DNO ASA

Management Reports • Apr 3, 2025

DNO ASA 2024 report Annual Statement of Reserves and Resources

Annual Statement of Reserves and Resources 2024

Contents

1 Introduction
2 Overview
2.1 Net reserves, resources and production
2.2 Kurdistan region of Iraq
2.3 North Sea
2.4 West Africa
2.5 Yemen
3 Management discussion and analysis
3.1 Disclaimer
3.2 Assumptions and methodology
3.3 Oil and gas prices
3.4 Ownership
4 Annex

*Million barrels of oil equivalent

1 Introduction

DNO ASA is a Norwegian oil and gas operator active in the Middle East, the North Sea and West Africa. Founded in 1971 and listed on the Oslo Stock Exchange, the Company holds stakes in onshore and offshore licenses at various stages of exploration, development and production in the Kurdistan region of Iraq, Norway, the United Kingdom, Côte d'Ivoire, Netherlands and Yemen.

The Company's Annual Statement of Reserves and Resources (ASRR) has been prepared in accordance with the Oslo Stock Exchange listing and disclosure requirements Circular No. 1/2013. International petroleum consultants DeGolyer and MacNaughton (D&M) carried out an independent assessment of the Tawke license (containing the Tawke and Peshkabir fields) and the Baeshiqa license (containing the Baeshiqa and Zartik structures) in the Kurdistan region of Iraq (Kurdistan). International petroleum consultants RPS Energy Consultants (RPS) carried out an independent assessment of DNO reserves and resources in Norway and the United Kingdom (UK). In Norway, contingent resources also include volumes that are classified as RC7F (production not evaluated) as reported by the Norwegian Offshore Directorate (NOD). In 2023, the international petroleum consultants Beicip-Franlab carried out an independent assessment of DNO's CI-27 license (held through its indirect 33.33 percent interest in the operating entity) in Côte d'Ivoire. For the P2543 license (Agar) in the UK and Block 47 in Yemen, DNO's contingent resources are internally assessed. The Dutch acreage held by DNO does not hold any reserves or resources.

2 Overview

Volumes classified as reserves are those quantities of oil and gas anticipated to be commercially recovered from known accumulations from a given date to the end of the field life and within the license period. Contingent resources are those quantities of oil and gas estimated on a given date to be potentially recoverable from known accumulations, but not currently considered to be commercially recoverable or where a field development plan has not yet been submitted. In the attached Annex, Table 1 shows a summary of remaining proven (1P), proven and probable (2P) and proven, probable and possible (3P) reserves on net and Net Entitlement (NE) basis at yearend 2024. Table 2 shows changes in net reserves between yearend 2023 and yearend 2024. Table 3 shows a summary of remaining contingent (2C) resources on a gross and net basis at yearend 2024.

2.1 Net reserves, resources and production

At yearend 2024, DNO's net 1P reserves stood at 178.9 million barrels of oil equivalent (MMboe), compared to 206.4 MMboe at yearend 2023, after adjusting for production during the year and changes due to acquisitions and divestments, reclassifications and technical revisions. On a 2P basis, DNO's net reserves stood at 281.9 MMboe, compared to 290.1 MMboe at yearend 2023. On a 3P basis, DNO's net reserves were 340.1 MMboe, compared to 360.5 MMboe at yearend 2023. DNO's net contingent (2C) resources were 213.4 MMboe, up from 205.0 MMboe at yearend 2023 after adjusting for new discoveries, volumes moved to reserves and technical revisions.

Table 2 of the annex details the most important factors impacting year-on-year development in reserves. While net production of 28.3 MMboe during 2024 drew on DNO's reserves, the impact was partially offset by acquisitions, volumes moved up from contingent resources, as well as technical revisions. Notably, DNO's 2024 acquisitions of stakes in the Arran field offshore UK and Norne area assets in Norway added a total of 4.9 MMboe in net 1P reserves, 7.8 MMboe in net 2P reserves and 11.4 MMboe in net 3P reserves (after allowing for divestment of Ringhorne East, used as part of the consideration for the Norne area assets). Volumes moved from contingent resources to reserves all relate to the 2024 sanctioning of the Bestla field development in Norway, which added 2.9 MMboe to 1P reserves, 7.6 MMboe to 2P reserves and 14.4 MMboe to 3P reserves, all on a net basis.

DNO's net production in 2024 was 28.3 MMboe of which 21.6 million barrels (MMbbls) of oil were in Kurdistan, 4.8 MMboe in Norway, 0.8 MMboe in the UK and 1.1 MMboe in Côte d'Ivoire. Net production in 2023 was 19.2 MMboe of which 12.7 MMbbls were in Kurdistan, 5.1 MMboe in Norway, 1.3 MMboe in Côte d'Ivoire and the balance in the UK.

The Company's net 2024 yearend Reserve Life Index (R/P) stood at 6.3 years on a 1P reserves basis, 10.0 years on a 2P reserves basis and 12.0 years on a 3P reserves basis.

2.2 Kurdistan region of Iraq

In mid-2024, DNO celebrated the 20th anniversary of the signing of its first production sharing contracts in the Kurdistan region of Iraq. The DNO-operated Tawke license, containing the Tawke and Peshkabir oil fields, continues to be a core asset for DNO and, importantly, for Kurdistan. At the end of 2024, there were 70 producing wells on the license.

Both the Tawke field (discovered in 2006) and Peshkabir field (discovered in 2012) are characterized by complex structural geology. While the Tawke field predominantly features the Cretaceous Bekhme and Qamchuqa formations, with some contributions from the younger Tertiary Jeribe formation, hydrocarbons from the Peshkabir field reside in the Cretaceous Shiranish and also Qamchuqa formations. All these formations are characterized as naturally fractured carbonate reservoirs containing medium gravity crude.

Gross production from the Tawke license averaged 78,615 barrels of oil per day (bopd) during 2024 (46,276 bopd in 2023). The Tawke field contributed 29,153 bopd (26,577 bopd in 2023) and the Peshkabir field contributed 49,462 bopd (19,699 bopd in 2023). Gross Tawke license production was up 70 percent year-on-year as output was held steady in 2024 following the disruptions caused by the closure of the Iraq-Türkiye Pipeline (ITP) export route in 2023.

DNO sold its oil at its Fish Khabur terminal as the ITP remained shut. Maintaining strict capital spending discipline, DNO drilled no new wells on the Tawke license in 2024. Notwithstanding, output was kept at a high level by bringing three previously drilled wells onstream, by workovers and interventions on more than 20 other wells across the license, and by gas injection into the Tawke field.

DNO holds a 75 percent operated interest in the Tawke license with partner Genel Energy International Limited holding the remaining 25 percent.

On DNO's other Kurdistan license, Baeshiqa, gross operated production averaged 5 bopd (224 bopd in 2023). The 2024 production resulted from well testing programs conducted in the fourth quarter of the year. Based on the test results, DNO took a partial impairment on the asset and is currently minimizing running costs while determining its future work program.

DNO holds a 64 percent operated interest in the Baeshiqa license (80 percent paying interest) with partners including the Turkish Energy Company Limited (TEC) with a 16 percent interest (20 percent paying interest) and the Kurdistan Regional Government (KRG) with a 20 percent carried interest.

On a net basis at yearend 2024, 1P reserves in the Company's Kurdistan portfolio totaled 142.8 MMbbls (175.1 MMbbls at yearend 2023), 2P reserves totaled 224.8 MMbbls (244.5 MMbbls at yearend 2023) and 3P reserves totaled 257.9 MMbbls (298.0 MMbbls at yearend 2023). Net 2C resources were 59.5 MMbbls, identical to the yearend 2023 level.

The Company's Kurdistan reserves relate entirely to the Tawke license. Out of the net 2C contingent resources in the Kurdistan portfolio, the Baeshiqa license represented 38.1 MMbbls (39.1 MMbbls at yearend 2023).

2.3 North Sea

Since re-entering the North Sea in 2017, DNO has been one of the most active explorers on the Norwegian Continental Shelf. Targeting organic growth, the Company made 13 discoveries in Norway from 2020 through 2024.

In 2024, DNO had diversified production across 15 fields in the North Sea of which 12 were in Norway and three in the UK. In 2024, DNO took steps to expand its North Sea business by acquiring a 25 percent interest in the producing Arran field in the UK and interests in four producing fields and one development asset in the Norne area offshore Norway. With contributions from the new assets coming in at the end of the year, North Sea net production increased to an average of 15,201 boepd (14,203 boepd in 2023). Of the total, 13,057 boepd were attributable to Norway and 2,144 to the UK (13,926 boepd and 277 boepd, respectively, in 2023).

Meanwhile, DNO is taking part in four ongoing North Sea field development projects expected to come online between 2025 and 2028 that represent proven and probable reserves of 26.2 MMboe net to the Company. These are Andvare (32 percent), Bestla (39.2 percent), Verdande (10.5 percent) and Berling (30 percent). In addition, DNO continued to mature other discoveries towards project sanction.

DNO drilled three exploration wells in the North Sea in 2024, namely Othello (50 percent and operator), Cuvette (20 percent) and Ringand (20 percent). All three were discoveries. The play-opening Othello light oil discovery was Norway's second largest find in 2024, significantly derisking nearby prospects in DNO's exploration portfolio. In addition, DNO drilled two combined exploration and appraisal wells in 2024 to assess the resource potential surrounding the 2023 Heisenberg discovery (spanning two licenses in which DNO holds 49 and 20 percent, respectively). While Heisenberg was successfully delineated, the additional exploration targets (Hummer and Angel) did not deliver the desired results.

At yearend 2024, DNO held 85 licenses in Norway in various stages of exploration, development and production (73 licenses at yearend 2023). Across its Norway portfolio and on a net basis, DNO's 1P reserves totaled 27.7 MMboe, 2P reserves stood at 44.9 MMboe, 3P reserves totaled 66.0 MMboe and 2C resources stood at 144.0 MMboe. The comparable yearend 2023 figures were 1P reserves of 23.7 MMboe, 2P reserves of 34.8 MMboe, 3P reserves of 49.0 MMboe and 2C resources of 132.0 MMboe. In 2024, reserves in Norway increased with the sanctioning of the Bestla field development and the acquisition of Norne area assets.

In the UK, DNO held seven licenses at yearend 2024 (four licenses at yearend 2023). On a net basis, 1P reserves totaled 1.9 MMboe, 2P reserves stood at 2.8 MMboe, 3P reserves totaled 4.1 MMboe and 2C resources of 22.1 MMboe at yearend 2024. The comparable yearend 2023 figures were 1P reserves of 0.1 MMboe, 2P reserves of 0.3 MMboe, 3P reserves of 0.4 MMboe and no 2C resources, all on a net basis. The increase in reserves and resources was due to both the acquisition of the Arran field and the inclusion of the license containing the Agar discovery, the latter formally allocated to DNO in February 2024.

2.4 West Africa

Through a one-third stake in the operating company, Foxtrot International, DNO holds a nine percent interest in Côte d'Ivoire's Block CI-27. The block includes four fields producing over 75 percent of Côte d'Ivoire's domestic gas supply. Formerly, Foxtrot International also operated the CI-12 exploration block, from which it withdrew in October 2024 after having fulfilled the exploration obligations pertaining to the license.

In West Africa, DNO held yearend 2024 1P reserves of 6.4 MMboe, 2P reserves of 9.4 MMboe, 3P reserves of 12.0 MMboe and 2C resources of 5 MMboe. The comparable yearend 2023 figures were 1P reserves of 7.6 MMboe, 2P reserves of 10.5 MMboe, 3P reserves of 13.2 MMboe and 2C resources of 8.6 MMboe, all on a net basis.

2.5 Yemen

Production start-up at the Yaalen field at Block 47 in Yemen, currently under force majeure, remains on hold. At yearend 2024, 2C resources at Block 47 stood at 4.8 MMbbls on a net basis, unchanged from yearend 2023.

3 Management discussion and analysis

3.1 Disclaimer

The report, including this Management Discussion and Analysis (MD&A), contains and was prepared, inter alia, on the basis of forward-looking information and statements. Such information and statements are based on management's current assumptions, expectations, estimates and projections and are therefore subject to risks and uncertainties that could cause actual results, performance or events to differ materially. The Company can give no assurance that those assumptions, expectations, estimates and projections will occur or be realized and readers should not place undue reliance on forward-looking statements. Forward-looking statements are generally identifiable by their use of terms such as "expect", "believe", "estimate", "may", "plan", "could", "will", "intend", "schedule" and similar terms or expressions. There are a number of factors that could cause actual results or events to differ materially from those underlying forward-looking information and statements. These factors include, among others: technical, geological and geotechnical conditions; economic and market conditions in or affecting the geographic areas and industries that are or will be major markets for DNO; oil and gas price fluctuations; market acceptance of new products and services; changes in laws and governmental regulations; political risks, including the risks of expropriation and renegotiation of the terms of contracts with governmental entities; delays or advancements in the approval of projects and delays in the reimbursement for shared costs; the risk of doing business in developing countries and countries subject to national or international sanctions; fluctuations in interest rates or currency exchange rates; and other such factors that may be discussed from time to time in the MD&A. All forward-looking statements contained in the report, including this MD&A, are expressly qualified in their entirety by the cautionary statements contained in this disclaimer. Additionally, DNO makes no representation or warranty, expressed or implied, as to the accuracy, reliability or completeness of these forward-looking statements and the MD&A, and neither DNO nor any of its directors, officers or employees will have any liability to the readers resulting from reliance on these forwardlooking statements and this MD&A.

3.2 Assumptions and methodology

DNO's reserves updates are completed in accordance with standard guidelines advised by the Society of Petroleum Engineers (SPE)1,2, and comply with Oslo Stock Exchange disclosure requirements, Circular No. 1/2013.

Reported reserves fall within classes 1-3 of the NOD's classification and 2C resources fall within classes 4-7.

The estimation and auditing of reserves are undertaken in accordance with generally accepted engineering and evaluation principles. It should be noted that reserves information is imprecise due to inherent uncertainties in – and the limited nature of – data upon which the reserves are predicated.

DNO has a reserves review committee consisting of competent professional geoscientists, engineers and economists to facilitate the review and reporting process and ensure compliance with standards and procedures. The committee collects and coordinates the review of all technical data and provides a full report of the Company's reserves and resources to the Managing Director for review and approval.

Economically recoverable reserves have been calculated based on input for the technical reserves and economic parameters such as license terms and projected future oil and gas prices. The reserves reported here are restricted to those volumes expected to be economically recovered prior to the expiry date of the respective licenses.

3.3 Oil and gas prices

D&M, RPS and Beicip-Franlab generate and utilize oil and gas price forecasts as the basis for their independent calculations of remaining DNO reserves.

3.4 Ownership

DNO's participation in certain licenses is governed by a Production Sharing Contract (PSC), which sets out the manner in which oil and gas production is shared between the government and the license holder. DNO and its joint venture partners typically bear all risks and costs of exploration, development and production in these licenses. In return, if exploration is successful, DNO and its partners recover their share of investments and operating costs from what is referred to as "cost oil", being a percentage of oil and gas produced and sold after deduction of the government royalty (if any). In addition to cost oil, DNO and its partners are entitled to receive a share of the remaining production, after payment of the royalty (if any) and deduction of cost oil, which results into what is referred to as "profit oil". Profit oil is shared

¹ For a full description of these guidelines and definitions, see www.spe.org

² https://www.spe.org/en/industry/petroleum-resources-management-system-2018/

among the government, DNO and its partners in accordance with the percentages set out in each PSC.

DNO's net entitlement (NE) reserves in the licenses governed by a PSC comprise the Company's entitlement to cost oil and profit oil multiplied by its participating interest. NE reserves are based on economic evaluation of the license agreements, incorporating projections of future production, costs and oil and gas prices. NE volumes may therefore fluctuate over time, even though there are no changes in the underlying gross and net volumes.

At yearend 2024, all of the Company's interests in licenses in Kurdistan, Côte d'Ivoire and Yemen were governed by PSCs. Net reserves in these licenses reflect DNO's share before government take while NE reserves reflect DNO's share after government take.

Net and NE reserves in DNO's licenses not governed by PSCs (Norway and the UK) are equivalent and reflect gross reserves multiplied by the Company's participating interest.

Chris Spencer Managing Director Oslo, 2 April 2025

4 Annex

	Proven (1P)				Proven + Probable (2P)		Proven + Probable + Possible (3P)
Asset (Region, Field)	Gross	Net	NE	Gross	Net	NE	Gross	Net	NE
	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe
Developed Assets
Kurdistan, Tawke	54.6	40.9	14.4	91.9	68.9	21.3	95.9	71.9	20.9
Kurdistan, Peshkabir	61.2	45.9	16.2	117.3	88.0	27.2	138.9	104.2	30.3
Kurdistan Developed	115.8	86.9	30.6	209.2	156.9	48.4	234.8	176.1	51.2
Norway, Alve	13.6	4.3	4.3	14.6	4.7	4.7	15.7	5.0	5.0
Norway, Brage	5.8	0.8	0.8	11.2	1.6	1.6	16.3	2.3	2.3
Norway, Enoch	0.1	0.0	0.0	0.2	0.0	0.0	0.2	0.0	0.0
Norway, Fenja	14.4	1.1	1.1	24.4	1.8	1.8	35.6	2.7	2.7
Norway, Marulk	1.5	0.5	0.5	3.2	1.2	1.2	5.3	2.0	2.0
Norway, Norne	5.2	0.4	0.4	7.7	0.5	0.5	11.2	0.8	0.8
Norway, Oda	2.7	0.4	0.4	3.6	0.5	0.5	4.5	0.7	0.7
Norway, Skuld	4.2	0.5	0.5	5.1	0.6	0.6	6.4	0.7	0.7
Norway, Tambar	1.0	0.5	0.5	3.2	1.4	1.4	4.7	2.1	2.1
Norway, Trym	2.3	1.1	1.1	2.9	1.5	1.5	3.7	1.8	1.8
Norway, Ula	2.7	0.5	0.5	4.7	0.9	0.9	6.8	1.4	1.4
Norway, Urd	3.7	0.4	0.4	5.7	0.7	0.7	8.0	0.9	0.9
Norway, Vilje	2.1	0.6	0.6	4.3	1.3	1.3	9.3	2.7	2.7
Norway Developed	59.2	11.2	11.2	90.8	16.7	16.7	127.6	23.1	23.1
UK, Arran	6.7	1.7	1.7	9.6	2.4	2.4	14.4	3.6	3.6
UK, Blane	0.6	0.3	0.3	0.8	0.4	0.4	1.2	0.5	0.5
UK Developed	7.2	1.9	1.9	10.4	2.8	2.8	15.5	4.1	4.1
Côte d'Ivoire, CI-27 (1)	70.6	6.4	4.2	103.1	9.4	6.3	132.4	12.0	7.8
West Africa Developed	70.6	6.4	4.2	103.1	9.4	6.3	132.4	12.0	7.8
Total Developed (1)		106.4	48.0		185.7	74.2		215.3	86.2
		Proven (1P)		Proven + Probable (2P)		Proven + Probable + Possible (3P)
Asset (Region, Field)	Gross	Net	NE	Gross	Net	NE	Gross	Net	NE
	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)
Under Development Assets
Kurdistan, Tawke	67.6	50.7	17.9	77.6	58.2	18.0	93.5	70.2	20.4
Kurdistan, Peshkabir	7.0	5.3	1.9	13.1	9.8	3.0	15.5	11.6	3.4
Kurdistan Under Development	74.6	56.0	19.7	90.7	68.0	21.0	109.1	81.8	23.8
Norway, Andvare	ರಿ.6	3.1	3.1	14.0	4.5	4.5	20.0	6.4	6.4
Norway, Berling	24.5	7.3	7.3	35.3	10.6	10.6	47.2	14.2	14.2
Norway, Bestla	7.3	2.9	2.9	19.3	7.6	7.6	36.7	14.4	14.4
Norway, Verdande	19.8	2.1	2.1	34.1	3.6	3.6	48.8	5.1	5.1
Norway, Tambar East	2.9	1.1	1.1	5.2	2.0	2.0	7.5	2.8	2.8
Norway Under Development	64.1	16.5	16.5	108.0	28.2	28.2	160.2	43.0	43.0
Total Under Development		72.4	36.2		96.2	49.2		124.7	66.7
DNO ASA		178.9	84.2		281.9	123.4		340.1	152.9

Table 1: Remaining reserves at yearend 2024 (Net and NE)

Table 2: Reserves development 2023-2024 (Net)

	Developed Assets			Under Development			TOTAL
DNO ASA	1P	2P	3P	1P	2P	3P	1P	2P	3P
	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)	(MMboe)
Balance as of yearend 2023	155.3	204.7	256.5	51.2	85.4	104.0	206.4	290.1	360 5
Production	-28.3	-28.3	-28.3				-28.3	-28.3	-28.3
Acquisitions	3.9	5.4	7.7	2.1	3.6	5.1	5.9	9.0	12.8
Divestments	-1.0	-1.2	-1.4				-1.0	-1.2	-1.4
Extentions and discoveries
New developments				2.9	7.6	14.4	2.9	7.6	14.4
Revision of previous estimates	-23.4	5.1	-19.2	16.3	-0.4	1.2	-7.1	4.7	-18.0
Balance as of yearend 2024	106.4	185.7	215.3	72.4	96.2	124.7	178.9	281.9	340.1

Table 3: Remaining 2C resources at yearend 2024 (Net)

	2C Resources
Asset	Net
	(MMboe)
Kurdistan	59.5 HERRESHIPBA ERREINDER BRENDING & BROUNDER & AERSIDER
Tawke PSC	215
Baeshiga PSC	38.1
Norway	121.9
UK	22.1
Yemen	4.8
Côte d'Ivoire	5.0
OTAL DNO ASA	213.4