director, employee representative
Torger Rød Chief Executive Officer
The Board of Directors and the CEO certify that the financial report for the first three months ended 31 March and the six months ended 30 June 2022 gives a fair view of the performance of the business, position and profit or loss of the Company, and describes the principal risks and uncertainties that the Company faces.
| Unaudited consolidated statement of comprehensive income | 27 | Note 10 Right of use assets |
45 | |
|---|---|---|---|---|
| Unaudited consolidated balance sheet statement | 28 | Note 11 Impairment |
46 | |
| Unaudited consolidated statement of changes in equity | 30 | Note 12 Trade receivables |
48 | |
| Note 13 Other current receivables and financial assets |
48 | |||
| Unaudited consolidated statement of cash flows | 31 | Note 14 Financial instruments |
49 | |
| Notes | 33 | Note 15 Cash and cash equivalents |
50 | |
| Note 1 | Summary of IFRS accounting principles and restatements | 34 | Note 16 Share capital and shareholders |
50 |
| Note 2 | Income | 37 | Note 17 Financial liabilities and borrowings |
51 |
| Note 3 | Production costs | 38 | Note 18 Asset retirement obligations |
52 |
| Note 4 | Other operating expenses | 39 | Note 19 Other current liabilities |
52 |
| Note 5 | Exploration expenses | 39 | Note 20 Commitments, provisions and contingent consideration |
52 |
| Note 6 | Financial items | 40 | Note 21 Lease agreements |
53 |
| Note 7 | Income taxes | 41 | Note 22 Related party transactions |
54 |
| Note 8 | Intangible assets | 43 | Note 23 License ownerships |
55 |
| Note 9 | Tangible assets | 44 | Note 24 Subsequent events |
55 |
| Restated | ||||||
|---|---|---|---|---|---|---|
| USD 1000, except earnings per share data | Note | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
| Petroleum revenues | 2 | 2 423 454 | 2 482 788 | 1 107 670 | 4 906 242 | 2 146 655 |
| Other operating income | 2 | 13 274 | 7 720 | 5 930 | 20 995 | 30 971 |
| Total income | 2 436 729 | 2 490 508 | 1 113 600 | 4 927 236 | 2 177 626 | |
| Production costs | 1, 3 | (378 442) | (296 992) | (327 866) | (675 433) | (500 616) |
| Exploration expenses | 5, 8 | (26 430) | (12 077) | (19 191) | (38 506) | (27 956) |
| Depreciation and amortisation | 9, 10 | (328 792) | (441 239) | (351 172) | (770 030) | (840 190) |
| Impairment loss and reversals | 8, 9, 11 | - | 10 865 | (26 137) | 10 865 | 177 500 |
| Other operating expenses | 4 | (29 113) | (32 912) | (27 912) | (62 026) | (49 082) |
| Total operating expenses | (762 776) | (772 354) | (752 277) | (1 535 131) | (1 240 343) | |
| Operating profit / (loss) | 1 673 952 | 1 718 153 | 361 323 | 3 392 106 | 937 283 | |
| Net financial income / (expenses) | 6 | (33 256) | (28 886) | (50 528) | (62 141) | (108 562) |
| Net exchange rate gain / (loss) | 6 | (426 279) | 5 877 | (11 719) | (420 402) | (7 785) |
| Profit/(loss) before taxes | 1 214 418 | 1 695 145 | 299 077 | 2 909 562 | 820 935 | |
| Income tax (expense) / income | 1, 7 | (1 157 979) | (1 271 283) | (189 628) | (2 429 261) | (544 650) |
| Profit / (loss) for the period | 56 439 | 423 862 | 109 449 | 480 301 | 276 285 | |
| Other comprehensive income: | ||||||
| Items that may be reclassified subsequently to the income statement: | ||||||
| Currency translation differences | (224 133) | 16 071 | (9 248) | (208 062) | (9 968) | |
| Net gain / (loss) on put options used for hedging | 9 929 | (2 370) | (592) | 7 559 | (5 484) | |
| Other comprehensive income for the period, net of tax | (214 204) | 13 701 | (9 840) | (200 503) | (15 451) | |
| Total comprehensive income | (157 765) | 437 563 | 99 609 | 279 798 | 260 834 | |
| Earnings per share | ||||||
| EPS Basic | 1, 16 | 0.02 | 0.17 | 0.04 | 0.19 | 0.11 |
| EPS Diluted | 1, 16 | 0.02 | 0.17 | 0.04 | 0.19 | 0.11 |
| Restated | Restated | ||||
|---|---|---|---|---|---|
| USD 1000 | Note | 30 Jun 2022 | 31 Mar 2022 | 31 Dec 2021 | 30 Jun 2021 |
| ASSETS | |||||
| Non-current assets | |||||
| Intangible assets | |||||
| Goodwill | 8 | 2 241 297 | 2 552 592 | 2 531 897 | 2 776 082 |
| Capitalised exploration wells | 8 | 180 484 | 202 769 | 199 981 | 184 129 |
| Other intangible assets | 8 | 92 524 | 105 374 | 104 520 | 107 397 |
| Tangible fixed assets | |||||
| Property, plant and equipment | 9 | 13 927 344 | 15 803 767 | 15 188 917 | 15 066 249 |
| Right of use assets | 10 | 222 066 | 272 741 | 298 432 | 116 880 |
| Financial assets | |||||
| Investment in shares | 755 | 860 | 853 | 879 | |
| Other non-current assets | 1 064 | 1 517 | 1 809 | 2 490 | |
| Total non-current assets | 16 665 533 | 18 939 620 | 18 326 409 | 18 254 105 | |
| Current assets | |||||
| Inventories | 257 458 | 313 391 | 301 329 | 277 648 | |
| Trade receivables | 12, 22 | 560 015 | 499 468 | 745 921 | 296 710 |
| Other current receivables and financial assets | 1, 13 | 246 135 | 300 369 | 201 809 | 243 678 |
| Cash and cash equivalents | 15 | 892 046 | 538 739 | 223 588 | 291 560 |
| Total current assets | 1 955 653 | 1 651 968 | 1 472 647 | 1 109 596 | |
| TOTAL ASSETS | 18 621 185 | 20 591 588 | 19 799 056 | 19 363 701 |
| USD 1000 | Note | 30 Jun 2022 | Restated 31 Mar 2022 |
Restated 31 Dec 2021 |
30 Jun 2021 | Sandnes, 25 July 2022 Signed Electronically |
|
|---|---|---|---|---|---|---|---|
| EQUITY AND LIABILITIES | |||||||
| Equity | |||||||
| Share capital | 16 | 45 972 | 45 972 | 45 972 | 45 972 | Thorhild Widvey | Liv Monica Bargem Stubholt |
| Share premium | 2 418 181 | 2 643 181 | 2 643 181 | 3 117 681 | Chair | Deputy Chair | |
| Other equity | 1 | (905 446) | (748 715) | (1 186 278) | (1 513 445) | ||
| Total equity | 1 558 706 | 1 940 437 | 1 502 874 | 1 650 208 | Francesco Gattei | Guido Brusco | |
| Non-current liabilities | Director | Director | |||||
| Interest-bearing loans and borrowings | 17 | 2 977 463 | 3 316 057 | 4 493 426 | 5 078 717 | ||
| Deferred tax liabilities | 7, 1 | 7 444 464 | 8 078 321 | 7 907 749 | 7 845 823 | Clara Andreoletti | Marica Calabrese |
| Asset retirement obligations | 18 | 2 947 552 | 3 552 873 | 3 235 640 | 3 337 339 | Director | Director |
| Lease liabilities, non-current | 21 | 160 305 | 191 341 | 216 208 | 106 387 | ||
| Other non-current liabilities | 151 930 | 162 642 | 162 870 | 156 205 | Fabio Romeo | Ove Gusevik | |
| Total non-current liabilities | 13 681 714 | 15 301 234 | 16 015 893 | 16 524 471 | Director | Director | |
| Current liabilities | |||||||
| Asset retirement obligations, current | 18 | 18 016 | 35 552 | 61 536 | 20 836 | Martha Skjæveland | Hege Susanne Blåsternes |
| Accounts payables | 22 | 344 327 | 416 973 | 422 155 | 328 967 | Director, | Director, |
| Taxes payable | 7 | 2 033 759 | 1 802 687 | 801 432 | 250 569 | employee representative | employee representative |
| Interest-bearing loans, current | 17 | 343 202 | 337 816 | 333 149 | - | ||
| Lease liabilities, current | 21 | 103 301 | 108 458 | 108 880 | 38 346 | Bjørn Nysted | Jan Inge Nesheim |
| Other current liabilities | 1, 19 | 538 160 | 648 430 | 553 136 | 550 303 | Director, | Director, |
| Total current liabilities | 3 380 765 | 3 349 916 | 2 280 289 | 1 189 022 | employee representative | employee representative | |
| Total liabilities | 17 062 479 | 18 651 150 | 18 296 182 | 17 713 493 | |||
| Torger Rød | |||||||
| TOTAL EQUITY AND LIABILITIES | 18 621 185 | 20 591 588 | 19 799 056 | 19 363 701 | Chief Executive Officer |
| Translation | |||||||
|---|---|---|---|---|---|---|---|
| USD 1000 | Note | Share capital | Share premium | Other equity | differences | Hedge reserve | Total equity |
| Balance at 1 January 2021 before restatement | 45 972 | 3 593 181 | (1 595 366) | (160 173) | (28 737) | 1 854 877 | |
| Impact of restatement | 1 | - | - | 8 409 | 487 | - | 8 897 |
| Balance at 1 January 2021 after restatement | 45 972 | 3 593 181 | (1 586 957) | (159 685) | (28 737) | 1 863 773 | |
| Profit / (loss) for the period | - | - | 276 285 | - | - | 276 285 | |
| Other comprehensive income / (loss) | - | - | - | (9 968) | (5 484) | (15 451) | |
| Total comprehensive income / (loss) | - | - | 276 285 | (9 968) | (5 484) | 260 834 | |
| Dividends paid | - | (475 500) | - | - | - | (475 500) | |
| Other | - | - | 1 101 | - | - | 1 101 | |
| Balance at 30 June 2021 | 45 972 | 3 117 681 | (1 309 571) | (169 653) | (34 220) | 1 650 208 | |
| Profit / (loss) for the period | - | - | 367 755 | - | - | 367 755 | |
| Other comprehensive income / (loss) | - | - | - | (53 001) | 12 403 | (40 598) | |
| Total comprehensive income / (loss) | - | - | 367 755 | (53 001) | 12 403 | 327 157 | |
| Dividends paid | - | (474 500) | - | - | - | (474 500) | |
| Other | - | - | 10 | - | - | 10 | |
| Balance at 31 December 2021 | 45 972 | 2 643 181 | (941 806) | (222 654) | (21 818) | 1 502 874 | |
| Profit / (loss) for the period | - | - | 480 301 | - | - | 480 301 | |
| Other comprehensive income / (loss) | - | - | - | (208 062) | 7 559 | (200 503) | |
| Total comprehensive income / (loss) | - | - | 480 301 | (208 062) | 7 559 | 279 798 | |
| Dividends paid | - | (225 000) | - | - | - | (225 000) | |
| Share-based payments | 16 | - | - | 1 034 | - | - | 1 034 |
| Balance at 30 June 2022 | 45 972 | 2 418 181 | (460 472) | (430 716) | (14 259) | 1 558 706 | |
| USD 1000 | Note | Q2 2022 | Restated Q1 2022 |
Q2 2021 | YTD 2022 | YTD 2021 |
|---|---|---|---|---|---|---|
| Profit / (loss) before income taxes | 1 | 1 214 418 | 1 695 145 | 299 077 | 2 909 562 | 820 935 |
| Adjustments to reconcile profit before tax to net cash flows: | ||||||
| - Depreciation and amortisation | 9, 10 | 328 792 | 441 239 | 351 172 | 770 030 | 840 190 |
| - Impairment loss and reversals | 8, 9 | - | (10 865) | 26 137 | (10 865) | (177 500) |
| - (Gain) / loss on sale and retirement of assets | 2 | - | - | - | - | (19 103) |
| - Impairment of exploration wells | 5, 8 | 18 032 | 5 098 | 3 796 | 23 130 | 4 908 |
| - Accretion expenses (asset retirement obligation) | 6, 18 | 22 076 | 24 282 | 21 975 | 46 358 | 43 546 |
| - Unrealised (gain) / loss on foreign currency transactions and balances | 6 | 382 048 | (28 037) | 47 565 | 354 011 | 67 037 |
| - Other non-cash items and reclassifications | 38 067 | 33 842 | 8 713 | 71 909 | 47 496 | |
| Working capital adjustments: | ||||||
| - Changes in inventories, accounts payable and receivables | (132 805) | 231 642 | 17 850 | 98 837 | (49 466) | |
| - Changes in other current balance sheet items | (6 816) | (8 499) | 79 158 | (15 315) | 13 360 | |
| Contingent consideration paid related to prior business combination | 19 | - | - | (30 000) | - | (30 000) |
| Income tax received / (paid) | 7 | (328 896) | (183 309) | 484 823 | (512 205) | 718 677 |
| Net cash flows from operating activities | 1 534 915 | 2 200 538 | 1 310 266 | 3 735 453 | 2 280 079 | |
| Cash flows from investing activities | ||||||
| Expenditures on exploration and evaluation assets | 8 | (21 114) | (6 233) | (58 727) | (27 347) | (82 405) |
| Expenditures on property, plant and equipment | 9 | (551 955) | (615 206) | (541 770) | (1 167 161) | (1 064 125) |
| Payment for decommissioning of oil and gas fields | 18 | (22 786) | (28 839) | (30 521) | (51 625) | (46 242) |
| Proceeds from sale of assets (sales price) | - | - | - | - | 20 670 | |
| Net cash used in investing activities | (595 854) | (650 278) | (631 018) | (1 246 132) | (1 172 102) |
| Restated | ||||||
|---|---|---|---|---|---|---|
| USD 1000 | Note | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
| Cash flows from financing activities | ||||||
| Dividends paid | (225 000) | - | (263 000) | (225 000) | (475 500) | |
| Net proceeds from bond issue | 496 906 | - | - | 496 906 | - | |
| Net proceeds/(payments) of revolving credit facilities | 17 | (840 000) | (1 180 500) | - | (2 020 500) | - |
| Net proceeds/(payments) of reserve based lending facility | 17 | - | - | (165 000) | - | (520 000) |
| Payment of principal portion of lease liability | 21 | (22 943) | (34 215) | (11 556) | (57 158) | (22 490) |
| Interest paid | 1 | (16 348) | (18 381) | (36 332) | (34 729) | (75 797) |
| Net cash from financing activities | (607 384) | (1 233 096) | (475 888) | (1 840 481) | (1 093 787) | |
| Net change in cash and cash equivalents | 331 676 | 317 163 | 203 360 | 648 840 | 14 189 | |
| Cash and cash equivalents, beginning of period | 538 739 | 223 588 | 82 082 | 223 588 | 272 411 | |
| Effect of exchange rate fluctuation on cash held | 21 630 | (2 012) | 6 118 | 19 618 | 4 960 | |
| Cash and cash equivalents, end of period | 892 046 | 538 739 | 291 560 | 892 046 | 291 560 |
The interim condensed consolidated financial statements for the period ended 30 June 2022 have been prepared in accordance with IAS 34 Interim Financial Reporting. Thus the interim financial statements do not include all information required by IFRSs and should be read in conjunction with the group's 2021 annual financial statements. The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the financial position, results of operations and cash flows for the dates and interim periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period. These interim financial statements have not been subject to review or audit by independent auditors.
These interim financial statements were authorised for issue by the company's Board of Directors on 25 July 2022.
The accounting principles adopted in the preparation of the interim condensed consolidated financial statements are consistent with those followed in the preparation of the Group's annual consolidated financial statements for the year ended 31 December 2021, except for a change in presentation of payment of borrowing costs in the statement of cash flows. The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.
During Q2 2022, the group decided to change its accounting principles related to presentation of interest payments in the cash flows statement. Interest payment are restated to be shown as financing activities in the statement of cash flows. In prior reporting periods, these cash flows were presented as operational activities. The reason behind the change is that interest payments are directly linked to the group's financing activities and are thus deemed more relevant to include under financing activities. Comparative figures have been restated accordingly and the impact on relevant previous periods is included in the table below.
| USD 1000 | |||||
|---|---|---|---|---|---|
| Restating impact on Statement of Cash Flow | Q1 2021 | Q2 2021 | Q3 2021 | Q4 2021 | Q1 2022 |
| Net cash flows from operating activities | |||||
| Before restatement | 930 347 | 1 273 934 | 1 310 447 | 922 484 | 2 182 157 |
| Impact of restatement | 39 466 | 36 332 | 37 513 | 28 221 | 18 381 |
| After restatement | 969 812 | 1 310 266 | 1 347 960 | 950 705 | 2 200 538 |
| Net cash from financing activities | |||||
| Before restatement | (578 434) | (439 556) | (598 318) | (218 378) | (1 214 715) |
| Impact of restatement | (39 466) | (36 332) | (37 513) | (28 221) | (18 381) |
| After restatement | (617 900) | (475 888) | (635 831) | (246 599) | (1 233 096) |
Effective from second quarter 2022, Vår Energi has corrected calculation of over/underlift of NGL lifted at the Kårstø terminal due to data quality issues in allocation of liftings at field level. Over/underlift of NGL from the fields that are lifted at the Kårstø terminal is recognised at the net position of the company's total portfolio. This was previously calculated at field level.
The impact of the restatement on the financial statement of previous quarters is summarized in the table below. The changes affect the relevant balance sheet line items; Other current receivables and financial assets, Other equity, Deferred tax liabilities and Other current liabilities. The line items Production costs and Income tax on the Statement of comprehensive income are affected.
| Underlift before restatement 142 257 210 866 180 364 158 691 189 105 Impact of restatement (67 948) (61 455) (76 139) (75 539) (78 888) Underlift after restatement 13 74 309 149 411 104 225 83 152 110 217 Overlift before restatement 166 175 168 011 192 336 296 345 317 605 Impact of restatement (108 388) (124 951) (164 780) (200 152) (217 548) Overlift after restatement 19 57 788 43 060 27 556 96 193 100 057 Equity before restatement 1 854 877 1 800 228 1 630 707 1 526 108 1 472 369 Impact of restatement 8 897 13 969 19 501 27 415 30 505 Equity after restatement 1 863 773 1 814 197 1 650 208 1 553 523 1 502 874 Deferred tax before restatement 7 342 952 7 579 941 7 776 683 7 754 476 7 799 594 Impact of restatement 31 543 49 527 69 140 97 198 108 155 |
USD 1000 Restating impact on Balance Sheet Statement |
Note | 01 Jan 2021 | 31 Mar 2021 | 30 Jun 2021 | 30 Sep 2021 | 31 Dec 2021 | 31 Mar 2022 |
|---|---|---|---|---|---|---|---|---|
| 182 563 | ||||||||
| (76 083) | ||||||||
| 106 480 | ||||||||
| 392 087 | ||||||||
| (260 268) | ||||||||
| 131 819 | ||||||||
| 1 899 917 | ||||||||
| 40 520 | ||||||||
| 1 940 437 | ||||||||
| 7 934 656 | ||||||||
| 143 665 | ||||||||
| Deferred tax after restatement 7 7 374 495 7 629 468 7 845 823 7 851 674 7 907 749 |
8 078 321 |
| USD 1000 | ||||||
|---|---|---|---|---|---|---|
| Restating impact on Statement of Comprehensive Income | Note | Q1 2021 | Q2 2021 | Q3 2021 | Q4 2021 | Q1 2022 |
| Adjustment of (over)/under lift before restatement | 61 139 | (69 121) | (118 018) | 9 053 | (67 687) | |
| Impact of restatement | 23 048 | 25 974 | 38 266 | 14 781 | 43 946 | |
| Adjustment of (over)/under lift after restatement | 3 | 84 187 | (43 147) | (79 752) | 23 834 | (23 741) |
| Income tax (expense) / income before restatement | (337 045) | (169 368) | (454 419) | (915 311) | (1 237 005) | |
| Impact of restatement | (17 977) | (20 260) | (29 847) | (11 529) | (34 278) | |
| Income tax (expense) / income after restatement | 7 | (355 022) | (189 628) | (484 266) | (926 840) | (1 271 283) |
| Earnings per share before restatement | 0.06 | 0.04 | 0.06 | 0.08 | 0.17 | |
| Impact of restatement | - | - | - | - | - | |
| Earnings per share after restatement | 0.07 | 0.04 | 0.06 | 0.08 | 0.17 |
Difference between impact in P&L vs. change in equity is related to translation effects.
| Petroleum revenues (USD 1000) | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
|---|---|---|---|---|---|
| Revenue from crude oil sales | 1 246 436 | 1 237 876 | 813 225 | 2 484 312 | 1 514 450 |
| Revenue from gas sales | 1 043 651 | 1 157 688 | 208 477 | 2 201 339 | 476 911 |
| Revenue from NGL sales | 133 367 | 87 224 | 85 968 | 220 591 | 155 294 |
| Total petroleum revenues | 2 423 454 | 2 482 788 | 1 107 670 | 4 906 242 | 2 146 655 |
| Sales of crude (boe 1000) | 10 743 | 12 433 | 11 993 | 23 176 | 23 557 |
| Sales of gas (boe 1000) | 6 896 | 7 087 | 5 016 | 13 983 | 12 596 |
| Sales of NGL (boe 1000) | 1 882 | 1 201 | 2 152 | 3 083 | 4 106 |
| Other operating income (USD 1000) | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
| Gain/(loss) from sale of assets | - | - | - | - | 19 103 |
| Other operating income | 13 274 | 7 720 | 5 930 | 20 995 | 11 868 |
| Total other operating income | 13 274 | 7 720 | 5 930 | 20 995 | 30 971 |
The majority of sales are to international customers in EU/UK.
Other operating income mainly consist of partner's share of lease cost recovered by the company in addition to a Q2 2022 insurance proceed of USD 4 million related to loss of production following the Balder subsea incident in first quarter 2022.
| Restated | ||||||
|---|---|---|---|---|---|---|
| USD 1000 | Note | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
| Cost of operations | 182 125 | 162 057 | 159 169 | 344 182 | 301 119 | |
| Transportation and processing | 58 361 | 58 260 | 56 849 | 116 621 | 122 243 | |
| Environmental taxes | 28 046 | 34 154 | 25 585 | 62 200 | 49 053 | |
| Insurance premium | 12 170 | 9 300 | 11 601 | 21 471 | 23 075 | |
| Production cost based on produced volumes | 280 702 | 263 771 | 253 204 | 544 474 | 495 491 | |
| Back-up cost shuttle tankers | 5 799 | (1 164) | 17 024 | 4 635 | 19 028 | |
| Adjustment of over/(underlift) | 1 | 81 705 | 23 741 | 43 147 | 105 447 | (41 040) |
| Premium expense for crude put options | 10 235 | 10 642 | 14 491 | 20 878 | 27 137 | |
| Production cost based on sold volumes | 378 442 | 296 992 | 327 866 | 675 433 | 500 616 | |
| Total produced volumes (boe 1000) | 19 089 | 21 775 | 18 711 | 40 864 | 43 200 | |
| Production cost per boe produced (USD/boe) | 14.7 | 12.1 | 13.5 | 13.3 | 11.5 |
| USD 1000 | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
|---|---|---|---|---|---|
| R&D expenses | 10 182 | 15 830 | 11 322 | 26 012 | 15 223 |
| Pre-production costs | 5 806 | 6 192 | 4 977 | 11 998 | 10 525 |
| Guarantee fee decommissioning obligation | 6 765 | 4 877 | 5 475 | 11 641 | 11 013 |
| Administration expenses | 6 361 | 6 014 | 5 494 | 12 374 | 10 784 |
| Other expenses | - | - | 772 | - | 1 665 |
| Total other operating expenses | 29 113 | 32 912 | 27 912 | 62 026 | 49 082 |
| USD 1000 | Note | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
|---|---|---|---|---|---|---|
| Seismic | 316 | 303 | 1 022 | 619 | 999 | |
| Area fee | 2 114 | 1 900 | 2 229 | 4 014 | 4 909 | |
| Dry well expenses | 8 | 18 032 | 5 099 | 3 796 | 23 130 | 4 908 |
| Other exploration expenses | 5 967 | 4 774 | 12 144 | 10 744 | 17 140 | |
| Total exploration costs | 26 430 | 12 077 | 19 191 | 38 506 | 27 956 |
Dry well expenses in Q2 2022 are related to the wells PL901 7122/6-3 S Rødhette and PL209 6305/5-C-3 H Ormen Lange Deep.
| USD 1000 | Note | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
|---|---|---|---|---|---|---|
| Other financial income | 492 | 350 | 5 868 | 842 | 7 538 | |
| Interests on debts and borrowings | 17 | (23 033) | (19 983) | (36 332) | (43 016) | (75 797) |
| Interest on lease debt | (1 930) | (3 227) | (1 750) | (5 157) | (3 563) | |
| Capitalised interest cost, development projects | 19 597 | 21 471 | 12 321 | 41 068 | 22 648 | |
| Amortisation of fees and expenses | (4 174) | (2 789) | (5 056) | (6 964) | (10 026) | |
| Accretion expenses (asset retirement obligation) | 18 | (22 076) | (24 282) | (21 977) | (46 358) | (43 546) |
| Other financial expenses | (2 131) | (425) | (3 603) | (2 556) | (5 817) | |
| Net financial income / (expenses) | (33 256) | (28 886) | (50 528) | (62 141) | (108 562) | |
| Unrealised exchange rate gain / (loss) | (382 048) | 28 037 | (47 565) | (354 011) | (67 037) | |
| Realised exchange rate gain / (loss) | (44 231) | (22 160) | 35 847 | (66 391) | 59 251 | |
| Net exchange rate gain / (loss) | (426 279) | 5 877 | (11 719) | (420 402) | (7 785) | |
| Net financial items | (459 535) | (23 009) | (62 247) | (482 543) | (116 348) |
Vår Energi's functional currency is NOK, whilst interest bearing loans are in USD. Due to weakening of NOK vs. USD, significant unrealised foreign exchange losses were recognised in the second quarter of 2022.
| USD 1000 | Q2 2022 | Restated Q1 2022 |
Q2 2021 | YTD 2022 | YTD 2021 |
|---|---|---|---|---|---|
| Current year tax payable / (receivable) | 774 004 | 1 163 800 | (64 390) | 1 937 804 | 40 638 |
| Prior period adjustments to current tax | 5 647 | 2 051 | 1 322 | 7 698 | 1 322 |
| Current tax expense / (income) | 779 651 | 1 165 851 | (63 069) | 1 945 503 | 41 959 |
| Deferred tax expense / (income) | 378 327 | 105 431 | 252 697 | 483 758 | 502 691 |
| Tax expense / (income) in profit and loss | 1 157 979 | 1 271 283 | 189 628 | 2 429 261 | 544 650 |
| Effective tax rate in % | 95% | 75% | 63% | 83% | 66% |
| Tax expense / (income) in put option used for hedging | 863 | (668) | (167) | 195 | (1 547) |
| Tax expense / (income) in other comprehensive income | 1 158 842 | 1 270 615 | 189 461 | 2 429 456 | 543 103 |
The tax calculation in the second quarter is based on the new cash flow based petroleum tax legislation, enacted by the Norwegian Parliament in June 2022 with effect from 1 January 2022. The main feature of the new legislation is that investments from 1 January 2022 can be expensed when incurred for special petroleum tax purposes, replacing the 6 years depreciation. The uplift deduction will be discontinued for investment not covered by the temporary 2020 tax regime. Impact of the new tax regime in the second quarter on first quarter figures was a reduction of payable taxed of USD 198 million, more than offset by an increase of USD 229 million in deferred taxes.
| Restated | ||||||
|---|---|---|---|---|---|---|
| Reconciliation of tax expense | Tax rate | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
| Corporate (78%) tax rate on profit / loss before tax 1 | 78% | 947 294 | 1 322 213 | 233 280 | 2 269 575 | 640 329 |
| Tax effect of uplift | 71.8% | (48 331) | (50 203) | (91 401) | (98 533) | (169 811) |
| Tax effects of new legislation on uplift 1 | 10 476 | (10 476) | - | - | - | |
| Impairment of goodwill | 78% | - | - | 28 709 | - | 28 709 |
| Tax effects of items taxed at other than corporate (78%) tax rate 2 | 56% | 219 539 | 7 565 | 30 628 | 227 104 | 56 478 |
| Tax effects of new legislation on other items 1 | 20 550 | - | - | 20 482 | - | |
| Other permanent differences, prior period adjustments and change in estimates of uncertain tax positions | 78% | 8 450 | 2 184 | (11 588) | 10 634 | (11 055) |
| Tax expense / (Income) | 1 157 979 | 1 271 283 | 189 628 | 2 429 261 | 544 650 |
1 Tax effects in the second quarter of the new legislation is USD 20.5 million related to valuation allowance for lack of statutory tax deduction at effective rate 6.204% related to abandonment of the last field, and USD 10.5 million
in reduced uplift deduction recognised in the first quarter. Effective tax rate has changed from 78% in the old tax regime to 78.004% in the new tax regime.
2 The effects of items taxed at other than corporate (78%) tax rate in second quarter 2022 is mainly impacted by fluctuation in USD/NOK exchange rate on the company's external borrowings.
| Restated | |||||
|---|---|---|---|---|---|
| Deferred tax asset / (liability) | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
| Deferred tax asset / (liability) at beginning of period | (8 078 321) | (7 907 749) | (7 629 468) | (7 907 749) | (7 374 495) |
| Current year deferred tax income / (expense) | (378 327) | (105 431) | (252 697) | (483 758) | (502 691) |
| Deferred taxes recognised directly in OCI or equity | (863) | 668 | 167 | (195) | 1 547 |
| Currency translation effects | 1 013 048 | (65 809) | 36 174 | 947 239 | 29 815 |
| Net deferred tax asset / (liability) as of closing balance | (7 444 464) | (8 078 321) | (7 845 823) | (7 444 464) | (7 845 823) |
| Restated | |||||
| Calculated tax (payable) / receivable | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
| Tax (payable) / receivable at beginning of period | (1 802 687) | (801 432) | 165 960 | (801 432) | 506 349 |
| Current year payable taxes | (774 004) | (1 163 800) | 64 390 | (1 937 804) | (40 638) |
| Payable taxes related to business combinations | - | - | - | - | - |
| Net tax payment / (tax refund) | 328 896 | 183 309 | (484 823) | 512 205 | (718 677) |
| Prior period adjustments and change in estimate of uncertain tax positions | (5 647) | (2 051) | (1 322) | (7 698) | (1 322) |
| Currency translation effects | 219 684 | (18 714) | 5 225 | 200 970 | 3 718 |
| Net tax (payable) / receivable as of closing balance | (2 033 759) | (1 802 687) | (250 569) | (2 033 759) | (250 569) |
| USD 1000 | Goodwill | Other intangible assets |
Capitalised exploration wells |
Total |
|---|---|---|---|---|
| Cost as at 1 January 2022 | 5 009 390 | 104 520 | 199 981 | 5 313 891 |
| Additions | - | - | 6 233 | 6 233 |
| Reclassification | - | - | - | - |
| Disposals / expensed exploration wells | - | - | (5 098) | (5 098) |
| Currency translation effects | 40 944 | 854 | 1 653 | 43 451 |
| Cost as at 31 March 2022 | 5 050 334 | 105 374 | 202 769 | 5 358 477 |
| Depreciation and impairment as at 1 January 2022 | (2 477 492) | - | - | (2 477 492) |
| Currency translation effects | (20 250) | - | - | (20 250) |
| Depreciation and impairment as at 31 March 2022 | (2 497 742) | - | - | (2 497 742) |
| Net book value as at 31 March 2022 | 2 552 592 | 105 374 | 202 769 | 2 860 735 |
| USD 1000 | Note | Goodwill | Other intangible assets |
Capitalised exploration wells |
Total |
|---|---|---|---|---|---|
| Cost as at 1 April 2022 | 5 050 334 | 105 374 | 202 769 | 5 358 477 | |
| Additions | - | - | 21 114 | 21 114 | |
| Disposals / expensed exploration wells | 5 | - | - | (18 032) | (18 032) |
| Currency translation effects | (615 901) | (12 851) | (25 366) | (654 118) | |
| Cost as at 30 June 2022 | 4 434 433 | 92 524 | 180 484 | 4 707 440 | |
| Depreciation and impairment as at 4 April 2022 | (2 497 742) | - | - | (2 497 742) | |
| Currency translation effects | 304 606 | - | - | 304 606 | |
| Depreciation and impairment as at 30 June 2022 | (2 193 136) | - | - | (2 193 136) | |
| Net book value as at 30 June 2022 | 2 241 297 | 92 524 | 180 484 | 2 514 304 |
Other intangible assets include exploration potentials acquired through business combinations and measured according to the successful efforts method.
| USD 1000 | Wells and production facilities |
Facilities under construction |
Other property, plant and equipment |
Total |
|---|---|---|---|---|
| Cost as at 1 January 2022 | 14 617 577 | 5 113 429 | 39 350 | 19 770 356 |
| Additions | 106 788 | 505 262 | 3 156 | 615 206 |
| Estimate change asset retirement cost | 266 158 | - | - | 266 158 |
| Reclassification | 63 417 | (45 273) | - | 18 144 |
| Disposals | - | - | - | - |
| Currency translation effects | 124 084 | 47 131 | 359 | 171 574 |
| Cost as at 31 March 2022 | 15 178 024 | 5 620 549 | 42 865 | 20 841 438 |
| Depreciation and impairment as at 1 January 2022 | (4 567 768) | - | (13 671) | (4 581 439) |
| Depreciation | (422 982) | - | (1 900) | (424 882) |
| Provision for impairment reversal / (loss) | 10 865 | - | - | 10 865 |
| Currency translation effects | (42 081) | - | (134) | (42 215) |
| Depreciation and impairment as at 31 March 2022 | (5 021 967) | - | (15 705) | (5 037 672) |
| Net book value as at 31 March 2022 | 10 156 057 | 5 620 549 | 27 161 | 15 803 767 |
| Wells and | Facilities | Other property, |
|||
|---|---|---|---|---|---|
| USD 1000 | Note | production facilities |
under construction |
plant and equipment |
Total |
| Cost as at 1 April 2022 | 15 178 024 | 5 620 549 | 42 865 | 20 841 438 | |
| Additions | 160 094 | 387 757 | 4 104 | 551 955 | |
| Estimate change asset retirement cost | 18 | (188 120) | - | - | (188 120) |
| Reclassification | 2 496 | 15 722 | - | 18 217 | |
| Currency translation effects | (1 856 882) | (704 486) | (5 463) | (2 566 832) | |
| Cost as at 30 June 2022 | 13 295 611 | 5 319 542 | 41 506 | 18 656 659 | |
| Depreciation and impairment as at 1 April 2022 | (5 021 967) | - | (15 705) | (5 037 672) | |
| Depreciation | (325 397) | - | (1 382) | (326 780) | |
| Provision for impairment reversal / (loss) | 11 | - | - | - | - |
| Currency translation effects | 633 120 | - | 2 017 | 635 137 | |
| Depreciation and impairment as at 30 June 2022 | (4 714 245) | - | (15 070) | (4 729 314) | |
| Net book value as at 30 June 2022 | 8 581 366 | 5 319 542 | 26 437 | 13 927 344 |
Capitalised interests for facilities under construction were USD 20 622 thousand in first quarter and USD 19 882 thousand in second quarter 2022.
Rate used for capitalisation of interests was 1.4% in first quarter 2022 and 1.9% in the second quarter.
Effective from 1 January 2022, Vår Energi has changed reserves classification system from U.S. Securities and Exchange Commission (SEC) to SPE-PRMS (Petroleum Resources Management System). The impact in UOP-depreciation rates are limited with increased total proved reserves of 0.7%.
| Rigs, helicopters and |
||||
|---|---|---|---|---|
| USD 1000 | Offices | supply vessels | Warehouse | Total |
| Cost as at 1 January 2022 | 75 830 | 304 182 | 13 546 | 393 558 |
| Additions | 4 081 | 2 596 | - | 6 677 |
| Reclassification | - | (18 144) | - | (18 144) |
| Currency translation effects | 351 | 1 793 | 969 | 3 113 |
| Cost as at 31 March 2022 | 80 262 | 290 427 | 14 515 | 385 204 |
| Depreciation and impairment as at 1 January 2022 | (15 707) | (72 924) | (6 496) | (95 126) |
| Depreciation | (1 422) | (14 055) | (880) | (16 356) |
| Currency translation effects | (151) | (752) | (77) | (980) |
| Depreciation and impairment as at 31 March 2022 | (17 280) | (87 731) | (7 453) | (112 463) |
| Net book value as at 31 March 2022 | 62 982 | 202 696 | 7 062 | 272 741 |
| Rigs, | ||||
|---|---|---|---|---|
| USD 1000 | Offices | helicopters and supply vessels |
Warehouse | Total |
| Cost as at 1 April 2022 | 80 262 | 290 427 | 14 515 | 385 204 |
| Reclassification | - | (18 217) | - | (18 217) |
| Currency translation effects | (13 966) | (32 436) | 431 | (45 971) |
| Cost as at 30 June 2022 | 66 296 | 239 774 | 14 945 | 321 015 |
| Depreciation and impairment as at 1 April 2022 | (17 280) | (87 731) | (7 453) | (112 463) |
| Depreciation | (175) | (1 729) | (108) | (2 012) |
| Currency translation effects | 1 854 | 12 754 | 918 | 15 525 |
| Depreciation and impairment as at 30 June 2022 | (15 600) | (76 706) | (6 642) | (98 950) |
| Net book value as at 30 June 2022 | 50 696 | 163 068 | 8 303 | 222 066 |
Impairment tests of individual cash-generating units (CGUs) are performed when impairment triggers are identified. Impairment tests were initiated in Q2 2022 due to increase in discount rate from 7% to 8%. Two categories of impairment tests have been performed:
Impairment is recognised when the book value of an asset or a cash-generating unit exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost of disposal and its value in use. The fair value less cost of disposal estimates are level 3 fair value estimates in the fair value hierarchy. Impairments are correspondingly reversed if the conditions for the impairment are no longer present. Upper limit of reversal is the historical impairments less estimated depreciation as if the impairment had not taken place. Impairments of goodwill are not reversed.
The impairment testing is performed based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields.
Key assumptions applied for impairment testing purposes as of 30 June 2022 are based on Vår Energi's macroeconomic assumptions. Below is an overview of the key assumptions applied:
Future price level is a key assumption and has significant impact on the net present value. The oil and gas prices are based on the forward curve for the next three-year period and from the fourth year the oil and gas prices are based on the company's long-term price assumptions. Vår Energi's long term oil price assumption is 65 USD/BBL (real 2022) and long-term gas price is 33.6 USD/BOE.
The nominal oil prices (USD/BBL) applied in the impairment test are as follows:
| Year | 31 Dec 2021 | 31 Mar 2022 | 30 Jun 2022 |
|---|---|---|---|
| 2022 | 74.1 | 90.4 | 105.1 |
| 2023 | 68.9 | 76.6 | 85.9 |
| 2024 | 68.1 | 70.2 | 73.9 |
The nominal gas prices (USD/BOE) applied in the impairment test are as follows:
| Year | 31 Dec 2021 | 31 Mar 2022 | 30 Jun 2022 |
|---|---|---|---|
| 2022 | 121.8 | 205.6 | 222.4 |
| 2023 | 61.5 | 96.0 | 137.4 |
| 2024 | 40.6 | 50.5 | 65.4 |
Future cash flows are calculated based on expected production profiles and estimated proven, probable and risked possible reserves.
Production (mboe) per period as applied in the impairment test:
| Year | MBOE |
|---|---|
| 2022 – 2026 | 489 |
| 2027 – 2031 | 327 |
| 2032 – 2036 | 157 |
| 2037 – 2041 | 84 |
| 2042 – 2054 | 60 |
Future capex, opex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost.
The post tax nominal discount rate used is 8.0 percent, up from 7.0 percent used in Q1 2022 mainly due to increased interest rates.
The currency rates used are 9.00 NOK/USD and 9.90 NOK/EUR for both short and long term. The NOK/USD rates are up from 8.50 NOK/USD as applied at Q1 2022.
The long-term inflation rate is assumed to be 2.0 per cent on the functional currency NOK, consistent with the rates applied at Q1 2022.
The technical goodwill recognised in previous business combinations is allocated to each CGU for the purpose of impairment testing. Hence, technical goodwill is included in the impairment testing of the CGU, and the technical goodwill is written down before the asset. The carrying value of the CGU is the sum of tangible assets, intangible assets and technical goodwill as of the assessment date. In the impairment test performed, carrying value is adjusted by the remaining part of deferred tax from which the technical goodwill arose, to avoid an immediate impairment of all technical goodwill. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable.
The ordinary goodwill is tested for impairment on an operating segment level. If the net recoverable amount calculated as total of NPV less Net book value (NBV) for the offshore asset portfolio exceeds the carrying value of ordinary goodwill, no impairment is recorded.
The impairment testing per Q2 2022 did not identify any impairments, mainly due to increase in short-term oil and gas prices. Historical impairments, excluding goodwill, were fully reversed per Q1 2022.
The table below shows how the impairment or reversal of impairment of assets and technical goodwill would be affected by changes in the various assumptions, given that the remaining assumptions are constant.
| Change in impairment after | |||||
|---|---|---|---|---|---|
| Assumption USD 1000 | Change | Increase in assumption |
Decrease in assumption |
||
| Oil and gas prices | +/-25% | - | 1 275 000 | ||
| Production profile | +/- 5% | - | 8 000 | ||
| Discount rate | +/- 1% point | 1 000 | - |
The sensitivities are created for illustration purposes, based on a simplified method and assumes no changes in other input factors. Significant reductions are likely to result in changes in business plans, cut-offs as well as other factors used when estimating an asset's recoverable amount. Changes in such input factors would likely significantly reduce the actual impairment amount compared to the illustrative sensitivity above.
The climate related risk assessment is generally described in the company's sustainability reporting. Financial reporting and impairment testing includes a step up of CO2 tax/fees from current levels to approximately NOK 2 000 per ton in 2030.
| USD 1000 | Note | 30 Jun 2022 | 31 Mar 2022 | 31 Dec 2021 | 30 Jun 2021 |
|---|---|---|---|---|---|
| Trade receivables – related parties | 22 | 361 750 | 465 067 | 424 834 | 205 180 |
| Trade receivables – external parties | 364 548 | 412 437 | 412 627 | 178 567 | |
| Sale of trade receivables | (166 283) | (378 036) | (91 540) | (87 037) | |
| Total trade receivables | 560 015 | 499 468 | 745 921 | 296 710 |
As part of the Group's working capital optimisation and finance cost minimisation procedures, Vår Energi has entered into Credit Discount Agreements with several banks. Under the arrangements the ownership, including credit risk, of invoices for oil cargos sold are transferred to the respective banks, and the receivables to which the payments relate are derecognised from Vår Energi's balance sheet. Payments to the banks are made when Vår Energi receives payments from the customers.
Trade receivables are presented net of payments received from the banks for the sold invoices, as Vår Energi has retained the right to receive payments from the customers, an obligation to pay these cash flows to the banks without material delay, but only to the extent Vår Energi collects the payments from the customers.
| USD 1000 | Note | 30 Jun 2022 | Restated 31 Mar 2022 |
Restated 31 Dec 2021 |
30 Jun 2021 |
|---|---|---|---|---|---|
| Net underlift of hydrocarbons | 1 | 131 475 | 106 480 | 110 217 | 104 225 |
| Prepaid expenses | 27 394 | 46 787 | 8 305 | 19 671 | |
| Brent crude put options – financial assets | 14 | 18 046 | 10 145 | 17 407 | 16 927 |
| Other | 69 219 | 136 957 | 65 880 | 102 856 | |
| Total other current receivables and financial assets | 246 135 | 300 369 | 201 809 | 243 678 |
The Group uses derivative financial instruments, such as Brent crude put options to hedge its commodity price risks.
As of 30 June 2021 and 30 June 2022, the Group had the following volumes of Brent crude oil put options in place and with the following strike prices:
| Hedging instruments | Volume (no of put options outstanding at balance sheet date) in thousands (BBL) |
Excercise price (USD per BBL) |
|---|---|---|
| Brent crude oil put options 30.06.2021, exercisable in 2021 | 8 214 | 40 |
| Brent crude oil put options 30.06.2021, exercisable in 2022 | 8 292 | 47 |
| Brent crude oil put options 30.06.2022, exercisable in 2022 | 7 219 | 47 |
| Brent crude oil put options 30.06.2022, exercisable in 2023 | 7 213 | 50 |
| USD 1000 | Note | Q2 2022 | 2021 | Q2 2021 |
|---|---|---|---|---|
| The beginning of the period | 10 145 | 26 354 | 16 155 | |
| Cost of hedge | 3 | (10 235) | (60 492) | (14 491) |
| Effective portion recognised in OCI | 6 870 | 9 976 | (631) | |
| New Brent crude put options | 11 116 | 39 339 | 15 859 | |
| FX-effect | 151 | 2 230 | 35 | |
| The end of the period | 18 046 | 17 407 | 16 927 |
As of 30 June 2022, the fair value of outstanding Brent Crude oil put options amounted to USD 18 046 thousand. Unrealised gains and losses are recognised in OCI. Note that the cost price (time value agreed at the inception of the contracts) for the options is paid at the time of realisation (time of exercise or expiration) and that this deferred payment is presented as current liabilities in the balance sheet, see below table.
| USD 1000 | Note | Q2 2022 | 2021 | Q2 2021 |
|---|---|---|---|---|
| The beginning of the period | (35 295) | (58 263) | (54 378) | |
| Cost of hedge | 3 | 10 235 | 60 492 | 14 491 |
| New Brent crude put options | (11 116) | (39 339) | (15 859) | |
| FX-effect | (151) | (2 229) | (35) | |
| The end of the period | (36 327) | (39 339) | (55 780) |
The full intrinsic value ("in the money value") of the options at the time of expiry, if any, is presented in petroleum revenues. The premiums paid for the put options are accounted for as cost of hedging and recycled from OCI to the income statement in the period in which the hedged revenues are realised, and presented as production costs.
The table below shows a reconciliation between the opening and the closing balances in the statement of financial position for liabilities arising from financing activities.
| Non-cash changes | ||||||
|---|---|---|---|---|---|---|
| USD 1000 | 31 Dec 2021 | Cash flows Amortisation | Currency | Other | 30 Jun 2022 | |
| Bond USD Senior Notes (22/27) | - | 500 000 | 500 000 | |||
| Long-term interest-bearing debt (RCF) | 4 520 500 | (2 020 500) | 2 500 000 | |||
| Deferred payment ExxonMobil 1 | 333 149 | 10 053 | 343 202 | |||
| Prepaid loan expenses | (27 074) | (3 094) | 6 964 | 316 | 351 | (22 537) |
| Totals | 4 826 575 | (1 523 594) | 17 017 | 316 | 351 | 3 320 665 |
1 Deferred payment to ExxonMobil is due 30.12.2022 and is classified as current liability as of December 2021. It includes accrued interest.
| USD 1000 | 30 Jun 2022 | 31 Mar 2022 | 31 Dec 2021 | 30 Jun 2021 |
|---|---|---|---|---|
| Bank deposits, unrestricted | 885 366 | 521 472 | 214 133 | 282 222 |
| Bank deposit, restricted, employee taxes | 6 679 | 17 267 | 9 454 | 9 338 |
| Total bank deposits | 892 046 | 538 739 | 223 588 | 291 560 |
Vår Energi ASA was listed on the Oslo Stock Exchange 16 February 2022, and as a consequence of this, company bylaws, voting rights and composition of the board was changed.
In 2021, the share capital was 399 425 shares at par value NOK 1 000. Every share had equal voting rights, 1 share corresponded to 1 vote.
As of 30 June 2022, the total share capital of the company is USD 45 972 thousand or NOK 399 425 thousand. The share capital is divided into 2 496 406 246 ordinary shares and 4 Class B shares. Each share has a nominal value of NOK 0.16. The ordinary shares represent NOK 399 424 999.36 of the total share capital, while the Class B shares represent NOK 0.64 of the total share capital.
All shares rank pari passu and have equal rights in all respect, including with respect to voting rights and dividends and other distributions, except from the class B shares. 4 members to the board, will be elected by the general meeting with a simple majority among the votes cast for Class B shares. Such number to be reduced if the holder of the Class B shares holds less shares of the company.
Earnings per share are calculated by dividing the net result attributable to shareholders of the Parent Company by the number of shares after the listing on Oslo Stock Exchange. The calculation for all periods presented have been adjusted retrospectively to the new number of shares.
Vår Energi ASA's share saving program gives employees the opportunity to buy shares in Vår Energi ASA through monthly salary deductions. If the shares are retained for two full calendar years with continuous employment after the end of the saving year, the employees will be awarded a bonus share for each share they have purchased. This will be settled by Vår Energi ASA buying shares in the market. The award is treated as equity settled, hence it will not affect earnings per share.
| USD 1000 | Coupon/ Int. Rate | Maturity | 30 Jun 2022 | 31 Mar 2022 | 31 Dec 2021 | 30 Jun 2021 |
|---|---|---|---|---|---|---|
| Bond USD Senior Notes (22/27) | 5% | 500 000 | - | - | ||
| RBL credit facility | - | - | 4 815 000 | |||
| Bridge facility | 0.65%+SOFR +CAS | Nov 2023 | 2 500 000 | 3 000 000 | 3 000 000 | - |
| Working capital facility | 1.08%+SOFR +CAS | Nov 2024 | - | 340 000 | 1 420 500 | - |
| Credit facility | 1.13%+SOFR +CAS | Mar 2023 | - | 100 000 | - | |
| Deferred payment ExxonMobil | 343 202 | 337 816 | 333 149 | 326 275 | ||
| Prepaid loan expenses | (22 537) | (23 943) | (27 074) | (62 559) | ||
| Total interest-bearing loans and borrowings |
3 320 665 | 3 653 873 | 4 826 575 | 5 078 717 | ||
| Of which current and non-current | ||||||
| Interest-bearing loans, current | 343 202 | 337 816 | 333 149 | - | ||
| Interest-bearing loans and borrowings | 2 977 463 | 3 316 057 | 4 493 426 | 5 078 717 |
| USD 1000 | 30 Jun 2022 | 31 Mar 2022 | 31 Dec 2021 | 30 Jun 2021 |
|---|---|---|---|---|
| Drawn amount RCF credit facility | 2 500 000 | 3 340 000 | 4 520 500 | 4 815 000 |
| Undrawn amount credit facilities 1 | 3 600 000 | 3 260 000 | 2 079 500 | 1 019 526 |
1 Where current share is 600 mUSD in Q2 2022
On 1 November 2021, Vår Energi signed a senior unsecured multicurrency facilities agreement for USD 6.0 billion with a group of 12 international banks, refinancing the reserve based lending ('RBL') facility.
On 18 May 2022 Vår Energi ASA issued USD 500 million of 5% Senior Notes due in 2027 at a price equal to 99.961% on the Luxembourg Stock Exchange ("LuxSE"). The cupon is payable semi-annually on 18 May and 18 November. The funds were used for partial repayment of the Bridge Facility.
Per 30 June the facilities agreement contains of 3 separate facilities amounting to USD 5.5 billion; (1) bridge to bond facility of USD 2.5 billion which including extension options at the borrower's discretion has a tenor of up to 2 years, (2) working capital revolving credit facility of USD 1.5 billion with a tenor 3 years and (3) liquidity facility of USD 1.5 billion with a tenor 5 years. The facilities have no amortisation structure and all amounts outstanding fall due at maturity. The facilities have covenants covering leverage (net interest-bearing debt to 12 months rolling EBITDAX not to exceed 3.5) and interest coverage (EBITDA to 12 months rolling interest expenses shall exceed 5) which will be tested at the end of each calendar quarter.
The interest rate payable for each of the facilities is determined by timing and the company's credit rating taking the aggregate of the Secured Overnight Financing Rate (SOFR) and the Credit Adjustment Spread (CAS) and adding the applicable margin for the present period as shown in the table above.
On 24 March 2020, Vår Energi signed two unsecured revolving credit facility agreements (RCF) for a total amount of USD 600 million with a tenor of 3 years. The agreements were amended and restated 18 November 2021 to align with the Corporate Facilities with no changes to tenor or total commitment.
Deferred payment to ExxonMobil is part of the consideration for the 2019 acquisition of ExxonMobil's ownership interests in Partner-Operated fields and licenses on the Norwegian Continental Shelf.
| USD 1000 | Q2 2022 | Q1 2022 | 2021 |
|---|---|---|---|
| Beginning of period | 3 588 425 | 3 297 176 | 4 286 451 |
| Change in estimate | (188 120) | 266 158 | (922 730) |
| Accretion discount | 22 076 | 24 282 | 94 733 |
| Payment for decommissioning of oil and gas fields | (22 786) | (28 839) | (70 418) |
| Currency translation effects | (434 027) | 29 648 | (90 860) |
| Total asset retirement obligations | 2 965 568 | 3 588 425 | 3 297 176 |
| Short-term | 18 016 | 35 552 | 61 536 |
| Long-term | 2 947 552 | 3 552 873 | 3 235 640 |
| Breakdown by decommissioning period | 30 Jun 2022 | 31 Mar 2022 | 31 Dec 2021 |
| 2022 – 2030 | 215 008 | 271 421 | 269 534 |
| 2031 – 2040 | 1 790 513 | 2 162 039 | 1 989 456 |
| 2041 – 2057 | 960 047 | 1 154 965 | 1 038 186 |
Change in estimate include updated discount rates and revised cost estimates for Balder and Goliat in Q2 2022.
The estimate is based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate 2.0% and discount rates between 2.9% – 3.2% per Q2 2022. For year end 2021 the inflation rates were 1.8% – 2.3% and the discount rates between 1.15% – 3.0%. The discount rates are based on risk-free interest without addittion of credit margin.
Second quarter 2022 payment for decommissioning of oil and gas fields (abex) is mainly related to Ringhorne USD 15 766 thousand and Ekofisk/Tor USD 7 021 thousand.
Vår Energi has a retirement obligation as a shipper in Gassled booked to other non-current liabilities in the balance sheet statement. The Group has accrued USD 66 353 thousand for this purpose per 30 June 2022.
| USD 1000 | Note | 30 Jun 2022 | Restated 31 Mar 2022 |
Restated 31 Dec 2021 |
30 Jun 2021 |
|---|---|---|---|---|---|
| Net overlift of hydrocarbons | 1 | 198 143 | 131 819 | 100 057 | 27 556 |
| Net payables to joint operations | 291 782 | 462 911 | 408 426 | 463 700 | |
| Employees, accrued public charges and other payables | 11 909 | 18 405 | 5 314 | 3 267 | |
| Deferred payment for option premiums – oil puts | 14 | 36 327 | 35 295 | 39 339 | 55 780 |
| Total other current liabilities | 538 160 | 648 430 | 553 136 | 550 303 |
The liability for oil put options relates to cost of oil put options that under the purchase agreement is due for payment at the time of settlement of the option (exercise/expiry) and is not a measure of fair value.
During the normal course of its business, the company will be involved in disputes, including tax disputes. The company has made accruals for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS37 and IAS12.
The company has significant contractual commitments for capital and operating expenditures from its participation in operated and partner operated exploration, development and production projects. The current main development projects are Johan Castberg, Balder Future and Breidablikk.
Vår Energi has entered into lease agreements for drilling rigs, helicopter, storage vessel and other vessels to secure planned activities.
The Group has lease agreements for offices in Sandnes, Oslo and Hammerfest. The most significant office contract is the lease of the main office building in Vestre Svanholmen 1, Sandnes.
Vår Energi also has leases for supply vessels and warehouses supporting operation at Balder and Goliat, where the most significant are for the supply vessels operating at Goliat.
Two new lease agreements commenced in Q1 2022 for helicopter services at Sola and storage unit in Sandnes. There are no new lease agreements in 2Q 2022.
| USD 1000 | Q2 2022 | Q1 2022 | 2021 |
|---|---|---|---|
| Opening Balance lease debt | 299 799 | 325 088 | 164 482 |
| New lease debt in period | - | 6 680 | 208 819 |
| Payments of lease debt | (25 627) | (35 838) | (48 401) |
| Interest expense on lease debt | 1 957 | 3 227 | 7 819 |
| Currency exchange differences | (12 523) | 642 | (7 631) |
| Total lease debt | 263 606 | 299 799 | 325 088 |
| Breakdown of the lease debt to short-term and long-term liabilities | 30 Jun 2022 | 31 Mar 2022 | 31 Dec 2021 |
| Short-term | 103 301 | 108 458 | 108 880 |
| Long-term | 160 305 | 191 341 | 216 208 |
| Total lease debt | 263 606 | 299 799 | 325 088 |
| Lease debt split by activities | 30 Jun 2022 | 31 Mar 2022 | 31 Dec 2021 |
| Offices | 57 301 | 66 376 | 66 525 |
| Rigs, helicopters and supply vessels | 197 301 | 222 319 | 250 811 |
| Warehouse | 9 003 | 11 103 | 7 752 |
| Total | 263 606 | 299 799 | 325 088 |
Vår Energi has a number of transactions with other wholly owned or controlled companies by the shareholders. The related party transactions reported is owned/controlled by the majority owner of Vår Energi, Eni International BV. Revenues are mainly related to sale of oil, gas and NGL while the expenditures are mainly related to technical services, seconded personnel, insurance guarantees and rental cost.
| Current assets | ||||
|---|---|---|---|---|
| USD 1000 | 30 Jun 2022 | 31 Mar 2022 | 31 Dec 2021 | 30 Jun 2021 |
| Trade receivables | ||||
| Eni Trade & Biofuels SpA | 110 883 | 271 626 | 160 533 | 160 091 |
| Eni SpA | 199 327 | 125 135 | 123 884 | 23 148 |
| Eni Global Energy Markets | 49 436 | 65 740 | 138 342 | 17 843 |
| Other | 2 104 | 2 566 | 2 075 | 4 098 |
| Total trade receivables | 361 750 | 465 067 | 424 834 | 205 180 |
All receivables are due within 1 year.
| USD 1000 | 30 Jun 2022 | 31 Mar 2022 | 31 Dec 2021 | 30 Jun 2021 |
|---|---|---|---|---|
| Account Payables | ||||
| Eni International BV | 10 868 | 26 369 | 21 336 | 10 992 |
| Eni Global Energy Markets | 11 152 | 12 349 | 24 547 | 18 923 |
| Eni SpA | 6 763 | 9 055 | 19 387 | 15 128 |
| Other | 1 099 | 979 | 915 | 814 |
| Total account payables | 29 882 | 48 751 | 66 185 | 45 858 |
| Sales revenue | |||||
|---|---|---|---|---|---|
| USD 1000 | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
| Eni Trade & Biofuels SpA | 646 220 | 707 828 | 459 820 | 1 354 048 | 835 545 |
| Eni SpA | 327 112 | 340 504 | 70 851 | 667 616 | 164 379 |
| Eni Global Energy Markets | 133 186 | 161 508 | 38 381 | 294 694 | 73 318 |
| Total sales revenue | 1 106 518 | 1 209 840 | 569 052 | 2 316 358 | 1 073 242 |
| USD 1000 | Q2 2022 | Q1 2022 | Q2 2021 | YTD 2022 | YTD 2021 |
|---|---|---|---|---|---|
| Eni Trade & Biofuels SpA | 13 705 | 17 782 | 7 876 | 31 486 | 10 858 |
| Eni International BV | 6 737 | 4 867 | 5 623 | 11 604 | 11 148 |
| Eni SpA | 9 200 | 2 549 | 12 176 | 11 748 | 16 775 |
| Eni Global Energy Markets | 373 | (12 329) | 13 661 | (11 957) | 15 617 |
| Eni International Resources Ltd. | 1 077 | 422 | 796 | 1 499 | 857 |
| Other | 276 | 152 | (5 203) | 428 | (10 252) |
| Total operating and capital expenditures | 31 367 | 13 442 | 34 928 | 44 809 | 45 003 |
| Fields | WI % | Operator |
|---|---|---|
| PL091F | 41% | Vår Energi |
| PL209 BS | 10% | Equinor |
| PL586B | 45% | Neptune |
| PL1025SB | 30% | Vår Energi |
| PL1043B | 40% | Vår Energi |
| PL1139 | 20% | Lundin |
| PL1154 | 40% | Vår Energi |
| PL1163 | 20% | ConocoPhillips |
| PL1168 | 50% | Vår Energi |
| PL1169 | 30% | Equinor |
| PL229H | 50% | Vår Energi |
| Fields | WI % | Operator | Changes |
|---|---|---|---|
| Additions | |||
| PL393 | 30% | Vår Energi | Working interest and operator |
| PL917 | 20% | Vår Energi | Working interest and operator |
| PL917B | 20% | Vår Energi | Working interest and operator |
| Disposals | |||
| PL956 | 20% | Vår Energi | Working interest |
| PL985 | 10% | Vår Energi | Working interest |
The asset transactions are licenses in the exploration phase and settled without cash considerations.
In 2022 Vår Energi has entered into forward gas sales contracts. Vår Energi has sold approximately 15% of its remaining estimated 2022 gas production on fixed prices at an average price of 140 USD/boe. The current market situation is very much impacted by the war in Ukraine and uncertainty related to availability of gas from Russia into the European market. There is currently not sufficient liquidity in the market to enter into new fixed price gas sales contracts.
Vår Energi operates only on the Norwegian Continental Shelf and market its petroleum products to customers in Norway, EU and UK. While not directly exposed to Russia's invasion of Ukraine, there is significant uncertainty regarding the potential impact on safe and reliable energy supply, as well as to the market prices of oil, gas and other commodities which mayimpact future operations and results.
| Term | Definition/description |
|---|---|
| Term | Definition/description |
| Boepd | Barrels of oil equivalent per day |
| Bscf | Billions of standard cubic feet |
| CFFO | Cash flow from operations |
| E&P | Exploration and Production |
| FID | Final investment decision |
| FPSO | Floating, production, storage and offloading vessel |
| HAP | High activity period |
| HSEQ | Health, Safety, Environment and Quality |
| HSSE | Health, Safety, Security and Environment |
| IG | Investment grade |
| Kboepd | Thousands of barrels of oil equivalent per day |
| Mmbls | Standard millions of barrels |
| Mmboe | Millions of barrels of oil equivalents |
| Mmscf | Millions of standard cubic feet |
| MoF | Ministry of Finance |
| MPE | Ministry of Petroleum and Energy |
| NCS | Norwegian Continental Shelf |
| NGL | Natural gas liquids |
| NPD | Norwegian Petroleum Directorate |
| OSE | Oslo Stock Exchange |
| PDO | Plan for Development and Operation |
| PIO | Plan for Installation and Operations |
| PRM | Permanent reservoir monitoring |
| Term | Definition/description |
|---|---|
| PRMS | Petroleum Resources Management System |
| Scf | Standard cubic feet |
| Sm3 | Standard cubic meters |
| SPT | Special petroleum tax |
| SPS | Subsea production system |
| SURF | Subsea umbilicals, riser and flowlines |
| 1P reserves | The quantities of petroleum which can be estimated with reasonable certainty to be commercially recoverable, also referred to as "proved reserves". |
| 2C resources | The quantities of petroleum estimated to be potentially recoverable from known accumulations, also referred to as "contingent resources". |
| 2P reserves | Proved plus probable reserves consisting of 1P reserves plus those additional reserves, which are less likely to be recovered than 1P reserves. |
The Materials speak only as of their date, and the views expressed are subject to change based on a number of factors, including, without limitation, macroeconomic and equity market conditions, investor attitude and demand, the business prospects of the Group and other specific issues. The Materials and the conclusions contained herein are necessarily based on economic, market and other conditions, as in effect on, and the information available to the Company as of, their date. The Materials do not purport to contain all information required to evaluate the Company, the Group and/or their respective financial position. The Materials should be reviewed together with the Company's Annual Report 2021. The Materials contain certain financial information, including financial figures for and as of 30 June, 2022 that is preliminary and unaudited, and that has been rounded according to established commercial standards. Further, certain financial data included in the Materials consists of financial measures which may not be defined under IFRS or Norwegian GAAP. These financial measures may not be comparable to similarly titled measures presented by other companies, nor should they be construed as an alternative to other financial measures determined in accordance with IFRS or Norwegian GAAP.
The Company strongly suggests that each Recipient seeks its own independent advice in relation to any financial, legal, tax, accounting or other specialist advice; no such advice is given by the Materials. Nothing herein shall be taken as constituting the giving of investment advice and the Materials are not intended to provide, and must not be taken as, the exclusive basis of any investment decision or other valuation and should not be considered as a recommendation by the Company (or any of its affiliates) that any Recipient enters into any transaction. The Materials comprise a general summary of certain matters in connection with the Group. The Materials do not purport to contain all the information that any Recipient may require to make a decision with regards to any transaction. Any decision as to whether to enter into any
transaction should be taken solely by the relevant Recipient. Before entering into such transaction, each Recipient should take steps to ensure that it fully understands such transaction and has made an independent assessment of the appropriateness of such transaction in the light of its own objectives and circumstances, including the possible risks and benefits of entering into such transaction.
The Materials may constitute or include forward-looking statements. Forwardlooking statements are statements that are not historical facts and may be identified by words such as "plans", "targets", "aims", "believes", "expects", "projects", "anticipates", "intends", "estimates", "will", "may", "continues", "should" and similar expressions. Any statement, estimate or projections included in the Materials (or upon which any of the conclusion contained herein are based) with respect to anticipated future performance (including, without limitation, any statement, estimate or projection with respect to the condition (financial or otherwise), prospects, business strategy, plans or objectives of the Group and/or any of its affiliates) reflect, at the time made, the Company's beliefs, intentions and current targets /aims and may prove not to be correct. Although the Company believes that these assumptions were reasonable when made, these assumptions are inherently subject to significant known and unknown risks, uncertainties, contingencies and other important factors which are difficult or impossible to predict and are beyond its control. The Company does not intend or assume any obligation to update these forwardlooking statements since they are based solely on the circumstances at the date of publication.
To the extent available, the industry, market and competitive position data contained in the Materials come from official or third-party sources. Thirdparty industry publications, studies and surveys generally state that the data contained therein have been obtained from sources believed to be reliable,
but that there is no guarantee of the accuracy or completeness of such data. While the Company believes that each of these publications, studies and surveys has been prepared by a reputable source, none of the Company, its affiliates or any of its or their respective representatives has independently verified the data contained therein. In addition, certain of the industry, market and competitive position data contained in the Materials come from the Company's own internal research and estimates based on the knowledge and experience of the Company in the markets in which it has knowledge and experience. While the Company believes that such research and estimates are reasonable, they, and their underlying methodology and assumptions, have not been verified by any independent source for accuracy or completeness and are subject to change and correction without notice. Accordingly, reliance should not be placed on any of the industry, market or competitive position data contained in the Materials.
The Materials are not directed to, or intended for distribution to or use by, any person or entity that is a citizen or resident or located in any locality, state, country or other jurisdiction where such distribution, publication, availability or use would be contrary to law or regulation of such jurisdiction or which would require any registration or licensing within such jurisdiction. Any failure to comply with these restrictions may constitute a violation of the laws of any such jurisdiction. The Company's securities have not been registered and the Company does not intend to register any securities referred to herein under the U.S. Securities Act of 1933 (as amended) or the laws of any state of the United States. This document is also not for publication, release or distribution in any other jurisdiction where to do so would constitute a violation of the relevant laws of such jurisdiction nor should it be taken or transmitted into such jurisdiction and persons into whose possession this document comes should inform themselves about and observe any such restrictions.
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