DNO ASA — Interim / Quarterly Report 2023

Nov 9, 2023

Key figures

USD million	Q3 2023	Quarters Q2 2023	Q3 2022	First nine months 2023 2022		Full-Year 2022
Key financials
Revenues	141.0	58.3	338.9	468.2	1,038.9	1,377.0
EBITDAX	78.2	11.7	274.4	296.4	871.7	1,116.0
EBITDA	71.8	-4.8	249.0	266.9	792.8	1,019.5
Operating profit/-loss	40.3	-15.0	190.7	180.7	507.7	431.4
Net profit/-loss	-54.5	-18.5	129.6	14.4	342.4	384.9
Free cash flow	-5.7	-144.2	150.8	-115.1	469.0	618.8
Operational spend	119.4	142.8	191.5	418.2	548.3	741.4
Net cash/- debt	141.9	176.8	251.7	141.9	251.7	388.2
Lifting costs (USD/boe)	13.0	45.5	6.3	12.4	6.0	6.5
Key operational data
Gross operated production (boepd)	25,984	65	109,054	40,004	107,575	107,637
Net production (boepd)*	37,150	14,417	95,698	46,797	93,406	97,310
Sales volume (boepd)	25,646	9,654	36,348	24,571	37,659	38,444

* Net production full-year 2022 includes West Africa segment (equity accounted investment), effective from 1 January 2022.

For more information about key figures, see the section on alternative performance measures.

Q3 2023 highlights

• Third quarter revenue of USD 141 million, up 142 percent from the previous quarter, on higher sales of oil and gas across the portfolio
• Operating profit stood at USD 40 million, reversing a loss of USD 15 million in the second quarter
• Net loss of USD 55 million was mainly driven by an accounting adjustment of USD 45 million in the book value of the KRG arrears
• During the quarter, DNO received USD 27 million in decommissioning tax refunds in the United Kingdom
• Also during the quarter, the Company paid a dividend of NOK 0.25 per share (totaling USD 23.0 million)
• The balance sheet remains strong with an equity ratio of 48 percent as the Company exited the quarter with cash deposits of USD 708 million and net cash of USD 142 million
• Net quarterly production totaled 37,200 barrels of oil equivalent per day (boepd), up 158 percent, with Kurdistan

contributing 19,500 boepd, North Sea 14,300 boepd and West Africa the balance

• Following closure of the Iraq-Türkiye Pipeline last March, the Company has gradually resumed operations at the Tawke and Peshkabir fields and stepped up deliveries to local trading companies in Kurdistan
• Higher production in the North Sea in Q3 2023 as thirdparty facilities conducted maintenance in the previous quarter
• West Africa production five percent lower than previous quarter as gas demand was negatively impacted by higher electricity generation from hydropower during rainy season
• North Sea exploration success continued with playopening gas condensate discovery at the DNO-operated Norma well (30 percent interest)
• Also in the North Sea, a concept selection (DG2) approved for Brasse (39.28 percent interest) as tie-back to the Brage platform ahead of expected investment decision early 2024

Operational review

Gross operated production (Thousand bopd)

Net production (Thousand boepd)

Gross production from the Company's operated licenses in Kurdistan averaged 25,984 barrels of oil per day (bopd) during the third quarter, up from 65 bopd in the previous quarter. Following closure of the Iraq-Türkiye Pipeline last March, DNO restarted production from its operated Tawke field on 18 July, with gross production from the field totaling 26,000 barrels of oil per day (bopd) during the third quarter.

Net production during the third quarter stood at 37,150 barrels of oil equivalent per day (boepd), up from 14,417 boepd in the previous quarter. In Kurdistan, net production averaged 19,488 bopd, up from 41 bopd in the previous quarter and North Sea averaged 14,288 boepd, up from 10,844 boepd in the previous quarter. In addition, the Company's West Africa gas asset offshore Côte d'Ivoire averaged 3,373 boepd, down from 3,532 boepd in the previous quarter. The increase in net production in the current quarter was mainly driven by restart of production from the Tawke field, increased production from the Alve/Marulk fields as uptime at third-party facilities resumed after shutdown parts of the previous quarter, full quarter production from the Fenja field which came on stream in April and increase in production from the Brage field driven by the Taliskar East well which came on stream in May.

Net entitlement (NE) production averaged 24,185 boepd during the third quarter, up from 11,438 boepd in the previous quarter.

Sales volume averaged 25,646 boepd during the third quarter, up from 9,654 boepd in the previous quarter. The increase in sales volume was driven by stepped up deliveries to local trading companies in Kurdistan and higher North Sea sales related to crude oil lifting at the Vilje field, higher crude oil liftings from the Ula area and increased gas sales from Alve/Marulk fields. The net underlift position was 0.31 million barrels of oil equivalent (MMboe) as of end-Q3 (Q2 2023: 0.47 MMboe).

Gross operated production

	Quarters			First nine months	Full-Year
boepd	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Kurdistan	25,984	65	109,054	40,004	107,575	107,637
North Sea	-	-	-	-	-	-
Total	25,984	65	109,054	40,004	107,575	107,637

Table above shows gross operated production from the Group's operated licenses.

Net production

	Quarters			First nine months	Full-Year
boepd	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Kurdistan	19,488	41	81,728	29,970	80,652	80,669
North Sea	14,288	10,844	13,970	13,301	12,754	13,314
Sub-total	33,777	10,885	95,698	43,271	93,406	93,983
West Africa	3,373	3,532	-	3,526	-	3,327
Sub-total	3,373	3,532	-	3,526	-	3,327
Total	37,150	14,417	95,698	46,797	93,406	97,310

Net production is based on DNO's percentage ownership in the licenses. West Africa segment is equity accounted (see Note 8).

Net entitlement (NE) production

	Quarters			First nine months	Full-Year
boepd	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Kurdistan	9,897	598	24,779	11,015	26,039	25,933
North Sea	14,288	10,841	13,970	13,301	12,754	13,314
Total	24,185	11,438	38,749	24,316	38,793	39,247

NE production from the North Sea equals the segment's net production.

Sales volume

	Quarters			First nine months	Full-Year
boepd	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Kurdistan	9,897	598	24,779	11,015	26,039	25,933
North Sea	15,749	9,056	11,569	13,556	11,621	12,511
Total	25,646	9,654	36,348	24,571	37,659	38,444

Sales volume reflect North Sea lifted volumes and NE production for Kurdistan.

Activity overview

Kurdistan region of Iraq

Tawke license

Following closure of the Iraq-Türkiye Pipeline (ITP) last March, the Company has gradually resumed operations at the Tawke field and stepped up deliveries to local trading companies in Kurdistan. Gross production in the third quarter averaged 25,984 bopd (nil in Q2 2023).

There were no drilling operations at the Tawke license during the third quarter as the number of rigs was reduced from three to zero earlier in the year due to the ITP closure and continued delays in payments by the Kurdistan Regional Government (KRG) for previous oil sales.

The Peshkabir field restarted production on 16 October and production from the Tawke license continues to increase. So far in the fourth quarter output is averaging double the level of the third quarter.

The DNO-Genel contractual entitlement, currently around onehalf of volumes produced, is sold at prices that vary narrowly in the mid USD 30s per barrel, and payments are made in advance before any oil is delivered.

DNO holds a 75 percent operated interest in the Tawke and Peshkabir fields with partner Genel Energy International Limited (25 percent).

Baeshiqa license

Due to the closure of the ITP export route, the DNO-operated Baeshiqa license did not produce in the third quarter (65 bopd in Q2 2023).

DNO holds a 64 percent operated interest in the license (80 percent paying interest) with partners being Turkish Energy Company (TEC) with a 16 percent interest (20 percent paying interest) and the KRG with a 20 percent carried interest.

Net production (bopd) per field in Kurdistan:

	Quarters			First nine months	Full-Year
bopd	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Tawke	19,402	-	34,859	17,517	33,275	33,798
Peshkabir	86	-	46,502	12,263	47,204	46,528
Baeshiqa	0	41	367	191	173	343
Total	19,488	41	81,728	29,970	80,652	80,669

North Sea

Net production averaged 14,288 boepd in the North Sea segment during the third (10,844 boepd in Q2 2023), of which 14,103 boepd was in Norway and 185 boepd in the United Kingdom (UK) (10,311 boepd and 533 boepd in Q2 2023). The increase in North Sea production was mainly due to increased production from the Alve/Marulk fields as uptime at third-party facilities resumed after shutdown parts of the previous quarter, full quarter production from the Fenja field which came on stream in April and increase in production from the Brage field driven by the Taliskar East well which came on stream in May.

Offshore Norway, DNO participated during Q3 2023 in the Carmen discovery (30 percent), the country's largest in a decade, and in the DNO-operated Norma well (30 percent interest), a playopening discovery located near existing infrastructure 20 kilometers northwest of the Balder hub and 30 kilometers south of the Alvheim hub. To date this year, the Company has participated in discoveries totaling 100 million barrels of oil equivalent net to DNO.

A concept selection (DG2) was in July approved for Brasse as tieback to the Brage platform and the operatorship was transferred to OKEA ahead of expected investment decision early 2024.

Following the end of the quarter, DNO was awarded a 50 percent operated interest in Blocks 9/9f, 9/10c, 9/14c and 9/15d in the UK's 33rd Offshore Licensing Round. Aker BP UK Ltd will hold the remaining 50 percent in the licensed area, adjacent to the Norwegian border and just west of the Aker BP operated Alvheim hub on the Norwegian Continental Shelf.

	Quarters			First nine months	Full-Year
boepd	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Alve/Marulk	5,155	3,148	4,732	5,007	5,613	5,768
Ula area	4,077	4,348	6,670	4,809	4,129	4,659
Vilje	819	1,078	1,303	986	1,287	1,295
Brage	2,272	1,379	808	1,504	1,086	1,020
Ringhorne E.	311	-	360	105	523	440
Fenja	1,605	787	-	803	-	-
Other	49	104	97	87	116	131
Total	14,288	10,844	13,970	13,301	12,754	13,314

Ula area comprises Ula, Tambar, Oda and Blane (UK) fields.

West Africa

The net production from the Company's equity accounted investment, Côte d'Ivoire (West Africa segment), averaged 3,373 boepd in the third quarter (3,532 boepd in Q2 2023). The five percent reduction from the previous quarter was due to gas demand temporarily negatively impacted by higher electricity generation from hydropower during rainy season.

	Quarters			First nine months	Full-Year
boepd	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Block CI-27	3,373	3,532	-	3,526	-	3,327
Total	3,373	3,532	-	3,526	-	3,327

Financial review

Revenues, operating and net results, and cash

Revenues in the third quarter stood at USD 141.0 million, up 142 percent compared to the previous quarter (Q2 2023: USD 58.3 million). Kurdistan generated revenues of USD 32.3 million (Q2 2023: USD 1.9 million), while the North Sea generated revenues of USD 108.7 million (Q2 2023: USD 56.4 million). In Kurdistan, the Company gradually reopened from the Tawke field in July and stepped up deliveries to local trading companies in Kurdistan. In the North Sea, the increase in revenues was driven by crude lifting at the Vilje field (compared to no crude lifting in Q2 2023), higher crude liftings from the Ula area fields and increased gas sales from Alve/Marulk fields as third-party facilities resumed after shutdown parts of the previous quarter.

The Group reported an operating profit of USD 40.3 million in the third quarter, up from an operating loss of USD 15.0 million in the previous quarter. The improved operational result was mainly due to higher sales volumes in both Kurdistan and the North Sea partly offset by higher depreciation and impairment charges. Net loss of USD 55 million during the quarter was mainly driven by an accounting adjustment of USD 45 million in the book value of receivables from the KRG (recognized as a financial expense, see Note 9).

The Group ended the quarter with a cash balance of USD 708.1 million and USD 141.9 million in net cash position.

Cost of goods sold

In the third quarter, the cost of goods sold amounted to USD 87.5 million, up from USD 56.8 million in the previous quarter. The increase was mainly due to net overlifting of crude oil in the quarter and higher depreciation driven by increased production.

Lifting costs

Lifting costs stood at USD 40.5 million in the third quarter, down from USD 45.1 million in the previous quarter. In Kurdistan, the average lifting cost was USD 10.2 per barrel, down from USD 6,998.4 per barrel in the previous quarter. In the North Sea, the average lifting cost stood at USD 17.0 per barrel of oil equivalent (boe), down from USD 19.0 per boe in the previous quarter.

	Quarters			First nine months	Full-Year
USD million	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Kurdistan	18.2	26.3	32.6	81.8	85.3	124.7
North Sea	22.4	18.8	22.5	65.2	68.3	97.4
Total	40.5	45.1	55.1	146.9	153.6	222.1

	Quarters			First nine months	Full-Year
(USD/boe)	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Kurdistan	10.2	6,998.4	4.4	10.0	3.9	4.2
North Sea	17.0	19.0	17.5	18.0	19.6	20.1
Average	13.0	45.5	6.3	12.4	6.0	6.5

Depreciation, depletion and amortization (DD&A)

DD&A related to the Group's oil and gas production assets amounted to USD 29.5 million in the third quarter, compared to USD 8.8 million in the previous quarter. The increase in DD&A was driven by increase in production.

		Quarters		First nine months	Full-Year
USD million	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Kurdistan	16.2	0.9	30.5	53.8	94.5	126.4
North Sea	13.2	7.9	26.3	27.5	59.2	84.7
Total	29.5	8.8	56.8	81.3	153.7	211.1

	Quarters			First nine months	Full-Year
(USD/boe)	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Kurdistan	17.8	17.2	13.4	17.9	13.3	13.4
North Sea	10.1	7.9	20.5	7.6	17.0	17.4
Average	13.2	8.4	15.9	12.2	14.5	14.7

Exploration costs expensed

Exploration costs expensed in the third quarter amounted to USD 6.4 million, down from USD 16.5 million in the previous quarter. The exploration costs expensed in the third quarter was lower compared to the previous quarter mainly explained by capitalized exploration related to the Norma discovery.

	Quarters			First nine months	Full-Year
USD million	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Kurdistan	-	-	-	-	-	-
North Sea	6.4	16.5	25.4	29.4	78.9	96.5
Total	6.4	16.5	25.4	29.4	78.9	96.5

Capital expenditures

Capital expenditures stood at USD 61.0 million in the third quarter, of which USD 5.8 million were in Kurdistan and USD 55.1 million in the North Sea. Given uncertain timing of export pipeline resumption and the delays in payments by the KRG for previous oil sales, DNO has scaled back spend in Kurdistan in 2023.

	Quarters			First nine months	Full-Year
USD million	Q3 2023	Q2 2023	Q3 2022	2023	2022	2022
Kurdistan	5.8	20.5	55.0	66.0	155.7	212.2
North Sea	55.1	52.2	35.0	141.3	129.6	161.1
Other	0.1	0.4	0.3	0.8	0.6	1.5
Total	61.0	73.1	90.3	208.0	285.8	374.8

Consolidated statements of comprehensive income

		Quarters		First nine months		Full-Year
(unaudited, in USD million)	Note	Q3 2023	Q3 2022	2023	2022	2022
Revenues	2,3	141.0	338.9	468.2	1,038.9	1,377.0
Cost of goods sold	4	-87.5	-116.7	-249.1	-315.3	-460.9
Gross profit		53.5	222.2	219.1	723.5	916.1
Share of profit/-loss from Joint Venture	8	2.9	-	8.0	-	6.0
Other income/-expenses		0.5	0.6	1.4	1.5	2.8
Administrative expenses		-9.1	-6.0	-16.0	-11.1	-17.9
Other operating expenses		-0.6	-0.7	-2.0	0.0	-7.7
Impairment oil and gas assets	7	-5.9	-	-5.9	-127.3	-371.3
Exploration expenses	5	-6.4	-25.4	-29.4	-78.9	-96.5
Net gain on disposal of licenses	11	5.5	-	5.5	-	-
Operating profit/-loss		40.3	190.7	180.7	507.7	431.4
Financial income		1.8	2.6	39.9	3.6	13.8
Financial expenses	9,10	-61.8	-17.4	-97.7	-78.1	-98.7
Profit/-loss before income tax		-19.7	175.9	122.8	433.2	346.5
Tax income/-expense	6	-34.8	-46.2	-108.4	-90.8	38.4
Net profit/-loss		-54.5	129.6	14.4	342.4	384.9
Other comprehensive income
Currency translation differences		5.7	-16.6	-19.3	-51.8	-31.6
Items that may be reclassified to profit or loss in later periods		5.7	-16.6	-19.3	-51.8	-31.6
Net fair value changes from financial instruments	8	-	10.9	-	13.5	14.2
Items that are not reclassified to profit or loss in later periods		-	10.9	-	13.5	14.2
Total other comprehensive income, net of tax		5.7	-5.7	-19.3	-38.4	-17.4
Total comprehensive income, net of tax		-48.8	123.9	-4.9	304.0	367.5
Net profit/-loss attributable to:
Equity holders of the parent		-54.5	129.6	14.4	342.4	384.9
Total comprehensive income attributable to:
Equity holders of the parent		-48.8	123.9	-4.9	304.0	367.5
Earnings per share, basic (USD per share)		-0.06	0.13	0.01	0.35	0.39
Earnings per share, diluted (USD per share)		-0.06	0.13	0.01	0.35	0.39
Weighted average number of shares outstanding (millions)		975.00	975.43	981.74	975.43	986.97

Consolidated statements of financial position

ASSETS			At 30 Sep	At 31 Dec
(unaudited, in USD million)	Note	2023	2022	2022
Non-current assets
Deferred tax assets	6	-	2.4	-
Goodwill	7	46.4	60.4	56.1
Other intangible assets	7	160.0	81.5	97.2
Property, plant and equipment	7	1,142.8	1,283.9	1,108.6
Investment in Joint Venture	8	65.8	-	76.1
Other non-current receivables	9	134.7	0.2	-
Total non-current assets		1,549.7	1,428.4	1,338.1
Current assets
Inventories	4	73.9	44.0	47.0
Trade and other receivables	9	251.5	415.0	437.8
Financial investments	14	-	29.6	-
Tax receivables	6	-	38.2	25.8
Cash and cash equivalents		708.1	817.9	954.3
Total current assets		1,033.4	1,344.6	1,464.9
TOTAL ASSETS		2,583.1	2,773.0	2,803.0
EQUITY AND LIABILITIES
		At 30 Sep		At 31 Dec
(unaudited, in USD million)	Note	2023	2022	2022
Equity
Shareholders' equity		1,244.7	1,275.7	1,369.4
Total equity		1,244.7	1,275.7	1,369.4
Non-current liabilities
Deferred tax liabilities	6	154.3	209.3	62.4
Interest-bearing liabilities	10	391.2	554.1	546.4
Provisions for other liabilities and charges	11	377.4	367.7	379.6
Total non-current liabilities		922.9	1,131.1	988.4
Current liabilities
Trade and other payables	12	211.2	223.0	244.1
Income taxes payable	6	2.7	78.2	125.7
Current interest-bearing liabilities	10	166.2	-	8.4
Provisions for other liabilities and charges	11	35.4	65.0	67.0
Total current liabilities		415.4	366.2	445.3
Total liabilities		1,338.4	1,497.3	1,433.6

Consolidated cash flow statement

		Quarters		First nine months		Full-Year
(unaudited, USD million)	Note	Q3 2023	Q3 2022	2023	2022	2022
Operating activities
Profit/-loss before income tax		-19.7	175.9	122.8	433.2	346.5
Adjustments to add/-deduct non-cash items:			-		-	-
Exploration cost previously capitalized carried to cost	5	-0.3	9.9	6.2	48.4	52.2
Depreciation, depletion and amortization	4	31.0	58.2	85.8	157.8	216.7
Impairment oil and gas assets	7	5.9	-	5.9	127.2	371.3
Time value effects on trade receivables	9	44.6	-	44.6	-	-
Share of profit/-loss from Joint Venture	8	-2.9	-	-8.0	-	-6.0
Amortization of borrowing issue costs		0.9	1.1	2.5	4.4	5.2
Accretion expense on ARO provisions		4.2	3.6	12.9	11.4	15.5
Interest expense		11.4	13.0	35.3	46.0	57.5
Interest income		-8.4	-2.6	-27.0	-3.7	-12.9
Other		-0.3	-3.2	-20.2	4.6	11.0
Change in working capital items and provisions:			-		-
- Inventories		-7.3	-3.6	-26.9	-8.1	-11.2
- Trade and other receivables	9	-9.2	33.3	6.5	84.0	59.9
- Trade and other payables	12	-20.1	-10.3	-32.9	-9.6	11.5
- Provisions for other liabilities and charges		1.6	0.3	-5.4	-2.8	5.9
Cash generated from operations		31.7	275.6	202.2	892.9	1,123.0
Net income taxes paid/tax refund received		27.2	-1.8	-95.8	-38.7	-21.2
Interest received		6.1	2.7	20.1	3.7	12.5
Interest paid		-11.6	-12.5	-34.7	-46.7	-58.1
Net cash from/-used in operating activities		53.4	264.0	91.7	811.3	1,056.3
Investing activities
Purchases of intangible assets		-35.1	-10.4	-80.5	-61.3	-74.6
Purchases of tangible assets		-25.9	-79.8	-127.5	-224.5	-300.2
Payments for decommissioning		-2.5	-22.9	-17.3		-70.0
Acquisition of subsidiary, net of cash acquired					-56.5
	8	-	-	-	-	21.5
Payments for license transactions and disposal of financial investments	11	-5.1	-	-5.1	-	1.0
Equity contribution into Joint Venture	8	-1.8	-	-5.2	-	-4.2
Dividends from Joint Venture	8	6.4	-	23.7	-	11.5
Net cash from/-used in investing activities		-64.1	-113.2	-211.9	-342.3	-415.0
Financing activities
Repayment of borrowings	10	-	-105.0	-	-323.7	-323.7
Purchase of treasury shares		-	-	-50.7	-	-11.7
Paid dividend		-23.0	-24.8	-69.3	-47.0	-72.8
Payments of lease liabilities		-0.5	-2.7	-3.8	-8.1	-10.8
Net cash from/-used in financing activities		-23.5	-132.6	-123.8	-378.8	-419.1
Net increase/-decrease in cash and cash equivalents
Cash and cash equivalents at beginning of the period		-34.3	18.2	-244.0	90.1	222.3
Exchange gain/-losses on cash and cash equivalents		743.0	800.6	954.4	736.6	736.6
Cash and cash equivalents at the end of the period		-0.7 708.1	-1.0 817.9	-2.4 708.1	-8.8 817.9	-4.5 954.3

Consolidated statement of changes in equity

(unaudited, in USD million)	Share capital	Share premium	Other comprehensive income Fair value changes equity instruments	Currency translation differences	Retained earnings	Total equity
Total shareholders' equity as of 31 December 2021	32.9	247.7	39.7	-77.5	776.0	1,018.8
Fair value changes from equity instruments	-	-	13.5	-	-	13.5
Currency translation differences	-	-	-	-51.8	-	-51.8
Other comprehensive income/-loss	-	-	13.5	-51.8	-	-38.4
Profit/-loss for the period	-	-	-	-	342.4	342.4
Total comprehensive income	-	-	13.5	-51.8	342.4	304.0
Payment of dividend	-	-	-	-	-47.0	-47.0
Transactions with shareholders	-	-	-	-	-47.0	-47.0
Total shareholders' equity as of 30 September 2022	32.9	247.7	53.2	-129.3	1,071.4	1,275.7

	Share	Share	Other comprehensive income Currency translation	Retained	Total
(unaudited, in USD million)	capital	premium	changes equity instruments	differences	earnings	equity
Total shareholders' equity as of 31 December 2022	33.9	343.6	-	-29.0	1,020.9	1,369.4
Fair value changes from equity instruments	-	-	-	-	-	-
Currency translation differences	-	-	-	-19.3	-	-19.3
Other comprehensive income/-loss	-	-	-	-19.3	-	-19.3
Profit/-loss for the period	-	-	-	-	14.4	14.4
Total comprehensive income	-	-	-	-19.3	14.4	-4.9
Purchase of treasury shares	-1.1	-	-	-	-49.5	-50.5
Payment of dividend	-	-	-	-	-69.1	-69.1
Transactions with shareholders	-1.1	-	-	-	-118.6	-119.7
Total shareholders' equity as of 30 September 2023	32.8	343.6	-	-48.3	916.7	1,244.7

On 25 May 2023, at the DNO Annual General Meeting, the Company's shareholders approved the resolution to cancel 79,376,509 treasury shares held by the Company. The cancellation of treasury shares was completed during third quarter 2023.

Notes to the consolidated interim financial statements

Note 1 | Basis of preparation and accounting policies

Principal activities and corporate information

DNO ASA (the Company) and its subsidiaries (DNO or the Group) are engaged in international oil and gas exploration, development and production.

Basis of preparation

DNO ASA's consolidated interim financial statements have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting and IFRS standards issued and effective at date of reporting as adopted by the EU. These interim financial statements have also been prepared in accordance with Oslo Stock Exchange regulations.

The interim financial statements do not include all of the information and disclosures required in the annual financial statements and should be read in conjunction with the DNO ASA Annual Report and Accounts 2022.

The interim financial information for 2023 and 2022 is unaudited.

Subtotals and totals in some of the tables included in these interim financial statements may not equal the sum of the amounts shown due to rounding.

The interim financial statements have been prepared on a historical cost basis, with the following exception: liabilities related to share-based payments, derivative financial instruments and equity instruments are recognized at fair value. A detailed description of the accounting policies applied is included in the DNO ASA Annual Report and Accounts 2022.

The accounting policies adopted in the preparation of the interim financial statements are consistent with those followed in the preparation of DNO ASA Annual Report and Accounts 2022.

Note 2 | Segment information

The Group reports the following three operating segments: Kurdistan, North Sea (which includes the Group's oil and gas activities in Norway and the UK) and West Africa (which represents the Group's equity accounted investment in Côte d'Ivoire, see Note 8). The segment assets/liabilities do not include internal receivables/liabilities.

						Total	Un
Third quarter ending 30 September 2023				West		reporting	allocated/	Total
USD million	Note	Kurdistan	North Sea	Africa	Other		segments eliminated	Group
Income statement information
Revenues	3	32.3	108.7	-	-	141.0	-	141.0
Inter-segment revenues		-	-	-	-	-	-	-
Cost of goods sold	4	-34.6	-52.1	-	-	-86.7	-0.8	-87.5
Gross profit		-2.3	56.6	-	-	54.3	-0.8	53.5
Share of profit/-loss from Joint Venture	8	-	-	2.9	-	2.9	-	2.9
Other operating income		-	0.5	-	-	0.5	-	0.5
Administrative and other operating costs		-0.1	-3.2	-	-0.7	-4.0	-5.6	-9.7
Impairment of oil and gas assets	7	-	-5.9	-	-	-5.9	-	-5.9
Exploration costs	5	-	-6.4	-	-	-6.4	-	-6.4
Net gain on disposal of license	11	-	5.5	-	-	5.5	-	5.5
Operating profit/-loss		-2.5	46.9	2.9	-0.7	46.7	-6.4	40.3
Financial income/-expense (net)	10	-48.9	-10.7	0.6	0.1	-58.9	-1.1	-60.0
Tax income/-expense	6	-	-34.8	-	-	-34.8	-	-34.8
Net profit/-loss		-51.3	1.4	3.5	-0.6	-47.0	-7.5	-54.5

						Total	Un
Third quarter ending 30 September 2022				West		reporting	allocated/	Total
USD million	Note	Kurdistan	North Sea	Africa	Other		segment eliminated	Group
Income statement information
Revenues	3	197.5	141.4	-	-	338.9	-	338.9
Inter-segment revenues		-	-	-	-	-	-	-
Cost of goods sold	4	-63.2	-52.6	-	-	-115.8	-0.9	-116.7
Gross profit		134.3	88.7	-	-	223.1	-0.9	222.2
Share of profit/-loss from Joint Venture	8	-	-	-	-	-	-	-
Other operating income		-	0.6	-	-	0.6	-	0.6
Administrative and other operating costs		-0.2	-2.2	-	-0.8	-3.2	-3.5	-6.7
Impairment of oil and gas assets	7	-	-	-	-	-	-	-0.1
Exploration costs	5	-	-25.4	-	-	-25.4	-	-25.4
Net gain on disposal of license		-	-	-	-	-	-	-
Operating profit/-loss		134.1	61.7	-	-0.8	195.0	-4.3	190.7
Financial income/-expense (net)	10	4.0	-6.2	-	0.1	-2.1	-12.7	-14.8
Tax income/-expense	6	-	-46.2	-	-	-46.2	-	-46.2
Net profit/-loss		138.1	9.2		-0.6	146.7	-17.1	129.6

Note 2 | Segment information

				West		Total reporting	Un allocated/	Total
First nine months ending 30 September 2023 USD million	Note	Kurdistan	North Sea	Africa	Other		segment eliminated	Group
Income statement information
Revenues	3	171.9	296.3	-	-	468.2	-	468.2
Inter-segment sales		-	-	-	-	-	-	-
Cost of goods sold	4	-136.1	-110.4	-	-	-246.5	-2.6	-249.1
Gross profit		35.8	185.9	-	-	221.7	-2.6	219.1
Share of profit/-loss from Joint Venture	8	-	-	8.0	-	8.0	-	8.0
Other operating income		-	1.4	-	-	1.4	-	1.4
Administrative and other operating costs		-1.2	-8.1	-	-2.1	-11.4	-6.5	-18.0
Impairment of oil and gas assets	7	-	-5.9	-	-	-5.9	-	-5.9
Exploration costs	5	-	-29.4	-	-	-29.4	-	-29.4
Net gain on disposal of license	11	-	5.5	-	-	5.5	-	5.5
Operating profit/-loss		34.6	149.3	8.0	-2.1	189.8	-9.1	180.7
Financial income/-expense (net)	10	-46.4	-1.2	0.6	0.3	-46.8	-11.1	-57.9
Tax income/-expense	6	-	-108.4	-	-	-108.4	-	-108.4
Net profit/-loss		-11.9	37.5	8.6	-1.8	32.4	-17.9	14.4
Financial position information
Non-current assets		898.8	570.4	65.8	-	1,535.0	14.7	1,549.7
Current assets		234.1	287.9	-	2.6	524.6	508.9	1,033.4
Total assets		1,132.9	858.3	65.8	2.6	2,059.5	523.6	2,583.1
Non-current liabilities		71.8	442.1	-	-	514.0	409.0	922.9
Current liabilities		86.1	151.4	-	32.6	270.1	145.3	415.4
Total liabilities		157.9	593.6	-	32.6	784.0	554.3	1,338.4

Note 2 | Segment information

						Total	Un
First nine months ending 30 September 2022 USD million	Note	Kurdistan	North Sea	West Africa	Other	reporting	allocated/ segment eliminated	Total Group
Income statement information
Revenues	3	645.6	393.3	-	-	1,038.9	-	1,038.9
Inter-segment sales		-	-	-	-	-	-	-
Cost of goods sold	4	-180.1	-132.5	-	-	-312.7	-2.7	-315.3
Gross profit		465.5	260.7	-	-	726.2	-2.7	723.5
Share of profit/-loss from Joint Venture	8	-	-	-	-	-	-	-
Other operating income		-	1.5	-	-	1.5	-	1.5
Administrative and other operating costs		-0.2	-3.2	-	-0.8	-4.2	-6.9	-11.1
Impairment of oil and gas assets	7	-	-127.3	-	-	-127.3	-	-127.3
Exploration costs	5	-	-78.9	-	-	-78.9	-	-78.9
Net gain on disposal of license		-	-	-	-	-	-	-
Operating profit/-loss		465.3	52.8	-	-0.8	517.3	-9.6	507.7
Financial income/-expense (net)	10	11.1	-25.3		0.4	-13.7	-60.7	-74.5
Tax income/-expense	6	-	-90.8	-	-	-90.8	-	-90.8
Net profit/-loss		476.4	-63.3	-	-0.4	412.7	-70.3	342.4
Financial position information
Non-current assets		726.8	692.9	-	-	1,419.7	8.6	1,428.4
Current assets		335.4	345.3	-	11.6	692.3	652.4	1,344.6
Total assets		1,062.3	1,038.1	-	11.6	2,112.0	661.0	2,773.0
Non-current liabilities		68.2	535.0	-	-	603.2	527.9	1,131.1
Current liabilities		89.3	228.8	-	34.3	352.3	13.9	366.2
Total liabilities		157.5	763.7	-	34.3	955.5	541.8	1,497.3

Note 3 | Revenues

	Quarters		First nine months		Full year
USD million	Q3 2023	Q3 2022	2023	2022	2022
Sale of oil	109.2	259.6	354.4	806.2	1,061.1
Sale of gas	26.2	71.5	94.6	203.6	281.1
Sale of natural gas liquids (NGL)	5.2	5.8	17.4	25.0	29.1
Tariff income	0.4	1.9	1.8	4.0	5.8
Total revenues from contracts with customers	141.0	338.9	468.2	1,038.9	1,377.0
Sale of oil (bopd)	19,686	31,031	18,861	31,423	32,273
Sale of gas (boepd)	4,736	4,046	4,360	4,722	4,800
Sale of natural gas liquids (NGL) (boepd)	1,223	1,271	1,349	1,514	1,370
Total sales volume (boepd)	25,646	36,348	24,571	37,659	38,444

Oil revenues from Kurdistan during Q3 2023 were related to local sales.

Note 4 | Cost of goods sold/ Inventory

	Quarters		First nine months		Full-Year
USD million	Q3 2023	Q3 2022	2023	2022	2022
Lifting costs	-40.5	-55.1	-146.9	-153.6	-222.1
Tariff and transportation expenses	-8.6	-7.8	-22.7	-21.9	-30.2
Production costs based on produced volumes	-49.1	-62.9	-169.7	-175.5	-252.3
Movement in overlift/underlift	-7.4	4.4	6.4	18.0	8.1
Production costs based on sold volumes	-56.5	-58.4	-163.3	-157.5	-244.2
Depreciation, depletion and amortization	-31.0	-58.2	-85.8	-157.8	-216.7
Total cost of goods sold	-87.5	-116.7	-249.1	-315.3	-460.9

The lifting costs in full-year 2022 included a provision for obsolete inventory of USD 2.9 million related to the North Sea.

	At 30 Sep		At 31 Dec
USD million	2023	2022	2022
Spare parts	73.9	44.0	47.0
Total inventory	73.9	44.0	47.0

Book value of inventory as of the reporting date relates to Kurdistan (USD 61.7 million) and the North Sea (USD 12.2 million).

Note 5 | Exploration expenses

	Quarters		First nine months		Full-Year
USD million	Q3 2023	Q3 2022	2023	2022	2022
Exploration expenses (G&G and field surveys)	-2.3	-2.3	-8.6	-7.5	-10.2
Seismic costs	0.1	-9.6	-3.0	-11.5	-18.5
Exploration cost capitalized in previous years carried to cost	-	-0.5	-	-3.9	-3.9
Exploration costs capitalized this year carried to cost	0.3	-9.4	-6.2	-44.5	-48.3
Other exploration cost expensed	-4.5	-3.6	-11.6	-11.5	-15.6
Total exploration expenses	-6.4	-25.4	-29.4	-78.9	-96.5

Note 6 | Income taxes

	Quarters		First nine months		Full-Year
USD million	Q3 2023	Q3 2022	Q3 2023	Q3 2022	2022
Tax income/-expense
Change in deferred taxes	-37.9	-15.1	-95.7	-3.0	162.9
Income tax receivable/-payable	3.1	-31.2	-12.7	-87.8	-124.5
Total tax income/-expense	-34.8	-46.2	-108.4	-90.8	38.4

	At 30 Sep		At 31 Dec
USD million	2023	2022	2022
Income tax receivable/-payable
Tax receivables (non-current) 0	-	-	-
Tax receivables (current) 38.193	-	38.2	25.8
Income taxes payable -78.209	-2.7	-78.2	-125.7
Net tax receivable/-payable -40.016	-2.7	-40.0	-99.9
Deferred tax assets/-liabilities
Deferred tax assets 2.356	-	2.4	-
Deferred tax liabilities -209.279	-154.3	-209.3	-62.4
Net deferred tax assets/-liabilities 2.356	-154.3	-206.9	-62.4

The tax balances relate to the activity on the Norwegian Continental Shelf (NCS). The current income tax payable relates to taxable profits in 2023 on the NCS and is net of a tax refund of USD 6.2 million to be received in November 2023.

Under the terms of the Production Sharing Contracts (PSC) in the Kurdistan region of Iraq, the Company's subsidiary, DNO Iraq AS, is not required to pay any corporate income taxes. The share of profit oil of which the government is entitled to is deemed to include a portion representing the notional corporate income tax paid by the government on behalf of DNO. Current and deferred taxation arising from such notional corporate income tax is not calculated for Kurdistan as there is uncertainty related to the tax laws of the Kurdistan Regional Government (KRG) and there is currently no well-established tax regime for international oil companies. This is an accounting presentational issue and there is no corporate income tax required to be paid.

Profits/-losses by Norwegian companies from upstream activities outside of Norway are not taxable/deductible in Norway in accordance with the General Tax Act, section 2-39. Under these rules, only certain financial income and expenses are taxable in Norway.

Note 7 | Intangible assets/ Property, plant and equipment (PP&E)

	Quarters		First nine months		Full-Year
USD million	Q3 2023	Q3 2022	2023	2022	2022
Additions of intangible assets	35.1	10.4	80.5	61.3	74.6
Transfers to/-from intangible assets	-	-	-3.1	-131.2	-132.6
Additions of tangible assets	30.4	82.5	132.0	264.8	326.1
Transfers to/-from tangible assets	-	-	3.1	131.2	132.6
Additions of right-of-use (RoU) assets	-	-	10.5	1.4	1.9
Depreciation, depletion and amortization (Note 4)	-31.0	-58.2	-85.8	-157.8	-216.7
Impairment oil and gas assets	-5.9	-	-5.9	-127.3	-371.3
Exploration cost previously capitalized carried to cost (Note 5)	0.3	-9.9	-6.2	-48.4	-52.2

Book values at the end of the reporting dates

	At 30 Sep		At 31 Dec
USD million	2023	2022	2022
Goodwill	46.4	60.4	56.1
Other intangible assets	160.0	81.5	97.2
Tangible assets (presented as part of the PP&E)	1,125.8	1,271.7	1,097.9
RoU assets (presented as part of the PP&E)	17.0	12.2	10.7

Additions of intangible assets are related to exploration and evaluation expenditures (successful efforts method), license interests and administrative software. Additions of tangible assets are related to oil and gas development and production assets including changes in estimate of asset retirement, and other tangible assets. Additions of right-of-use (RoU) assets are related to lease contracts under IFRS 16 Leases, see Note 11.

Impairment assessment

At each reporting date, the Group assesses whether there is an indication that an asset may be impaired. An assessment of the recoverable amount is made when an impairment indicator exists. Goodwill is tested for impairment annually or more frequently when there are impairment indicators. Impairment is recognized when the carrying amount of an asset or a cash-generating unit (CGU), including associated goodwill, exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost to sell and the value in use.

During the third quarter of 2023, an impairment charge of USD 5.9 million was recognized against technical goodwill and was entirely related to the Vilje field, driven by a downward revision of reserves as reported in the 2024 Revised National Budget (RNB).

USD million	Income statement:			Balance sheet:
	Recoverable amount (post-tax)	Impairment -charge/ reversal (pre-tax)	Tax income/ -expense	Impairment -charge/ reversal (post-tax)	Goodwill	Property, plant and equipment	Deferred tax asset/ -liability	Currency effects
Vilje, North Sea	13.6	-5.9	-	-5.9	-6.0	-	-	0.1
Total	13.6	-5.9	-	-5.9	-6.0	-	-	0.1

The table above shows the recoverable amounts and impairment charge or reversal for the CGUs which were impaired in the current quarter, and how it was recognized in the income statement and balance sheet.

The future Brent oil price is a key assumption in the impairment assessments and has significant impact on the recoverable amount of the Group's assets. The Brent oil price assumptions applied in the impairment testing were based on the forward curve and observable broker and analyst consensus (Q4 2023: USD 85, 2024: USD 86, 2025: USD 83 and 2026: USD 77 per barrel, nominal terms). From 2027, the Brent oil price was based on the Group's long-term price assumption (USD 65 per barrel, real term), unchanged from yearend 2022. The relevant post-tax nominal discount rate (WACC) applied in the impairment test was 9.4 percent.

Note 8 | Investment in Joint Venture

General information

In October 2022, DNO acquired Mondoil Enterprises LLC (Mondoil Enterprises) and its 33.33 percent indirect interest in privately-held Foxtrot International LDC (Foxtrot International) whose principal assets are operated stakes in offshore production of gas and associated liquids in Côte d'Ivoire. Foxtrot International holds a 27.27 percent interest in and operatorship of Block CI-27 containing reserves of gas, produced together with condensate and oil, from four offshore fields tied back to two fixed platforms. Foxtrot International also operates an exploration license offshore Côte d'Ivoire, Block CI-12 in which it holds a 24 percent interest.

The provisional fair values from the PPA performed at yearend 2022, were based on currently available information about fair values as of the completion date (11 October 2022). If new information becomes available within 12 months from the completion date (measurement period), the Group may change the fair value assessment in the PPA. Eventual changes in fair values will be recorded retrospectively from the completion date.

Financial information of Foxtrot International

The Company's indirect 33.33 percent interest in Foxtrot International is treated in accordance with IFRS 11 Joint Arrangements and IAS 28 Investments in Associates and Joint Ventures (i.e., the Group's interest in Mondoil Côte d'Ivoire/Foxtrot International is accounted for using the equity method) and disclose in the table below the summarised financial information of Foxtrot International as an associate/joint venture (IAS 28) in terms of summarised financial information.

Foxtrot International's summarized statement of financial position	At 30 Sep	At 31 Dec
USD million	2023	2022
Non-current assets	201.5	216.5
Current assets	54.1	67.3
Total assets	255.6	283.7
Non-current liabilities	68.8	67.1
Current liabilities	25.8	30.0
Total liabilities	94.6	97.2
Equity	161.0	186.6
Group's share of net assets (33.33 percent)	53.7	62.2
Goodwill	0.8	0.8
Fair value uplift on PP&E and ARO (net of related deferred tax)	11.2	13.0
Carrying amount Investment in Joint Venture	65.8	76.1

Foxtrot International's summarized statement of comprehensive income*	Quarter	First nine months
USD million	Q3 2023	2023
Revenues	17.7	58.7
Expenses	-4.5	-12.7
Depreciation	-5.5	-25.1
Other income/finance income	1.9	6.2
Tax income/-expense	-	-
Net profit/-loss	9.6	27.0
Group's share of net profit (33.33 percent)	3.2	9.0
Depletion of fair value uplift of PP&E and ARO (net of related deferred tax)	-0.3	-1.0
Share of profit/-loss from Joint Venture	2.9	8.0

Note 8 | Investment in Joint Venture

Movement of investment carrying amount

Movement in the carrying amount of Investment in Joint Venture USD million	At 30 Sep 2023	At 31 Dec 2022
Opening balance	76.1	77.5
Share of profit/-loss from Joint Venture	8.0	6.0
Equity contribution into Joint Venture	5.2	4.2
Dividends from Joint Venture	-23.7	-11.5
Carrying amount Investment in Joint Venture	65.8	76.1

Note 9 | Other non-current receivables/ Trade Receivables

	At 30 Sep		At 31 Dec
USD million	2023	2022	2022
Trade debtors (non-current portion)	134.7	-	-
Other non-current receivables	-	0.2	-
Total other non-current receivables	134.7	0.2	-
Trade debtors	151.6	300.3	311.8
Underlift	13.2	20.4	14.0
Other short-term receivables	86.6	94.3	111.9
Total trade and other receivables	251.5	415.0	437.8

As of 30 September 2023, the Company was owed a total of USD 317.4 million, excluding any interest, by the KRG related to sales of DNO's entitlement shares of oil to the KRG for the months October 2022 through March 2023 plus part of the amount invoiced for oil sold to the KRG in September 2022. These receivables are past due and the last payment for oil sales received by DNO from the KRG was in March 2023 for oil deliveries in September 2022. Since 2017, DNO has consistently invoiced the KRG for such oil sales based on an agreed Brent pricing mechanism. For September 2022, the KRG unilaterally decided to pay based on a purported price realized by the KRG during the delivery month. KRG proposed such change to the agreed pricing mechanism in September 2022 to which DNO has not agreed. DNO therefore continues to request payment of the full invoiced amount.

The Company continues to engage with the KRG regarding collection of the arrears and expects that it will recover the full invoiced amount (as has occurred in the past), but the timing of recovery is uncertain. On 12 October 2023, KRG settled USD 7.8 million of these arrears with DNO by way of offsetting payables due to the KRG. Nonetheless, due to the IFRS 9 Financial Instruments requirement to incorporate the time value of money, the Company has reduced the book value of the KRG arrears by USD 44.6 million (presented under Financial expenses in the income statement) when comparing the book value of these arrears with the present value of the estimated future cash flows. The calculation of present value in accordance with IFRS 9, considers a range of possible scenarios with assigned weighting, involving estimation of the timing of receipt of the arrears which will be dependent upon uncertain future events, in particular the expected timing of the re-opening of the Iraq-Türkiye Pipeline which has been shut-in since 25 March 2023. A discount rate of 12 percent has been applied for discounting of the estimated future cash flows. In addition, USD 134.7 million was reclassified from short-term to non-current arrears considering the estimated timing of the recovery of the arrears.

The underlift receivable as of the reporting date relates to North Sea underlifted volumes. Other short-term receivables mainly relate to items of working capital in licenses in Kurdistan and the North Sea and accrual for earned income not invoiced in the North Sea.

Note 10 | Interest-bearing liabilities

Interest-bearing liabilities

					At 30 Sep		At 31 Dec
Ticker	currency	amount/limit	Interest	Maturity	2023	2022	2022
DNO03	USD	150.7	8.375 %	29/05/24	-	131.2	131.2
DNO04	USD	400.0	7.875 %	09/09/26	400.0	400.0	400.0
					-8.8	-12.0	-11.3
	USD	350.0	see below	see below	-	35.0	26.6
					391.2	554.1	546.4
DNO03	USD	150.7	8.375 %	29/05/24	131.2	-	-
	USD	350.0	see below	see below	35.0	-	8.4
					166.2	-	8.4
					557.3	554.1	554.8
		Facility	Facility

Changes in liabilities arising from financing activities split on cash and non-cash changes

	At 1 Jan	Cash	Non-cash changes			At 30 Sep
USD million	2023		flows Amortization	Currency	Reclassification	2023
Bond loans	531.2	-	-	-	-131.2	400.0
Bond loans (current)	-	-	-	-	131.2	131.2
Borrowing issue costs	-11.3	-	2.5	-	-	-8.8
Reserve based lending facility	26.6	-	-	-	-26.6	-0.0
Reserve based lending facility (current)	8.4	-	-	-	26.6	35.0
Total	554.8	-	2.5	-	-	557.3

	At 1 Jan	Cash	Non-cash changes		At 30 Sep
USD million	2022		flows Amortization	Currency	Reclassification	2022
Bond loans	794.9	-263.7	-	-	-	531.2
Borrowing issue costs	-16.5	-	4.4	-	-	-12.1
Reserve based lending facility	95.0	-60.0	-	-	-	35.0
Total	873.4	-323.7	4.4	-	-	554.1

Facility and carrying amount for the bonds is shown net of bonds held by the Company.

As of 30 September 2023, the Group had a reserve-based lending (RBL) facility for its Norwegian and UK production licenses with a total facility limit of USD 350 million which is available for both debt and issuance of letters of credit, and an uncommitted accordion option of USD 350 million. The borrowing base amount of the facility from 1 July 2023 is USD 46 million. Amount utilized as of the reporting date is disclosed in the table above. In addition, USD 24.4 million is utilized in respect of letters of credit.

For additional information about the Group's interest-bearing liabilities, refer to the DNO ASA Annual Report and Accounts 2022.

Note 11 | Provisions for other liabilities and charges/ Lease liabilities

	At 30 Sep		At 31 Dec
USD million	2023	2022	2022
Non-current
Asset retirement obligations (ARO)	356.4	356.2	368.2
Other long-term provisions and charges	6.7	4.8	4.9
Lease liabilities	14.3	6.7	6.5
Total non-current provisions for other liabilities and charges	377.4	367.7	379.6
Current
Asset retirement obligations (ARO)	3.2	24.4	20.5
Other provisions and charges	28.9	31.2	39.8
Current lease liabilities	3.3	9.3	6.8
Total current provisions for other liabilities and charges	35.4	65.0	67.0
Total provisions for other liabilities and charges	412.8	432.7	446.6

Asset retirement obligations

The provisions for ARO are based on the present value of estimated future cost of decommissioning oil and gas assets in Kurdistan and the North Sea. The discount rates before tax applied were between 4.5 percent and 4.8 percent.

Net gain on disposal of licenses of USD 5.5 million in the third quarter, was mainly related to DNO's sale of the 10 percent working interest in the East Foinaven license on the UKCS. The transaction was completed 14 July 2023 and involved a net negative consideration of USD 5.4 million from DNO and in return, the buyer took over the ARO obligation. Consequently, as part of the gain/loss calculation, the related book value of the ARO obligation was derecognized from the balance sheet.

Non-cancellable lease commitments

The recognized lease liabilities in the balance sheet are mainly related to office rent. The identified lease liabilities have no significant impact on the Group's financing, loan covenants or dividend policy. The Group does not have any residual value guarantees. Extension options are included in the lease liability when, based on the management's judgement, it is reasonably certain that an extension will be exercised. Non-lease components are not included as part of the lease liabilities.

Undiscounted lease liabilities and maturity of cash outflows (non-cancellable):

	At 30 Sep		At 31 Dec
USD million	2023	2022	2022
Within one year	4.6	9.9	7.0
Two to five years	12.9	7.0	6.5
After five years	-	-	-
Total undiscounted lease liabilities end of the period	17.4	17.0	13.5

The table above summarizes the Group's maturity profile of the lease liabilities based on contractual undiscounted payments.

Note 12 | Trade and other payables

	At 30 Sep		At 31 Dec
USD million	2023	2022	2022
Trade payables	88.8	51.1	62.7
Public duties payable	2.6	1.2	4.1
Prepayments from customers	13.7	20.6	12.7
Overlift	2.0	6.4	9.0
Other accrued expenses	104.1	143.7	155.7
Total trade and other payables	211.2	223.0	244.1

Trade payables are non-interest bearing and normally settled within 30 days.

Trade payables and other accrued expenses include items of working capital related to participation in oil and gas licenses in Kurdistan and the North Sea, and prepayment from customers related to oil sales in the North Sea.

The overlift payable relates to North Sea overlifted volumes, valued at production cost including depreciation.

Note 13 | Subsequent events after the reporting date

DNO receives 4 awards in UK's offshore licensing round

On 30 October 2023, DNO announced that its wholly-owned subsidiary DNO North Sea (U.K.) Limited has been awarded a 50 percent operated interest in four Blocks in United Kingdom's 33rd offshore licensing round. Aker BP UK Limited will hold the remaining 50 percent in the licensed area.

DNO farms down in PL740 (Brasse)

On 6 November 2023, the Company's wholly-owned subsidiary DNO Norge AS entered into a sales and purchase agreement with Lime Petroleum AS to farm down 10.7212 percent in PL740 containing the Brasse discovery. The transaction is conditional on customary governmental approvals. Prior to this agreement, DNO held 50 percent in the license.

Alternative performance measures

DNO discloses alternative performance measures (APMs) as a supplement to the Group's financial statements prepared based on issued guidelines from the European Securities and Markets Authority (ESMA). The Company believes that the APMs provide useful supplemental information to management, investors, securities analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of DNO's business operations, financing and future prospects and to improve comparability between periods. Reconciliations of relevant APMs, definitions and explanations of the APMs are provided below.

EBITDA

	Quarters		First nine months		Full-Year
USD million	Q3 2023	Q3 2022	2023	2022	2022
Revenues	141.0	338.9	468.2	1,038.9	1,377.0
Lifting costs	-40.5	-55.1	-146.9	-153.6	-222.1
Tariff and transportation	-8.6	-7.8	-22.7	-21.9	-30.2
Movement in overlift/underlift	-7.4	4.4	6.4	18.0	8.1
Share of profit/-loss from Joint Venture	2.9	-	8.0	-	6.0
Exploration expenses	-6.4	-25.4	-29.4	-78.9	-96.5
Administrative expenses	-9.1	-6.0	-16.0	-11.1	-17.9
Other operating income/expenses	-0.1	-0.1	-0.6	1.5	-5.0
EBITDA	71.8	249.0	266.9	792.8	1,019.5

EBITDAX

USD million	Q3 2023	Q3 2022	2023	2022	2022
EBITDA	71.8	249.0	266.9	792.8	1,019.5
Exploration expenses	6.4	25.4	29.4	78.9	96.5
EBITDAX	78.2	274.4	296.4	871.7	1,116.0
Lifting costs	Q3 2023	Q3 2022	2023	2022	2022
Lifting costs (USD million)	-40.5	-55.1	-146.9	-153.6	-222.1
Net production (MMboe)*	3.1	8.8	11.8	25.5	34.3
Lifting costs (USD/boe)	13.0	6.3	12.4	6.0	6.5

* For accounting purposes, the net production from equity accounted investments is excluded.

Capital expenditures	Q3 2023	Q3 2022	2023	2022	2022
Purchases of intangible assets	-35.1	-10.4	-80.5	-61.3	-74.6
Purchases of tangible assets*	-25.9	-79.8	-127.5	-224.5	-300.2
Capital expenditures	-61.0	-90.3	-208.0	-285.8	-374.8

* Excludes estimate changes on asset retirement obligations.

Alternative performance measures

Operational spend

	Quarters		First nine months		Full-Year
USD million	Q3 2023	Q3 2022	2023	2022	2022
Lifting costs	-40.5	-55.1	-146.9	-153.6	-222.1
Tariff and transportation expenses	-8.6	-7.8	-22.7	-21.9	-30.2
Exploration expenses	-6.4	-25.4	-29.4	-78.9	-96.5
Exploration cost previously capitalized carried to cost (Note 5)	-0.3	9.9	6.2	48.4	52.2
Purchases of intangible assets	-35.1	-10.4	-80.5	-61.3	-74.6
Purchases of tangible assets	-25.9	-79.8	-127.5	-224.5	-300.2
Payments for decommissioning	-2.5	-22.9	-17.3	-56.5	-70.0
Operational spend	-119.4	-191.5	-418.2	-548.3	-741.4
Free cash flow

USD million	Q3 2023	Q3 2022	2023	2022	2022
Net cash from/-used in operating activities	53.4	264.0	91.7	811.3	1,056.3
Capital expenditures	-61.0	-90.3	-208.0	-285.8	-374.8
Payments for decommissioning	-2.5	-22.9	-17.3	-56.5	-70.0
Equity contribution into Joint Venture (Note 8)	-1.8	-	-5.2	-	-4.2
Dividends from Joint Venture (Note 8)	6.4	-	23.7	-	11.5
Free cash flow	-5.7	150.8	-115.1	469.0	618.8

Equity ratio USD 2023 2022 2022 Equity 1,244.7 1,275.7 1,369.4 Total assets 2,583.1 2,773.0 2,803.0 Equity ratio 48.2% 46.0% 48.9% Net debt USD million 2023 2022 2022 Cash and cash equivalents (including restricted cash) 708.1 817.9 954.3 Bond loans and reserve based lending (Note 10) 566.2 566.2 566.2 Net cash/-debt 141.9 251.7 388.2

Alternative performance measures

Definitions and explanations of APMs

ESMA issued guidelines on APMs that came into effect on 3 July 2016. The Company has defined and explained the purpose of the following APMs:

EBITDA (Earnings before interest, tax, depreciation and amortization)

EBITDA, as reconciled above, can be found by excluding the DD&A and impairment of oil and gas assets from the profit/-loss from operating activities. Management believes that this measure provides useful information regarding the Group's ability to fund its capital investments and provides a helpful measure for comparing its operating performance with those of other companies.

EBITDAX (Earnings before interest, tax, depreciation, amortization and exploration expenses)

EBITDAX, as reconciled above, can be found by excluding the exploration expenses from the EBITDA. Management believes that this measure provides useful information regarding the Group's profitability and ability to fund its exploration activities and provides a helpful measure for comparing its performance with those of other companies.

Lifting costs (USD/boe)

Lifting costs comprise of expenses related to the production of oil and gas, including operation and maintenance of installations, well intervention activities and insurances. DNO's lifting costs per boe are calculated by dividing DNO's share of lifting costs across producing assets by net production for the relevant period. Management believes that the lifting cost per boe is a useful measure because it provides an indication of the Group's level of operational cost effectiveness between time periods and with those of other companies.

Capital expenditures

Capital expenditures comprise the purchase of intangible and tangible assets irrespective of whether paid in the period. Management believes that this measure is useful because it provides an overview of capital investments used in the relevant period.

Operational spend

Operational spend is comprised of lifting costs, tariff and transportation expenses, exploration expenses, capital expenditures and payments for decommissioning. Management believes that this measure is useful because it provides a complete overview of the Group's total operational costs, capital investments and payments for decommissioning used in the relevant period.

Equity ratio

The equity ratio is calculated by dividing total equity by the total assets. Management uses the equity ratio to monitor its capital and financial covenants (see Note 9 in the consolidated accounts). The equity ratio also provides an indication of how much of the Group's assets are funded by equity.

Free cash flow

Free cash flow comprises net cash from/-used in operating activities less capital expenditures, payments for decommissioning and net cash received/-paid from equity accounted investments. Management believes that this measure is useful because it provides an indication of the profitability of the Group's operating activities excluding the non-cash items of the income statement and includes operational spend. This measure also provides a helpful measure for comparing with that of other companies.

Net debt

Net debt comprises cash and cash equivalents less bond loans and reserve based lending facility. Management believes that net debt is a useful measure because it provides indication of the minimum necessary debt financing (if the figure is negative) to which the Group is subject at the reporting date.

DNO ASA Dokkveien 1 N-0250 Oslo Norway

Phone: (+47) 23 23 84 80 Fax: (+47) 23 23 84 81

Third Quarter 2023 Interim Results | 27

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