DNO ASA — Interim / Quarterly Report 2022

Nov 3, 2022

Key figures

	Quarters			First nine months		Full-Year
USD million	Q3 2022	Q2 2022	Q3 2021	2022	2021	2021
Key financials
Revenues	338.9	360.6	253.5	1,038.9	607.6	1,004.1
EBITDAX	274.4	303.8	193.1	871.7	472.0	739.3
EBITDA	249.0	256.1	156.6	792.8	398.3	606.9
Operating profit/-loss	190.7	80.8	65.4	507.7	192.7	320.9
Net profit/-loss	129.6	72.3	30.9	342.4	139.0	203.9
Netback	247.2	231.6	193.5	754.1	481.6	781.6
Free cash flow	150.8	166.5	54.1	469.0	134.7	362.0
Operational spend	191.5	197.4	190.8	548.3	493.1	663.8
Net cash/- debt	251.7	129.5	-360.3	251.7	-360.3	-153.4
Lifting costs (USD/boe)	6.3	5.7	5.7	6.0	5.4	5.3
Netback (USD/boe)	28.1	27.7	22.9	29.6	18.7	22.7
Key operational data
Gross operated production (boepd)	109,054	107,178	105,179	107,575	109,131	108,713
Net production (boepd)	95,698	91,937	91,986	93,406	94,579	94,477
Sales volume (boepd)	36,348	39,276	41,402	37,659	38,637	42,171

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

Q3 2022 highlights

• Continued strong operational and financial results
• DNO's net production across the portfolio totaled 95,700 boepd, of which Kurdistan contributed 81,700 bopd and the North Sea 14,000 boepd
• In Kurdistan, gross operated production totaled 109,100 bopd, of which Peshkabir field contributed 62,000 bopd, Tawke field 46,500 bopd and Baeshiqa field 600 bopd
• Entered West Africa through completion of the previously announced transaction with RAK Petroleum plc
• Oil discovery in Ofelia well offshore Norway near existing infrastructure
• Revenues exceeded USD 300 million for fourth consecutive quarter; higher gas prices in Q3 compared to last quarter offset by lower oil prices and sales volumes
• Operating profit more than doubled quarter-on-quarter
• Net profit up 79 percent from previous quarter
• Free cash flow in Q3 totaled USD 151 million (cumulative USD 469 million in first nine months 2022)
• At the end of the quarter, net cash totaled USD 252 million
• Equity ratio increased with retained earnings and debt reduction

Operational review

Production

Quarterly net production (boepd)

Net production by segment (boepd)

Gross production from the Company's operated licenses in Kurdistan averaged 109,054 barrels of oil per day (bopd) during the third quarter, up from 107,178 bopd in the previous quarter.

Net production during the third quarter stood at 95,698 barrels of oil equivalent per day (boepd), up from 91,937 boepd in the previous quarter. In Kurdistan, net production averaged 81,728 bopd, compared to 80,358 bopd in the previous quarter. Net production from the North Sea averaged 13,970 boepd, up from 11,579 boepd in the previous quarter. The increase in the North Sea production was mainly driven by higher production from Ula area following maintenance activities in the previous quarter and new well on stream at the Oda field, partly offset by lower gas production from Alve/Marulk fields due to maintenance activities.

Net entitlement (NE) production averaged 38,749 boepd during the third quarter, compared to 38,261 boepd in the previous quarter.

Sales volume averaged 36,348 boepd during the third quarter, down from 39,276 boepd in the previous quarter. The decrease in sales volume was mainly due to lower lifting from the Vilje field (lifted semi-annually) and lower gas production from Alve/Marulk fields, partly offset by higher lifting from the Ula area. The net underlift position was 0.43 million barrels of oil equivalent (MMboe) as of Q3 2022 (0.21 MMboe as of Q2 2022).

Gross operated production

	Quarters			First nine months	Full-Year
boepd	Q3 2022	Q2 2022	Q3 2021	2022	2021	2021
Kurdistan	109,054	107,178	105,179	107,575	109,131	108,713
North Sea	-	-	-	-	-	-
Total	109,054	107,178	105,179	107,575	109,131	108,713

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

Net production

	Quarters			First nine months	Full-Year
boepd	Q3 2022	Q2 2022	Q3 2021	2022	2021	2021
Kurdistan	81,728	80,358	78,884	80,652	81,848	81,535
North Sea	13,970	11,579	13,102	12,754	12,730	12,942
Total	95,698	91,937	91,986	93,406	94,579	94,477

Net production is based on DNO's percentage ownership in the licenses.

Net entitlement (NE) production

Quarters			First nine months	Full-Year
boepd	Q3 2022	Q2 2022	Q3 2021	2022	2021	2021
Kurdistan	24,779	26,682	26,749	26,039	27,661	28,091
North Sea	13,970	11,579	13,102	12,754	12,730	12,942
Total	38,749	38,261	39,851	38,793	40,391	41,033

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

Sales volume

	Quarters			First nine months	Full-Year
boepd	Q3 2022	Q2 2022	Q3 2021	2022	2021	2021
Kurdistan	24,779	26,682	26,749	26,039	27,661	28,091
North Sea	11,569	12,594	14,653	11,621	10,977	14,080
Total	36,348	39,276	41,402	37,659	38,637	42,171

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

Activity overview

Kurdistan region of Iraq

Tawke license

Gross production from the DNO-operated Tawke license, containing the Tawke and Peshkabir fields, averaged 108,481 bopd during the third quarter of 2022 (106,948 bopd in Q2 2022). The Peshkabir field contributed 62,003 bopd (62,348 bopd in Q2 2022) and the Tawke field contributed 46,478 bopd (44,600 bopd in Q2 2022) during this period.

Production at the legacy Tawke field has increased in two consecutive quarters this year, the first quarterly increases since 2015 as new wells are drilled, workovers conducted on existing ones and gas injection continued to counter natural field decline.

The Company maintains its Tawke licence full-year projection of 107,000-109,000 bopd.

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

Baeshiqa license

Following government approvals, DNO commenced trucking of production in mid-June from the Zartik-1 discovery well in the operated Baeshiqa license for export at an average rate of around 600 bopd during the third quarter of 2022. Production from the well has been choked back as the Company targets zones with lower gas-to-oil ratios to avoid flaring. The Baeshiqa-2 discovery well was brought onstream in late September. Baeshiqa license rampup has been slower than previously expected. Development of the field continues with further drilling.

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

Table below shows the net production (bopd) per field in Kurdistan.

	Quarters			First nine months	Full-Year
bopd	Q3 2022	Q2 2022	Q3 2021	2022	2021	2021
Tawke	34,859	33,450	33,943	33,275	35,788	35,199
Peshkabir	46,502	46,761	44,942	47,204	46,060	46,335
Baeshiqa	367	147	-	173	-	-
Total	81,728	80,358	78,884	80,652	81,848	81,535

North Sea

Net production averaged 13,970 boepd in the North Sea during the third quarter of 2022 (11,579 boepd in Q2 2022), of which 13,626 boepd was in Norway and 344 boepd in the UK (11,411 boepd and 168 boepd in Q2 2022). The Company maintains its full-year North Sea net production projection of 13,000 bopd.

In Norway, the Company continues to review its field development projects ahead of yearend 2022 investment decisions in light of recent proposed fiscal changes.

In August, DNO announced the Ofelia discovery in the highly prospective Troll-Gjøa area offshore Norway, an area in which the Company holds 12 licenses and has scheduled a six-well exploration program over the next 12 months.

Table below shows the net production (boepd) per field in the North Sea.

		Quarters		First nine months	Full-Year
boepd	Q3 2022	Q2 2022	Q3 2021	2022	2021	2021
Alve/Marulk	4,732	5,711	5,112	5,613	4,747	5,024
Ula area	6,670	2,485	4,957	4,129	4,722	4,635
Vilje	1,303	1,283	1,684	1,287	1,609	1,613
Brage	808	1,200	1,093	1,086	1,229	1,218
Ringhorne	360	796	185	523	257	286
E. Other	97	103	70	116	167	165
Total	13,970	11,579	13,102	12,754	12,730	12,942

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

Financial review

Revenues, operating profit and cash

Revenues in the third quarter stood at USD 338.9 million, down from USD 360.6 million in the previous quarter. Kurdistan generated revenues of USD 197.5 million (Q2: USD 239.4 million), while the North Sea generated revenues of USD 141.4 million (Q2: USD 121.1 million). The decrease in Kurdistan revenues was driven by lower average oil price compared to previous quarter, and lower override revenues as override equivalent to three percent of gross Tawke license revenues under the August 2017 receivables settlement agreement ended 31 July 2022. The North Sea revenue increase was driven by higher achieved gas prices partly offset by lower gas volumes sold.

The Group reported an operating profit of USD 190.7 million in the third quarter, up from USD 80.8 million in the previous quarter mainly explained by lower impairments and expensing of exploration wells partly offset by lower revenues.

The Group ended the quarter with a cash balance of USD 817.9 million and USD 251.7 million in net cash position, compared to a cash balance of USD 736.6 million and USD 153.4 million in net interest-bearing debt at yearend 2021.

Cost of goods sold

In the third quarter, the cost of goods sold amounted to USD 116.7 million, up from USD 103.7 million in the previous quarter. The increase in cost of goods sold was mainly explained by first production at the Baeshiqa license and higher depreciation in the North Sea.

Lifting costs

Lifting costs stood at USD 55.1 million in the third quarter, up from USD 47.7 million in the previous quarter. In Kurdistan, the average lifting cost was USD 4.4 per barrel, up from USD 3.4 per barrel in the previous quarter mainly explained by first production at the Baeshiqa license. In the North Sea, the average lifting cost stood at USD 17.5 per barrel of oil equivalent (boe), down from USD 21.9 per boe in the previous quarter primarily driven by to higher production from the Ula area.

	Quarters			First nine months	Full-Year
USD million	Q3 2022	Q2 2022	Q3 2021	2022	2021	2021
Kurdistan	32.6	24.6	24.9	85.3	73.4	99.6
North Sea	22.5	23.1	23.1	68.3	66.6	84.6
Total	55.1	47.7	48.0	153.6	140.0	184.2

(USD/boe)	Quarters Q3 2022 Q2 2022 Q3 2021			First nine months 2022	Full-Year 2021
Kurdistan	4.4	3.4	3.4	3.9	3.3	3.3
North Sea	17.5	21.9	19.2	19.6	19.2	17.9
Average	6.3	5.7	5.7	6.0	5.4	5.3

Depreciation, depletion and amortization (DD&A)

DD&A related to the Group's oil and gas production assets amounted to USD 56.8 million in the third quarter, up from USD 46.8 million in the previous quarter. The increase in deprecation was mainly related to North Sea, driven by higher net production and increase in DD&A/boe on Ula area following reduction in reserves from the impairment in the previous quarter.

		Quarters		First nine months	Full-Year
USD million	Q3 2022	Q2 2022	Q3 2021	2022	2021	2021
Kurdistan	30.5	32.3	29.0	94.5	89.0	120.8
North Sea	26.3	14.5	20.6	59.2	59.1	79.2
Total	56.8	46.8	49.6	153.7	148.1	200.1

		Quarters		First nine months	Full-Year
(USD/boe)	Q3 2022	Q2 2022	Q3 2021	2022	2021	2021
Kurdistan	13.4	13.3	11.8	13.3	11.8	11.8
North Sea	20.5	13.8	17.1	17.0	17.0	16.8
Average	15.9	13.4	13.5	14.5	13.4	13.4

Exploration costs expensed

Exploration costs expensed in the third quarter amounted to USD 25.4 million, down from USD 47.7 million in the previous quarter. The decrease in exploration costs expensed was primarily due to lower expensing of wells in the third quarter, partly offset by seismic purchase booked in the third quarter.

		Quarters		First nine months	Full-Year
USD million	Q3 2022	Q2 2022	Q3 2021	2022	2021	2021
Kurdistan	-	-	0.9	-	1.6	2.8
North Sea	25.4	47.7	35.5	78.9	72.2	129.6
Total	25.4	47.7	36.4	78.9	73.8	132.3

Capital expenditures

Capital expenditures costs stood at USD 90.3 million in the third quarter, of which USD 55.0 million were in Kurdistan and USD 35.0 million in the North Sea.

USD million	Quarters Q3 2022 Q2 2022 Q3 2021		First nine months 2022	Full-Year 2021
Kurdistan	55.0	56.4	22.8	155.7	56.1	94.9
North Sea	35.0	57.7	71.0	129.6	148.7	185.1
Other	0.3	-0.2	-	0.6	-	0.7
Total	90.3	113.9	93.7	285.8	204.8	280.6

Consolidated statements of comprehensive income

			Quarters First nine months			Full-Year
(unaudited, in USD million)	Note	Q3 2022	Q3 2021	2022	2021	2021
Revenues	2,3	338.9	253.5	1,038.9	607.6	1,004.1
Cost of goods sold	4	-116.7	-105.6	-315.3	-278.0	-443.1
Gross profit		222.2	147.8	723.5	329.6	561.0
Other income/-expenses		0.6	-	1.5	0.2	0.5
Administrative expenses		-6.0	-4.6	-11.1	-6.7	-16.2
Other operating expenses		-0.7	-1.1	0.0	-3.7	-12.0
Impairment oil and gas assets	7	-	-40.3	-127.3	-52.8	-80.1
Exploration expenses	5	-25.4	-36.4	-78.9	-73.8	-132.3
Operating profit/-loss		190.7	65.4	507.7	192.7	320.9
Financial income	9	2.6	6.3	3.6	24.2	26.0
Financial expenses	9,10	-17.4	-34.9	-78.1	-101.7	-126.7
Profit/-loss before income tax		175.9	36.9	433.2	115.2	220.1
Tax income/-expense	6	-46.2	-6.0	-90.8	23.8	-16.3
Net profit/-loss		129.6	30.9	342.4	139.0	203.9
Other comprehensive income
Currency translation differences		-16.6	-8.8	-51.8	-9.0	-12.5
Items that may be reclassified to profit or loss in later periods		-16.6	-8.8	-51.8	-9.0	-12.5
Net fair value changes from financial instruments	8	10.9	0.1	13.5	5.5	3.6
Items that are not reclassified to profit or loss in later periods		10.9	0.1	13.5	5.5	3.6
Total other comprehensive income, net of tax		-5.7	-8.7	-38.4	-3.5	-8.9
Total comprehensive income, net of tax		123.9	22.2	304.0	135.5	195.0
Net profit/-loss attributable to:
Equity holders of the parent		129.6	30.9	342.4	139.0	203.9
Total comprehensive income attributable to:
Equity holders of the parent		123.9	22.2	304.0	135.5	195.0
Earnings per share, basic (USD per share)		0.13	0.03	0.35	0.14	0.21
Earnings per share, diluted (USD per share)		0.13	0.03	0.35	0.14	0.21
Weighted average number of shares outstanding (millions)		975.43	975.43	975.43	975.43	975.43

Consolidated statements of financial position

ASSETS	At 30 Sep	At 31 Dec
(unaudited, in USD million) Note	2022	2021	2021
Non-current assets
Deferred tax assets 6	2.4	37.6	29.3
Goodwill 7	60.4	120.8	88.2
Other intangible assets 7	81.5	382.0	232.4
Property, plant and equipment 7	1,283.9	1,149.6	1,284.9
Financial investments 8	-	18.1	16.2
Other non-current receivables 9	0.2	71.1	19.4
Total non-current assets	1,428.4	1,779.2	1,670.4
Current assets
Inventories 4	44.0	34.1	35.8
Trade and other receivables 9	415.0	453.4	483.8
Financial investments 8	29.6	-	-
Tax receivables 6	38.2	111.3	21.1
Cash and cash equivalents	817.9	585.7	736.6
Total current assets	1,344.6	1,184.5	1,277.3
TOTAL ASSETS	2,773.0	2,963.7	2,947.7
EQUITY AND LIABILITIES	At 30 Sep		At 31 Dec
(unaudited, in USD million) Note	2022	2021	2021
Equity
Shareholders' equity	1,275.7	981.1	1,018.8
Total equity	1,275.7	981.1	1,018.8
Non-current liabilities
Deferred tax liabilities 6	209.3	273.2	267.3
Interest-bearing liabilities 10	554.1	911.6	873.4
Provisions for other liabilities and charges 11	367.7	411.6	402.4
Total non-current liabilities	1,131.1	1,596.5	1,543.2
Current liabilities
Trade and other payables 12	223.0	250.1	232.6
Income taxes payable 6	78.2	-	33.1
Current interest-bearing liabilities 10	-	16.9	-
Provisions for other liabilities and charges 11	65.0	119.0	120.1
Total current liabilities	366.2	386.1	385.8
Total liabilities	1,497.3	1,982.6	1,929.0
TOTAL EQUITY AND LIABILITIES	2,773.0	2,963.7	2,947.7

Consolidated cash flow statement

		Quarters		First nine months		Full-Year
(unaudited, USD million)	Note	Q3 2022	Q3 2021	2022	2021	2021
Operating activities
Profit/-loss before income tax		175.9	36.9	433.2	115.2	220.1
Adjustments to add/-deduct non-cash items:
Exploration cost previously capitalized carried to cost	5	9.9	24.2	48.4	24.2	54.1
Depreciation, depletion and amortization	4	58.2	51.0	157.8	152.7	206.0
Impairment oil and gas assets	7	-	40.3	127.2	52.8	80.1
Amortization of borrowing issue costs		1.1	2.7	4.4	8.4	9.4
Accretion expense on ARO provisions		3.6	4.3	11.4	13.4	17.7
Interest expense		13.0	17.7	46.1	55.1	74.2
Interest income		-2.6	-0.4	-3.7	-1.0	-1.7
Other		-3.2	2.1	4.6	0.8	1.0
Change in working capital items and provisions:
- Inventories		-3.6	0.4	-8.1	10.0	5.0
- Trade and other receivables	9	33.3	-52.0	84.0	-120.8	-99.5
- Trade and other payables		-10.3	30.3	-9.6	72.6	55.1
- Provisions for other liabilities and charges		0.3	-2.3	-2.9	-0.6	3.8
Cash generated from operations		275.6	155.1	892.9	382.9	625.3
Income taxes paid		-1.8	-	-1.8	-	-
Tax refund received/-repaid		-	36.9	-36.9	83.3	174.7
Interest received		2.7	0.4	3.7	1.1	1.7
Interest paid		-12.5	-16.5	-46.7	-55.3	-73.0
Net cash from/-used in operating activities		264.0	175.9	811.2	412.1	728.8
Investing activities
Purchases of intangible assets		-10.4	-55.3	-61.3	-71.3	-86.8
Purchases of tangible assets		-79.8	-38.4	-224.5	-133.6	-193.8
Payments for decommissioning		-22.9	-28.1	-56.5	-72.7	-86.2
Proceeds from license transactions		-	-	-	-	4.7
Net cash from/-used in investing activities		-113.2	-121.8	-342.3	-277.4	-362.0
Financing activities
Proceeds from borrowings	10
Repayment of borrowings	10	-	400.0	-	400.0	400.0
Payment of debt issue costs		-105.0	-302.8	-323.7	-402.8	-459.0
Paid dividend		- -24.8	-15.6 -	- -47.0	-15.6 -	-15.6 -22.2
Payments of lease liabilities		-2.7	-2.9	-8.1	-6.3	-8.6
Net cash from/-used in financing activities		-132.6	78.7	-378.8	-24.7	-105.4
Net increase/-decrease in cash and cash equivalents		18.2	132.8	90.1	109.8	261.5
Cash and cash equivalents at beginning of the period		800.6	454.2	736.6	477.1	477.1
Exchange gain/-losses on cash and cash equivalents		-1.0	-1.3	-8.8	-1.1	-2.0
Cash and cash equivalents at the end of the period		817.9	585.7	817.9	585.7	736.6
Of which restricted cash		21.3	12.6	21.3	12.6	15.8

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 2020	32.9	247.7	36.1	-65.0	593.9	845.6
Fair value changes from equity instruments	-	-	5.5	-	-	5.5
Currency translation differences	-	-	-	-9.0	-	-9.0
Other comprehensive income/-loss	-	-	5.5	-9.0	-	-3.5
Profit/-loss for the period	-	-	-	-	139.0	139.0
Total comprehensive income	-	-	5.5	-9.0	139.0	135.5
Payment of dividend	-	-	-	-	-	-
Transactions with shareholders	-	-	-	-	-	-
Total shareholders' equity as of 30 September 2021	32.9	247.7	41.6	-74.0	733.0	981.1

	Other comprehensive income Fair value Currency
	Share	Share	changes equity	translation	Retained	Total
(unaudited, in USD million)	capital	premium	instruments	differences	earnings	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

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 2021.

The interim financial information for 2022 and 2021 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 2021.

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 2021.

Note 2 | Segment information

The Group reports the following two operating segments: Kurdistan and the North Sea (which includes the Group's oil and gas activities in Norway and the UK). The segment assets/liabilities do not include internal receivables/liabilities.

					Total	Un
Third quarter ending 30 September 2022					reporting	allocated/	Total
USD million	Note	Kurdistan	North Sea	Other		segments 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
Operating profit/-loss		134.1	61.7	-0.8	195.0	-4.3	190.7
Financial income/-expense (net)	9,10						-14.8
Tax income/-expense	6	-	-46.2	-	-46.2	-	-46.2
Net profit/-loss							129.6
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 2 | Segment information (continued)

Third quarter ending 30 September 2021 USD million	Note	Kurdistan	North Sea	Other	Total reporting	Un allocated/ segment eliminated	Total Group
Income statement information
Revenues	3	149.3	104.1	-	253.5	-	253.5
Inter-segment revenues		-	0.4	-	0.4	-0.4	-
Cost of goods sold	4	-54.0	-50.9	-	-104.9	-0.7	-105.6
Gross profit		95.3	53.6	-	148.9	-1.1	147.8
Operating profit/-loss		93.9	-26.4	-1.4	66.1	-0.7	65.4
Financial income/-expense (net)	9, 10						-28.6
Tax income/-expense	6	-	-6.0	-	-6.0	-	-6.0
Net profit/-loss							30.9
Financial position information
Non-current assets		720.6	1,029.8	-	1,750.4	28.8	1,779.2
Current assets		308.9	411.5	4.6	725.1	459.4	1,184.5
Total assets		1,029.5	1,441.3	4.6	2,475.4	488.2	2,963.7
Non-current liabilities		62.5	743.3	-	805.8	790.7	1,596.5
Current liabilities		65.4	277.0	30.5	372.8	13.2	386.1
Total liabilities		127.9	1,020.2	30.5	1,178.7	803.9	1,982.6

Note 2 | Segment information (continued)

First nine months ending 30 September 2022 USD million	Note	Kurdistan	North Sea	Other	Total reporting	Un 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
Operating profit/-loss		465.3	52.8	-0.8	517.3	-9.6	507.7
Financial income/-expense (net)	9,10						-74.5
Tax income/-expense	6	-	-90.8	-	-90.8	-	-90.8
Net profit/-loss							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

					Total	Un
First nine months ending 30 September 2021					reporting	allocated/	Total
USD million	Note	Kurdistan	North Sea	Other		segment eliminated	Group
Income statement information
Revenues	3	413.9	193.7	-	607.6	-	607.6
Inter-segment sales		-	1.8	-	1.8	-1.8	-
Cost of goods sold	4	-162.7	-113.2	-	-275.9	-2.1	-278.0
Gross profit		251.2	82.2	-	333.5	-3.9	329.6
Operating profit/-loss		248.3	-44.9	-3.3	200.1	-7.4	192.7
Financial income/-expense (net)	10						-77.5
Tax income/-expense	6	-	24.2	-0.3	23.8	-	23.8
Net profit/-loss							139.0
Financial position information
Non-current assets		720.6	1,029.8	-	1,750.4	28.8	1,779.2
Current assets		308.9	411.5	4.6	725.1	459.4	1,184.5
Total assets		1,029.5	1,441.3	4.6	2,475.4	488.2	2,963.7
Non-current liabilities		62.5	743.3	-	805.8	790.7	1,596.5
Current liabilities		65.4	277.0	30.5	372.8	13.2	386.1
Total liabilities		127.9	1,020.2	30.5	1,178.7	803.9	1,982.6

Note 3 | Revenues

	Quarters		First nine months		Full-Year
USD million	Q3 2022	Q3 2021	2022	2021	2021
Sale of oil	259.6	207.7	806.2	524.0	828.1
Sale of gas	71.5	36.9	203.6	66.1	151.3
Sale of natural gas liquids (NGL)	5.8	7.6	25.0	15.0	21.3
Tariff income	1.9	1.3	4.0	2.5	3.4
Total revenues from contracts with customers	338.9	253.5	1,038.9	607.6	1,004.1
Sale of oil (bopd)	31,031	35,204	31,423	33,380	36,583
Sale of gas (boepd)	4,046	4,540	4,722	4,056	4,344
Sale of natural gas liquids (NGL) (boepd)	1,271	1,659	1,514	1,201	1,244
Total sales volume (boepd)	36,348	41,402	37,659	38,637	42,171

Note 4 | Cost of goods sold/ Inventory

	Quarters		First nine months		Full-Year
USD million	Q3 2022	Q3 2021	2022	2021	2021
Lifting costs	-55.1	-48.0	-153.6	-140.0	-184.2
Tariff and transportation expenses	-7.8	-8.9	-21.9	-25.8	-34.5
Production costs based on produced volumes	-62.9	-56.8	-175.5	-165.8	-218.8
Movement in overlift/underlift	4.4	2.1	18.0	40.5	-18.3
Production costs based on sold volumes	-58.4	-54.7	-157.5	-125.3	-237.0
Depreciation, depletion and amortization	-58.2	-51.0	-157.8	-152.7	-206.0
Total cost of goods sold	-116.7	-105.6	-315.3	-278.0	-443.1

Lifting costs consist of expenses related to the production of oil and gas, including operation and maintenance of installations, well intervention activities and insurances. Tariff and transportation expenses consist of charges incurred by the Group for the use of infrastructure owned by other companies in the North Sea.

	At 30 Sep		At 31 Dec
USD million	2022	2021	2021
Spare parts	44.0	34.1	35.8
Total inventory	44.0	34.1	35.8

Total inventory of USD 44.0 million as of 30 September 2022 was related to Kurdistan (USD 28.4 million) and the North Sea (USD 15.6 million).

Note 5 | Exploration expenses

	Quarters		First nine months		Full-Year
USD million	Q3 2022	Q3 2021	2022	2021	2021
Exploration expenses (G&G and field surveys)	-2.3	-2.1	-7.5	-14.5	-19.1
Seismic costs	-9.6	-5.0	-11.5	-20.2	-37.6
Exploration cost capitalized in previous years carried to cost	-0.5	-11.2	-3.9	-11.2	-13.4
Exploration costs capitalized this year carried to cost	-9.4	-13.1	-44.5	-13.1	-40.7
Other exploration cost expensed	-3.6	-4.9	-11.5	-14.7	-21.5
Total exploration expenses	-25.4	-36.4	-78.9	-73.8	-132.3

Exploration costs capitalized carried to cost are mainly related to expensing of the Uer (PL943) exploration well in the North Sea.

Note 6 | Income taxes

	Quarters		First nine months		Full-Year
USD million	Q3 2022	Q3 2021	2022	2021	2021
Tax income/-expense
Change in deferred taxes	-15.1	-46.8	-3.0	-111.3	-115.2
Income tax receivable/-payable	-31.2	40.8	-87.8	135.1	98.9
Total tax income/-expense	-46.2	-6.0	-90.8	23.8	-16.3

	At 30 Sep		At 31 Dec
USD million	2022	2021	2021
Income tax receivable/-payable
Tax receivables (non-current) 0	-	-	-
Tax receivables (current) 111.345	38.2	111.3	21.1
Income taxes payable 0	-78.2	-	-33.1
Net tax receivable/-payable 111.345	-40.0	111.3	-11.9
Deferred tax assets/-liabilities
Deferred tax assets 37.598	2.4	37.6	29.3
Deferred tax liabilities -273.241	-209.3	-273.2	-267.3
Net deferred tax assets/-liabilities 37.598	-206.9	-235.6	-238.0

The tax balances relate to the activity on the Norwegian Continental Shelf (NCS) and the UK Continental Shelf (UKCS). The current tax receivable of USD 38.2 million relates to tax refunds of decommissioning spend on the UKCS, of which USD 17.3 million is expected to be received during the fourth quarter of 2022. The current income tax payable of USD 78.2 million relates to taxable profits in 2022 on the NCS.

During June 2022, the Norwegian Parliament approved certain changes to the taxation of oil and gas companies operating on the NCS with effect from 1 January 2022. The companies can expense investments immediately in the special tax basis and receive a cash refund of tax value of losses in the special tax basis. The uplift on investments is discontinued but will apply to the investments covered by the temporary changes, as approved by the parliament in June 2020. The ordinary corporate tax is deductible in the special tax basis and to maintain a combined marginal tax rate of 78 percent, the special tax rate is increased to 71.8 percent. Losses in the corporate tax basis are not eligible for refund but can be carried forward. The tax value of unused uplift and carried forward losses as of yearend 2021 will be paid out in connection with the 2022 tax assessment in November 2023. The tax effects of these changes were recognised in the second quarter of 2022.

On 6 October 2022, the Norwegian Government proposed a change to the uplift under the temporary tax rules applying to PDOs delivered by the end of 2022, from 17.69 percent to 12.4 percent, effective from 1 January 2023. The proposal has not been approved by the Norwegian Parliament and may be subject to adjustments. If the proposal is approved, it will adversely impact the economics of development projects under the temporary rules.

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 2022	Q3 2021	2022	2021	2021
Additions of intangible assets	10.4	42.3	61.3	58.3	86.8
Additions of intangible assets through license acquisition	-	35.2	-	35.2	35.2
Divestments of intangible assets through license acquisition	-	-	-	-	-6.0
Transfers to/-from intangible assets	-	-	-131.2	-	-125.7
Additions of tangible assets	82.5	41.5	264.8	149.3	206.4
Transfers to/-from tangible assets	-	-	131.2		129.7
Additions of right-of-use (RoU) assets	-	-	1.4	14.4	14.6
Depreciation, depletion and amortization (Note 4)	-58.2	-51.0	-157.8	-152.7	-206.0
Impairment oil and gas assets	-	-40.3	-127.3	-52.8	-80.1
Exploration cost previously capitalized carried to cost (Note 5)	-9.9	-24.3	-48.4	-24.3	-54.1

Book values at the end of the reporting dates

	At 30 Sep		At 31 Dec
USD million	2022	2021	2021
Goodwill	60.4	120.8	88.3
Other intangible assets	81.5	382.0	232.4
Tangible assets (presented as part of the PP&E)	1,271.7	1,127.3	1,264.3
RoU assets (presented as part of the PP&E)	12.2	22.3	20.6

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. No impairment testing was required to be performed during the third quarter.

Note 8 | Financial investments

Financial investments are comprised of equity instruments and are recorded at fair value (market price, where available) at the end of the reporting period. Fair value changes are included in other comprehensive income (FVTOCI).

	Quarters		First nine months		At 31 Dec
USD million	Q3 2022	Q3 2021	2022	2021	2021
Beginning of the period	18.8	18.0	16.2	12.6	12.6
Fair value changes through other comprehensive income (FVTOCI)	10.9	0.1	13.5	5.5	3.6
Total financial investments end of the period	29.6	18.1	29.6	18.1	16.2
Non-current portion		18.1	-	18.1	16.2
Current portion	29.6		29.6	-	-

Financial investments was related to the Company's shares in RAK Petroleum plc. As of 30 September 2022, the Company held a total of 15,849,737 shares in RAK Petroleum plc. RAK Petroleum plc was listed on the Oslo Stock Exchange and was the largest shareholder in DNO ASA with 44.94 percent of the total issued shares. See Note 13 (Subsequent events after the reporting date) related to the transaction agreement entered between DNO ASA and RAK Petroleum plc.

Change in fair value during the quarter was recognized in other comprehensive income.

Note 9 | Other non-current receivables/ Trade and other receivables

	At 30 Sep		At 31 Dec
USD million	2022	2021	2021
Trade debtors (non-current portion)	-	69.4	18.2
Other non-current receivables	0.2	1.7	1.3
Total other non-current receivables	0.2	71.1	19.4
Trade debtors	300.3	290.1	344.4
Underlift	20.4	65.7	17.2
Other short-term receivables	94.3	97.6	122.2
Total trade and other receivables	415.0	453.4	483.8

Total book value of trade debtors of USD 300.3 million as of 30 September 2022 relate mainly to the outstanding invoices for Tawke license crude oil deliveries for the months June through September 2022 (USD 283.8 million). See also Note 13 regarding subsequent events after the reporting date.

The underlift receivable of USD 20.4 million as of 30 September 2022 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

		Facility	Facility			At 30 Sep		At 31 Dec
USD million	Ticker	currency	amount/limit	Interest	Maturity	2022	2021	2021
Non-current
Bond loan (ISIN NO0010852643)	DNO03	USD	150.7	8.375 %	29/05/24	131.2	397.2	394.9
Bond loan (ISIN NO0011088593)	DNO04	USD	400.0	7.875 %	09/09/26	400.0	400.0	400.0
Capitalized borrowing issue costs						-12.0	-17.5	-16.5
Reserve based lending facility		USD	350.0	see below	see below	35.0	131.9	95.0
Total non-current interest-bearing liabilities						554.1	911.6	873.4
Current
Reserve based lending facility (current)		USD	350.0	see below	see below	-	16.9	-
Total current interest-bearing liabilities						-	16.9	-
Total interest-bearing liabilities						554.1	928.5	873.4

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	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

	At 1 Jan	Cash Non-cash changes			At 30 Sep
USD million	2021		flows Amortization	Currency	Reclassification	2021
Bond loans	800.0	-2.8	-	-	-	797.2
Borrowing issue costs	-15.4	-10.5	8.4	-	-	-17.5
Reserve based lending facility	149.6	-	-	-0.8	-16.9	131.9
Reserve based lending facility (current)	-	-	-	-	16.9	16.9
Total	934.2	-13.3	8.4	-0.8	-	928.5

During Q3 2022, DNO ASA completed buybacks in the DNO03 bond totaling USD 45 million. Of the total, USD 25.4 million was cancelled by the Company during the quarter and the remaining USD 19.6 million was cancelled subsequent to Q3 2022. Facility and carrying amount for the bonds is shown net of bonds held by the Company.

The Group had available a revolving exploration financing facility (EFF) in an aggregate amount of NOK 250 million with an uncommitted accordion option of NOK 750 million. Following the changes in taxation of oil and gas companies operating on the NCS (see Note 6), the EFF agreement was terminated by the Company subsequent to Q3 2022.

The Group has a reserve-based lending (RBL) facility for its Norway 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. In addition, there is an uncommitted accordion option of USD 350 million. Interest charged on utilizations is based on LIBOR plus a margin ranging from 2.75 to 3.25 percent. The facility will amortize over the loan life with a final maturity date of 7 November 2026. The borrowing base amount of the facility from 1 July 2022 is USD 158 million. Amount utilized as of the reporting date is disclosed in the table above. In addition, USD 65.5 million is utilized in respect of letters of credit. During Q3 2022, USD 60 million of the outstanding RBL loan was repaid.

For additional information about the Group's interest-bearing liabilities, refer to the DNO ASA Annual Report and Accounts 2021.

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

	At 30 Sep		At 31 Dec
USD million	2022	2021	2021
Non-current
Asset retirement obligations (ARO)	356.2	394.4	386.3
Other long-term provisions and charges	4.8	3.7	3.6
Lease liabilities	6.7	13.5	12.5
Total non-current provisions for other liabilities and charges	367.7	411.6	402.4
Current
Asset retirement obligations (ARO)	24.4	74.4	69.7
Other provisions and charges	31.2	27.0	34.8
Current lease liabilities	9.3	17.6	15.7
Total current provisions for other liabilities and charges	65.0	119.0	120.1
Total provisions for other liabilities and charges	432.7	530.7	522.6

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 3.2 percent and 3.7 percent.

Non-cancellable lease commitments

The recognized lease liabilities in the balance sheet are mainly related to rig lease and office rent. In the second quarter of 2021, DNO entered into a rig lease agreement to perform decommissioning, plugging and abandonment at the Schooner and Ketch fields in the UK part of the North Sea. The rig lease was entered into with DNO as the operator of the licenses at the initial signing and subsequently partly allocated to the license partners (presented under non-current and current receivables). The rig lease was recognized on a gross basis, rather than based on DNO's working interest share (60 percent).

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	2022	2021	2021
Within one year	9.9	18.7	16.6
Two to five years	7.0	14.0	13.1
After five years	-	0.3	-
Total undiscounted lease liabilities end of the period	17.0	33.0	29.7

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	2022	2021	2021
Trade payables	51.1	67.9	85.7
Public duties payable	1.2	1.7	6.1
Prepayments from customers	20.6	41.5	-
Overlift	6.4	6.3	17.3
Other accrued expenses	143.7	132.7	123.4
Total trade and other payables	223.0	250.1	232.6

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

Payments from Kurdistan

Since end-Q3 2022, DNO has received a total of USD 88 million from the KRG (net to DNO), of which USD 76.6 million represents DNO's entitlement share of June 2022 crude oil deliveries to the export market from the Tawke license, USD 10.3 million are override payments equivalent to three percent of gross June 2022 Tawke license revenues under the August 2017 receivables settlement agreement, and the balance represents DNO's entitlement share of June 2022 crude oil deliveries from the Baeshiqa license.

DNO enters West Africa through completion of the transaction with RAK Petroleum plc

On 11 October 2022, the Company announced the completion of the transaction with RAK Petroleum plc (RAK Petroleum) for transferring shares in Mondoil Enterprises LLC (Mondoil Enterprises) to DNO ASA as referenced in a 22 August 2022 stock exchange announcement. Following completion, the Company holds 100 percent of the shares in Mondoil Enterprises. Mondoil Enterprises owns 50 percent of Mondoil Côte d'Ivoire LLC (Mondoil Côte d'Ivoire), which, in turn, owns 66.66 percent of Foxtrot International LDC (Foxtrot International), resulting in the Company's indirect 33.33 percent interest in Foxtrot International.

The transaction was entered on 22 August 2022 with effective date 1 January 2022 and was valued at USD 117.25 million. The Company has issued 78.94 million new shares to RAK Petroleum as consideration.

On 19 October 2022, RAK Petroleum distributed by way of a capital repayment the entirety of its DNO shareholding, including the abovementioned transaction consideration shares, to its shareholders, which also included DNO (5.1 percent). Following the distribution, the Company has 26,269,183 own shares which will be retained as treasury shares. Prior to the issuance of the consideration shares, RAK Petroleum held 438,379,418 shares in DNO, representing 44.94 percent of shares outstanding.

As the transaction was completed subsequent to the balance sheet date it does not impact the Q3 2022 interim results. A purchase price allocation (PPA) is being performed to allocate the consideration shares to fair value of acquired assets and assumed liabilities. For accounting purposes, the DNO ASA share price at completion date will be applied for valuation of the consideration shares and for recognition of the transaction. Based on a preliminary accounting assessment, the transaction will be treated in accordance with IFRS 11 and IAS 28 Investments in Associates and Joint Ventures.

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 2022	Q3 2021	2022	2021	2021
Revenues	338.9	253.5	1,038.9	607.6	1,004.1
Lifting costs	-55.1	-48.0	-153.6	-140.0	-184.2
Tariff and transportation	-7.8	-8.9	-21.9	-25.8	-34.5
Movement in overlift/underlift	4.4	2.1	18.0	40.5	-18.3
Exploration expenses	-25.4	-36.4	-78.9	-73.8	-132.3
Administrative expenses	-6.0	-4.6	-11.1	-6.7	-16.2
Other operating income/expenses	-0.1	-1.1	1.5	-3.5	-11.5
EBITDA	249.0	156.6	792.8	398.3	606.9

EBITDAX

USD million	Q3 2022	Q3 2021	2022	2021	2021
EBITDA	249.0	156.6	792.8	398.3	606.9
Exploration expenses	25.4	36.4	78.9	73.8	132.3
EBITDAX	274.4	193.0	871.7	472.0	739.3

Netback

USD million	Q3 2022	Q3 2021	2022	2021	2021
EBITDA	249.0	156.6	792.8	398.3	606.9
Tax refund received/-taxes paid	-1.8	36.9	-38.7	83.3	174.7
Netback	247.2	193.5	754.1	481.6	781.6
	Q3 2022	Q3 2021	2022	2021	2021
Netback (USD million)	247.2	193.5	754.1	481.6	781.6
Net production (MMboe)	8.8	8.5	25.5	25.8	34.5
Netback (USD/boe)	28.1	22.9	29.6	18.7	22.7
Lifting costs	Q3 2022	Q3 2021	2022	2021	2021
Lifting costs (USD million)	-55.1	-48.0	-153.6	-140.0	-184.2
Net production (MMboe)	8.8	8.5	25.5	25.8	34.5
Lifting costs (USD/boe)	6.3	5.7	6.0	5.4	5.3

Alternative performance measures (continued)

Capital expenditures

	Quarters		First nine months		Full-Year
USD million	Q3 2022	Q3 2021	2022	2021	2021
Purchases of intangible assets	-10.4	-55.3	-61.3	-71.3	-86.8
Purchases of tangible assets*	-79.8	-38.4	-224.5	-133.6	-193.8
Capital expenditures	-90.3	-93.7	-285.8	-204.8	-280.6
* Exclude estimate changes on asset retirement obligations.
Operational spend
USD million	Q3 2022	Q3 2021	2022	2021	2021
Lifting costs	-55.1	-48.0	-153.6	-140.0	-184.2
Tariff and transportation expenses	-7.8	-8.9	-21.9	-25.8	-34.5
Exploration expenses	-25.4	-36.4	-78.9	-73.8	-132.3
Exploration cost previously capitalized carried to cost (Note 5)	9.9	24.2	48.4	24.0	54.1
Purchases of intangible assets	-10.4	-55.3	-61.3	-71.3	-86.8
Purchases of tangible assets*	-79.8	-38.4	-224.5	-133.6	-193.8
Payments for decommissioning	-22.9	-28.1	-56.5	-72.7	-86.2
Operational spend	-191.5	-190.8	-548.3	-493.1	-663.8
* Exclude estimate changes on asset retirement obligations. Free cash flow
USD million	Q3 2022	Q3 2021	2022	2021	2021
Net cash from/-used in operating activities	264.0	175.9	811.2	412.1	728.8
Capital expenditures	-90.3	-93.7	-285.8	-204.8	-280.6
Payments for decommissioning	-22.9	-28.1	-56.5	-72.7	-86.2
Free cash flow	150.8	54.1	469.0	134.7	362.0
Equity ratio
USD			2022	2021	2021
Equity			1,275.7	981.1	1,018.8
Total assets			2,773.0	2,963.7	2,947.8
Equity ratio			46.0%	33.1%	34.6%
Net debt
USD million			2022	2021	2021
Cash and cash equivalents (including restricted cash)			817.9	585.7	736.6
Bond loans and reserve based lending (Note 10)			566.2	946.0	889.9
Net cash/-debt			251.7	-360.3	-153.4

Alternative performance measures (continued)

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.

Netback

Netback, as reconciled above, comprises EBITDA adjusted for taxes received/-paid. Management believes that this measure is useful because it provides an indication of the profitability of the Group's operating activities after taxes received/-paid without regard to significant events and/or decisions in the period that are expected to occur less frequently. This measure is also helpful for comparing the Group's operational performance between time periods and with those of other companies.

Netback (USD/boe)

Netback (USD/boe) is calculated by dividing netback in USD by the net production for the relevant period. Management believes that this measure is useful because it provides an indication of the profitability of the Group's operating activities after taxes received/-paid without regard to significant events and/or decisions in the period that are expected to occur less frequently, per net boe produced. This measure is also helpful for comparing the Group's operational performance between time periods and with that 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 and payments for decommissioning. 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

dno.no

Third Quarter 2022 Interim Results | 27