DNO ASA — Interim / Quarterly Report 2021

Nov 4, 2021

Cover photo: On board the Borgland Dolphin drilling rig during DNO operations offshore Norway

Key figures

		Quarters		First nine months		Full-Year
USD million	Q3 2021	Q2 2021	Q3 2020	2021	2020	2020
Key financials
Revenues	253.5	184.3	163.0	607.6	440.7	614.9
Gross profit	147.8	97.7	4.9	329.6	-10.2	24.9
Profit/-loss from operating activities	65.4	60.9	-208.1	192.7	-300.4	-314.5
Net profit/-loss	30.9	56.7	-122.5	139.0	-225.6	-285.9
EBITDA	156.6	122.2	76.1	398.3	224.1	322.8
EBITDAX	193.0	149.1	84.8	472.0	264.6	378.8
Netback	193.5	153.4	100.6	481.6	248.6	559.1
Acquisition and development costs	80.7	60.4	27.2	191.9	156.6	207.9
Exploration expenses	36.4	26.9	8.7	73.8	40.5	55.9
Production
Gross operated production (boepd)	105,179	110,304	113,742	109,131	110,317	110,282
Net production (boepd)	91,986	92,667	102,995	94,579	100,776	100,063
Key performance indicators
Lifting costs (USD/boe)	5.7	5.7	4.2	5.4	5.0	4.9
Netback (USD/boe)	22.9	18.2	10.6	18.7	9.0	15.3

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

Q3 2021 operational highlights

• Gross operated Tawke license production including the Tawke and Peshkabir fields averaged 105,200 barrels of oil per day (bopd) in Q3 2021 (110,300 bopd in Q2 2021) of which 78,900 bopd net to DNO's interest (82,700 bopd Q2 2021)
• North Sea contributed another 13,100 barrels of oil equivalent per day (boepd), up from 9,900 boepd in Q2 2021 as production resumed at Marulk and Alve fields
• Totaling net DNO production of 92,000 boepd in Q3 2021 (92,700 boepd in Q2 2021)
• Tawke license 2021 gross operated production guidance unchanged at around 110,000 bopd
• North Sea 2021 net production guidance unchanged at around 13,000 boepd
• DNO had 91 licenses across its portfolio at end Q3 2021 (25 operated), of which two in Kurdistan, 74 in Norway, 11 in the United Kingdom, two in the Netherlands, one in Ireland and one in Yemen

Q3 2021 financial highlights

• Revenues totaled USD 253 million in Q3 2021, up 38 percent quarter-onquarter driven by strengthening oil and gas prices and higher North Sea sales
• Kurdistan revenues of USD 149 million (USD 141 million in Q2 2021) and North Sea revenues of USD 104 million (USD 43 million in Q2 2021)
• Operating profit of USD 65 million in Q3 2021 (USD 61 million in Q2 2021)
• New USD 400 million five-year bonds with coupon rate of 7.875 percent, lowering average debt interest rate and extending maturity
• Received USD 120 million from Kurdistan in Q3 2021 (entitlement USD 88 million, override USD 11 million and USD 20 million towards arrears built up from non-payment of certain invoices in 2019 and 2020)
• At end Q3 2021, outstanding Kurdistan arrears had dropped to USD 203 million, down from the original USD 259 million, excluding any interest

Operational review

Production

Quarterly net production (boepd)

Net production by segment (boepd)

Gross operated Tawke license production including the Tawke and Peshkabir fields averaged 105,179 bopd during the third quarter, compared to 110,304 bopd in the previous quarter.

Net production during the third quarter stood at 91,986 boepd, compared to 92,667 boepd in the previous quarter. In Kurdistan, net production averaged 78,884 bopd, down from 82,728 bopd in the previous quarter impacted by well shut-ins for maintenance and interventions at the Peshkabir field. Net production from the North Sea averaged 13,102 boepd, up from 9,939 boepd in the previous quarter as production resumed at the Alve and Marulk gas fields following planned maintenance in the previous quarter.

Net entitlement (NE) production averaged 39,851 boepd during the third quarter, up from 37,600 boepd in the previous quarter. Sales volume averaged 41,402 boepd during the quarter, up from 34,946 boepd in the previous quarter driven by increased North Sea sales. Net underlift position relating to the North Sea was 1.0 million barrels of oil equivalent (MMboe) as of Q3 2021 (1.1 MMboe as of Q2 2021).

Gross operated production

		Quarters		First nine months	Full-Year
boepd	Q3 2021	Q2 2021	Q3 2020	2021	2020	2020
Kurdistan	105,179	110,304	113,742	109,131	110,317	110,282
North Sea	-	-	-	-	-	-
Total	105,179	110,304	113,742	109,131	110,317	110,282

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

Net production

		Quarters		First nine months	Full-Year
boepd	Q3 2021	Q2 2021	Q3 2020	2021	2020	2020
Kurdistan	78,884	82,728	85,306	81,848	82,738	82,711
North Sea	13,102	9,939	17,690	12,730	18,038	17,352
Total	91,986	92,667	102,995	94,579	100,776	100,063

Effective Q1 2021, the Company reports its net production from the Tawke license in Kurdistan based on its percentage ownership in the license. Comparison figures have been updated.

Net entitlement (NE) production

		Quarters		First nine months	Full-Year
boepd	Q3 2021	Q2 2021	Q3 2020	2021	2020	2020
Kurdistan	26,749	27,661	30,674	27,661	37,211	36,257
North Sea	13,102	9,939	17,690	12,730	18,038	17,352
Total	39,851	37,600	48,364	40,391	55,249	53,609

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

Sales volume

		Quarters		First nine months	Full-Year
boepd	Q3 2021	Q2 2021	Q3 2020	2021	2020	2020
Kurdistan	26,749	27,661	30,674	27,661	37,211	36,257
North Sea	14,653	7,285	22,184	10,977	16,917	18,125
Total	41,402	34,946	52,857	38,637	54,128	54,383

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

Activity overview

Kurdistan region of Iraq

Tawke license

Gross production from the Tawke license, containing the Tawke and Peshkabir fields, averaged 105,179 bopd during the third quarter of 2021 (110,304 bopd in Q2 2021). The Peshkabir field contributed 59,922 bopd (62,983 in Q2 2021) and the Tawke field contributed 45,257 bopd (47,321 in Q2 2021) during this period. Drilling at the Tawke field resumed in the third quarter after an 18 month pause during which natural production decline was slowed through pressure support from gas injection and workovers. Third quarter production at the Peshkabir field was impacted by well shut-ins for maintenance and interventions. Both fields are slated for multi-year development campaigns.

DNO's USD 110 million Peshkabir-Tawke gas project, which was commissioned in mid-2020, has injected eight billion cubic feet of otherwise flared gas through the end of the third quarter, capturing 480,000 tonnes of CO2 equivalent. In September, the Company initiated a USD 25 million second phase of the gas capture project to reinject and retain gas in the Tawke reservoir and avoid flaring. Having already eliminated routine venting of methane in operations in 2019, DNO recently launched a leak detection and repair initiative to measure, monitor and mitigate fugitive methane emissions.

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

Baeshiqa license

In the third quarter of 2021, DNO declared commerciality on the license with plans submitted for fast-track development including early production from previously drilled but suspended wells.

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 Kurdistan Regional Government (KRG) with a 20 percent carried interest.

North Sea

Net production averaged 13,102 boepd in the North Sea during the third quarter of 2021 (9,939 boepd in Q2 2021), of which 13,021 boepd was in Norway and 80 boepd in the UK (9,362 boepd and 577 boepd in Q2 2020). Resumption of gas production at the Marulk and Alve fields drove the output increase in Norway, while a temporary shutdown of the Blane field was behind the low UK third quarter contribution.

DNO's active North Sea exploration program notched up a success in the third quarter with appraisal drilling on the 2020 Bergknapp discovery (DNO 30 percent) resulting in a 35 percent upgrade of DNO's recoverable resource estimate. Also during the quarter, DNO made an oil discovery on the Gomez prospect (DNO 65 percent and operator). Due to uncertainty of producibility, no estimate of recoverable volumes has been established pending further analysis. Another third quarter 2021 appraisal well, Black Vulture (DNO 32 percent), was dry.

DNO-operated plugging and abandonment operations of three wells at the shut-down Oselvar field in Norway were completed during the quarter while the decommissioning campaign at DNOoperated Schooner and Ketch fields in the UK continued.

Due to capital prioritization and risk review, DNO exited the Fogelberg discovery license and shelved the Trym South project (DNO 50 percent and operator) during the quarter. DNO continues to evaluate Iris/Hades (DNO 30 percent), Orion/Syrah (DNO 20 percent) and Gjøk (DNO 32 percent) discoveries for project sanction in 2022.

The Brasse development (DNO 50 percent and operator) is on track for a 2022 project sanction with DNO recently entering into a strategic framework agreement with Technip FMC covering subsea deliveries (SURF and SPS).

Financial review

Revenues, operating profit and cash

Revenues in the third quarter stood at USD 253.5 million, up from USD 184.3 million in the previous quarter. Kurdistan generated revenues of USD 149.3 million (USD 141.2 million in the previous quarter), while the North Sea generated revenues of USD 104.1 million (USD 43.1 million in the previous quarter). The increase in revenues was driven by higher North Sea volumes, mainly higher cargo liftings from the Ula area fields and higher gas production at the Alve and Marulk fields combined with higher oil and gas prices.

The Group reported an operating profit of USD 65.4 million in the third quarter, up from USD 60.9 million in the previous quarter mainly driven by higher revenues, partly offset by increase in cost of goods sold and higher impairments and expensed exploration.

The Group ended the quarter with a cash balance of USD 585.7 million and USD 360.3 million in net interest-bearing debt, compared to USD 477.1 million and USD 472.5 million at yearend 2020, respectively.

Cost of goods sold

In the third quarter, the cost of goods amounted to USD 105.6 million, up from USD 86.6 million in the previous quarter. The increase in cost of goods sold was mainly driven by a reduction in the North Sea net underlift position due to higher cargo liftings (compared to a build-up of the underlift in the previous quarter), partly offset by higher valuation of the underlift as of Q3 2021.

Lifting costs

Lifting costs stood at USD 48.0 million in the third quarter, compared to USD 48.1 million in the previous quarter. In Kurdistan, the average lifting cost during the third quarter was USD 3.4 per barrel. In the North Sea, the average lifting cost during the third quarter stood at USD 19.2 per barrel of oil equivalent (boe).

	Quarters			First nine months	Full-Year
USD million	Q3 2021	Q2 2021	Q3 2020	2021	2020	2020
Kurdistan	24.9	26.5	18.7	73.4	65.7	94.5
North Sea	23.1	21.6	20.7	66.6	71.9	86.6
Total	48.0	48.1	39.4	140.0	137.5	181.1

(USD/boe)	Q3 2021	Quarters Q2 2021	Q3 2020	2021	First nine months 2020	Full-Year 2020
Kurdistan	3.4	3.5	2.4	3.3	2.9	3.1
North Sea	19.2	23.9	12.7	19.2	14.5	13.6
Average	5.7	5.7	4.2	5.4	5.0	4.9

Depreciation, depletion and amortization (DD&A)

DD&A from the Group's oil and gas production assets amounted to USD 49.6 million in the third quarter, compared to USD 47.2 million in the previous quarter. The increase in DD&A was driven by higher net production from the North Sea.

		Quarters		First nine months	Full-Year
USD million	Q3 2021	Q2 2021	Q3 2020	2021	2020	2020
Kurdistan	29.0	29.7	48.5	89.0	182.1	234.9
North Sea	20.6	17.5	31.0	59.1	91.7	116.3
Total	49.6	47.2	79.4	148.1	273.8	351.2

		Quarters		First nine months	Full-Year
(USD/boe)	Q3 2021	Q2 2021	Q3 2020	2021	2020	2020
Kurdistan	11.8	11.8	17.2	11.8	17.9	17.7
North Sea	17.1	19.4	19.0	17.0	18.5	18.3
Average	13.5	13.8	17.8	13.4	18.1	17.9

Exploration costs expensed

In the third quarter, the exploration costs expensed amounted to USD 36.4 million, up from USD 26.9 million in the previous quarter. The increase in expensed exploration costs was mainly due to expensing of the Black Vulture appraisal well at the Alve license (PL159B).

	Quarters			First nine months	Full-Year
USD million	Q3 2021	Q2 2021	Q3 2020	2021	2020	2020
Kurdistan	0.9	0.4	0.4	1.6	0.9	1.6
North Sea	35.5	26.5	8.3	72.2	39.5	54.4
Total	36.4	26.9	8.7	73.8	40.5	55.9

Acquisition and development costs

Acquisition and development costs stood at USD 80.7 million in the third quarter, of which USD 22.8 million were in Kurdistan and USD 58.0 million in the North Sea. Acquisition and development costs in the third quarter were driven by higher capitalized exploration in the North Sea.

		Quarters		First nine months	Full-Year
USD million	Q3 2021	Q2 2021	Q3 2020	2021	2020	2020
Kurdistan	22.8	19.5	8.6	56.1	71.5	92.6
North Sea	58.0	40.9	18.6	135.8	84.3	114.5
Other	-	-	-	-	0.8	0.9
Total	80.7	60.4	27.2	191.9	156.6	207.9

Consolidated statements of comprehensive income

		Quarters			First nine months
(unaudited, in USD million)	Note	Q3 2021	Q3 2020	2021	2020	2020
Revenues	2,3	253.5	163.0	607.6	440.7	614.9
Cost of goods sold	4	-105.6	-158.1	-278.0	-450.9	-590.0
Gross profit		147.8	4.9	329.6	-10.2	24.9
Other income/-expenses		-	-	0.2	0.2	-
Administrative expenses		-4.6	-1.7	-6.7	-5.3	-4.8
Other operating expenses		-1.1	-0.4	-3.7	-1.7	-2.7
Impairment oil and gas assets	7	-40.3	-202.2	-52.8	-243.0	-276.0
Exploration expenses	5	-36.4	-8.7	-73.8	-40.5	-55.9
Profit/-loss from operating activities		65.4	-208.1	192.7	-300.4	-314.5
Financial income	9	6.3	0.3	24.2	2.4	19.8
Financial expenses	9,10	-34.9	-21.8	-101.7	-89.3	-131.0
Profit/-loss before income tax		36.9	-229.6	115.2	-387.3	-425.8
Tax income/-expense	6	-6.0	107.1	23.8	161.7	139.8
Net profit/-loss		30.9	-122.5	139.0	-225.6	-285.9
Other comprehensive income
Currency translation differences		-8.8	19.3	-9.0	-46.9	-3.6
Items that may be reclassified to profit or loss in later periods		-8.8	19.3	-9.0	-46.9	-3.6
Net fair value changes from financial instruments	8	0.1	-1.6	5.5	-12.1	-8.4
Items that are not reclassified to profit or loss in later periods		0.1	-1.6	5.5	-12.1	-8.4
Total other comprehensive income, net of tax		-8.7	17.7	-3.6	-59.0	-12.0
Total comprehensive income, net of tax		22.2	-104.9	135.5	-284.6	-298.0
Net profit/-loss attributable to:
Equity holders of the parent		30.9	-122.5	139.0	-225.6	-285.9
Total comprehensive income attributable to:
Equity holders of the parent		22.2	-104.9	135.5	-284.6	-298.0
Earnings per share, basic (USD per share)		0.03	-0.13	0.14	-0.23	-0.29
Earnings per share, diluted (USD per share)		0.03	-0.13	0.14	-0.23	-0.29
Weighted average number of shares outstanding (excluding treasury shares) (millions)		975.43	975.43	975.43	975.83	975.73

Consolidated statements of financial position

(unaudited, USD million) Note 2021 2020 2020 Non-current assets Goodwill 7 120.8 178.8 162.0 Deferred tax assets 6 37.6 58.1 47.4 Other intangible assets 7 382.0 278.6 308.6 Property, plant and equipment 7 1,149.6 1,139.9 1,174.1 Financial investments 8 18.1 8.9 12.6 Other non-current receivables 9 71.1 - 182.4 Tax receivables 6 - 12.7 - Total non-current assets 1,779.2 1,677.0 1,887.1 Current assets Inventories 4 34.1 39.1 41.9 Trade and other receivables 9 453.4 409.8 239.6 Tax receivables 6 111.3 228.0 63.1 Cash and cash equivalents 585.7 373.0 477.1 Total current assets 1,184.5 1,049.9 821.6 TOTAL ASSETS 2,963.7 2,726.9 2,708.7 EQUITY AND LIABILITIES At 30 Sep At 31 Dec (unaudited, USD million) Note 2021 2020 2020 Equity Shareholders' equity 981.1 859.0 845.6 Total equity 981.1 859.0 845.6 Non-current liabilities Deferred tax liabilities 6 273.2 139.3 178.8 Interest-bearing liabilities 10 911.6 942.3 934.2 Lease liabilities 11 13.5 13.4 13.9 Provisions for other liabilities and charges 11 398.1 406.1 440.1 Total non-current liabilities 1,596.5 1,501.2 1,566.9 Current liabilities Trade and other payables 250.1 188.3 180.3 Income tax payable 6 - - - Current interest-bearing liabilities 10 16.9 82.5 - Current lease liabilities 11 17.6 3.2 3.8 Provisions for other liabilities and charges 11 101.4 92.7 112.0 Total current liabilities 386.1 366.6 296.1 Total liabilities 1,982.6 1,867.8 1,863.0 TOTAL EQUITY AND LIABILITIES 2,963.7 2,726.9 2,708.7	ASSETS	At 30 Sep	At 31 Dec

Consolidated cash flow statement

		Quarters		First nine months		Full-Year
(unaudited, in USD million)	Note	Q3 2021	Q3 2020	2021	2020	2020
Operating activities
Profit/-loss before income tax
Adjustments to add/-deduct non-cash items:		36.9	-229.6	115.2	-387.3	-425.8
Exploration cost capitalized in previous years carried to cost	5
Depreciation, depletion and amortization	4	11.2	-	11.2	0.4	0.4
Impairment oil and gas assets	7	51.0	82.0	152.7	281.6	361.4
Amortization of borrowing issue costs		40.3	202.2	52.8	243.0	276.0
Accretion expense on ARO provisions		2.7	1.1	8.4	5.8	7.6
Interest expense		4.3	1.8	13.4	12.4	17.0
Interest income		17.7	20.5	55.1	64.9	87.3
Other		-0.4	-0.3	-1.0	-2.4	-5.4
Change in working capital items and provisions:		2.1	-2.7	0.8	-6.1	1.1
- Inventories
- Trade and other receivables	9	0.4	-8.1	10.0	-11.0	-13.7
- Trade and other payables		-52.0	8.9	-120.8	68.7	41.1
- Provisions for other liabilities and charges		30.3	-75.7	72.6	-100.6	-108.5
Cash generated from operations		-2.3	5.1	-0.6	-2.1	-2.7
Tax refund received		142.1	5.0	369.9	167.3	235.8
Interest received		36.9	24.5	83.3	24.5	236.3
Interest paid		0.4	0.3	1.1	1.9	2.7
Net cash from/-used in operating activities		-16.5	-21.3	-55.3	-65.9	-85.7
		162.9	8.5	399.0	127.8	389.1
Investing activities
Purchases of intangible assets		-42.3	-9.0	-58.3	-40.4	-45.7
Purchases of tangible assets		-38.4	-18.2	-133.6	-116.1	-162.2
Payments for decommissioning		-28.1	-4.4	-72.7	-28.3	-30.7
Net cash from/-used in investing activities		-108.8	-31.5	-264.5	-184.8	-238.6
Financing activities
Proceeds from borrowings	10
Repayment of borrowings	10	400.0	-	400.0	152.3	152.3
Payment of debt issue costs		-302.8	-29.4	-402.8	-187.9	-290.3
Purchase of treasury shares		-15.6	-	-15.6	-	-
Payments of lease liabilities		-	-	-	-17.8	-17.8
Net cash from/-used in financing activities		-2.9	-1.3	-6.3	-2.3	-3.4
		78.7	-30.8	-24.7	-55.7	-159.1
Net increase/-decrease in cash and cash equivalents		132.8	-53.8	109.8	-112.7	-8.6
Cash and cash equivalents at beginning of the period		454.2	426.8	477.1	485.7	485.7
Exchange gain/-losses on cash and cash equivalents		-1.3	-	-1.1	-	-
Cash and cash equivalents at the end of the period		585.7	373.0	585.7	373.0	477.1
Of which restricted cash		12.6	12.5	12.6	12.5	13.6

Consolidated statement of changes in equity

				Other comprehensive income
			Other paid-in	Fair value	Currency
(unaudited, in USD million)	Share capital	Share premium	capital/Other reserves	changes equity instruments	translation differences	Retained earnings	Total equity
Total shareholders' equity as of 31 December 2019	33.3	247.7	-30.2	44.5	-61.4	927.3	1,161.3
Fair value changes from equity instruments	-	-	-	-12.1	-	-	-12.1
Currency translation differences	-	-	-	-	-46.9	-	-46.9
Other comprehensive income/-loss	-	-	-	-12.1	-46.9	-	-59.0
Profit/-loss for the period	-	-	-	-	-	-225.6	-225.6
Total comprehensive income	-	-	-	-12.1	-46.9	-225.6	-284.7
Purchase of treasury shares	-0.4	-	-17.3	-	-	-	-17.7
Transactions with shareholders	-0.4	-	-17.3	-	-	-	-17.7
Total shareholders' equity as of 30 September 2020	32.9	247.7	-47.5	32.4	-108.3	701.7	859.0

				Other comprehensive income
	Share	Share	Other paid-in capital/Other	Fair value changes equity	Currency translation	Retained	Total
(unaudited, in USD million)	capital	premium	reserves	instruments	differences	earnings	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	-	-3.6
Profit/-loss for the period	-	-	-			139.0	139.0
Total comprehensive income	-	-	-	5.5	-9.0	139.0	135.5
Purchase of treasury shares	-	-	-	-	-	-	-
Transactions with shareholders	-	-	-	-	-	-	-
Total shareholders' equity as of 30 September 2021	32.9	247.7	-	41.6	-74.0	733.0	981.1

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 2020.

The interim financial information for 2021 and 2020 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 2020.

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 2020.

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 2021					reporting	allocated/	Total
USD million	Note	Kurdistan	North Sea	Other		segments eliminated	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
Profit/-loss from operating activities		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)

Third quarter ending 30 September 2020 USD million	Note	Kurdistan	North Sea	Other	Total reporting	Un allocated/ segment eliminated	Total Group
Income statement information
Revenues	3	84.9	78.1	-	163.0	-	163.0
Inter-segment revenues		-	0.4	-	0.4	-0.4	-
Cost of goods sold	4	-68.4	-89.1	-	-157.5	-0.6	-158.1
Gross profit		16.5	-10.6	-	5.9	-1.0	4.9
Profit/-loss from operating activities		15.9	-220.7	-1.3	-206.1	-2.0	-208.1
Financial income/-expense (net)	10						-21.5
Tax income/-expense	6	-	107.1	-	107.1	-0.1	107.1
Net profit/-loss							-122.5
Financial position information
Non-current assets		680.6	974.7	-	1,655.3	21.7	1,677.0
Current assets		341.2	422.0	4.3	767.5	282.3	1,049.9
Total assets		1,021.8	1,396.7	4.3	2,422.8	304.0	2,726.9
Non-current liabilities		59.2	723.8	0.3	783.2	717.9	1,501.2
Current liabilities		80.9	247.0	28.4	356.4	10.3	366.6
Total liabilities		140.1	970.8	28.7	1,139.6	728.2	1,867.8

Note 2 | Segment information (continued)

					Total	Un
First nine months ending 30 September 2021 USD million	Note	Kurdistan	North Sea	Other	reporting	allocated/ segment eliminated	Total 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
Profit/-loss from operating activities		248.3	-44.9	-3.3	200.1	-7.4	192.7
Financial income/-expense (net)	9,10						-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

					Total	Un
First nine months ending 30 September 2020					reporting	allocated/	Total
USD million	Note	Kurdistan	North Sea	Other		segment eliminated	Group
Income statement information
Revenues	3	273.3	167.4	-	440.7	-	440.7
Inter-segment sales		-	1.0	-	1.0	-1.0	-
Cost of goods sold	4	-251.3	-197.5	-	-448.7	-2.1	-450.9
Gross profit		22.0	-29.0	-	-7.0	-3.1	-10.2
Profit/-loss from operating activities		20.0	-318.1	-4.5	-302.6	2.2	-300.4
Financial income/-expense (net)	10						-86.9
Tax income/-expense	6	-	163.5	0.4	164.0	-2.2	161.7
Net profit/-loss							-225.6
Financial position information
Non-current assets		680.6	974.7	-	1,655.3	21.7	1,677.0
Current assets		341.2	422.0	4.3	767.5	282.3	1,049.9
Total assets		1,021.8	1,396.7	4.3	2,422.8	304.0	2,726.9
Non-current liabilities		59.2	723.8	0.3	783.2	717.9	1,501.2
Current liabilities		80.9	247.0	28.4	356.4	10.3	366.6
Total liabilities		140.1	970.8	28.7	1,139.6	728.2	1,867.8

Note 3 | Revenues

	Quarters		First nine months		Full-Year
USD million	Q3 2021	Q3 2020	2021	2020	2020
Sale of oil	207.7	149.7	524.0	408.1	566.6
Sale of gas	36.9	5.7	66.1	15.2	27.5
Sale of natural gas liquids (NGL)	7.6	4.4	15.0	11.6	14.8
Tariff income	1.3	3.2	2.5	5.8	6.0
Total revenues from contracts with customers	253.5	163.0	607.6	440.7	614.9
Sale of oil (bopd)	35,204	46,869	33,380	48,243	48,139
Sale of gas (boepd)	4,540	4,100	4,056	4,054	4,548
Sale of natural gas liquids (NGL) (boepd)	1,659	1,889	1,201	1,831	1,695
Total sales volume (boepd)	41,402	52,857	38,637	54,128	54,383

Note 4 | Cost of goods sold/ Inventory

	Quarters		First nine months		Full-Year
USD million	Q3 2021	Q3 2020	2021	2020	2020
Lifting costs	-48.0	-39.4	-140.0	-137.5	-181.1
Tariff and transportation expenses	-8.9	-9.6	-25.8	-28.0	-36.2
Production costs based on produced volumes	-56.8	-48.9	-165.8	-165.5	-217.3
Movement in overlift/underlift	2.1	-27.1	40.5	-3.8	-11.3
Production costs based on sold volumes	-54.7	-76.1	-125.3	-169.3	-228.6
Depreciation, depletion and amortization	-51.0	-82.0	-152.7	-281.6	-361.4
Total cost of goods sold	-105.6	-158.1	-278.0	-450.9	-590.0

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	2021	2020	2020
Spare parts	34.1	39.1	41.9
Total inventory	34.1	39.1	41.9

Total inventory of USD 34.1 million as of 30 September 2021 was related to Kurdistan (USD 18.5 million) and the North Sea (USD 15.6 million).

Note 5 | Exploration expenses

	Quarters		First nine months		Full-Year
USD million	Q3 2021	Q3 2020	2021	2020	2020
Exploration expenses (G&G and field surveys)	-2.1	-3.1	-14.5	-11.5	-16.1
Seismic costs	-5.0	-1.8	-20.2	-2.6	-2.9
Exploration cost capitalized in previous years carried to cost	-11.2	-	-11.2	-0.4	-0.4
Exploration costs capitalized this year carried to cost	-13.1	-0.6	-13.1	-11.2	-17.1
Other exploration cost expensed	-4.9	-3.2	-14.7	-14.7	-19.5
Total exploration expenses	-36.4	-8.7	-73.8	-40.5	-55.9

Exploration costs expensed in the third quarter were mainly related to exploration activities in the North Sea.

Note 6 | Income taxes

	Quarters		First nine months		Full-Year
USD million	Q3 2021	Q3 2020	Q3 2021	Q3 2020	2020
Tax income/-expense
Change in deferred taxes	-46.8	81.2	-111.3	49.1	11.1
Income tax receivable/-payable	40.8	25.9	135.1	112.7	128.8
Total tax income/-expense	-6.0	107.1	23.8	161.7	139.8

	At 30 Sep		At 31 Dec
USD million	2021	2020	2020
Income tax receivable/-payable
Tax receivables (non-current) 12.703	-	12.7	-
Tax receivables (current) 227.987	111.3	228.0	63.1
Income tax payable 0	-	-	-
Net tax receivable/-payable 240.69	111.3	240.7	63.1
Deferred tax assets/-liabilities
Deferred tax assets 58.126	37.6	58.1	47.4
Deferred tax liabilities -139.332	-273.2	-139.3	-178.8
Net deferred tax assets/-liabilities 58.126	-235.6	-81.2	-131.4

The tax income, tax receivables and recognized deferred tax assets/-liabilities relate to activity on the Norwegian Continental Shelf (NCS) and the UK Continental Shelf (UKCS). Current tax receivables consist of tax value of incurred losses on the NCS for 2021 (USD 81.8 million) and tax refund of decommissioning spend on the UKCS for 2020 and 2021 (USD 29.6 million). During the first nine months of 2021, DNO has received tax refunds of USD 83.3 million in Norway in relation to tax losses incurred in 2020 and 2021. The refund of tax losses on the NCS incurred in 2021 will be paid out in six instalments every two months with the first instalment received on 1 August 2021. The decommissioning tax refund on the UKCS for 2021 of USD 14.4 million is expected during the third quarter of 2022. Following the end of third quarter, DNO received the second instalment for tax losses on the NCS for 2021 of USD 37.5 million and decommissioning tax refund on the UKCS for 2020 of USD 15.3 million.

On 19 June 2020, the Norwegian Parliament approved certain temporary changes to the taxation of oil and gas companies operating on the NCS with effect from the income year 2020. The changes comprise of immediate expensing of investments in the special tax basis, increased uplift from 20.8 percent over four years to 24.0 percent in the first year and cash refund of tax value of losses incurred in the income years 2020 and 2021. The temporary changes will also apply to investments where the Plan for Development and Operation (PDO) is delivered within 31 December 2022 and approved within 31 December 2023.

During August 2021, the Norwegian Government proposed certain changes to the taxation of oil and gas companies operating on the NCS with effect from 2022. The companies will be able to expense the investments immediately in the special tax basis and receive cash refund of tax value of all losses in the special tax basis. The uplift on investments is proposed discontinued. The ordinary corporate tax will be 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 will not be eligible for refund but can be carried forward. Moreover, tax value of unused uplift and carried forward losses as of yearend 2021 will be paid out. Provisions under the temporary changes extending beyond 2021 will not be impacted. As of the date of issuing this interim report, the proposal has not been approved by the Norwegian Parliament and may be subject to adjustments. If the proposal is approved, limited impact is estimated on DNO's asset values.

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 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 2021	Q3 2020	2021	2020	2020
Additions of other intangible assets	42.3	9.0	58.3	40.4	45.7
Additions of other intangible assets through license acquistion	35.2	-	35.2	-	-
Additions of PP&E	41.5	37.8	149.3	135.7	192.1
Additions of RoU assets	-	3.0	14.4	5.9	7.0
Impairment oil and gas assets	-40.3	-202.2	-52.8	-243.0	-276.0

Additions of intangible assets are related to capitalized exploration costs, license interests and administrative software. Additions of PP&E are related to development assets, production assets including changes in estimate of asset retirement, and other PP&E. Additions of right-of-use (RoU) assets are related to lease contracts under IFRS 16 Leases (presented as part of the PP&E balance sheet item), see also Note 11.

Additions of other intangible assets through license acquisition relate to DNO's acquisition of ExxonMobil Kurdistan Region of Iraq Limited's (ExxonMobil) remaining 32 percent interest in the Baeshiqa license. As consideration, DNO has covered ExxonMobil's share of exploration costs since January 2019 up to KRG's approval of the acquisition in August 2021 and the seller will receive a payment of USD 15 million. Following KRG's approval of the acquisition, DNO's payments for ExxonMobil's share of exploration costs have been transferred to Other intangible assets, previously presented under Trade and other receivables.

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 2021, a net impairment charge of USD 40.3 million (USD 42.9 million post-tax) was recognized driven by updated assessment of future production and cost profiles (Ula area, Fenja, Trym area), and updated assessment of cost estimates for decommissioning (Schooner and Ketch fields, Oselvar field, other).

USD million			Income statement:			Balance sheet:
CGU, Segment	Recoverable amount (post-tax)	Impairment -charge/ reversal (pre-tax)	Tax income/ -expense	Impairment -charge/ reversal (post-tax)	Goodwill	Asset retirement obligations	Deferred tax asset/ -liability	Currency effects
Fenja, North Sea	59.8	-3.0	-	-3.0	-2.8	-	-	0.1
Trym area, North Sea	5.7	-7.7	-	-7.7	-7.5	-	-	0.2
Ula area, North Sea	191.3	-26.5	-	-26.5	-26.3	-	-	0.2
Schooner and Ketch, North Sea	-	-13.9	4.0	-9.8	-	13.6	3.9	0.3
Oselvar, North Sea	-	8.5	-6.7	1.9	-	-8.4	-6.6	-0.1
Other CGUs, North Sea	-	2.2	-	2.2	-	-2.2	-	-
Total	256.8	-40.3	-2.6	-42.9	-36.6	3.0	-2.6	0.7

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. In the impairment tests, the Brent oil price assumptions were based on the forward curve and observable broker and analyst consensus (Q4 2021: USD 73.1, 2022: USD 70.8, 2023: USD 68.4 and 2024: USD 69.4 per barrel in nominal terms). From 2025, the Brent oil price was based on the Group's long-term price assumptions (USD 65.0 per barrel, real terms), unchanged from yearend 2020.

Sensitivity analysis shows that a 15 percent decrease in the Brent oil price assumption and a 5 percent decrease in the estimated reserves and resources over the lifetime of the Group's assets that were partially impaired during the quarter (above), would lead to an estimated additional impairment charge of USD 47.0 million (post-tax) and USD 19.5 million (post-tax), respectively. This sensitivity analysis is for indicative purposes only and has been prepared on the assumption that all other factors would remain unchanged. The post-tax nominal discount rates (WACC) applied in the impairment tests were consistent with the rates applied at yearend 2020.

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		Full-Year
USD million	Q3 2021	Q3 2020	2021	2020	2020
Beginning of the period	18.0	10.5	12.6	21.0	21.0
Fair value changes through other comprehensive income (FVTOCI)	0.1	-1.6	5.5	-12.1	-8.4
Total financial investments end of the period	18.1	8.9	18.1	8.9	12.6

Financial investments include the following:

	At 30 Sep		At 31 Dec
USD million	2021	2020	2020
Listed securities:
RAK Petroleum plc	18.1	8.9	12.6
Total financial investments	18.1	8.9	12.6

As of 30 September 2021, the Company held a total of 15,849,737 shares in RAK Petroleum plc. RAK Petroleum plc is listed on the Oslo Stock Exchange. Through its subsidiary, RAK Petroleum Holdings B.V., RAK Petroleum plc is the largest shareholder in DNO ASA with 44.94 percent of the total issued shares. 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	2021	2020	2020
Trade debtors (non-current portion)	69.4	-	182.0
Other non-current receivables	1.7	-	0.4
Total other non-current receivables	71.1	-	182.4
Trade debtors	290.1	277.0	96.2
Underlift	65.7	32.0	27.4
Other short-term receivables	97.6	100.8	115.9
Total trade and other receivables	453.4	409.8	239.6

Total book value of trade debtors of USD 359.5 million (current and non-current portion) as of 30 September 2021 relates mainly to the Tawke license arrears for 2019 and 2020 entitlement and override invoices (USD 201.4 million), and outstanding invoices for Tawke license crude oil deliveries for the months July through September 2021 (USD 149.3 million). See Note 12.

In December 2020, a plan was put in place by the KRG to pay the international oil companies operating in Kurdistan 50 percent of incremental revenue in any month in which Brent prices exceed USD 50 per barrel towards the arrears for 2019 and 2020. In May 2021, the KRG informed the international oil companies of revised terms reducing the payment of the arrears to 20 percent of incremental revenue in any month in which Brent prices exceed USD 50 per barrel. The KRG also advised that all international oil company invoices, including towards the arrears, will be settled within 60 days of receipt. The Company expects at a minimum to recover the full nominal value of the withheld receivables, including but not limited to interest payments reflecting the Company's cost of debt.

At yearend 2020, due to the IFRS 9 requirement to incorporate the time value of money, the Company reduced the book value of these receivables by USD 16.0 million when comparing the book value of the arrears to the estimated present value. As of 30 September 2021, in line with IFRS 9, the Company made a re-run of the estimated present value, updated Brent price assumptions and other considerations resulting in a net increase in the book value of the arrears by USD 5.9 million (USD 14.9 million year to date). Moreover, the classification of the receivables (current/non-current portion) was updated accordingly. The calculation of present value in accordance with IFRS 9, takes into account the most recent production forecasts for the Tawke license and the Company's Brent price assumptions to determine the expected timing of payments towards the arrears plus contractual interests under IFRS 9, and reflects the probability-weighted amount for a range of possible scenarios including probability-weighted Brent price scenarios with a probability assigned to each. The discount rate applied reflects the Company's cost of debt.

The underlift receivable of USD 65.7 million as of 30 September 2021 relates mainly to North Sea underlifted volumes, valued at the lower of production cost including depreciation and the market value at the reporting date. 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	2021	2020	2020
Non-current
Bond loan (ISIN NO0010823347)	DNO02	USD	-	-	-	-	400.0	400.0
Bond loan (ISIN NO0010852643)	DNO03	USD	397.2	8.375 %	29/05/24	397.2	400.0	400.0
Bond loan (ISIN NO0011088593)	-	USD	400.0	7.875 %	09/09/26	400.0	-	-
Bond loan (ISIN NO0010811268)	FAPE01	USD	-	-	-	-	8.0	-
Capitalized borrowing issue costs						-17.5	-17.0	-15.4
Reserve based lending facility		USD	350.0	see below	see below	131.9	151.3	149.6
Total non-current interest-bearing liabilities						911.6	942.3	934.2
Current
Exploration financing facility		NOK	250.0	see below	see below	-	82.5	-
Reserve based lending facility (current)		USD	350.0	see below	see below	16.9	-	-
Total current interest-bearing liabilities						16.9	82.5	-
Total interest-bearing liabilities						928.5	1,024.8	934.2

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

	At 1 Jan	Cash		Non-cash changes
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

	At 1 Jan	Cash		Non-cash changes		At 30 Sep
USD million	2020		flows Amortization	Currency	Reclassification	2020
Bond loans	821.2	-13.2	-	-	-	808.0
Bond loans (current)	140.0	-139.8	-0.2	-	-	-
Borrowing issue costs	-23.0	-	6.0	-	-	-17.0
Reserve based lending facility	37.8	114.2	-	-0.7	-	151.3
Exploration financing facility	85.6	3.2	-	-6.3	-	82.5
Total	1,061.6	-35.6	5.8	-7.0	-	1,024.8

On 1 September 2021, DNO ASA completed the placement of USD 400 million of a new, five-year senior unsecured bond issued at 100 percent at par with a coupon rate of 7.875 percent. In connection with the bond placement, the Company agreed to buy back USD 154 million in nominal value of DNO02 at 103.7 percent of par plus accrued interest. The remaining DNO02 bonds were called and settled after completion of the new bond at 103.5 percent of par plus accrued interest. The financial covenants of the bonds issued by DNO ASA require minimum USD 40 million of liquidity, and that the Group maintains either an equity ratio of 30 percent or a total equity of a minimum of USD 600 million.

During the third quarter, DNO ASA has acquired USD 2.8 million of DNO03 bonds at a price range of 103.9 to 104.0 percent of par plus accrued interest. Facility and carrying amount for the bonds is shown net of bonds held by the Company.

The Group has available a revolving exploration financing facility (EFF) in an aggregate amount of NOK 250 million with an uncommitted accordion option of NOK 750 million. The interest rate equals NIBOR plus a margin of 1.70 percent. Utilizations can be made until 31 December 2022. Due to temporary changes to the taxation of oil and gas companies in Norway, the Group has chosen to not utilize the EFF in relation to exploration spend in 2021.

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 2021 is USD 226 million. Amount utilized as of the reporting date is disclosed in the table above. In addition, USD 87.9 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 2020.

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

	At 30 Sep		At 31 Dec
USD million	2021	2020	2020
Non-current
Asset retirement obligations (ARO)	394.4	403.1	436.6
Other long-term provisions and charges	3.7	3.0	3.4
Lease liabilities	13.5	13.4	13.9
Total non-current provisions for other liabilities and charges and lease liabilities	411.6	419.5	453.9
Current
Asset retirement obligations (ARO)	74.4	68.6	86.7
Other provisions and charges	27.0	24.1	25.3
Current lease liabilities	17.6	3.2	3.8
Total current provisions for other liabilities and charges and lease liabilities	119.0	96.0	115.8
Total provisions for other liabilities and charges and lease liabilities	530.7	515.5	569.7

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 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 DNO's name as the operator of the licenses at the initial signing and subsequently partly allocated to the license partners. 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
USD million	2021	2020	2020
Within one year	18.7	4.7	4.7
Two to five years	14.0	14.3	13.8
After five years	0.3	1.2	1.1
Total undiscounted lease liabilities end of the period	33.0	20.2	19.6

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

Note 12 | Subsequent events

Payments from Kurdistan

Following end of Q3 2021, DNO has received net USD 62.6 million for July 2021 and USD 57.7 million for August 2021 towards the respective month's entitlement share of oil deliveries to the export market from the Tawke license, override payments equivalent to three percent of gross revenues under the August 2017 receivables settlement agreement and arrears relating to withheld payment of 2019 and 2020 entitlement and override invoices.

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 2021	Q3 2020	2021	2020	2020
Revenues	253.5	163.0	607.6	440.7	614.9
Lifting costs	-48.0	-39.4	-140.0	-137.5	-181.1
Tariff and transportation	-8.9	-9.6	-25.8	-28.0	-36.2
Movement in overlift/underlift	2.1	-27.1	40.5	-3.8	-11.3
Exploration expenses	-36.4	-8.7	-73.8	-40.5	-55.9
Administrative expenses	-4.6	-1.7	-6.7	-5.3	-4.8
Other operating income/expenses	-1.1	-0.4	-3.5	-1.5	-2.7
EBITDA	156.6	76.1	398.3	224.1	322.8

EBITDAX

USD million	Q3 2021	Q3 2020	2021	2020	2020
EBITDA	156.6	76.1	398.3	224.1	322.8
Exploration expenses	36.4	8.7	73.8	40.5	55.9
EBITDAX	193.0	84.8	472.0	264.6	378.8

Netback

USD million	Q3 2021	Q3 2020	2021	2020	2020
EBITDA	156.6	76.1	398.3	224.1	322.8
Tax refund received/-taxes paid	36.9	24.5	83.3	24.5	236.3
Netback	193.5	100.6	481.6	248.6	559.1
	Q3 2021	Q3 2020	2021	2020	2020
Netback (USD million)	193.5	100.6	481.6	248.6	559.1
Net production (MMboe)	8.5	9.5	25.8	27.6	36.6
Netback (USD/boe)	22.9	10.6	18.7	9.0	15.3
Effective Q1 2021, the Group reports its net production from the Tawke license in Kurdistan based on its percentage ownership in the license. Comparison figures have been updated.
Lifting costs	Q3 2021	Q3 2020	2021	2020	2020
Lifting costs (USD million)	-48.0	-39.4	-140.0	-137.5	-181.1
Net production (MMboe)	8.5	9.5	25.8	27.6	36.6
Lifting costs (USD/boe)	5.7	4.2	5.4	5.0	4.9

Alternative performance measures (continued)

Acquisition and development costs

	Quarters		First nine months		Full-Year
USD million	Q3 2021	Q3 2020	2021	2020	2020
Purchases of intangible assets	-42.3	-9.0	-58.3	-40.4	-45.7
Purchases of tangible assets	-38.4	-18.2	-133.6	-116.1	-162.2
Acquisition and development costs	-80.7	-27.2	-191.9	-156.6	-207.9
Acquisition and development costs exclude estimate changes on asset retirement obligations.
Operational spend
USD million	Q3 2021	Q3 2020	2021	2020	2020
Lifting costs	-48.0	-39.4	-140.0	-137.5	-181.1
Tariff and transportation expenses	-8.9	-9.6	-25.8	-28.0	-36.2
Exploration expenses	-36.4	-8.7	-73.8	-40.5	-55.9
Exploration costs capitalized in previous years carried to cost (Note 5)	11.2	-	11.2	0.4	0.4
Acquisition and development costs	-80.7	-27.2	-191.9	-156.6	-207.9
Payments for decommissioning	-28.1	-4.4	-72.7	-28.3	-30.7
Operational spend	-190.8	-89.3	-492.9	-390.5	-511.4
Free cash flow
USD million	Q3 2021	Q3 2020	2021	2020	2020
Net cash from/-used operating activites	162.9	8.5	399.0	127.8	389.1
Acquisition and development costs	-80.7	-27.2	-191.9	-156.6	-207.9
Payments for decommissioning	-28.1	-4.4	-72.7	-28.3	-30.7
Free cash flow	54.1	-23.1	134.4	-57.1	150.5
Effective Q3 2021, tax refund received/-taxes paid and net interest paid are included in this APM. Comparison figures have been updated.
Equity ratio
USD			2021	2020	2020
Equity			981.1	859.0	845.6
Total assets			2,963.7	2,726.9	2,708.7
Equity ratio			33.1%	31.5%	31.2%
Net debt
USD million			2021	2020	2020
Cash and cash equivalents including restricted cash			585.7	373.0	477.1
Bond loans and reserve based lending (Note 10)			946.0	959.3	949.6
Net cash/-debt			-360.3	-586.3	-472.5

Exploration financing facility has been excluded as it is covered by the exploration tax refund booked as an asset in the statement of financial position.

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.

Acquisition and development costs

Acquisition and development costs 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, acquisition and development costs 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 acquisition and development costs 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.

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