Equinor

Annual Report • Mar 21, 2024

Oil and gas reserves report

Contents

• Introduction
• Proved oil and gas reserves
• Preparation of reserves estimates
• Operational statistics
• Delivery commitments
• Entitlement production
• Supplementary oil and gas information (unaudited)
• Expected oil and gas reserves
• Terms and abbreviations

| Equinor 2023 Oil and gas reserves report

Introduction

About the report

This report presents Equinor`s proved oil and gas reserves as of 31 December 2023. 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).

With the exclusion of the section of this report titled "Expected oil and gas reserves", numbers have been prepared in accordance with the definitions of reserves to be used in filings with the US Securities and Exchange Commission (SEC) contained in Rule 4-10(a) (1)-(32) of the SEC's Regulation S-X. All numbers are internal estimates produced by Equinor. Estimates of reserves may change over time as further production history and additional information becomes available. The determination of these reserves estimates 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 section titled "Expected oil and gas reserves" presents information on reserves prepared according to The Norwegian Offshore Directorate's resource classification system 2016 and is explicitly excluded from any filings we make with the SEC.

Operational performance

Proved oil and gas reserves

Proved oil and gas reserves were estimated to be 5,2141 million boe at year end 2023, compared to 5,191 million boe at the end of 2022.

Proved reserves

(in million boe)

Proved developed 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 continue to affect proved reserves estimates in the future.

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

Changes in product 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 category in the tables that follow 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 SEC. The geographical areas are defined by country and continent. In 2023 these are Norway, Eurasia excluding Norway, Africa, the USA and the Americas excluding USA.

In Norway and other countries where there is a reasonable 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 assets 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 83% of Equinor's proved reserves are located in countries that are members of the Organisation of Economic Co-Operation and Development (OECD). 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, Libya and Nigeria. Other proved non-OECD reserves are related to concession fields in Brazil and Argentina, representing together 12% of Equinor's total proved reserves.

Distribution of proved reserves

1) Volumes related to the planned exit from Azerbaijan are included in the proved oil and gas reserves at year end 2023.

1) Volumes related to the planned exit from Azerbaijan are included in the proved oil and gas reserves at year end 2023.

Changes in proved reserves

The total volume of proved reserves increased by 23 million boe in 2023.

Changes in proved reserves

		For the year ended 31 December
(in million boe)	2023	2022	2021
Revisions and improved recovery	232	344	596
Extensions and discoveries	507	278	306
Purchases of reserves-in-place	31	36	-
Sales of reserves-in-place	(35)	(128)	(96)
Total reserve additions	734	530	806
Production	(711)	(695)	(710)
Net changes in proved reserves	23	(165)	96

Changes in proved reserves

Revisions and improved recovery

Revisions of previously booked reserves, including the effect of improved recovery, increased the proved reserves by net 232 million boe in 2023. The increase is the result of 366 million boe in positive revisions and increased recovery, partially offset by 135 million boe in negative revisions. Many producing assets 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. Increased entitlement volumes from several fields with PSAs added to the positive revisions. The negative revisions were mainly related to unforeseen events and operational challenges resulting in reduced production potential on some assets. The negative revisions also included a direct effect of lower commodity prices, decreasing the proved reserves by approximately 17 million boe through decreased economic lifetime on several assets.

Extensions and discoveries

A total of 507 million boe of new proved reserves were added through extensions and discoveries. The Raia field in Brazil, the Rosebank field in the United Kingdom (UK) and the Sparta field in the USA are the main contributors in this category and are included in the proved reserves for the first time this year. In addition, this category includes extension of the proved area through continuous drilling of new wells in previously undrilled areas in the Appalachian basin assets in the USA and in Argentina.

Purchases and sales of reserves-in-place

A total of 31 million boe of proved reserves were added through the purchase of Suncor Energy UK Limited in 2023 which included a working interest in the producing Buzzard field.

A total of 35 million boe of sales of reserves-in-place in

2023 are related to the sale of a 28% working interest in the Statfjord area on the Norwegian continental shelf (NCS) and the sale of our interests in the Corrib field in Ireland.

In the fourth quarter of 2023, Equinor entered into an agreement to divest our interests in the Azeri-Chirag-Gunashli (ACG) field in Azerbaijan. Closing is subject to regulatory and contractual approvals and is expected to take place in mid 2024. The sale will result in an estimated reduction in proved reserves of approximately 45 million boe.

Production

The 2023 entitlement production was 711 million boe, compared to 695 million boe in 2022. The increase was mainly due to ramp up to plateau production at the Johan Sverdrup field in Norway and the Peregrino field in Brazil.

Development of reserves

In 2023, 325 million boe were matured from proved undeveloped to proved developed reserves mainly due to continued drilling in major offshore assets, Johan Sverdrup being the largest contributor, and in the Appalachian basin in the USA. The production start of Vito in the USA in addition to Breidablikk and Bauge in Norway added to the maturation of proved undeveloped reserves. The positive revision and improved recovery of proved undeveloped reserves of 90 million boe is related to large offshore fields in Norway such as the Oseberg area, Visund, Johan Sverdrup and Snorre due to continued high activity level and planned future infill wells. Finally, 475 million boe was added to proved undeveloped reserves through extensions and discoveries. The largest additions in this category are related to the sanctions of Raia in Brazil, Rosebank in the UK and Sparta in the USA, in addition to further development in the Appalachian basin.

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 was 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 were 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 were 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.

Equinor has matured 2,123 million boe of proved undeveloped reserves to proved developed reserves over the last five years.

Development of proved reserves		2023			2022			2021
(in million boe)	Total proved reserves	Developed	Undeveloped	Total proved reserves	Developed	Undeveloped	Total proved reserves	Developed	Undeveloped
At 1 January	5,191	3,672	1,519	5,356	3,818	1,538	5,260	3,222	2,038
Revisions and improved recovery	232	141	90	344	322	22	596	471	125
Extensions and discoveries	507	31	475	278	22	256	306	37	269
Purchases of reserves-in-place	31	31	1	36	29	7	-	-	-
Sales of reserves-in-place	(35)	(30)	(5)	(128)	(66)	(62)	(96)	(83)	(13)
Production	(711)	(711)	-	(695)	(695)	-	(710)	(710)	-
Moved from undeveloped to developed	-	325	(325)	-	241	(241)	-	881	(881)
At 31 December	5,214	3,459	1,755	5,191	3,672	1,519	5,356	3,818	1,538

Proved developed and undeveloped reserves

At 31 December 2023	Oil and condensate (mmboe)	NGL (mmboe)	Natural gas (mmmcf)	Total oil and gas (mmboe)
Developed
Norway	720	124	9,131	2,470
Eurasia excluding Norway	57	1	16	61
Africa	107	7	70	126
USA	201	51	1,859	583
Americas excluding USA	211	-	42	219
Total proved developed reserves	1,296	182	11,118	3,459
Undeveloped
Norway	426	57	2,175	871
Eurasia excluding Norway	156	2	55	168
Africa	16	1	4	18
USA	79	10	408	162
Americas excluding USA	410	-	710	537
Total proved undeveloped reserves	1,089	69	3,353	1,755
Total proved reserves	2,384	251	14,471	5,214

Reserves replacement ratio

	For the year ended 31 December
	2023	2022	2021
Annual	103%	76%	113%
Three-year average	98%	62%	61%

As of 31 December 2023, the total proved undeveloped reserves amounted to 1,755 million boe, close to 50% of which are related to fields in Norway. The Oseberg area, Snøhvit and Johan Sverdrup fields, which have continuous development activities, together with fields not yet in production, such as Johan Castberg, Munin and Ormen Lange Phase 3, have the largest proved undeveloped reserves in Norway. The largest assets with proved undeveloped reserves outside Norway, are Raia, Bacalhau, Peregrino and Roncador in Brazil, Rosebank and Mariner in the UK, Sparta and the Appalachian basin in the USA, and ACG in Azerbaijan. All these assets are either currently in the production phase or will start production within the next five years.

For assets 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, that would require a separate future investment decision by management, included in our proved reserves estimates. Some offshore development activities will take place more than five years from the disclosure date on many assets, 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 the 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, but the start-up is delayed to the fourth quarter of 2024.

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

In 2023, Equinor incurred USD 8.1 billion in development costs relating to assets carrying proved reserves, of which USD 6.7 billion was related to proved undeveloped reserves.

Reserves replacement

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

The 2023 reserves replacement ratio was 103% and the corresponding three-year average was 98%, compared to 76% and 62% respectively at the end of 2022.

The organic reserves replacement ratio, excluding sales and purchases, was 104% in 2023 compared to 89% in 2022. The organic three-year average replacement ratio was 107% at the end of 2023 compared to 70% at the end of 2022.

Proved reserves by region

Proved reserves in Norway

A total of 3,341 million boe was recognised as proved reserves on the NCS, representing 64% of Equinor's total proved reserves at year end 2023. Of these, 2,923 million boe are related to fields and field areas currently in production, 95% 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 241 million boe in 2023. Negative revisions totalled 85 million boe and were mainly related to reduced well performance as well as operational challenges on some fields, and lower commodity prices. A total of 25 million boe of sales of reserves-in-place are related to the sale of a 28% working interest in the Statfjord area.

Of total proved reserves on the NCS, 2,470 million boe (74%) are proved developed reserves at year end 2023. Of the total proved reserves in this region, 60% are gas reserves mainly related to large fields such as Troll, the Oseberg area, Snøhvit, Ormen Lange, Visund, Tyrihans and Aasta Hansteen, and 40% are liquid reserves mainly related to large fields such as Johan Sverdrup, Johan Castberg, Snorre, the Oseberg area, the Gullfaks area and Munin.

Proved reserves - Norway

Proved reserves in Eurasia excluding Norway

A total of 229 million boe was recognised as proved reserves in the UK and Azerbaijan1 at year end 2023. Eurasia excluding Norway represents 4% of Equinor's total proved reserves. All fields in this region except for Rosebank are in the production phase at year end. The sanctioning of the Rosebank field in 2023 added a total of 117 million boe in the extensions and discoveries category. A total of 31 million boe of new proved reserves were added through the purchase of Suncor Energy UK Limited in 2023 which included a working interest in the producing Buzzard field. The sale of our interest in the Corrib field in Ireland in 2023 resulted in a reduction of proved reserves of 11 million boe.

Of total proved reserves in Eurasia excluding Norway, 61 million boe (27%) are proved developed reserves at year end 2023. Of the total proved reserves in this region, 94% are liquid reserves mainly related to larger fields such as Rosebank, ACG and Mariner, and 6% are gas reserves mainly related to the Rosebank field and the UK part of the Statfjord field.

Proved reserves - Eurasia excluding Norway

(in million boe)

Proved reserves in Africa

A total of 144 million boe was recognised as proved reserves in PSAs in Angola, Algeria, Libya and Nigeria at year end 2023. Angola and Algeria are the primary contributors to the proved reserves in this region. Africa represents 3% of Equinor's total proved reserves. All fields in this region are currently producing. Net positive revisions increased the proved reserves by 34 million boe in 2023, mainly related to positive reservoir performance and new wells. Lower commodity prices increased the proved reserves in Africa by 9 million boe due to increased entitlement to produced volumes.

Of total proved reserves in Africa, 126 million boe (88%) are proved developed reserves at year end 2023. Of the total proved reserves in this region, 91% are liquid reserves mainly related to large oil fields such as CLOV, Agbami and In Amenas, and 9% are gas reserves related to the In Salah field.

Proved reserves - Africa

(in million boe)

Proved developed reserves Proved undeveloped reserves

1) Volumes related to the planned exit from Azerbaijan are included in the proved oil and gas reserves at year end 2023.

Proved developed reserves Proved undeveloped reserves

Proved reserves in the USA

A total of 745 million boe was recognised as proved reserves related to both onshore and offshore assets in the USA at year end 2023. The USA represents 14% of Equinor's total proved reserves. All assets in this region except for Sparta are in the production phase at year end. Most of the onshore and offshore assets in the USA are mature assets and on decline. New wells extending the proved areas in the USA onshore assets and the sanctioning of the Sparta field in 2023, added a total of 147 million boe in the extensions and discoveries category. The revisions and improved recovery category increased the proved reserves by net 18 million boe. Better performance on some fields in the Gulf of Mexico area increased the proved reserves by 62 million boe, while reduced activity level on some onshore assets in the USA reduced the proved reserves by 44 million boe.

Of total proved reserves in the USA, 583 million boe (78%) are proved developed reserves at year end 2023. Of the total proved reserves in this region, 54% are gas reserves mainly related to the Appalachian basin, and 46% are liquid reserves mainly related to the offshore fields Sparta, Caesar-Tonga and St. Malo in addition to the Appalachian basin.

Proved reserves - USA

(in million boe)

Proved undeveloped reserves

Proved reserves in the Americas excluding USA

A total of 756 million boe was recognised as proved reserves in the Americas excluding USA at year end 2023. Four fields are located offshore Brazil, two fields offshore Canada and one field onshore in Argentina. The Americas excluding USA represents 14% of Equinor's total proved reserves. All fields in this region except for Bacalhau and Raia are in the production phase at year end. The sanctioning of the Raia field in 2023, added a total of 215 million boe in the extensions and discoveries category.

Of total proved reserves in the Americas excluding USA, 219 million boe (29%) are proved developed reserves at year end 2023. Of the total proved reserves in this region, 82% are liquid reserves mainly related to large oil fields such as Bacalhau, Peregrino, Raia and Roncador, and 18% are gas reserves mainly related to the Raia field.

Proved reserves - Americas excluding USA (in 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 26 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 38 years' experience in the oil and gas industry, 37 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 2023 using data provided by Equinor. The evaluation accounts for 100% of Equinor's proved reserves. 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 2023.

Net proved reserves

At 31 December 2023	Oil and condensate (mmboe)	NGL/LPG (mmboe)	Natural gas (mmmcf)		Oil equivalent (mmboe)
Estimated by Equinor	2,384	251	14,471	5,214
Estimated by DeGolyer and MacNaughton	2,447	280	15,105	5,418

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 2023, are presented in the table below.

Total developed and undeveloped oil and gas acreage

			Eurasia excluding			Americas
At 31 December 2023 (in thousands of acres)		Norway	Norway	Africa	USA	excluding USA	Total
Developed acreage	- gross1)	913	45	847	404	259	2,468
	- net2)	367	14	267	100	63	811
Undeveloped acreage	- gross1)	9,694	1,555	7,154	1,647	22,223	42,274
	- net2)	4,609	813	2,372	676	9,919	18,389

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 represent the largest net developed acreage.

The largest concentration of net undeveloped acreage is in Argentina, which represents 35% of Equinor's total net undeveloped acreage, followed by Norway and Canada.

Equinor holds acreage in numerous concessions, blocks and leases. The terms and conditions regarding expiration dates vary significantly from property to property. Work programs 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 2023, are presented in the table below.

Number of productive oil and gas wells

			Eurasia excluding	Americas
At 31 December 2023		Norway Norway		Africa	USA	excluding USA	Total
Oil wells	- gross1)	784	201	482	78	266	1,811
	- net2)	312	47	74	25	80	538
Gas wells	- gross1)	240	0	119	2,572	0	2,931
	- net2)	105	0	46	493	0	644

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 increased from last year mainly due to the purchase of Suncor Energy UK Limited which included a working interest in the producing Buzzard field and continued drilling in Argentina. 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 2023 includes 324 oil wells and 13 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 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 2023
Net productive and dry exploratory wells drilled	10.0	-	-	1.4	2.0	13.5
- Net dry exploratory wells	4.4	-	-	0.9	-	5.3
- Net productive exploratory wells	5.7	-	-	0.5	2.0	8.1
Net productive and dry development wells drilled	34.8	4.7	5.6	25.3	13.7	84.1
- Net dry development wells	1.1	1.4	0.5	0.6	1.7	5.2
- Net productive development wells	33.6	3.3	5.1	24.8	12.0	78.9
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

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 2023.

Number of wells in progress

			Eurasia excluding	Americas
At 31 December 2023		Norway Norway		Africa	USA excluding USA		Total
Exploratory wells	- gross1)	3.0	-	-	1.0	1.0	5.0
	- net2)	1.3	-	-	0.5	0.4	2.1
Development wells	- gross1)	27.0	10.0	10.0	47.0	45.0	139.0
	- net2)	11.2	3.4	2.6	4.3	13.8	35.3

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 2024, 2025, 2026 and 2027 expressed as the sum of expected gas off-take, are equal to 50.6, 39.5, 26.8 and 18.7 bcm, respectively.

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 assets with multiple owners and does not include production of the Norwegian State's oil and gas. NGL includes both LPG and naphtha. From 2023 all our assets are classified as consolidated companies. 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)
2023	202	15	32	40	39	327	-	-	-	327
2022	188	11	32	33	23	287	1	3	4	291
2021	200	15	32	37	19	303	5	2	7	310
NGL (mmboe)
2023	29	0	2	10	-	42	-	-	-	42
2022	34	0	2	8	-	45	-	-	-	45
2021	38	0	3	9	-	49	-	-	-	49
Natural gas (mmmcf)
2023	1,515	5	32	357	11	1,920	-	-	-	1,920
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
Sum of oil, condensate, NGL and natural gas (mmboe)
2023	501	16	40	114	41	711	-	-	-	711
2022	508	16	40	103	24	691	1	3	5	695
2021	505	18	42	117	20	703	6	2	8	710

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

		For the year ended 31 December
Troll entitlement production	2023	2022	2021
Troll field
Oil and condensate (mmboe)	4	7	8
NGL (mmboe)	2	2	2
Natural gas (mmmcf)	399	427	403
Sum of oil, condensate, NGL and natural gas (mmboe)	78	85	82

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 2023.

There have been no incidents since 31 December 2023, which would cause a significant change in the estimated proved reserves or any other numbers presented in this report.

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 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 proved reserves is part of an ongoing process subject to continual revision as additional information becomes available. Estimates of proved reserves 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 estimated 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 2023, 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 5% and 6% of total proved reserves for 2022 and 2021, respectively. Net entitlement oil and gas production from fields with such agreements was 44 million boe during 2023, compared to 44 million boe for 2022 and 49 million boe for 2021. 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. The estimated proved reserves do 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:

Lower commodity prices affected the profitable reserves to be recovered from accumulations, resulting in decreased proved reserves. The negative revisions due to lower prices are in general a result of earlier economic cut-off. For PSA fields the effect of lower prices is to some degree offset by increased entitlement to the reserves. These changes are all included in the revision category, resulting in a net decrease of Equinor's estimated 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 SDFI. These volumes 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.

Volume weighted average prices At 31 December	Brent blend (USD/boe)	Oil (USD/boe)	Condensate (USD/boe)	NGL (USD/boe)	Natural gas (USD/mmbtu)
2023	83.27	80.86	72.70	40.27	11.02
2022	101.24	100.30	90.79	56.23	30.66
2021	69.22	67.61	65.02	47.17	11.89

Topic 932 requires the presentation of reserves and certain other supplemental oil and gas disclosures to be by geographic area, defined as country or continent containing 15% or more of total proved reserves. At 31 December 2023, Norway is the only country in this category, with 64% of the total estimated proved reserves. The USA contains close to 15% of the total proved reserves at 31 December 2023 and has been close to this level for several years. Management has therefore determined that the most meaningful presentation of geographical areas in 2023 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 shown in the table Net proved reserves (in million boe) that represent 10% or more of the net estimated proved reserves in million boe at the beginning of each year are discussed.

Proved reserves movements 2023

Eurasia excluding Norway

The increase of 117 million boe in extensions and discoveries in Eurasia excluding Norway is the result of the sanctioning of the Rosebank field in the UK. Purchase of reserves-in-place of 31 million boe is the result of the purchase of Suncor Energy UK Limited which included a working interest in the producing Buzzard field. Sale of reserves-in-place of 11 million boe is the result of the sale of our share in the Corrib field in Ireland.

Africa

The increase of 34 million boe in the revisions and increased recovery category is the sum of several smaller positive revisions on most fields in this area, mainly related to positive reservoir performance and new planned wells. Lower commodity prices also resulted in an increase of 9 million boe through increased entitlement volumes, which is included in this category.

USA

The increase of 147 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 and sanctioning of the Sparta field in the Gulf of Mexico.

Americas excluding USA

The increase of 239 million boe in extensions and discoveries in the Americas excluding USA is mainly the result of the sanctioning of the Raia discovery offshore Brazil. This category also includes some additions through drilling of new wells in previously unproven areas in our onshore developments in Argentina and in the Roncador field in Brazil. From 2023 all our equity accounted assets in this region have been reclassified to consolidated companies. This reclassification is presented as a negative revision of 24 million boe of reserves in the equity accounted assets, and as a positive revision of 24 million boe of reserves in the consolidated companies.

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 sale 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.

The following tables present the estimated oil, condensate, NGL and natural gas proved reserves at 31 December 2020 through 2023 and the changes therein. From 2023 all our assets are classified as consolidated companies.

			Consolidated companies			Equity accounted
Net proved oil and condensate reserves		Eurasia			Americas		Eurasia	Americas
(in million boe)	Norway	excluding Norway1)	Africa	USA	excluding USA	Subtotal	excluding Norway	excluding USA	Subtotal	Total
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
Revisions and improved recovery2)	67	7	30	52	33	190	-	(19)	(19)	170
Extensions and discoveries	0	106	1	51	114	273	-	-	-	273
Purchases of reserves-in-place	-	31	-	-	-	31	-	-	-	31
Sales of reserves-in-place	(12)	-	-	-	-	(12)	-	-	-	(12)
Production	(202)	(15)	(32)	(40)	(39)	(327)	-	-	-	(327)
At 31 December 2023	1,146	213	123	280	622	2,384	-	-	-	2,384
Proved developed oil and condensate reserves
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
At 31 December 2023	720	57	107	201	211	1,296	-	-	-	1,296
Proved undeveloped oil and condensate reserves
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
At 31 December 2023	426	156	16	79	410	1,089	-	-	-	1,089

1) Volumes related to the planned exit from Azerbaijan are included in the proved oil and gas reserves at year end 2023. 2) From 2023 all our equity accounted assets have been reclassified to consolidated companies.

			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 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
Revisions and improved recovery	4	(1)	1	(1)	-	3	-	-	-	3
Extensions and discoveries	1	2	-	12	-	15	-	-	-	15
Purchases of reserves-in-place	-	-	-	-	-	-	-	-	-	-
Sales of reserves-in-place	(4)	-	-	-	-	(4)	-	-	-	(4)
Production	(29)	(0)	(2)	(10)	-	(42)	-	-	-	(42)
At 31 December 2023	180	3	7	61	-	251	-	-	-	251
Proved developed NGL reserves
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
At 31 December 2023	124	1	7	51	-	182	-	-	-	182
Proved undeveloped NGL reserves
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
At 31 December 2023	57	2	1	10	-	69	-	-	-	69

			Consolidated companies				Equity accounted
Net proved natural gas reserves		Eurasia			Americas			Eurasia	Americas
(in billion cf)	Norway	excluding Norway	Africa	USA	excluding USA	Subtotal	Norway	excluding Norway	excluding USA	Subtotal	Total
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
Revisions and improved recovery1) Extensions and discoveries	480 11	(11) 52	16 -	(185) 465	53 700	353 1,228	- -	- -	(26) -	(26) -	327 1,228
Purchases of reserves-in-place	-	-	-	-	-	-	-	-	-	-	-
Sales of reserves-in-place	(51)	(59)	-	-	-	(110)	-	-	-	-	(110)
Production	(1,515)	(5)	(32)	(357)	(11)	(1,920)	-	-	-	-
											(1,920)
At 31 December 2023	11,306	72	74	2,267	752	14,471	-	-	-	-	14,471
Proved developed natural gas reserves
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
At 31 December 2023	9,131	16	70	1,859	42	11,118	-	-	-	-	11,118
Proved undeveloped natural gas reserves
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
At 31 December 2023	2,175	55	4	408	710	3,353	-	-	-	-	3,353

1) From 2023 all our equity accounted assets have been reclassified to consolidated companies.

			Consolidated companies					Equity accounted
Net proved reserves		Eurasia			Americas		Eurasia	Americas
(in million boe)	Norway	excluding Norway1) Africa USA excluding USA		Subtotal	excluding Norway	excluding USA	Subtotal	Total
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
Revisions and improved recovery2)	157	4	34	18	43	256	-	(24)	(24)	232
Extensions and discoveries	3	117	1	147	239	507	-	-	-	507
Purchases of reserves-in-place	-	31	-	-	-	31	-	-	-	31
Sales of reserves-in-place Production	(25) (501)	(11) (16)	- (40)	- (114)	- (41)	(35) (711)	- -	- -	- -	(35)
										(711)
At 31 December 2023	3,341	229	144	745	756	5,214	-	-	-	5,214
Proved developed reserves
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
At 31 December 2023	2,470	61	126	583	219	3,459	-	-	-	3,459
Proved undeveloped reserves
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
At 31 December 2023	871	168	18	162	537	1,755	-	-	-	1,755

1) Volumes related to the planned exit from Azerbaijan are included in the proved oil and gas reserves at year end 2023.

2) From 2023 all our equity accounted assets have been reclassified to consolidated companies.

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 2023		excluding			Americas
(in USD million)	Norway	Norway1)	Africa	USA	excluding USA	Total
Consolidated companies
Future net cash inflows	261,852	18,468	11,062	27,256	55,255	373,892
Future development costs	(14,383)	(4,297)	(807)	(3,460)	(6,556)	(29,502)
Future production costs	(52,468)	(8,217)	(3,304)	(9,521)	(23,769)	(97,279)
Future income tax expenses	(161,063)	(2,254)	(2,625)	(2,537)	(6,875)	(175,352)
Future net cash flows	33,938	3,701	4,327	11,738	18,055	71,759
10% annual discount for estimated timing of cash flows	(12,395)	(2,230)	(1,047)	(4,296)	(9,710)	(29,677)
Standardised measure of discounted future net cash flows	21,543	1,471	3,280	7,443	8,346	42,082
Equity accounted investments2)
Standardised measure of discounted future net cash flows	-	-	-	-	-	-
Total standardised measure of discounted future net cash flows including equity accounted investments	21,543	1,471	3,280	7,443	8,346	42,082

1) Volumes related to the planned exit from Azerbaijan are included in the proved oil and gas reserves at year end 2023. 2) From 2023 all our equity accounted assets have been reclassified to consolidated companies.

		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 (in USD million)	Norway	excluding Norway	Africa	USA	Americas 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

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

(in USD million)	2023	2022	2021
Consolidated companies
Standardised measure at 1 January	88,418	43,439	18,209
Net change in sales and transfer prices and in production (lifting) costs related to future production	(224,133)	231,555	126,974
Changes in estimated future development costs	(4,940)	(4,739)	(5,915)
Sales and transfers of oil and gas produced during the period, net of production cost	(43,225)	(91,580)	(43,998)
Net change due to extensions, discoveries, and improved recovery	3,794	15,928	7,734
Net change due to purchases and sales of minerals in place	710	386	(2,280)
Net change due to revisions in quantity estimates	11,706	34,325	17,080
Previously estimated development costs incurred during the period	8,101	6,691	6,619
Accretion of discount	35,905	15,063	4,078
Net change in income taxes	165,746	(162,965)	(85,062)
Total change in the standardised measure during the year	(46,336)	44,663	25,230
Standardised measure at 31 December	42,082	88,102	43,439
Equity accounted investments1)
Standardised measure at 31 December	-	316	350
Standardised measure at 31 December including equity accounted investments2)	42,082	88,418	43,789

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. From 2023 all our assets are classified as consolidated companies.

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 2022. The proved reserves at 31 December 2022 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.

1) From 2023 all our equity accounted assets have been reclassified to consolidated companies.

2) Volumes related to the planned exit from Azerbaijan are included in the proved oil and gas reserves at year end 2023.

Expected oil and gas reserves

This section presents an overview of Equinor's expected oil and gas reserves as of 31 December 2023. Equinor's expected reserves are the result of internal work processes and requirements that follow established industry standards. The definition of expected oil and gas reserves differs from the proved reserves as defined by the SEC. Equinor`s expected reserves are estimated quantities of future production in which future increases and decreases are just as likely, while the proved reserves are lower volume estimates which are much more likely to increase or remain constant than to decrease with time. The expected reserves estimates are economic to produce based on Equinor's internal economic planning assumptions where product prices vary with time, while our proved reserves estimates are based on average first-day-ofmonth prices for the reporting year, applied flat for all future years, in accordance with the reserves definitions of Rule 4-10(a) (1)-(32) of Regulations S-X of the SEC.

Proved reserves are presented as entitlement volumes, while the expected reserves are presented as equity volumes in line with how production is reported on Equinor. com and how our expected reserves estimates in Norway are reported to the Norwegian government through the annual Revised National Budget reporting.

Equinor classifies both reserves and resources according to The Norwegian Offshore Directorate's resource classification system 2016. This classification system is comparable to the Petroleum Resources Management System issued by the Society of Petroleum Engineers and others. According to the Norwegian classification system, reserves comprise the remaining, recoverable, marketable petroleum resources which the licensees have decided to develop and for which the authorities have approved a PDO or have granted exemption from the PDO requirement. Reserves also comprise petroleum resources which the licensees have decided to develop but for which the authorities have not yet approved a PDO or granted a PDO exemption.

The volumes presented in the following table are the sum of expected future production from 1 January 2024, from sanctioned projects and producing assets, that fulfil these requirements. Expected reserves are further divided into three resource sub-classes; Producing (RC1), Approved for production (RC2) and Decided for production (RC3).

Expected oil and gas reserves were estimated to be 8,935 million boe at year end 2023, whereof 5,632 million boe were in assets in resource sub-class RC1.

Classification of reserves and resources according to the Norwegian Offshore Directorate.

Expected reserves (in million boe)						For the year ended 31 December
	2023				2022
	Oil and condensate	NGL	Dry gas	Total oil equivalent	Oil and condensate			Total oil equivalent	Oil and condensate	2021 NGL	Dry gas	Total oil equivalent
						NGL	Dry gas
RC1
Norway	1,304	196	2,143	3,642	1,431	231	2,593	4,255	1,439	270	2,850	4,560
North Sea	1,173	115	1,691	2,980	1,283	142	1,861	3,285	1,260	172	2,031	3,463
Norwegian Sea	97	75	384	557	85	68	416	569	108	75	479	663
Barents Sea	33	6	67	106	64	21	316	401	71	23	340	434
Eurasia excluding Norway1)	172	2	6	180	135	4	25	165	362	-	37	400
Africa	265	10	26	302	263	13	38	314	226	15	48	290
USA	515	85	489	1,088	419	85	446	949	437	80	545	1,062
Americas excluding USA	409	-	10	419	429	-	6	435	299	-	4	303
Total RC 1	2,666	292	2,674	5,632	2,677	332	3,108	6,118	2,764	366	3,485	6,615
RC2-3
Norway	493	92	713	1,299	590	89	511	1,190	705	43	251	999
North Sea	144	35	221	400	227	37	213	477	379	12	110	501
Norwegian Sea	48	36	246	331	82	52	285	419	45	31	141	217
Barents Sea	301	21	246	568	281	0	13	294	281	-	-	281
Eurasia excluding Norway1)	293	4	22	319	102	0	0	102	25	-	-	25
Africa	38	1	-	39	66	-	-	66	45	-	-	45
USA	154	54	432	640	113	58	489	660	110	48	420	579
Americas excluding USA	719	-	287	1,006	508	-	7	515	657	-	7	664
Total RC2-3	1,696	151	1,454	3,302	1,379	147	1,007	2,533	1,542	92	678	2,312
Total expected reserves	4,362	444	4,128	8,935	4,056	480	4,115	8,651	4,305	457	4,164	8,926

1) Volumes related to the planned exit from Azerbaijan are included in the expected oil and gas reserves at year end 2023.

Terms and abbreviations

Organisational abbreviations

• ACG Azeri-Chirag-Gunashli
• CLOV Cravo, Lirio, Orquidea and Violeta
• 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
• UK United Kingdom
• USA United States of America
• USD United States dollar

Measurement abbreviations etc.

• 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
• one billion one thousand million

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.
• Barrels of oil equivalent (boe): 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, heptane 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 assets.
• 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: 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.

Additional terms used in connection with expected oil and gas reserves (excluded from filings with the SEC)

• Expected reserves: Expected or mean/best values of remaining, recoverable, marketable petroleum resources which the licensees have decided to develop.

Equinor ASA

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Box 8500 NO-4035 Stavanger Norway Telephone: +47 51 99 00 00 www.equinor.com

29 | Equinor 2023 Oil and gas reserves report