Equinor

Annual Report • Mar 23, 2023

| Equinor 2022 Oil and gas reserves report

Oil and gas reserves report

Introduction

About the report

This report presents Equinor`s proved oil and gas reserves as of 31 December 2022. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

In alignment with industry practice and regulatory requirements, we report operational performance and supplementary oil and gas information (unaudited). Numbers have been prepared in accordance with the reserve definitions of Rules 4-10(a) (1)-(32) of Regulations S-X of the United States Securities and Exchange Commission (SEC). All numbers are internal estimates produced by Equinor. Estimates of reserves should be regarded only as estimates that may change over time as further production history and additional information becomes available. The determination of these reserves is part of an ongoing process subject to continual revision. Moreover, identified reserves and contingent resources that may become proved in the future are excluded from the estimates of proved reserves provided in this report.

The Oil and gas reserves report may be downloaded from Equinor`s website at www.equinor.com/reports. The report is also included as Exhibit 15.5 to the 2022 annual report on Form 20-F.

Operational performance

Proved oil and gas reserves

Proved oil and gas reserves were estimated to be 5,191 million boe at year end 2022, compared to 5,356 million boe at the end of 2021.

Proved reserves

Changes in proved reserves estimates are most commonly the result of revisions of estimates due to observed production performance or changes in prices or costs, extensions of proved areas through drilling activities or the inclusion of proved reserves in new discoveries through the sanctioning of new development projects. These changes are the result of continuous business processes and can be expected to

Proved reserves can also be added or subtracted through purchases and sales of reserves-in-place or factors outside management control.

Changes in oil and gas prices can affect the quantities of oil and gas that can be recovered from the accumulations. Higher oil and gas prices will normally allow more oil and gas to be recovered, while lower prices will normally result in reduced recovery. However, for fields with production sharing agreements (PSA), higher prices may result in reduced entitlement to produced volumes and lower prices may result in increased entitlement to produced volumes. These described changes are included in the revisions and improved recovery (IOR) category in the tables that follows in this report.

The principles for booking proved gas reserves are limited to contracted gas sales or gas with access to a robust gas market.

Equinor prepares its disclosures for oil and gas reserves and certain other supplemental oil and gas disclosures by geographical area, as required by the US Securities and Exchange Commission (SEC). The geographical areas are defined by country and continent. These are Norway, Eurasia excluding Norway, Africa, the USA and the Americas excluding USA.

In Norway and other countries where there is a resonable certainty that the authorities will approve the plan for development and operation (PDO), Equinor recognises reserves as proved undeveloped reserves when the PDO is submitted to the authorities. Otherwise, reserves are generally booked as proved

undeveloped reserves when regulatory approval is received, or when such approval is imminent. Undrilled well locations in onshore fields in the USA are generally booked as proved undeveloped reserves when a development plan has been adopted and the well locations are scheduled to be drilled within five years.

Approximately 87% of Equinor's proved reserves are located in the Organisation of Economic Co-Operation and Development (OECD) countries. Norway is by far the most important contributor in this category, followed by the USA. Of Equinor's total proved reserves, 5% are related to PSAs in non-OECD countries such as Angola, Brazil, Azerbaijan, Algeria, Nigeria and Libya. Other proved non-OECD reserves are related to concession fields in Argentina and Brazil, representing all together 7% of Equinor's total proved reserves.

Eurasia excluding Norway

continue to affect reserves in the future.

Proved developed reserves

Changes in proved reserves in 2022

The total volume of proved reserves decreased by 165 million boe in 2022.

Change in proved reserves

		For the year ended 31 December
(in USD million)	2022	2021	2020
Revisions and improved recovery (IOR)	344	596	(171)
Extensions and discoveries	278	306	131
Purchases of reserves-in-place	36	-	6
Sales of reserves-in-place	(128)	(96)	-
Total reserve additions	530	806	(34)
Production	(695)	(710)	(710)
Net change in proved reserves	(165)	96	(744)

Changes in proved reserves million boe

Revisions and IOR

Revisions of previously booked reserves, including the effect of improved recovery, increased the proved reserves by net 344 million boe in 2022. The increase is the result of 433 million boe in positive revisions and increased recovery, partially offset by 89 million boe in negative revisions. Many producing fields had positive revisions due to better performance, new drilling targets and improved recovery measures, as well as reduced uncertainty due to further drilling and production experience. The positive revisions also included a direct effect of higher commodity prices, increasing the proved reserves by approximately 63 million boe through increased economic lifetime on several fields. The negative revisions were mainly related to unforeseen events and operational challenges resulting in reduced production potential on some fields in addition to reduced entitlement volumes from several fields with PSAs.

Extensions and discoveries

A total of net 278 million boe of new proved reserves were added through extensions and discoveries. Continuous extension of the proved area in the Appalachian basin together with a record number of submitted PDOs in Norway, of which Munin and Halten Øst were the largest, are the main contributors in this category. In addition, this category includes extensions of proved areas through drilling of new wells in previously undrilled areas at other fields in Norway and in Argentina.

Purchases and sales of reserves-in-place

A total of 36 million boe of new proved reserves in the Statfjord Area, which covers the Norwegian continental shelf (NCS) and UK continental shelf, were purchased in 2022.

A total of 128 million boe of sales of reserves-in-place are related to the exit of joint arrangements in Russia in addition to the sale of the Ekofisk Area and a minority share in the Martin Linge field on the NCS. Equinor has no remaining proved reserves in Russia at year end 2022.

In the fourth quarter of 2021, Equinor entered into an agreement to divest our interests in the Corrib field in Ireland. Closing is dependent on governmental approval and is expected to take place in the first quarter of 2023. The sale will result in an estimated reduction in proved reserves of approximately 11 million boe.

Production

The 2022 entitlement production was 695 million boe, down from 710 million boe in 2021 due to sales, natural decline and operational challenges.

Increase Decrease Total

Development of reserves

In 2022, 241 million boe were matured from proved undeveloped to proved developed reserves. Continued drilling in the Appalachian basin in the USA and on major offshore assets in addition to the production start of Askeladd (Snøhvit), Johan Sverdrup Phase 2 and Peregrino Phase 2 contributed to the major portion of maturation of proved undeveloped to proved developed reserves in 2022. Smaller volumes are related to individual assets world-wide. The positive revision and improved recovery of proved developed reserves of 322 million boe is related to increased economic lifetime at some fields, increased activity levels, higher commodity prices and implementation of improved recovery projects. Finally, 256 million boe was added to proved undeveloped reserves through

extensions and discoveries, the largest of these being Munin and Halten Øst in Norway, in addition to further development in the Appalachian basin in the USA.

In 2021, 881 million boe were matured from proved undeveloped to proved developed reserves. Production start of the Troll Phase 3 project and the Martin Linge field added more than 600 million boe to the proved developed reserves. Continued drilling in the Appalachian basin in the USA and in the Oseberg, Johan Sverdrup, and Snorre fields in Norway increased the proved developed reserves by 180 million boe during 2021. The remaining 100 million boe of the matured volume is related to a wide range of activities on assets world-wide. The positive revisions of both

proved developed reserves of 471 million boe and proved undeveloped reserves of 125 million boe are related to higher commodity prices, increasing economic lifetime at some fields, as well as increased activity levels. Undeveloped extensions and discoveries of 269 million boe are dominated by the onshore assets in the Appalachian basin and in Argentina, together with the Bacalhau field in Brazil and the Johan Castberg field in Norway.

In 2020, 250 million boe were matured from proved undeveloped to proved developed reserves. Continued drilling in the Appalachian basin in the USA and in the Johan Sverdrup, Ærfugl and Oseberg fields in Norway, increased the proved developed reserves by

200 million boe during 2020. The remaining 50 million boe of the matured volume was related to a wide range of activities on assets world-wide. The negative revision of proved undeveloped reserves of 131 million boe was both related to lower commodity prices, decreasing economic lifetime at some fields, as well as reduced activity levels and operational challenges This resulted in a reduction of proved undeveloped reserves, particularly in the onshore assets in the USA, in fields in Brazil and in the UK.

Over the last five years, Equinor has matured 2,376 million boe of proved undeveloped reserves to proved developed reserves.

		2022			2021			2020
	Total proved			Total proved			Total proved
(million boe)	reserves	Developed	Undeveloped	reserves	Developed	Undeveloped	reserves	Developed	Undeveloped
At 1 January	5,356	3,818	1,538	5,260	3,222	2,038	6,004	3,679	2,325
Revisions and improved recovery	344	322	22	596	471	125	(171)	(40)	(131)
Extensions and discoveries	278	22	256	306	37	269	131	37	94
Purchases of reserves-in-place	36	29	7	-	-	-	6	6	0
Sales of reserves-in-place	(128)	(66)	(62)	(96)	(83)	(13)	-	-	-
Production	(695)	(695)	-	(710)	(710)	-	(710)	(710)	-
Moved from undeveloped to developed	-	241	(241)	-	881	(881)	-	250	(250)
At 31 December	5,191	3,672	1,519	5,356	3,818	1,538	5,260	3,222	2,038

Proved developed and undeveloped reserves

As of 31 December 2022	Oil and condensate (mmboe)	NGL (mmboe)	Natural gas (mmmcf)	Total oil and gas (mmboe)
Developed
Norway	731	149	10,294	2,714
Eurasia excluding Norway	35	3	89	53
Africa	107	8	91	131
USA	161	51	1,921	554
Americas excluding USA	216	-	25	220
Total developed proved reserves	1,249	210	12,420	3,672
Undeveloped
Norway	562	60	2,087	994
Eurasia excluding Norway	48	0	5	50
Africa	17	0	-	17
USA	56	9	423	140
Americas excluding USA	316	-	11	318
Total undeveloped proved reserves	999	70	2,526	1,519
Total proved reserves	2,248	280	14,946	5,191

Reserves replacement ratio

		For the year ended 31 December
	2022	2021
Annual	76%	113%	(5%)
Three-year-average	62%	61%	95%

As of 31 December 2022, the total proved undeveloped reserves amounted to 1,519 million boe, 65% of which are related to fields in Norway. The Johan Sverdrup, Snøhvit and Oseberg area fields, which have continuous development activities, together with fields not yet in production, such as Johan Castberg and Munin, have the largest proved undeveloped reserves in Norway. The largest assets with proved undeveloped reserves outside Norway, are Bacalhau, Peregrino and Roncador in Brazil, the Appalachian basin, Vito and Caesar-Tonga in the USA, Mariner in the UK, and ACG in Azerbaijan. All these fields are either producing or will start production within the next five years.

For fields with proved reserves where production has not yet started, investment decisions have already been sanctioned and investments in infrastructure and facilities have commenced. There are no material development projects, which would require a separate future investment decision by management, included in our proved reserves. Some offshore development activities will take place more than five years from the disclosure date on many fields, but these are mainly related to incremental type of spending, such as drilling of additional wells from existing facilities, in order to secure continued production.

For projects under development, the Covid-19 pandemic impacted progress due to personnel limitations on offshore as well as onshore facilities and yards. The pandemic has delayed production start at the Johan Castberg field in Norway. The field was originally planned to start production in 2022, four years after the field development was sanctioned. The start-up is delayed to 2024.

For our onshore assets, all proved undeveloped reserves are limited to wells that are scheduled to be drilled within five years.

In 2022, Equinor incurred USD 6.9 billion in development costs relating to assets carrying proved reserves, of which USD 5.8 billion was related to proved undeveloped reserves.

Reserves replacement

The reserves replacement ratio is defined as the net amount of proved reserves added divided by produced volumes in any given period.

The 2022 reserves replacement ratio was 76% and the corresponding three-year average was 62%.

The organic reserves replacement ratio, excluding sales and purchases, was 89% in 2022 compared to 127% in 2021. The organic average three-year replacement ratio was 70% at the end of 2022 compared to 68% at the end of 2021.

Proved reserves by region

Proved reserves in Norway

A total of 3,708 million boe was recognised as proved reserves on the NCS, representing 71% of Equinor's total proved reserves at year end 2022. Of these, 3,208 million boe are related to fields and field areas currently in production, 94% of which is operated by Equinor.

Production experience, further drilling and improved recovery on many of Equinor's producing fields contributed with positive revisions of 318 million boe in 2022. Negative revisions totalled 43 million boe and were mainly related to operational challenges. Higher commodity prices increased the proved reserves by 74 million boe. PDOs for several new fields have been submitted to the Norwegian Ministry of Petroleum and Energy in 2022, contributing to extensions and discoveries which totalled 181 million boe in 2022. This increase also included the addition of new segments to some fields.

Of total proved reserves on the NCS, 2,714 million boe (73%) are proved developed reserves at year end 2022. Of the total proved reserves in this area, 60% are gas reserves mainly related to large fields such as Troll, the Oseberg area and Snøhvit, and 40% are liquid reserves mainly related to large fields such as Johan Sverdrup, Snorre and the Oseberg area.

Proved reserves - Norway (million boe)

5000

Proved reserves in Eurasia, excluding Norway

A total of 103 million boe was recognised as proved reserves in the United Kingdom, Azerbaijan and Ireland at year end 2022. Eurasia excluding Norway represents 2% of Equinor's total proved reserves. All fields in this area are producing. The sale of our interest in joint arrangements in Russia in 2022 resulted in a reduction of proved reserves of 86 million boe.

Of total proved reserves in Eurasia excluding Norway, 53 million boe (52%) are proved developed reserves at year end 2022. Of the total proved reserves in this area, 84% are liquid reserves mainly related to larger fields such as ACG and Mariner, and 16% are gas reserves mainly related to the Corrib field and the UK part of the Statfjord field.

Proved reserves - Eurasia exluding Norway (million boe)

Proved developed reserves Proved undeveloped reserves

Proved reserves in Africa

A total of 148 million boe was recognised as proved reserves in PSAs in Angola, Algeria, Nigeria and Libya at year end 2022. Angola and Algeria are the primary contributors to the proved reserves in this area. Africa represents 3% of Equinor's total proved reserves. All fields in this area are producing. Net positive revisions increased the proved reserves by 29 million boe in 2022, mainly related to extended contract and longer technical lifetime on some fields, new wells and positive reservoir performance. Higher commodity prices decreased the proved reserves in Africa by 20 million boe.

Of total proved reserves in Africa, 131 million boe (88%) are proved developed reserves at year end 2022. Of the total proved reserves in this area, 89% are liquid reserves mainly related to large oil fields such as Agbami, In Amenas and Murzuq, and 11% are gas reserves related to the In Salah field.

Proved reserves - Africa

(million boe)

Proved developed reserves Proved undeveloped reserves

Proved developed reserves Proved undeveloped reserves

Proved reserves in the USA

A total of 694 million boe was recognised as proved reserves related to onshore operations and offshore fields in the USA at year end 2022. The USA represents 13% of Equinor's total proved reserves. All fields in this area except for Vito are in the production phase at year end. Most of the onshore operations and offshore fields in the USA are mature and on decline. New wells extending the proved areas in the USA onshore assets in 2022, added a total of 89 million boe in the extensions and discoveries category. The proved reserves in the USA were also subject to a net positive revision of 49 million boe, mainly due to increased activity levels and higher commodity prices.

Of total proved reserves in the USA, 554 million boe (80%) are proved developed reserves at year end 2022. Of the total proved reserves in this area, 60% are gas reserves mainly related to the Appalachian basin, and 40% are liquid reserves mainly related to the Appalachian basin and the offshore fields Caesar-Tonga and St. Malo.

Proved reserves - USA

(million boe)

Proved reserves in the Americas excluding USA

A total of 538 million boe was recognised as proved reserves in the Americas excluding USA at year end 2022, generally at the same level as at year end 2021. Three fields are located offshore Brazil, two fields offshore Canada and one field onshore in Argentina. The Americas excluding USA represents 10% of Equinor's total proved reserves. All fields in this area except for Bacalhau are in the production phase at year end.

Of total proved reserves in the Americas excluding USA, 220 million boe (41%) are proved developed reserves at year end 2022. Of the total proved reserves in this area, 99% are liquid reserves mainly related to large oil fields such as Bacalhau, Peregrino and Roncador, and 1% are gas reserves.

Proved reserves - Americas excl. USA (million boe)

Proved developed reserves Proved undeveloped reserves

Preparation of reserves estimates

Equinor's annual reporting process for proved reserves is coordinated by a central corporate reserves management (CRM) team consisting of qualified professionals in geosciences, reservoir and production technology and financial evaluation. The team has an average of more than 25 years' experience in the oil and gas industry. CRM reports to the senior vice president of accounting and financial compliance in the Chief financial officer organisation and is independent of the exploration and production business areas. All the reserves estimates have been prepared by Equinor's technical staff.

Although the CRM team reviews the information centrally, each asset team is responsible for ensuring compliance with the requirements of the SEC and Equinor's corporate standards. Information about proved oil and gas reserves, standardised measures of discounted net cash flows related to proved oil and gas reserves and other information related to

proved oil and gas reserves, is collected from the local asset teams and checked by CRM for consistency and conformity with applicable standards. The final numbers for each asset are quality-controlled and approved by the responsible asset managers, before aggregation to the required reporting level by CRM.

The person with primary responsibility for overseeing the preparation of the reserves estimates is the manager of the CRM team. The person who currently holds this position has a bachelor's degree in earth sciences from the University of Gothenburg, and a master's degree in petroleum exploration and exploitation from Chalmers University of Technology in Gothenburg, Sweden. She has 37 years' experience in the oil and gas industry, 36 of them with Equinor. She is a member of the Society of Petroleum Engineering (SPE) and of the UNECE Expert Group on Resource Management (EGRM).

DeGolyer and MacNaughton report

Petroleum engineering consultants DeGolyer and MacNaughton have carried out an independent evaluation of Equinor's proved reserves as of 31 December 2022 using data provided by Equinor. The evaluation accounts for 100% of Equinor's proved reserves including equity accounted entities. The aggregated net proved reserves estimates prepared by DeGolyer and MacNaughton do not differ materially from those prepared by Equinor when compared on the basis of net equivalent barrels.

A report of third party summarising this evaluation is included as Exhibit 15.3 in the annual report on Form 20-F for 2022.

Net proved reserves

At 31 December 2022	Oil and condensate (mmboe)	NGL/LPG (mmboe)	Natural gas (mmmcf)	Oil equivalent (mmboe)
Estimated by Equinor	2,248	280	14,946	5,191
Estimated by DeGolyer and MacNaughton	2,311	289	15,252	5,318

Operational statistics

Developed and undeveloped oil and gas acreage

Total gross and net developed and undeveloped oil and gas acreage, in which Equinor had interests at 31 December 2022, are presented in the table below.

Total developed and undeveloped oil and gas acreage

	Eurasia excluding Americas
At 31 December 2022 (in thousands of acres)		Norway Norway		Africa	USA	excluding USA	Total
Developed acreage	- gross1)	903	41	846	387	259	2,437
	- net2)	370	14	267	96	63	809
Undeveloped acreage	- gross1)	11,473	1,487	6,006	1,679	22,655	43,300
	- net2)	5,117	751	1,813	656	10,018	18,355

1) A gross value reflects the acreage in which Equinor has a working interest.

2) The net value corresponds to the sum of the fractional working interests owned by Equinor in the same acreage.

Equinor's largest concentrations of net developed acreage in Norway are in the Troll, Oseberg Area, Snøhvit, Ormen Lange and Johan Sverdrup fields. In Africa, the Algerian gas development projects In Amenas and In Salah represent the largest concentrations of net developed acreage. In the USA, the Appalachian basin assets represents the largest net developed acreage.

The largest concentration of net undeveloped acreage is in Argentina, which represents 36% of Equinor's total net undeveloped acreage, followed by Norway and Canada.

At 31 December 2022, Equinor no longer holds acreage in Russia due to the exit of joint arrangements.

Equinor holds acreage in numerous concessions, blocks and leases. The terms and conditions regarding expiration dates vary significantly from property to property. Work programmes are designed to ensure that the exploration potential of any property is fully evaluated before expiration.

Acreage related to several of these concessions, blocks and leases are scheduled to expire within the next three years. Most of the undeveloped acreage

that will expire within the next three years, is related to early exploration activities where no production is expected in the foreseeable future. The expiration of these concessions, blocks and leases will therefore not have any material impact on our proved reserves. Any acreage which has already been evaluated to be non-profitable may be relinquished prior to the current expiration date. In other cases, Equinor may decide to apply for an extension if more time is needed to fully evaluate the potential of the properties. Historically, Equinor has generally been successful in obtaining such extensions.

Productive oil and gas wells

The number of gross and net productive oil and gas wells, in which Equinor had interests at 31 December 2022, are presented in the table below.

Number of productive oil and gas wells

			Eurasia excluding			Americas
At 31 December 2022 (in thousands of acres)		Norway	Norway	Africa	USA	excluding USA	Total
Oil wells	- gross1)	776	163	467	75	231	1712
	- net2)	335	37	71	24	68	536
Gas wells	- gross1)	225	6	115	2421	0	2767
	- net2)	97	2	44	469	0	613

1) A gross value reflects the number of wells in which Equinor owns a working interest.

2) The net value corresponds to the sum of the fractional working interests owned by Equinor in the same gross wells.

The gross and net number of oil wells has decreased from last year mainly due to the exit of joint arrangements in Russia and the sale of the Ekofisk Area. The gross and net number of gas wells has increased from last year mainly due to continued drilling in the Appalachian basin onshore assets in the USA.

The total gross number of productive wells at year end 2022 includes 319 oil wells and 12 gas wells with multiple completions or wells with more than one branch.

Net productive and dry oil and gas wells drilled

The following table presents the number of net productive and dry exploratory and development oil and gas wells drilled and completed or abandoned over the past three years. Productive wells include exploratory wells in which hydrocarbons were discovered, and where drilling or completion has been suspended pending further evaluation. A dry well is a well found to be incapable of producing sufficient quantities to justify completion as an oil or gas well. Dry development wells are mainly injector wells, but does also include drilled and permanently abandoned wells.

		Eurasia
Number of net productive and dry oil and gas wells drilled1)	Norway	excluding Norway	Africa	USA	Americas excluding USA	Total
Year 2022
Net productive and dry exploratory wells drilled	6.7	-	0.3	0.5	5.1	12.6
- Net dry exploratory wells	4.5	-	0.2	0.5	2.1	7.3
- Net productive exploratory wells	2.2	-	0.1	-	3.0	5.3
Net productive and dry development wells drilled	35.4	5.4	4.0	27.6	12.3	84.7
- Net dry development wells	6.4	1.8	0.9	-	0.1	9.2
- Net productive development wells	28.9	3.6	3.1	27.6	12.2	75.5
Year 2021
Net productive and dry exploratory wells drilled	7.4	0.5	-	-	0.6	8.5
- Net dry exploratory wells	4.0	0.5	-	-	0.6	5.0
- Net productive exploratory wells	3.5	-	-	-	-	3.5
Net productive and dry development wells drilled	38.8	26.6	2.0	19.7	8.5	95.6
- Net dry development wells	8.3	8.6	0.4	-	0.4	17.8
- Net productive development wells	30.5	18.0	1.5	19.7	8.1	77.8
Year 2020
Net productive and dry exploratory wells drilled	8.2	2.0	-	1.1	2.7	14.0
- Net dry exploratory wells	4.7	1.0	-	0.4	0.9	6.9
- Net productive exploratory wells	3.6	1.0	-	0.7	1.8	7.0
Net productive and dry development wells drilled	27.6	22.1	1.6	48.2	8.7	108.2
- Net dry development wells	4.0	3.9	-	-	0.7	8.6
- Net productive development wells	23.6	18.2	1.6	48.2	8.0	99.6

1) The net value corresponds to the sum of the fractional working interests owned by Equinor in the same gross wells.

Exploratory and development drilling in process

The following table presents the number of gross and net exploratory and development oil and gas wells in the process of being drilled, or drilled but not yet put on stream at 31 December 2022.

Number of wells in progress

			Eurasia excluding			Americas
At 31 December 2022		Norway Norway		Africa	USA	excluding USA	Total
Exploratory wells	- gross1)	4.0	-	-	1.0	-	5.0
	- net2)	2.2	-	-	0.3	-	2.4
Development wells	- gross1)	36.0	5.0	7.0	9.0	8.0	65.0
	- net2)	15.7	1.2	2.0	4.0	1.8	24.8

1) A gross value reflects the number of wells in which Equinor owns a working interest.

2) The net value corresponds to the sum of the fractional working interests owned by Equinor in the same gross wells.

Delivery commitments

Equinor is responsible for managing, transporting and selling the Norwegian State's oil and gas from the NCS on behalf of the Norwegian State's direct financial interest (SDFI). These reserves are sold in conjunction with Equinor's own reserves. As part of this arrangement, Equinor delivers gas to customers under various types of sales contracts. In order to meet the commitments, a field supply schedule is utilised to ensure the highest possible total value for Equinor and SDFI's joint portfolio of oil and gas.

Equinor's and SDFI's delivery commitments under bilateral agreements for the calendar years 2023, 2024, 2025 and 2026 expressed as the sum of expected gas off-take, are equal to 43.3, 26.4, 20.2 and 10.6 bcm, respectively. Delivery commitments under bilateral agreements is declining over time as our customers are increasingly requesting more and more short-term contracts and increased volumes are traded on the spot market.

Equinor's currently developed gas reserves on the NCS are more than sufficient to meet our share of these commitments for the next four years.

Any remaining volumes after covering our delivery commitments under the bilateral agreements, will be sold through trading activities at the hubs.

Entitlement production

The following tables present Equinor's Norwegian and international entitlement production of oil, condensate, NGL and natural gas for the periods indicated. The stated production volumes are the volumes to which Equinor is entitled, pursuant to conditions laid down in licence agreements and PSAs. The production volumes are net of royalty oil paid in-kind, and of gas used for fuel and flaring. Production is based on proportionate participation in fields with multiple owners and does not include production of the Norwegian State's oil and gas. NGL includes both LPG and naphtha. For further information on production volumes see section Terms and abbreviations.

	Consolidated companies				Equity accounted
		Eurasia			Americas		Eurasia	Americas
	Norway	excluding Norway	Africa	USA	excluding USA	Subtotal	excluding Norway	excluding USA	Subtotal	Total
Oil and condensate (mmboe)
2022	188	11	32	33	23	287	1	3	4	291
2021	200	15	32	37	19	303	5	2	7	310
2020	193	15	39	48	25	320	1	1	2	322
NGL (mmboe)
2022	34	0	2	8	-	45	-	-	-	45
2021	38	0	3	9	-	49	-	-	-	49
2020	40	0	3	11	-	54	-	-	-	54
Natural gas (mmmcf)
2022	1,608	23	28	346	7	2,012	0	2	3	2,015
2021	1,500	20	41	396	8	1,966	3	1	5	1,971
2020	1,425	26	42	373	9	1,874	3	1	3	1,878
Combined oil, condensate, NGL and natural gas (mmboe)
2022	508	16	40	103	24	691	1	3	5	695
2021	505	18	42	117	20	703	6	2	8	710
2020	486	20	49	126	26	708	2	1	3	710

The Troll field in Norway is the only field containing more than 15% of total proved reserves based on barrels of oil equivalent.

Troll entitlement production	2022	2021	2020
Troll field
Oil and condensate (mmboe)	7	8	9
NGL (mmboe)	2	2	2
Natural gas (mmmcf)	427	403	378
Combined oil, condensate, NGL and natural gas (mmboe)	85	82	79

Supplementary oil and gas information (unaudited)

In accordance with the US Financial Accounting Standards Board Accounting Standards Codification "Extractive Activities - Oil and Gas" (Topic 932), Equinor is reporting certain supplemental disclosures about oil and gas exploration and production operations. While this information is developed with reasonable care and disclosed in good faith, it is emphasised that some of the data is necessarily imprecise and represents only approximate amounts because of the subjective judgement involved in developing such information. Accordingly, this information may not necessarily represent the present financial condition of Equinor or its expected future results.

For further information regarding the reserves estimation requirement, see note 12 Property, plant and equipment - Estimation uncertainty regarding determining oil and gas reserves and Estimation uncertainty; Proved oil and gas reserves in the annual report on Form 20-F for 2022.

No events have occurred since 31 December 2022 that would result in a significant change in the estimated proved reserves or other figures reported as of that date.

Proved oil and gas reserves

Equinor's proved oil and gas reserves have been estimated by its qualified professionals in accordance with industry standards under the requirements of

the US Securities and Exchange Commission (SEC), Rule 4-10 of Regulation S-X. Statements of reserves are forward-looking statements. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The determination of these reserves is part of an ongoing process subject to continual revision as additional information becomes available. Estimates of proved reserve quantities are dynamic and change over time as new information becomes available. Moreover, identified reserves and contingent resources that may become proved in the future are excluded from the estimates of proved reserves.

Equinor's proved reserves are recognised under various forms of contractual agreements, including PSAs where Equinor's share of reserves can vary due to commodity prices or other factors. Reserves from agreements such as PSAs are based on the volumes to which Equinor has access (cost oil and profit oil), limited to available market access. At 31 December 2022, 5% of total proved reserves were related to such agreements, representing 10% of the oil, condensate and NGL reserves and 1% of the gas reserves. This compares with 6% and 5% of total proved reserves for 2021 and 2020, respectively. Net entitlement oil and gas production from fields with such agreements was 44 million boe during 2022, compared to 49 million boe for 2021 and 59 million boe for 2020. Equinor participates in such agreements in Algeria, Angola, Azerbaijan, Brazil, Libya and Nigeria.

Equinor is recording, as proved reserves, volumes equivalent to our tax liabilities under negotiated fiscal arrangements (PSAs) where the tax is paid on behalf

of Equinor. Reserves are net of royalty volumes in the USA and net of royalty paid in-kind in PSA fields. Proved reserves does not include quantities consumed during production.

Rule 4-10 of Regulation S-X requires that the estimation of reserves shall be based on existing economic conditions, including a 12-month average price determined as an unweighted arithmetic average of the first-of-the month price for each month within the reporting period, unless prices are defined by contractual arrangements. Volume weighted average prices for the total Equinor portfolio, and the Brent blend price, are presented in the following table:

	Volume weighted average prices at 31 December
	Brent blend (USD/boe)	Oil (USD/boe)	Condensate (USD/boe)	NGL (USD/boe)	Natural gas (USD/mmbtu)
2022	101.24	100.30	90.79	56.23	30.66
2021	69.22	67.61	65.02	47.17	11.89
2020	41.26	40.60	33.99	23.72	3.18

Higher commodity prices affected the profitable reserves to be recovered from accumulations, resulting in increased proved reserves. The positive revisions due to higher price are in general a result of later economic cut-off. For fields with a PSA the effect of higher prices is to some degree offset by reduced entitlement to the reserves. These changes are all included in the revision category, giving a net increase of Equinor's proved reserves at year end.

From the NCS, Equinor is responsible for managing, transporting and selling the Norwegian State's oil and gas on behalf of the Norwegian State's direct financial interest (SDFI). These reserves are sold in conjunction with the Equinor reserves. As part of this arrangement, Equinor delivers and sells gas to customers in accordance with various types of sales contracts on behalf of the SDFI. In order to fulfil the commitments, Equinor utilises a field supply schedule which provides the highest possible total value for the joint portfolio of oil and gas between Equinor and the SDFI.

Equinor and the SDFI receive income from the joint gas sales portfolio based upon their respective share in the supplied volumes. For sales of the SDFI gas, to Equinor and to third parties, the payment to the Norwegian State is based on achieved prices, a net back formula calculated price or market value. All of the Norwegian State's oil and NGL is acquired by Equinor. The price Equinor pays to the SDFI for the crude oil is based on market reflective prices. The prices for NGL are either based on achieved prices, market value or market reflective prices. The regulations of the owner's instruction may be changed or withdrawn by the Equinor ASA's general meeting.

Topic 932 requires the presentation of reserves and certain other supplemental oil and gas disclosures by geographic area, defined as country or continent containing 15% or more of total proved reserves. At 31 December 2022, Norway is the only country in this category, with 71% of the total proved reserves. The

USA contains close to 15% of the total proved reserves at 31 December 2022 and has been close to this level for several years. Management has therefore determined that the most meaningful presentation of geographical areas in 2022 would be Norway, the USA, and the continents of Eurasia excluding Norway, Africa, and Americas excluding USA.

Proved reserves movements

The largest relative changes in the proved reserves within a geographic area compared to the previous year for each of the last three years, are summarised below. All changes in the Net proved reserves (in million boe) table that represent 10% or more of the net proved reserves in million boe at the beginning of each year are discussed.

Proved reserves movements 2022

Eurasia excluding Norway

The net decrease of 14 million boe in revisions and improved recovery in Eurasia excluding Norway is the combined effect of mainly negative revisions based on reduced production potential, and reduced entitlement volumes resulting from higher commodity prices. Purchase of the UK part of the Statfjord field is the main reason for the increase of 15 million boe through purchases of reserves-in-place in this area. Exit from our Russian joint arrangements reduced the proved reserves in both consolidated (10 million boe) and equity accounted (76 million boe) companies and is included as a sales of reserves-in-place.

Africa

The net effect of revisions and improved recovery of 29 million boe in Africa is the combined effect of 46 million boe in positive revisions resulting from both longer economic lifetime with higher commodity prices as well as extended contract and longer technical lifetime on some fields, and negative revisions of 17 million boe related to reduced entitlement volumes with higher commodity prices.

USA

The increase of 89 million boe in extensions and discoveries in the USA is the result of new wells drilled in previously unproven areas in our onshore developments in the Appalachian basin assets.

Americas excluding USA

The increase of 9 million boe in extensions and discoveries in the Americas excluding USA is the result of new wells drilled in previously unproven areas in our onshore developments in Argentina.

Proved reserves movements 2021

Norway

The increase of 465 million boe in revisions and improved recovery in Norway was the combined effect of positive revisions following increased certainty in the ultimate recovery at many fields, prolonged economic lifetime at several fields due to higher commodity prices, and decisions to install low pressure production facilities increasing the future recovery at the Oseberg and Ormen Lange fields.

Eurasia excluding Norway

The net decrease of 16 million boe in equity accounted assets in the revisions and improved recovery category was related to proved reserves in Russia, where negative revisions of 35 million boe due to reduced production potential in some areas was partially offset by positive revisions based on increased certainty in the expected ultimate recovery in other areas.

USA

The increase of 78 million boe in revisions and improved recovery was the combined effect of positive revisions following increased certainty in the ultimate recovery, and prolonged economic lifetime at several fields mainly due to higher commodity prices. Sales of reserves-inplace of 89 million boe was a result of the divestment of our interests in the Bakken assets which was completed in 2021.

Americas excluding USA

The increase of 62 million boe in revisions and improved recovery was mainly related to proved reserves in Brazil and is the combined effect of positive revisions following increased certainty in the ultimate recovery, and prolonged economic lifetime due to higher commodity prices. The increase of 210 million boe in extensions and discoveries was the result of sanctioning of the Bacalhau development in Brazil, and the 14 million boe of equity accounted additions in the same category represent drilling of new wells in previously unproven areas at the Bandurria Sur development in Argentina.

Proved reserves movements 2020

Africa

The net increase of 40 mill boe in revision and improved recovery was mainly due to positive revisions on several fields with PSAs in Angola, Algeria, Nigeria and Libya.

USA

The net decrease of 118 million boe in revisions and improved recovery included a negative revision of 110 million boe related to our onshore developments. This was mainly due to reduced activity levels as well as shorter economic field lifetime caused by lower oil and gas prices. The lower prices have also affected some of our Gulf of Mexico fields negatively. The increase of 101 million boe in extension and discoveries was the result of new wells drilled in previously unproven areas in our onshore developments.

Americas excl USA

The net decrease of 55 million boe in revisions and improved recovery was mainly due to shorter economic lifetime for fields in Brazil caused by lower oil prices. The equity accounted increase of 6 million boe in purchases of reserves-in-place is in Argentina.

The following tables reflect the estimated oil, condensate, NGL and natural gas proved reserves at 31 December 2019 through 2022 and the changes therein.

			Consolidated companies					Equity accounted
Net proved oil and condensate reserves		Eurasia			Americas		Eurasia	Americas
(in million boe)	Norway	excluding Norway	Africa	USA	excluding USA	Subtotal	excluding Norway	excluding USA	Subtotal	Total
At 31 December 2019	1,463	168	137	383	369	2,518	56	-	56	2,575
Revisions and improved recovery	32	(12)	33	(55)	(57)	(58)	(5)	-	(5)	(63)
Extensions and discoveries	27	2	-	7	-	36	0	-	0	36
Purchases of reserves-in-place	-	-	-	-	-	-	-	5	5	5
Sales of reserves-in-place	-	-	-	-	-	-	-	-	-	-
Production	(193)	(15)	(39)	(48)	(25)	(320)	(1)	(1)	(2)	(322)
At 31 December 2020	1,329	143	131	287	287	2,177	50	5	55	2,232
Revisions and improved recovery	153	(15)	18	23	61	240	17	0	17	257
Extensions and discoveries	14	0	-	1	210	225	2	12	14	239
Purchases of reserves-in-place	-	-	-	-	-	-	-	-	-	-
Sales of reserves-in-place	-	-	-	(57)	(6)	(63)	-	-	-	(63)
Production	(200)	(15)	(32)	(37)	(19)	(303)	(5)	(2)	(7)	(310)
At 31 December 2021	1,296	114	116	217	533	2,276	64	15	79	2,355
Revisions and improved recovery	133	(15)	40	32	3	192	0	(0)	(0)	192
Extensions and discoveries	67	-	-	1	-	68	-	7	7	75
Purchases of reserves-in-place	10	5	-	-	-	15	-	-	-	15
Sales of reserves-in-place	(25)	(10)	-	-	-	(35)	(62)	-	(62)	(97)
Production	(188)	(11)	(32)	(33)	(23)	(287)	(1)	(3)	(4)	(291)
At 31 December 2022	1,292	83	123	217	513	2,228	-	19	19	2,248
Proved developed oil and condensate reserves
At 31 December 2019	691	44	124	278	254	1,392	5	-	5	1,396
At 31 December 2020	654	54	110	217	202	1,237	8	5	13	1,249
At 31 December 2021	702	47	104	161	205	1,218	22	10	31	1,249
At 31 December 2022	731	35	107	161	203	1,236	-	12	12	1,249
Proved undeveloped oil and condensate reserves
At 31 December 2019	772	123	13	104	115	1,127	52	-	52	1,178
At 31 December 2020	676	88	21	70	86	940	42	0	42	982
At 31 December 2021	594	67	13	56	328	1,058	42	5	47	1,105
At 31 December 2022	562	48	17	56	309	992	-	7	7	999

			Consolidated companies					Equity accounted
Net proved NGL reserves		Eurasia			Americas		Eurasia	Americas
(in million boe)	Norway	excluding Norway	Africa	USA	excluding USA	Subtotal	excluding Norway	excluding USA	Subtotal	Total
At 31 December 2019	254	-	18	65	-	337	-	-	-	337
Revisions and improved recovery	(7)	0	2	(8)	-	(13)	-	-	-	(13)
Extensions and discoveries	0	-	-	7	-	8	-	-	-	8
Purchases of reserves-in-place	-	-	-	-	-	-	-	-	-	-
Sales of reserves-in-place	-	-	-	-	-	-	-	-	-	-
Production	(40)	(0)	(3)	(11)	-	(54)	-	-	-	(54)
At 31 December 2020	208	0	17	53	-	278	-	-	-	278
Revisions and improved recovery	31	0	(1)	14	-	44	-	-	-	44
Extensions and discoveries	1	-	-	4	-	5	-	-	-	5
Purchases of reserves-in-place	-	-	-	-	-	-	-	-	-	-
Sales of reserves-in-place	-	-	-	(17)	-	(17)	-	-	-	(17)
Production	(38)	(0)	(3)	(9)	-	(49)	-	-	-	(49)
At 31 December 2021	202	0	14	45	-	261	-	-	-	261
Revisions and improved recovery	13	0	(3)	13	-	23	-	-	-	23
Extensions and discoveries	26	-	-	10	-	37	-	-	-	37
Purchases of reserves-in-place	4	3	-	-	-	7	-	-	-	7
Sales of reserves-in-place	(3)	-	-	-	-	(3)	-	-	-	(3)
Production	(34)	(0)	(2)	(8)	-	(45)	-	-	-	(45)
At 31 December 2022	209	3	8	60	-	280	-	-	-	280
Proved developed NGL reserves
At 31 December 2019	175	-	15	49	-	240	-	-	-	240
At 31 December 2020	141	0	15	47	-	204	-	-	-	204
At 31 December 2021	160	0	12	37	-	209	-	-	-	209
At 31 December 2022	149	3	8	51	-	210	-	-	-	210
Proved undeveloped NGL reserves
At 31 December 2019	78	-	3	16	-	97	-	-	-	97
At 31 December 2020	66	(0)	2	6	-	74	-	-	-	74
At 31 December 2021	42	-	2	8	-	52	-	-	-	52
At 31 December 2022	60	0	0	9	-	70	-	-	-	70

			Consolidated companies				Equity accounted
Net proved natural gas reserves		Eurasia			Americas			Eurasia	Americas
(in million boe)	Norway	excluding Norway	Africa	USA	excluding USA	Subtotal	Norway	excluding Norway	excluding USA	Subtotal	Total
At 31 December 2019	14,330	111	241	2,371	8	17,060	-	295	-	295	17,355
Revisions and improved recovery	(195)	(36)	29	(311)	8	(505)	-	(28)	-	(28)	(534)
Extensions and discoveries	4	-	-	485	-	488	-	-	-	-	488
Purchases of reserves-in-place	-	-	-	-	-	-	-	-	4	4	4
Sales of reserves-in-place	-	-	-	-	-	-	-	-	-	-	-
Production	(1,425)	(26)	(42)	(373)	(9)	(1,874)	-	(3)	(1)	(3)	(1,878)
At 31 December 2020	12,714	49	227	2,171	7	15,169	-	264	3	267	15,436
Revisions and improved recovery	1,576	46	(23)	231	7	1,837	-	(183)	1	(182)	1,656
Extensions and discoveries	23	-	-	313	-	337	-	-	11	11	348
Purchases of reserves-in-place	-	-	-	-	-	-	-	-	-	-	-
Sales of reserves-in-place	-	-	-	(87)	-	(87)	-	-	-	-	(87)
Production	(1,500)	(20)	(41)	(396)	(8)	(1,966)	-	(3)	(1)	(5)	(1,971)
At 31 December 2021	12,813	75	163	2,233	6	15,289	-	78	14	92	15,381
Revisions and improved recovery	720	3	(44)	23	11	713	-	0	6	6	720
Extensions and discoveries	494	-	-	434	-	928	-	-	9	9	937
Purchases of reserves-in-place	41	40	-	-	-	81	-	-	-	-	81
Sales of reserves-in-place	(79)	-	-	-	-	(79)	-	(78)	-	(78)	(157)
Production	(1,608)	(23)	(28)	(346)	(7)	(2,012)	-	(0)	(2)	(3)	(2,015)
At 31 December 2022	12,380	94	91	2,344	10	14,920	-	-	26	26	14,946
Proved developed natural gas reserves
At 31 December 2019	9,417	111	217	1,645	8	11,398	-	67	-	67	11,465
At 31 December 2020	7,863	49	199	1,681	7	9,799	-	123	3	126	9,926
At 31 December 2021	11,145	75	145	1,845	5	13,217	-	19	9	28	13,244
At 31 December 2022	10,294	89	91	1,921	8	12,403	-	-	17	17	12,420
Proved undeveloped natural gas reserves
At 31 December 2019	4,912	0	23	726	-	5,662	-	228	-	228	5,889
At 31 December 2020	4,851	0	28	490	-	5,369	-	141	0	141	5,510
At 31 December 2021	1,667	-	17	387	0	2,072	-	59	5	64	2,136
At 31 December 2022	2,087	5	-	423	2	2,517	-	-	9	9	2,526

			Consolidated companies					Equity accounted
Net proved reserves		Eurasia			Americas		Eurasia	Americas
(in million boe)	Norway	excluding Norway	Africa	USA	excluding USA	Subtotal	excluding Norway	excluding USA	Subtotal	Total
At 31 December 2019	4,270	187	198	870	370	5,895	109	-	109	6,004
Revisions and improved recovery	(9)	(18)	40	(118)	(55)	(161)	(10)	-	(10)	(171)
Extensions and discoveries	28	2	-	101	-	131	0	-	0	131
Purchases of reserves-in-place	-	-	-	-	-	-	-	6	6	6
Sales of reserves-in-place	-	-	-	-	-	-	-	-	-	-
Production	(486)	(20)	(49)	(126)	(26)	(708)	(2)	(1)	(3)	(710)
At 31 December 2020	3,802	151	189	727	289	5,158	97	5	102	5,260
Revisions and improved recovery	465	(6)	13	78	62	611	(16)	1	(15)	596
Extensions and discoveries	19	0	-	61	210	290	2	14	16	306
Purchases of reserves-in-place	-	-	-	-	-	-	-	-	-	-
Sales of reserves-in-place	-	-	-	(89)	(6)	(96)	-	-	-	(96)
Production	(505)	(18)	(42)	(117)	(20)	(703)	(6)	(2)	(8)	(710)
At 31 December 2021	3,781	127	159	660	534	5,261	77	18	95	5,356
Revisions and improved recovery	275	(14)	29	49	4	343	0	1	1	344
Extensions and discoveries	181	-	-	89	-	269	-	9	9	278
Purchases of reserves-in-place	21	15	-	-	-	36	-	-	-	36
Sales of reserves-in-place	(42)	(10)	-	-	-	(52)	(76)	-	(76)	(128)
Production	(508)	(16)	(40)	(103)	(24)	(691)	(1)	(3)	(5)	(695)
At 31 December 2022	3,708	103	148	694	514	5,167	-	24	24	5,191
Proved developed reserves
At 31 December 2019	2,544	64	178	621	255	3,663	17	-	17	3,679
At 31 December 2020	2,196	63	161	564	203	3,187	30	5	35	3,222
At 31 December 2021	2,847	60	141	527	206	3,782	25	12	36	3,818
At 31 December 2022	2,714	53	131	554	205	3,656	-	16	16	3,672
Proved undeveloped reserves
At 31 December 2019	1,725	123	20	250	115	2,233	92	-	92	2,325
At 31 December 2020	1,606	88	28	163	86	1,971	67	0	67	2,038
At 31 December 2021	934	67	18	133	328	1,479	53	6	59	1,538
At 31 December 2022	994	50	17	140	310	1,510	-	9	9	1,519

The conversion rates used in this table are 1 standard cubic meter = 35.3 standard cubic feet, 1 standard cubic meter oil equivalent = 6.29 barrels of oil equivalent (boe) and 1,000 standard cubic meter gas = 1 standard cubic meter oil equivalent.

Standardised measure of discounted future net cash flows relating to proved oil and gas reserves

The table below shows the standardised measure of future net cash flows relating to proved reserves. The analysis is computed in accordance with Topic 932, by applying average market prices as defined by the SEC, year end costs, year end statutory tax rates and a discount factor of 10% to year end quantities of net proved reserves. The standardised measure of discounted future net cash flows is a forward-looking statement.

Future price changes are limited to those provided by existing contractual arrangements at the

end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year end estimated proved reserves based on year end cost indices, assuming continuation of year end economic conditions. Pre-tax future net cash flow is net of decommissioning and removal costs. Estimated future income taxes are calculated by applying the appropriate year end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pre-tax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using a discount rate of 10% per year. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced. The standardised measure of discounted future net cash flows prescribed under Topic 932 requires assumptions as to the timing and amount of future development and production costs and income from the production of proved reserves. The information does not represent management's estimate or Equinor's expected future cash flows or the value of its proved reserves and therefore should not be relied upon as an indication of Equinor's future cash flow or value of its proved reserves.

		Eurasia
At 31 December 2022		excluding			Americas
(in USD million)	Norway	Norway	Africa	USA	excluding USA	Total
Consolidated companies
Future net cash inflows	620,024	11,225	13,955	35,382	50,744	731,330
Future development costs	(15,595)	(1,795)	(1,012)	(1,388)	(3,830)	(23,620)
Future production costs	(60,837)	(4,356)	(3,706)	(8,736)	(19,807)	(97,442)
Future income tax expenses	(449,351)	(1,725)	(3,864)	(5,402)	(5,122)	(465,465)
Future net cash flows	94,241	3,348	5,374	19,855	21,984	144,803
10% annual discount for estimated timing of cash flows	(36,714)	(954)	(1,275)	(7,124)	(10,633)	(56,701)
Standardised measure of discounted future net cash flows	57,527	2,394	4,099	12,731	11,351	88,102
Equity accounted investments
Standardised measure of discounted future net cash flows	-	-	-	-	316	316
Total standardised measure of discounted future net cash flows including equity accounted investments	57,527	2,394	4,099	12,731	11,667	88,418

		Eurasia
At 31 December 2021		excluding	Americas
(in USD million)	Norway	Norway	Africa	USA	excluding USA	Total
Consolidated companies
Future net cash inflows	287,382	8,705	9,619	21,486	35,236	362,429
Future development costs	(10,999)	(1,947)	(685)	(1,112)	(4,186)	(18,928)
Future production costs	(53,251)	(4,196)	(3,380)	(7,269)	(16,782)	(84,878)
Future income tax expenses	(178,370)	(352)	(2,138)	(2,686)	(2,979)	(186,525)
Future net cash flows	44,763	2,209	3,416	10,420	11,289	72,097
10% annual discount for estimated timing of cash flows	(18,051)	(652)	(707)	(3,406)	(5,842)	(28,658)
Standardised measure of discounted future net cash flows	26,711	1,557	2,709	7,014	5,447	43,439
Equity accounted investments
Standardised measure of discounted future net cash flows	-	224	-	-	126	350
Total standardised measure of discounted future net cash flows including equity accounted investments	26,711	1,782	2,709	7,014	5,573	43,789

	Eurasia
At 31 December 2020 (in USD million)	Norway	excluding Norway	Africa	USA	Americas excluding USA	Total
Consolidated companies
Future net cash inflows	107,618	6,610	7,234	14,892	10,685	147,039
Future development costs	(11,209)	(2,489)	(682)	(1,351)	(1,534)	(17,265)
Future production costs	(42,410)	(3,622)	(3,170)	(8,020)	(7,568)	(64,790)
Future income tax expenses	(35,236)	(209)	(1,262)	(965)	(336)	(38,008)
Future net cash flows	18,763	290	2,119	4,556	1,248	26,976
10% annual discount for estimated timing of cash flows	(6,937)	(80)	(505)	(1,269)	24	(8,768)
Standardised measure of discounted future net cash flows	11,826	210	1,614	3,286	1,272	18,209
Equity accounted investments
Standardised measure of discounted future net cash flows	-	(32)	-	-	22	(10)
Total standardised measure of discounted future net cash flows including equity accounted investments	11,826	178	1,614	3,286	1,294	18,199

Changes in the standardised measure of discounted future net cash flows from proved reserves

(in USD million)	2022	2021	2020
Consolidated companies
Standardised measure at 1 January	43,439	18,209	35,173
Net change in sales and transfer prices and in production (lifting) costs related to future production	231,555	126,974	(52,527)
Changes in estimated future development costs	(4,739)	(5,915)	(1,547)
Sales and transfers of oil and gas produced during the period, net of production cost	(91,580)	(43,998)	(15,180)
Net change due to extensions, discoveries, and improved recovery	15,928	7,734	265
Net change due to purchases and sales of minerals in place	386	(2,280)	-
Net change due to revisions in quantity estimates	34,325	17,080	3,263
Previously estimated development costs incurred during the period	6,691	6,619	6,558
Accretion of discount	15,063	4,078	9,087
Net change in income taxes	(162,965)	(85,062)	33,117
Total change in the standardised measure during the year	44,663	25,230	(16,965)
Standardised measure at 31 December	88,102	43,439	18,209
Equity accounted investments
Standardised measure at 31 December	316	350	(10)
Standardised measure at 31 December including equity accounted investments	88,418	43,789	18,199

In this table each line item presents the sources of changes in the standardised measure of value on a discounted basis, with the accretion of discount line item reflecting the increase in the net discounted value of the proved oil and gas reserves due to the fact that the future cash flows are now one year closer in time.

The standardised measure at the beginning of the year represents the discounted net present value after deductions of both future development costs, production costs and taxes. The line item Net change in sales and transfer prices and in production (lifting) costs related to future production is, on the other hand, related to the future net cash flows at 31 December 2021. The proved reserves at 31 December 2021 were multiplied by the actual change in price, and change in unit of production costs, to arrive at the net effect of changes in price and production costs. Development costs and taxes are reflected in the line items Change in estimated future development costs and Net change in income taxes and are not included in the Net change in sales and transfer prices and in production (lifting) costs related to future production.

Terms and abbreviations

Organisational abbreviations

• ACG Azeri-Chirag-Gunashli
• CAPEX Capital expenditure
• IOR Improved oil recovery
• LPG Liquefied petroleum gas
• NCS Norwegian continental shelf
• NGL Natural gas liquids
• OECD Organisation of Economic Co-Operation and Development
• PDO Plan for development and operation
• PSA Production sharing agreement
• SDFI Norwegian State's Direct Financial Interest
• SEC US Securities and Exchange Commission
• UKCS UK continental shelf
• USA United States of America
• USD United States dollar

Measurement abbreviations etc.

• one billion one thousand million
• bbl barrel
• mmbbl million barrels
• boe barrels of oil equivalent
• mmboe million barrels of oil equivalent
• cf cubic feet
• mmmcf billion cubic feet
• MMBtu million british thermal units
• bcm billion cubic metres of natural gas

Equivalent measurements are based upon

• 1 barrel equals 0.134 tonnes of oil (33 degrees API)
• 1 barrel equals 0.159 standard cubic metres
• 1 barrel of oil equivalent equals 1 barrel of crude oil
• 1 barrel of oil equivalent equals 159 standard cubic metres of natural gas
• 1 barrel of oil equivalent equals 5,612 cubic feet of natural gas
• 1 barrel of oil equivalent equals 0.0837 tonnes of NGLs
• 1 billion standard cubic metres of natural gas equals 1 million standard cubic metres of oil equivalent
• 1 cubic metre equals 35.3 cubic feet
• 1 cubic metre of natural gas equals 1 standard cubic metre of natural gas
• 1,000 standard cubic meter gas equals 1 standard cubic meter oil equivalent
• 1,000 standard cubic metres of natural gas equals 6.29 boe
• 1 standard cubic foot equals 0.0283 standard cubic metres
• 1 standard cubic foot equals 1000 British thermal units (btu)
• 1 tonne of NGLs equals 1.9 standard cubic metres of oil equivalent

Miscellaneous terms

• Appraisal well: A well drilled to establish the extent and the size of a discovery.
• BOE (barrels of oil equivalent): A measure to quantify crude oil, natural gas liquids and natural gas amounts using the same basis. Natural gas volumes are converted to barrels on the basis of energy content.
• Condensates: The heavier natural gas components, such as pentane, hexane, iceptane and so forth, which are liquid under atmospheric pressure – also called natural gasoline or naphtha.
• Development: The drilling, construction, and related activities following discovery that are necessary to begin production of crude oil and natural gas fields.
• Equity and entitlement volumes of oil and gas: Equity volumes represent volumes produced under a production sharing agreement (PSA) that correspond to Equinor's percentage ownership in a particular field. Entitlement volumes, on the other hand, represent Equinor's share of the volumes distributed to the partners in the field, which are subject to deductions for, among other things, royalties and the host government's share of profit oil. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. The distinction between equity and entitlement is relevant to most PSA regimes, whereas it is not applicable in most concessionary regimes such as those in Norway, the United Kingdom, Canada and Brazil. The overview of equity production provides additional information for readers, as certain costs described in the profit and loss analysis were directly associated with equity volumes produced during the reported years.
• IOR (improved oil recovery): Actual measures resulting in an increased oil recovery factor from a reservoir as compared with the expected value at a certain reference point in time. IOR comprises both of conventional and emerging technologies.
• Liquids: Refers to oil, condensates and NGL.
• LPG (liquefied petroleum gas): Consists primarily of propane and butane, which turn liquid under a pressure of six to seven atmospheres. LPG is shipped in special vessels.
• Natural gas: Petroleum that consists principally of light hydrocarbons. It can be divided into 1) lean gas, primarily methane but often containing some ethane and smaller quantities of heavier hydrocarbons (also called sales gas) and 2) wet gas, primarily ethane, propane and butane as well as smaller amounts of heavier hydrocarbons; partially liquid under atmospheric pressure.
• NGL (natural gas liquids): Light hydrocarbons mainly consisting of ethane, propane and butane which are liquid under pressure at normal temperature.
• Petroleum: A collective term for hydrocarbons, whether solid, liquid or gaseous. Hydrocarbons are compounds formed from the elements hydrogen (H) and carbon (C). The proportion of different compounds, from methane and ethane up to the heaviest components, in a petroleum find varies from discovery to discovery. If a reservoir primarily contains light hydrocarbons, it is described as a gas field. If heavier hydrocarbons predominate, it is described as an oil field. An oil field may feature free gas above the oil and contain a quantity of light hydrocarbons, also called associated gas.
• Proved reserves: Reserves claimed to have a reasonable certainty (normally at least 90% confidence) of being recoverable under existing economic and political conditions and using existing technology. They are the only type the US Securities and Exchange Commission allows oil companies to report.