DNO ASA — Interim / Quarterly Report 2021

Feb 10, 2022

Cover photo: Signing of the Baeshiqa first phase development plan by the license Management Committee chairperson Dr Khazal Auzer (KRG) and vice chairperson Tom Allan (DNO)

Key figures

		Quarters			Full-Year
USD million	Q4 2021	Q3 2021	Q4 2020	2021	2020
Key financials
Revenues	396.5	253.5	174.2	1,004.1	614.9
Gross profit	231.4	147.8	35.1	561.0	24.9
Profit/-loss from operating activities	128.2	65.4	-14.2	320.9	-314.5
Net profit/-loss	64.8	30.9	-60.4	203.9	-285.9
EBITDA	208.8	156.6	98.7	606.9	322.8
EBITDAX	267.4	193.0	114.2	739.3	378.8
Netback	300.2	193.5	310.4	781.6	559.1
Operational spend	170.5	190.8	121.0	663.8	511.4
Acquisition and development costs	75.6	93.6	57.3	280.6	225.0
Exploration expenses	58.6	36.4	15.5	132.3	55.9
Production and Sales
Gross operated production (boepd)	107,472	105,179	110,176	108,713	110,282
Net production (boepd)	94,175	91,986	97,942	94,477	100,063
Sales volume (boepd)	52,655	41,402	55,140	42,171	54,382
Key performance indicators
Lifting costs (USD/boe)	5.1	5.7	4.8	5.3	4.9
Netback (USD/boe)	34.6	22.9	34.4	22.7	15.3

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

2021 operational highlights

• Net production to DNO's interest of 94,500 barrels of oil equivalent per day (boepd) in 2021 (94,200 boepd in Q4 2021), of which 81,500 barrels of oil per day (bopd) from the Kurdistan region of Iraq (80,600 in Q4 2021)
• North Sea contributed another 12,900 boepd (13,600 boepd in Q4 2021), down from 2020 levels due to natural decline, delayed new production and planned maintenance
• Five North Sea exploration wells led to four discoveries, of which two likely commercial
• Exited 2021 with net 2P reserves (proven plus probable) of 321 million barrels of oil equivalent (MMboe) and 2C contingent resources of 189 MMboe¹
• In Kurdistan, Baeshiqa license development approved and fast-tracked with early production expected before midyear 2022
• DNO had 90 licenses across its portfolio at yearend 2021 (23 operated), of which two in Kurdistan, 73 in Norway, 11 in the United Kingdom, two in the Netherlands, one in Ireland and one in Yemen; Awarded 10 additional APA licenses in Norway in January 2022

¹ Preliminary figures subject to final release

2021 financial highlights

• Record revenues topped USD 1 billion in 2021, up 63 percent from a year earlier, on back of high oil and gas prices and solid production
• North Sea revenue boosted by spot gas price exposure in strong European market
• Return to profitability with operating profit of USD 321 million
• Exited 2021 with net debt of USD 153 million, down from USD 473 million a year earlier
• Resumed dividend payments
• New USD 400 million five-year bond issued, refinancing prior bond facility, lowering average debt interest rate and extending maturities
• On a cash basis, received USD 537 million from Kurdistan in 2021 (USD 398 million towards entitlements, USD 48 million towards overrides and USD 90 million towards payment arrears)
• Yearend outstanding Kurdistan arrears of USD 169 million down from USD 259 million

Operational review

Production

Quarterly net production (boepd)

Net production by segment (boepd)

Gross operated Tawke license production including the Tawke and Peshkabir fields averaged 107,472 bopd during the fourth quarter, compared to 105,179 bopd in the previous quarter.

Net production during the fourth quarter stood at 94,175 boepd, compared to 91,986 boepd in the previous quarter. In Kurdistan, net production averaged 80,604 bopd, up from 78,884 bopd in the previous quarter related to higher production from the Peshkabir field. Net production from the North Sea averaged 13,571 boepd, up from 13,102 boepd in the previous quarter mainly driven by increased gas production from the Alve and Marulk fields.

Net entitlement (NE) production averaged 42,938 boepd during the fourth quarter, up from 39,851 boepd in the previous quarter.

Sales volume averaged 52,655 boepd during the quarter, up from 41,402 boepd in the previous quarter mainly driven by higher Tawke license entitlement and higher cargo liftings from the Brage and Ringhorne East fields. Net underlift position was 0.1 million barrels of oil equivalent (MMboe) as of Q4 2021 (1.0 MMboe as of Q3 2021).

Gross operated production

	Quarters			Full-Year
boepd	Q4 2021	Q3 2021	Q4 2020	2021	2020
Kurdistan	107,472	105,179	110,176	108,713	110,282
North Sea	-	-	-	-	-
Total	107,472	105,179	110,176	108,713	110,282

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

Net production

	Quarters			Full-Year
boepd	Q4 2021	Q3 2021	Q4 2020	2021	2020
Kurdistan	80,604	78,884	82,632	81,535	82,711
North Sea	13,571	13,102	15,309	12,942	17,352
Total	94,175	91,986	97,942	94,477	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 Full-Year
boepd	Q4 2021	Q3 2021	Q4 2020	2021	2020
Kurdistan	29,367	26,749	33,417	28,091	36,257
North Sea	13,571	13,102	15,309	12,942	17,352
Total	42,938	39,851	48,727	41,033	53,609

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

Sales volume

	Quarters			Full-Year
boepd	Q4 2021	Q3 2021	Q4 2020	2021	2020
Kurdistan	29,367	26,749	33,417	28,091	36,257
North Sea	23,289	14,653	21,723	14,080	18,125
Total	52,655	41,402	55,140	42,171	54,382

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 107,472 bopd during the fourth quarter of 2021 (105,179 bopd in Q3 2021). The Peshkabir field contributed 62,869 bopd (59,922 in Q3 2021) and the Tawke field contributed 44,602 bopd (45,257 in Q3 2021) during this period.

Drilling at the Tawke field resumed in the third quarter of 2021 after an 18-month pause. With few new wells, production decline has been partially offset by gas injection and workovers.

DNO's USD 110 million Peshkabir-Tawke gas project, which was commissioned in mid-2020, captured and injected 7.6 billion cubic feet (461,500 tonnes of CO2) of Peshkabir gas that would otherwise have been flared into the Tawke field in 2021.

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

Baeshiqa license

In the fourth quarter of 2021, the first phase field development plan for the Baeshiqa license was approved by the Kurdistan Regional Government (KRG), clearing the way for a fast-track project to deliver early production from previously drilled but suspended discovery wells. This is DNO's first new field development in Kurdistan since the Peshkabir startup in 2017.

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.

North Sea

Net production averaged 13,571 boepd in the North Sea during the fourth quarter of 2021 (13,102 boepd in Q3 2021), of which 13,223 boepd was in Norway and 348 boepd in the UK (13,021 boepd and 80 boepd in Q3 2021).

In 2021, North Sea production was down compared to 2020 due to natural decline, delayed new production and planned maintenance.

DNO maintained a high activity level drilling seven development wells and five exploration wells during the year. This resulted in four discoveries, of which two likely commercial, notably Røver Nord and the deeper Åre formation of the Bergknapp discovery made in 2020.

DNO-operated plugging and abandonment operations on the Oselvar field in Norway and Ketch field in the UK were completed during 2021.

Also in Norway, the DNO-operated Brasse project as well as the partner-operated Iris-Hades, Gjøk and Orion discoveries target 2022 project sanction, supporting the Company's North Sea growth ambitions.

Financial review

Revenues, operating profit and cash

Revenues in the fourth quarter stood at USD 396.5 million, up from USD 253.5 million in the previous quarter. Kurdistan generated revenues of USD 180.4 million (USD 149.3 million in the previous quarter), while the North Sea generated revenues of USD 216.1 million (USD 104.1 million in the previous quarter). The increase in revenues was primarily driven by higher cargo liftings at the Brage, Ringhorne East and Ula area fields, and increased gas production combined with rising gas prices.

The Group reported an operating profit of USD 128.2 million in the fourth quarter, up from USD 65.4 million in the previous quarter mainly driven by higher revenues, partly offset by higher cost of goods sold and expensed exploration.

The Group ended the quarter with a cash balance of USD 736.6 million and USD 153.4 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 fourth quarter, the cost of goods sold amounted to USD 165.1 million, up from USD 105.6 million in the previous quarter. The increase in cost of goods sold was due to significant North Sea overlifting in the quarter.

Lifting costs

Lifting costs stood at USD 44.2 million in the fourth quarter, compared to USD 48.0 million in the previous quarter. In Kurdistan, the average lifting cost during the fourth quarter was USD 3.5 per barrel (USD 3.4 per barrel in the previous quarter). In the North Sea, the average lifting cost during the fourth quarter stood at USD 14.4 per barrel of oil equivalent (boe) (USD 19.2 per boe in the previous quarter). The decrease in the North Sea average lifting cost per boe compared to the previous quarter was mainly related to lower lifting costs in the UK.

		Quarters	Full-Year
USD million	Q4 2021	Q3 2021	Q4 2020	2021	2020
Kurdistan	26.3	24.9	28.8	99.6	94.5
North Sea	18.0	23.1	14.8	84.6	86.6
Total	44.2	48.0	43.5	184.2	181.1

	Quarters			Full-Year
(USD/boe)	Q4 2021	Q3 2021	Q4 2020	2021	2020
Kurdistan	3.5	3.4	3.8	3.3	3.1
North Sea	14.4	19.2	10.5	17.9	13.6
Average	5.1	5.7	4.8	5.3	4.9

Depreciation, depletion and amortization (DD&A)

DD&A from the Group's oil and gas production assets amounted to USD 52.0 million in the fourth quarter, compared to USD 49.6 million in the previous quarter. The increase in DD&A was driven by higher net entitlement production from Kurdistan.

	Quarters			Full-Year
USD million	Q4 2021	Q3 2021	Q4 2020	2021	2020
Kurdistan	31.8	29.0	52.8	120.8	234.9
North Sea	20.1	20.6	24.6	79.2	116.3
Total	52.0	49.6	77.4	200.1	351.2

	Quarters			Full-Year
(USD/boe)	Q4 2021	Q3 2021	Q4 2020	2021	2020
Kurdistan	11.8	11.8	17.2	11.8	17.7
North Sea	16.1	17.1	17.5	16.8	18.3
Average	13.2	13.5	17.3	13.4	17.9

Exploration costs expensed

In the fourth quarter, the exploration costs expensed amounted to USD 58.6 million, up from USD 36.4 million in the previous quarter. The increase in expensed exploration costs was mainly due to higher expensing of wells, and seismic purchase.

	Quarters			Full-Year
USD million	Q4 2021	Q3 2021	Q4 2020	2021	2020
Kurdistan	1.2	0.9	0.6	2.8	1.6
North Sea	57.4	35.5	14.8	129.6	54.4
Total	58.6	36.4	15.5	132.3	55.9

Acquisition and development costs

Acquisition and development costs stood at USD 75.6 million in the fourth quarter, of which USD 38.8 million were in Kurdistan and USD 36.2 million in the North Sea. Acquisition and development costs in the fourth quarter is explained by higher capital spend in the Tawke license in Kurdistan and lower capitalized exploration in the North Sea.

	Quarters			Full-Year
USD million	Q4 2021	Q3 2021	Q4 2020	2021	2020
Kurdistan	38.8	22.8	21.0	94.9	92.6
North Sea	36.2	71.0	36.2	185.1	131.6
Other	0.5	-	0.1	0.7	0.9
Total	75.6	93.6	57.3	280.6	225.0

Consolidated statements of comprehensive income

		Quarters		Full-Year
(unaudited, in USD million) Note	Q4 2021	Q4 2020	2021	2020
Revenues 2,3	396.5	174.2	1,004.1	614.9
Cost of goods sold 4	-165.1	-139.1	-443.1	-590.0
Gross profit	231.4	35.1	561.0	24.9
Other income/-expenses Administrative expenses	0.4 -9.5	-0.2 0.5	0.5 -16.2	- -4.8
Other operating expenses	-8.3	-1.0	-12.0	-2.7
Impairment oil and gas assets 7	-27.3	-33.0	-80.1	-276.0
Exploration expenses 5	-58.6	-15.5	-132.3	-55.9
Profit/-loss from operating activities	128.2	-14.2	320.9	-314.5
Financial income 9	1.8	14.7	26.0	19.8
Financial expenses 9,10	-25.0	-39.0	-126.7	-131.0
Profit/-loss before income tax	104.9	-38.5	220.1	-425.8
Tax income/-expense 6	-40.1	-21.9	-16.3	139.8
Net profit/-loss	64.8	-60.4	203.9	-285.9
Other comprehensive income
Currency translation differences	-3.5	43.3	-12.5	-3.6
Items that may be reclassified to profit or loss in later periods	-3.5	43.3	-12.5	-3.6
Net fair value changes from financial instruments 8	-1.9	3.7	3.6	-8.4
Items that are not reclassified to profit or loss in later periods	-1.9	3.7	3.6	-8.4
Total other comprehensive income, net of tax	-5.3	47.0	-8.9	-12.0
Total comprehensive income, net of tax	59.5	-13.4	195.0	-298.0
Net profit/-loss attributable to:
Equity holders of the parent	64.8	-60.4	203.9	-285.9
Total comprehensive income attributable to:
Equity holders of the parent	59.5	-13.4	195.0	-298.0
Earnings per share, basic (USD per share)	0.07	-0.06	0.21	-0.29
Earnings per share, diluted (USD per share)	0.07	-0.06	0.21	-0.29
Weighted average number of shares outstanding (excluding treasury shares) (millions)	975.43	975.43	975.43	975.73

Consolidated statements of financial position

ASSETS		At 31 Dec
(unaudited, in USD million)	Note	2021	2020
Non-current assets
Goodwill	7	88.2	162.0
Deferred tax assets	6	29.3	47.4
Other intangible assets	7	232.4	308.6
Property, plant and equipment	7	1,284.9	1,174.1
Financial investments	8	16.2	12.6
Other non-current receivables	9	19.4	182.4
Total non-current assets		1,670.4	1,887.1
Current assets
Inventories	4	35.8	41.9
Trade and other receivables	9	483.8	239.6
Tax receivables	6	21.1	63.1
Cash and cash equivalents		736.6	477.1
Total current assets		1,277.3	821.6
TOTAL ASSETS		2,947.8	2,708.7
EQUITY AND LIABILITIES		At 31 Dec
(unaudited, in USD million)	Note	2021	2020
Equity
Shareholders' equity		1,018.8	845.6
Total equity		1,018.8	845.6
Non-current liabilities
Deferred tax liabilities	6	267.3	178.8
Interest-bearing liabilities	10	873.4	934.2
Lease liabilities	11	12.5	13.9
Provisions for other liabilities and charges	11	389.9	440.1
Total non-current liabilities		1,543.2	1,566.9
Current liabilities
Trade and other payables		232.6	180.3
Income tax payable	6	33.1	-
Current lease liabilities	11	15.7	3.8
Provisions for other liabilities and charges	11	104.4	112.0
Total current liabilities		385.8	296.1
Total liabilities		1,929.0	1,863.0
TOTAL EQUITY AND LIABILITIES		2,947.8	2,708.7

Consolidated cash flow statement

		Quarters		Full-Year
(unaudited, USD million) Note	Q4 2021	Q4 2020	2021	2020
Operating activities
Profit/-loss before income tax	104.9	-38.5	220.1	-425.8
Adjustments to add/-deduct non-cash items:
Exploration cost previously capitalized carried to cost 5	30.1	5.9	54.1	17.5
Depreciation, depletion and amortization 4	53.3	79.8	206.0	361.4
Impairment oil and gas assets 7	27.3	33.0	80.1	276.0
Amortization of borrowing issue costs	1.0	1.6	9.4	7.6
Accretion expense on ARO provisions	4.3	4.6	17.7	17.0
Interest expense	19.1	22.4	74.2	87.3
Interest income	-0.7	-3.0	-1.7	-5.3
Other	-0.3	5.7	1.0	1.0
Change in working capital items and provisions:
- Inventories	-5.0	-2.7	5.0	-13.7
- Trade and other receivables 9	21.2	-27.7	-99.5	41.1
- Trade and other payables	-17.5	-7.9	55.1	-108.5
- Provisions for other liabilities and charges	4.4	1.2	3.8	-2.7
Cash generated from operations	242.2	74.5	625.3	252.9
Tax refund received	91.4	211.7	174.7	236.3
Interest received	0.7	0.8	1.7	2.7
Interest paid	-17.7	-19.8	-73.0	-85.7
Net cash from/-used in operating activities	316.5	267.3	728.8	406.2
Investing activities
Purchases of intangible assets
Purchases of tangible assets	-15.4	-11.2	-86.8	-62.8
	-60.2	-46.1	-193.8	-162.2
Payments for decommissioning	-13.5	-2.4	-86.2	-30.7
Proceeds from license transactions	4.7	-	4.7	-
Net cash from/-used in investing activities	-84.4	-59.6	-362.0	-255.7
Financing activities
Proceeds from borrowings 10	-	-	400.0	152.3
Repayment of borrowings 10	-56.2	-102.4	-459.0	-290.3
Payment of debt issue costs	-	-	-15.6	-
Purchase of treasury shares	-	-	-	-17.8
Paid dividend	-22.2	-	-22.2	-
Payments of lease liabilities	-2.2	-1.1	-8.6	-3.4
Net cash from/-used in financing activities	-80.6	-103.4	-105.4	-159.1
Net increase/-decrease in cash and cash equivalents	151.5	104.2	261.5	-8.6
Cash and cash equivalents at beginning of the period	585.7	373.0	477.1	485.7
Exchange gain/-losses on cash and cash equivalents	-0.6	-	-2.0	-
Cash and cash equivalents at the end of the period	736.6	477.1	736.6	477.1
Of which restricted cash	15.8	13.6	15.8	13.6

Consolidated statement of changes in equity

				Other comprehensive income
			Other paid-in	Fair value	Currency
	Share	Share	capital/Other	changes equity	translation	Retained	Total
(unaudited, in USD million)	capital	premium	reserves	instruments	differences	earnings	equity
Total shareholders' equity as of 31 December 2019	33.3	247.7	-30.2	44.5	-61.4	927.4	1,161.3
Fair value changes from equity instruments	-	-	-	-8.4	-	-	-8.4
Currency translation differences	-	-	-	-	-3.6	-	-3.6
Other comprehensive income/-loss	-	-	-	-8.4	-3.6	-	-12.0
Profit/-loss for the period	-	-	-	-	-	-285.9	-285.9
Total comprehensive income	-	-	-	-8.4	-3.6	-285.9	-298.0
Purchase of treasury shares	-0.4	-	-17.3	-	-	-	-17.7
Transactions with shareholders	-0.4	-	-17.3	-	-	-	-17.7
Transfers	-	-	47.5	-	-	-47.5	-
Total shareholders' equity as of 31 December 2020	32.9	247.7	-	36.1	-65.0	593.9	845.6

				Other comprehensive income
			Other paid-in	Fair value	Currency
	Share	Share	capital/Other	changes equity	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	-	-	-	3.6	-	-	3.6
Currency translation differences	-	-	-	-	-12.5	-	-12.5
Other comprehensive income/-loss	-	-	-	3.6	-12.5	-	-8.9
Profit/-loss for the period	-	-	-			203.9	203.9
Total comprehensive income	-	-	-	3.6	-12.5	203.9	195.0
Payment of dividend	-	-	-	-	-	-21.8	-21.8
Transactions with shareholders	-	-	-	-	-	-21.8	-21.8
Total shareholders' equity as of 31 December 2021	32.9	247.7	-	39.7	-77.5	776.0	1,018.8

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
Fourth quarter ending 31 December 2021					reporting	allocated/	Total
USD million	Note	Kurdistan	North Sea	Other		segments eliminated	Group
Income statement information
Revenues	3	180.4	216.1	-	396.5	-	396.5
Inter-segment revenues		-	0.8	-	0.8	-0.8	-
Cost of goods sold	4	-58.2	-106.3	-	-164.4	-0.6	-165.1
Gross profit		122.2	110.7	-	232.9	-1.5	231.4
Profit/-loss from operating activities		119.8	20.2	-8.3	131.8	-3.6	128.2
Financial income/-expense (net)	9,10						-23.2
Tax income/-expense	6	-	-40.1	-	-40.1	-	-40.1
Net profit/-loss							64.8
Financial position information
Non-current assets		679.8	964.1	-	1,643.9	26.6	1,670.5
Current assets		372.2	367.1	11.5	750.8	526.5	1,277.3
Total assets		1,052.0	1,331.2	11.5	2,394.7	553.1	2,947.8
Non-current liabilities		63.2	691.2	-	754.4	788.8	1,543.2
Current liabilities		78.0	248.5	36.3	362.8	23.0	385.8
Total liabilities		141.2	939.8	36.3	1,117.2	811.7	1,929.0

Note 2 | Segment information (continued)

Fourth quarter ending 31 December 2020 USD million	Note	Kurdistan	North Sea	Other	Total reporting	Un allocated/ segment eliminated	Total Group
Income statement information
Revenues	3	95.8	78.4	-	174.2	-	174.2
Inter-segment revenues		-	0.3	0.1	0.4	-0.4	-
Cost of goods sold	4	-82.7	-55.9	-	-138.6	-0.6	-139.1
Gross profit		13.2	22.8	0.1	36.0	-1.0	35.1
Profit/-loss from operating activities		11.6	-26.3	-1.0	-15.7	1.5	-14.2
Financial income/-expense (net)	10						-24.3
Tax income/-expense	6	-	-21.8	-	-21.8	-0.1	-21.9
Net profit/-loss							-60.4
Financial position information
Non-current assets		830.5	1,031.6	-	1,862.1	25.0	1,887.1
Current assets		173.1	335.9	3.9	512.8	308.8	821.6
Total assets		1,003.6	1,367.4	3.9	2,374.9	333.8	2,708.7
Non-current liabilities		60.6	710.1	-	770.7	796.2	1,566.9
Current liabilities		73.9	178.8	28.9	281.6	14.5	296.1
Total liabilities		134.5	888.9	28.9	1,052.3	810.8	1,863.0

Note 2 | Segment information (continued)

Full-Year ending December 2021 USD million	Note	Kurdistan	North Sea	Other	Total reporting	Un allocated/ segment eliminated	Total Group
Income statement information
Revenues	3	594.3	409.8	-	1,004.1	-	1,004.1
Inter-segment sales		-	2.6	-	2.6	-2.6	-
Cost of goods sold	4	-220.9	-219.4	-	-440.3	-2.7	-443.1
Gross profit		373.4	193.0	-	566.4	-5.4	561.0
Profit/-loss from operating activities		368.1	-24.7	-11.6	331.9	-11.0	320.9
Financial income/-expense (net)	9,10						-100.7
Tax income/-expense	6	-	-15.9	-0.3	-16.3	-	-16.3
Net profit/-loss							203.9
Financial position information
Non-current assets		679.8	964.1	-	1,643.9	26.6	1,670.5
Current assets		372.2	367.1	11.5	750.8	526.5	1,277.3
Total assets		1,052.0	1,331.2	11.5	2,394.7	553.1	2,947.8
Non-current liabilities		63.2	691.2	-	754.4	788.8	1,543.2
Current liabilities		78.0	248.5	36.3	362.8	23.0	385.8
Total liabilities		141.2	939.8	36.3	1,117.2	811.7	1,929.0

					Total	Un
Full-Year ending December 2020					reporting	allocated/	Total
USD million	Note	Kurdistan	North Sea	Other		segment eliminated	Group
Income statement information
Revenues	3	369.1	245.8	-	614.9	-	614.9
Inter-segment sales		-	1.4	-	1.4	-1.4	-
Cost of goods sold	4	-334.0	-253.4	-	-587.3	-2.7	-590.0
Gross profit		35.2	-6.2	-	29.0	-4.1	24.9
Profit/-loss from operating activities		31.6	-344.4	-5.4	-318.3	3.7	-314.5
Financial income/-expense (net)	10						-111.2
Tax income/-expense	6	-	141.7	0.5	142.2	-2.4	139.8
Net profit/-loss							-285.9
Financial position information
Non-current assets		830.5	1,031.6	-	1,862.1	25.0	1,887.1
Current assets		173.1	335.9	3.9	512.8	308.8	821.6
Total assets		1,003.6	1,367.4	3.9	2,374.9	333.8	2,708.7
Non-current liabilities		60.6	710.1	-	770.7	796.2	1,566.9
Current liabilities		73.9	178.8	28.9	281.6	14.5	296.1
Total liabilities		134.5	888.9	28.9	1,052.3	810.8	1,863.0

Note 3 | Revenues

	Quarters		Full-Year
USD million	Q4 2021	Q4 2020	2021	2020
Sale of oil	304.1	158.5	828.1	566.6
Sale of gas	85.2	12.3	151.3	27.5
Sale of natural gas liquids (NGL)	6.2	3.2	21.3	14.8
Tariff income	0.9	0.2	3.4	6.0
Total revenues from contracts with customers	396.5	174.2	1,004.1	614.9
Sale of oil (bopd)	46,088	47,831	36,583	48,139
Sale of gas (boepd)	5,199	6,019	4,344	4,548
Sale of natural gas liquids (NGL) (boepd)	1,369	1,290	1,244	1,695
Total sales volume (boepd)	52,655	55,140	42,171	54,382

Note 4 | Cost of goods sold/ Inventory

	Quarters		Full-Year
USD million	Q4 2021	Q4 2020	2021	2020
Lifting costs	-44.2	-43.5	-184.2	-181.1
Tariff and transportation expenses	-8.7	-8.2	-34.5	-36.2
Production costs based on produced volumes	-52.9	-51.8	-218.8	-217.3
Movement in overlift/underlift	-58.8	-7.6	-18.3	-11.3
Production costs based on sold volumes	-111.7	-59.3	-237.0	-228.6
Depreciation, depletion and amortization	-53.3	-79.8	-206.0	-361.4
Total cost of goods sold	-165.1	-139.1	-443.1	-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 31 Dec
USD million	2021	2020
Spare parts	35.8	41.9
Total inventory	35.8	41.9

Total inventory of USD 35.8 million as of 31 December 2021 was related to Kurdistan (USD 18.8 million) and the North Sea (USD 17.0 million).

Note 5 | Exploration expenses

	Quarters		Full-Year
USD million	Q4 2021	Q4 2020	2021	2020
Exploration expenses (G&G and field surveys)	-4.6	-4.6	-19.1	-16.1
Seismic costs	-17.5	-0.2	-37.6	-2.9
Exploration cost capitalized in previous years carried to cost	-2.4	-	-13.4	-0.4
Exploration costs capitalized this year carried to cost	-27.7	-5.9	-40.7	-17.1
Other exploration cost expensed	-6.4	-4.7	-21.5	-19.5
Total exploration expenses	-58.6	-15.5	-132.3	-55.9

Note 6 | Income taxes

	Quarters		Full-Year
USD million	Q4 2021	Q4 2020	2021	2020
Tax income/-expense
Change in deferred taxes	-3.9	-38.0	-115.2	11.1
Income tax receivable/-payable	-36.2	16.1	98.9	128.8
Total tax income/-expense	-40.1	-21.9	-16.3	139.8

		At 31 Dec
USD million	2021	2020
Income tax receivable/-payable
Tax receivables (current) 63.05	21.1	63.1
Income tax payable 0	-33.1	-
Net tax receivable/-payable 63.05	-11.9	63.1
Deferred tax assets/-liabilities
Deferred tax assets 47.365	29.3	47.4
Deferred tax liabilities -178.759	-267.3	-178.8
Net deferred tax assets/-liabilities 47.365	-238.0	-131.4

The tax income/-expense, tax receivable/-payable and recognized deferred tax assets/-liabilities relate to activity on the Norwegian Continental Shelf (NCS) and the UK Continental Shelf (UKCS). Current tax receivable of USD 21.1 million relate to tax refund of decommissioning spend on the UKCS for 2021. Current income tax payable of USD 33.1 million relate to repayment of tax refunds in Norway that exceeded the tax value of actual losses for 2021. During 2021, DNO received total tax refunds of USD 159.4 million in Norway in relation to tax losses incurred in 2020 and estimated tax losses for 2021 and USD 15.3 million in the UK in relation to decommissioning spend for 2020. The refund of tax losses on the NCS incurred in 2021 is paid out in six instalments every two months with the first three instalments received during the second half of 2021. As the tax value of actual tax loss incurred for 2021 is lower than what has already been received in tax refunds during 2021, DNO will repay the difference over the remaining three instalments during the first half of 2022. The decommissioning tax refund on the UKCS for 2021 of USD 21.1 million is expected during the third quarter of 2022.

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			Full-Year
USD million	Q4 2021	Q4 2020	2021	2020
Additions of intangible assets	15.4	11.2	86.8	62.8
Additions of intangible assets through license acquisition	-	-	35.2	-
Divestments of intangible assets through license acquisition	-6.0	-	-6.0	-
Transfers to/-from intangible assets	-125.7	-	-125.7	-
Additions of tangible assets	57.1	56.4	206.4	192.1
Transfers to/-from tangible assets	129.7	-	129.7	-
Additions of right-of-use (RoU) assets	0.2	1.1	14.6	7.0
Depreciation, depletion and amortization (Note 4)	-53.3	-79.8	-206.0	-361.4
Impairment oil and gas assets	-27.3	-33.0	-80.1	-276.0
Exploration cost previously capitalized carried to cost (Note 5)	-30.1	-5.9	-54.1	-17.5

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 (presented as part of the PP&E balance sheet item), see Note 11.

Divestments of intangible assets through license acquisition during the quarter relate to an asset swap transaction in the North Sea. Transfers during the quarter relate to reclassifications of exploration assets (intangible assets) to development assets (tangible assets). The book value of USD 77.3 million related to the Baeshiqa license was reclassified to development assets following KRG approval of the first phase development plan in December 2021, and the book value of USD 49.2 million related to the Iris/Hades (PL644) license was reclassified to development assets following approval of concept select in November 2021.

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 fourth quarter of 2021, a net impairment charge of USD 27.3 million (USD 31.7 million post-tax) was recognized as part of the annual impairment testing of goodwill, mainly driven by updated assessment of future contingent (2C) resources and updated assessment of cost estimates for decommissioning.

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	54.0	-6.7	-	-6.7	-6.8	-	-	0.1
Ula area, North Sea	158.0	-24.6	-	-24.6	-25.3	-	-	0.4
Asset retirement obligations, North Sea	-	4.0	-4.4	-0.4	-	-4.1	-4.4	0.1
Total	212.0	-27.3	-4.4	-31.7	-32.1	-4.1	-4.4	0.6

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 (2022: USD 76.9, 2023: USD 70.4, 2024: USD 68.3 and 2025: USD 70.0 per barrel in nominal terms). From 2026, the Brent oil price was based on the Group's long-term price assumptions (USD 65.0 per barrel, real term), 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, would have led to an estimated additional impairment charge of USD 51.5 million (post-tax) and USD 11.5 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 discount 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		Full-Year
USD million	Q4 2021	Q4 2020	2021	2020
Beginning of the period	18.1	8.9	12.6	21.0
Fair value changes through other comprehensive income (FVTOCI)	-1.9	3.7	3.6	-8.4
Total financial investments end of the period	16.2	12.6	16.2	12.6

Financial investments include the following:

	At 31 Dec
USD million	2021	2020
Listed securities:
RAK Petroleum plc	16.2	12.6
Total financial investments	16.2	12.6

As of 31 December 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 31 Dec
USD million	2021	2020
Trade debtors (non-current portion)	18.2	182.0
Other non-current receivables	1.3	0.4
Total other non-current receivables	19.4	182.4
Trade debtors	344.4	96.2
Underlift	17.2	27.4
Other short-term receivables	122.2	115.9
Total trade and other receivables	483.8	239.6

Total book value of trade debtors of USD 362.6 million (current and non-current portion) as of 31 December 2021 relates mainly to the Tawke license arrears for 2019 and 2020 entitlement and override invoices (USD 169.1 million), and outstanding invoices for Tawke license crude oil deliveries for the months October through December 2021 (USD 180.3 million). See also Note 12 for KRG payments received after end-Q4 2021.

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, and DNO continues to work to improve the terms of recovery of the arrears, including but not limited to interest payments.

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 31 December 2021, in line with IFRS 9, the Company made a re-run of the estimated present value, updated the Brent price assumptions resulting in a net increase in the book value of the arrears by USD 1.1 million in the quarter (USD 16.0 million for the full-year, entirely reversing the financial expense recognized in 2020). Moreover, the classification of the receivables (current/noncurrent 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 17.2 million as of 31 December 2021 relates 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 31 Dec
USD million	Ticker	currency	amount/limit	Interest	Maturity	2021	2020
Non-current
Bond loan (ISIN NO0010823347)	DNO02	USD	-	-	-	-	400.0
Bond loan (ISIN NO0010852643)	DNO03	USD	394.9	8.375 %	29/05/24	394.9	400.0
Bond loan (ISIN NO0011088593)	DNO04	USD	400.0	7.875 %	09/09/26	400.0	-
Capitalized borrowing issue costs						-16.5	-15.4
Reserve based lending facility		USD	350.0	see below	see below	95.0	149.6
Total non-current interest-bearing liabilities						873.4	934.2

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

	At 1 Jan	Cash		Non-cash changes		At 31 Dec
USD million	2021		flows Amortization	Currency	Reclassification	2021
Bond loans	800.0	-5.1	-	-	-	794.9
Borrowing issue costs	-15.4	-10.5	9.4	-	-	-16.5
Reserve based lending facility	149.6	-53.9	-	-0.7	-	95.0
Reserve based lending facility (current)	-	-	-	-	-	-
Total	934.2	-69.5	9.4	-0.7	-	873.4

	At 1 Jan	Cash	Non-cash changes			At 31 Dec
USD million	2020		flows Amortization	Currency	Reclassification	2020
Bond loans	821.2	-21.2	-	-	-	800.0
Bond loans (current)	140.0	-139.8	-0.2	-	-	-
Borrowing issue costs	-23.0	-	7.6	-	-	-15.4
Reserve based lending facility	37.8	109.2	-	2.6	-	149.6
Exploration financing facility	85.6	-86.1	-	0.5	-	-
Total	1,061.6	-137.9	7.4	3.1	-	934.2

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 fourth quarter, DNO ASA has acquired USD 2.3 million of DNO03 bonds at 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 January 2022 is USD 106 million. Amount utilized as of the reporting date is disclosed in the table above. In addition, USD 88.0 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 31 Dec
USD million	2021	2020
Non-current
Asset retirement obligations (ARO)	386.3	436.6
Other long-term provisions and charges	3.6	3.4
Lease liabilities	12.5	13.9
Total non-current provisions for other liabilities and charges and lease liabilities	402.4	453.9
Current
Asset retirement obligations (ARO)	69.7	86.7
Other provisions and charges	34.8	25.3
Current lease liabilities	15.7	3.8
Total current provisions for other liabilities and charges and lease liabilities	120.1	115.8
Total provisions for other liabilities and charges and lease liabilities	522.6	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 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 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 31 Dec
USD million	2021	2020
Within one year	16.6	4.7
Two to five years	13.1	13.8
After five years	-	1.1
Total undiscounted lease liabilities end of the period	29.7	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

Since yearend 2021, DNO received USD 78.2 million net to the Company from the KRG, of which USD 55.1 million represents DNO's entitlement share of October 2021 crude oil deliveries to the export market from the Tawke license in Kurdistan. Of the balance, USD 6.9 million is an override payment equivalent to three percent of gross October 2021 Tawke license revenues under the August 2017 receivables settlement agreement and USD 16.2 million is a payment towards the Company's arrears relating to withheld payment of Tawke license 2019 and 2020 entitlement and override invoices.

DNO receives 10 awards in Norway's APA licensing round

On 18 January 2022, DNO announced that its wholly-owned subsidiary DNO Norge AS has been awarded participation in 10 exploration licenses, of which three are operatorships, under Norway's Awards in Predefined Areas (APA) 2021 licensing round. Of the 10 new licenses, six are in the North Sea and four in the Norwegian Sea.

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		Full-Year
USD million	Q4 2021	Q4 2020	2021	2020
Revenues	396.5	174.2	1,004.1	614.9
Lifting costs	-44.2	-43.5	-184.2	-181.1
Tariff and transportation	-8.7	-8.2	-34.5	-36.2
Movement in overlift/underlift	-58.8	-7.6	-18.3	-11.3
Exploration expenses	-58.6	-15.5	-132.3	-55.9
Administrative expenses	-9.5	0.5	-16.2	-4.8
Other operating income/expenses	-7.9	-1.2	-11.5	-2.7
EBITDA	208.8	98.7	606.9	322.8
EBITDAX USD million	Q4 2021	Q4 2020	2021	2020
EBITDA	208.8	98.7	606.9	322.8
Exploration expenses	58.6	15.5	132.3	55.9
EBITDAX	267.4	114.2	739.3	378.8
Netback USD million	Q4 2021	Q4 2020	2021	2020
EBITDA	208.8	98.7	606.9	322.8
Tax refund received/-taxes paid	91.4	211.7	174.7	236.3
Netback	300.2	310.4	781.6	559.1
	Q4 2021	Q4 2020	2021	2020
Netback (USD million)	300.2	310.4	781.6	559.1
Net production (MMboe)	8.7	9.0	34.5	36.6
Netback (USD/boe)	34.6	34.4	22.7	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	Q4 2021	Q4 2020	2021	2020
Lifting costs (USD million)	-44.2	-43.5	-184.2	-181.1
Net production (MMboe)	8.7	9.0	34.5	36.6
Lifting costs (USD/boe)	5.1	4.8	5.3	4.9

Alternative performance measures (continued)

Acquisition and development costs

USD million Q4 2021 Q4 2020 2021 2020 Purchases of intangible assets -15.4 -11.2 -86.8 -62.8 Purchases of tangible assets -60.2 -46.1 -193.8 -162.2 Acquisition and development costs -75.6 -57.3 -280.6 -225.0 Acquisition and development costs exclude estimate changes on asset retirement obligations. Operational spend Q4 2021 Q4 2020 2021 2020 USD million Lifting costs -44.2 -43.5 -184.2 -181.1 Tariff and transportation expenses -8.7 -8.2 -34.5 -36.2 Exploration expenses -58.6 -15.5 -132.3 -55.9 Exploration cost previously capitalized carried to cost (Note 5) 30.1 5.9 54.1 17.5 Acquisition and development costs -75.6 -57.3 -280.6 -225.0 Payments for decommissioning -13.5 -2.4 -86.2 -30.7 Operational spend -170.5 -121.0 -663.8 -511.4 Free cash flow Q4 2021 Q4 2020 2021 2020 USD million Net cash from/-used operating activities 316.5 267.3 728.8 406.2 Acquisition and development costs -75.6 -57.3 -280.6 -225.0 Payments for decommissioning -13.5 -2.4 -86.2 -30.7 Free cash flow 227.4 207.6 362.0 150.5 Effective Q3 2021, tax refund received/-taxes paid and net interest paid are included in this APM. Comparison figures have been updated. Equity ratio 2021 2020 USD Equity 1,018.8 845.6 Total assets 2,947.8 2,708.7 Equity ratio 34.6% 31.2% Net debt 2021 2020 USD million Cash and cash equivalents including restricted cash 736.6 477.1 Bond loans and reserve based lending (Note 10) 889.9 949.6 Net cash/-debt -153.4 -472.5	Quarters		Full-Year

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.

DNO ASA Dokkveien 1 N-0250 Oslo Norway

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

2021 Interim Results | 29 dno.no