The World Is Screaming for Oil After 20 Yearsand Eroded Spare

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INDUSTRIAL CONTEXT FOR US ENDEAVOUR 2005-2020 FINAL REPORT

02.10.2020 Executive summary The need to go out – US GoM deepwater was the best initial choice

Strong strategic reasons to seek international US GoM deepwater was the rational choice opportunities for a NCS player in 2005 • Macro environment called for non-OPEC production • Steep creaming curve, low political risk, attractive growth and improved oil price fiscal regime and no privileges to NOCs • IOCs were priced on growth outlooks • All significant deepwater operators entered GOM • NCS production appeared to have peaked with • Statoil was the largest deepwater operator globally NCS players' value penalized due to low R/P ratios and entered early with an attractive Encana deal • NCS players were leading in deepwater/subsea • Statoil was an aggressive explorer in US GoM, but technologies and had organizational capacity underestimated geological and business challenges

Historical and projected oil production as seen from 2005 Top deepwater operators in 2005 US GoM investment* 2005-19 Million barrels per day Crude production deeper than 125m Billion USD real 2020 4 Statoil + Hydro NCS Petrobras 3.5 ExxonMobil BP 3 Shell Total 2.5 2006 Annual Chevron Energy Outlook Eni 2 Freeport CNRL 1.5 CNOOC Anadarko 1 TAQA US GoM Santos 0.5 deepwater Hess 2005 Resource Report CoP 0 Murphy Oil 1990 1995 2000 2005 2010 2015 2020 2025 Woodside *M&A, capex and expex Source: UCube; EIA; NPD; Rystad Energy research and analysis

2 Executive summary Shale – a true revolution early understood by Statoil

Shale gas was the natural choice in 2008 Tight oil was the natural choice in 2010

• World still screaming for oil, “the easy oil is gone” – • US screaming for gas, attractive prices expected – tight oil break-through could take off globally as confirmed in Snøhvit and Shtokman studies • Statoil early in acquiring acreage and organization • Potential global revolution – important to master in Bakken - the most attractive basin in 2011 • Statoil picked the right play early, and cheap • Statoil missed the tight oil revolution in Permian • All relevant players entered at similar conditions as • All relevant players entered US tight oil, but Statoil’s Statoil or worse bet was high relative to company size • Statoil underestimated need to align contract • Statoil underestimated need for midstream access incentives and take-away capacity and complexity of land management

Selected companies and the bet taken in shale gas and tight oil (Net M&A + Capex) BUSD real 2020 100 Majors

75 IOCs 67 Pure play shale companies 56 43 38 34 33 33 27 27 26 26 17 11 8.5 7.4 6.0 3.1 0.1

Source: UCube; Rystad Energy research and analysis

3 Executive summary The unforeseen market collapse and NCS success made US entry look bad in hindsight

Shale a victim of its own success

• Shale became a success beyond everybody’s expectations resulting in oversupply and market collapse • Gas prices under double attack: Shale gas abundance and associated gas from tight oil revolution • Oil price under triple attack: Tight oil productivity, new super play (Permian) and OPEC volume war • Almost all players destroyed value except from landowners and early exits, Brigham deal would have created marginal value if market conditions prevailed. • Unforeseen successes at NCS made US expansion, seen in hindsight, less pressing.

US commodity prices and major acquisitions by Statoil Value creation from US onshore activity 2005-2019 (excl. finance costs) WTI (USD/bbbl) Henry Hub (USD/mmBTU) Present value 2020 (BUSD)* Tax payed Opex incurred 250 140 Brigham/ 20 Capex incurred US Bakken 18 200 Remaining value of portfolio 120 Revenue received GoM 16 150 Net M&A 100 14 Value creation 100 80 12 10 50 60 Eagle 8 0 Ford 40 6 -50 4 20 -100 2 Marcellus 0 0 -150 -200

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 -250

*WACC 10% nominal, 2% future inflation Source: UCube; EIA; Rystad Energy research and analysis

4 Index

Industry outlook in 2005 as seen from the NCS Activity in the US GoM deepwater from 2005-2020 Developments in the US unconventional industry from 2005 to 2020 External analyst coverage of Equinor’s M&A activity on US onshore

5 2005: The world is screaming for oil after 20 years of low prices low spare capacity

OPEC spare Liquids demand history and IEA projections (WEO 2006) Brent oil price capacity Million barrels per day Dollar per barrel (Real Dec. 2005) Percent* 120 100 100%

90 90% WEO2006 projections 100 with 1.7% annual growth 80 80%

Brent oil High GDP growth 70 70% 80 price expectations for: - China 60 60% Liquids - India 60 demand Oil - Brazil 50 50% prices rising 40 40% 40 “The easy oil is gone” 30 30% OPEC spare 20 20% 20 capacity eroded 10 10% OPEC spare capacity 0 0 0% 1980 1985 1990 1995 2000 2005 2010 2015

• Following the oil price collapse in 1986, where OPEC decided to increase their market shares by utilizing their large spare capacity (25% of the worlds production in 1985), the industry saw 20 years of low oil prices. • Over the same period oil demand grew at 1.7% per year. Over these years the OPEC spare capacity gradually eroded to serve the increase in demand. • 20 years of very low oil prices had led to underinvestment in the non-OPEC world. With steady demand growth expectations and very limited OPEC capacity to deliver these volumes, it was up to the non-OPEC world and largely offshore oil to deliver these volumes. The stage was set for production growth outside OPEC and higher oil prices.

*Measured as percentage of global production in every year Sources: IEA WEO 2006, EIA, Cube; Rystad Energy research and anlysis

6 2005: Production growth was seen as the key challenge in the upstream industry

2005: • “All” industry players, at this page illustrated by CERA, Shell and OPEC, expected oil demand to far exceed 100 Mmboe by 2020, driven by Asia • A supply shortage was expected • Oil from the North Sea and other OECD regions expected to decline • Deepwater, oil sands and OPEC were seen as key growth areas • Oil companies focused on growth in their capital market communication

Source: CERA; November 19, 2005: Oil Industry’s Growth Challenge, Shell annual report 2006; OPEC presentation March 2005 …

7 2005: Statoil had among the lowest RP ratio in the industry and recieved a price discount

RP-ratio* as of 31.12.2004 by company RP-ratio as of 31.12.2004 by company** RP-ratio as of 31.12.2004 by region Oil and gas production divided by 1P reserves Oil production divided by 1P reserves Oil production divided by 1p reserves

Petrobras 16.9 Petrobras 17.7 Brazil 17.7 Anadarko 16.9 Vintage 17.0 US 12.6 ConocoPhillips 16.8 Burlington 15.9 Africa 11.2 Vintage Petroleum 15.8 Spinnaker 15.3 XTO Energy 15.8 Asia 8.8 ConocoPhillips Spinnaker 15.3 14.5 Europe 5.9 Anadarko 13.2 Chevron 14.2 Norway 5.1 ExxonMobil 13.8 Chesapeake 13.0 - 5.0 10.0 15.0 20.0 Burlington 13.8 Chevron 12.1 Chesapeake 13.5 Devon Energy 12.0 BG 12.9 BP 11.8 EOG Resources 12.3 • In 2005, Norway was at peak ExxonMobil 10.9 Eni 12.1 production and Norwegian players Apache 10.7 Statoil and Hydro with high production Apache 11.8 and relatively low on proven reserves, Total 11.7 Total 9.1 thus low RP ratio Statoil 10.5 Eni 9.1 • Analysts looked for growth through BP 10.2 EOG Resources 8.3 higher RP ratio and Statoil shares Marathon Oil 9.9 Marathon Oil 6.8 were traded with discount due to low Hydro 9.8 RP ratio and limited production Hess 6.6 growth outlooks. Devon Energy 9.6 Hydro 5.7 Shell 8.8 • Seen as important to get “out of the Hess 8.7 Shell 5.6 Norwegian corner” and achieve growth internationally. Petro-Canada 7.8 Statoil 4.8

0 5 10 15 20 0 5 10 15 20

* Reserve to Production Ratio; **Only oil RP ratio in the six regions to the right included; *** Companies as shown to the left Source: SEC Edgar database; 10-K / 20-F reports; Annual reports 2004

8 2005: Liquids production on the NCS was expected to decline rapidly

Liquids production on the NCS as seen from 2005 Million Sm3 liquids per year

• The chart on the left shows the expected liquids production as published in the 2005 resource report by NPD. Resource report • On the NCS in 2005 peak oil from 2005 production was expected to be behind us – the Norwegian government was preparing for reduced oil production outputs in the future.

• Even with sanctioning of contingent resources and expected exploration success, the result was still that the annual production towards 2010 would be reduced by 20%. Towards 2020, the same production levels compared to 2005 was expected to be halved.

Legend: “Uoppdagede ressurser”=Undiscovered resources, “Betingede ressurser i funn”=Contingent resources in discoveries, “Betingede ressurser i felt”= Contingent resources in producing fields, “Reserver”=Reserves Source: Rystad Energy research and analysis, NPD resource report 2005

9 2020: Actual liquids production has outperformed the 2005 forecast since 2013

Liquids production on the NCS as seen from 2020 Million Sm3 liquids per year

250

• The chart on the left shows the 200 expected liquids production as published in the 2005 resource report by NPD compared to what really happened (black line).

150 Actual • Between 2005 and 2013, liquids production production underperformed compared to the expectations in 2005. However, actual liquids Forecast production has exceeded 100 from 2020 expectations since 2013.

• Between 2005 and 2020 the liquids production has exceeded the forecast from 2005 with 2% in total.

0 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

10 2005: First five-year period where the NCS was not able to replace volumes produced

Average gross increase in oil reserves Average reserve replacement ratio (RRR) Million boe Percentage A RRR of 2.2 indicates that more than twice as much reserves where 2250 added than reserves produced 250%

1750 2.2 1278 200% 1250 1.8 1047 831 Gross 741 750 reserve 150% 372 1.4 increase 250 1.2 100% -250 -203 0.7 -379 Production -750 50% Gross increase in reserves -761 -1250 -1064 -1087 Production 0% -1750 First negative reserve RRR trend, only replacing 70% -2250 of produced volumes -50% 1980-1984 1985-1989 1990-1994 1995-1999 2000-2004

Positive reserve replacement ratio in all time periods historically on NCS before 2000. The average reserve replacement ratio has been decreasing slowly from the peak period in 1985 to 1989 to 2000-2004. However, it has remained above 1 up until 2000. After year 2000 the average reserve replacement ratio has dropped to 0.68. This implies that only 68% of what was produced in that period was replaced with new reserves. Hence, the outlook for production and additional volumes was rather dark in 2005 on the NCS.

Source: Rystad Energy research and analysis

11 2005: Exploration at all-time low – cash-back introduced, but it does not benefit incumbents

Exploration activity on the NCS # wildcats and appraisals 70 The Norwegian government acknowledges that 60 exploration activity is halting and seeks to stimulate activity. Cash-back on 50 exploration expenses is introduced in 2005.

40 36 wells

30 Appraisals ! 21 wells 20 Avg: 20 wells Wildcats

0 1970 1975 1980 1985 1990 1995 2000 2005

• In 2005 the number of exploration wells on the NCS in 2005 was at the lowest level since at the lowest level ever since 1970. 12 exploration wells in 2005 represents a drop of 76% from the all-time high levels in 1985 and 1997.

• The Norwegian government acknowledged that exploration activity was halting and that it had to stimulate activity. Cash-back on exploration expenses was introduced in 2005. This was a very positive measure for new entrants that were not in tax position, but tax neutral for incumbents with production like Hydro and Statoil. The effect for incumbents were increased competition for offshore exploration acreage.

Source: Rystad Energy research and analysis, NPD

12 2005: Discovered resources per exploration well on NCS was at an all-time low

NCS creaming curve - cumulated discoveries Billion boe 70 Curve flattens out from 1990 to 2005

Additional 21% of • The creaming curve on the left 60 shows how the cumulated historical volumes discovered resources on the NCS added Ormen have flattened out from the late 1980s to 2005. Grane Lange 50 61% of all volumes • Of the 63.6 billion boe that was Heidrun discovered before 2005, 61% was discovered discovered before 1980 and 82% Aasgard 800 16.0 before 1980 Average discovered before 1990. 40 Snohvit 700 resources (mmboe) 14.0 • Although the number of average Oseberg 600 10.6 12.0 discoveries remains relatively 9.4 500 10.0 constant, the average resource 30 8.5 Snorre size of each discovery is trending 400 Average discoveries 8.0 774 downwards drastically. per year (#)

300 6.0 • Average discovered resources per 20 Troll 200 3.6 4.0 discovery (column chart) at all time

100 2.0 low in the period 2000-2005 at 39 Gullfaks 142 90 39 mmboe per discovery, 95% below 0 0.0 the all-time high level in 1966- 1966-1979 1980-1989 1990-1999 2000-2005 10 Statfjord 1979.

Ekofisk 1980 1990 2000 2005* 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 73 75 77 79 81 83 85 87 89 91 93 95 97 99 0 101 103 105 107 109 111 113 115 117 119 121 123 125 127 129 131 133 135 137 139 141 143 145 147 149 151 153 155 157 159 161 163 165 167 169 171 173 175 177 179 181 183 185 187 189 191 193 195 197 199 201 203 205 207 209 211 213 215 217 219 221 223 225 227 229 231 233 235 237 239 241 243 245 247 249 251 253 255 257 259 261 263 265 267 269 271 273 275 277 279 281 283 285 287 289 291 293 295 297 299 301 303 305 307 309 311 313 315 317 319 321 323 325 327 329 331 333 335 337 339 341 343 345 347 349 351 353 355 357 359 361 363 365 367 369 371 373 375 377 379 381 383 385 387 389 391 393 395 397 399 401 403 405 407 409 411 413 415 417 419 421 423 425 427 429 431 433 435 437 439 441 443 445 447 449 451 453 455 457 459 461 463 465 467 469 471 473 475 477 479 481 483 485 487 489 491 493 495 497 499 501 503 505 507 509 511 513 515 517 519 521 523 525 527 529 531 533 535 537 539 541 543 545 547 549 551 553 555 557 559 561 563 565 567 569 571 573 575 577 579 581 583 585 587 589 591 593 595 597 599 601 603 605 607 609 611 613 615 617 619 621 623 625 627 629 631 633 635 637 639 641 643 645 647 649 651 653 655 657 659 661 663 665 667 669 671 673 675 677 679 681 683 685 687 689 691 693 695 697 699 701 703 705 707 709 711 713 715 717 719 721 723 725 727 729 731 733 735 737 739 741 743 745 747 749 751 753 755 # wildcats drilled (755 drilled from 1966 through 2005)

*All other years than 2005 represent year beginning, e.g. 1980 = beginning of 1980. 2005 is year end. Source: Rystad Energy research and analysis, NPD

13 2005: Strong drive to look for opportunities outside NCS and outside Africa/Middel East

• Norwegian oil and gas production was peaking over the period 2001-2005 • The sentiment was then, as expressed by the government and in the press as shown here, that production will 30%-50% by 2020 • For Statoil, having an aggressive strategy for internationalization was seen as natural and correct. • However, two issues was associated with current international portfolio; 1) risks associated with corruption and political stability, 2) issues with PSA regimes – typically in Africa and Middle East - limiting financial upside and production growth at high oil prices. • Thus, pursuing growth in United States, with recent breakthrough in the geological potential and attractive fiscal systems, was seen as attractive

Sources: St.meld.38 2001-2002 Om olje- og gassvirksomheten; Aftenposten 9.11.2002; DN 20.1.2004;

14 2005: Growing and competent knowledge base on the NCS with few projects to work on

Direct employment in the Norwegian petroleum industry Resources under development Thousands Billion boe 40 40 Direct employment level in oil and gas in 2005 Top 10 countries by installed subsea XMTs in 2005 0 100 200 300 400 500 600 700 800 at all time high with 35,000 people. UK 756 35 Brazil 643 35 Norway 467 US GoM 420 30 Angola 235 30 Eq. Guinea 86 Nigeria 73 Australia 71 25 Canada 42 25 Indonesia 37 With limited development agenda on the NCS it was a 20 clear rationale to staff employees 20 to resource development elsewhere. Resources under 15 development had fallen by 72% 15 from 1994 to 2005 and the direct employment level in the 10 Norwegian oil and gas industry 10 had risen by 41%. Troll

5 Oseberg 5

Statfjord Aasgard Gullfaks 0 0 1973 1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005

• The employment level in the oil and gas industry in 2005 had grown in the opposite direction of the resource under development in 2005. In order to utilize the people and knowledge base within the Norwegian oil and gas industry it was pertinent to look for international growth opportunities to utilize the highly competent labor • In 2005 the Norwegian oil and gas industry was leading on reservoir modelling and subsurface understanding, flow assurance, horizontal drilling and subsea technologies.

Source: Rystad Energy research and analysis, NPD

15 2005: Where to go? Deepwater GoM was sought out for resource potential and economics

Discovered deepwater offshore liquids resources (deeper than 125m) US GoM investment rationales: Billion boe 12 North “The Gulf of Mexico was identified early as a focus area Other Sea as it offered significant growth potential (estimated 6 % Large undiscovered resources of 15 billion barrels of oil and 100 14 % Tcf of gas), established infrastructure and market, Brazil resource politically stable area and good fiscal terms.” – 2002 10 potential 9 %

22 % 49 %

8 US GoM West "This acquisition creates a new international core area for Statoil. It gives us the opportunity to utilize and further Africa build on our capabilities in exploration, reservoir management and subsea technology. US production, with Political its attractive fiscal regime and stable political environment, 6 stability provides an attractive balance to our overall international portfolio.“ – 2005

“The Gulf of Mexico is a highly prolific hydrocarbon province where giant fields are still being discovered. . . The fiscal regime in the GoM is simple and profitable, and 2 Attractive the leasing system allows competitors of all sizes to participate. Fiscal incentives like royalty free periods were fiscal terms introduced to help commercialise the smaller deep water finds.” - 2002

0 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Source: Rystad Energy research and analysis

16 2005: US natural gas imbalance established and improving Henry Hub prices

US natural gas consumption and production US gas prices (Henry Hub) Trillion cubic feet USD/kcf 35 Deal to study development options 30 for Shtokman with the aim to market gas to the US

30 Statoil places a bet on the US gas market with the 25 sanctioning of the Snøhvit field, Melkøya LNG terminal and Cove Point regas terminal on the US 25 East Coast 20

20 RegionalRegional supply/demand supply/demand imbalanceimbalance increasing increasing Gas from US shelf 15 US GoM production Gasassets deliveries on decline from the 15 US shelf on decline

Gas prices all- time high 10 10 L48 conventional production*

5 5

Henry Hub 0 0 1980 1985 1990 1995 2000 2005 2010 2015

*Includes CBM and tight gas Source: EIA; UCube; Equinor press releases

17 2008: Emergence of shale gas with still favorable macro conditions in the US

US natural gas consumption and production US gas prices (Henry Hub) Trillion cubic feet USD/kcf 35 Deal to study development options 30 for Shtokman with the aim to market gas to the US

30 Total and StatoilHydro chosen as Statoil places a bet on the US gas market with the partners for the Shtokman 25 sanctioning of the Snøhvit field, Melkøya LNG development terminal and Cove Point regas terminal on the US 25 East Coast 20

20 Gas from tight/shale oil Shale gas 15 US GoM production 15

10 10 L48 conventional production*

5 5

Henry Hub 0 0 1980 1985 1990 1995 2000 2005 2010 2015

*Includes CBM and tight gas Source: EIA; UCube; Equinor press releases

18 2019: Shale gas revolution yielded net gas exports from the US and low gas prices

US natural gas consumption and production US gas prices (Henry Hub) Trillion cubic feet USD/kcf 35 Deal to study development options 30 for Shtokman with the aim to market gas to the US

20 Shale gas 15 US GoM production 15

10 10 L48 conventional production*

5 5

Henry Hub 0 0 1980 1985 1990 1995 2000 2005 2010 2015

*Includes CBM and tight gas Source: EIA; UCube; Equinor press releases

19 2008-2019: Equinors bet in the US was high compared to other INOCs

US investments relative to market cap US investments (M&A and capex) Market cap in 2008 Percentage invested by market cap) BUSD real 2008 BUSD

0 0.2 0.4 0.6 0.8 1 1.2 1.4

0 20 40 60 80 100 120 140 0 100 200 300 400 500 600

EQT Corporation

Exxonmobil +100% 97 Exxonmobil 511

EOG Resources

Occidental Petroleum +100% 68 Shell 265

Chesapeake +100% Chevron 57 Petrobras 240

Occidental Petroleum +100% Shell 56 BP 231

Murphy Oil 80 % EOG Resources 46 Total 198

Devon Energy Chevron 79 % BP 44 197

Marathon Oil BHP 64 % BHP 34 188

Hess Eni 62 % Equinor 33 147

CNOOC ConocoPhillips 34 % ConocoPhillips 33 141

Equinor Equinor 33 % Devon Energy 32 100

CNOOC Chevron 29 % Marathon Oil 28 75

Occidental Petroleum ConocoPhillips 23 % CNOOC 26 65

Repsol Repsol 22 % Chesapeake 23 44

Marathon Oil Shell 21 % EQT Corporation 21 44

Devon Energy

BP 19 % Hess 19 41

Hess

Exxonmobil 19 % Murphy Oil 13 32

EOG Resources

BHP Repsol 22 18 % 10

Chesapeake

Total Total 20 5 % 9

Murphy Oil Eni 16 4 % Eni 6

EQT Corporation

Petrobras 7 2 % Petrobras 4

Sinochem

Sinochem 0 Sinochem 3

Source: Rystad Energy research and analysis

20 2008-2019: Several companies struggled to captured value from their US bets

Present value of historical and future cash flows (excl. finance costs)* Value creation (black line) Billion USD Billion USD

400 400

300 300

200 200

Revenue Value creation 100 (right axis) 100

Remaining value 0 of portfolio 0

M&A Capex -100 -100 Opex

Tax -200 -200

-300 -300

-400 BP Shell EOG Resources ExxonMobil Chesapeake Chevron ConocoPhillips Devon Energy Marathon Oil BHP Hess Equinor Occidental Petroleum EQT Corporation Murphy Oil Eni CNOOC Repsol Total Petrobras Sinochem -400

*10% nominal discount rate, 2% inflation rate Source: Rystad Energy research and analysis

21 2008-2019: Like many other IOCs Equinor struggled to create value

Value creation per dollar invested Value creation* Present value of investments USD (real 2020) BUSD NPV 2020 BUSD PV2020

-1.0 -0.8 -0.6 -0.4 -0.2 - 0.2 0.4 0.6 0.8 1.0 Exxonmobil 213 0.9 82

Shell 0.6 53 117

Chevron 0.6 48 103

Occidental Petroleum 0.5 38 103

0.4 27 BP 93

0.4 15 EOG Resources 91

0.4 11 BHP 85

0.3 8 Equinor 75

0.2 2 Devon Energy 70

0.0 0 ConocoPhillips 68

-0.0 -1 Marathon Oil 57

-0.0 -2 Chesapeake 48

-0.1 -3 Hess 41

-0.1 -5 EQT Corporation 38

-0.2 -6 CNOOC 26

-0.2 -6 Murphy Oil 25

-0.3 -7 Total19

-0.3 -11 Repsol17

-0.3 -24 14Eni

-0.4 -28 11Petrobras

-0.5 -69 4Sinochem

0 50 100 150 200 250 300 350 400 450

*Before finance costs, discount rate 10%, inflation rate 2% Source: Rystad Energy research and analysis Index

23 The deepwater US GoM saw large investments from international players, with exploration results strong overall but mixed for Statoil

Key take-away Industrial context in US GoM deepwater Statoil positioning

In the early 2000s, the For a company with strong offshore US GoM deepwater drew investment and new deepwater Gulf of Mexico capabilities, the deepwater GoM was one of entries due to its resource potential, open access, emerged as a top the logical areas to add to the portfolio in attractive tax terms, and a lack of a NOCs with destination for international the context of a weak growth outlook for privileges E&P investment Norway

From 2005-2010 multiple international companies entered the US GoM deepwater through Statoil and Hydro entered prior or early in Deepwater GOM saw a new acquisitions, including Repsol, Eni, Inpex and this wave. Hydro entered in 2001, Statoil in wave of new international Ecopetrol. These companies spent over $12 2003, but the major entry was with the entrants in the early 2000s billion to enter or bolster positions in the Gulf of acquisition of the Encana portfolio in 2005 Mexico.

Statoil began leasing acreage in 2005 and The exploration potential of Explorers spent $16 billion acquiring exploration was the third highest spender in the lease the GoM drove growing licenses in lease sales (auctions) in the US rounds, spending $1.2 billion in these spend in lease auctions deepwater Gulf of Mexico from 2005-2019. auctions in this period. However, Statoil was unable to create value in exploration.

Source: Rystad Energy research and analysis

24 After Statoil’s initial M&A entry followed significant investments in new developments

Statoil’s historical investments in US GoM

BUSD nominal Total spend in the period: 2.5 • M&A 4.9 BUSD • Lease Sale 1.0 BUSD 2 • Exploration 2.1 BUSD • Development 21.4 BUSD 1.5

1 Lease sales Developments Acquisition 0.5 Exploration 0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Acquired Plains E&P’s working interest in two Statoil signed an agreement discoveries (Caesar and with Chevron Texaco to Bigfoot) and one prospect secure interest in a small for $700 million. Sold all former Spinnaker Acquired 40% interest in number of deepwater asset on the shelf to North Platte from Cobalt’s Mariner Energy for $243 bankruptcy auction, in $339 exploration opportunities. Acquired Anadarko’s million million joint bid with Total. interest in two discoveries (Knotty Head and Bigfoot) and one prospect for $901 million. Exercised preferential right Statoil purchased Encana’s to acquire 22.45% interest deepwater GoM portfolio for in Caesar Tonga from Shell $2 billion. Included stake in Merged with Norsk Hydro to for $965 million. Chevron-operated Tahiti become StatoilHydro, and a number of inheriting former Spinnaker discoveries. Exploration shelf and deepwater assets.

Source: Rystad Energy research and analysis

25 Since 2005, nearly $220 billion of capex has been spent in the deepwater Gulf of Mexico, bringing recent production to all-time highs above 2 million boe/d

60 Macondo Moratorium temporarily halted new Exploration 40 exploration and lease sales [# exploration wells] 20

0 1995 2000 2005 2010 2015 2020

25 Capital investment 2014 oil price from 2003 – 2014 in crash and shifted 20 the Gulf of Mexico investments grew on average 14% Macondo towards shale 15 per annum, peaking at drilling Development over $20B USD moratorium [BUSD capex] 10 5

0 1995 2000 2005 2010 2015 2020

2.5

1.5 Increase in production Production following the development [mmboe/d] 1 wave in 2011-2015 Hurricane Katrina Macondo 0.5

0 1995 2000 2005 2010 2015 2020

Source: UCube; Rystad Energy research and analysis

26 DW GoM has yielded large discoveries before and after Statoil’s entry in 2005

Gulf of Mexico discovered oil resources per year Million barrels of oil equivalent Thunder Horse North Mad Dog 2 (1026 mmboe) 2500 (505 mmboe) Shenzi (506 mmboe) Big Foot (400 mmboe) Tahiti (492 mmboe) Anchor (1232 mmboe) Thunder Horse (781 mmboe) Great White (403 mmboe) Appomattox (542 mmboe) Mars (1087 mmboe) 2000 Atlantis (661 mmboe) St Malo Mad Dog (414 mmboe) (320 mmboe) Ballymore (551 mmboe) Tiber (391 mmboe)

1500 Whale Auger North Platte (391 mmboe) Ursa (514 mmboe) (320 mmboe) (350 mmboe) 961 949 mmboe 933 1000 mmboe 901 mmboe mmboe Avg: 647 mmboe 491 500 415 mmboe mmboe

Pre-2005 Post-2005 0 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019

Prolific exploration discoveries by the Supermajors such as Mars (1087 mmboe) from Shell, Mad Dog (combined 1440 mmboe) by BP, and Thunder Horse (combined 1286 mmboe) from BP offered exciting opportunities for new entrants to the basin.

Note: Only showing discoveries with greater than 300 mmboe resources Source: Rystad Energy research and analysis

27 DW GoM has yielded large discoveries before and after Statoil’s entry in 2005

1500 Whale Auger North Platte (391 mmboe) Ursa (514 mmboe) (320 mmboe) (350 mmboe) 961 949 mmboe 933 1000 mmboe 901 mmboe mmboe Avg: 647 mmboe 491 500 415 mmboe mmboe

Pre-2005 Post-2005 0 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019

Since Statoil’s entry to the Gulf of Mexico in 2005, major discoveries such as Anchor (1232 mmboe) in 2014 by Chevron, Ballymore (551 mmboe) in 2018 by Chevron, and Appomattox (542 mmboe) in 2010 by Shell proved that the maturing basin still had exciting exploration opportunities

Note: Only showing discoveries with greater than 300 mmboe resources Source: Rystad Energy research and analysis

28 Before 2007 US GoM delivered superior returns compared to global offshore

Return on Gross Investments (CROGI) Percentage 30%

25%

US GoM deepwater

20%

US GoM deepwater Cost escalation delivered superior returns 15% from 2000-2007

Global deepwater Global offshore 2014 oil price collapse 10% Company WACC range

COVID-19

0% 2000 2005 2010 2015 2020

*CROGI on organic investments (return on asset spend, M&A excluded) Source: Rystad Energy research and analysis

29 Statoil entered just before the big wave of international M&A entries between 2005-2010

Gulf of Mexico M&A activity 2005-2015 Deal value, billion USD 12 10 Wave of non-US 8 entrants from 2005 to 2010 6

4 Majors US players 2 Non-US players 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Statoil acquired portfolio of deepwater assets from EnCana for $2 billion. Eni acquired Marubeni acquired Dominion portfolio mature assets from BP for • Statoil’s 2005 Encana deal was Marubeni acquired for $4.8 billion. $650 million. interest in assets from ahead of a wave of GoM

US players US JX Nippon and - Pioneer for $1.3 billion. acquisitions by foreign companies. Mitsubishi jointly Inpex farmed into Repsol bought into acquired 23.2% Anadarko GoM project • From 2006-2009, foreign non-Majors Shenzi for $2.15B interest in K2 from for $556 million. Anadarko for spent over $12 billion to enter or Statoil acquired $1.2 billion. bolster positions in the Gulf of interest in two GoM Mexico—half of all acquisitions. discoveries from Plains E&P for • International spending in the GoM $700 million. Ecopetrol acquired interest slowed from 2010-2015. Statoil acquired in K2 from interest in two GoM Chevron for discoveries from $510 million. Selected entries by non by entries Selected Anadarko for $901 million.

Note: Includes deals identified by Rystad Source: Rystad Energy research and analysis

30 Many operators and analysts recognized deepwater GoM as attractive place to invest

“The Gulf of Mexico is one of the deepwater “The oil industry is on the verge of cracking open a areas with the highest exploration potential in deep-water region in the Gulf of Mexico that could the world; with total yet-to-find reserves become the nation's biggest new domestic source of oil estimated to be at least 20,000 million barrels.” – since the discovery of Alaska's North Slope more than a Large 2006 generation ago.” – 2006 resource potential “The Gulf of Mexico was identified early as a focus area as it offered significant growth potential (estimated undiscovered resources of 15 billion barrels of oil and 100 Tcf of gas), established infrastructure and market, politically stable area and good fiscal terms.” – 2002

"This acquisition creates a new international core area for Statoil. It gives us the opportunity to utilize and further build on our capabilities “This zone (GoM) also possesses an attractive and stable in exploration, reservoir management and subsea technology. US tax regime and has historically provided one of the largest Political production, with its attractive fiscal regime and stable political returns on capital in the offshore oil industry.” – 2006 environment, provides an attractive balance to our overall international stability portfolio.“ – 2005

“The Gulf of Mexico is a highly prolific hydrocarbon province where giant fields are still being discovered. . . The fiscal regime in the GoM is simple and profitable, and the leasing system allows Attractive competitors of all sizes to participate. Fiscal incentives like royalty free periods were introduced to help commercialise the smaller "Deep-water Gulf of Mexico developments are very fiscal terms deep water finds.” - 2002 attractive. This increase in margins is accelerating our value growth despite relatively flat production year-over-year.“ - 2003

Source: Rystad Energy research and analysis

31 Statoil GoM acquisitions compare favorably to other deals at the time on a $/boe basis

Comparable US GoM deals 2005-2014 Current original resource estimate* $ per barrel-of-oil-equivalent resources mmboe

70 250

$63 60 Resource estimates revised down post transaction 200 $53 50

150 40 $40 $41

30 100

20 $14 $15 50 10 $9 $8 $9 $6 $6 0 0 Various 2010 2010 2006 2005 2010 2006 2006 2014 2006 2012 2010 Inpex (2012) Inpex Statoil (2010) Statoil (2006) Statoil (2005) Statoil (2006) Statoil Freeport Repsol (2006) Repsol Maersk (2010) Maersk Various (2006) Various Chevron (2010)Chevron Petrobras (2010) Petrobras

Statoil’s major acquisitions were among the lowest in $ per boe of comparable deals in the 2005-2014(2014) -MacMoran decade. On average, Statoil paid $9/boe for discovered resources. However, some Gulf of Mexico deals exceed $40/boe, typically when resources disappointed initial estimates. Typically, Gulf of Mexico deepwater resources cost $20/bbl to develop.

Note: Statoil deals include pre-emption rights increase of St Malo stake (2010, $6/boe); Anadarko assets deal (2006,$8/boe); Encana deal (2005, $9/boe); and Plains deal (2006, $9/boe) 1: Rystad resource estimates for discovered and producing resources only—exploration upside excluded Source: Rystad Energy research and analysis

32 Statoil developments were impacted by delays and negative macro developments

Change in Development First Project Deal FID Operator Brent FID to Performance vs expectations cost $/boe Oil First oil

Metallurgical issues with mooring shackles set Tahiti (Spar) Encana 2006 2009 12 -18% the development back by 12 months

Plains Caesar-Tonga was developed as a sub-sea Caesar-Tonga (Caesar), tieback to Anadarko’s existing Constitution (Sub-sea 2009 2012 10 Encana +150% spar, approximately 10 miles east. Tying into tieback) (Tonga) existing facility kept development costs low.

First oil was four years later than expected. The Plains & first attempt to install the platform in 2015 failed Big Foot (TLP) 2010 2018 36 Anadarko -29% as powerful currents caused tethers to detach and suffer irreparable damage.

Jack / St. Malo Chevron developed Jack/St. Malo with a semi- Encana 2010 2014 (FPS) 27 -25% sub in multiple phases.

Anadarko modelled the spar after the Lucius Heidelberg spar, as part of “Design One, Build Two” 2013 2016 (Spar) 27 -70% strategy, saving costs and abbreviating development cycle.

Delivered ahead of schedule and under budget. Facing the same strong currents as Big Foot, Stampede Anadarko 2014 2018 25 -25% Hess said that they learned from Big Foot’s mishap.

Following a long period after discovery, the Vito 16.8 2018 2021 development concept of Vito was reimagined in order to achieve substantial cost reductions

Deepwater GoM average: $21/boe Statoil average: $21/boe 1: The Jack/St. Malo development consists of 5 separate assets; Chevron is operator of 4, ExxonMobil of 1; Total, ENI, Petrobras and Murphy Oil also hold interests Source: Rystad Energy research and analysis

33 Overall, Statoil’s developments were near the GoM average breakeven

Equinor developments by full-cycle break-evens (backward looking) Average full-cycle break-even by operator USD/boe, Bubble size represents resource size USD/boe, 2005-2019 120 BP 32 Seventeen Heidelberg 100 Hands (Anadarko) Shell 38 Telemark hub Independence Chevron 39 80 hub Big BHP 51 Foot Stampede 60 Hess 51

Murphy 55 40 Jack/St.Malo Fieldwood 59 Caesar/Tonga Tahiti Tahiti (Anadarko) 20 Oxy 67

Equinor acquired 22.45% Other 84 from Shell in May 2019 0 2004 2006 2009 2012 2014 2017 2020 Start-up year

The Encana deal brought both Tahiti, Tonga part of Ceasar/Tonga, and Jack/St.Malo. These have been high quality development projects with robust break-evens. Stampede and Big Foot, both acquired through the Anadarko deal, had more challenging break-evens. Heidelberg, which was sanctioned in 2013 at the peak of the cost-curve, have some of the most challenging full-cycle break-evens.

Source: Rystad Energy Ucube

34 However, preliminary evaluation indicates that Statoil’s major deals in the Gulf of Mexico were unable to create value

Cash flows from major Statoil deals Billion USD, nominal

1.5 Forecast 1.0

0.5

0.0

-0.5 Anadarko and Plains acquisitions yet to -1.0 see positive cash flows Encana acquisition -1.5 Anadarko acquisition

-2.0 Plains acquisition

-2.5 2005 2010 2015 2020 2025 2030 2035

Performance metrics for major Statoil deals

Acquisition NPV (10%) IRR year Million USD With large upfront acquisition costs and years of Encana portfolio 2005 -870 6% development costs prior to positive cash flows, Statoil’s major Gulf of Mexico deals ultimately Anadarko assets 2006 -1 220 0% resulted in negative NPVs (10% discount rates) and low-to-negative rates of return Plains assets 2006 -720 -1%

Cash flows from Statoil acquisitions Source: Deal announcement; Rystad Energy UCube

35 Lease sales in GoM became significantly more competitive in 2007

Total spend on leases per year Median winning bid Billion USD Thousand USD

5 DW GoM Lease Sale spend 2005-2019 2 500 Shell $1.8 Chevron $1.5 Median winning bid 4 Statoil $1.1 2 000 BP $1.1 COP $0.9 Hess $0.7 3 1 500 Cobalt $0.7 Statoil entry with ExxonMobil $0.7 Encana acquisition BHP $0.7 2 1 000 Anadarko $0.6

1 500

Total lease spend

0 0 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

As Statoil entered the Gulf of Mexico, the median winning bid on a lease was approximately $600,000 USD. By 2007, this would shortly peak at over $1,400,000 USD. At the time, the minimum bid was approximately $187,000 or $37.50/acre. The rapid increase in median winning bid from 2003 to its peak in 2008 was indicative of the attractiveness of the US GoM.

Source: BOEM; Rystad Energy research and analysis

36 Of the top 30 winning lease bids, Statoil drilled on only 5 and made a discovery on 1

Statoil winning lease bids of over $10 million Million USD • In 2006, Statoil began bidding in Lease Sales in which 180 Statoil drilled a well on the Martin prospect, Wells Drilled 5 acreage is awarded to the finding noncommercial highest bidder. Awards are based purely on signature resources 130 million 160 Discovered Resources bonus. bbl • Unlike in the NCS, in the DW 140 No well GOM there is a culture of bidding with 100% working Participated in Blacktip Non-commercial well result interest and then later discovery operated by Shell, negotiating – less up-front 120 with net resources to Statoil Discovery of 100 million boe cooperation • Among Statoil’s winning bids, 100 34 were of more than $10 million, which is shown on the Statoil made a technical graph. Of these leases, Statoil 80 discovery at Thorvald only drilled 5 wells while an Statoil drilled on the Cobra additional two wells were finding noncommercial drilled by other companies on 60 amounts of crude these leases.

No commercial • The $60 million dollar joint bid for AC380 was a success, as 40 resources found at Bioko Blacktip was discovered on that block, which resources of around 125 million boe, with 20 upside. • Overall, it appears that 0 sourcing drillable prospects in this less “collegial” exploration culture has proven to be

KC78 difficult for Equinor WR55 KC384 AC380 AC810 KC154 KC198 AC811 KC169 AC424 KC383 KC698 KC178 KC121 KC284 KC136 GC480 GC486 GC955 GC139 GC436 GC138 GC322 GC485 MC718 MC801 MC814 WR271 WR227 WR160 WR589 WR315 WR189 WR272

Source: BOEM, Rystad Energy Ucube & WellCube

37 Equinor has struggled with GoM exploration, with a commercial success rate of 17%

Equinor exploration history in the Gulf of Mexico Avg. US GoM deepwater Number of wells drilled Commercial success rate Commercial Discoveries DW GoM Avg 48% Technical Discoveries Statoil non-op 25% Dry Hole Statoil operated 8% Statoil 17% Julia (75 mmboe) 6

Vito (252 mmboe) Blacktip (125 mmboe)

Heidelberg (46 mmboe) Monument (95 mmboe) 3 3 3

2 2 2 2 2

1 1 1 1

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Equinor has struggled to source its own prospects –only 6 of its 31 wells have come from licensed acreage from Lease Sales. Furthermore, Equinor struggled to find commercial discoveries (17%), significantly lower than compared to the GoM average, which is high at 48% in part because many smaller discoveries in GoM can be commercialized via tieback to existing facilities and pipelines. After more than a decade exploring deepwater GoM, Equinor made its first operated commercial (RE estimate) discovery at Monument in 2020.

Source: Rystad Energy research and analysis

38 Miocene had been the predominant play; Lower Tertiary / Paleogene emerged in 2000s

5-year average Gulf of Mexico discovered oil resources per year by geographic time period • Deepwater GoM was largely a Million barrels of oil equivalent Miocene and subsalt Miocene Youngest play until the Lower Tertiary 1500 Unknown emerged in the early 2000s Pleistocene • Lower Tertiary is also referred Pliocene to as Paleogene and Miocene sometime by the formation, Eocene usually the Wilcox 1000 Paleogene • The Jurassic / Norphlet play Tertiary has emerged in recent years Tertiary Lower with the leader being Shell Jurassic with its Appomattox discovery Oldest and various tiebacks • Equinor has maintained focus 500 on Lower Tertiary and Subsalt Miocene • Equinor has not targeted a single play but spread its efforts. Likely a result of 0 acquiring different portfolios. 1985-1989 1990-1994 1995-1999 2000-2004 2005-2009 2010-2014 2015-2019 Only 6 of the wells came from their own acquired leases Equinor exploration wells by geographic time period • The two recent successes are: Number of exploration wells 21 • Monument, operated discovery which is a Paleogene play in 11 11 Walker Ridge (remote area) • Blacktip, a Paleogene discovery in the Perdido thrustbelt on 2005-2009 2010-2014 2015-2019 the far west of the GoM

Source: Equinor; Rystad Energy research and analysis

39 …Which lags substantially Gulf of Mexico peers

Operated exploration history in the Gulf of Mexico Number of wells drilled

10 10 8 31% 8 6 6 30% commercial success commercial success 4 Thunder Horse North (563 mmboe) 4 Julia (75 mmboe) 2 2

0 0 2000 2005 2010 2015 2020 2000 2005 2010 2015 2020

10 10 8 8 27% 54% commercial success 6 Great White (467 mmboe) commercial success 6 Shenzi (525 mmboe) 4 4

2 2

0 0 2000 2005 2010 2015 2020 2000 2005 2010 2015 2020

10 10 8 Tahiti (528 mmboe) 33% 8 41% 6 6 commercial success Ceasar (135 mmboe) commercial success 4 Ballymore (550 mmboe) 4 2 2

0 0 2000 2005 2010 2015 2020 2000 2005 2010 2015 2020

Note: Anadarko operated exploration includes Occidental Petroleum Source: Rystad Energy research and analysis

40 Statoil has been unable to create value in GoM exploration, but has avoided large value destruction that has plagued peers such as BHP, XOM, and BP from 2005-2019

GoM Exploration value creation Net development value (real) Analyzed E&A Spend (real) $ Billion, 2005-19 $ Billion, 2005-19 discoveries $ Billion, 2005-19

4.5 18.9 14.5 • Despite a lackluster performance as an operator, Equinor’s non-op 0.8 3.8 3.1 exploration was able to limit value destruction overall in the GoM 2.0 1.3 0.7 • Equinor was not successful in ventures they chose to take a larger 6.3 0.5 5.8 stake and more risk on such as Heidelberg, Julia, and Pony. -0.2 2.6 2.7 • These prospects were more typically in remote -0.4 1.1 1.5 areas of the Gulf of Mexico with little to no previous infrastructure to fast-track -0.7 2.0 2.7 development • Large discoveries such as Appomattox, Whale, -1.4 -0.2 1.2 Power Nap and Vito that were easily able to be tied- back to exiting -2.4 0.2 2.5 infrastructure created tremendous and quick value for Shell -2.4 3.8 6.1

Source: Rystad Energy research and analysis

41 Statoil’s wildcats were spread across 7 operators and three main protraction areas

Statoil exploration wells drilled in deepwater GoM 2005-2020 YTD

Operator Play Target Protraction Area

Garden Atwater Banks Jurassic Valley Alaminos 3 % 7 % 3 % Perdido Canyon 7 % Mississippi 7 % Canyon DeSoto 28 % 7 % Canyon 7 %

45 % 10 % Keathley Canyon 7 %

14 % Lower Tertiary 14 % 31 % Green Miocene Canyon 21 % Walker 55 % Ridge 24 %

Statoil’s approach to exploration, garnered largely from experience in the NCS, was not built for the less collaborative, more operator-driven deepwater GoM. The large number of partnerships may reflect Statoil’s inability to organically generate drillable prospects on leased acreage and bring on partners willing to share the risk. It may also be indicative of Statoil being seen by counterparties as being very eager to grow in the GoM and hence more willing to take on risk.

Source: Rystad Energy research and analysis

42 Index

43 Index

Industry outlook in 2005 as seen from the NCS Activity in the US GoM deepwater from 2005-2020 Developments in the US unconventional industry from 2005 to 2020 Overview Statoil in the Marcellus Statoil in the Eagle Ford Statoil in the Bakken – evaluation of the Brigham transaction External analyst coverage of Equinor’s M&A activity on US onshore

44 Statoil saw shale as prime growth opportunity early in the sector’s development

Key take-away Industrial context in US shale Statoil positioning

In 2008, Statoil formed a JV with Chesapeake, US independents were the first entrants into shale Shale gas and tight oil were a leader in shale, to develop acreage in the gas and later tight oil. Companies such as consistently underestimated Marcellus and evaluate shales outside North Chesapeake and EOG grabbed prime acreage before in the 2000s America. This was part of positioning Statoil as other competitors entered the unconventional basins. a leader in global unconventionals.

Statoil was among the first entrants to shale Majors and international International oil companies, majors, and even NOCs gas in 2008 before most companies entered in E&Ps spent billions on spent $50 billion acquiring companies and stakes in 2009-11. However, this meant that Statoil shale acquisitions, largely shale projects. However, US-based independents still entered near the peak in gas price and had to in the 2008-2014 timeframe accounts for more than 70% of production. contend with a very difficult gas price environment.

Collapses in price followed Statoil’s Marcellus The industry was so successful at unlocking shale and Bakken acquisitions, hindering value Macro headwinds have gas supplies that it cratered natural gas prices, which creation substantially. hindered the sectors ability to has been a hindrance to value creation. Similarly, the create value oil price collapse of 2014-15 made early tight oil Statoil did not take a position in the Permian drilling largely uneconomic. which proved to be the most prolific tight oil play.

Source: Rystad Energy research and analysis

45 Unconventionals evolved in three phases and brought a massive productivity increase

L48 wells by type Oil & gas production ‘000 of wells Million boe/d 90 Shale 1.0: Unconventional Shale 2.0 – Moving to oil plays 35 End of the conventional era Gas Boom and Bust Shale gas techniques are The number of conventional wells The first phase of effectively applied to oil wells, 80 drilled dropped sharply over the unconventional activity in the which are focused in Eagle Ford, 80s and production flattened US was driven largely by Bakken and later Permian 30 shale/tight gas in the Rockies, Also focus on liquid rich gas plays 70 Texas and Arkansas, but this in Marcellus and Utica activity fell sharply after the gas price collapse late 2008 25 60 Production begins to soar from the application 20 50 of horizontal drilling and hydraulic fracturing From 2007-2017 first 40 month production per 15 well in the Permian grew from roughly 30 b/d to 30 more than 500 b/d 10 20 Shale 3.0 – Highly productive shale oil Oil price collapse caused in part by shale 2.0 forced 5 10 impressive efficiency improvements in drilling and hydraulic fracturing. Repositioning shale as a lower cost supply source 0 0 1980 1985 1990 1995 2000 2005 2010 2015 2020

Conventional Shale/tight gas Shale/tight oil Oil & gas production

Source: Rystad Energy ShaleWellCube; Rystad Energy Ucube

46 Growth in tight oil plays was unexpected, as evidenced by the EIA’s 2012 forecast

EIA lower 48 oil production forecasts Million barrels per day

10 May-17 Jan-15 Sep-17 9 • The graph shows reported oil production from the US outside EIA’s forecast from Jan 2012 for Jan-17 of Alaska. The US government 8 onshore oil production Dec 2013: Jan-14 (EIA) strongly missed on these 2mmbbl/d during actual production; projections due to the shale oil the market in general did not foresee Jan-16 revolution. the shale oil revolution 7 Jan-13 • In January 2012, the EIA expected a slight increase over the next two years to 5.5 million 6 barrels per day in 2014. The actual figure was 7.65 mmbbl/d. Actual Overall, we can conclude that production almost no one saw the shale oil Jan-05 Jan-07Jan-08 Jan-12 5 revolution that came and Jan-10 Jan-11 caused dramatic demand for Jan-09 rigs. 4 Jan-06 . 3

Source: Rystad Energy Ucube, Rystad Energy research and analysis; EIA, IEA

47 By 2014, tight oil capital investment dwarfed shale gas and outpaced conventional fields

US capital expenditure by supply segment Billion USD Permian trends towards dominance 250 2013 would be the last year in which the Permian emerges stronger after Permian would not be the top play by downturn total capex During the oil price downturn of 2015-16 the Permian became more cost competitive and became a top destination for E&P capital 200 Tight oil plays ramp up Operators aggressively leasing up tight oil plays and drilling aggressively at a time of strong oil prices 150 Early pilot programs Tight oil First Eagle Ford and Bakken wells completed in 2008

100

Shale gas

50 Offshore

L48 conventional 0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Source: Rystad Energy Ucube

48 The Bakken and Eagle Ford emerged earlier but the Permian became the dominant oil play

Shale and tight oil wells spudded by basin Thousand wells

16 • Tight oil drilling increased 14 rapidly in the US in the 2010s, 12 going from a little more than 10 three thousand wells spudded in 2010 to almost ten thousand 8 Other in 2012. 6 4 • Statoil acquired Brigham at a time (2011) of rapid growth in Permian 2 this segment in the industry. 0 Year-on-year growth in 2005 2007 2009 2011 2013 2015 2017 2019 Bakken wells spudded in 2011 and 2012 was 32% and 42%, Pre-2013 2013-2020 respectively. 37,881 wells 78,332 wells • Initially, the Eagle Ford and Bakken together were the Bakken Other primary basins, together 14 % accounting for nearly half of 18 % tight oil drilling prior to 2013. Other Bakken Anadarko • However, the Permian 16 % 10 % emerged as the premier tight Permian 26 % oil basin, with a larger resource and some of the most 16 % economic wells in the country. 18 % Permian • Ultimately the Permian 20 % 24 % 38 % emerged as the predominant Anadarko tight oil play, with the lowest- Eagle Ford Eagle Ford cost resource

Source: Rystad Energy Ucube

49 A growth machine - US shale liquids plays has yet to be in the green

Organic FCF from US shale liquids plays Billion USD nominal 80 Forecast 60 • The chart show the organic FCF from US shale plays in the period. 40 • From 2005 the portfolio had yet to return positive cash flows except for 2016 following 20 a slow down in growth and investments • This cash flow profile is mostly - result of the continued 2005 2010 2015 2020 2025 investment growth in US shale where all cash have been -20 reinvested. • Building on a base of producing wells and more -40 muted growth outlooks we expect the free cash flows from shale to be in the green -60 from 2021 and onwards

-80

Source: Rystad Energy UCube; Rystad Energy research and analysis

50 But looking at well vintages, wells completed from 2016-2019 will likely create value

Production by vintage for key oil plays Million boe per day (liquids and gas) 14 Key tight oil plays included: - Permian Delaware 12 - Permian Midland - Bakken 10 2019 - DJ Basin Future - Eagle Ford vintages • The top chart show production 8 2018 from key tight oil plays by vintage (completion year) 6 2015 2017 2016 • Vintages drilled before 2016 2014 4 have largely been value 2013 destructive, with negative NPVs and IRRs below 10. 2 2012 2011 • From 2016, with improved 2010 0 break-evens and healthier oil 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 prices, all vintages are NPV positive given cashflows they Return and value obtained per vintage 72 % have already obtained and Million boe per day (liquids and gas) forecasted production and oil IRR 35 % prices. 27 % NPV 18 % 20 19 • An average tight oil player 11 would have had difficulties in 7 % 4 creating value prior to 2016. 1 % 2 % 4 % 2 % 2 %

-2 %-4 -3 -9 -10 -14 -15 -21 Pre 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2010

NPVs and IRRs include midstream and overhead, but not finance and acquisition cost. Discount rate of 10% applied to NPV. Rystad Energy base case prices used for forward calculations (See appendix) Source: ShaleWellCube; Rystad Energy research and analysis

51 The larger shale players have outperformed smaller setups, but on average destroyed value

Shareholder return indexed to 2010 for pure-play shale players

10.0 Big shale players Medium shale players** 9.0 8.0 7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0 -1.0 -2.0 -3.0 -4.0 -5.0 -6.0 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 YTD*

From the organic view taken on the vintage evaluation, this also considers acquisition cost and expectations for future improvement in learning curves. As such not directly comparable with NPV calculations on organic cash flows The larger shale players have higher value creation than the smaller players from 2010 until today. Before 2013, the smaller outperformed the larger and after 2013, the smaller have been outperformed by the larger companies. Negative value creation after 2014 for the small and medium shale players on average. Covid-19 in 2020 results in negative development for all shale players compared to 2019.

*Through June 2020 **Not exhaustive list of companies Source: Rystad Energy research and analysis

52 Majors and international E&Ps bought into shale—but together still account for less than 20% of total shale production

US shale production by company type Total shale gas and oil production % of total production Million boe/d More than $50 billion spend on acquisitions Notable buyers:

100 % Others 30 Int E&Ps NOCs 90 % Int Majors US Majors 25 80 % US independents

70 % 20 60 %

50 % 15

Pure US shale players 40 % 10 30 %

20 % 5 10 %

0 % 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

*Excluding low production companies Source: Rystad Energy Ucube

53 Equinor were part of a very active period of M&A in the onshore US

Top 20 US onshore deals by deal value, 2008 - 2014 Billion USD 41.0 2009: ExxonMobil acquires XTO Energy for $41B 15.1 2011: BHP Billiton acquires Petrohawk Energy for $15B 7.0 2014: Encana acquires Athlon Energy for $7B 6.0 2013: Devon acquires Eagle Ford assets from GeoSouthern for $6B 6.0 2014: Whiting Petroleum acquires Kodiak Oil & Gas for $6B 5.4 2014: Chesapeake sells Marcellus and Utica assets to Southwestern Energy for $5.38B 4.8 2011: Chesapeake divests Fayetteville assets to BHP Billiton for $4.8B 4.7 2010: Shell acquires Marcellus acreage from East Resources for $4.7B 4.7 2011: Statoil acquires Brigham Exploration for $4.7B 4.3 2010: Chevron acquires Atlas Energy for $4.3B 3.5 2010: CONSOL Energy acquires Dominion's E&P business for $3.5B 3.4 2008: StatoilHydro acquires 32.5% interest in Chesapeake’s Marcellus Shale assets for $3.4b 3.3 2008: Plains E&P acquires Louisiana and Texas acreage from Chesapeake Energy for $3.3B 3.1 2014: Encana acquires Eagle Ford assets from Freeport for $3.1B 2.9 2012: Apache acquires Cordillera Energy for $2.85B 2.6 2014: Baytex Energy acquires Aurora for $2.59B 2.5 2014: AEP acquires Permian assets from Enduring Resources for $2.5B 2.3 2009: Total acquires 25% interest in Chesapeake's Barnett Shale portfolio for $2.25b 2.2 2012: Devon and Sinopec form JV for five unconventional plays in US 2010: Talisman and Statoil form $1.3B Eagle Ford JV 1.3

Note: Equinor’s Eagle Ford transaction falls outside the top 20 Source: UCube; Rystad Energy research and analysis

54 Shale has grown more productive despite of weak oil and gas prices over the past decade

US shale gas production Henry Hub monthly price Billion cubic feet per day $3.375B acquisition of $253m acquisition of USD/MMBtu Marcellus assets from additional Marcellus Chesapeake assets from Chesapeake 80 $590m additional 16 acreage in Marcellus 70 14 60 12 Henry Hub price 50 10 40 8 30 6 20 4 10 Production 2 0 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

US tight oil production WTI monthly price Million barrels per day USD/bbl $405m additional 5 $1.3B JV with Talisman in working interest in 160 Eagle Ford Eagle Ford JV $27m acquisition of Bakken assets from 140 4 Earthstone 120 100 3 WTI price 80

2 $4.7B acquisition of 60 Bakken assets from 40 Brigham 1 20 Production 0 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Source: Rystad Energy UCube, EIA

55 Index

56 Statoil’s early entry into the Marcellus allowed it to achieve a lower entry cost than others

Metrics for representative Marcellus deals

Deal value Acres Net production $ per acre Comments Comments million USD Thousand Mcf/d Statoil acquires additional Marcellus acreage Statoil (2010) 4,300 300 59 Unknown from Chesapeake for $253m Ultra Petroleum acquires additional acreage in Ultra Petroleum (2009) 5,000 400 80 Unknown Marcellus for $400M ExxonMobil acquiers Marcellus assets for ExxonMobil (2011) 5,300 1,700 317 Unknown $1.7B StatoilHydro acquires 32.5% interest in Statoil (2008) 5,700 3,400 600 39 Chesapeake’s Marcellus assets for $3.4b Chief Oil & Gas and partners acquire Chief Oil & Gas (2013) 6,700 500 75 130 Marcellus assets from Chesapeake for $500M Chevron acquires additional Marcellus acreage Chevron (2011) 7,000 1,600 228 Unknown from Chief Oil and partner for $1.6B Shell acquires Marcellus acreage from East Shell (2010) 7,200 4,700 650 60 Resources for $4.7B Statoil acquiers Marcellus assets for $590M Statoil (2012) 8,400 600 70 28

Williams acquires Marcellus acreage from Alta Williams (2010) 11,900 500 42 Unknown Resources for $501M Chesapeake sells Marcellus and Utica assets Southwestern (2014) 13,000 5,400 413 336 to Southwestern Energy for $5.38B

One of the earliest movers to enter the gassy Marcellus play, Statoil was able to strike high acreage positions for less than its supermajor peers.

Source: Rystad Energy research and analysis

57 Chesapeake was a highly sought-after partner, but cost carries created misalignment

Total Deal Cost Company Deal Year Shale Play Comments Value carry Statoil acquired 32.5% of Chesapeake’s Marcellus assets, equating to 0.6 million acres. The transaction involved $1.25B in cash upfront. Chesapeake received the 2008 $3.375 B $2.1 B Marcellus remaining $2.1 billion via Statoil funding 75% of Chesapeake drilling costs from 2009 to 2012. Both companies noted ongoing discussions around a future international strategic alliance geared towards unconventional gas Total acquired a 25% interest in Chesapeake’s upstream Barnett shale assets, a total of 270,000 acres. The asset included 700mcfd of production and 3 trillion cubic feet of 2010 $2.25 B $1.4 B Barnett reserves with possible vast unproved reserves. Transaction included $800 million in upfront cash as well as Total funding 60% of Chesapeake drilling until the remaining $1.45B is recouped. CNOOC acquired a 33.33% stake in Chesapeake’s Eagle Ford acreage, equivalent to 200,000 acres overall. The JV was reviewed by CFIUS, the US congressional 2010 $2.16 B $1.08 B Eagle Ford authority on foreign direct investment, due to CNOOC’s affiliation with the Chinese government. CNOOC paid $1.08B upfront and financed Chesapeake’s drilling and completion costs to pay the other $1.08B.

Total acquired a 25% interest in 619,000 acres owned by Chesapeake and EnerVest 2012 $2.32B $1.42 B Utica in the Utica shale. Total paid $610 million upfront and the other $1.42B by financing Chesapeake’s drilling and completion costs. EnerVest received $290 million.

Sinopec acquired a 50% stake in Chesapeake’s Mississippi Lime venture which Mississippi included 850,000 acres in northern Oklahoma. Chesapeake received 93% of the 2013 $1.02B $0 Lime purchase price upfront. Sinopec did not pay for Chesapeake’s drilling and completion costs to finance the deal like had been normal in previous transactions.

A features that Chesapeake often built into its JV agreements was the “cost carry” in which the new partner would agree to pay for future drilling up to a certain amount of capex. In the Statoil deal, the carry accounted for $2.2 billion out of the $3.4 billion deal consideration. During a cost carry, the JV partners are usually facing misaligned incentives. Chesapeake, which had a high debt load in 2008-09 at the time of the deal, had an incentive to keep drilling wells even if they were not NPV-positive because Statoil would be paying the well costs and Chesapeake needed the cash flow. Notably, the last of these deals, in 2013, did not include a cost carry.

Source: Rystad Energy Ucube, Chesapeake Energy press releases

58 The Marcellus proved to be the most economically robust shale gas play but became a victim of its own success, keeping gas prices depressed

Gas wellhead breakeven prices US L48 gas production Henry Hub Price $/mcf by completion year Billion cubic feet per day $/MMBtu

10 Appalachia 100 16 Appalachia is now Barnett Shale nearly one third of US 9 90 14 Lower 48 gas supply Haynesville/Bossier Shale 8 80 Fayetteville Shale 12 7 70 Appalachia 10 6 60 Henry Hub

5 50 8 Associated shale gas 4 40 Other shale gas 6

3 $3.0 30 $2.3 4 2 $2.0 20 Conventional

1 $1.1 10 2

0 0 0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Gas production in the US dramatically increased with the Breakeven prices at the wellhead have consistently declined introduction of shale gas. Appalachia has fueled the largest over the last decade. portion of this growth, keeping gas prices depressed.

Source: Rystad Energy research and analysis, Rystad Energy ShaleWellCube

59 Chesapeake operated highly productive and low-breakeven wells

Median Marcellus initial 90-day production by completion year Median Marcellus wellhead breakeven by completion year Million cubic feet per day USD per million Btu

18 4

16 Chesapeake

14 Statoil adds an 3 additional 59,000 12 Statoil enters acres from Marcellus in JV Chesapeake with Chesapeake 10 for $3.375 B Marcellus 2 8

Marcellus 6

1 4 Chesapeake

0 0 2008 2010 2012 2014 2016 2018 2010 2012 2014 2016 2018

Statoil partnered with one of the top performing operators in Chesapeake has maintained one of the lowest breakevens the basin in Chesapeake, at the early stages of the since Statoil entered the Marcellus, well below the average. Marcellus’s development.

Source: Rystad Energy research and analysis

60 The Marcellus position is large, highly productive and among the best in Appalachia

Top 10 producing operators in the Appalachia Wellhead gas price BE*, 2019 Initial production 90 days, 2019 Million cubic feet per day (2019) Dollars per mcf Million cubic feet per day

EQT Corporation 1 111 $1.44 12.1

Chesapeake 735 $0.91 22.3

Cabot Oil and Gas 681 $1.32 17.4

Antero Resources 645 $0.90 14.3

Southwestern Energy 577 $1.50 11.1

Range Resources 525 $0.72 12.2

CNX Resources 427 $0.73 7.8 Corporation

Diversified Gas & Oil Plc 400 No 2019 wells 14.9

Ascent Resources, LLC 329 No 2019 wells 21.1

Encino Energy 258 No 2019 wells 14.8

Despite the overall macro adversity, Chesapeake and Statoil have one of the most material, economically robust Appalachia acreage positions, evidenced by low breakevens, the plays most productive wells and the 2nd largest production.

*Operators with no new completions are excluded Source: Rystad Energy research and analysis; ShaleWellCube

61 Despite Chesapeake's operational performance, infrastructure issues further depressed gas prices in the Marcellus

Northeast takeaway capacity & production Utilization Henry Hub & Dominion South gas prices Million cubic feet per day Percentage USD per MMBtu

35 Utilization 120% 12 108%

30 97% 93% 93% 89% 100% 10 88% 25 8 71% 80% 20 6 60% 15 Production Henry Hub 4 40% 10 2 Capacity 20% 5 Dominion South

0 0 0% 2012 2013 2014 2015 2016 2017 2018

A gap emerged between takeaway capacity and Marcellus gas production. Statoil had secured some firm takeaway The takeaway shortage drove the spread between Henry Hub capacity on the Northern Access Pipeline in 2010, however price and Dominion South price. the pipeline has yet to be built due to regulatory hurdles.

Source: Rystad Energy Research and Analysis

62 Index

63 Statoil’s Eagle Ford acquisitions were slightly expensive when benchmarked against other deals in the same time period

Metrics for representative Eagle Ford deals

Deal value Acres Net production $ per acre Comments million USD Thousand kboe/d Part of the purchase went to a JV with EOG Resources. Plains E&P believed the acreage Plains E&P (2010) 9,600 600 60 2,000 had potential for high reserves.

CNOOC acquired a 1/3 stake in Chesapeake’s CNOOC (2010) 10,800 Eagle Ford assets. More than half of the 2,200 200 Unknown purchase price was financed through drilling costs.

KKR helped Exco to finance the deal by Exco (2013) 12,400 contributing 50% of the costs while Exco 700 55 Unknown operated the wells.

Statoil partnered with Talisman to form a JV in Statoil (2010) 12,600 800 67 2,800 the Eagle Ford.

Statoil and Talisman added acreage to their Statoil (2011) 14,600 200 15 6,100 Eagle Ford JV through the acquisition of SM acreage.

Statoil and Talisman’s entry deal consideration was largely in line with typical spend per acre in the basin. At the time, Statoil was aware that its position was in the condensate and dry gas windows. With gas and condensate prices relatively strong at the time, the part of the part of the play Statoil and Talisman entered wasn’t inherently less attractive than the oil window acreage.

Source: Rystad Energy Ucube

64 Statoil bought into gassy acreage on the southern end of the Eagle Ford condensate window

Eagle Ford JV acreage and wells

• Statoil and Talisman formed a JV in the Eagle Ford in 2010, in which Statoil spent more than $800 million. The JV went onto to acquire more acreage from SM Energy. Oil window • In 2015, Repsol acquired Talisman and Statoil became the operator of the entire JV’s portfolio. Later, in 2019, Equinor divested their entire Eagle Ford portfolio Condensate window to Repsol, leaving the basin. • By the time Statoil entered the Eagle Ford in 2010, the geology of the basin Dry gas window was well known, including the different resource windows. JV acreage • Overall, Statoil ended up having much “gassier” acreage than average in the JV wells Eagle Ford. Statoil expected a significant portion of revenue from NGLs and Gas-to-oil ratio of production Completed wells per year condensate, but oversupplies in the Gulf Thousand cubic feet per barrel Well count Coast depressed prices. 30 120

25 Statoil JV wells completed 100 . . . this acreage is located in an attractive, 20 80 liquids rich area of the Eagle Ford play. Statoil expects that a significant 15 Statoil JV 60 proportion of the revenue from Statoil’s 10 40 Eagle Ford acreage will come from gas Eagle Ford Average liquids and condensate which are 5 20 competitively located to be sold into the 0 0 petrochemical and refinery centres in 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Texas. – 2010 press release

Source: Rystad Energy ShaleWellCube, Rystad Energy research and analysis

65 Statoil’s production mix reflected the multi-commodity nature of the commercialization

Eagle Ford hydrocarbon mix by operator1, 2010-2019 Percent production

100 %

90 %

80 % 42%

70 % Gas 60 %

50 % 28% 40 %

30 %

20 % NGL 30% 10 % Oil 0 %

1: Gas considered on a boe basis; top 15 operators by production Source: Rystad Energy research and analysis

66 Statoil relied on NGLs and condensate revenues, but NGL prices dropped and condensate discounts widened

NGL composite price1 and Henry Hub natural gas price Plains Marketing posted prices2 USD per MMBtu USD per bbl

18 140 16 120 NGL composite price Eagle Ford crude 14 100 12

10 80

8 Eagle Ford condensate 60 6 Henry Hub 40 4

2 20

0 0 jul-2011 jul-2012 Jan-2010 Jan-2011 Jan-2012 Jan-2013 Jan-2014 Jan-2015 Jan-2016 Jan-2017 Jan-2018 Jan-2019 jan-2011 jan-2012 jan-2013 sep-2010 nov-2010 mai-2011 sep-2011 nov-2011 mai-2012 sep-2012 nov-2012 mar-2011 mar-2012

• A high proportion of the Eagle Ford JV’s production consisted of gas, NGLs and condensate, but all 3 commodities were impacted negatively by the surge in light hydrocarbon production from shale plays • Eagle Ford condensate was priced at only a slight discount to Eagle Ford crude in 2010, evidenced by Plains Marketing price postings. In 2012, Plains’ Eagle Ford condensate posting averaged $17/bbl below the Eagle Ford crude posting.

1: EIA NGL composite price is an average of Bloomberg spot prices for component hydrocarbons, weighted by actual monthly gas plant production volumes 2: Data only available Sept-2010 to Jan-2013.Posted prices represent prices Plains Marketing is willing to pay to acquire the commodity. Eagle Ford crude represents 40-45 API crude; condensate prices represent 60.1 API condensate Source: Rystad Energy, EIA, Plains All American

67 Prior to 2013, nearly all Statoil Eagle Ford crude and condensate was trucked to market

Lease disposition of Statoil’s Eagle Ford oil Percent of oil trucked Barrels of energy equivalent per day Percentage

45 000 120% • In 2010, over 95% of crude and condensate production in the Eagle Ford was trucked from the 40 000 lease as production exceeded Statoil JV % trucked pipeline capacity. Most was 100% trucked to refineries in Corpus 35 000 Christi. • In 2012, trucking began to decline as new pipelines entered service. 30 000 Eagle Ford 80% average % • The Statoil JV entered into long- term agreements with the Double 25 000 trucked Eagle Condensate Pipeline in H1 2012. It is possible that acquiring 60% undeveloped acreage may have 20 000 delayed Statoil’s process of arranging for firm pipeline transportation, as the prior owners 15 000 40% were unlikely to have had midstream arrangements in place • Following the completion of the 10 000 Double Eagle pipeline in mid- 20% 2013 the JV’s trucking began to 5 000 decrease rapidly. • By 2015, the JV averaged 18% trucking while the basin averaged 0 0% 50%. • The basin-average trucking rate remains high as many areas do not have high enough production density to merit crude gathering systems Karnes - Pipeline McMullen Pipeline La Salle - Pipeline Other - Pipeline Trucked

Source: Rystad Energy ShaleWellCube

68 Statoil’s Eagle Ford position was below average in productivity and economic robustness

Initial 90-day production, 2010-18 average Gas to oil ratio, 2010-18 average Boe/d Cubic feet per barrel

Statoil JV 597 8% lower initial Statoil JV 10 323 60% higher gas production content

EF 650 EF 4 128

0 200 400 600 800 0 5000 10000 15000

Well cost, 2010-18 average Wellhead oil breakeven, 2010-18 average Million USD $ / barrel

Statoil JV 9.0 20% higher well Statoil JV 95 38% higher cost breakeven

The multi-commodity mix EF 7.1 EF meant neither the gas nor oil 59 breakeven would be fully reflective of the well economics 0 2 4 6 8 10 0 20 40 60 80 100

• In large part due to its position in the southern flank of the play, outside the core, Statoil’s JV lagged industry averages in the Eagle Ford for initial production, gas to oil ratio, well cost and breakeven. • The economics are complicated by the multi-commodity nature of the Gas-Condensate play as well as the deeper wells required, which drove up well costs relative to other parts of the Eagle Ford. These economics did not compete well within the Equinor portfolio, resulting in divestment in 2019.

Source: Rystad Energy ShaleWellCube

69 Index

70 The Brigham acquisition in 2011 – two main areas of activity pre-acquisition

Ross Area Completions by 2011: 34 wells Avg. 30-d IP 2010-11:1205 boe/d

Rough Rider Area Completions by 2011: 84 wells Avg. 30-d IP 2010-11:888 boe/d

Non-core acreage Completions by 2011: 15 wells Avg. 30-d IP 2010-11:458 kboe/d

Source: Rystad Energy UCube

71 Statoil’s Brigham acquisition did not compare unfavorably on a per acreage pricing kUSD/acre WTI, USD/bbl 60 160 Bubble size equals 500 MUSD Selected deals for comparison 2010-2014 Corporate deal Consider to reduce range on deal value/boe, creates more QEP-Helis Asset deal 140 dynamics in deal value 50 Statoil’s Brigham deal

120

40 Whiting-Kodiak 100

30 80

Halcon-Petro-hunt 60 20 Statoil-Brigham Kodiak-Liberty

Kodiak-Mercuria Exxon-Denbury 40 Williams-Dakota-3 Oasis-4 assets 10 Hess-America Oil & Gas Oasis-SM Energy Occidental-private 20 XTO-Headington Liberty-Sequel Hess-TRZ Continental-Samson Tristar-Talisman 0 2005 2005 2005 2005 2005 2005 2005 2005 2005 2005 2005 2005 2006 2006 2006 2006 2006 2006 2006 2006 2006 2006 2006 2006 2007 2007 2007 2007 2007 2007 2007 2007 2007 2007 2007 2007 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2009 2009 2009 2009 2009 2009 2009 2009 2009 2009 2009 2009 2010 2010 2010 2010 2010 2010 2010 2010 2010 2010Enerplus2010 2010 2011 2011 2011 2011 2011 2011 2011 2011 2011-2011private2011 2011 2012 2012 2012 2012 2012 2012 2012 2012 2012 2012 2012 2012 2013 2013 2013 2013 2013 2013 2013 2013 2013 2013 2013 2013 2014 2014 2014 2014 2014 2014 2014 2014 2014 2014 2014 2014 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2016 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2018 2018 2018 2018 2018 2018 2018 2018 2018 2018 2018 2018 2019 2019 2019 2019 2019 2019 2019 2019 2019 2019 2019 2019 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Source: Bloomberg, Rystad Energy research and analysis

72 Metrics per Bakken deal completed 2010-2014

Acreage (kUSD/acre) Production (kUSD/boe)* 1P reserves (USDboe)

QEP-Helis 50 Williams-Dakota-3 280 Statoil-Brigham 70

Whiting-Kodiak 35 Occidental-private 255 Whiting-Kodiak 36

Halcon-Petro-hunt 18 Hess-TRZ 239 Halcon-Petro-hunt 34

Kodiak-Liberty 16 Statoil-Brigham 224 Oasis-4 assets 33

Kodiak-Mercuria 12 Kodiak-Mercuria 169 Exxon-Denbury 18

Statoil-Brigham 11 Oasis-4 assets 163 Hess-America Oil & Gas 6

Williams-Dakota-3 11 Whiting-Kodiak 148 Liberty-Sequel

Exxon-Denbury 10 Halcon-Petro-hunt 138 Continental-Samson

Oasis-4 assets 9 QEP-Helis 131 Occidental-privateShale valuation metrics is largely a function the maturity of the acreage Liberty-Sequel 8 Exxon-Denbury 129 acquired.Enerplus-private Statoil bought in early at in Bakkens evolution and paid fairly Occidental-private 8 Kodiak-Liberty 116 cheapQEP-Helis per acreage acquired, but high for the relative small amount Hess-America Oil & Gas 6 Liberty-Sequel 112 existingHess-TRZ production and proved reserves compared to later Hess-TRZ 6 Continental-Samson 100 Williams-Dakota-3transactions of more matured acreage positions Continental-Samson 5 Enerplus-private 85 Kodiak-Liberty

Enerplus-private Hess-America Oil & Gas Kodiak-Mercuria

*Production at time of transaction Source: Rystad Energy research and analysis

73 Brigham acquisition rationale – why acquire an operator?

Operatorship Rationale Supporting points needed

Diversify away We are positioning ourselves as a leading player in the fast-growing US from NCS and • Clear ambition from Statoil to add reserves and production onshore oil and gas industry, in line with the strategic direction we have reach set outside the NCS. Following prior strategic decision to move set out. Helge Lund after Brigham transaction into unconventional US onshore. No production We actively manage our portfolio to create value and we will put our goals and • Shale provides improved R/P and rapid production growth money where our strategy is. So we are expanding into unconventionals reserves possibilities. … this is actually one of the largest single transactions Statoil has ever done. It builds on our stepwise approach into US unconventionals. targets

• Statoil had prior experience with Chesapeake in Marcellus In Marcellus, we have a carry structure, which is an incentive to build where carry agreements and different hedging positions up production over a certain period. Here there are no carry Be in control lead to unequal economic positions and possibly structures. There are no promotes. There is equality of unfavorable position for Statoil. economics point forward in this joint venture with Talisman, which is of your own one of the very attractive aspects of it, and it is a 50-50 JV. So we destiny • The operator have more power in the US than on the NCS, have got a lot more flexibility in this to mix and match to events, rock quality and macro environments. ✓ operatorship would allow Statoil to better control the efforts given change in macro and infrastructure conditions John Knight after Eagle Ford JV

Chesapeake concentrating mostly“on the G&G in the [coring] office. We have also had some diligence in there, but we have looked mostly • Statoil needed to build an organization in order to expand Use at the commercial terms available in other parts of the world and the operations internationally. In the joint global efforts with knowledge to above ground risks in the Statoil part of the team. Chesapeake, it was Chesapeake that had led the John Knight after Eagle Ford JV expand in subsurface work. Brigham has proven itself as a premier operator with a highly attractive Europe and • Brigham acquisition was viewed as good strategic fit for ✓ internationally position in the Williston Basin. We are a strong strategic fit, as both Statoil with one technology leader acquiring another. companies put a premium on technological innovation and advancement. Helge Lund after Brigham transaction

• Some metrics pointed to that it was cheaper to buy acreage Cheaper with From an investor's point of view, it seems like a lot of oil shares are through corporate transactions than asset deals. valued at implicit oil prices way below $80, while asset deals seem to corporate be done in that kind of range. Wouldn't it have been cheaper to look deals than • This would also be true for the Brigham deal for the stock for some oil companies to buy instead of assets at the moment? price prior to the transaction, but with 36% premium to the Question from Carnegie to Statoil following Eagle Ford JV asset deals 30-day trailing average, it was at par or higher. ✓

Source: Conference call transcripts following Eagle Ford acquisition; press releases; Rystad Energy research and analysis

74 Statoil’s deals in the US were part of a global strategy of leading in unconventionals

Statoil shale initiatives outside of North America

“At the time we announced the Marcellus deal, we said that we were also forming a joint group with Chesapeake to look at deals outside of North America, and we have had a joint team looking at those things for the last two years. There is about 2000 people.”

“We have done a very extensive review of opportunities around the world, but particularly in Europe, and we have been into around 1000 data rooms”

“As a matter of public record, we are looking at opportunities in China, and we have been scanning opportunity the last two years in Europe. We are Sonatrach & Shell, 2014 CNPC, 2011 going to be very choosy about this and find just the Jointly acquired Timissit Joint study and test right place. But I'm sure that we will continue to permit license, Illihizi Valeura Energy, drilling with CNPC divert our exposure to this type of investment. Ghadames basin 2012 JV with Valeura for John Knight, SVP Business Development Banali license in northern Turkey and Global Unconventional Gas

PetroFrontier, 2012 YPF, 2017 JV with PetroFrontier in Sasol & CHK, 2010 JV with YPF to jointly Australia’s Northern JV with Sasol and explore Vaca Muerta shale Territory Chesapeake, acquired permit to explore Karoo basin

Source: Rystad Energy research and analysis

75 Pre-transaction: In 2010-11 Brigham was chasing Bakken records for well productivity

May 26th, 2010 April 13th, 2011

September 23rd, 2011

October 4th, 2010

Source: News articles

76 Pre-transaction: - Brigham with best in class in IPs and worst in class in well cost

Initial production - 30 days (boe/d) Initial production decline (percent) EUR per well (kboe)

Brigham 975 Hunt 0.7 Encore 615 Tracker 795 Marathon 1.4 Slawson 575 Hess 740 Whiting 1.6 Marathon 530 Slawson 715 Anshcutz 2 Burlington 520 Whiting 680 PetroHunt 2.1 PetroHunt 515 Encore 645 EOG 3.2 Brigham 495 Burlington 645 XTO 3.3 Continental 480 Continental 630 1st Encore 3.8 11th Tracker 480 6th Oasis 610 Oasis 3.9 Whiting 465

Productivity PetroHunt 585 Continental 5.3 Hunt 440 Hunt 575 Brigham 5.4 XTO 430 Anshcutz 565 Slawson 5.5 Anshcutz 400 Marathon 555 Tracker 5.6 Hess 400 EOG 495 Burlington 6.3 Oasis 375

Lateral length (feet) Proppant (Thousand pounds) Frac stages

XTO 9680 Oasis 4020 Brigham 35 Oasis 9655 Brigham 3805 Oasis 30 Marathon 9580 Continental 3465 Tracker 30 Burlington 9525 EOG 3210 Hess 28 Brigham 9520 Hunt 2870 Continental 26 Continental 9445 Tracker 2770 Slawson 25 Whiting 9405 Burlington 2720 Whiting 25 Anshcutz 9305 5th Marathon 2620 2nd PetroHunt 23 1st Tracker 9255 Hess 2600 Hunt 21 Hess 9180 Slawson 2460 XTO 21 PetroHunt 9010 PetroHunt 2365 EOG 20 Hunt 8770 Encore 2325 Anshcutz 20 Encore 7970 XTO 2245 Encore 19 Completion intensity EOG 6715 Whiting 2055 Marathon 18

Well cost (MUSD) Wellhead break-even (USD/boe)

Anshcutz 6.1 Slawson 43 Hunt 7 Hunt 52 Brigham with very high Slawson 7 Whiting 52 EOG 7.2 Burlington 54 Whiting 7.3 Encore 55 completion intensity per Burlington 8 Anshcutz 58 Marathon 8.7 Marathon 61 lateral length. Resulted XTO 8.8 14th Brigham 64 8th Oasis 9.7 PetroHunt 65

Economics Encore 9.8 Tracker 65 high IPs, but less optimal PetroHunt 9.9 EOG 67 Continental 9.9 Continental 68 long-term economics. Brigham 10.4 XTO 74 Hess 10.9 Oasis 76

All data from wells completed in 2010-2011 Source: Rystad Energy ShaleWellCube

77 Post transaction: Ross with declining performance and Rough Rider below peer average

Ross Area Rough Rider Area

Wells completed Wells completed Ross Area with limited activity 81 97 68 47 from 2015, drilled out? 35 44 46 36 36 45 43 17 25 27 5 2 10 9 8 6 1 9

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Wellhead break-evens Wellhead break-evens 100 100

Pre-transaction Improvement in break-evens, 80 80 advantage over peers but less than peers Brigham/ Equinor 60 Brigham/ 60 Equinor At par pre-transaction 40 40 Break-evens increased post-transaction Rough Rider Area peers Ross Area peers* 20 20 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Evolution in well design Evolution in well design 2010-11 2012-13 2014-15 2016-17 2018-19 2010-11 2012-13 2014-15 2016-17 2018-19 Lateral (feet) 9550 9600 9950 9500 No wells Lateral (feet) 9500 9800 9800 9800 9700 Frac stages 36 34 34 44 No wells Frac stages 34 34 33 42 42 Proppant (klbs) 3 700 3 400 5 100 7 700 No wells Proppant (klbs) 3 800 3 800 5 300 8 000 8 700 IP (boe/d) 1210 700 650 650 No wells IP (boe/d) 890 800 610 840 970 Well cost (MUSD) 9.0 9.0 8.0 8.0 No wells Well cost (MUSD) 11.0 10.9 8.0 8.0 8.4

Source: ShaleWellCube; Rystad Energy research and analysis

78 Post transaction: Three severe disappointments in oil price development

Oil price (USD/bbl) 1. Multi-year price discounts to WTI and Brent 130 A. WTI discount to Brent due to light oil surplus in US B. Clearbrook discount to WTI due to infrastructure issues in Bakken

110

2. Oil price collapse: OPEC and shale volume war

90 3. COVID-19 demand erosion

70 Brent Cushing WTI Clearbrook 50

acquires 10

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 -10

-30

Source: Bloomberg; Rystad Energy research and analysis

79 Post transaction: Up to 25 USD/bbl discount to WTI for Clearbrook, closest hub to Bakken

Bakken oil production and takeaway capacity Discount to WTI for Bakken crude at Clearbrook Thousand barrels per day USD/bbl

1 600 Dakota Access in service Statoil 30 acquires 1 400 Brigham High discount end-2018 due 1 200 Production 25 to refinery Dakota maintenance 1 000 20 Access pipeline in- 800 service 15 600 10 400 Pipeline takeaway capacity* 200 5

0 0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Oct-10 Oct-11 Oct-12 Oct-13 Oct-14 Oct-15 Oct-16 Oct-17 Oct-18 Oct-19 • The Bakken faced acute pipeline constraints from 2011 to 2010-2011 (pre-deal) 2012-2014 (post-deal) 2017, when the Dakota Access Pipeline came into service following a series of delays. Clearbrook-WTI spread Clearbrook-WTI spread USD/bbl USD/bbl • Due to pipeline constraints and reliance on expensive crude- by-rail, Bakken discounts to WTI reached $25/bbl at the 10 2 5 nearby Clearbrook pricing hub. -3

• Infrastructure constraints led to low realized prices by Clearbrook Realized prices by Clearbrook Realized prices by Bakken operators – a $10/bbl realized price discount to WTI Bakken operators Bakken operators from 2012-2014.

*Pipeline takeaway capacity includes local refining Source: Bloomberg; UCube; North Dakota Pipeline Authority (takeaway capacity); Rystad Energy research and analysis

80 Statoil’s initial production target has been reached despite unfavorable market conditions

Equinor/Brigham Bakken production kboe/d 100 Current equity production is approximately 21,000 Production target: 60-100kboe/d boe per day, and the acreage has potential to 90 ramp up to 60,000-100,000 boe per day equity production over a five-year period. 80

acquires 60

40 Rough Rider Area

10 Ross Area 0 Jul-08 Jul-09 Jul-10 Jul-11 Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-17 Jul-18 Jul-19 Jul-20 Apr-08 Oct-08 Apr-09 Oct-09 Apr-10 Oct-10 Apr-11 Oct-11 Apr-12 Oct-12 Apr-13 Oct-13 Apr-14 Oct-14 Apr-15 Oct-15 Apr-16 Oct-16 Apr-17 Oct-17 Apr-18 Oct-18 Apr-19 Oct-19 Apr-20 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20

Source: Rystad Energy research and analysis

81 When adjusting for market effects the Brigham acquisition was fairly priced

Estimated value creation Value creation at $86 WTI flat (NPV 31.12.2011) (NPV 31.12.2011)

Capex spent 2012-2019 -3.5 -3.5

Production 2012-2019 4.8 7.1

Opex + taxes 2012-2019 -1.2 -1.7

Value captured 31.12.2019 0.1 1.9

Producing wells 1.4 3.0

Opex + taxes producing wells -0.6 -1.0

Value drilled 31.12.2019 0.8 3.9

Capex new wells -0.4 -0.4

Production new wells 0.9 1.6

Opex + taxes new wells -0.3 -0.5

Full asset value 0.9 4.6

Deal consideration 4.7 4.7

Delta -3.8 -0.1

• With full market effects: historical commodity prices • With expected market effects at time of transaction: Flat obtained in Bakken and Rystad Energy base case price 2011 commodity prices adjusted for inflation strips forward • Deal appears value neutral and fairly priced • Drilled inventory has yielded 0.8 BUSD, but not enough to defend acqusition price of 4.7 BUSD.

Production is measured as revenue from entitlement production (revenue after royalties and production tax). WACC of 10% used, inflation rate of 2%. In the value creation adjusted for market effects 2011 average prices are used going forward (WTI 95 USD/bbl, Henry Hub 4 USD/mmBTU). Note: In a different, more positive macro environment it is likely that the drilling program would have looked different and that service price escalation would have been higher. This has not been accounted for in the valuation that has been adjusted for market effects. Source: Company news reports; UCube; ShaleWellCuibe; Rystad Energy research and analysis

82 Index

83 Seven sizeable onshore transactions in the US by Statoil in the period from 2008 to 2019

WTI Cushing oil price Henry Hub gas price USD/bbl USD/MMbtu 20 WTI 140 17.10.2011 10.10.2010 Acquisition of Henry Hub Acquisition of 50% Brigham stake in Eagle Ford Exploration (Bakken assets) 11.12.2015 JV together with Acquisition of additional 120 4.7 BUSD 16 Talisman (later 13% stake in Eagle Repsol) Ford JV and 843 MUSD 7.11.2019 operatorship from Divestment of 100 Repsol 63% stake in Asset swap. (15% Eagle Ford JV stake in Gudrun and operatorship 12 swapped in favor of to Repsol 13% stake in Eagle 325 MUSD 80 18.12.2012 Ford JV) Acquisition of Limited analyst info 31.12.2011 Marcellus assets Acquisition of from Grenadier, 60 additional Protege and 8 Marcellus PetroEdge acreage from 590 MUSD Chesapeake (Limited analyst (No analyst info as sellers 40 reports) were private co.) 11.11.2008 Acquisition of 4 32.5% stake in 20 Chesapeake’s Marcellus shale assets 3.4 BUSD 0 0 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20

Source: Rystad Energy research and analysis

84 Summary of analyst evaluations

Description Analysts Summary of analyst evaluation

11/11-2008 • All analysts believed that the acquisition represented a sound strategic entry Acquiring 32.5% On November 11, 2008, StatoilHydro into US onshore, but analysts disagreed on pricing. announced that it would enter US stake in • DNB Markets stated that Marcellus was a quality asset, pricing, while other unconventional by acquiring a 32.5% banks saw too ambitious production targets. Chesapeake stake in Chesapeake’s Marcellus assets Marcellus assets for 3.375 BUSD. • Chesapeake (the seller) in liquidity squeeze at the time, could have helped Value: 3.4 BUSD StatoilHydro’s bargaining power to obtain an even lower price.

On October 10, 2010, Statoil 10/10-2010 • The overall takeaway of the equity research reports is that the acquisition s announced that it would acquire a 50% fairly priced and that it makes sense strategically. JV with Talisman stake in Eagle Ford through a joint venture with Talisman (later Repsol) for • At the time Statoil was also looking at other potential shale plays globally and in Eagle Ford 843 MUSD. The acreage was acquired the knowledge and experience the company would gather from being an operator in the Eagle Ford was therefore also key for their success in shale Value: 843 MUSD from Enduring Resources and Talisman. globally.

• All banks had unchanged recommendations for their Statoil target pricing 17/10-2011 On October 17, 2011, Statoil compared to their previous target pricing, implies a neutral valuation. Acquisition of announced that it intended to acquire Brigham Exploration and its Bakken • Several analysts noted that the deal was expensive compared to previous Brigham assets for 4.7 BUSD. The price transactions in the Bakken and that it required high oil prices to create value. Exploration represented a 36% premium to the 30- • Most analysts acknowledged the deal as the right strategic move in the day trailing average price. Value: 4.7 BUSD continuation of Statoil’s strategic decision to move into shale.

• Limited analyst coverage on the transaction from Equinor’s perspective. On November 7, 2019, Equinor 7/11-2019 announced that it would sell all its stake • Berenberg supported Equinor’s exit from the Eagle Ford at the time since the Divestment of (63%) in the Eagle Ford JV and US operations had been challenging and led to significant impairments. The operatorship to Repsol for 325 MUSD. transaction was also recommended due to its favorable pricing. Eagle Ford assets The consideration was significantly • The acquirer, Repsol said that the field breakeven level was at above $55 lower than the 843 MUSD Equinor had Value: 325 MUSD USD/boe without synergies, which would have barely made it profitable in to pay for 50% ownership back in 2010. the end of 2019. Therefore, overall good deal for Equinor.

According to analysts, most of Statoil’s US onshore acquisitions had a Deal summary clear strategic rationale and were reasonably priced. The exception is the Brigham deal, which was viewed as an expensive deal.

Source: Rystad Energy research and analysis

85 Positive long-term commodity price outlooks at the time of the transactions were expected to increase

11/11-2008: 32.5% stake in Marcellus 10/10-2010: JV in Eagle Ford None ofthe analysts predicted the Henry Hub collapse a few months Bullish long-term oil 8.8 after the transaction price outlooks 120 8.0 Analyst avg: 7.2 7.0 95 Analyst avg: 8 USD/mmbtu 90 83 102 USD/bbl

3.6 45

Henry Hub Deutsche UBS Macquarie Henry Hub at Bank +5 years WTI at Morgan DNB Arctic WTI +5 transaction transaction Stanley Markets Securities years 17/10-2011: Acquisition of Brigham 7/11-2019: Divestment in Eagle Ford

Bullish long-term oil price outlooks 120 120 100 Analyst avg: 95 109 USD/bbl 84 80 65 65 65 Analyst avg: 50 55 69 USD/bbl 43

WTI at UBS Deutsche Societe Swedbank WTI +5 WTI at UBS Societe Morgan Barclays WTI transaction Bank Generale years transaction Generale Stanley 08/25/2020

*For the analysts price outlooks, the longest time horizon provided has been used. Source: Research reports, Rystad Energy research and analysis

86 11/11-2008: StatoilHydro acquires 32.5% in Chesapeake’s Marcellus assets for 3.4 BUSD

Deal description Key deal metrics Communicated deal rationale by StatoilHydro

Deal size relative to STO’s EV* Deal value: 3.375 BUSD • Deal makes sense for StatoilHydro as it contributes to On November 11, 2008 diversify its upstream portfolio. StatoilHydro announced that it 50 Production: • The acquisition enhances StatoilHydro’s offering in the would enter US kboed by 2012 international gas value chain and increases the company’s unconventional by acquiring a flexibility in LNG cargo arbitrage by sending gas through 32.5% stake in Chesapeake’s Net acres: 585k Cove Point. Marcellus assets for 3.375 6% BUSD. • The high gas prices in 2008 were expected to continue and it STO share price**: Marcellus therefore made sense to invest in a gas play. Area: 126 NOK

Change in stock price following Analyst Analyst evaluation Analyst summary Overall evaluation announcement

Views that the pricing of the gas in the acquisition is fairly good All analysts believed that the and emphasizes the maturity of the field as an advantage as a lot of technical work has been conducted. Also stresses that it is acquisition represented a sound -13.0% 7-days before a good strategic step into new secure reserves in quality assets strategic entry into US onshore, in North America. Target stock price: 180 NOK but analysts disagreed on pricing. DNB Markets stressed -5.6% Intraday Thinks the deal makes good strategic sense and boosts that Marcellus was a quality StatoilHydro’s equity gas position in the US. JP Morgan also asset with lots of technical work % change change % to -16.3% 7-days after believes the pricing is reasonable and maintains its overweight conducted, which defended the recommendation for the stock. pricing, while other banks saw -0.25 -0.2 -0.15 -0.1 -0.05 0 Target stock price: 170 NOK too ambitious production targets As JP Morgan and DNB Markets, Deutsche Bank thinks the deal and lower future gas prices. makes strategic sense, but also see some limitations with the Chesapeake was also in a deal. First, they believe forecasted production could be to liquidity squeeze, which could -2.6% 7-days before agressive and that they see potentially lower gas prices as new supply was coming on stream globally. have helped StatoilHydro’s Target stock price: 100 NOK bargaining power to obtain an -5.5% Intraday Also believes it is a good strategic move, but also stresses that even lower price. the Marcellus development is complex and that production

% change change % to targets could be difficult to reach. They also see potentially -10.8% 7-days after weakening oil prices and more negative macro conditions. In “Neutral deal” summary, the price paid by StatoilHydro is above UBS’ estimate.

-0.25 -0.2 -0.15 -0.1 -0.05 0 Target stock price: 160 NOK

*EV=enterprise value at time of transactions **Closing prices Source: Rystad Energy research and analysis

87 11/11-2008: StatoilHydro acquires 32.5% in Chesapeake’s Marcellus assets for 3.4 BUSD

“In our view these are quality assets, “Reasonable price, good strategic “On simple metrics the deal looks even though they are drilling “Well, well, well…” move” good but….” intensive”

“We think this deal makes good “The strategic shift into secure “The Marcellus development is strategic sense to Statoil as it “We have a number of key reserves in North America is a good complex, and the reserve estimates provides the company with a foothold reservations, namely production (may one and a right one, in our view, as employed by Statoil are ambitious. in North American unconventional be too aggressive), US gas prices this one has missed in their total Hence the price paid is well in excess gas, close to consuming areas and at and infrastructure” portfolio” of our prior estimates” a reasonable price”

Source: Rystad Energy research and analysis

88 10/10-2010: Acquisition of 50% stake in Eagle Ford JV together with Talisman for 0.8 BUSD

Deal description Key deal metrics Communicated deal rationale by Statoil

Deal size relative to STO’s EV* Deal value: • Strategic importance of becoming a shale operator was key On October 10, 2010 Statoil 0.843 BUSD in this deal for Statoil as they had ambitions of being announced that it would involved in other shale plays globally. acquire a 50% stake in Eagle Resources: 550 Ford through a joint venture million boe • The knowledge and experience they would gather from with Talisman (later Repsol) being an operator in the Eagle Ford was therefore key for for 843 MUSD. The acreage Net acres: 67k their success in shale plays globally. was acquired from Enduring 1% • The deal also made sense as they increased their position in Resources and Talisman STO share price**: US shale gas after having entered shale gas in the Marcellus Energy. Eagle Ford Area: 127.8 NOK two years prior.

Change in stock price following Analyst Analyst evaluation Analyst summary Overall evaluation announcement

Judged the pricing of the transaction as fair after having compared it to recent transactions in the Eagle Ford. Stressed The overall takeaway of the that the acquisition was important for Statoil to gather equity research reports is that 7-days before 2.7% Target stock price: 150 NOK experiences before investing in other shale plays globally. the acquisition was fairly priced and that it made sense DNB Markets judged the pricing as fair, similar to Nordea strategically. In addition, as Intraday 0.7% Markets. That was primarily because of the asset being a liquid Statoil was looking at other Target oil price: 95 USD/bbl rich shale play (50/50 liquids and gas). potential shale plays globally the

% change change % to Target stock price: 160 NOK 7-days after 0.4% knowledge and experience the UBS emphasized that increasing position in US shale made company would gather from 0 0.01 0.02 0.03 0.04 0.05 strategic sense as they were already present in the Marcellus play. In addition, deal price seemed reasonable. Also mentioned being an operator in the Eagle Ford was key for their success in Target stock price: 135 NOK that it would provide valuable experience for Statoil. shale plays globally. Arctic menttioned that transaction prices had increased in the 7-days before 2.2% Eagle Ford, which could imply that Statoil had to pay extra to Target oil price: 120 USD/bbl enter Eagle Ford late. Therefore neutral valuation. Target stock price: 180 NOK Intraday 2.1% Fair valuation when comparing to other transactions that was % change change % to conducted in the past two years. Acquisition made sense as “Good deal” 7-days after 1.2% Statoili was increasing its exposure to and knowledge of US non- Target stock price: 155 NOK conventional resources. 0 0.01 0.02 0.03 0.04 0.05

*EV=enterprise value at time of transactions **Closing prices Source: Rystad Energy research and analysis

89 10/10-2010: Acquisition of 50% stake in Eagle Ford JV together with Talisman for 0.8 BUSD

“We expect the transaction to create “Statoil entering Eagle Ford at fair “First foray into Eagle Ford liquid rich “In for a penny, in for a pound” value, and view the acquisition as price” shale play” positive”

“Eagle Ford has become one of the “Statoil is virtually recycling its Statoil “Transaction prices have increased hottest shale plays in the USA thanks Fuel and Retail mid-point proceeds “Deal price seems reasonable and already as many majors have entered to a high liquid content (~50%). $752m investing $843m into the will provide valuable experience” Eagle Ford” Prices clearly favors liquids over gas” Eagle Ford play in Texas”

Source: Rystad Energy research and analysis

90 2000 people at Statoil have been staffed looking at international opportunities in shale

Source: Rystad Energy research and analysis

91 Statoil entered Bakken at a high price to secure drilling technology and industry knowledge

Deal description Key deal metrics Communicated deal rationale by Statoil

Deal size relative to STO’s EV* Deal value: 4.7 BUSD • Was consistent with Statoil’s strategy and supplemented its previously acquired stakes in the Marcellus and the Eagle On October 17, 2011 Statoil Resources: Ford. (STO) announced that it 300-500 mmboe intended to acquire Brigham • Acquisition would also help diversify Statoil’s portfolio away Exploration (BEXP) and its Net acres: 415k from only NCS operations. Bakken assets for 4.7 BUSD. 6% • Acquisition included access to pipeline, leading drilling The price represented a 36 % STO share price**: technology and valuable industry knowledge. Bakken premium to the 30-day trailing Area: 137 NOK average price.

Change in stock price following Analyst Analyst evaluation Analyst summary Overall evaluation announcement • Viewed the acquisition as a logic extension of Statoil’s company strategy. All banks had unchanged Target oil price: 100 USD/bbl • Retained their “buy” recommendation with a high target recommendations for their Statoil Target stock price: 160 NOK price. 7-days before 1.7% target pricing compared to their previous target pricing. This • Pricy acquisition but Statoil’s balance sheet remained solid. Target oil price: 119 USD/bbl • Deal consistent with Statoil’s strategy. could imply a neutral valuation. Intraday -0.4% Target stock price: 137 NOK On the other hand, several • Noted that Statoil did a corporate deal and not only an asset banks believed that it was an % change change % to 7-days after 4.2% deal because of the expertise of BEXP’s management. expensive deal but justified it in • Statoil’s share price remained relatively robust after their belief that Statoil would be -0.04 -0.02 0 0.02 0.04 0.06 0.08 0.1 Target stock price: 175 NOK announcement of deal. able to create value with future • Viewed the price as high. oil prices at well above 100 • Price implied WTI long term at 90-95 USD/bbl. Target oil price: 119 USD/bbl • Deal provided Statoil with new expertise and technology, USD/bbl and through portfolio Target stock price: 120 NOK which helps defend the high price. management. 7 days prior 34.4% • UBS calculated a breakeven level for the deal at greater than 70 USD/bbl. Target oil price: 95 USD/bbl • Deal made sense because of presence in US onshore and Intra day 21.0% Target stock price: 150 NOK because of expectations for high oil prices in the future. “Strategic, but % change change % to • Viewed the deal as expensive but mentioned that Statoil had 7 days after 20.3% demonstrated ability to generate value from what seemed to too expensive” Target oil price: 120 USD/bbl be expensive transactions in the past. -0.3 -0.2 -0.1 0 0.1 0.2 0.3 0.4 0.5 Target stock price: 185 NOK

*EV=enterprise value at time of transactions **Closing prices Source: Rystad Energy research and analysis

92 Deutsche Bank, Societe Generale and Barclays were the most optimistic deal analysts

“We regard Statoil’s recommended “Acquisition is consistent with offer for Brigham Exploration as a Statoil’s strategy to increase its “Backing the Bakken” logical extension of company positions in US unconventional” strategy” “Despite the big acquisition, Statoil’s “We see two notable takeaways. First “The price paid does not compare balance sheet remains solid thanks to is that Statoil has chosen to do a unfavorably to either past two significant disposals carried out corporate rather than asset deal. The transactions or the commodity price by the company recently (Brazil & second is the relative robustness of outlook” Canadian oil sands)” Statoil’s share price to the deal”

Source: Rystad Energy research and analysis

93 But other analysts were more pessimistic due to the high price paid

“Statoil enters the Bakken play at “At $9k/acre the price paid a price we estimate implies WTI “It provides the company with “Deal deepens Statoil North appears full and the all in long term at USD 90-95/bbl, and access to new American position” economic breakeven for the deal we consider this as a full price for expertise/technology” is probably >$70/bbl” the assets”

Source: Rystad Energy research and analysis

94 Swedbank emphasized that the price was rather high compared to Rystad estimates

“Expensive compared to Rystad “Looks like an expensive acquisition” upstream valuation”

“Rystad Energy have valued Brigham’s upstream “Compared to several recent assets at USD 2,576m, which implies that Statoil transactions in the area, Statoil has paid pays an 82% premium to the estimated fair value” a significant premium. However, the company has previously demonstrated “This value excludes however the value of the its ability to generate value from midstream assets acquired and the overprice apparently expensive acquisitions” is therefore somewhat lower”

Source: Rystad Energy research and analysis

95 7/11-2019: Divestment of 63% stake in Eagle Ford JV to Repsol for 0.3 BUSD

Deal description Key deal metrics Communicated deal rationale by Equinor

Deal size relative to STO’s EV* On November 7, 2019 Equinor Deal value: 325 MUSD announced that it would sell • The communicated deal rationale by Equinor was to all its stake (63%) in the Eagle Production: 34 rebalance its upstream portfolio. Ford JV and operatorship to kboe/d Repsol for 325 MUSD. The • Operating US onshore assets had not been easy and consideration was despite having conducted cost optimization activities, impairments had been inevitable. As the economics of the significantly lower than the Net acres: 70k 0.4% 843 MUSD Equinor had to pay deal seemed sound it appeared to be an optimal time for for 50% ownership back in STO share price**: Equinor to exit from its Eagle Ford position. Eagle Ford 2010. Area: 179.85 NOK

Change in stock price following Analyst Analyst evaluation Analyst summary Overall evaluation announcement

Limited analyst coverage on the transaction. Berenberg Berenberg believed that Equinor exited the Eagle Ford 7-days before 3.6% supported Equinor’s exit from the at a fair valuation. In addition, Berenberg supported a Eagle Ford as the US operations rebalancing of Equinor’s upstream portfolio as US onshore had not been easy and impairments had been had been challenging and led to Intraday 0.8% unevitable as the macro outlook and oil prices had been significant impairments. The low (compared to pre-2014 levels) since 2014. transaction was also % change change % to 7-days after -1.3% recommended by Berenberg due Target oil price: 65 USD/bbl*** to the favorable pricing. Finally, -0.03 -0.02 -0.01 0 0.01 0.02 0.03 0.04 0.05 0.06 Target stock price: 200 NOK Repsol also revealed that the field breakeven level was at Equity report conducted in Repsol’s perspective. It was above $55 USD/boe without stressed that the deal’s breakeven was at >$55 synergies, which would have 7-days before USD/boe, but that cost synergies for Repsol would drive barely made it profitable at the it down to 55 USD/boe. In the end of 2019 Brent prices end of 2019. Overall good deal were above 60 and the deal therefore appeared to be for Equinor. Intraday value accretive for Repsol. However, with little margin between the oil price and breakeven level it seemed % change change % to favorable for Equinor to exit its position. “Good deal” -3.0% 7-days after

-0.05 -0.04 -0.03 -0.02 -0.01 0

*EV=enterprise value at time of transactions **Closing prices ***2021 oil price forecast Source: Rystad Energy research and analysis

96 7/11-2019: Divestment of 63% stake in Eagle Ford JV to Repsol for 0.3 BUSD

“US onshore has not been easy. “The asset offers two types of upside. “Exiting Eagle Ford at good Despite executing cost optimization “The deal’s breakeven is >$55 1) EOR (enhanced oil recovery) and valuation” activities impairments have been USD/boe” 2) potential upside in Austin Chalk” inevitable ”

Source: Rystad Energy research and analysis