DNO ASA — Interim / Quarterly Report 2019

Oct 31, 2019

Key figures

	Quarters		First nine months		Full-Year
USD million	Q3 2019	Q2 2019	Q3 2018	2019	2018	2018
Key financials
Revenues	227.0	265.7	171.2	696.7	460.5	829.3
Gross profit	88.0	131.9	76.9	307.0	216.7	478.7
Profit/-loss from operating activities	-106.0	99.4	70.6	31.3	146.8	376.8
Net profit/-loss	-96.4	68.0	63.0	22.6	124.0	354.3
EBITDA	109.2	176.6	142.7	392.4	334.0	638.8
EBITDAX	156.5	195.0	150.0	490.9	379.1	703.5
Netback	109.2	176.6	142.7	392.4	334.0	489.1
Acquisition and development costs	108.3	94.7	41.3	295.6	91.5	138.0
Exploration expenses	47.4	18.3	7.2	98.5	45.1	64.7
Key performance indicators
Lifting costs (USD/boe)	5.5	4.8	2.9	5.3	2.7	3.0
Netback (USD/boe)	12.0	18.8	19.0	14.3	15.6	16.4

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

Corporate overview – Q3 2019

• Strong revenues of USD 227 million, up 33 percent from a year earlier
• On back of solid production averaging 99,300 barrels of oil equivalent per day (boepd) on a Company Working Interest (CWI) basis, up 22 percent year on year
• Financial results impacted by non-recurring items as well as lower oil prices and higher exploration expenses, resulting in a net loss of USD 96 million
• USD 228 million in cash from operations including USD 64 million in working capital reduction
• Share buyback program resumed with 23 million shares acquired at a cost of USD 35 million, lifting overall stake to 58 million treasury shares, representing 5.35 percent of total outstanding shares at end quarter
• Bought back additional USD 17 million of FAPE01 bonds

Q3 2019 operational highlights

• Tawke license cumulative production reached significant milestone of 300 million barrels (MMbbls)
• Operated production in Kurdistan region of Iraq averaged 119,800 barrels of oil per day (bopd) compared to 113,200 bopd in Q3 2018
• CWI production averaged 99,300 boepd compared to 81,500 boepd during Q3 2018. Kurdistan production averaged 84,400 bopd and North Sea production averaged 14,900 boepd during Q3 2019
• In 2019 in Kurdistan, nine wells spud through end third quarter with an additional ten wells planned for fourth quarter
• In North Sea, 13 wells spud through end third quarter, with an additional four wells planned for fourth quarter, including DNO's first operated exploration well, Canela, in the North Sea since 2007

• On track to deliver Peshkabir-to-Tawke gas project in Q1 2020, effectively eliminating gas flaring throughout DNO's operations while enhancing recoverability in the Tawke field

• Schooner and Ketch (United Kingdom) well plugging and abandonment campaign to commence early November

• Following reduction in reserve estimate, operator DNO and partner Vår Energi recalibrating Brasse project (Norway). Concept selection expected in Q2 2020

Q3 2019 financial highlights

• Financial results impacted by impairment charges of USD 138 million, including USD 89 million for technical goodwill on the Brasse discovery and USD 33 million for decommissioning of the Schooner and Ketch fields
• Full-year operational spend projected at USD 620 million, of which USD 454 million was spent through end third quarter, including USD 244 million in Kurdistan and USD 210 million (post-tax) in the North Sea
• Exited Q3 2019 with cash balance of USD 624 million (USD 729 million at yearend 2018), plus USD 110 million treasury shares and marketable securities (USD 281 million at yearend 2018)
• Maintain previously approved dividend distribution program with another semiannual payment of NOK 0.20 per share to be made on 4 November 2019

Operational review

Production

Quarterly production (boepd)

CWI production (boepd)

Operated gross production averaged 122,753 boepd during the third quarter, of which 119,757 bopd was from Kurdistan and 2,997 boepd from the North Sea segment.

Company Working Interest (CWI) production during the third quarter stood at 99,305 boepd, compared to 103,902 boepd in the previous quarter. In Kurdistan, CWI production averaged 84,428 bopd, down from 89,209 bopd in the previous quarter. The lower production compared to the previous quarter was primarily driven by planned workover and side-track on P-2 and P-3 respectively on the Peshkabir field in the Tawke license. CWI production from the North Sea segment averaged 14,876 boepd, slightly up from 14,692 boepd in the previous quarter. The slight increase in third quarter production compared to the previous quarter was driven by the Ula area fields coming back on stream after the maintenance stop in June and improved production from Tambar, offset by operational issues with the Oda and Vilje fields, and the planned shutdown of the Trym field from September.

Entitlement production averaged 51,487 boepd during the third quarter, down from 52,626 boepd in the previous quarter.

Gross production (operated)

	Quarters			First nine months	Full-Year
boepd	Q3 2019	Q2 2019	Q3 2018	2019	2018	2018
Kurdistan	119,757	126,538	113,175	124,326	108,393	113,149
North Sea	2,997	4,330	-	4,010	-	-
Oman	-	-	4,403	61	4,539	4,458
Total	122,753	130,868	117,578	128,397	112,931	117,607

The table above shows gross production (boepd) from the Group's operated licenses.

Company Working Interest (CWI) production

		Quarters First nine months				Full-Year
boepd	Q3 2019	Q2 2019	Q3 2018	2019	2018	2018
Kurdistan	84,428	89,209	79,766	87,650	76,386	79,747
North Sea*	14,876	14,692	-	12,721	-	-
Oman	-	-	1,760	29	2,004	1,965
Total	99,305	103,902	81,526	100,399	78,390	81,712

* The production from assets acquired through the Norwegian assets swap with Equinor is included from the date of transaction completion (30 April 2019).

Net entitlement production

	Quarters			First nine months	Full-Year
boepd	Q3 2019	Q2 2019	Q3 2018	2019	2018	2018
Kurdistan	36,611	37,933	35,522	37,309	30,672	32,240
North Sea*	14,876	14,692	-	12,721	-	-
Oman	-	-	764	14	763	767
Total	51,487	52,626	36,287	50,043	31,435	33,007

The table above reflects the Group's net entitlement production (boepd). The net entitlement production (boepd) from the North Sea segment equals the segment's CWI production (boepd).

Activity overview

Kurdistan region of Iraq

Tawke license

Gross production from the Tawke license, containing the Tawke and Peshkabir fields, averaged 119,757 bopd during the third quarter of 2019.

The Peshkabir-11 well was drilled and placed on production during the third quarter of 2019. Nine wells are currently producing from Peshkabir and the Peshkabir-3A well is expected to come onstream shortly. Peshkabir production averaged 51,944 bopd during the third quarter of 2019.

At the Tawke field, the Tawke-56 Cretaceous well was drilled and placed on production during the third quarter of 2019 and the Tawke-58 Cretaceous well was placed on production in October 2019. The Tawke-57A deep well to appraise the Jurrassic was spud in August 2019 with testing to commence shortly. The Tawke-59 Cretaceous well spud in October 2019 and is expected to come on production next month. Two Jeribe wells, Tawke-61 and Tawke-62 were drilled in October 2019 and will be placed on production shortly. Four additional Jeribe wells are planned to spud by yearend. Tawke production averaged 67,813 bopd during the third quarter 2019.

The Company's active 2019 drilling campaign at the Tawke and Peshkabir fields continues. Nine wells were spud through the end of the third quarter 2019 with an additional ten wells planned for the fourth quarter.

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

Baeshiqa license

Rigless testing at the Baeshiqa-2 well targeting the deeper Jurassic and Triassic reservoirs continues. A third well, also targeting the Jurassic and Triassic, but on a separate structure, will be drilled next year.

DNO acquired a 32 percent interest and operatorship of the Baeshiqa license in 2017. Partners include ExxonMobil with 32 percent, Turkish Energy Company with 16 percent and the Kurdistan Regional Government with 20 percent.

North Sea

CWI production averaged 14,876 boepd in Norway and the UK during the third quarter 2019, of which 13,995 boepd was in Norway and 881 boepd was in the UK.

DNO relinquished two licenses PL810 and PL810 B during the third quarter of 2019. The Company now holds 87 licenses in Norway, of which 21 are operated.

The Company has diversified production across 13 fields, of which nine are in Norway and four in the UK.

In the North Sea, 13 wells spud through the end of the third quarter in 2019 with an additional four wells planned for the fourth quarter.

Financial review

Revenues, operating profit and cash

Revenues in the third quarter stood at USD 227.0 million, compared to USD 265.7 million in the previous quarter. The decrease in revenues compared to the previous quarter was primarily driven by lower oil prices. Kurdistan generated revenues of USD 164.5 million, while the North Sea segment contributed USD 61.7 million.

The Company reported an operating loss of USD 106.0 million in the third quarter, down from an operating profit of USD 99.4 million in the previous quarter reflecting the decrease in revenues, impairment charges and higher expensed exploration.

The Company ended the quarter with a cash balance of USD 624.0 million and USD 109.8 million in market value of treasury shares and financial investments, compared to USD 729.1 million and USD 281.3 million at yearend 2018 respectively.

Cost of goods sold

In the third quarter, the cost of goods sold stood at USD 139.0 million, compared to USD 133.8 million in the previous quarter.

Lifting costs

Lifting costs stood at USD 50.4 million in the third quarter, compared to USD 44.9 million in the previous quarter. In Kurdistan, the average lifting cost during the third quarter stood at USD 3.8 per barrel of oil equivalent (boe). In the North Sea segment, the average lifting cost during the third quarter stood at USD 15.5 per boe.

		Quarters			First nine months
USD million	Q3 2019	Q2 2019	Q3 2018	2019	2018	2018
Kurdistan	29.3	22.5	19.5	80.1	50.6	80.6
North Sea	21.3	22.4	-	65.2	-	-
Oman	-		2.7	-	7.7	9.6
Other	-0.2		-	-0.3	0.2	-
Total	50.4	44.9	22.1	145.0	58.5	90.4

Including export volumes

		Quarters		First nine months	Full-Year
(USD/boe)	Q3 2019	Q2 2019	Q3 2018	2019	2018	2018
Kurdistan	3.8	2.8	2.7	3.3	2.4	2.8
North Sea	15.5	16.8	-	18.8		-
Oman	-	-	16.5	-	14.1	13.4
Other	-	-	-	-	-	-
Average	5.5	4.8	2.9	5.3	2.7	3.0

Depreciation, depletion and amortization (DD&A)

DD&A for assets in operation amounted to USD 75.8 million in the third quarter compared to USD 75.9 million in the previous quarter.

		Quarters		First nine months	Full-Year
USD million	Q3 2019	Q2 2019	Q3 2018	2019	2018	2018
Kurdistan	52.3	53.7	71.7	158.3	183.8	258.2
North Sea	23.4	22.2	-	60.8	-	-
Total	75.8	75.9	71.7	219.0	183.8	258.2

Including export

volumes (USD/boe)	Q3 2019	Quarters Q2 2019	Q3 2018	First nine months Q3 2019	Q3 2018	Full-Year 2018
Kurdistan	15.5	15.6	21.9	15.5	21.9	21.9
North Sea	17.1	16.6	-	17.5	-	-
Average	16.0	15.9	21.5	16.0	21.4	21.4

Exploration expenses

Exploration expenses of USD 47.4 million in the third quarter were mainly related to exploration activities in the North Sea segment, including the purchase of seismic, expensing of exploration wells and exploration costs capitalized in previous years.

		Quarters		First nine months	Full-Year
USD million	Q3 2019	Q2 2019	Q3 2018	2019	2018	2018
Kurdistan	0.4	0.5	0.4	1.5	0.8	1.5
North Sea	47.2	17.8	6.7	97.2	27.0	45.9
Tunisia	-	-	-	-	16.6	16.6
Other	-0.2	-	0.1	-0.2	0.7	0.7
Total	47.4	18.3	7.2	98.5	45.1	64.7

Acquisition and development costs

Acquisition and development costs stood at USD 108.3 million in the third quarter, of which USD 55.2 million was in the North Sea segment and USD 52.9 million in Kurdistan.

		Quarters		First nine months	Full-Year
USD million	Q3 2019	Q2 2019	Q3 2018	2019	2018	2018
Kurdistan	52.9	69.7	40.8	162.0	90.3	135.4
North Sea	55.2	24.4	1.0	131.8	1.1	1.3
Other	0.3	0.5	-0.4	1.8	0.0	1.3
Total	108.3	94.7	41.3	295.6	91.5	138.0

Consolidated statements of comprehensive income

		Quarters		First nine months		Full-Year
(unaudited, in USD million)	Note	Q3 2019	Q3 2018	2019	2018	2018
Revenues	2,3	227.0	171.2	696.7	460.5	829.3
Cost of goods sold	4	-139.0	-94.2	-389.7	-243.8	-350.6
Gross profit		88.0	76.9	307.0	216.7	478.7
Other income		-	6.1	-0.5	4.7	4.8
Administrative expenses		-7.0	-8.2	-20.1	-23.7	-36.7
Other operating expenses		-1.6	3.0	-18.4	-3.9	-3.4
Impairment oil and gas assets	7	-138.2	-	-138.2	-1.9	-1.9
Exploration expenses	5	-47.4	-7.2	-98.5	-45.1	-64.7
Profit/-loss from operating activities		-106.0	70.6	31.3	146.8	376.8
Financial income		4.0	3.9	9.7	8.1	12.6
Financial expenses	10	-44.0	-17.0	-107.5	-47.1	-66.9
Profit/-loss before income tax		-146.0	57.5	-66.6	107.8	322.5
Tax income/-expense	6	49.6	5.6	89.2	16.2	31.8
Net profit/-loss		-96.4	63.0	22.6	124.0	354.3
Other comprehensive income
Currency translation differences		-39.8	0.3	-45.5	0.3	1.4
Items that may be reclassified to profit or loss in later periods		-39.8	0.3	-45.5	0.3	1.4
Net fair value changes from financial instruments	8	-4.7	35.3	24.2	54.4	12.1
Items that are not reclassified to profit or loss in later periods		-4.7	35.3	24.2	54.4	12.1
Total other comprehensive income, net of tax		-44.5	35.7	-21.3	54.7	13.5
Total comprehensive income, net of tax		-140.9	98.7	1.3	178.7	367.7
Net profit/-loss attributable to:
Equity holders of the parent		-96.4	63.0	22.6	124.0	354.3
Total comprehensive income attributable to:
Equity holders of the parent		-140.9	98.7	1.3	178.7	367.7
Earnings per share, basic		-0.09	0.06	0.02	0.12	0.34
Earnings per share, diluted		-0.09	0.06	0.02	0.12	0.34
Weighted average number of shares outstanding (in millions)		1,046.33	1,048.81	1,047.98	1,048.81	1,048.81

Consolidated statements of financial position

ASSETS		At 30 Sep		At 31 Dec
(unaudited, USD million)	Note	2019	2018	2018
Non-current assets
Goodwill	12	356.3	-	-
Deferred tax assets	6	56.5	6.0	7.0
Other intangible assets	7	343.2	30.2	32.8
Property, plant and equipment	7	1,277.5	770.9	758.2
Right-of-use assets	7	11.7	-	-
Financial investments	8	26.1	262.6	230.8
Tax receivables	6	84.6	15.0	-
Total non-current assets		2,155.9	1,084.7	1,028.7
Current assets
Inventories	4	26.8	7.6	8.3
Trade and other receivables	9	298.7	38.9	209.8
Tax receivables	6	57.1	33.8	28.3
Cash and cash equivalents		624.0	640.2	729.1
Total current assets		1,006.7	720.5	975.5
TOTAL ASSETS		3,162.5	1,805.2	2,004.3
EQUITY AND LIABILITIES		At 30 Sep		At 31 Dec
(unaudited, USD million)	Note	2019	2018	2018
Equity
Share capital		34.3	35.0	35.0
Other reserves		139.9	238.0	239.6
Retained earnings		985.3	755.8	943.2
Total equity		1,159.5	1,028.8	1,217.8
Non-current liabilities
Deferred tax liabilities	6	177.2	-	-
Interest-bearing liabilities	10	1,012.9	584.0	575.7
Lease liabilities	11	9.2	-	-
Provisions for other liabilities and charges	11	409.1	49.9	68.1
Total non-current liabilities		1,608.5	633.9	643.8
Current liabilities
Trade and other payables		239.5	100.0	116.4
Income tax payable	6	-	0.7	0.5
Current interest-bearing liabilities	10	53.9	32.1	18.4
Current lease liabilities	11	3.1	-	-
Provisions for other liabilities and charges	11	98.1	9.7	7.4
Total current liabilities		394.6	142.5	142.7
Total liabilities		2,003.1	776.4	786.5
TOTAL EQUITY AND LIABILITIES		3,162.5	1,805.2	2,004.3

Consolidated cash flow statement

		Quarters		First nine months		Full-Year
(unaudited, in USD million)	Note	Q3 2019	Q3 2018	2019	2018	2018
Operating activities
Profit/-loss before income tax		-146.0	57.5	-66.6	107.8	322.5
Adjustments to add/-deduct non-cash items:
Previously capitalized exploration and evaluation expenses	5	17.9	-	21.1	-	-
Depreciation, depletion and amortization	4	77.1	72.1	222.9	185.3	260.1
Impairment oil and gas assets	7	138.2	-	138.2	1.9	1.9
Other*		-38.4	10.4	-1.3	35.1	50.2
Change in working capital items and provisions:
- Inventories		-2.9	-1.4	-0.7	-1.6	-2.4
- Trade and other receivables		93.3	-8.5	31.0	-11.1	-181.7
- Trade and other payables		19.9	11.8	-67.5	0.4	16.8
- Provisions for other liabilities and charges		69.1	-8.9	87.0	6.9	4.7
Cash generated from operations		228.1	132.9	364.0	324.8	472.0
Tax refund received		-	-	-	-	33.2
Net interests received/-paid		-18.2	-6.7	-49.8	-22.0	-34.1
Net cash from/-used in operating activities		209.9	126.2	314.2	302.7	471.1
Investing activities
Purchases of intangible assets
Purchases of tangible assets		-21.0	-2.1	-61.9	-2.2	-7.8
Payments for decommissioning		-87.3 -5.3	-39.2 -	-233.7 -13.6	-89.3	-130.3 -
Acquisition of Faroe Petroleum plc net of cash acquired**				-428.7	-	-
Proceeds from license transactions	12	-	- -	29.6	-	-
Acquisition of financial investments	8	-	-4.8		- -190.8	-201.3
Net cash from/-used in investing activities		- -113.6	-46.1	- -708.3	-282.2	-339.4
Financing activities
Proceeds from borrowings net of issue costs	10	6.3	2.0	464.5	200.4	223.9
Repayment of borrowings	10	-16.6	-	-113.8	15.0	-31.0
Purchase of treasury shares, including options Paid dividend		-35.0	-	-35.0	-	-
Payments of lease liabilities		-	-25.8	-24.6	-25.8	-25.8
Net cash from/-used in financing activities		-0.7	-	-2.1	-	-
		-46.0	-23.8	289.0	189.5	167.1
Net increase/-decrease in cash and cash equivalents		50.3	56.3	-105.0	210.1	298.9
Cash and cash equivalents at beginning of the period		573.8	584.0	729.1	430.2	430.2
Cash and cash equivalents at the end of the period		624.0	640.2	624.0	640.2	729.1
Of which restricted cash		14.3	2.7	14.3	2.7	3.2
Of which held on restricted account in relation to the Faroe Petroleum plc offer		-		-		418.1

* Includes net interest income/-expense and amortization of bond issue costs.

** The amount consists of USD 583.0 million paid during the first quarter of 2019 for the acquisition of the remaining Faroe Petroleum plc shares deducted with cash acquired of USD 154.5 million (see Note 12).

Consolidated statement of changes in equity

	Share	Other	Retained	Total
(unaudited, in USD million)	capital	reserves	earnings	equity
Total equity as of 1 January 2018	35.0	262.7	578.2	875.9
Fair value changes from equity instruments	-	-	54.4	54.4
Currency translation differences	-	1.1	-0.7	0.4
Other comprehensive income/-loss	-	1.1	53.6	54.7
Profit/-loss for the period	-	-	124.0	124.0
Total comprehensive income	-	1.1	177.7	178.7
Issue of share capital	-	-	-	-
Purchase of treasury shares	-	-	-	-
Sale of treasury shares Payment of dividend	- -	- -25.8	- -	- -25.8
Transaction with shareholders	-	-25.8	-	-25.8
Total equity as of 30 September 2018	35.0	238.0	755.8	1,028.8
	Share	Other	Retained	Total
(unaudited, in USD million)	capital	reserves	earnings	equity
Total equity as of 1 January 2019	35.0	239.6	943.2	1,217.8
Fair value changes from equity instruments	-	-	24.2	24.2
Currency translation differences	-	-40.7	-4.8	-45.5
Other comprehensive income/-loss	-	-40.7	19.4	-21.3
Profit/-loss for the period	-	-	22.6	22.6
Total comprehensive income	-	-40.7	42.0	1.3
Issue of share capital	-	-	-	-
Purchase of treasury shares	-0.6	-34.4	-	-35.0
Sale of treasury shares	-	-	-	-
Payment of dividend	-	-24.7	-	-24.7
Transaction with shareholders	-0.6	-59.1	-	-59.7
Total equity as of 30 September 2019	34.3	139.9	985.3	1,159.5

Notes to the consolidated interim financial statements

Note 1 | Basis of preparation and accounting policies

Principal activities and corporate information

DNO ASA (the Company) is engaged in international oil and gas exploration, development and production.

Basis of preparation

The DNO ASA's consolidated (DNO's or the Group's) 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 2018 (the Group annual accounts).

The interim financial information for 2019 and 2018 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 Group annual accounts for 2018.

Changes in accounting policies

Effective 1 January 2019, the Group made the following changes affecting the significant accounting policies:

• Implementation of IFRS 16 Leases. As described in the Group annual accounts for 2018, IFRS 16 entered into force from 1 January 2019. IFRS 16 replaces IAS 17 Leases and provides a single lessee accounting model, requiring lessees to recognize assets and liabilities for all leases unless the lease term is 12 months or less or the underlying asset has a low value. The accounting principles applied are in line with the description provided in the Group annual accounts for 2018, Note 1. The impact on the balance sheet is presented on separate balance sheet items, and further details are provided in the notes. The Group has applied the modified retrospective approach with no restatement of comparative figures.
• Change in principle for valuation and presentation of overlift/underlift. Revenues are recognized on the basis of volumes lifted and sold to customers during the period (the sales method). Overlift/underlift balances, previously valued at net realizable value, are now valued at production cost including depreciation and movements in overlift/underlift are presented as an adjustment to cost of goods sold, previously presented as Other revenues. This change was made due to the discussion in the IFRS Interpretations Committee (IFRIC) on the topic "Sale of output by a joint operator (IFRS 11 Joint Arrangements)", which was concluded in March 2019. The change does not have a material impact on the revenues from Kurdistan and it is expected to only have an impact on revenues from the North Sea segment. Comparative figures have not been restated based on a materiality assessment.
• Change in the unit-of-production depreciation method. The Group has previously depreciated its capitalized costs for oil and gas assets over the estimated remaining proven developed reserves. Following review of the depreciation method, the Group has decided to change the reserves basis from proven developed reserves to proven and probable reserves. The change in depreciation method is reflected prospectively as a change in estimate under IAS 8.

Except for the changes described above, the accounting policies adopted in the preparation of the interim financial statements are consistent with those followed in the preparation of the Group's annual accounts for 2018.

Note 2 | Segment information

From the first quarter of 2019, the Group reports the following two operating segments: Kurdistan and North Sea. The segment North Sea comprise DNO's activities on the Norwegian Continental Shelf (NCS) and UK Continental Shelf (UKCS). The segment assets do not include internal receivables/liabilities.

Third quarter ending 30 September 2019 USD million	Note		Kurdistan North Sea	Other	Total reporting	Un allocated/ segments eliminated	Total Group
Income statement information
Revenues	3	164.5	61.7	0.8	227.0	-	227.0
Inter-segment revenues		-	-	-	-	-0.1	-
Cost of goods sold	4	-81.8	-56.5	-	-138.3	-0.6	-139.0
Gross profit		82.7	5.2	1.0	88.9	-0.9	88.0
Profit/-loss from operating activities		65.8	-162.8	-3.1	-100.0	-6.0	-106.0
Financial income/-expense (net)	10						-40.0
Tax income/-expense	6	-	49.6	-	49.6	-	49.6
Net profit/-loss							-96.4
Total assets		986.3	1,582.2	5.0	2,573.6	589.0	3,162.5
					Total	Un

Third quarter ending 30 September 2018					reporting	allocated/	Total
USD million	Note		Kurdistan North Sea	Other		segment eliminated	Group
Income statement information
Revenues	3	164.1	-	7.1	171.2	-	171.2
Inter-segment revenues		-	0.3	0.0	0.3	-0.3	-
Cost of goods sold	4	-91.2	-0.1	-2.7	-93.9	-0.3	-94.2
Gross profit		72.9	0.2	4.4	77.5	-0.6	76.9
Other operating income		-		6.1			6.1
Profit/-loss from operating activities		74.1	-7.3	9.7	76.5	-5.8	70.6
Financial income/-expense (net)	10						-13.1
Tax income/-expense	6	-	5.6	-0.0	5.6	-	5.6
Net profit/-loss							63.0
Total assets		964.7	67.7	21.0	1,053.4	751.8	1,805.2

Note 2 | Segment information (continued)

First nine months ending 30 September 2019 USD million	Note		Kurdistan North Sea	Other	Total reporting	Un allocated/ segment eliminated	Total Group
Income statement information
Revenues	3	526.0	170.0	0.8	696.7	-	696.7
Inter-segment sales		-	0.4	0.0	0.4	-0.4	-
Cost of goods sold	4	-238.8	-148.7	-0.0	-387.5	-2.2	-389.7
Gross profit		287.2	21.7	0.8	309.6	-2.6	307.0
Profit/-loss from operating activities		267.8	-203.0	-21.6	43.2	-11.9	31.3
Financial income/-expense (net)	10						-97.8
Tax income/-expense	6	0.6	89.2	-	89.8	-0.6	89.2
Net profit/-loss							22.6
Total assets		986.3	1,582.2	5.0	2,573.6	589.0	3,162.5

					Total	Un
First nine months ending 30 September 2018					reporting	allocated/	Total
USD million	Note		Kurdistan North Sea	Other		segment eliminated	Group
Income statement information
Revenues	3	441.6	-	18.9	460.5	-	460.5
Inter-segment sales		-	0.7	0.1	0.8	-0.8	-
Cost of goods sold	4	-234.4	-0.1	-7.9	-242.3	-1.4	-243.8
Gross profit		207.3	0.6	11.1	218.9	-2.2	216.7
Other Operating income		-	-1.4	6.1	4.7		4.7
Profit/-loss from operating activities		204.8	-29.9	-10.2	164.7	-17.9	146.8
Financial income/-expense (net)	10						-39.0
Tax income/-expense	6	-	17.8	-1.3	16.4	-0.3	16.2
Net profit/-loss							124.0
Total assets		964.7	67.7	21.0	1,053.4	751.8	1,805.2

Note 3 | Revenues

	Quarters		First nine months		Full-Year
USD million	Q3 2019	Q3 2018	2019	2018	2018
Oil sales	208.8	171.2	659.4	460.5	829.3
Gas sales	11.7	-	27.6	-	-
Natural gas liquids sales	5.8	-	7.3	-	-
Tariff income	0.8	-	2.5	-	-
Total revenues	227.0	171.2	696.7	460.5	829.3

The full-year 2018 revenues included a recognition of an additional USD 182.8 million (booked in the fourth quarter of 2018) following a change in Kurdistan revenue recognition criteria (see Note 1).

Note 4 | Cost of goods sold/ inventory

	Quarters		First nine months	Full-Year
USD million	Q3 2019	Q3 2018	2019	2018	2018
Lifting costs	-50.4	-22.1	-145.0	-58.5	-90.4
Tariff and transportation expenses	-13.9	-	-25.8	-	-
Production cost based on produced volumes	-64.3	-22.1	-170.8	-58.5	-90.4
Movement in overlift/underlift	2.4	-	4.0	-	-
Production cost based on sold volumes	-61.9	-22.1	-166.8	-58.5	-90.4
Depreciation, depletion and amortization	-77.1	-72.1	-222.9	-185.3	-260.1
Total cost of goods sold	-139.0	-94.2	-389.7	-243.8	-350.6

Lifting costs consist of expenses related to the production of oil and gas, including operation and maintenance of installations, well intervention workover 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. For more information about movement in overlift/underlift, see Note 1.

	At 30 Sep	At 31 Dec
USD million	2019	2018	2018
Spare parts	26.8	7.6	8.3
Total inventory	26.8	7.6	8.3

Total inventory of USD 26.8 million as of 30 September 2019 is related to Kurdistan (USD 12.2 million) and the North Sea segment (USD 14.6 million).

Note 5 | Exploration expenses

	Quarters		First nine months		Full-Year
USD million	Q3 2019	Q3 2018	2019	2018	2018
Exploration expenses (G&G and field surveys)	-0.9	-2.1	-15.2	-9.5	-13.8
Seismic costs	-9.4	-2.9	-19.7	-8.4	-18.0
Exploration cost capitalized in previous years carried to cost	-17.9	-	-21.1	-	-
Exploration costs capitalized this year carried to cost	-9.0	0.1	-22.2	-4.4	-8.2
Impairment expenses	-	-	-	-	-
Other exploration cost expensed	-10.0	-2.4	-20.3	-22.7	-24.8
Total exploration expenses	-47.4	-7.2	-98.5	-45.1	-64.7

For details on geographic spread of exploration expenses, see the Financial review section. The Group allocates its administrative and other expenses related to the Norwegian and the UK oil and gas activities to exploration, development and production activities respectively.

Exploration expenses of USD 47.4 million in the third quarter were mainly related to exploration activities in the North Sea segment, including purchase of seismic data, expensing of exploration wells and expensing of exploration costs previously capitalized mainly related to the Fogelberg discovery.

Note 6 | Income taxes

	Quarters		First nine months		Full-Year
USD million	Q3 2019	Q3 2018	2019	2018	2018
Tax income/-expense
Change in deferred taxes	15.7	-0.2	-16.2	2.3	3.9
Income tax receivable/-payable	33.8	5.7	105.4	13.9	27.9
Total tax income/-expense	49.6	5.6	89.2	16.2	31.8

	At 30 Sep		At 31 Dec
USD million	2019	2018	2018
Income tax receivable/-payable
Tax receivables (non-current) 14.96	84.6	15.0	-
Tax receivables (current) 33.841	57.1	33.8	28.3
Income tax payable -0.658	-	-0.7	-0.5
Net tax receivable/-payable 48.143	141.7	48.1	27.8
Deferred tax assets/-liabilities
Deferred tax assets 5.987	56.5	6.0	7.0
Deferred tax liabilities 0	-177.2	-	-
Total deferred tax assets/-liabilities 5.987	-120.7	6.0	7.0

The tax income, tax receivable and deferred tax assets/liabilities mainly relate to activity on the NCS subject to the Norwegian Petroleum Taxation Act. The Company's subsidiaries, DNO Norge AS and DNO North Sea (Norge) AS, are currently not in a tax payable position and can claim a 78 percent refund of the eligible exploration costs limited to taxable losses for the year. The refund is paid out in November-December in the subsequent year. Deferred tax asset has been recognised for carry forward losses in relation to activity on the NCS as tax value of carried forward losses can be paid out upon termination of petroleum activity. In addition, deferred tax asset has been recognized in the UK in relation to temporary differences and ring fenced tax losses that are available indefinitely for offset against future taxable profits. Deferred tax assets/liabilities are presented net in the statements of financial position if there is a legal right to settle current tax amounts on a net basis and the deferred tax amounts are levied by the same tax authority.

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 foreign 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.

Increase in deferred tax assets and liabilities compared to 2018 is mainly due to the acquisition of Faroe Petroleum plc (see Note 12).

Note 7 | Other intangible assets/ Property, plant and equipment (PP&E)/ Right-of-use (RoU) assets

	Quarters		First nine months		Full-Year
USD million	Q3 2019	Q3 2018	2019	2018	2018
Additions of Other intangible assets	21.0	2.1	61.9	2.2	7.9
Additions of Other intangible assets through business combination*	-	-	282.1	-	-
Other intangible assets reclassified to Assets held for sale*	3.3	-	-	-	-
Additions of PP&E	123.4	39.2	270.7	89.3	149.3
Additions of PP&E through business combination*	-8.1	-	702.0	-	-
PP&E assets reclassified to Assets held for sale*	-2.8	-	-159.8	-	-
Additions of RoU assets	-	-	12.9	-	-
Additions of RoU assets through business combination*	-	-	2.0	-	-
Impairment oil and gas assets	-138.2	-	-138.2	-1.9	-1.9

* See Note 12 for additions through business combination.

Additions of Other intangible assets are related to capitalized exploration costs, license interests and administrative software. Additions of PP&E are related to development assets, assets in operation including estimate change on asset retirement obligations, and other PP&E.

On transition to IFRS 16, the Group recognized USD 12.9 million in right-of-use (RoU) assets. The Group`s right-of-use assets are related to office rent. The Group also leases personal computers and IT equipment with contract terms of one to three years, but has elected to apply the practical expedient on low value assets and does not recognize lease liabilities or right-of-use assets and the leases are instead expensed when the costs are incurred. A practical expedient has been applied to not recognize lease liabilities and RoU assets for short-term leases. The RoU assets are depreciated linearly over the lifetime of the related lease contract. The lease term varies from two to six year. See also Note 1.

Impairments

In accordance with IAS 36 Impairment of Assets, the Company's oil and gas assets are tested for impairment whenever indicators of impairment exist at the end of each reporting period. Goodwill is tested for impairment at least annually. An impairment charge is recognized when the carrying amount of the asset, including any associated goodwill, exceeds the recoverable amount (i.e., recoverable amount is the higher of the asset's fair value less cost to sell and value in use). During the third quarter of 2019, a total impairment charge of USD 138.2 million was recognized, of which USD 89.4 million was related to an impairment of technical goodwill (with no tax impact) on the Brasse discovery in the Norwegian sector of the North Sea triggered by a reduction in reserve estimate, USD 32.6 million related to an upward revision in the cost estimate for decommissioning the Schooner and Ketch fields in the UK sector of the North Sea and USD 16.2 million related to an impairment of the Erbil PSC in Kurdistan with no significant planned investments in 2020 while the company re-assesses its position in this asset. During the first nine months of 2018, a total impairment charge of USD 1.9 million was related to the SL18 exploration license in Somaliland (USD 0.4 million) and the Sfax Offshore Exploration Permit in Tunisia (USD 1.5 million).

	First nine months ending 30 September 2019			Full-Year ending 31 December 2018
	Impairment	Net recoverable/	Impairment	Net recoverable/
	charge (-)/	Net carrying	charge (-)/	Net carrying
USD million	reversal (+)	amount	reversal (+)	amount
Erbil license, Kurdistan	-16.2	-	-	16.2
Brasse, North Sea	-89.4	38.0	-	-
Schooner and Ketch, North Sea	-32.6	-	-	-
SL 18, Somaliland	-	-	-0.4	-
Sfax Offshore Exploration Permit, Tunisia	-	-	-1.5	-
Total	-138.2	38.3	-1.9	16.2

The table shows the recoverable/carrying amount for the cash generating units which have been impaired in 2019 and 2018.

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 2019	Q3 2018	2019	2018	2018
Beginning of the period	30.8	223.1	230.8	17.4	17.4
Additions	-	4.2	226.3	190.9	201.3
Fair value changes through other comprehensive income (FVTOCI)	-4.7	35.3	24.2	54.4	12.1
Disposal (step acquisition Faroe Petroleum plc)	-	-	-455.2	-	-
Total financial investments end of the period	26.1	262.6	26.1	262.6	230.8
Non-current portion	26.1	262.6	26.1	262.6	230.8
Current portion	-	-	-	-	-

Financial investments include the following:

	At 30 Sep		At 31 Dec
USD million	2019	2018	2018
Listed securities:
RAK Petroleum plc	20.8	26.7	17.9
Faroe Petroleum plc	-	228.5	209.2
Panoro Energy ASA	5.3	7.4	3.7
Total financial investments	26.1	262.6	230.8

The Company has 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 40.45 percent of the total issued shares. The Company's Executive Chairman Bijan Mossavar-Rahmani, the largest shareholder in RAK Petroleum, also serves as Executive Chairman of RAK Petroleum plc.

During 2018, the Company acquired 111,494,028 shares in Faroe Petroleum plc which represented 29.90 percent of the outstanding shares. At yearend 2018, Faroe Petroleum plc was listed on the UK's Alternative Investment Market (AIM) of the London Stock Exchange. On 11 January 2019, the Company obtained control of Faroe Petroleum plc and subsequently de-listed the company from AIM on 14 February 2019 (see Note 12).

The Company has a total of 2,641,465 shares in the Oslo-listed Panoro Energy ASA.

Note 9 | Trade and other receivables

USD million	At 30 Sep 2019	2018	At 31 Dec 2018
Trade debtors	169.3	-	182.8
Underlift	25.2	14.0	1.1
Other short-term receivables	104.3	24.9	25.9
Total trade and other receivables	298.7	38.9	209.8

The underlift receivable of USD 25.2 million as of 30 September 2019 relates to the North Sea segment and will be realized at market value when the barrels are lifted. Other short-term receivables relate mainly to items of working capital for oil and gas licenses in Kurdistan and the North Sea segments.

The trade debtors relate mainly to crude oil deliveries to the export market from the Tawke license in Kurdistan.

Note 10 | Interest-bearing liabilities

Interest-bearing liabilities

		Facility	Facility			At 30 Sep		At 31 Dec
USD million	Ticker	currency	amount	Interest	Maturity	2019	2018	2018
Non-current
Bond loan (ISIN NO0010740392)	DNO01	USD	140.0	8.75%	18/06/20	140.0	200.0	400.0
Bond loan (ISIN NO0010823347)	DNO02	USD	400.0	8.75%	31/05/23	400.0	400.0	200.0
Bond loan (ISIN NO0010852643)	-	USD	400.0	8.375 %	29/05/24	400.0	-	-
Bond loan (ISIN NO0010811268)	FAPE01	USD	51.6	8.00%	28/04/23	51.6	-	-
Borrowing issue costs related to bonds						-20.5	-26.6	-24.3
Exploration financing facilities		NOK	1,700.0	see below	see below	41.8	10.6	-
Total non-current interest-bearing liabilities						1,012.9	584.0	575.7
Current
Exploration financing facilities		NOK	1,700.0	see below	see below	53.9	32.1	18.4
Total current interest-bearing liabilities						53.9	32.1	18.4
Total interest-bearing liabilities						1,066.8	616.2	594.1

Security and pledges

		At 30 Sep
USD million	2019	2018	2018
Exploration tax refund	136.4	48.8	28.3
Restricted cash	-	0.9	0.6
Total book value of assets pledged	136.4	49.7	28.9

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

	At 1 Jan	Cash		Non-cash changes	At 30 Sep
USD million	2019		flows Amortization	Currency	Acquisition	2019
Bond loans	600.0	291.6	-	-	100.0	991.6
Borrowing issue costs	-24.3	-5.5	9.3	-	-	-20.5
Exploration financing facilities (non-current)	-	43.7	-	-2.0	-	41.7
Exploration financing facilities (current)	18.4	20.8	-	-3.1	17.7	53.9
Total	594.1	350.6	9.3	-5.1	117.7	1,066.8

	At 1 Jan	Cash		Non-cash changes	At 30 Sep
USD million	2018		flows Amortization	Currency	Acquisition	2018
Bond loans	400.0	200.0	-	-	-	600.0
Borrowing issue costs	-27.2	-10.5	11.1	-	-	-26.6
Exploration financing facility (non-current)	-	10.9	-	-0.2	-	10.7
Exploration financing facility (current)	17.6	15.0	-	-0.5	-	32.1
Total	390.4	215.4	11.1	-0.7	-	616.2

Details regarding bonds issued by DNO ASA or its subsidiaries can be found in the table above. Facility amount is shown net of bonds held by DNO ASA.

On 29 May 2019, DNO ASA completed the placement of USD 400 million of a new, five-year senior unsecured bond issued at 100 percent of par with a coupon rate of 8.375 percent. In connection with the bond placement, the Company agreed to buy back USD 60 million in nominal value of DNO01 at 104.16 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. DNO ASA has during the second and third quarter acquired USD 34.2 million of FAPE01 bonds at a price range of 107.25 to 107.50 percent of par plus accrued interest.

Note 10 | Interest-bearing liabilities (continued)

The Group has available revolving exploration facilities in an aggregate amount of NOK 1.7 billion (equivalent to USD 187.1 million as of 30 September 2019). Utilization requests need to be delivered for each proposed loan. The facilities are secured against the Norwegian tax refunds and are repaid when the refunds have been received which is approximately eleven months after the end of the financial year. The interest rate equals NIBOR plus a margin of 1.30 or 1.55 percent. Utilizations can be made until 31 December 2019 (NOK 700 million) and 31 December 2020 (NOK 1.0 billion). Amount utilized as of 30 September 2019 is disclosed in the table above.

The Group has a reserve-based lending (RBL) facility in relation to its Norway and UK licenses with a total facility amount of USD 245 million which is available for both debt and issuance of letters of credit. As of 30 September 2019, the facility is undrawn and USD 84.6 million is utilized in respect of letters of credit. Interest charged on utilizations is based on the LIBOR, NIBOR or EURIBOR rates (depending on the currency of the drawdown) plus a margin ranging from 3.0 to 3.5 percent. The facility will amortize over the loan life with a final maturity date of 31 December 2025.

The Group has also available a USD 200 million short-term bank credit facility which expires on 23 January 2020.

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

		At 30 Sep
USD million	2019	2018	2018
Non-current
Asset retirement obligations	402.9	32.9	49.4
Other long-term provisions and charges	6.2	17.0	18.7
Lease liabilities	9.2	-	-
Total non-current provisions for other liabilities and charges and lease liabilities	418.3	49.9	68.1
Current
Asset retirement obligations	65.6	-	-
Other provisions and charges	32.5	9.7	7.4
Current lease liabilities	3.1	-	-
Total current provisions for other liabilities and charges and lease liabilities	101.3	9.7	7.4
Total provisions for other liabilities and charges and lease liabilities	519.6	59.6	75.4

The increase in asset retirement obligations compared to 2018 is mainly due to the acquisition of Faroe Petroleum plc (see Note 12). See Note 7 for impairment charge recognized related to the Schooner and Ketch fields in the UK sector of the North Sea, due to an upward revision in the cost estimate for decommissioning.

On transition to IFRS 16, the Group recognized USD 12.7 million as lease liabilities. The identified lease liabilities have no significant impact on the Groups financing, loan covenants or dividend policy. The Group does not have any residual value guarantees. Extension options are included in the lease liability when, it based on the managements judgement, is reasonably certain that an extension will be exercised.

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

		At 30 Sep
USD million	2019	2018	2018
Within one year	3.8	5.4	4.0
Two to five years	10.1	14.4	11.1
After five years	0.6	1.5	2.3
Total undiscounted lease liabilities end of the period	14.5	21.3	17.3

The Groups future minimum lease payments under non-cancellable operating leases are related to office rent including warehouse and equipment. The difference between the recognized lease liabilities and undiscounted lease liabilities is due to discounting and adjustment for short-term leases and low-value leases. The Groups lease of drilling rigs relates to Kurdistan drilling activities. The contracts are cancellable and thus not included in the table above. Total cancellable contracts are estimated to be USD 13 million (gross, undiscounted) as of 30 September 2019.

Note 12 | Business combinations

The Company has completed two transactions during the first half of 2019 as described below. Both transactions are regarded as business combinations and are accounted for using the acquisition method in accordance with IFRS 3 Business Combinations. The general principle in IFRS 3 is that the identifiable assets acquired and liabilities assumed are measured at their acquisition date fair values. Each identifiable asset and liability is measured at its acquisition date fair value based on guidance in IFRS 3 and IFRS 13 Fair Value Measurement. The standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. This definition emphasizes that the fair value is a market-based measurement, not an entity-specific measurement. When measuring the fair value, the Group uses the assumptions that market participants would use when pricing the asset or liability under current market conditions, including assumptions about risk. Acquired producing and development assets (i.e., PP&E) as well as discovery assets (i.e., intangible assets) have been valued using the income-based approach.

The valuations are based on currently available information about fair values as of the acquisition dates. If new information becomes available within 12 months from the acquisition dates, the Group may change the fair value assessment in the PPAs in accordance with guidance in IFRS 3. Eventual changes in fair values will be recorded retrospectively from the acquisition dates.

Acquisition of Faroe Petroleum plc (Faroe)

On 8 January 2019, the Company announced the terms of a final cash offer for the entire issued and to be issued share capital of Faroe at a price of 160 pence in cash for each Faroe share. The final offer had become unconditional in all respects on 11 January 2019, which was when the Company obtained control over Faroe by achieving more than 50 percent ownership. The Company now owns 100 percent of the entire issued share capital of Faroe.

The Company has obtained the necessary government approvals for the change of control in Norway and has submitted the required notifications in the UK and Ireland. No notification was necessary in the Netherlands.

The consideration payable by the Company under the terms of the final offer was funded from existing cash resources. The Company's main reason for the acquisition was to firmly establish itself in the North Sea. The Faroe acquisition strengthens the Group's portfolio and operational capabilities in the North Sea, transforming the Group into a more diversified company with a strong, second leg. Through the transaction, the Group obtained attractive exploration, development and production projects and an experienced team with extensive knowledge of the North Sea.

Purchase price allocation (PPA)

The acquisition date is determined to be the date the offer became unconditional in all respects on 11 January 2019, which is when the Company obtained control over Faroe by achieving more than 50 percent ownership. For convenience purposes, the Company has designated 1 January 2019 as the acquisition date. A PPA has been performed as of this acquisition date to allocate the consideration to provisional fair values of acquired assets and assumed liabilities of Faroe. Provisional fair values of the acquired assets and liabilities assumed as of the acquisition date were as shown in the table below:

	Fair value at
USD million	acquisition-date
Deferred tax assets*	45.9
Other intangible assets	282.1
Property, plant and equipment	560.6
Right-of-use assets	2.0
Inventories	17.9
Trade and other receivables	121.0
Tax receivables (current)	31.2
Cash and cash equivalents	154.5
Total assets	1,215.2
Deferred tax liabilities*	143.2
Interest-bearing liabilities (non-current)	100.0
Lease liabilities	2.0
Provisions for other liabilities and charges (non-current)	394.1
Trade and other payables	180.8
Income tax payable	0.5
Current interest-bearing liabilities	17.7
Provisions for other liabilities and charges	15.8
Total liabilities	854.1
Total identifiable net assets at fair value	361.1
Consideration	812.0
Goodwill	450.9

* Deferred tax assets/liabilities are presented net in the statements of financial position if there is a legal right to settle current tax amounts on a net basis and the deferred tax amounts are levied by the same tax authority.

Note 12 | Business combinations (continued)

The PPA above does not include effects from the swap agreement with Equinor as the transaction was completed on 30 April 2019 following approval by Norwegian authorities (see below). The note disclosure information related to assets held for sale was included in the first quarter 2019 interim report.

The goodwill recognized in the transaction relates mainly to technical goodwill due to the requirement to recognize deferred tax assets and liabilities for the temporary difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. Licenses under development and licenses in production can only be sold on a post-tax value pursuant to the Norwegian Petroleum Taxation Act, section 10. The assessment of fair value of such licenses is therefore based on cash flows after tax. Nevertheless, in accordance with IAS 12 Income Taxes, a provision is made for deferred tax corresponding to the tax rate multiplied by the difference between the acquisition cost and the tax base. The offsetting entry to this deferred tax is technical goodwill. This goodwill will be not be deductible for tax purposes.

Swap agreement with Equinor Energy AS (Equinor)

On 30 April 2019, the Company announced the completion of the swap agreement with Equinor Energy AS, a wholly-owned subsidiary of Equinor ASA following approval by Norwegian authorities. The swap agreement was signed on 4 December 2019 and represents a balanced swap with no cash consideration. The effective date of the transaction is 1 January 2019.

As part of the transaction, Faroe Petroleum's interests in the non-producing Njord and Hyme redevelopment and Bauge development assets (divested assets) were exchanged for interests in four Equinor-held producing assets on a cashless basis, including interests in the Alve, Marulk, Ringhorne East and Vilje fields (acquired assets). The Company received a USD 46 million payment from Equinor reflecting net income from the acquired assets, reimbursement of investments related to the divested assets and working capital adjustments from 1 January 2019 to transaction completion on 30 April 2019. The divested assets have been derecognized and no gain or loss was recorded in the Group accounts.

Purchase price allocation (PPA)

The acquisition date is determined to be 30 April 2019, which is the date of completion of the agreement. A PPA has been performed as of this acquisition date to allocate the consideration to provisional fair values of acquired assets and assumed liabilities of the acquired assets. Provisional fair values of the acquired assets and liabilities assumed as of the acquisition date were as shown in the table below:

USD million	Fair value at acquisition-date
Property, plant and equipment	141.5
Tax receivables (non-current)	-22.6
Trade and other receivables	2.2
Cash and cash equivalents	29.6
Total assets	150.9
Deferred tax liabilities*	89.1
Provisions for other liabilities and charges (non-current)	14.0
Total liabilities	103.1
Total identifiable net assets at fair value	47.8
Fair value of acquired assets	148.5
Goodwill	100.7

* Deferred tax assets/liabilities are presented net in the statements of financial position if there is a legal right to settle current tax amounts on a net basis and the deferred tax amounts are levied by the same tax authority.

The goodwill recognized in the transaction relates to technical goodwill due to the requirement to recognize deferred tax assets and liabilities for the temporary difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. Licenses under development and licenses in production can only be sold on a post-tax value pursuant to the Norwegian Petroleum Taxation Act, section 10. The assessment of fair value of such licenses is therefore based on cash flows after tax. Nevertheless, in accordance with IAS 12, a provision is made for deferred tax corresponding to the tax rate multiplied by the difference between the acquisition cost and the tax base. The offsetting entry to this deferred tax is technical goodwill. This goodwill will be not be deductible for tax purposes.

For comparison purposes, assuming that the acquisition had taken place effective 1 January 2019, it is estimated that revenues in the first nine months of 2019 would have increased by USD 44 million while net profit (after tax) would have increased by USD 5 million.

Note 13 | Subsequent events

The Company's Board of Directors approve dividend payment

On 23 October 2019, the Company announced that, pursuant to the authorization granted at the Annual General Meeting held on 29 May 2019, the Board of Directors has approved a dividend payment of NOK 0.20 per share to be made on 4 November 2019 to all shareholders of record as of 28 October 2019.

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). DNO 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 2019	Q3 2018	2019	2018	2018
Revenues	227.0	171.2	696.7	460.5	829.3
Lifting costs	-50.4	-22.1	-145.0	-58.5	-90.4
Tariffs and transportation	-13.9	-	-25.8	-	-
Movement in overlift/underlift	2.4	-	4.0	-	-
Exploration expenses	-47.4	-7.2	-98.5	-45.1	-64.7
Administrative expenses	-7.0	-8.2	-20.1	-23.7	-36.7
Other operating income/-expenses	-1.6	9.1	-18.9	0.8	1.4
EBITDA	109.2	142.7	392.4	334.0	638.8

EBITDAX

USD million	Q3 2019	Q3 2018	2019	2018	2018
EBITDA	109.2	142.7	392.4	334.0	638.8
Exploration expenses	47.4	7.2	98.5	45.1	64.7
EBITDAX	156.5	150.0	490.9	379.1	703.5

Netback

USD million	Q3 2019	Q3 2018	2019	2018	2018
EBITDA	109.2	142.7	392.4	334.0	638.8
Change in revenue recognition criteria, Kurdistan	-	-	-	-	-182.8
Taxes received/-paid	-	-	-	-	33.2
Netback	109.2	142.7	392.4	334.0	489.1
	Q3 2019	Q3 2018	2019	2018	2018
Netback (USD million)	109.2	142.7	392.4	334.0	489.1
Company Working Interest production (MMboe)	9.1	7.5	27.4	21.4	29.9
Netback (USD/boe)	12.0	19.0	14.3	15.6	16.4

Lifting costs	Q3 2019	Q3 2018	2019	2018	2018
Lifting costs (USD million)	-50.4	-22.1	-145.0	-58.5	-90.4
Company Working Interest production (MMboe)	9.1	7.5	27.4	21.4	29.9
Lifting costs (USD/boe)	5.5	2.9	5.3	2.7	3.0

Acquisition and development costs

USD million	Q3 2019	Q3 2018	2019	2018	2018
Purchases of intangible assets	-21.0	-2.1	-61.9	-2.2	-7.8
Purchases of tangible assets	-87.3	-39.2	-233.7	-89.3	-130.3
Acquisition and development costs*	-108.3	-41.3	-295.6	-91.5	-138.0

* Acquisition and development costs exclude estimate changes on asset retirement obligations.

Alternative performance measures (continued)

Operational spend

	Quarters		First nine months		Full-Year
USD million	Q3 2019	Q3 2018	2019	2018	2018
Lifting costs	-50.4	-22.1	-145.0	-58.5	-90.4
Exploration expenses	-47.4	-7.2	-98.5	-45.1	-64.7
Exploration costs capitalized in previous years carried to cost (Note 5)	17.9	-	21.1	-	-
Acquisition and development costs	-108.3	-41.3	-295.6	-91.5	-138.0
Operational spend	-188.2	-70.6	-518.0	-195.1	-293.2
Equity ratio USD	Q3 2019	Q3 2018	2019	2018	2018
Equity	1,159.5	1,028.8	1,159.5	1,028.8	1,217.8
Total assets	3,162.5	1,805.2	3,162.5	1,805.2	2,004.3
Equity ratio	36.7%	57.0%	36.7%	57.0%	60.8%
Free cash flow	Q3 2019	Q3 2018	2019		2018
				2018
USD million
Cash generated from operations Acquisition and development costs	228.1 -108.3	132.9 -41.3	364.0 -295.6	324.8 -91.5	472.0 -138.0
Payments for decommissioning	-5.3	-	-13.6	-	-
Free cash flow	114.5	91.6	54.8	233.3	334.0
Marketable securities USD million	Q3 2019	Q3 2018	2019	2018	2018
Financial investments	26.1	262.6	26.1	262.6	230.8
Treasury shares*	83.7	72.0	83.7	72.0	50.5
Marketable securities	109.8	334.7	109.8	334.7	281.3

USD million	Q3 2019	Q3 2018	2019	2018	2018
Cash and cash equivalents	624.0	640.2	624.0	640.2	729.1
Bond loan (Note 10)	991.6	600.0	991.6	600.0	600.0
Net cash/-debt	-367.6	40.2	-367.6	40.2	129.1

Exploration financing facilities have been excluded as these are covered by the exploration tax refund recognized as asset in the statements of financial position. See Note 6 and 10.

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 also 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, 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 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 before tax for the period 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 CWI 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 before tax for the period without regard to significant events and/or decisions in the period that are expected to occur less frequently, per CWI 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 CWI 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, exploration expenses and acquisition and development costs. Management believes that this measure is useful because it provides a complete overview of the Group`s total operational costs and capital investments 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 cash generated from operations less acquisition and development costs. 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.

Marketable securities

Marketable securities are comprised of the sum of market value of financial investments and treasury shares. Management believes that this measure is useful because it provides an overview of liquid assets that can be converted to cash in a short period of time.

Net debt

Net debt comprises cash and cash equivalents less bond loans (see Note 15 in the consolidated accounts). 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 balance sheet date.

		NOTES
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